Introduction to the drilling manual

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

June 2006

GENERAL INFORMATION

A

INTRODUCTION

___________________________________________________________________________________________________________________________

INTRODUCTION TO THE DRILLING MANUAL 1.0

OBJECTIVES

2.0

CONTENTS 2.1 Source of Information 2.2 Ownership 2.3 Confidentiality 2.4 Contributors

3.0

REVISIONS

4.0

MEDIA

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

June 2006

GENERAL INFORMATION

A

INTRODUCTION

___________________________________________________________________________________________________________________________

INTRODUCTION TO THE DRILLING MANUAL 1.0

OBJECTIVES This comprehensive manual has been compiled for the main purpose of serving as a guide to Drilling Operations personnel and a reference to new Drilling Engineers. Most common Saudi Aramco drilling rig operations have been presented in this manual to familiarize the reader with the actual step-by-step procedures required to execute the job. This manual is written in such a way that it is clear, easy to follow, uses acceptable oilfield terminology, and the information is current and very specific to Saudi Aramco’s operations.

2.0

CONTENTS 2.1

Source of Information The information contained in this manual has been collected from many different sources. These include: Saudi Aramco drilling guideline and instruction letters, Service Company manuals and catalogues, field experience, Saudi Aramco’s Completion & Workover training manual, oil industry recognized standards (e.g. API), and other sources.

2.2

Ownership Saudi Aramco is the sole owner of the information in this manual. Any alterations or future updates of this manual shall be done only by the Workover Engineering and Technical Service Division personnel.

2.3

Confidentiality The information in this manual has been prepared for Saudi Aramco. Even though the information is not highly confidential, yet discretion should be exercised when copying pages for non-Saudi Aramco personnel.

2.4

Contributors Drilling and Workover staff, along with Laboratory Research and Development Center personnel have been instrumental in compiling the information in this manual.

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SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 1 SECTION

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DRILLING MANUAL June 2006

GENERAL INFORMATION INTRODUCTION

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3.0

REVISIONS As in every manual, information has to be periodically updated to reflect changing field conditions and the application of new technology. Suggested changes should be forwarded to the General Supervisor of Workover Engineering and Technical Services Division for review and inclusion in the next update of the manual. Chapter 1, Section B provides detailed procedures for revising this manual.

4.0

MEDIA The Drilling Manual will be available on different media to meet user requirements. These are: A) B) C)

Hard copy. Electronically, on Drilling & Workover servers. CD-ROM disc with key word search capability.

Initially, the manual will be available in hard copy format and electronically, on the servers. Eventually, a CD-ROM version will be distributed to those who require it.

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

B

June 2006

GENERAL INFORMATION DRILLING MANUAL ORIGINAL ISSUE AND REVISION GUIDELINES

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DRILLING MANUAL ORIGINAL ISSUE & REVISION GUIDELINES 1.0

ORIGINAL DOCUMENT ISSUE 1.1 Document Format 1.2 Media 1.3 Distribution 1.3.1 List 1.3.2 Manual Numbering 1.3.3 Responsibility

2.0

REVISIONS 2.1 Frequency 2.2 Revision Format 2.3 Responsibilities 2.3.1 Manual Modification 2.3.2 Manual Distribution 2.4 Distribution Instructions

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

B

June 2006

GENERAL INFORMATION DRILLING MANUAL ORIGINAL ISSUE AND REVISION GUIDELINES

___________________________________________________________________________________________________________________________

DRILLING MANUAL ORIGINAL ISSUE & REVISION GUIDELINES 1.0

ORIGINAL DOCUMENT ISSUE 1.1

Document Format 1.1.1

A common format has been developed to maintain structure uniformity since the manual has been authored by a number of individuals. Future revisions should utilize the same structure in order for the Drilling Manual to maintain its organization and appearance.

1.1.2

The Drilling Manual has been prepared using Microsoft Word. Each chapter will consist of an index page, followed by text. Headings, text fonts, bullets and indentations will vary throughout the chapter but will conform to the following guidelines: A)

Page Set-up: i)

ii)

iii)

iv)

Margins Top : 0.5” Bottom : 0.88” Left : 1.25” Right : 1.25” Header : 0.5” Footer : 0.19” Paper Size Paper Size : Letter Width : 8.5” Height : 11” Orientation : Portrait (checked) Paper Source First Page : Default Tray Other Pages : Default Tray Layout Section Start : New Page Header & Footer : Different Odd & Even (checked) Different First Page (checked) Vertical Alignment : Top

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

B

June 2006

GENERAL INFORMATION DRILLING MANUAL ORIGINAL ISSUE AND REVISION GUIDELINES

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B)

Index: i) ii) iii) iv) v) vi)

vii) C)

Text i) ii) iii) iv)

v) vi) vii)

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Header : ‘As shown above’ Section Heading: Title, Arial 14, Bold, Italic, Centered, Red First Subheading: Title, Arial 11, Bold, First text indent at 0”, Hanging text indent at 3/8”, Teal Second Subheading: Title, Arial 11, Bold, First text indent at 6/8”, Hanging text indent at 1-1/8”, Black Third Subheading: Title, Arial 11, Bold, First text Indent at 1-1/8”, Hanging text indented at 1-5/8”, Black The subheadings numbering sequence should be as follows: 1.0 First subheading 1.1 Second subheading 1.1.1 Third subheading Page Numbering: None

Section Heading : Title, Arial 14, Bold, Italic, Centered, Red First Subheading : Heading 1, Arial 11, Bold, First text indent at 0”, Hanging text indent at 3/8”, Teal Second Subheading : Heading 2, Arial 11, Bold, First text indent at 3/8”, Hanging text indent at 6/8’, Dark Red Third Subheading : Heading 3, Arial 11, First text indent at 6/8”, Hanging text indent at 1-2/8”, Only number or title Blue and bolded Forth Subheading : Body text, Arial 11, First text indent at 1-2/8”, Hanging text indent at 1-5/8”, Black Fifth Subheading : Body text, Arial 11, First text indent at 15/8”, Hanging text indent at 2” The subheading numbering sequence should be as follows: 1.0 First Subheading 1.1 Second Subheading 1.1.1 Third Subheading A) Fourth Subheading i) Fifth Subheading The First Subheading numbering sequence cannot be changed. However, subsequent Subheadings can be altered to Bullets or Lettering, depending on context and flow of text.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

B

June 2006

GENERAL INFORMATION DRILLING MANUAL ORIGINAL ISSUE AND REVISION GUIDELINES

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viii) Main Text : Body Text, Arial 11, Text alignment Justify. ix) Page Numbering: 1 of xx, 2 of xx, etc, the page number location will alternate between the lower right and left hand corners. 1.2

Media The Drilling Manual will be available on three different media to meet user requirements. These are: A) Hard copy (3-ring binder). B) Electronically, on Drilling & Workover servers. C) CD-ROM disc with key word search capability.

1.3

Distribution 1.3.1

List Hard copies of the Drilling Manual will be distributed based on need and accessibility to the LAN servers. A copy of the Drilling Manual will be stored in electronic form on the LAN server for easy access; consequently, hard copy distribution will be minimized. The hard copy distribution of the Manual will be as follows: A) B) C) D) E) F) G)

General Manager, D&W Managers, D&W Rig Superintendents, D&W General Supervisors, DWOED Supervisors, DWOED Rig Foremen, D&W Loss Prevention Representative

Additional copies of the Drilling Manual requested by individuals other than those listed above will be considered on a case-by-case basis and will be decided by the custodian of the Manual, General Supervisor of Workover Engineering and Technical Services Division. 1.3.2

Manual Numbering Each hard copy of the Drilling Manual will be numbered to insure the document is traceable. It will be properly marked, both on the outside of the binder and on the fist page of the document. A record will be kept of the Manual numbered and the recipient name.

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

B

June 2006

GENERAL INFORMATION DRILLING MANUAL ORIGINAL ISSUE AND REVISION GUIDELINES

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1.3.3

Responsibility A) B)

C)

2.0

A designated person will be responsible for distributing all hard copies of the Drilling Manual to the recipients. The responsible person will ask each recipient, prior to delivery, his preference of the Drilling Manual media; hard copy, CD-ROM (when available) or none. Copies of the Drilling Manual will be hand-delivered to each recipient and their initials obtained to verify receipt of the manual.

REVISIONS 2.1

Frequency The Drilling Manual will be updated no later than once every two years. The duration of the revision should not exceed two months since majority of the changes will be minor.

2.2

Format The same format as the original Drilling Manual will be followed. All changes and addendums will be highlighted on a separate page and inserted in the inside cover of the manual for quick reference. The updated sections or paragraphs within the Manual will have a line on the side of the page, as shown to the right of this paragraph. It is also important to change the date of the updated section in the upper right hand corner of the document.

2.3

Responsibilities 2.3.1

Manual Modification The General Supervisor of Workover Engineering and Technical Services will assign a person to undertake the task of modifying the Drilling Manual. The assigned person will collect all pertinent information related to updating the Manual, evaluate the proposed changes/additions, prepare them in a draft form, and circulate to Management for approval. Once approved, he will modify the Manual and highlight the changes as described in Section 2.2 above.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

B

June 2006

GENERAL INFORMATION DRILLING MANUAL ORIGINAL ISSUE AND REVISION GUIDELINES

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2.3.2

Manual Distribution The person designated to modify the Manual will also be responsible for distribution of copies of the Manual. He may seek the help of a technician to deliver the Manual to the rig sites if necessary.

2.4 Distribution Instructions Using the original Drilling Manual distribution list, either inserts, page replacements or complete Manual replacements will be hand delivered to the Manual recipients. Old Manuals that have been replaced will new ones will be destroyed to avoid inadvertent use. When all Manuals have been delivered, the issue list will be updated to reflect the up-to-date Manual recipients.

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Drilling & Workover Engineering Department CHAPTER 1 SECTION

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June 2006

GENERAL INFORMATION ORGANIZATION AND RESPONSIBILITES

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ORGANIZATION AND RESPONSIBILITES 1.0

ORGANIZATION CHART

2.0

RESPONSIBILITIES 2.1 Drilling Foreman 2.1.1 Well and Comp Location 2.1.2 Rig Move 2.1.3 Program Execution 2.1.4 Communication 2.1.5 Rig Operations 2.1.6 Record Keeping 2.1.7 Miscellaneous 2.2

Drilling Engineer 2.2.1 Drilling Programs 2.2.2 Communication 2.2.3 Rig Surveillance 2.2.4 Completion Report 2.2.5 Training, Seminars, Forums and Courses

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

C

June 2006

GENERAL INFORMATION ORGANIZATION AND RESPONSIBILITIES

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ORGANIZATION CHART AND RESPONSIBILITIES 1.0

ORGANIZATION CHART 1.1

Figure 1-C-1 is the most current organization chart of Drilling & Workover. Due to periodic reorganization and restructuring of Drilling & Workover, this chart maybe replaced the next time the manual is due for an update.

DRI LLI N G & WORK OV ER DRILLING & WORKOVER GENERAL MANAGER PLANNING & ACCOUNTING SERVICES UNIT SUPERVISOR

DRILLING & WORKOVER SERVICES DEPT. MANAGER

DRILLING & WORKOVER ENGINEERING DEPT. MANAGER

DEVELOPMENT DRILLING & OFFSHORE WORKOVER DEPT. MANAGER

DEEP DRILLING & ONSHORE WORKOVER DEPT. MANAGER

Material Acquisition & Forecasting Unit Supervisor

Drilling Engrg. Division 1 General Supervisor

Drilling Division 1 Superintendent

Drilling Division 1 Superintendent

Drilling Rig Support Division Superintendent

Drilling Engrg. Division 2 General Supervisor

Drilling Division 2 Superintendent

Drilling Division 2 Superintendent

Dril. Equip. & Water Well Maint. Div. Superintendent

Workover Engrg. & Tech. Srvcs. Div. General Supervisor

Drilling Division 3 Superintendent

Drilling Division 3 Superintendent

Wellsites Division Superintendent

Drilling Division 4 Superintendent

Drilling Division 4 Superintendent

Special Projects Superintendent

Drilling Division 5 Superintendent

Figure 1-C-1

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2.0

RESPONSIBILITIES 2.1

Drilling Foreman The Drilling Foreman has a diverse set of responsibilities which are very critical in achieving safe drilling operations. On Contractor operated drilling rigs, the Foreman is the primary liaison between Saudi Aramco and the Contractor. On Company owned rigs, he is the primary site leader, directing all rig operations. Since his responsibilities are numerous and diverse, the following sections, 2.1.1 through 2.1.7 will only cover his main duties: 2.1.1

Well and Camp Location: A)

Inspect new well location to ensure well site, roads, power line crossings, water well location and campsite are within acceptable limits. i) ii)

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Well site and road dimensions must conform to SAES-B062 (See Appendix) Rig equipment that is being transported to the new well site should clear the power lines as specified in section 2.1.2 (B).

B)

Insure the flare pit (usually located south of the spud point) is positioned down-wind of the derrick on all wells except Khuff and Exploratory.

C)

Two flare pits will be available for Khuff and Exploratory wells. The advantage of having a second flare pit is that in the event of an uncontrolled flow and should the flare go out, then the gas can be safely diverted to the second flare pit. This minimizes the chances of the flow being ignited by the generators, and eliminates the necessity or relocating the rig equipment. Depending on the rig layout, the second pit could be on the easterly or westerly side of the location; the first pit is usually located south of the spud point. See Appendix for details.

D)

Camp location for all wells (except Khuff and Exploratory wells) are selected based on a central site that is in proximity of a number of upcoming wells to be drilled. This practice eliminates unnecessary and costly camp moves. It is important to note that the camp should never be located within walking distance from the rig.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

C

June 2006

GENERAL INFORMATION ORGANIZATION AND RESPONSIBILITIES

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E)

2.1.2

The rig camp should be in a northerly direction and should be no less than 3 to 4 Kms from the well site for all Khuff and Exploratory wells. This distance would allow the rig personnel to concentrate on controlling the well at the rig site, rather than having to worry about evacuating the camp in case of an emergency.

Rig Move: A)

Witness the rig move. Insure safety guidelines are being followed at all times while moving the rig and related equipment to the new well location.

B)

When transporting rig equipment under power lines, clearance distance becomes important to prevent line severing and electrocution. The following guidelines are used in determining safe clearance distance. i) ii)

8 feet for 69 kV or greater transmission lines. 5 feet for less than 69 kV transmission lines.

When the above clearances are not possible to attain, then every effort should be made to find a different rout to transport the rig equipment. If re-routing is not possible or does not provide the necessary clearance, then de-energizing the power line is considered as the last resort. C) 2.1.3

Witness setting of the main camp.

Program Execution: A)

Adhere to drilling, supplementary and completion programs. Review contents of the program to ensure all steps are fully understood. If unclear, contact the Superintendent or Drilling Engineering for clarification and consultation.

B)

Discuss the program with the Assistant Foreman, contract rig Supervisor and Driller to ensure all the steps are clearly understood.

C)

Any changes from the program will need to be discussed with the Superintendent to ensure that all the related facts have been considered.

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DRILLING MANUAL

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2.1.4

2.1.5

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Communication: A)

Prepare the daily rig activities morning and afternoon reports and transmit to the Superintendent.

B)

Communicate with Superintendent regarding possible changes to drilling programs based on operational requirements.

C)

Obtain advice from Drilling Engineering to improve drilling techniques and as well conditions dictate.

D)

Talk to Service Company representatives regarding operation of their equipment. The operation of each equipment should be fully understood prior to running in the well.

E)

Discuss with Superintendent new ideas and suggestions to improve operating performance and safety procedures. The Foreman is in the best position to observe and experience firsthand rig activities.

Rig Operations A)

Directly supervise important rig operations such as nippling up/ down BOPE, running casing/liner, making up bottom hole assemblies, logging/perforating operations, drilling through hydrocarbon and potentially problem zones, etc.

B)

Witness all non-routine and critical work, e.g. cementing, fishing, drill stem testing, kick circulation, testing of BOPs, completion operations, tripping, etc.

C)

Monitor performance of the bit (weight and RPM) and decide on when to pull a bit. Determine bit wear grading and replace worn out equipment.

D)

Order materials and equipment from the Toolhouse in anticipation of upcoming need. See that all equipment necessary for drilling and completing the well, as well as maintaining the rig, is at the rig site.

E)

Schedule Service Company to perform work on the well as needed. Provide sufficient lead-time when contacting the Service Company.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

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2.1.6

2.1.7

F)

Ensure all work performed on the rig is being performed in a safe and efficient manner.

G)

Conduct daily inspection and provide proper daily maintenance of the nearby water supply well.

Record Keeping A)

Casing, tubing and drill pipe tally.

B)

Tour sheets.

C)

Casing cementing details.

D)

Wellhead and tree work (pack-off energizing and testing, bonnet testing, etc).

E)

Inspect and record condition of bottom hole assemblies on all trips. Replace equipment as necessary.

F)

Maintain current pre-recorded information kill sheet.

G)

Prepare other Saudi Aramco forms and paperwork as needed.

Miscellaneous A)

Training of the Assistant Foreman

B)

Conduct periodic well control and disaster drills

C)

Participate in scheduled rig inspections

D)

Prepare accident reports as necessary

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2.2

Drilling Engineer The Drilling Engineer is primarily responsible for providing technical support to the rig operations to which he is assigned. He uses his knowledge and expertise to advise and recommend solutions to problems and find cost effective ways of performing rig work. He works closely with the Drilling Foreman and various organizations within Saudi Aramco to ensure all requirements are met while drilling the well. The following sections, 2.2.1 through 2.2.6, outline his responsibilities in more detail: 2.2.1

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Drilling Programs A)

The engineer is responsible for preparing and publishing the approved drilling program at least one week in advance of drilling commencement for Development wells and at least two weeks in advance for Deep Gas and Exploratory wells.

B)

Prior to preparing the program, the engineer should thoroughly research the drilling practices and problems encountered in adjacent wells. He is also expected to contact the Geologist, Production and Reservoir Engineers in charge of the field or area where the well is to be drilled to obtain important reservoir information, such as pressures, fluctuation of injection trends, facility shut-downs, depth of horizons, potential loss circulation zones, dip angle, etc. He should then design or modify the standard program (Well Menu) to include this information which could avoid potential problems while drilling the well.

C)

The engineer will check the surplus material list and include in the program usable materials in order to reduce inventory. Surplus material can be used as long as they continue to meet specifications and are acceptable alternatives without compromising performance and safety.

D)

As field conditions dictate, the engineer will prepare Supplements to the original program in order to revise operating procedures or provide additional direction to the Foreman. The Supplements should state the purpose it is being issued for and what problem or change in condition has necessitated the preparation of the supplement. A supplement program should be issued ahead of work start-up. Sometimes, temporary handwritten directions are faxed to the Drilling Foreman due to time constraints while the supplement is being prepared.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

C

June 2006

GENERAL INFORMATION ORGANIZATION AND RESPONSIBILITIES

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E)

Occasionally, a drilling program will be approved but not used due to schedule changes. In such a case, the engineer is responsible for checking all the contents of the program to insure current data is being used; if necessary, he will issue a supplement to the program. For development wells, this program review will be done if the elapsed time between program and spud date exceeds six (6) weeks. On exploration wells, it is a judgement decision made by the Supervisor or General Supervisor.

F)

The engineer will design the cement program depending on the mixing/displacement time calculations and bottom hole temperatures. If cement additives are to be used, he will coordinate lab testing on field samples (cement and mix water) by the Service Company and the Saudi Aramco Laboratory ahead of time in order to eliminate all uncertainties Final confirmation tests are coordinated by the Drilling Engineer after supervising the mixing of chemicals on site, for 13-3/8”, 95/8”, 7” and 4-1/2” liners on Khuff/Pre-Khuff wells. The Drilling Engineer will also witness these cement jobs.

G)

The engineer will calculate the mud weight to provide the required overbalance for proper well control. Supervisor should be consulted if diverting from the established guidelines, as follows: i) ii) iii)

Known water bearing zones Known oil & gas bearing zones Wildcats/outpost wells

100 psi *300 psi Based on review of offset wells and/or judgement decision by the Gen. Supvr. and Manager.

* When drilling oil wells with good offset control, calculate the overbalance by taking the reservoir pressure and lost circulation information into consideration. In these cases, the overbalance could be reduced to the range of 200 to 300 psi. Conversely, if sufficient offset information is not available, then use the minimum 300 psi overbalance in the calculations. For Khuff/PreKhuff wells, the 300 psi overbalance guideline will be adhered to at all times.

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H)

The engineer will calculate/design an optimum hydraulics program to maximize hole cleaning and rate of penetration based on the available rig equipment (pumps, DCs, etc.). He will study the offset wells and recommend a suitable and costeffective bit program depending on the lithology of the formations being drilled.

I)

The Drilling Engineer will estimate the target time using the standard targets for each area for Development wells. For Exploratory/outpost wells, the engineer will review available offset well data and assign a realistic target time estimate.

J)

Cost estimate will be prepared for each program or supplement using the unit price book and Service Company price list.

K)

Program verification: The Drilling Engineering Supervisor is responsible for reviewing the program with the engineer. The Supervisor is to pay special attention to mud weight in case of questionable pressures, and ensure the drilling program provides safe direction and is both practical and cost effective.

L)

The final completion of a well will be discussed between the Drilling, Production and Reservoir Engineers, and will conform to the requirements. The Drilling Engineer is responsible for insuring the availability of all completion equipment. If the desired equipment is not available, compatible substitute equipment is an option provided the proponent is in agreement. The engineer will include in the completion all drift sizes of tubing, nipples, crossovers, etc., and the type of packer and completion fluid. As a final step, he will investigate the possibility of performing a stimulation to remove formation damage and improve well productivity.

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Drilling & Workover Engineering Department CHAPTER 1 SECTION

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2.2.2

Communication The Drilling Engineer must be a good listener and communicator. He should establish dialog and close contact with the Forman, his Supervisor. Drilling Superintendent, other Drilling Engineers, Mud and Cement Lab Experts, Toolhouse and Contractor personnel, Geologist, Reservoir and Production Engineers to exchange information when necessary. Periodic field visits to the rig help enhance his working relationship with the Foreman and rig contract personnel.

2.2.3

Rig Surveillance A)

The Drilling Engineer will keep abreast of work progress on his rig(s). On all wells, the engineer will plot the well drill time progress on a daily basis and ensure that the well work is proceeding as planned. If progress is slower than expected, he will investigate the reasons and make recommendations to remedy the situation. The engineer is expected to anticipate the technical needs of the rig and keep the Foreman duly advised. If trouble is experienced on a particular job, the Drilling Engineer and the Foreman will determine the cause and submit an action plan. The engineer is expected to witness all subsequent rig jobs until the problem is resolved.

B)

The engineer is responsible for picking the casing points, coring points and total depth for the following formations: i) Ahmadi

When 13-3/8” casing is set 50’ below Ahmadi ii) K. S. Member Water Supply wells (nominal 9-5/8” C.P, 500’ below K.S.) iii) Shu’aiba Water Supply/Producer/Water Injection wells (nominal 9-5/8” C.P.) iv) Arab-D/Hanifa/Fadhili Producer/Water Injection wells (nominal 7” C.P.) v) Khuff/Pre-Khuff This is the responsibility of the Wellsite Geologist The engineer will inform the Foreman depth of drill time picks and all pertinent picks (core points, casing points, TDs, Etc.) on the Tour Sheet. He will sign his name since this is the official field record for the well.

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C)

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At the request of the engineer, an open hole caliper log is run prior to running casing or liner. The engineer will obtain results of the log and will calculate the cement volumes based on the bore hole geometry. The cement volume excess should be as follows: Full Casing Strings

200 – 250 cubic feet of excess, more than the caliper volume.

Liners

500 – 700 feet of rise around the DP (with the hanger setting tool in place).

D)

The drilling engineer will witness all perforating jobs for production, cement or injectivity tests. He will discuss with the Service Company the alternatives to best achieve the objective, i.e. deep penetration, underbalanced perforating, large entry holes, gun length, etc.

E)

The engineer will witness all open hole and cased hole Drill Stem and Production Tests, and he will be responsible for preparing a detailed testing procedure that satisfies the test objectives. He is responsible for coordinating the testing equipment and procedures. He is to discuss all phases of the operation with his Supervisor and Foreman so that the required data can be collected with minimum risk to operations.

F)

On deep wells, the drill string requirements should be calculated for each section of the hole. The Forman and Supervisor must be informed if the equipment in use is not adequate and needs to be modified.

G)

The engineer will keep a continuous watch on the mud properties and propose changes to the system as drilling parameters also change.

H)

The engineer is responsible for providing technical information on tubulars ( e.g. collapse, burst, hardness, etc.) to the Forman as the need arises and provide recommendations on inhibitors.

I)

When running unusual or new equipment, or trial testing a new procedure, the engineer should be fully informed of the details and he should witness it while being implemented on the rig.

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2.2.4

Completion Report The Drilling Engineer will prepare completion reports for his well(s) and submit to the Supervisor within one (1) week of rig release for Development wells and within three (3) weeks for Exploration or Khuff wells. It is highly recommended for the engineer to compile the drilling morning reports on a daily basis in order to meet the completion submission deadline.

2.2.5

Training, Seminars, Forums and Courses A)

It is the engineer’s responsibility to stay abreast with new technology. He must attend courses, seminars and forums, time permitting, in order to enhance his knowledge of drilling engineering aspects.

B)

The engineer will devote significant time and effort to mentor and train young engineers. He will expose the young engineer to all his responsibilities regarding office and fieldwork. Following a specified elapsed time, the young engineer should be on his own and be able to perform the normal duties of a Drilling Engineer.

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GENERAL INFORMATION EMERGENCY RESPONSE PLAN

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EMERGENCY RESPONSE PLAN 1.0

ONSHORE 1.1 The Document 1.2 Purpose 1.3 Content 1.4 Update

2.0

OFFSHORE 2.1 The Document 2.2 Purpose 2.3 Content 2.4 Update

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GENERAL INFORMATION EMERGENCY RESPONSE PLAN

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EMERGENCY RESPONSE PLAN 1.0

2.0

ONSHORE 1.1

The Document: An Emergency Response Plan has been available since the early 1980s in the form of a General Instruction, GI-1850.001. The GI is entitled “Onshore Contingency Plan”. It is periodically updated to reflect changes in responsibility and policy. The most current revision is dated 08/01/1996. A copy of GI 1850.001 can be found in Chapter XI, Appendix A.

1.2

Purpose: GI 1850.001 contains the Contingency Plan for a disaster occurring at any onshore wellsite during drilling or workover operation, or when a Producing organization has turned over responsibility for well control to the Drilling and Workover organization.

1.3

Content: The GI contains clear instructions and guidelines on who reports the emergency, how it should be reported, which organizations are responsible for taking action, and what are some immediate steps to take to gain expedient control of the well. The document also provides guidance on intentional well ignition, cost accounting, periodic disaster drills, documenting and after-the-fact critiquing of the Contingency Plan implementation.

1.4

Update: GI-1850.001 will be updated every 3 years to assure the document stays current with the ever-changing requirements. Proposed modifications by individuals should be forwarded to the General Supervisor of Workover Engineering and Technical Services Division for evaluation and eventual inclusion into the next update of the GI.

OFFSHORE 2.1

The Document: An Offshore Emergency Response Plan had been available for sometime as part of the Department Instruction Manual, DIM-1700.001. It was converted to a General Instruction, GI-1851.001 during the last quarter of 1998 for ease of document storage, access and updating. The GI is entitled “Drilling and Workover Operations Offshore Contingency Plan”, and it was last updated as DIM-1700.001 in December 1996. A copy of this new GI 1851.001 can be found in Chapter XI, Appendix A.

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2.2

Purpose: GI 1851.001 contains the Contingency Plan for a disaster occurring at any offshore wellsite during drilling or workover operation, or when Producing has turned over responsibility for well control to the Drilling and Workover organization.

2.3

Content: The GI contains clear instructions and guidelines on who reports the emergency, how it should be reported, and what are some immediate steps to take to gain expedient control of the well. The document clearly spells out the responsibilities of each organization that is required to provide support, including the Marine Department which provides crucial oil spill and platform fire containment equipment and services. In addition, the GI also outlines the criteria used in deciding on intentional well ignition, procedures for cost accounting, periodic disaster drills, documenting and after-the-fact critiquing of the Contingency Plan implementation.

2.4

Update: GI-1851.001 will be updated every 3 years to assure the document stays current with the ever-changing requirements. Proposed modifications by individuals should be forwarded to the General Supervisor of Workover Engineering and Technical Services Division for evaluation and eventual inclusion into the next update of the GI.

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GENERAL INFORMATION COMMUNICATION SYSTEMS

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COMMUNCIATION SYSTEMS 1.0

GENERAL

2.0

SYSTEMS 2.1 ESU (Extended Subscriber Unit) 2.2 IMTS (Improved Mobile Telephone System) 2.3 SSB (Single Side Band Radio) 2.4 Satellite Communication 2.5 Drilling Circuit Radio

3.0

REPAIRS

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COMMUNCIATION SYSTEMS 10

GENERAL 1.1

2.0

Communication between the rigs and camp to the Drilling office is of paramount importance during daily rig operations and emergencies. The rig Foreman must have the capability to consult the Superintendent and Engineering on a daily basis as drilling activities progress. He also needs to be able to call the Toolhouse to order required materials and equipment, and contact Service Companies to schedule upcoming rig work. During critical operations or emergencies, the Foreman needs to keep the Superintendent fully informed of the transpiring events, and be able to discuss action alternatives as well conditions dictate. The importance of an effective communication system cannot be stressed enough.

SYSTEMS Every drilling rig is equipped with more than one communication system to ensure uninterrupted service. Each system has limitations, however, a combination of these systems complement each other. 2.1

ESU This is the primary communication service for all rigs. The ESU, Extended Subscriber Unit, radio equipment operates in UHF at a range of up to 60 kms from the rig site. This microwave radio system was originally designed for narrow band voice transmission only, however, it is also being used for sending and receiving fax and low speed data transmission via a modem. Communication on the ESU system is sometimes not possible due to topographic blind spots, such as sand dune valleys.

2.2

IMTS This is the backup to the ESU system, designed for use in case of emergency. IMTS (Improved Mobile Telephone System) is a 25+ year-old system and carries 4 channels; it is used for voice communication only. Since spare parts are no longer manufactured, the IMTS equipment will eventually be phased out in favor of newer state of the art equipment. There are geographical “dead spots” where communication is not possible due to limitations in antenna distribution and signal strength.

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2.3

SSB Single Side Band Radios (SSBs) are mounted on every rig Foreman’s vehicle and on all offshore rigs. SSB uses high frequency signal and is monitored by HYZ-3, more commonly known as Y-3. It is possible to make a telephone patch through HYZ-3 on the SSB radio. First call HYZ-3 and tell the operator that you wish to make a telephone patch; give him the number you want to call. If calling the rig from the Drilling Office, call Y-3 and tell the operator the rig number you would like to contact. The Y-3 telephone number is 8764088. SSB communication can be completely lost for hours since the signal is sensitive to weather conditions.

2.4

Satellite Communication Saudi Aramco has units available which have the capability to communicate with remote sites through Mini-m satellite. The units are compact, battery charged, portable and easy to operate. The major factor of these equipment is the high operating unit rate of satellite airtime.

2.5

Drilling Circuit Radio Every rig is equipped with a drilling circuit radio. Two channels are available: A or F-1 (while drilling in Northern area) and B or F-2 (while drilling in Southern area).

3.0

REPAIRS All communication problems should be reported to “Communication Repair” by calling 904. A trouble ticket is issued and the faulty communication equipment is repaired or replaced thereafter.

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RIG SPECIFICATIONS

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RIG SPECIFICATIONS 1.0

GENERAL

2.0

RIG SPECIFICATIONS DATA SHEETS (LAND RIGS) 2.1

ARABIAN DRILLING COMPANY 2.1.1 ADC-3 2.1.2 ADC-4 2.1.3 ADC-12 2.1.4 ADC-14 2.1.5 ADC-15 2.1.6 ADC-16 2.1.7 ADC-21 2.1.8 ADC-23 2.1.9 ADC-28 2.1.10 ADC-29 2.1.11 ADC-31 2.1.12 ADC-32 2.1.13 ADC-34 2.1.14 ADC-35 2.1.15 ADC-36 2.1.16 ADC-39

2.2

RAWABI DALMA LTD. 2.2.1 DALMA-1 2.2.2 DALMA-2 2.2.3 DALMA-7 2.2.4 DALMA-8 2.2.5 DALMA-9 2.2.6 DALMA-10

2.3

DRILLING & PETROLEUM SERVICES CO. 2.3.1 DPS-4 2.3.2 DPS-43 2.3.3 DPS-44 2.3.4 DPS-45 2.3.5 DPS-46

2.4

POOL ARABIA LIMITED 2.4.1 PA-70 2.4.2 PA-77 2.4.3 PA-115 2.4.4 PA-117 2.4.5 PA-125 2.4.6 PA-128 2.4.7 PA-203 2.4.8 PA-207 2.4.9 PA-210 2.4.10 PA-212 2.4.11 PA-263 2.4.12 PA-295 1

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2.4.13 2.4.14 2.4.15 2.4.16 2.4.17 2.4.18 2.4.19 2.4.20 2.4.21 2.4.22 2.4.23

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PA-312 PA-393 PA-575 PA-654 PA-718 PA-785 PA-854 PA-858 PA-859 PA-860 PA-866

2.5

PRECISION DRILLING SERVICES 2.5.1 PD-144 2.5.2 PD-157 2.5.3 PD-173 2.5.4 PD-174 2.5.5 PD-786 2.5.6 PD-787

2.6

SAUDI ARAMCO DRILLING CO. 2.6.1 SAR-102 2.6.2 SAR-103 2.6.3 SAR-151 2.6.4 SAR-153

2.7

ZP ARABIA DRILLING CO. 2.7.1 SINO-1 2.7.2 SINO-2 2.7.3 SINO-3 2.7.4 SINO-5 2.7.5 SINO-6 2.7.6 SINO-7 2.7.7 SINO-9 2.7.8 SINO-10 2.7.9 SINO-12 2.7.10 SINO-18

2.8

SINO PAC DRILLING COMPANY 2.8.1 SP-1

2.9

SAUDI ARABIA SAIPEM LTD. 2.9.1 SSA-29 2.9.2 SSA-46 2.9.3 SSA-91 2.9.4 SSA-95 2.9.5 SSA-101 2.9.6 SSA-102 2.9.7 SSA-201 2.9.8 SSA-202

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3.0

RIG SPECIFICATIONS DATA SHEETS (OFFSHORE RIGS) 3.1

ARABIAN DRILLING COMPANY 3.1.1 ADC-17

3.2

ENSCO ARABIA LIMITED 3.2.1 ENS-76 3.2.2 ENS-95 3.2.3 ENS-96 3.2.4 ENS-97

3.3

POOL ARABIA LIMITED 3.3.1 PA-145 3.3.2 PA-656 3.3.3 OS-655

3.4

PRIDE ARABIA COMPANY 3.4.1 PM-1 3.4.2 PND-1

3.5

ROWEN ARABIA DRILLING CO. 3.5.1 RM-22 3.5.2 CR-36 3.5.3 AR-37 3.5.4 RC-42

3.6

SAUDI ARABIAN SAIPEM LIMITED 3.6.1 PN-2 3.6.2 PN-5

3.7

SAUDI ARAMCO DRILLING CO. 3.6.1 SAR-201

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RIG SPECIFICATIONS 1.0

GENERAL 1.1

During drilling operations, it becomes necessary at times to perform rig work, such as fishing or running casing, that requires rig equipment to be operated near the designed limit. If this limit is exceeded, then the equipment is likely to fail thus causing financial loss and delays in the drilling operations. It is common practice to review the rig equipment specifications in order to operate within its capabilities and limitations.

1.2

Each and every rig is supplied with different equipment. components of a rig can be categorized as follows: A) B) C) D) E) F)

1.3

2.0

The main

Rig equipment Rig power Mud system & pump BOP equipment Safety Equipment Drill pipe & drill collars

Important information about a rig is the depth limitation or capacity. Every piece of equipment has a maximum operating limit before failure occurs. In the case of the rig depth limitation, it is based on the load the derrick structure can sustain during operations. The limit is calculated based on the drill pipe size (and weight) to be run, additional equipment on the drill pipe, and the amount of overpull which might be needed in case of getting stuck. There are also safety factors included in the limitation to account for normal wear and tear.

SPECIFICATION DATA SHEETS Since rig contractors are periodically changed, new rig specification sheets are required. Also, existing rig equipment is sometimes modified or replaced. For these reasons, it is important to update the Specification Data Sheets in section 2.0 of this chapter every time the Drilling Manual is revised. As of May, 1999, there were 23 onshore and 2 offshore drilling rigs in operation.

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2.1.1

ADC-3 (ONSHORE RIG)

A)

Year Built

:

1978

B)

Rig Equipment 1. Drawworks – Type 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE Pyramid Open Face Cantilever Type, 143’ x 25’ 700,000 lbs. Varco TDS-11SA National C-375 (37-1/2”), Independent drive National – 660-H-500, 500 Tons (Hook/Block Combination) National P-400, 400 Tons Static 20’ (clearance) from ground to rotary beam Not Operating; ADC system in place – ID3

Rig Power 1. Engine Power 2. Drawworks

: :

3. 4. 5.

: : :

5 x Caterpillar D398, 900 hp National 110-UE, 1500 hp 2 x GE 752 Shunt motors – 800 hp each 2 x G-D PZ-11, 1600 hp, 4 x GE 752 Shunt motors – 800 hp each 1 x GE 752 Shunt motor – 900 hp, 180 RPM, 30000 ft-lbs torque 1 x AC Motor, 800 hp each, 37,500 ft-lbs torque

: : : : : : :

2 Gardner Denver PZ-11, 1600 hp 2100 bbl. capacity, 128 bbl trip tank 2 x Derrick-Flo Line Cleaners Swaco 2 x 12” cones, 1000 gpm Swaco 20 x 4” cones, 1000 gpm None Swaco horizontal, 1000 GPM

C)

D)

Mud pumps Rotary Top Drive

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

E)

BOP Equipment (per Saudi Aramco Class ‘A’ Standard) 1. Accumulator : 3000 psi, Koomey 2. Choke manifold : 5000 psi WP, sour service 3. BOPs : Cameron U 13-5/8” double ram, 5000 psi, H2S trim Cameron U 13-5/8” single ram, 5000 psi, H2S trim Hydril GK 13-5/8” x 5000 psi, H2S trim Hydril MSP 21-1/4”, 2000 psi, H2S trim

F)

Safety Equipment

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

62 Fire extinguishers, 2 fire pumps (one at main camp), 2 portable 3-way, continuous monitoring detectors (O2/LEL/H2S), 1 cascade system, 18 Scott Air Pack SCBAs, 5 eye wash stations, 3 shower units, 5 wind socks, 1 Bauer (K-146) breathable air compressor.

HWDP Drill collars

: : : :

5” Grade G, 19.5 lbs./ft, 10,000 ft. 4”, 14#/ft, XT39, G-105Y, 16,000 ft. 60 of 5”, 80 of 4” 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”, 15 of 3-3/8”

H)

Depth Capacity

:

16,000 ft

I)

DF – GL Elevation Clearance below DF

: :

26.0 ft 0.0 ft

2. 3.

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2.1.2

ADC-4 (ONSHORE RIG)

A)

Year Built

:

1973

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Gardner Denver 1100E – 1500 HP with auxiliary brake Lee C. Moore 25’ x 145 ft 769,000 lbs. Varco TDS 9S National C375, 37 ½” Continental Emsco – 350 Ton National P-400 – 400 Ton Specify structure type and load bearing capacity? Totco, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x CAT D398, 925 HP ea. w/ xxxx KVA generators 2 x GE 752 motors, 800 HP ea. 4 x GE 752 motors, 800 HP ea. GE 752 DC motor, 750 HP, Torque xxx Amps / xxxxx ft.-lbs Specify power & model? 700 HP, Torque xxx Amps / xxx ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x National 10 P 130 – 1300 HP ea. 1300 bbl. capacity with 60 bbl trip tank and 1100 bbl reserve 2 x Derrick Flo-line cleaners Swaco 212 / Swaco PO4C16 – 800 GPM ea. None Swaco model?– 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey model and model No. of stations? 3 1/8” Make? 5,000 psi WP, sour service Hydril MSP 21 ¼” annular, 2000 psi, Hydril GK 13-5/8” annular, 5000 psi, Cameron U 13-5/8” double ram, 5,000 psi, All H2S trimmed.

F)

Safety Equipment

:

74 fire extinguishers, 1 fire pump, 2 Gas detector, 1 H2S monitoring system, 1 Cascade system, 38 Scott SCBA`s, 3 eye wash stations, 1 shower at mud pits, 3 wind socks, 1 Bauer breathing air compressor, 1 foam unit

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5 Grade-G, 19.5 lbs/ft, 10000 ft, 3 ½” Grade-G, 13.3 lbs/ft, 10000 ft. 2 3/8” Grade-E 6.65 lbs/ft, 2000 ft. 60 of 5”, 100 of 3 ½” 9 of 9 ½”, 24 of 8 ½”, 24 of 6 ½”, 24 of 4 ¾”, 24 of 3 3/8”

H)

Depth Capacity

:

16,000 ft

I)

DF – GL Elevation Clearance below DF

: :

25.5 ft 21.5 ft

C)

D)

E)

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2.1.3

ADC-12 (ONSHORE RIG)

A)

Year Built

:

1986

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE – 1500 HP with auxiliary brake Lee C. Moore 25’ x 149 ft 710,000 lbs. National PS 350/500 – xxx Ton National C375, 37 ½” – xxx Ton Continental Emsco – 350 Ton National P-400 – 400 Ton Specify structure type and load bearing capacity? Totco, 6-pen

Rig Power 1. Engine Power

:

2. 3. 4. 5.

: : : :

4 x Caterpillar D398, 825 HP ea. 1 x Caterpillar D399, 100 HP w/ xxxx KW Generator 2 x GE 752 motors, 1000 HP ea. 4 x Reliance model motor, 1000 HP ea. 1 GE 752 DC motor, 750 HP, Torque xxx Amps / xxxxx ft.-lbs Specify make and model ? HP 1000, Torque xxx Amps / xxx ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Gardner Denver PZ10, 1300 HP ea 1500 bbls capacity with 120 bbl trip tank 2 x Derrick Flo-line cleaners Swaco 212 – 800GPM specify make size and capacity in GPM? None Swaco model – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, NL Shaffer / Koomey Type 20 3 1/8” 5,000 psi WP, sour service Hydril MSP 21 ¼” annular, 2000 psi, Hydril GK 13-5/8” annular, 5000 psi, Cameron UU 13-5/8” double ram, 5,000 psi, All H2S trimmed.

F)

Safety Equipment

:

33 fire extinguishers, 1 fire pump, 1 Gas detector, 1 H2S detector, 1 Cascade system, 22 Scott SCBA`s, 3 portable gas monitors, 6 H2S portable monitors, 4 eye wash stations, 4 wind socks, 2 showers at mud pits, 1 Bauer breathing air compressor, 1 foam unit

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5 Grade E, 19.5 lbs/ft., 10,000 ft., 3 ½” Grade G105, 13.3 lbs/ft, 10,000 ft. 70 of 5”, 99 of 3 ½” 7 of 9 ½”, 30 of 8 ½”, 30 of 6 ½”, 24 of 4 ¾”, 21 of 3 3/8”

H)

Depth Capacity

:

16,000 ft

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft 22.3 ft

C)

D)

E)

Drawworks Mud pumps Rotary Top Drive

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2.1.4

ADC-14 (ONSHORE RIG)

A)

Year Built

:

1975 (Mast Inspection, BOP upgrade to 10,000 psi with Choke Manifold and Mud System. New T. Block, Sub base Extension)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE (1500HP) Lee C. Moore 25’ x 149 ft 750,000 lbs. Varco TDS-11S Ideco 375E, 37 ½” National 660H – 500 Tons National P-400 Lee C. Moore, Casing 5,000,000 lbs, setback 7,000,000 lbs. Totco, 6 pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary

: : : :

5.

:

5 x Caterpillar D398TA, 910 HP ea. with 930 KW GE Generators. 2 x GE 752 motors – 750 HP ea. 4 x GE 752 motors – 750 HP ea. GE 752 DC motor – 750 HP, Torque Continuous 800 Amps Torque Intermittent 1500 Amps. AC motor – HP 800, Torque Continuos: 32,500 ft-lbs. Torque Intermittent: 50,000 Ft Lb.

C)

D)

Top Drive

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 5. Centrifuge 6. Degasser

: : : : : : :

2 x Gardner Denver PZ11, 800 HP ea. 3000 bbls capacity with 2 x 60 bbl trip tanks 3 x Derrick Flo-line cleaners Derrick 3 x 10” cone – 600 GPM Derrick 20 x 4” cone – 600 GPM None Swaco with type 30 Vacuum pump – 550 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Stewart & Stevenson Koomey Type 80 4-1/16”, 10,000 psi WP, sour service 2 x Cameron U 13-5/8”, 10,000 psi, double, 3 x Stewart & Stevensen 20 ¾”, 5000 psi, 1 x SS Q 26 ¾”, 3000 psi, double, 1 x Hydril GK, 13-5/8”, 5000 psi, 1 x Hydril MSP, 21 ¼”, 2000 psi, 1 x Shaffer, 30”, 1000 psi

F)

Safety Equipment

:

33 fire extinguishers, 1 fire pump, 1 Gas detector, 1 h2S detector, 1 Cascade system, 22 scott SCBA`s, 3 portable gas monitors, 6 H2S portable monitors, 4 eye wash stations, 4 wind socks, 2 showers at mud pits, 1 Bauer breathing air compressor, 1 foam unit

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade-G105, 19.5 ppf, 15,000 ft., 3 ½” Grade-G105, 13.3 ppf, 9,000 ft, 2-3/8” Grade-E, 6.65 ppf, 5,000 ft 50 of 5”, 50 of 3 ½” 30 of 6 ½”, 30 of 4 ¾”, 24 of 2 7/8”

H)

Depth Capacity

:

15,000 ft

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft 26.0 ft

E)

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2.1.5

ADC-15 (ONSHORE RIG)

A)

Year Built

:

2001

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Midcontinent U-1220 EB (1220 HP) w/ xxxxxxxx auxiliary Brake Dreco 25’ x 20’ x 146 ft. 1,300,000 lbs. (static) with 12 lines National Oilwell, PS 350/500 – xxx Ton Oilwell, Model? 37 ½” – xxx Ton Ideco Model? – 650 Tons National Model? – 650 Tons Dreco slingshot type, specify load capacity? Totco, 6 pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

6 x Caterpillar D398TA, 1000 HP ea. w/ xxxxx 1778KVA generators 2 x EMD D79 motor, 1000 HP ea. (Different HP? Please check) 2 x EMD D79 motor, 800 HP ea. GE 752 DC motor, 1000 HP Torque ------ Amps / ------- ft-lbs. GE 752 motor Torque ------ Amps / ------- ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x Gardner Denver PZ11, 800 HP ea. 4000 bbls mud & 1000 bbls drill water, 60 bbl trip tank 3 x Derrick Flo-line cleaners Derrick, 2 x 12” – 800 GPM / 12 x 4” – 800 GPM Swaco - SC4, Capacity GPM? Swaco – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

Stewart & Stevensen Koomey Unit, Type 80 10,000 psi WP, sour service 2 x Cameron U 13-5/8”, 10,000 psi, double, 3 x Stewart & Stevensen 20-3/4”, 5000 psi, 1 x SS Q 26-3/4”, 3000 psi, double, Hydril GK, 13-5/8”, 5000 psi, Hydril MSP, 21-1/4”, 2000 psi, Shaffer, 30”, 1000 psi

F)

Safety Equipment

:

80 Fire extinguishers, 1 Fire pump, 1 gas detector, 1 H2S detector, 1 cascade system, Scott SCBAs, 3 portable gas monitors, eye wash stations, 2 shower at mud pits, 3 wind socks, 2 foam units, 1 breathable air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5-1/2’ Grade E, 24.7 lbs./ft., 10,000 ft., 5” Grade G, 19.5 lbs./ft., 15,000 ft, 3-1/2” Grade G, 15.5 lbs./ft, 15,000 ft 25 of 5-1/2”, 30 or 5”, 30 of 3-1/2” 17 of 9-1/2’, 24 of 8-1/4”, 30 of 6-1/4”, 30 of 4-3/4”

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

31 ft 27 ft

C)

D)

E)

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2.1.6

ADC-16 (ONSHORE RIG) A) Year Built

:

1975

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1320EU, 2000 HP Dreco 30 ft x 152 ft. 1,200,000 lbs with 12 Lines National PS500 (PS2) National C375 National 650 Ton National P500 Dreco Schlumberger iD3 System, 26 function digital recorder

Rig Power 1. 2. 3. 4. 5.

: : : : :

5 x Caterpiller D399 – 1215 HP ea 2 x GE 752, DC motor – 1000 HP ea Check HP? 6 x GE 752 DC motor – 1000 HP ea GE 752 DC motor – 1000 HP Torque 1050 Amps / 54,000 ft.-lbs. GE 752 DC motor, Torque 1050 Amps / 54,000 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud Pits & Storage 3. Shale Shakers 4. Desander 5. Desilter 5. Centrifuge 6. Degasser

: : : : : : :

3 x National 12P160 (1600 HP) 2,000 bbl active, total 4,000 capacity 3 x Derrick Linear Motion Flo-Line Cleaner – 513 Derrick 3 cone Derrick 24 cone, None Derrick vacuum – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke Manifold 3. BOP’s

: : :

Cameron, 3,000 psi, 14 Stations 4-1/16'' 10,000 psi Shaffer 30” Annualr Preventer – 1000 psi, Hydril 21 ¼” Annualr Preventer – 2000 ps, 1X 13-5/8'' 5K Hydril Annular Preventer, 1X 26-3/4'' 3K Cameron Single RAM, 1X 26-3/4'' Cameron Double RAM, 2 X 13-5/8'' 10K Cameron Double RAM

F)

:

100 Fire extinguishers, 1 Fire pump, Air cascade system, 12 Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed gas detection system, Portable gas detection Equipment, 5 eye wash stations, 1 emergency shower, 4 x wind socks

Engine Power Drawworks Mud Pumps Rotary Top Drive

Safety Equipment

G)

Drill Pipes & Drill Collars 1. Drill Pipe : 2. 3.

HWDP Drill collars

: :

5 ½” Grade G, 24.7 lbs./ft, 12,000 ft., 5” Grade G, 19.5 lbs/ft, 15000 ft, 3-1/2” Grade G, 13.3 lbs./ft, 9,000 ft. 15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3-1/2” 18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H)

Depth Capacity

:

19,000 ft

I)

DF – GL Elevation Clearance below DF

: :

33.0 ft 27.0 ft

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2.1.7

ADC-21 (ONSHORE RIG)

A)

Year Built

:

1982

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Gardner Denver 3000 E (3000 HP) w/ 7838 Elmagco Auxiliary Brake L.C. Moore, 30’ x 26’ x 147 ft. 1,550,000 lbs. (static) with 12 lines Hydralift, Hydraulic HPS 500 – 500 Ton Continental Emsco, 37-1/2” – 750 Ton LC Moore, Crown / Travel Combination – 650 Tons Continental Emsco LB650 – 650 Tons L.C. Moore, slingshot, casing 1,500,000 lbs. setback 800,000 lbs. MD/Totco, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D399 – 1215 HP ea. w/ Kato 1050 KW generators 3 x EMD D79 DC motors – 1000 HP ea. 4 x EMD D79 DC motors – 800 HP ea. EMD D79 DC motor Torque 763 Amps / 24,000 ft-lbs. GE 752 DC motor Torque 1270 Amps / 36,000 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Gardner Denver PZ11, 1600 HP ea. 4000 bbl capacity with 1208 bbl. active and 120 bbl trip tank Derrick shakers, 3 x Derrick Fl-Line cleaners Harrisburg 2 x 12” cone – 1600 GPM Harrisburg 16 x 4” cone – 1600 GPM None Swaco Vacuum type Horizontal & Poor-by Vertical – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP Koomey w/ 14 stations and 40 x 11 gal. bottles 4 1/16” Cameron 10,000 psi WP, sour service Cameron 13-5/8” double ram, 10,000 psi, 2 x Cameron 13-5/8” single ram, 10,000 psi. 1 Cameron U 20-3/4” double ram, 3000 psi, 1 Cameron U 20-3/4” single ram, 3000 psi, 2 x Cameron U 26-3/4” single ram, 3000 psi, Hydril GL 13-5/8”, 5000 psi; Hydril MSP, 211/4”, 2000 psi, Shaffer 30” annular 1000 psi

F)

Safety Equipment

:

Fire extinguishers, 1 Fire pump, fixed gas detector system, 1 cascade system, Scott SCBAs, portable gas detectors, eye wash stations and showers, 3 wind socks, 1 foam unit, 1 breathable air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

: :

5.5” Grade G 24.7 ppf, 12,000 ft.; 5” Grade G, 19.5 ppf, 15,000 ft. 3-12” Grade G, 13.3 ppf, 9,000 ft. 30 of 5-1/2”, 50 of 5”, 30 of 3-1/2” 12 of 9-1/2”, 30 of 8-1/2’, 30 of 6-1/4”, 30 of 4-3/4”

C)

D)

E)

HWDP (Joints) Drill collars (Joints)

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

34.0 ft 27.0 ft

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2.1.8

ADC-23 (ONSHORE RIG)

A)

Year Built

:

1975 (Completely refurbished in 2005)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National Oil Well E-3000 Dreco, 30’ x 160 ft. 1,500,000 lbs. (static) with 12 lines National Oil Well PS750/500 National C-375 (37-1/2”) National – 750/500 National Oilwell, 750/500 Dreco, Load Casing 2,360,000 lbs. Schlumberger, ID Cubed with 26 functions digital recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D3512 – 1450 HP ea. 3 x GE 752 motor – 1000 HP ea. 6 x GE 752 motors – 1000 HP ea. Ind. Dr, GE 752 motor, 1000 HP, Torque 1050 Amps / 39500 ft.-lbs AC motor, 1400 HP, Torque 1600 Amps / 89,000 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x National 14P220 (2200 HP) 4000 bbl. capacity, 120 bbl trip tank 3 x Derrick-Flo Line Cleaner Derrick – 1000 GPM Derrick High G – 1600 GPM None Derrick – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey 10000 psi WP, Cameron, sour service Cameron UU 13-5/8” double ram, 10000 psi, Cameron U 13-5/8” double ram, 10000 psi, Hydril GK 13-5/8” x 5000 psi, Hydril MSP 20” and 20-1/4”, 2000 psi, All H2S trimmed

F)

Safety Equipment

:

105 Fire extinguishers, 2 Fire pump, 2 gas detector, 4 H2S detectors, 1 cascade system, 17 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 5 eye wash stations, 3 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5.5” Grade XD-105 24.7 ppf, 14,300 ft. 5.5” Grade S-135, 24.7 ppf, 7000 ft 4” Grade XD-105, 14.4 ppf, 9,860 ft. 41 of 5.5”, 53 of 4” 18 of 9-1/2”, 28 of 8-1/2”, 40 of 6-1/4”, 5 of 4-3/4”

H)

Depth Capacity

:

25,000 feet

I)

DF – GL Elevation Clearance below DF

: :

38.5 ft 28.5 ft

C)

D)

E)

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2.1.9

ADC-28 (ONSHORE RIG)

A)

Year Built

:

1981

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Gardner Denver 1100E (1500 HP) with Auxiliary brake Pyramid, 25 ft x 160 ft 1,000,000 lbs (static) with 12 lines TDS-11 SA, – 500 Ton Continental Emsco T375 37 ½” – 650 Ton (static) National 650-G500 – 650 Ton (Hook block combination) National P-400 – 400 Ton (static), 268 Ton (dynamic) Pyramid, Lo-lift Cantilever, casing xxxxxx lbs, setback xxxxxx lbs. Schlumberger ID3, 26 function digital data recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud Pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D-398TA – xxxx HP ea. w/ 1165 KVA generators 2 x GE 752 motors – xxxxx HP ea. 4 x GE 752 motors – xxxxx HP ea GE 752 DC motor – xxxxx HP, Torque ---- Amps / ----- ft-lbs. 2 x Reliance motors - 400 HP ea, Torque ---- Amps / ---- ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud Pits & Storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Gardner Denver PZ11, 1600 HP ea. 2000 bbl capacity with 50 bbl trip tank, 1 x Derrick 2000 Flo-Line Cleaner, 1x Derrick 503 Flo-Line Cleaner Swaco 2 x 12” Cone – 1000 GPM Swaco 16 x 4” Cone – 1000 GPM None Swaco Horizontal Vacum – 1200 GPM

: : :

3000 psi, CAD 24 x 11 gal bottles, 12 stations 3 1/8” Cameron FLS, 5000 psi Hydril MSP-20, 21 ¼” Annular 2000 psi, Hydril GK, 13 5/8"

C)

D)

E)

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs Annular,

5000 psi, Cameron U 13 5/8” single ram 5000 psi, Cameron U 13 5/8" double ram 5000 psi w/ tandem booster F)

Safety Equipment

:

81 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade-G, 19.9 lbs/ft, 10000 ft, 4” Grade-XD, 14.4 lbs/ft, 10,000 ft, 2 3/8” Grade-E 6.6 lbs/ft, 3000 ft. 60 of 5", 80 of 4" 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”

H)

Depth Capacity

:

18,000 ft with 4 ½” Drillpipe

I)

DF – GL Elevation Clearance below DF

: :

xx.x ft xx.x ft

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RIG SPECIFICATIONS

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2.1.10

ADC-29 (ONSHORE RIG)

A)

Year Built

:

1981

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Gardner Denver 1100E (1500 HP) w/ xxxxx auxiliary brake Pyramid, 160 ft high x 25 ft square base 1,000,000 lbs (static) with 12 lines TDS-11 SA, 500 Ton Continental Emsco T375, 650 ton static load Continental Emsco RA-52-6, 500 Ton National P-400, 400 Ton static, 268 Ton dynamic Pyramid, Lo-Lift Cantilver casing xxxxxx lbs, setback xxxxxx lbs Schlumberger ID3, 26 function digital data recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud Pumps 4. Rotary 5. Top Drive

: : : : :

5 x CAT D-398TA ---- HP ea. 2 x GE 752 DC motors – ------ HP ea. 2 x GE 752 DC motors f– ------ HP ea. 1 x GE 752 DC Shun Motor ---- HP, Torque ---- Amps / ----- ft.-lbs 2 x Reliance AC Motors 400 HP ea, Torque ---- Amps / ---- ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud Pits & Storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Gardner Denver PZ11, 1600 HP 1500 Bbl. active, 500 Bbl. reserve, …. Bbl. Trip tank 2 x Derrick 2000 Flo-Line Cleaner Derrick 2 x 12”cone – 1000 GPM Derrick 16 x 4” cone – 1200 GPM None Derrick, Vacu-Flo vacuum – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 24 x 11 gal bottles, 12 stations 3 1/8” Cameron FLS 5000 psi WP, sour service? Hydril MSP-20, 21 ¼” Annular 2000 psi, Hydril GK, 13 5/8" Annular 5000 psi, Cameron U 13 5/8" single ram 5000 psi, Cameron U 13 5/8" double ram 5000 psi with tandem Boosters, All H2S trimmed

F)

Safety Equipment

:

81 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.

G)

Drill Pipe & Drill Collars 1. Drill Pipe lbs./ft,

:

5” Grade G-105, 19.9 lbs/ft, 10,000 ft., 4” Grade XD-105, 14.4

2. 3.

HWDP Drill collars

: :

16,000 ft., 2-3/8" Grade E-95, ---- lbs/ft, 3,000 ft. 60 of 5", 80 of 4" 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”

H)

Depth Capacity

:

18,000 ft with 4 ½” Drillpipe

I)

DF – GL Elevation Clearance below DF

: :

xx.x ft xx.x ft

C)

D)

E)

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RIG SPECIFICATIONS

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2.1.11

ADC-31 (ONSHORE RIG)

A)

Year Built

:

2005

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1100 UE, 1500 HP with xxxxxx Auxiliary brake Dreco Beam Leg – 30 ft x 152 ft. 1,300,000 lbs (static) with 12 lines. Varco-TDS 11SA – 500 Ton Continental Emsco -T375 (37 ½”) – 650 Ton Dreco – 650 Ton TL-400 – 400 Ton National Sligshot, casing xxxxxx lbs, setback xxxxxx lbs?. Schlumberger ID3, 26 function digital data recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1321 HP ea, w/ 1165 KVA generators 2 x Joliet C75ZB3-15 motor – ------ HP ea. 2 x Joliet C75ZB3-15 motor – ------ HP ea. Joliet C75ZB3-15 motor, 750 HP, Torque ----- Amps / ------ ft.-lbs Make ? motor, 800 HP ea. Torque ---- Amps / ------ ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 12-P-1600 (1600 HP ea.) 2000 Bbls. with 76 Bbls. trip tank 2 x Derrick 513-Flo Line Cleaner Derrick 3 x 10 cone – 1200 GPM Derrick 20 x 4 cone – 1200 GPM None Derrick Vacu-Flo – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 12 station 4 1/16” Swaco 10,000 psi WP, sour service, Check? Cameron U 21 ¼” single ram 2000 psi, Cameron U 13-5/8” double ram 5000 psi, Cameron U 13-5/8” single ram 5000 psi, Hydril MSP 13-5/8” Annular 5000 psi, All H2S trimmed

F)

Safety Equipment

:

75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2 Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell nipple area, 4 portable gas/ H2S , 1 cascade system, 14 Scott Air Pack SCBAs, monitors, 4 eye wash stations, 4 shower-mud pits and 1 on CMT tank, 4 wind socks, 1 Bauer Breathable air compressor, please check all ?

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5” Grade G, 19.5 lbs/ft, 10,000 ft. 4” Grade G, 14 lbs./ft, 16,000 ft., 2 3/8” Grade E, lbs/ft, 3000 ft. 60 of 5” Grade ? ---- lbs/ft, 80 of 4” Grade ? ---- lbs/ft 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

xx.x ft xx.x ft

C)

D)

E)

2. 3.

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RIG SPECIFICATIONS

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2.1.12

ADC-32 (ONSHORE RIG)

A)

Year Built

:

2005

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1100 UE, 1500 HP with xxxxxx Auxiliary brake Dreco Beam Leg – 30 ft x 152 ft. 1,300,000 lbs (static) with 12 lines. Varco-TDS 11SA – 500 Ton Continental Emsco -T375 (37 ½”) – 650 Ton Dreco – 650 Ton TL-400 – 400 Ton National Sligshot, casing xxxxxx lbs, setback xxxxxx lbs?. Schlumberger ID3, 26 function digital data recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1321 HP ea, w/ 1165 KVA generators 2 x Joliet C75ZB3-15 motor – ------ HP ea. 2 x Joliet C75ZB3-15 motor – ------ HP ea. Joliet C75ZB3-15 motor, 750 HP, Torque ----- Amps / ------ ft.-lbs Make ? motor, 800 HP ea. Torque ---- Amps / 37,500 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 12-P-1600 (1600 HP ea.) 2000 Bbls. with 76 Bbls. trip tank 2 x Derrick 513-Flo Line Cleaner Derrick 3 x 10 cone – 1200 GPM Derrick 20 x 4 cone – 1200 GPM None Derrick Vacu-Flo – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 12 station 4 1/16” Swaco 10,000 psi WP, sour service Cameron U 21 ¼” single ram 2000 psi, Cameron U 13-5/8” double ram 5000 psi, Cameron U 13-5/8” single ram 5000 psi, Hydril MSP 13-5/8” Annular 5000 psi, All H2S trimmed

F)

Safety Equipment

:

75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2 Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell nipple area, 4 portable gas/ H2S , 1 cascade system, 14 Scott Air Pack SCBAs, monitors, 4 eye wash stations, 4 shower-mud pits and 1 on CMT tank, 4 wind socks, 1 Bauer Breathable air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5” Grade G, 19.5 lbs/ft, 10,000 ft. 4” Grade G, 14 lbs./ft, 16,000 ft., 2 3/8” Grade E, lbs/ft, 3000 ft. 60 of 5” Grade ? ---- lbs/ft, 80 of 4” Grade ? ---- lbs/ft 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

xx.x ft xx.x ft

C)

D)

E)

2. 3.

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2.1.13

ADC-34 (ONSHORE RIG)

A)

Year Built

:

2001 (Upgraded in 2005

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National Oil Well E-2000 (2000 HP) Lee C Moore, 30 x 142 ft. 1,300,000 lbs. (static) with 12 lines National Oil Well PS-500A Oilwell (37-1/2”) Oilwell – 650 Ton None Lee C. Moore Schlumberger, ID Cubed with 26 functions digital recorder

: : : :

5 x Caterpillar D3512, 1478 HP ea. 2 x GE 752 motor – 1000 HP ea. 6 x GE 752 motors – 1000 HP ea. Ind. Dr, GE 752 motor, 1000 HP, Torque 1000 Amps / 48,000 ft.-

:

GE B 20B2 motor, 1150 HP, Torque 1052 Amps/ 45,000 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Gardner Denver PZ-11 (1100 HP ea.) 4000 bbl. capacity, 120 bbl trip tank 3 x Brandt King Cobra Brandt Hydro-cyclone System – 1000 GPM Brandt Hydro-cyclone System – 1000 GPM None Brandt VG-1 Hyflow – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey 10000 psi WP, sour service Cameron UU 13-5/8” double ram, 10000 psi, Cameron U 13-5/8” single ram, 10000 psi, Hydril GK 13-5/8” x 5000 psi, Hydril MSP 30” annular 2000 psi, Hydril MSP 20-1/4” Annular 2000 psi, All H2S trimmed.

F)

Safety Equipment

:

92 Fire extinguishers, 2 Fire pump, 2 gas detector, 4 H2S detectors, 18 Scott Air Pack SCBAs, 4 portable gas / H2S monitors, 4 eye wash stations, 2 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 Mako Breathable air compressor, 1 foam unit.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5.5” Grade XD-105 24.7 ppf, 15,000 ft. 5.5” Grade S-135, 24.7 ppf, 7000 ft 4” Grade XD-105, 14.4 ppf, 10,000 ft. 30 of 5” and 100 of 4” 18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H)

Depth Capacity

:

19,000 ft

I)

DF – GL Elevation Clearance below DF

: :

35.0 ft 30.0 ft

C)

D)

E)

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary lbs. 5. Top Drive

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RIG SPECIFICATIONS

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2.1.14

ADC-35 (ONSHORE RIG)

A)

Year Built

:

2001

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National Oilwell E-2000 – 2000 HP Lee C Moore, 30” x 152 ft. 1,300,000 lbs. (static) with 14 lines National PS-500 (PS2) – 650 Ton Oilwell -B375 (37 ½”) – 650 Ton Oilwell – 650 Ton C. Emsco LB-500 – 500 Ton Lee C. Moore, double Cantilever, Load 1,300,000 lbs. Schlumberger, ID Cubed system with 26 function digital recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar 3512B, 1478 HP ea. 2 x GE 752, 1000 HP ea. 6 x GE 752, 1000 HP ea. GE 752, 1000 HP, Torque 750 Amps / 20,000 ft.-lbs. National motor, 1000 HP ea. Torque 800 Amps / 22,500 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Garden Denver PZL-11, 1600 HP ea. 4000 Bbls. total with 2000 Bbls active w/ 90 bbl. trip tank 3 x Brandt King Cobra King Cobra 3 cone – 500 GPM King Cobra 24 cone – 1200 GPM None Brandt DG-10 – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Shaffer, 14 station 4 1/16” Swaco 10,000 psi WP, H2S trim Shaffer 30” Annular, 2000 psi, Hydril 13 5/8” Annular - 5000 psi, Cameron 26 ¾” single ram, 3000 psi, Cameron 26 ¾” double ram, 3000 psi, Cameron 13-5/8” single ram, 10,000 psi, Cameron 135/8” double ram w/ shear, 10,000 psi.

F)

Safety Equipment

:

75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2 Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell nipple area, 4 portable gas / H2S monitors, Cascade system, 14 Scott Air Pack SCBAs, monitors, 4 eye wash stations, 4 showermud pits and 1 on CMT tank, 4 wind socks, Bauer Breathable air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill Collars

: :

5.5” Grade XD-105, 24.7 ppf, 15,000 ft., 5.5” Grade S-135, 24.7 ppf, 7000 ft, 4” Grade XD-105, 14.0 ppf, 10,000 ft., 15 of 6 5/8”, 50 of 5 ½” 18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

19,000 ft

I)

DF – GL Elevation Clearance below DF

: :

36.0 ft 30.6 ft

C)

D)

E)

18 of 102

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Drilling & Workover Engineering Department CHAPTER 1

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F

SECTION

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.1.15

ADC-36 (ONSHORE RIG)

A)

Year Built

:

2005

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National Oilwell E-2000 (2000 HP) with Wichita Auxiliary Brake Dreco, 160 ft. 1,555,000 lbs. with 14 lines National Oilwell TPS2-750A – 750 Ton Oilwell -A375 (37 ½”) – 750 Ton Dreco 760 TB 750-8A – 750 Ton OIlwell 650 – 650 Ton Dreco cantilever, Casing 1,000,000 lbs, setback 800,000 lbs. Schlumberger ID Cubed system, 26 function digital recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar 3512 – 1400 HP ea. w/ Kato 1200 KW generators 2 x– GE 752 rebuilt motor – 1000 HP ea. 6 x GE 752 rebuilt motor – 1000 HP ea. GE 752 rebuilt motor – 1000 HP, Torque 1100 Amps / 50,000 ft-lbs. NOV-GB motor, 1150 HP, Torque 1100 Amps / 60,286 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x National Oilwell 12-P-160 – 1600 HP ea. 5,000 bbl. capacity with 2000 bbl. active and 2 x 50 bbl. trip tanks 3 x Brandt King Cobra – xxx GPM Brandt King Cobra 3 x 12” cone – 1500 GPM Brandt King Cobra 24 x 3” cones– 1200 GPM None Brandt XC10 Horizontal Vacuum type – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD with 14 stations, 42 x 10 gal. bottles 4 1/16” Cameron 10,000 psi WP, H2S trimmed Hydril GK 13 5/8” Annular – 5000 psi, 2 x Cameron 13-5/8” double ram – 10,000 psi

F)

Safety Equipment

:

75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2 Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell nipple area, 4 portable H2S gas detectors, 1 cascade system, 14 Scott Air Pack SCBAs, monitors, 4 eye wash stations, 4 shower at mud pits and 1 at CMT tank, 4 wind socks, One Bauer Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill Collars

: :

5.5” Grade XD-105, 24.7 ppf, 14,000 ft., 5.5” Grade S-135, 24.7ppf, 7,500 ft., 4” Grade XD-105, 14.0 ppf, 10,000 ft., 15 of 6 5/8”, 50 of 5 ½” 18 of 9 ½”, 30 of 8 ½”, 15 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

21,000 ft

I)

DF – GL Elevation Clearance below DF

: :

39.0 ft 32.5 ft

C)

D)

E)

19 of 102

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Drilling & Workover Engineering Department CHAPTER 1 SECTION

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GENERAL INFORMATION

F

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.1.16

ADC-39 (ONSHORE RIG)

A)

Year Built

:

2005

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 80 UE, 1000 HP with xxxxxxx auxiliary brake LCM check ?, - 30’ x W’ x 160 ft. 500,000 lbs. static with 12 lines None National C275 (27 ½”) ----- Ton National 545, ---- Tons National P-400, ---- Tons Specify type Load?. casing xxxxxx lbs, setback xxxxxxxx lbs. Schlumberger ID Cubed system, 26 function digital recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x Caterpillar D398, ------ HP ea. with xxxx KW generators 1 x GE 752, ------ HP ea. 2 x GE 752 HT, ------ HP ea. 1 x GE 752, ----- HP, Torque ---- Amps / -------- ft.-lbs None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Garden Denver PZ10, 1000 HP ea. 2000 Bbls. 60 Bbls. trip tank 2 x Derrick Flo-Line Cleaner Brandt S12-2, 1000 GPM ? None None Swaco DG-10 horizontal, 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomy T20-220-3S Make and Model ? 5000 psi WP? Hydril 21 ¼” MSP 20 - 2000 psi, Hydril 13 5/8” GK - 5000 psi Cameron 13 5/8” double ram - 10000 psi,

F)

Safety Equipment

:

75 dry chemical fire extinguishers, 20 x CO2 fire extinguishers, 2 Fire pump, 3 gas LEL and 5 H2S detector fixed @ shaker and bell nipple area, 4 portable gas/ H2S , 1 cascade system, 14 Scott Air Pack SCBAs, monitors, 4 eye wash stations, 4 shower-mud pits and 1 on CMT tank, 4 wind socks, 1 Bauer Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill Collars

: : :

5” Grade G105, 19.9 lbs/ft, 5,000 ft. 50 of 5” Grade ---, ------ lbs/ft 6 of 9 ½”, 15 of 8 ½”

H)

Depth Capacity

:

11,000 ft

I)

DF – GL Elevation Clearance below DF

: :

26.0 ft xx.x ft

C)

D)

E)

20 of 102

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Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.2.1

DALMA-1 (ONSHORE RIG)

A)

Year Built

:

1979 (Mast upgraded and major refurbishment in May 2006)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Oilwell E2000 (2000 HP) w/ Baylor Eddy Current Auxiliary Brake Derrick Cantilever, 28’ x 19’ x 152 ft. 1,125,000 lbs with 12 lines. None Oilwell B37.5 (37 ½”) – 500 Ton Dreco Flat 760C crown - 583 Ton, Oilwell B500, traveling – 500 Ton Oilwell P.C500 – 500 Tons Derrick, Self Elevating, set back 500,000 lbs. M.D. Totco, 7-Pens

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 1200 HP ea. 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 850 HP ea. Ind. drive, GE 752 motor 1000 HP, Torque 800 Amps / 43,200 ft.-lbs. 2 x 350 AC Motor, 400 HP ea, Torque 700 Amps / 32,500 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Oilwell A-1700PT (1700 HP) 2000 bbl. active with 1000 bbl. reserve 2 x Derrick-Flo Line Cleaners Harrisburg 3 x 10” cone – 1600 GPM. National Oilwell, DSL-1600-5c – 1600 GPM. None Swaco 255 – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey ABB TX-280, 14 station 20 x 15 gal bottles Swaco 3 1/8”, 5000 psi WP, H2S trim Hydril MSP 21 ¼” Annular – 3000 psi, Hydril GK 13 5/8” Annular – 5000 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13 5/8” single ram, 5000 psi

F)

Safety Equipment

:

51 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas / H2S monitors, 3 eye wash stations, 1 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade G105, 19.5 ppf, 10,000 ft, 4” Grade XT-39, 13.3 ppf, 9,000 ft, 2 3/8” Grade E, 6.65 ppf, 5,000 ft. 50 of 5”, 50 of 3 ½” 18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾” and 15 of 3 1/8”

H)

Depth Capacity

:

10,000 ft with 5” Drillpipe

I)

DF – GL Elevation Clearance below DF

: :

33.0 ft 27.0 ft.

C)

D)

E)

21 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.2.2

DALMA-2 (ONSHORE RIG)

A)

Year Built

:

1981

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1320-4E (2000hp) Derrick Services International 1,000,000 (static) with 12 lines Varco-TDS 115 Oilwell C375 (37-1/2”) National Dynamic 650-G-500 (Hook/Block Combination) – 500 Tons National P500 Derrick, Tilt up Parallelogram, setback 500,000 lbs. M.D. Totco, RG100, 7 pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 1215 HP ea. 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 1000 HP ea. Ind. drive, GE 752 motor 1000 HP, Torque 800 Amps/36,800 ft.-lbs. 2 x 350 AC Motor, 400 HP ea, Torque 700 Amps / 32,500 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Oilwell, A-1700PT – 1700 HP, 1 x GD PZ8–800 HP 2458 bbl. capacity, 2 x 60 bbl trip tanks, 2 x 500 bbl cmt tanks 2 x Derrick-Flo Line Cleaner Harrisburg – 1600 GPM Harrisburg – 1600 GPM None Swaco – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey 80, 14 station, 16 x 11 gal bottles 3 1/16 10,000 up, 3 1/8 5000 psi down WP, sour service, Hydril MSP 21 ¼” Annular 2000 psi, Hydril 13 5/8” Annular 5000 psi, Cameron UU 13-5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi, All H2S trim

F)

Safety Equipment

:

51 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 14 x 30-min. SCBA, 16 Scott Air Pack SCBAs, 2 portable gas / H2S monitors, 3 eye wash stations, 1 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade-G, 19.5 ppf, 8,850 ft. 4” Grade-X 15.7 ppf, 14,000 ft. 57 of 5” 11 of 9 ½”, 32 of 8 ½”, 25 of 6 ½”, 30 of 4 ¾”, 15 of 3 3/8”

H)

Depth Capacity

:

10,000 ft with 5” Drillpipe

I)

DF – GL Elevation : Clearance below DF :

C)

D)

E)

22 of 102

33.5 ft 27.0 ft.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

June 2006

GENERAL INFORMATION

F

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.2.3

DALMA-7 (ONSHORE RIG)

A)

Year Built

:

1979

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE (1500 HP) Union Industries, 28’ x 19’, 142 ft. 750,000 lbs with 12 lines. Varco TDS 9 National C-375 (37 ½”) National – 350 Ton National – 400 Ton Union Industries M.D. Totco, 7-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1442 HP ea. with 1077 KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 850 HP Ind. drive, GE 752 motor – 1000 HP 2 x 350 AC Motor, 350 HP ea, Torque 700 Amps / 32,500 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x National 10-P-130 (1300 HP ea.) 2324 bbl. mud, 937 bbl. water, 120 bbl. trip tanks 3 x Derrick-Flo Line Cleaner Harrisburg – 1600 GPM Harrisburg – 1600 GPM None Swaco

3.

BOP Equipment 1. Accumulator 2. Choke manifold BOPs

: : :

3000 psi, Koomey type 80, 32 x 11 gal bottles 3 1/8” Choke, 5000 psi, source service Hydril GK 13 5/8” Annular – 5000 psi, Cameron U 13 5/8” double ram, 5000 psi

F)

Safety Equipment

:

50 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 17 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade G105, 19.5 ppf, 10,000 ft. 80 of 5” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

16,000 ft with 5” Drillpipe

I)

DF – GL Elevation Clearance below DF

: :

30.4 ft 23.1 ft.

C)

D)

E)

23 of 102

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

June 2006

GENERAL INFORMATION

F

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.2.4

DALMA-8 (ONSHORE RIG)

A)

Year Built

:

1979

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE (1500 HP) Union Industries, 28’ x 19’, 142 ft. 750,000 lbs with 12 lines. Varco TDS 9 National C-375 (37 ½”) National – 350 Ton National – 400 Ton Union Industries M.D. Totco, 7-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1442 HP ea. with 1077 KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 850 HP Ind. drive, GE 752 motor – 1000 HP 2 x 350 AC Motor, 350 HP ea, Torque 700 Amps / 32,500 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x National 10-P-130 (1300 HP ea.) 2324 bbl. mud, 937 bbl. water, 120 bbl. trip tanks 3 x Derrick-Flo Line Cleaner Harrisburg – 1600 GPM Harrisburg – 1600 GPM None Swaco

3.

BOP Equipment 1. Accumulator 2. Choke manifold BOPs

: : :

3000 psi, Koomey type 80, 32 x 11 gal bottles 3 1/8” Choke, 5000 psi, source service Hydril GK 13 5/8” Annular – 5000 psi, Cameron U 13 5/8” double ram, 5000 psi

F)

Safety Equipment

:

50 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 17 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade G105, 19.5 ppf, 10,000 ft. 80 of 5” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

16,000 ft with 5” Drillpipe

I)

DF – GL Elevation Clearance below DF

: :

30.4 ft 23.1 ft.

C)

D)

E)

24 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.2.5

DALMA-9 (ONSHORE RIG)

A)

Year Built

:

1979

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 11-VE Branham 575,000 lbs. None National C375 (37 ½”) National Hook / Block combination – 500 Ton National P500 – 500 Ton Branham M.D. Totco, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 398, 1050 HP ea. 2 x Schneider motor – 750 HP ea. 6 x Schneider motor – 750 HP ea. Chain Driven 160/3R None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x National 10-P-130 (1300 HP ea.) 3000 bbl. capacity, 2 x 63 bbl. trip tanks, 2 x 500 bbl. cmt. tanks 4 x Derrick-Flo Line Cleaner Derrick– 1200 GPM Derrick– 1200 GPM None Swaco – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey ABB TX-280, 6 stations, 20 x 15 gal. bottles 3 1/16” Cameron, 5000 psi, source service Hydril 13-5/8” Annular 10,000 psi, Cameron 13 5/8” double ram, 10000 psi, Cameron 13 5/8” single ram, 10,000 psi, All H2S trimmed.

F)

Safety Equipment

:

34 Fire extinguishers, 6-channel gas detection system, 5 x T-40 H2S personal monitors, 2 x Multigas Monitors (H2S, LEL, Oxygen, CO2), 5 wind socks, 18 x 30-min. Scott Air Pack SCBAs, Mako Breathable air compressor, 2 x Fire pumps, H2S sniffer, Cascade system, 2 x portable & 3 x fixed showers, 3 eye wash stations,

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade G105, 19.5 ppf, 10,000 ft. 3 ½” Grade G105, 13.3 ppf, 9,000 ft. 50 of 5”, 82 of 3 ½” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

12,000 ft.

I)

DF – GL Elevation Clearance below DF

: :

25.8 ft 20.0 ft.

C)

D)

E)

25 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

June 2006

GENERAL INFORMATION

F

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.2.6

DALMA-10 (ONSHORE RIG)

A)

Year Built

:

1979

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE (1500 HP) Union Industries, 28’ x 19’, 142 ft. 750,000 lbs with 12 lines. Varco TDS 9 National C-375 (37 ½”) National – 350 Ton National – 400 Ton Union Industries M.D. Totco, 7-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1442 HP ea. with 1077 KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 850 HP Ind. drive, GE 752 motor – 1000 HP 2 x 350 AC Motor, 350 HP ea, Torque 700 Amps / 32,500 ft.-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x National 10-P-130 (1300 HP ea.) 2324 bbl. mud, 937 bbl. water, 120 bbl. trip tanks 3 x Derrick-Flo Line Cleaner Harrisburg – 1600 GPM Harrisburg – 1600 GPM None Swaco

3.

BOP Equipment 1. Accumulator 2. Choke manifold BOPs

: : :

3000 psi, Koomey type 80, 32 x 11 gal bottles 3 1/8” Choke, 5000 psi, source service Hydril GK 13 5/8” Annular – 5000 psi, Cameron U 13 5/8” double ram, 5000 psi

F)

Safety Equipment

:

50 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 17 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade G105, 19.5 ppf, 10,000 ft. 80 of 5” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

16,000 ft with 5” Drillpipe

I)

DF – GL Elevation Clearance below DF

: :

30.4 ft 23.1 ft.

C)

D)

E)

26 of 102

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.3.1

DPS-4 (ONSHORE RIG)

A)

Year Built

:

1992

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Continental Emsco C-2 C. Emsco 150’ x 30 ft 1,560,000 lbs with 14 lines National Oilwell PS-500 Continental Emsco 37 ½” Continental Emsco 650 Ton BJ Dynaplex 5500 Specify structure type and load capacity? Varco RigSense, no. of recorder pens?

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar 3512-TA, 1435 HP ea. Each with 1025 KW generator 2 x GE 752, 1000 HP ea. 4 x GE 752, 1000 HP ea. 1 x GE 752 – 1000 HP, Torque --- Amps / ----- ft.-lbs 1 x GE 752 High Torque – 1000 HP, Torque --- Amps / ----- ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 5. Centrifuge 6. Degasser

: : : : : : :

2 x C. Emsco FB-1600, 1600 HP ea. 4000 Bbls capacity, xxxx Bbls Active, xxx Bbls trip tank 3 x Derrick Flo-line cleaners Specify Make & Model? – 1000 GPM Specify Make? / 1000 GPM None Brandt Specify Model? – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomy 2T60392 with 14 stations 4-1/16” Shaffer 10,000 psi WP, sour service 1 x Shaffer 21 ¼” annular – 1000 psi, 1 x Cameron 20 ¾” single rams, 3000 psi, 1 x Cameron 20 ¾” double rams, 3000 psi, 1 x Shaffer 21 ¼” annular - 5000 psi, 2 x Cameron 13-5/8” double ram, 10,000 psi

F)

Safety Equipment

:

80 fire extinguishers, 1 fire pump, Gas detection systems for H2S and explosive gasses, Cascade System, xx SCBA / xx SABA breathing sets, x portable gas monitors, x eyewash stations, x wind socks, shower at mud pits, breathing air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5 ½” Grade G-105, 21.9 lbs/ft., 12,000 ft., 5” Grade G 19.5 lbs/ft, 15000 ft, 3 ½” Grade G 13.3 lbs/ft, 9000 ft. 15 of 6-5/8”, 30 of 5 ½”, 50 of 5”, 50 of 3 ½” 18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

19,000 feet

I)

DF – GL Elevation Clearance below DF

: :

35 feet 30.0ft.

C)

D)

E)

27 of 102

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.3.2

DPS-43 (ONSHORE RIG)

A)

Year Built

:

1980

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Oilwell E 2000 Pyramid 152’ 1,300,000 lbs National 350/500 Oilwell D-375 Oilwell B-500 Oilwell 350/500 power swivel Specify structure type and load capacity? Martin Decker 6-pen recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D-399, 2000 HP ea. 2 x GE 752, ----- HP ea. 2 x GE 752 ----- HP ea. 1 x GE 752 – 1000 HP, Torque --- Amps / ----- ft.-lbs 1 x GE 752 – 1000 HP, Torque --- Amps / ----- ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 5. Centrifuge 6. Degasser

: : : : : : :

2 x Oilwell 1700 PT, 1700 HP ea. 4000 Bbls capacity, 60 Bbls trip tank 3 x Brandt LCM-2D, 2 x 800 GPM mud cleaners Specify Make & Model? – 1600 GPM Specify Make? / 1600 GPM Brandt SC4, ------ GPM Specify Make & Model? – 1200 GPM Degasser

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Shaffer 2130420-3SX Shaffer 10,000 psi WP, sour service 1 x Shaffer 30” annular - 1000 psi, 2 x Stewart & Stevenson 26 ¾” single rams - 3000 psi, 1 x Shaffer 20 ¾” double rams, 3000 psi, 1 x Shaffer 20 ¾” single ram, 3000 psi 1 x Shaffer 21 ¼” annular 2000 psi, 2 x Shaffer 13-5/8” double ram, 10,000 psi, 1 x Shaffer 13-5/8” annular, 5000 psi,

F)

Safety Equipment

:

xx fire extinguishers, 1 fire pump, Gas detection systems for H2S and explosive gasses, Cascade System, xx SCBA / xx SABA breathing sets, x portable gas monitors, x eyewash stations, x wind socks, shower at mud pits, breathing air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5 ½” Grade E 21.9 lbs/ft., 10,000 ft., 5” Grade G 19.5 lbs/ft, 15000 ft, 3 ½” Grade G 13.3 lbs/ft, 15000 ft. 30 of 5 ½”, 100 of 5”, 100 of 3 ½” 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

20,000 ft

I)

DF – GL Elevation Clearance below DF

: :

35 ft 28.0 ft.

C)

D)

E)

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2.3.3

DPS-44 (ONSHORE RIG)

A)

Year Built

:

1998

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Oilwell E 2000, 2000 HP Pyramid 152’ 1,000,000 lbs with 12 lines National 350/500 power swivel Oilwell D-375, 650 Ton Oilwell B-600, 600 Ton Oilwell 350/500 power swivel Pyramid self elevating, csg 1,300,000 lbs, set back 800,000 lbs Drill Watch, VIP Visua-logger

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar 3512, 1000 HP ea. w/ 1025 KW Generators 2 x GE 752, 1000 HP ea. 4 x GE 752, 1000 HP ea. Oilwell D 375, 1000 HP, Torque 1500 Amps / 43,200 ft.-lbs 1 x GE 752, 1000 HP, Torque 1400 Amps / 38,722 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Oilwell 1700 PT, 1700 HP ea. 4000 Bbls capacity, 1526 Bbls Active, 60 Bbls trip tank 3 x Brandt shakers, 2 x 800 GPM mud cleaners Brandt SR-3, 1600 GPM Brandt SE-24, 1600 GPM None Brandt DG-10, 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

Koomy 2T30420-38X, 3000 psi 4-1/16”, Shaffer 10,000 psi WP, H2S trimmed Shaffer 30” Annular, 1000 psi, Cameron 26 ¾” Dbl Ram 3000 psi. Cameron 26 ¾” Sgl Ram 3000 psi, Shaffer 13-5/8” Annular 5000 psi, Cameron 13 5/8” Dbl Ram 10000 psi BSR w/ Booster. Cameron 13 5/8” Dbl Ram 10000 psi.

F)

Safety Equipment

:

65 Fire extinguishers, 1 Fire pump, Air cascade system, 12 Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed gas detection system, Portable gas detection Equipment, 5 eye wash stations, 2 emergency showers, 4 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5-1/2” Grade E, 24.7 lbs/ft., 10,000 ft., 5” Grade G, 19.5 lbs/ft., 15,000 ft., 3-1/2”, Grade G, 13.3 lbs/ft., 15,000 ft. 30 of 5 ½”, 50 of 5”, 50 of 3 ½” 18 of 9-1/2”, 30 of 8-1/2”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

20,000 feet

I)

DF – GL Elevation Clearance below DF

: :

35.0 ft. 28.0 ft.

C)

D)

E)

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2.3.4

DPS-45 (ONSHORE RIG)

A)

Year Built

:

1997 (Refurbished)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Oilwell E 2000 (2000 HP) with Elmagco Auxiliary Brake Pyramid 30’ x 152 ft 1,275,000 lbs with 12 lines National 350/500 – 500 Ton Oilwell D-375 (37 ½”) – 500 Ton Oilwell B-500 – 500 Ton Oilwell 350/500 power swivel (integrated with Top Drive) Pyramid, self-elevating, casing 1,275,000 lbs, set back 800,000 lbs. Martin Decker, 6-Pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D-399, 1200 HP ea. w/ 1050 KW generators 2 x GE 752 – 1000 HP ea. 4 x GE 752 – 1000 HP ea. Ind. Dr, GE 752 motor – 1000 HP, Torque 750 Amps / 17500 ft.-lbs GE 752 motor – 1000 HP, Torque 750 Amps / 17500 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Oilwell 1700 PT, 1700 HP ea. 4,000 bbl. capacity w/ 1940 bbl. active, 60 bbl. trip tank 3 x Brandt shakers, 2 x 800 GPM mud cleaners Brandt, Brexel – 1600 GPM Brandt – 1600 GPM None Ingersol Rand, 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

Shaffer 2T30420-38X Shaffer 10,000 psi WP, sour service Shaffer 30” annular, 1000 psi, 2 x Stewart & Stevenson 26 ¾” single ram, 3000 psi, Shaffer 21-1/4” annular, 2000 psi, 2 x Shaffer 135/8” double ram, 10,000 psi, Shaffer 13-5/8” annular, 5000 psi, Shaffer 20-3/4” double ram, 3000 psi, Shaffer 20-3/4” single ram, 3000 psi

Safety Equipment

:

154 Fire extinguishers (Rig & Camp), Fire pump, Air cascade system, 13 Breathing 5 min apparatus (13 spare bottles), 20 SCBA 30 min Breathing (20 spare Bottles) Apparatus, Fixed gas detection system, 7 Portable gas detection Equipment, 5 eye wash stations, 3 emergency showers, 4 x wind socks

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5-1/2” Grade E, 21.9 ppf, 10,000 ft., 5” Grade G, 19.5 ppf, 15000 ft, 3-1/2”, Grade G, 13.3 ppf, 15,000 ft. 30 of 5 ½”, 100 of 5”, 100 of 3 ½” 12 of 9-1/2”, 30 of 8-1/2”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

20,000 feet

I)

DF – GL Elevation Clearance below DF

: :

35.0 ft. 28.0 ft.

C)

D)

E)

F)

G)

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2.3.5

DPS-46 (ONSHORE RIG)

A)

Year Built

:

1975 (Refurbished in 2000)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110 UE, 1500 HP with Baylor 6032 eddy current brake Pyramid 152 ft., load 840,000 lbs 705,000 lbs with 12 lines National Oilwell PS500A National C-375 (37 ½”) National 660 – 500 Ton National P500 – 500 Ton pyramid self elevating, set back 504,000 lbs Martin Decker 8-Pen with Rig-sense version 2.0 SP 2

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1321 HP ea. w/ 925 KW Generators 2 x GE 752 – 750 HP ea. 4 x GE 752 – 1000 HP ea. Oilwell D 375 – 1000 HP Torque 17,500 ft-lbs. GE 752 – 1000 HP, Torque 33,154 ft.-lbs continuous @120 RPM

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Oilwell 1700 PT, 1700 HP ea. 4053 bbl. capacity with 1156 bbl. active and 2 x 50 bbl. trip tanks 3 x Brandt shakers, 2 x 800 GPM mud cleaners Brandt SRS-3 cones – 1600 GPM Brandt SE-24cones – 1600 GPM None Brandt vacuums – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey/Shaffer 2T60392-3SX 4-1/16” Shaffer 10,000 psi WP, H2S trimmed Shaffer30” annular, 1000 psi, 2 x Cameron 26 ¾” single rams, 3000 psi, Shaffer 20-3/4” double ram, 3000 psi, Shaffer 20-3/4” single ram, 3000 psi, Shaffer 21 ¼” annular, 2000 psi, Shaffer 13-5/8” double ram, 10,000 psi, Shaffer 13-5/8” annular, 5000 psi, Shaffer 13-5/8” double ram with shear rams, large bore bonnets and 16” boosters, 10000 psi

F)

Safety Equipment

:

54 Fire extinguishers, 1 Fire pump, Air cascade system, 12 Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed gas detection system, Portable gas detection Equipment, 7 eye wash stations, 2 emergency shower,4 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5-1/2” Grade G, 24.7 ppf, 9860 ft, 5” Grade G, 19.5 ppf, 15,000 ft, 3 ½” Grade G, 13.3 ppf, 10,000 ft, 2 3/8” Grade E 6.65 ppf, 4,800 ft. 15 of 5 ½”, 61 of 5” 18 of 9-1/2”, 30 of 8-1/2”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

15,000 feet

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft 25.0 ft.

C)

D)

E)

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RIG SPECIFICATIONS

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2.4.1

PA-70 (ONSHORE RIG)

A)

Year Built

:

1980

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Mid Continent U-1220 EB with Elmagco Auxiliary Brake Lee C. Moore 35 ft x 142 ft. 1,300,000 lbs with 12 lines None Continental Emsco T-37.50 (37 ½”) – 650 Ton McLissick Model RP-686 – 650 Tons Continental Emsco LB 650 – 650 Ton LCM Sligshot, casing 1,300,000 lbs., setback 800,000 lbs. Totco, 6-Pen

C)

Rig Power 1. Engine Power generators 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

:

5 x Caterpillar D-399, 1200 HP ea. with Kato 5 x 1050 KW

: : : :

2 x GE 752 Motors – 1000 HP ea. 4 x GE 752 Motors – 1000 HP ea. Ind. Dr, GE 752 Motor – 1000 HP, Torque 1050 Amps / 54,000 ft-lbs. None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Continental Emsco FB 1600 (1600 HP) 3000 bbl. capacity with120 bbl. Trip tank 3 x Derrick Flo Line Cleaners –Model L-48-96F Derrick Model 38-1612 with 3 x 12” cones – 945 GPM Derrick Model 38-10613 with 20 x 5” cones – 800 GPM None Swaco Type 30, Model 255 – 1000 GPM

:

3000 psi, Shaffer-Koomey T40240-3S w/ 14 sta., 36 x 12 gal.

: :

4 1/16”, Energy, 10,000 psi WP, sour service. Hydril 30” annular 1000 psi, 2 x Cameron U 26 3/4” single ram, 3000 psi, Hydril 21 ¼” annular 2000 psi, Cameron 20 3/4” double ram, 3000 psi, Cameron 20 ¾” single ram, 3000 psi, Hydril GK 135/8” annular 5000 psi, 2 x Cameron 13 5/8” double ram, 10,000 psi, All H2S Trim.

:

20 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S detectors, 1 x Cascade system, 1 x Mako breathable air compressor, 1 x CO2 system, 3 x Eye Wash Stations, 1 x Emergency Shower on Mud Pits

HWDP Drill collars

: : : :

5 ½” Grade G, 24.7 ppf, 12,000 ft., 5” Grade G, 19.5 ppf, 15,000 ft. 3-1/2” Grade G, 13.3 ppf, 9,000 ft. 9 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½” 18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

34.7 ft 25.0 ft

D)

E)

BOP Equipment 1. Accumulator bottles 2. Choke manifold 3. BOPs

F)

Safety Equipment

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. 3.

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RIG SPECIFICATIONS

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2.4.2

PA-77 (ONSHORE RIG)

A)

Year Built

:

1975

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Mid Continental U-914 EC (1500 HP) with Elmagco Auxiliary Brake Pyramid 25 x 156 ft. 890,000 lbs. (static) with 12 lines Can-Rig-1050E – 500 Ton Gardner Denver RT375, 37 ½” McKissick – 500 Ton None Pyramid Slingshot type, casing 800,000 lbs., setback 500,000 lbs. Acadiana, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399 – 1000 HP ea. w/ 1050 KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 motor – 1000 HP ea. GE 752 motor – 1000 HP. GE 752, 1000 HP, Torque 1250 Amps / 30,000 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x C. Emsco FB-1300 – 1300 HP ea. 2000 bbl. capacity with100 bbl. trip tank 2 x Derrick-Flo Line Cleaner Derrick Super ‘G’ Model-58, 3 x 12” cone – 800 GPM Derrick Super ‘G’ Model-58, 20 x 4” cone – 800 GPM None Derrick Vacu-Flo – 1000 GPM, Burgess Magna – 1000 GPM”

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey T20200 with 9 stations 3 1/8”, 5000 psi WP, sour service Hydril GK 13 5/8” Annular 5000 psi, Cameron UU 13 5/8” double ram, 5000 psi with s. booster, Cameron U 13 5/8” single ram, 5000 psi, All H2S trimmed

F)

Safety Equipment

:

68 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

4” Grade-G, 14.00 ppf, 16,000 ft. 3 ½” Grade-G, 13.3 ppf, 5000 ft, 2 3/8” Grade-E, 6.65 ppf, 500 ft. 60 of 4” 30 of 6 ¼”, 30 of 4 ¾”, 30 of 2-7/8”

H)

Depth Capacity

:

15,000 ft

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft 25.0 ft

C)

D)

E)

2. 3.

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RIG SPECIFICATIONS

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2.4.3

PA-115 (ONSHORE RIG)

A)

Year Built

:

1975

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Mid Continental U 1220 EB – 2000 HP with xxxxxxx auxiliary brake Lee C. Moore 30’ x W x 152 ft. 1,300,000 lbs. static with 12 lines Can-Rig 1165E – 500 Ton Ideco LR375 (37 ½”) – xxx Ton Mc Kissick model? – 650 Ton None LCM what type? Load casing xxxxxxx lbs, setback 800,000 lbs? Acadia, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 1000 HP ea. with xxx KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 motor – 1000 HP ea. Ind. drive, GE 752 motor 800 HP, Torque ….. Amps / xxxx ft-lbs. 1 GE 752 Motor, 1000 HP, Torque ……. Amps / 31000 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x C. Emsco FB-1300 – 1300 HP ea 3,000 bbl. capacity, 120 bbl trip tank 3 x Derrick Flo Line Cleaner 2000 Derrick 2 x 12” cone – 800 GPM ? Derrick 12 x 4” cone – 800 GPM 2 x Oil Tools DE 1000 – 1000 GPM Swaco model? – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomy 160-11ST w/ 11 stations, 16 x 00 gal. bottles 3 1/8” Make? 5000 psi WP, sour service Hydril GK 13 5/8” annular, 5000 psi, Cameron U 13 5/8” single ram, 5000 psi, Cameron U 13 5/8” double ram w/ shear booster, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

28 Fire extinguishers, 1 Fire pump, 2gas detector, 4 H2S detectors, 1 cascade system with 12 work packs, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 4 eye wash stations, 2 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 MAKO Breathable air compressor, 1 foam unit.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5” Grade G, 19.5 lbs/ft, 25,000 ft. 4’’Grade-G 14.0 lb/ft, 25,000 ft 100 of 5”, 100 of 3 ½” 12 of 9 ½”, 30 of 8 ¼” 30 of 6 ¼”, 60 of 4 ¾”

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

25.0 ft xx.x ft.

C)

D)

E)

2. 3.

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2.4.4

PA-117 (ONSHORE RIG)

A)

Year Built

:

1981 (Upgrade / Refurbishment done in 2003)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Mid Continent U-1220 EB LCM 156 ft. 1,300,000 lbs with12 lines None Continental Emsco T-3750 Oilwell 650 Tons Continental Emsco LB650 Dreco, Load, casing 1,500,000 lbs, setback 800,000 lbs. M.D. TOTCO, 6 Pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D-399, 1000 HP ea. 2 x GE 752 Motors, 1000 HP ea. 4 x GE 752 Motors – 1000 HP ea. Ind. Drive, GE 752 Motor, 1000 HP None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Continental Emsco FB 1600 (1600 HP) 3000 bbl. capacity with120 bbl. Trip tank 3 x Derrick Flo Line Cleaners Derrick – 800 GPM None None SWACO – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

Shaffer T20160-2S, 3000 psi, xx Stations 4 1/16”, 10,000 psi WP, sour service. Cameron U 13-5/8” Double Ram, 10,000 psi with shear booster, Hydril GK, 13-5/8” Annular 5000 psi – All H2S trimmed

F)

Safety Equipment

:

28 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S detectors, 2 x Cascade system, 2 x Mako breathable air compressor, 1 x CO2 system, 0 x Eye Wash Stations, 2 x Emergency Shower on Mud Pits

G)

Drill Pipe & Drill Collars 1. Drill Pipe ft.

:

5 ½” Grade G, 24.7 lbs/ft -10,000 ft., 5” Grade G, 19.5 lbs/ft-15,000

HWDP Drill collars

: : :

3-1/2” Grade G, 13.3 lbs./ ft - 9,000 ft. 9 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½” 18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

25.0 ft 20.0 ft

C)

D)

E)

2. 3.

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2.4.5

PA-125 (ONSHORE RIG)

A)

Year Built

:

1980

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Mid Continent U-914EC (xxxx HP) w/ xxxxxx auxiliary brake Lee C. Moore 25 ft x 152 ft. 1,000,000 lbs (static) with12 lines Can-Rig 1050E – xxx Ton National C375, 37 ½” – xxx Ton Oilwell 500 – 500 Ton None Dreco – xxxxxxxx Csg, xxxxxxx set back. Totco, 6 Pen

: : : :

4 x Caterpillar 3512, 1300 HP ea. w/ ABC xxxxx KW generators 2 x GE 752 Motors, 1000 HP ea. 4 x GE 752 Motors – 1000 HP ea. Ind. Drive, GE 752 Motor, 1000 HP, Torque xxxx Amps / xxxxx ft-

:

GE 752 Motors, 1000 HP, Torque xxxx Amps / xxxxx ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Continental Emsco FB1600 (1600 HP) 2,000 bbl. capacity with100 bbl. Trip tank 2 x Derrick Flo Line Cleaners 513 Derrick 3 x 12” cone – 800 GPM Derrick 12 x 2” cone – 800 GPM None Brandt, Model xxxx, – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Vetco TX392-15SB3, xx stations 4 1/16”, Make? 10,000 psi WP, sour service. Hydril GK, 13 5/8” Annular 5000 psi, Cameron U 13 5/8” double ram, 10,000 psi with shear booster, Cameron U 13 5/8” single ram, 10,000 psi – All H2S trimmed

F)

Safety Equipment

:

23 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S detectors, 1 x Cascade system, MAKO breathable air compressor, 1 x CO2 system, 0 x Eye Wash Stations, 2 x Emergency Showers.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5” Grade-G, 19.5 lbs/ft -10,000 ft. 4” Grade-G, 14.5 lbs/ft-16,000 ft. 60 of 5” and 80 of 4”.” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”

H)

Depth Capacity

:

15,000 ft

I)

DF – GL Elevation Clearance below DF

: :

xx.x ft 25.0 ft

C)

D)

E)

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary lbs. 5. Top Drive

2. 3.

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RIG SPECIFICATIONS

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2.4.6

PA-128 (ONSHORE RIG)

A)

Year Built

:

1980

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Mid Continent U-1220 EB LCM 30 ft x 156 ft. 1,300,000 lbs with12 lines National PS 350/500 Continental Emsco T-3750 Oilwell 650 Tons None Dreco Totco, 6 Pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D-399, 1000 HP ea. 2 x GE 752 Motors, 1000 HP ea. 4 x GE 752 Motors – 1000 HP ea. Ind. Drive, 1 X GE 752 Motor, 1000 HP 1 x GE 752 Motors – 1000 HP, 1050 Amps / 54,000 ft./lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Continental Emsco FB 1600 (1600 HP) 3000 bbl. capacity with120 bbl. Trip tank 3 x Derrick Flo Line Cleaners Derrick – 800 GPM as above None Swaco – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Shaffer T40240-3S, 4 1/16”, 10,000 psi WP, sour service. 2 x Cameron U 13-5/8” Double Ram, 10,000 psi with shear booster, Hydril GK, 13-5/8” Annular 5000 psi – All H2S trimmed

F)

Safety Equipment

:

31 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S detectors, 1 x Cascade system, 2 x Mako breathable air compressor, 1 x CO2 system, 0 x Eye Wash Stations, 2 x Emergency Shower on Mud Pits

G)

Drill Pipe & Drill Collars 1. Drill Pipe ft.

:

5 ½” Grade G, 24.7 lbs/ft -10,000 ft., 5” Grade G, 19.5 lbs/ft-15,000

HWDP Drill collars

: : :

3-1/2” Grade G, 13.3 lbs./ ft - 9,000 ft. 9 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½” 18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”

H)

Depth Capacity

:

20,000 ft

I)

DF – GL Elevation Clearance below DF

: :

25.0 ft 20.0 ft

C)

D)

E)

2. 3.

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2.4.7

PA-203 (ONSHORE RIG)

A)

Year Built

:

1978

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Ideco E-1700 (1700 HP) with Elmagco 7838W Auxiliary Brake Pyramid 25 x 142 ft. 750,000 lbs with12 lines None Ideco 37 ½” Name 400 Tons Name 400 Tons Pyramid – Load Capacity xxxxxxxxx Csg, xxxxxxxx set back. Totco, 6 Pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D-398, 900 HP ea. 2 x GE 752 Motors, 1000 HP ea. 6 x GE 752 Motors – 1000 HP ea. Ind. Drive, 1 X GE 752 Motor, 1000 HP (xxxx Amps / xxxxx ft./lbs) 1 X GE 752 Motor, 1000 HP (xxxx Amps / xxxxx ft./lbs)

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Oilwell 1400 PT (1400 HP) 3000 bbl. capacity with120 bbl. Trip tank 3 x Derrick Flo Line Cleaners Derrick 12” x 3 cone – 800 GPM Derrick 4” x 16 cone – 800 GPM None Swaco Model xxxx, 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

Koomy, 3000 psi, 16 Stations 4 1/16”, 10,000 psi WP, sour service. Shaffer 30” annular – 1000 psi, 2 x Hydril 26 ¾” single ram – 3000 psi, 2 x Hydril 20 ¾” single ram – 3000 psi, Hydril GK, 13-5/8” Annular – 5000 psi, Hydril 11” annular – 10000 psi, All H2S trimmed

F)

Safety Equipment

:

xx Fire extinguishers, 1 Fire pump, Air cascade system, 12 x 5-min. Breathing apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed gas detection system, Portable gas detection Equipment, 5 x eye wash stations, 1 emergency shower, 4 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe ft.

:

5 ½” Grade G, 24.7 lbs/ft -10,000 ft., 5” Grade G, 19.5 lbs/ft 15,000

2. 3.

HWDP Drill collars

: :

3 ½” Grade G, 13.3 lbs/ft 9,000ft., 2 7/8” Grade E, 6.7 lbs/ft 5,000 ft 30 of 5-½”, 30 of 5” and 50 of 3-½” 18 of 10”, 30 of 8 ½”, 30 of 6 ½”, and 30 of 4 ¾”

H)

Depth Capacity

:

17,000 ft

I)

DF – GL Elevation Clearance below DF

: :

31.0 ft 26.0 ft

C)

D)

E)

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2.4.8

PA-207 (ONSHORE RIG)

A)

Year Built

B)

Rig Equipment 1. Drawworks Brake 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

C)

D)

E)

F)

:

1956 (Refurbished 2005)

:

National 100-UE (1000 HP) with Baylor/Elmagco 6032 Auxiliary

: : : : : : : :

Lee C. Moore, 24 ft x152 ft (Extended 10 ft., May 2006) 800,000 lbs. (static) with 12 lines Can-Rig 1050 – 500 Ton. National C375 37 ½” – 650 Ton McKissick – 550 Ton None Lee C. Moore, Box-on-Box, set back 500,000 lbs. Acadiana, 6-pen.

: : : :

4 x Caterpillar D398, 825 HP ea. with 1000 KW generators 2 x GE 752 motors – 750 HP ea 4 x GE 752 motors – 750 HP ea EMD S-79 motor – 800 HP, Torque 900 Amp/36,250 ft/lbs @ 100

:

GE 752 motor – 1000 HP, Torque 1250 Amps/30,000 ft/lbs @ 180

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 10-P-130 (1300 HP) 2237 bbl. capacity with 164 bbl trip tank capacity 2 x Derrick Flo Line Cleaners Derrick 3 x 12” cone – 800 GPM Derrick 20 x 4” cone – 800 GPM None Swaco Horizontal – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, CAD, 9 stations 3 1/8” EEC, 5000 psi WP, sour service. Hydril GK 13 5/8” Annular 5000 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13 5/8” single ram, All H2S trimmed

:

3 x portable fire extinguishers, 5 x 10 lbs CO2 fire extinguishers, 41

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary RPM 5. Top Drive RPM

Safety Equipment x

30 lbs DCP fire extinguishers, 15 SCBA, 12 SABA, 2 x chemical PPE box, 5 x eye wash stations, 1 emergency shower, 5 x wind socks, 6 x portable gas monitors, (4 x Combustible Gas,2 x H2S), Fire pump, Air Cascade System. G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

4” Grade-CY, 14.0 ppf, 16,000 ft, 3 ½” Grade-G, 13.3 ppf, 5,000 ft. 2 3/8” Grade-C, 6.5 ppf, 5,000 ft 60 of 4” 30 of 6 ¼”, 30 of 4 ¾”, 30 of 2 7/8”, 30 of 2 3/8”

H)

Depth Capacity

:

16,000 ft

I)

DF – GL Elevation Clearance below DF

: :

25.5 ft 21.3 ft

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RIG SPECIFICATIONS

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2.4.9

PA-210 (ONSHORE RIG)

A)

Year Built

:

1975 (Inspected and recertified by Pyramid, Jun. 2001)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110 UE – 1500 HP with Baylor auxiliary brake Pyramid 30’ x 24’ x 149 ft. 1,000,000 lbs. static with 12 lines Can-Rig 1050E – 500 Ton Oilwell A-37.5 (37 ½”) – 500 Ton National 650G – 500 Ton C. Emsco – 500 Ton Pyramid Girder, Load casing 900,000 lbs, setback 800,000 lbs. M.D./Totco, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D398, 900 HP ea. with 1030 KW generators 2 x EMD 79 motor – 800 HP ea. 4 x EMD 79 motor – 800 HP ea. Ind. Dr. EMD 79 motor – 800 HP, Torque 1000 Amps / 26,500 ft-lbs. GE 752 shunt motor, 1000 HP, Torque 1400 Amps / 31,000 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Oilwell A-1700PT – 1700 HP ea. Gardner Denver PZ-7 – 550 HP 1900 bbl. capacity, 2 x 40 bbl trip tanks 2 x Derrick Flo Line Cleaner 503 Demco Sand Bull, 2 x 10” cone – 500 GPM Demco Sand Bull, 8 x 4” cone – 500 GPM None Burgess Magna VAC – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, NL Shaffer with 8 stations, 12 x 10 gal. bottles 3 1/8” Cameron 5000 psi WP, sour service Hydril MPS 21-1/4” annular 2000 psi, Cameron 13 5/8” annular 500 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13 5/8” single ram, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

90 portable Fire extinguishers, 1 Fire pump, 4 x 150 lbs. wheeled Fire Extinguishers, 58 x 30 lbs. wheeled Fire Extinguishers, 2 gas detector, 4 H2S detectors, 1 cascade system with 12 work packs, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 4 eye wash stations, 2 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor, 1 foam unit.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5” Grade-G, 19.5 ppf, 15,000 ft, 4’’Grade-G 14.0 ppf, 18,000 ft. 2 3/8” Grade-E 6.65 ppf, 2000 ft 60 of 5”, 60 of 4” 12 of 9-1/2”, 30 of 8 ¼”, 33 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”.

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clear below DF – GL

: :

25.5 ft 19.2 ft.

C)

D)

E)

2. 3.

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.10

PA-212 (ONSHORE RIG)

A)

Year Built

:

1975 (Major Refurbishment and Certification in 2001)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110 UE – 1500 HP with xxxxxxx auxiliary brake Lee C. Moore 30’ x W x 152 ft. 990,000 lbs. static with 12 lines Can-Rig 1165E – 500 Ton National C375 (37 ½”) – xxx Ton National model? – 500 Ton None LCM what type? Load casing xxxxxxx lbs, setback 800,000 lbs? Totco, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 1000 HP ea. with xxx KW generators 2 x EMD79motor – 1000 HP ea. 4 x EMD D79 – 1000 HP ea. Ind. drive, EMD D79 motor 800 HP, Torque ….. Amps / xxxx ft-lbs. 1 GE 752 Motor, 1000 HP, Torque ……. Amps / 31000 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x C. Emsco FB-1300 – 1300 HP ea 2,000 bbl. capacity, 100 bbl trip tank 3 x Derrick Flo Line Cleaner 2000 Harrisburg 2 x 12” cone – 800 GPM ? Demco 12 x 4” cone – 800 GPM None Swaco specify model No. 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Shaffer with xx stations and 00 x 00 gal. bottles 3 1/8” Make? 5000 psi WP, sour service Hydril GK 13 5/8” annular, 5000 psi, Cameron U 13-5/8” double ram, 5000 psi, Cameron U 13 5/8” single ram, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

29 Fire extinguishers, 1 Fire pump, 2gas detector, 4 H2S detectors, 1 cascade system with 12 work packs, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 4 eye wash stations, 2 shower-mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 MAKO Breathable air compressor, 1 foam unit. PLEASE CHECK ALL

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5” Grade G, 19.5 lbs/ft, 10,000 ft. 4’’Grade G 105 14.0 lb/ft 18,000 ft 100 of 5”, 100 of 4” 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 60 of 4 ¾”

H)

Depth Capacity

:

15,000 ft

I)

DF – GL Elevation Clearance below DF

: :

xx.x ft xx.x ft.

C)

D)

E)

2. 3.

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RIG SPECIFICATIONS

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2.4.11

PA-263 (ONSHORE RIG)

A)

Year Built

:

2002

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Oilwell E-2000 (2000 HP) Dreco 32 ft x 147 ft. 1,000,000 lbs with12 lines Can Rig 1050E Oilwell B 37 ½” Mc Kissick 650 Tons None (Integrated with Top Drive) Dreco. Totco, 6 Pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D-399, 1000 HP ea. 2 x GE 752 Motors, 1000 HP ea. 6 x GE 752 Motors – 1000 HP ea. Ind. Dr, GE 752 Motor, 1000 HP, Torque 1050 Amps / 54,000 ft-lbs. GE 752 Motor, 1000 HP, Torque 1050 Amps / 54,000 ft- lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Continental Emsco FB 1600 (1600 HP) 3000 bbl. capacity with120 bbl. Trip tank 3 x Derrick Flo Line Cleaners Derrick – 800 GPM None None Swaco – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

CAD SB360-11SB3K, 3000 psi, xx Stations 4 1/16”, 10,000 psi WP, sour service. 2 x Cameron U 13-5/8” Double Ram, 10,000 psi, Hydril GK, 13-5/8” Annular 5000 psi – All H2S trimmed with shear booster

F)

Safety Equipment

:

25 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S detectors, 2 x Cascade system, 2 x MKO breathable air compressor, 1 x CO2 system, 0 x Eye Wash Stations, 2 x Emergency Shower on Mud Pits

G)

Drill Pipe & Drill Collars 1. Drill Pipe ft.

:

5 ½” Grade G, 24.7 lbs/ft -12,000 ft., 5” Grade G, 19.5 lbs/ft-15,000

HWDP Drill collars

: : :

3-1/2” Grade G, 13.3 lbs./ ft - 9,000 ft. 9 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½” 18 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

32.0 ft 26.0 ft

C)

D)

E)

2. 3.

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.12

PA-295 (ONSHORE RIG)

A)

Year Built

:

1988 (Refurbished: Dec. 2004)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Mid Continent, U-1220 EB (2000 HP) with 7838 Elmagco Brake Pyramid 31’ x 152 ft. 1,000,000 lbs. (static) with 12 lines National 350/500 – 500 Ton Oilwell B-37 1/2 (37-1/2”) Continental Emsco – 500 Ton Continental Emsco – LB 650 Ton Pyramid Cantilever Type, casing 900,000 lbs, setback 700,000 lbs Totco, 7 pen & Epoch Rig Watch system

: : : :

4 x Caterpillar D399, 1225 HP ea. With 1050 KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 1000 HP ea. Ind. Dr. GE 752 motor – 1000 HP, Torque 1400 Amps / 38,000 ft.-

:

GE 752 motor – 1000 HP, Torque 1400 Amps / 38,455 ft.-lbs

: : : : : : :

2 x Continental Emsco FB 1600 – 1600 HP ea. 2000 bbl. capacity, 1200 bbl. active with 120 bbl trip tanks 3 x Derrick-Flo Line Cleaner 500 Derrick 3 x 10” cones Derrick 20 x 4” cones Derrick DE-1000 hydraulic, Variable GPM Brandt DG-10 – 1000 GPM

: : :

3000 psi, Vetco TX392-15SB3 with 14 stations 4 1/16” Energy Equipment Corporation, 10000 psi WP, sour service Hydril GK 13-5/8” Annular 5000 psi, Cameron U 13-5/8” double

C)

D)

E)

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary lbs 5. Top Drive Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs ram,

5000 psi, Cameron U 13-5/8” single ram, 5000 psi, All H2S trimmed. F)

Safety Equipment

:

104 Fire extinguishers, 1 Fire pump, 4 gas detector, 4 H2S detectors, 1 cascade system, 29 Scott Air Pack SCBAs, 4 portable gas/ H2S monitors, 5 eye wash stations, 1 shower-mud pits, 5 wind socks, 2 Drager H2S sniffer, 1 Mako Breathable air compressor, 2 Gastec units w/ accessories & tubes.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

HWDP Drill collars

: : : : :

4” Grade G, 14.0 lbs./ ft, 16,000 ft. 3-1/2” Grade G, 13.3 lbs./ ft, 5,000 ft. 2-3/8” Grade E, 6.6 lbs / ft, 5,000 ft. 60 of 4” 30 of 6-1/4”, 30 of 4-3/4”, 30 of 2 7/8”

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

31.5 ft 25.5 ft

2. 3.

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.13

PA-312 (ONSHORE RIG)

A)

Year Built

:

1976

B)

Rig Equipment 1. Drawworks Brake 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

:

Gardner Denver 1500E (2000 HP) w/ National Baylor Elmagco

: : : : : : : :

Pyramid 27’ x 152 ft. 1,000,000 lbs. (static) with 12 lines Can-Rig 1050E – 500 Tons National C375, 37 ½” Continental Emsco – 500 Tons None Pyramid, casing 700,000 lbs, setback 450,000 lbs. Totco, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D398, 825 HP ea. with 1,000 KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 1000 HP ea. GE 752 motor – 1000 HP, Torque 1000 Amps / 15,130 ft-lbs GE 752 motor, 1000 HP, Torque 1400 Amps / 38,455 ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Continental Emsco FB-1600 – 1600 HP ea. 2000 bbl. capacity, 1500 bbl. Active with 100 bbl trip tank 2 x Derrick-Flo Line Cleaner 513 Derrick 3 x 10” cone – 800 GPM Derrick 20 x 4”cone – 800 GPM Derrick DE-1000 – 220 GPM Brandt – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 4201472-BS2 with 14 stations 4 1/16” Energy Equipment 10,000 psi WP, sour service Hydril GK 13-5/8” Annular 5000 psi, Cameron UU 13-5/8” double Ram, 5000 psi with booster, Cameron UU 13-5/8” single ram, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

32 Fire extinguishers, 1 Fire pump, 4 gas detector, 4 H2S detectors, Cascade System, 29 Scott Air Pack SCBAs, 4 portable gas/ H2S monitors, 5 eye wash stations, 1 shower-mud pits, 5 wind socks, 2 Drager H2S sniffer, 1 Mako Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

4” Grade-G, 15.0 ppf, 16,000 ft. 3 ½” Grade G, 13.3 ppf, 5,000 ft. 60 of 4” 30 of 6 ¼”, 30 of 4 ¾”, 30 of 2 7/8”

H)

Depth Capacity

:

25,000 feet

I)

DF – GL Elevation Clearance below DF

: :

31.5 ft. 25.5 ft.

C)

D)

E)

2. 3.

44 of 102

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Drilling & Workover Engineering Department CHAPTER 1

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F

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.14

PA-393 (ONSHORE RIG)

A)

Year Built

:

1980 (Upgraded in 2005)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Mid Continent U-1220 EB (2,000 HP) w/ Elmagco auxiliary brake Dreco 25 ft x 152 ft. 1,167,000 lbs (static) with12 lines National PS 350/500 – 350 Ton (Drilling) – 500 Ton (Max. Pull) C. Emsco T3750, 37 ½” – 350 Ton C. Emsco – 500 Ton None Dreco – Load casing 1,167,000 lbs, setback 700,000 lbs. Totco, 6 Pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1500 HP ea. w/ ABC 1365 KW generators 2 x GE 752 Motors – 1000 HP ea. 4 x GE 752 Motors – 1000 HP ea. GE 752 Motor – 1000 HP, Torque 1200 Amps / 38455 ft-lbs. GE 752 Motors, 1085 HP, Torque 1400 Amps / 38455 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Continental Emsco FB1600 (1600 HP) 2,000 bbl. capacity with100 bbl. Trip tank 2 x Derrick Flo Line Cleaners 513 Derrick 3 x 12” cone – 800 GPM Derrick 12 x 2” cone – 800 GPM None Brandt, Model DG-10, – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD with 14 stations 4 1/16” EEC, 10,000 psi WP, sour service. Hydril GK, 13 5/8” Annular 5000 psi, Cameron U 13 5/8” double ram 10,000 psi with shear booster, Cameron U 13 5/8” single ram, 10,000 psi – All H2S trimmed

F)

Safety Equipment

:

21 x Fire extinguishers, 1 x Fire pump, 1 x Gas detector, 1 x H2S detectors, 1 x Cascade system, MAKO breathable air compressor, 1 x CO2 system, 0 x Eye Wash Stations, 2 x Emergency Showers.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5” Grade-G, 19.5 ppf, 10,000 ft. 4” Grade-G, 14.5 ppf, 16,000 ft. 60 of 5” and 80 of 4”. 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, and 30 of 4 ¾”

H)

Depth Capacity

:

20,000 ft

I)

DF – GL Elevation Clearance below DF

: :

33.6 ft 25.0 ft

C)

D)

E)

2. 3.

45 of 102

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.15

PA-575 (ONSHORE RIG)

A)

Year Built

:

1975

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1320 UE (2000 HP) with Baylor Elmago Brake Pyramid 25’ x 152 ft. 1,000,000 lbs. National PS 350/500 – 500 Ton National C375, 37 ½” – 500 Tons Mc Kissick – 500 Ton (Hook/Block Combination) None Pyramid single pony, set back 1,000,000 lbs Totco, 6-pen and Epoch Rig Watch System

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 825 HP ea. w/ KATO 1050 KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 1000 HP ea. GE 752 motor – 1000 HP, Torque 1400 Amps / 17,600 ft/lbs. GE 752 motor – 1000 HP, Torque 1400 Amps / 38,712 ft/lbs.

: : : :

2 x National FB-1600 – 1600 HP ea. 2000 bbl. capacity, 1500 bbl. Active with 172 bbl trip tank 2 x Derrick-Flo Line Cleaner 513 Brandt 4 x 10” cone – 500 GPM, Derrick Hi-Speed 20 cone –

: : :

Brandt 16 x 4” cone – 500GPM None Brandt DG-10 – 500GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey E-80 with 3 stations and 28 x 10 gal bottles. 3 1/16” EEC, 5000 psi WP, sour service Hydril 21 ¼” Annular 2000 psi, Hydril GK 13-5/8” Annular 5000 psi, Cameron U 13-5/8” double ram, 5000 psi with booster, Cameron U 13-5/8” single ram, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

Zeiger, 8-channel gas monitoring system, 25 Fire extinguishers, 1 Fire pump, 4 gas detector, 4 H2S detectors, 1 cascade system, 29 Scott Air Pack SCBAs, 4 portable gas/ H2S monitors, 5 eye wash stations, 1 shower-mud pits, 5 wind socks, 2 Drager H2S sniffer, 1 MAKO Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

HWDP Drill collars

: : : : :

5” Grade-G, 19.5 ppf, 10,000 ft. 4” Grade G, 14.5 ppf, 16,000 ft. 2 3/8” Grade E 00.0 ppf, 3000 ft. 60 of 5”, 80 of 4” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 ½”

H)

Depth Capacity

:

20,000 feet

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft. 25.5 ft.

C)

D)

E)

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 1000 GPM 5. Desilter 6. Centrifuge 7. Degasser

2. 3.

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RIG SPECIFICATIONS

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2.4.16

PA-654 (ONSHORE RIG)

A)

Year Built

:

1975

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1320 UE (2000 HP) with Auxiliary Brake Lee C. Moore 30’ x 152 ft. 1,000,000 lbs. (static) with 12 lines Can Rig 1050E – 500 Ton National C375, 37 ½” – 500 Ton National Model? – 500 Ton None LCM, type? casing xxxxxx lbs, setback 600,000 lbs. Totco, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1300 HP ea. w/ KATO 1050 KW generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 1000 HP ea. GE 752 motor – 1000 HP, Torque …… Amps / …… ft-lbs GE 752 motor, 1000 HP, Torque 000 Amps / 000000 ft-lbs

: : : :

2 x C. Emsco FB-1600 – 1600 HP ea. 2000 bbl. capacity, with 100 bbl trip tank 2 x Derrick-Flo Line Cleaner 513 Derrick 10” x 4 cones – 1000 GPM, Derrick Hi-Speed 20 cone ….

: : :

Derrick 4” x 16 cones – 1000 GPM None Brandt DG-10 – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Vetco Model? with xx stations and 00 x 00 gal bottles. 4 1/16” MAKE?, 10,000 psi WP, sour service Hydril GK 13-5/8” Annular 5000 psi, Cameron U 13-5/8” single ram, 5000 psi, Cameron U 13-5/8” double ram, 5000 psi, with booster. All H2S trimmed.

F)

Safety Equipment

:

Zeiger, 8-channel gas monitoring system, 23 Fire extinguishers, 1 Fire pump, 4 gas detector, 4 H2S detectors, 1 cascade system, 29 Scott Air Pack SCBAs, 4 portable gas/ H2S monitors, 5 eye wash stations, 1 shower-mud pits, 5 wind socks, 2 Drager H2S sniffer, 1 MAKO Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade-G, 19.5 ppf, 10,000 ft. 4” Grade G, 14.0 ppf, 16,000 ft. 2 3/8” Grade E 00.0 ppf, 3000 ft. 60 of 5”, 80 of 4” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

22,000 feet

I)

DF – GL Elevation Clearance below DF

: :

00.0 ft. 25.5 ft.

C)

D)

E)

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander GPM 5. Desilter 6. Centrifuge 7. Degasser

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RIG SPECIFICATIONS

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2.4.17

PA-718 (ONSHORE RIG)

A)

Year Built

:

1981 (Commenced Operations: Dec. 2004)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Gardner Denver 1100E (1500 HP) Dreco 24’ x 152 ft. (Mast Extension Mar. 2006) 787,000 lbs. (12 lines) Can-Rig-1050E – 500 Ton Gardner Denver 37-1/2” National G-650 None Dreco Slingshot, Casing 775,000 lbs., setback 450,000 lbs. Martin Decker, 7 pen

:

5 x Caterpillar D398, 800 HP ea. w/ Kato 1030/900/800 KW

: : : :

2 x EMD D-79 motor – 800 HP ea. 4 x EMD D-79 motor – 800 HP ea. Compound Drive (Installed Mar. 2006) GE 752, 1000 HP, Torque 1250 Amps / 30,000 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Gardner Denver PZ-11(1600 HP) 2120 bbl. capacity with 160 bbl trip tanks 2 x Derrick-Flo Line Cleaner Derrick Super ‘G’ Model-58, 3 cone – 500 GPM Derrick Super ‘G’ Model-58, 20 cone – 500 GPM None Derrick Vacu-Flo – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey type-80, 10 Station 3 1/8” EEC, 5000 psi WP, sour service Hydril GK 13-5/8” Annular 5000 psi, Cameron UU 13-5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi, All H2S trimmed

F)

Safety Equipment

:

82 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, Cascade system, 32 Scott Air Pack SCBAs, 2 portable gas / H2S Monitors, 4 eye wash stations, 1 shower-mud pits, 6 wind socks, 2 Dragger H2S sniffer,1 Bauer Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

4” Grade CY-105, 14.00 ppf, 8,525 ft., 3-1/2” Grade G-105, 13.3 ppf, 5,084 ft., 2 3/8” Grade-E 6.65 ppf, 2,480 ft. 60 of 4” 28 of 6 ¼”, 30 of 4 ¾”, 15 of 2 7/8”

H)

Depth Capacity

:

16,000 ft

I)

DF – GL Elevation Clearance below DF

: :

29.30 ft 25.80 ft

C)

D)

E)

48 of 102

Rig Power 1. Engine Power generators 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

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SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.18

PA-785 (ONSHORE RIG)

A)

Year Built

:

1981

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure lbs. 9. Geolograph

: : : : : : : :

Ideco E-1700 (1700 HP) with Baylor auxiliary brake Dreco 30’ x 142 ft. 900,000 lbs. Can Rig 1050E – 500 Ton Ideco LR275 27 ½” – 500 Ton National – 500 Tons (Hook/Block Combination) Integrated with Top Drive Pyramid Sling shot type, casing 1,000,000 lbs, set back 600,000

:

Acadia, 7-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 1000 HP ea. w/ 1313 KVA generators 2 x GE 752 motor – 1000 HP ea. 4 x GE 752 – 1000 HP ea. GE 752 motor – 800 HP, Torque 750 Amps / 25,000 ft-lbs Can-Rig, AC motor, 800 HP, Torque 1350 Amps / 30,000 ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 5. Centrifuge 6. Degasser

: : : : : : :

2 x C. Emsco FB-1600 – 1600 HP ea. 2000 bbl. capacity with 100 bbl trip tank 2 x Derrick-Flo Line Cleaner Derrick 2 x 12” cones – 1000 GPM Derrick 12 x 4” cones – 1000 GPM None Harrisburg – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey T20180 4 1/16” EEC, 10,000 psi WP, sour service Hydril GK 13-5/8” 5000 psi, Cameron UU 13 5/8” double ram, 5000 psi, Cameron U 13 5/8” single ram, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

21 Fire extinguishers, 1 Fire pump, 1 gas detection system, 4 H2S detectors, 1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower at mud pits, 4 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

4” Grade-G, 14.5 ppf, 16,000 ft. 3 ½” Grade-G, 13.3 ppf, 5,000 ft. 60 of 4’’ 30 x 6 ¼” 30 x 4 ¾”

H)

Depth Capacity

:

18,000 ft.

I)

DF – GL Elevation Clearance below DF

: :

29.0 ft. 25.0 ft.

C)

D)

E)

2. 3.

49 of 102

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.19

PA-854 (ONSHORE RIG)

A)

Year Built

:

1982 (New Dog House, Mud Cleaner and Minor Refurbishments)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Cabot / IRI 2042 (700 HP) Four Leg Cabot / IRI 12’ x 117 ft. 300,000 lbs. None National C275 (27 ½”) – 300 Ton Gardner Denver – 200 Ton Gardner Denver – 200 Ton Pyramid Sling shot type, casing 300,000 lbs, set back 250,000 lbs. Totco, 4-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

2 x Caterpillar 3406 DI, 825 HP ea. w/ 250 KW generators 2 x GE 752 motor – 800 HP ea. 2 Caterpillar 398 – 800 HP ea. Compound Drive, Torque 30,000 ft-lbs. None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Gardner Denver PZ-8 – 800 HP ea. 1500 bbl. capacity with 100 bbl trip tank 1-Derrick-Flo Line Cleaner One Desander None None National – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey T20160 with 8 stations 3 1/8” Cameron 5,000 psi WP, sour service Shaffer LWS 13 5/8” double ram , 3000 psi, Shaffer LWS 13 5/8” annular 3000 psi, All H2S trimmed.

F)

Safety Equipment

:

49 Fire extinguishers, No Fire pump, 1 gas detection system, 1 cascade system, 16 Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 2 eye wash stations, 1 shower at mud pits, 3 wind socks, 1 Drager H2S sniffer, 1 Bauer Breathable air compressor,

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

3 ½” Grade-E, 13.3 ppf, 10,000 ft. 2 3/8” Grade-E, 6.65 ppf, 5,650 ft. None 10 x 6 ¼”, 20 x 4 ¾”, 20 of 3 3/8”

H)

Depth Capacity

:

12,500 ft

I)

DF – GL Elevation Clearance below DF

: :

20.0 ft. 16.0 ft.

C)

D)

E)

2. 3.

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2.4.20

PA 858 (ONSHORE RIG)

A)

Year Built

:

1975

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Cabot / IRI Model 2042 (720 HP ) w/ Hydromatic Auxiliary Brake Cabot / IRI, 117 ft. 350,000 lbs None National C-275 (27 ½”) – 500 Ton McKissick – 250 Ton (Hook / Block Combination) National N-47 – 200 Ton Cabot Bogie type (wheel), Load 500,000 lbs. simultaneous capacity Totco, 6 pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

2 x Caterpillar 3412 – 665 HP ea w/ 650 KW generators 2 x Caterpillar 3406 – 350 HP ea. 2 x Caterpillar D 398 – 860 HP ea Compound Chain Drive (Mechanical Drive) None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 8-P-80 – 800 HP ea 1300 bbl. capacity with 100 bbl trip tank 1 x Derrick-Flo Line Cleaner none None None Brandt DG-10 – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey with 7 stations 2 1/16” Cameron 5000 psi WP, sour service Cameron UU 13 5/8” double ram, 5000 psi, Cameron U 13 5/8” single ram, 5000 psi, Hydril GK 13 5/8” Annular 5000 psi, All H2S trimmed

F)

Safety Equipment

:

54 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 16 x 30-min. Scott Air Pack SCBAs, 12 x 15min. Diablo Air packs, 2 portable gas / H2S monitors, 2 eye wash stations, 6 small bottle eye wash, 1 shower at mud pits, 4 wind socks, 1 BW Defender H2S sniffer, 1 Bauer Breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

3 ½” Grade E 13.3 ppf, 10,000 ft. 2 3/8” Grade E 6.65 ppf, 5,000 ft. None 14 of 6 ¼”, 20 of 4 ¾”, 20 of 3 3/8”

H)

Depth Capacity

:

12,500 ft

I)

DF – GL Elevation Clearance below DF

: :

18 .0 16.0

C)

D)

E)

2. 3.

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.21

PA-859 (ONSHORE RIG)

A)

Year Built

:

1977 (Refurbished & Upgraded to 1500 HP, August 2002)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110 UE (1500 HP) with Auxiliary Brake Pyramid, 25’ x 142 ft. 771,000 lbs. (static) with 12 lines None National C-375 (37-1/2”) – 500 Ton National – Type G 650 G500 (Hook/Block Combination) C. Emsco LB400 – 400 Ton Pyramid Wagner, 6-pen

: : : :

5 x Caterpillar D398, 960 HP ea. 2 x GE 752 motor – 800 HP ea. 4 x GE 752 – 800 HP ea. Ind. Dr., GE 752 motor – 800 HP, Torque 1000 Amps / 24,000 ft-

:

None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Continental Emsco FB1600 (1600 HP) & one Oilwell A 1100PT 4500 bbl. capacity, 120 bbl trip tank 2 x Derrick-Flo Line Cleaner Derrick High G Drier 1200 GPM Derrick High G Drier 1200 GPM None Swaco 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 10000 psi WP, sour service Hydril GX 11” annular 10,000 psi, 2 x Cameron U 11” double ram, 10,000 psi, All H2S trimmed.

F)

Safety Equipment

:

70 Fire extinguishers, 1 Fire pump, 1 gas detector, 4 H2S detectors, 1 cascade system, 17 Faber 15 min & 14 EA Diablo 30 min Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower-mud pits, 5 wind socks, 1 Drager H2S sniffer, 1 Mako Breathable air compressor,

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade G, 19.5 ppf, 15,000 ft, 3-1/2” Grade G, 13.3 ppf, 10,000 ft, 3-1/2” Grade E, 13.3 ppf, 4,000 ft., 3-1/2” Grade G, 15.5 ppf, 4,000 ft, 2-3/8” Grade E, 6.65 ppf, 4,000 ft 60 of 5”, 60 of 3-1/2” 30 of 6-1/4”, 30 of 4-3/4”, 15 of 3-3/8”

H)

Depth Capacity

:

16,000 ft.

I)

DF – GL Elevation Clearance below DF

: :

31 ft. 25 ft.

C)

D)

E)

52 of 102

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary lbs. 5. Top Drive

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DRILLING MANUAL

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GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.22

PA-860 (ONSHORE RIG)

A)

Year Built

:

1978 (Re-furbished – Dec. 2003)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Ideco E-1700 (1700 HP) with Elmagco 7838W Brake Pyramid 25 x 152 ft. 771,000 lbs with 12 lines Can Rig 1050E – 500 Ton Oilwell A 37 ½” Ideco –TB-525-6-50 – 400 Ton National P400 – 400 Ton Pyramid – Load Casing 700,000 lbs, Set back 500,000 lbs. Totco, 6-Pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D-398, 900 HP ea with 800 KW generators 2 x GE 752 Motors, 1000 HP ea. 4 x GE 752 Motors – 1000 HP ea. Ind. Drive, GE 752 Motor, 1000 HP (963 Amps / 19500 ft/lbs) GE 752 Motor, 1132 HP (1000 Amps / 33,300 ft/lbs)

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser 8. Dryer

: : : : : : : :

2 x Oilwell A1700PT (1700 HP) 3000 bbl. capacity with77 bbl. trip tank 3 x Derrick Flo Line Cleaners 2000 Demco 12” x 3 cone – 800 GPM Demco 4” x 16 cone – 800 GPM None Brandt Model DG-10 – 1000 GPM Derrick, Hi-“G”

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

Shaffer T20200, 3000 psi, 16 Stations 4 1/16”, 10,000 psi WP, sour service. Hydril 30” Annular 1000 psi, Hydril 21 ¼” Annular 2000 psi, Hydril 13 5/8” Annular 5000 psi, Hydril 11” Annular 5000 psi, 2 x Cameron 26 ¾” single ram 3000 psi, 2 x Cameron 13 5/8” double ram 10000 psi, Shaffer 20 ¾” double ram 3000 psi, Shaffer 20 ¾” single ram 3000 psi, All H2S trimmed. Shaffer 13 5/8” Rotating Head 500 psi WP

F)

Safety Equipment

:

50 Fire extinguishers, 1 Fire pump, 31 x 5-min. Breathing apparatus, Air Cascade system, 2 x BAUER BA compressor. 1 emergency shower, 4 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe ft.

:

5 ½” Grade G, 24.7 lbs/ft -10,000 ft, 5” Grade G, 19.5 lbs/ft 15,000

2. 3.

HWDP Drill collars

: :

3 ½” Grade G, 13.3 lbs/ft 9,000ft, 2 3/8” Grade-E, 6.65 lbs/ft 5000ft. 30 of 5 ½” & 50 of 5” & 50 of 3 ½” 18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 24 of 2 7/8”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

32.8 ft 25.3 ft

C)

D)

E)

53 of 102

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F

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.4.23

PA-866 (ONSHORE RIG)

A)

Year Built

:

1985 (Upgrade / Refurbishment done in 2003)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Continental Emsco, C-III (2000 HP) with Elmagco Auxiliary Brake Dreco 28 ft x 147 ft 1,555,000 lbs (with 14 lines) National PS-350/500 – 500 Ton National C-375 (37 ½”) – 650 Ton Continental Emsco – 650 Ton National P-500 – 500 Ton Dreco Sling Shot – casing 1,500,000 lbs., setback 800,000 lbs. MD Totco, 7-Pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x D-399 Caterpillar, 1195 HP ea. with 1030 KW generators 2 x GE 752 Motors, 1000 HP ea. 6 x GE 752 Motors – 1000 HP ea. Ind. Dr, GE 752 Motor – 1000 HP (1050 Amps / 54,000 ft.-lbs) GE 752 Motor – 1000 HP (1050 Amps / 54,000 ft.-lbs)

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Continental Emsco FB-1600 (1600 HP ea.) 4000 bbl with 120 bbl. Trip tank 3 x Derrick Super G Flo Line Cleaners 2 Derrick DSV-3, 3 x 12” cone – 1000 GPM 2 Derrick D-RND-16, 16 x 2” cone – 1600 GPM None Swaco – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, CAD SB360-11SB3K with 14 stations 4-1/16” EEC, 10,000 psi WP with 5 x HCR Valves, Sour Service Hydril 30” Annular 1000 psi with 7-1/16” HCR Diverter Valves, 2 x Cameron U 26-3/4” Single Ram, 3000 psi, Hydril MSP 21-1/4” Annular 2000 psi, Cameron UU 20-3/4” Double Ram 3000 psi, Cameron U 20-3/4” Single Ram 3000 psi, Hydril GK 13-5/8” Annular 5000 psi, Cameron UU 13-5/8” Double Ram 10,000 psi, 2 x Cameron U 13-5/8” Single Ram 10,000 psi – All H2S trimmed

F)

Safety Equipment

:

54 Fire extinguishers, 1 Fire pump, 1 (Pem Tech) Gas detector system with 1 LEL and 5 H2S detectors, 1 Bauer Cascade system breathable air compressor, 17 ea. Scott 30 min Air Packs SCBA's, 8 x 5-min. Scott Air Packs SCBA, 7 x 15-min Air Packs SCBA’s, 6 x Portable H2S monitors, 2 x Portable LEL monitors, 5 x Eye Wash Stations, Emergency Shower on Mud Pits, 7 Wind socks.

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5 ½” Grade G, 24.7 ppf, 12,000 ft., 5” Grade G, 19.5 ppf, 15,000 ft. 3-1/2” Grade G, 13.3 ppf, 9,000 ft. 15 of 6-5/8”, 30 of 5-½”, 50 of 5” and 50 of 3-½” 18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, and 30 of 4-3/4”

H)

Depth Capacity

:

28,000 ft

I)

DF – GL Elevation Clearance below DF

: :

38.2 ft 31.7 ft

C)

D)

E)

2. 3.

54 of 102

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F

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.5.1

PD-144 (ONSHORE RIG)

A)

Year Built

:

1978 (10’ mast extension)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-structure 9. Geolograph

: : : : : : : : :

Continental Emsco C-3 (3000 HP) with Elmagco 7838W brake Lee C. Moore 152 ft. 1,500,000 lbs. (static) with 14 lines Varco-IDS-1 Oilwell B-37.5, 37 ½” Oilwell A500 with BJ 5750 Dynaplex Hook Integrated with top drive Lee C. Moore Swing Up, casing 1,500,000 lbs, set back 750,000 lbs. MD Totco, 8 pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D3516, 1855 HP ea. w/ 1322 KW Generator 2 x GE 752 DC motor – 1000 HP ea. 6 x GE 752 – 1000 HP ea. (2 with each pump) Ind. drive, GE 752 motor 1000 HP AC Motor, 1000 HP.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Oilwell A-1700-PT – 1700 HP ea. 4000 bbl. capacity (active and reserve120 bbl. trip tank 3 x Derrick Flo-line Cleaners Demco 2 x 12” cone – 1600 GPM. Harrisburg 20 x 4” cone – 1600 GPM. None Swaco 225, double life vacuum – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 550USG. 4 1/16” 10000 psi w/ 2 x hydraulic chokes and one manual 2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trim. Hydril GL 13-5/8” x 5000 psi,

F)

Safety Equipment

:

100 Fire extinguishers, 1 Fire pump, Air cascade system, 12 Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed gas detection system, Portable gas detection Equipment, 5 eye wash stations, 2 emergency showers, 4 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: : :

5 ½” Grade G, 24.7 ppf, 12,000 ft. 5” Grade G, 19.5 ppf, 15,000 ft 3-1/2” Grade G, 13.3 ppf, 9,000 ft. 15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3 ½” 18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

20,000 ft

I)

DF – GL Elevation Clearance below DF

: :

35.0 ft 29.0 ft

C)

D)

E)

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___________________________________________________________________________________________________________________________

2.5.2

PD-157 (ONSHORE RIG)

A)

Year Built

:

1978

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-structure 9. Geolograph

: : : : : : : : :

Ideco E-1700 (1700 HP) with Elmagco 6032 auxiliary brake Dreco width x 142 ft 900,000 lbs. (static) with 12 lines None Oilwell B-37 ½” National 660H500 with BJ 5500 Dynaplex Hook, 1,000,000 lbs. Ideco TL-500, 1,000,000 lbs. Dreco Slingshot, casing 800,000 lbs, set back 880,000 lbs Specify type with number of pens and system ?

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 1200 HP ea. w/ 1050 KW Generator 2 x GE 752 DC motor – 1000 HP ea. 2 x GE 752 DC motors – 1000 HP ea. Ind. drive, GE 752 motor 1000 HP, Torque xxx Amps / xxxxx ft.-lbs N/A

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

1 x Oilwell A-1700-PT, 1 x Oilwell A-1400-PT, 1 x Ideco T-1600 3599 bbl. Capacity (active and reserve) mention trip tank ? 3 x Derrick Dual Flow with 2 x National Mud Cleaners (capacity?) Make ? 2 x 12” cone specify GPM ? Make ? 16 x 4” cone specify GPM ? None Make?, Closed Bottom, 36” OD, 4” Outlet (specify GPM ?)

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey 550 USG 4 1/16” Make?, 10000 psi w/ 2 x hydraulic chokes and one mannual 2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trim (check?) Hydril GL 13-5/8” x 5000 psi,

F)

Safety Equipment

:

100 Fire extinguishers, 1 Fire pump, Air cascade system, 12 Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed gas detection system, Portable gas detection Equipment, 5 eye wash stations, 1 emergency shower, 4 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: : :

5 ½” Grade G, 24.7 lbs./ft, 12,000 ft. 5” Grade G, 19.5 lbs/ft, 15000 ft 3 ½” Grade G, 13.3 lbs./ft, 9,000 ft. 15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3 ½” 18 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

xx,000 ft

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft 26.0 ft

C)

D)

E)

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2.5.3

PD-173 (ONSHORE RIG)

A)

Year Built

:

1981 (Blocks Re-built in 2006)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-structure 9. Geolograph

: : : : : : : : :

Gardner Denver 3000E w/ Baylor 7838 Electric Brake Dreco 147 ft. 1,300,000 lbs. (static) with 14 lines Varco IDS -1, 1000 HP Gardner Denver 37 ½” Dreco – 750 Ton Continental Emsco LB -500 Dreco Sling Shot capacity 1,500,000 lbs. MD Totco ,8 Pins

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar 399, 1300 HP ea w/ 1050 KW Generators 3 x GE 752 DC motor – 1000 HP ea. 6 x GE 752 motor – 800 HP ea. Ind. drive, GE 752 motor – 800 HP GE 752 Motor, 1000 HP, Torque – 34,000 ft/lbs

: : : : : :

3 x Gardner Denver PZ -11 (1600 HP) 4000 bbl. Capacity (active and reserve),2 x 66 Bbl trip tanks 3 x Derrick Model 58 Flo-line Cleaner Plus Harrisburg 3 x 10” cone – 600 GPM Harrisburg 20 x 5” cone – 600 GPM None : Swaco 2 stage vacuum pump – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

Cad Oilfield,3000 psi, 14 stations, 40 x 10 gal bottles 4 1/16” 10000 psi w/ 2 hydraulic and one manual chokes. 2 x Cameron U 13-5/8” double ram, 10000 psi, Hydril GL 13-5/8”, 5000 psi (H2S Trim)

Safety Equipment

:

95 Fire extinguishers, 1 Fire pump, Air cascade System, 13 x 5-min air packs, 13 x 30-min SCBA Air Packs, Fixed gas detection system (MSA Model 5300), Portable Gas Detection system (Bio systems), 4 x Eye Wash Stations, 1 x Emergency Shower, 5 x Wind Socks, 2 x

C)

D)

E)

F)

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

Sate Proving Areas

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill Collars

: : :

5 ½” Grade G, 24.7 ppf, 11,500 ft. 5” Grade G, 19.5 ppf, 18,200 ft 3 ½” Grade-G, 13.3 lbs./ft, 6200 ft. 38 x 6 5/8”, 53 x 5 ½”, 53 x 5” 16 of 10”, 22 of 8 ½”, 10 of 6 ¼”.”

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

38.0 ft 35.35 ft

57 of 102

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F

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.5.4

PD-174 (ONSHORE RIG)

A)

Year Built

:

1981

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-structure 9. Geolograph

: : : : : : : : :

Emsco C-3 (3000 HP) with Elmagco 7838W auxiliary brake Pyramid 152 ft 1,300,000 lbs. (static) with 14 lines Varco IDS 1 – 500 Ton National Oilwell A-375 (37 ½”) – 500 Ton Emsco RA-60-6 (1,300,000 lbs) with BJ 5500 Dynaplex Hook Integrated with top drive Dreco Raised Floor, casing 1,000,000 lbs, set back 800,000 lbs M.D, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D399, 1200 HP ea. w/ 1000 KW Generator 2 x GE 752 DC motor – 1000 HP ea. 6 x GE 752 – 1000 HP ea. Ind. Dr, GE 752 motor 1000 HP, Torque 1050 Amps / 54,000 ft.-lbs GE 752 – 1000 HP, Torque 1050 Amps / 54,000 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Emsco F-1600 (1600 HP) 4000 bbl. Capacity (active and reserve) with 67/52 bbl. trip tank 3 x Derrick 58 and 2 x Harrisburg Mud Cleaners Harrisburg 4 cone – 1600 GPM Harrisburg 20 x 4” cone – 1600 GPM None One Atmospheric, One Double Life Vacuum – 1600 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomy 550 USG Type 80 4 1/16” 10000 psi w/ 2 x hydraulic chokes and one mannual 2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trimmed. Hydril GL 13-5/8” x 5000 psi

F)

Safety Equipment

:

100 Fire extinguishers, 1 Fire pump, Air cascade system, 12 Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed gas detection system, Portable gas detection Equipment, 5 eye wash stations, 1 emergency shower, 5 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5 ½” Grade XD-105, 27.06 ppf, 15,000 ft. 5 ½” Grade S-135, 27.53 ppf, 6,900 ft 4” Grade G-105, 14.0 ppf, 10,235 ft. 27 x 6 5/8”, 50 x 5 ½”, 100 x 4” 9 of 10”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H)

Depth Capacity

:

25,000 ft

I)

DF – GL Elevation Clearance below DF

: :

35.0 ft 29.0 ft

C)

D)

E)

58 of 102

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F

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.5.5

PD-786 (ONSHORE RIG)

A)

Year Built

:

2001

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-structure 9. Geolograph

: : : : : : : : :

Oilwell E-2000 (2000 HP) with Elmagco 7838W auxiliary brake Pyramid 162 ft 1,275,000 lbs. (static) with 14 lines Varco TDS 11SA C. Emsco T-3750 (37 ½”) – 650 Ton Oilwell A500 with BJ 5500 Dynaplex Hook Integrated with top drive Pyramid Swing Up, casing 1,275,000 lbs, set back 750,000 lbs M.D / Totco 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D3516, 1855 HP ea. w/ 1322 KW Generator 2 x GE 752 DC motor – 1000 HP ea. 2 x GE 752 – 1000 HP ea. Chain Drive with Drawworks 2 x AC Motor, 400 HP ea.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Oilwell A-1700-PT (1700 HP) 4400 bbl. Capacity (active and reserve) with 57/65 bbl. trip tanks 3 x Brandt King Cobra Brandt 2 x 12” cone – 1000 GPM Brandt 16 x 4” cone – 1000 GPM None One Atmospheric, One Double Life Vacuum

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey 550 USG w/ 50 x 11 gal. bottles 4 1/16” 10000 psi w/ 2 x hydraulic and one mannual chokes 2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trimmed Hydril GL 13-5/8” x 5000 psi

F)

Safety Equipment

:

36 Fire extinguishers, 1 Fire pump, 2 x Air cascade system, 15 Breathing apparatus, 4 station Fixed gas detection system, 2 set Portable gas detection Equipment, 6 eye wash stations, 3 emergency shower, 4 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: : :

5 ½” Grade G, 24.7 lbs./ft, 12,000 ft. 5” Grade G, 19.5 lbs/ft, 15000 ft 3-1/2” Grade G, 13.3 lbs./ft, 9,000 ft. 15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3-1/2” 18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H)

Depth Capacity

:

19,000 ft

I)

DF – GL Elevation Clearance below DF

: :

35.5 ft 29.25 ft

C)

D)

E)

59 of 102

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Drilling & Workover Engineering Department CHAPTER 1

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F

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.5.6

PD-787 (ONSHORE RIG)

A)

Year Built

:

1978 (New Derrick and Substructure: 2001)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-structure 9. Geolograph

: : : : : : : : :

National 1320-UE (2000 HP) with Elmagco 7838 Auxiliary Brake Pyramid 30 x 162 ft. 1,275,000 lbs (static) w/ 14 lines, 900,000 lbs. (static) w/ 12 lines Varco TDS-11SA – 500 Ton Oilwell BC37 ½” – 650 Ton BJ 5500 Dynaplex Hook – 500 Ton Integrated with top drive Pyramid, casing 800,000 lbs, set back 880,000 lbs. M.D. / Totco, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D3516, 1855 HP ea. w/ 1322 KW Generator 2 x GE 752 DC motor – 1000 HP ea. 6 x GE 752 DC motors – 1000 HP ea. Drive Not Installed 2 x AC motors – 400 HP ea. Torque 37,000 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

3 x Oilwell A-1700-PT – 1600 HP ea. 4000 bbl. capacity with 2000 bbl. active and 2 x 60 bbl. trip tanks. 3 x Brandt King Cobra shakers, 2 x Brandt KC Cleaner – 2000 GPM Brandt 2 x 12” cone – 1000 GPM Brandt 16 x 4” cone – 1000 GPM None DL Closed Bottom, 36” OD, 8” Outlet – 700 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey 550USG, 14 stations 4-1/16” ECC, 10,000 psi w/ 2 x hydraulic and one manual chokes Hydril GL 13-5/8” annular 5000 psi, 2 x Cameron U 13-5/8” double ram, 10000 psi, H2S trimmed

F)

Safety Equipment

:

100 Fire extinguishers, 1 Fire pump, Air cascade system, 12 x 5-min. Breathing Apparatus, 19 x 30-min. SCBA, Fixed gas detection system, Portable gas detection equipment, 5 eye wash stations, 2 emergency shower, 4 wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5.5” Grade XT-105 24.7 ppf, 15,000 ft, 5.5” Grade S-105 24.7 ppf, 7,000 ft, 4” Grade XT-105 14.0 ppf, 7,000 ft. 115 of 5” 11 of 10”, 19 of 8-1/4”, 28 of 6 -1/2”

H)

Depth Capacity

:

20,000 ft. with 5” drillpipe

I)

DF – GL Elevation Clearance below DF

: :

35.0 ft 30.0 ft

C)

D)

E)

60 of 102

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Drilling & Workover Engineering Department CHAPTER 1

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F

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.6.1

SAR-102 (ONSHORE RIG)

A)

Year Built

:

1991 (Out of Service from Dec. 1998 to Aug. 2005)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Skytop Brewster H1-4610B1-38, 500 HP with auxiliary brake Skytop Brewster, 110 ft. 275,000 lbs with 8 lines None Skytop Brewster RSB-275, 27 ½” – 500 Ton BJ HB-154 – 150 Ton Oilwell – 225 Ton Skytop Brewster, Load capacity 290,000 lbs setback None

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

2 x Caterpillar D379, 600 HP ea. w/ 460KW Generators Detroit Diesel 12A-90748 – 575 HP 2 x Caterpillar D398 – 1100 HP ea. Load capacity 500 Ton, 350 RPM None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Garden Denver PZ-8, Triplex – 1100 HP ea 1015 bbl. Capacity (active and reserve) 60 bbl trip tank 1x Derrick Flo-Line Cleaner Brandt 2 x 12” cone – 1000 GPM None None Poor-boy, 24” OD, 3” Outlet – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Cameron 8 station, 40 bottles 2 1/16” 5000 psi H2S trimmed Shaffer 11” Annular 5000 psi, 1 x Shaffer 11” double ram, 5000 psi, 1 x Shaffer single ram 5000 psi, All H2S trimmed

F)

Safety Equipment

:

44 Fire extinguishers, 1 Fire pump, 1 x Air Cascade system, 27 x 30-min. SCBA, 10 x 5-min. SCBA, 1 x 5-station gas detector, 4 x H2S detectors, 2 x portable gas detectors, ,3 x wind socks, 2 x shower stations, 3 x eye wash stations, 1 x Breathing Air compressor

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

3 ½” Grade G, 13.3 ppf, 7,500 ft. 2 3/8”” Grade G, 6.7 ppf, 6,500 ft. 10 of 3-1/2” 22 of 4 ¾”, 18 of 3 3/8”

H)

Depth Capacity

:

7,000 ft with 3 ½” drillpipe

I)

DF – GL Elevation Clearance below DF

: :

15.0 ft 12.5 ft

C)

D)

E)

61 of 102

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F

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June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.6.2

SAR-103 (ONSHORE RIG)

A)

Year Built

:

1993

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Skytop Brewster 950 HP with auxiliary brake Skytop Brewster 25 x 115 ft. 275,000 lbs with 10 lines None Skytop Brewster RSB-375, 37 ½” Web Wilson 250 Ton Oilwell 225 Ton Skytop Brewster, Load capacity 290,000 lbs setback Totco, 6 pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

2 x Caterpillar D379 – 600 HP ea. w/ xxxx KW Generator 2 x Caterpillar 3408 – 450 HP ea. 2 x Caterpillar 398 – 1100 HP ea. xxxxxxx 1000 HP, Torque xxx Amps / 410,000 ft.-lbs N/A

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Garden Denver PZ-8, Triplex – 750 HP ea 820 bbl. Capacity (active and reserve) 35 bbl trip tank 1x Derrick Flo-Line Cleaner (Tandem unit) None None Mission Magnum 6” x 8” – 75 HP None

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Cameron 7 stations 2 1/16” 5000 psi H2S trimmed Shaffer 11” Annular 5000 psi, 1 x Shaffer 11” double ram, 5000 psi, All H2S trimmed

F)

Safety Equipment

:

44 Fire extinguishers, 1 Fire pump, 1 x Air Cascade system, 27 x 30-min. SCBA, 10 x 5-min. SCBA, 1 x 5-station gas detector, 4 x H2S detectors, 2 x portable gas detectors, ,3 x wind socks, 2 x shower stations, 3 x eye wash stations, 1 x Breathing Air compressor. H2S LEL 5-channel fixed combustible gas detection system

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

3 ½” Grade G, 13.3 lbs/ft, 9000 ft. 2 3/8”” Grade G, 6.65 lbs./ft, 600 ft. 2 of 3 ½” 15 of 4 ¾”, 20 of 3 3/8”

H)

Depth Capacity

:

10,000 ft with 3 ½” drillpipe

I)

DF – GL Elevation Clearance below DF

: :

18.0 ft 13.5 ft

C)

D)

E)

62 of 102

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DRILLING MANUAL

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GENERAL INFORMATION

F

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June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.6.3

SAR-151 (ONSHORE RIG)

A)

Year Built

:

1975 (Refurbished 1996

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Midcontinental U712-EA – 1200 HP with Elmagco auxiliary brake Lee C. Moore 25 x 115 ft. 550,000 lbs with 8 lines None National C-375, 37 ½” Ideco – 350 Ton National P-4000 – 400 Ton Aramco made, Load capacity, setback 290,000 lbs. MD / Totco 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

Type of engines? 1500 HP ea. w/ 1000 KW Generators 2 x GE 752 DC motor – 1000 HP ea. 2 x GE 752 DC motors – 1000 HP ea. Ind. Dr, GE 752 motor 1000 HP, Torque 800 Amps None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Oilwell A-1700 PT, Triplex – 1700 HP ea 1335 bbl. Capacity (active and reserve) 70 bbl trip tank 2 x Derrick Flo-Line Cleaner Brandt double 2 x 12” cone – 1000 GPM Brandt double 2 x 12” cone – 1000 GPM None None

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Cameron 8 station 3 1/8” 5000 psi WP, H2S trimmed Shaffer 13 5/8” Annular 3000 psi, Shaffer 13 5/8” double ram, 5000 psi, Shaffer 11” Annular 3000 psi, All H2S trimmed

F)

Safety Equipment

:

40 Fire extinguishers, 1 Fire pump, 1 x Air Cascade system, 30 x 30-min. SCBA, 11 x 5-min. SCBA, 5-station gas detector, 4 x H2S detectors, 2 x portable gas detectors, ,3 x wind socks, 2 x shower stations, 3 x eye wash stations, Breathing Air compressor. H2S Light & siren 5-channel fixed combustible gas detection system

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade G, 19.5 ppf, 6,900 ft. 3 ½” Grade G, 13.3 ppf, 7,200 ft. 25 of 5”, 12 of 3 ½” 3 of 10”, 18 of 8”, 23 of 6 ¼”, 24 of 4 ¾”

H)

Depth Capacity

:

12,000 ft

I)

DF – GL Elevation Clearance below DF

: :

16.3 ft 13.0 ft

C)

D)

E)

63 of 102

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F

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June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.6.4

SAR-153 (ONSHORE RIG)

A)

Year Built

:

1993 (Completely Refurbished in 1998)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110 UE – 1500 HP with auxiliary brake Pyramid 25 x 147 ft. 750,000 lbs with 12 line. National PS350/500 – 250 Ton National A or B 375, 37 ½” Make & model? 350 Ton Make and model? 400 Ton Pyramid, specify type?, Load setback 290,000lbs lbs. Totco 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D3512 – 1321 HP ea. w/ xxxx KW Generator 2 x GE 752 DC motor – 750 HP ea. 2 x GE 752 DC motors – 1300 HP ea. Ind. drive, GE 752 motor 1365 HP, Torque xxx Amps / xxxxx ft.-lbs 2 x AC motors, 350 HP ea. Torque xxx Amps / xxxxx ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 10P-130, Triplex – 1300 HP ea 1500 bbl. Capacity (active and reserve) 60 bbl trip tank 2 x Derrick Flo-Line Cleaner Derrick x” x 3 cone – 500 GPM Derrick x” x 15 cone – 500 GPM None Derrick Vacu-Flow – 1000 GMP, Poor Boy 24” dia – xxx GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Stewart & Stevenson x station (Check?) 3 1/8” 5000 psi WP, Cameron H2S trimmed Hydril 13 5/8” Annular 3000 psi, 1 x Cameron 13 5/8” double ram, 3000 psi, All H2S trimmed

F)

Safety Equipment

:

40 Fire extinguishers, 1 Fire pump, 1 x Air Cascade system, 25 x 30-min. SCBA, 11 x 5-min. SCBA, 1 x 5-station gas detector, 4 x H2S detectors, 2 x portable gas detectors, ,3 x wind socks, 2 x shower stations, 3 x eye wash stations, 1 x Breathing Air compressor. H2S Light & siren 5-channel fixed combustible gas detection system

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5” Grade E, 19.5 lbs/ft, xxxxx ft. 3 ½” Grade G, 13.3 lbs./ft, xxxxx ft. xx of 5”, xx of 3 ½” xx of 8”, xx of 6 ¼”, xx of 4 ¾”

H)

Depth Capacity

:

16,000 ft

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft 24.6 ft

C)

D)

E)

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Drilling & Workover Engineering Department CHAPTER 1

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.1

SINO-1 (ONSHORE RIG)

A)

Year Built

:

1999 (Upgraded to 1500 HP in 2002)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

3H, JC50D – 1500 HP with DS-50 CURRUNT Brake Lanzho Pet. & Chem. Mach. Factory, LL315/45K, 26’ x 147 ft. 770,000 lbs with 10 lines Varco TDS 11SA – 350 Ton LPMP, ZP-375, 37 ½” – 600 Ton LPMP, TC350 (Hook/Block Combination) – 350 Tons LPMP, SL450 – 300 Ton 3H, Pyramid slingshot type, casing 500,000 lbs, setback 350,000 lbs. TDS-2000 Petron, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512, 1381 HP ea. with 1400 KW generators 2 x GE 752 motor, 1500 HP ea. 4 x GE 752 motor, 1000 HP ea. YJ23A motor – 800 HP, Torque 24,000 ft-lbs 2 x AC motor – 400 HP ea., Torque, 30,000 ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x BPMP F-1300 – 1300 HP ea. 2000 bbl. capacity, 60 bbl trip tank 2 x Derrick Flo-line cleaner Derrick 2 x 12” – 800 GPM Derrick 16 x 2” – 800 GPM None ZDRI, ZCQ/4– 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, CAP Specialties Inc., SB330-15SB3K-14 stations 3-1/8”, 3H, 3000 psi WP, JLGH 3000 psi, sour service Cameron 13 5/8” annular 3000 psi Cameron U 13 5/8” double ram, 3000 psi Cameron U 13-5/8” single ram, 3000 psi All H2S trimmed

:

60 Fire extinguishers, 1 fire pump, 2 gas detector, 4 H2S Detector, Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 3 eye wash stations, 2 showers, 4 wind socks, 1 breathable air compressor

HWDP Drill collars

: : : :

5” Grade G-105, 19.5 ppf, 5000 ft. 4”.Grade CY-105, 15.67 ppf, 15000 ft. 20 of 5” 15 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

8,000 feet

I)

DF – GL Elevation Clearance below DF

: :

29.6 ft. 25.0 ft.

C)

D)

E)

F)

G)

Safety Equipment

Drill Pipe & Drill Collars 1. Drill Pipe 2. 3.

65 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.2

SINO-2 (ONSHORE RIG)

A)

Year Built

:

2003

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

NanYang Pet. Machinery, JC30/11700CZ (737HP) NYPM, JJ-18938, 24’ x 147 ft. 405,000 lbs (static) with 10 lines None NYPM, ZP27-1/2” NYPM, TC180/YG-180 – 180 Ton NYPM, SL225 – 225 Ton NYPM, Load casing 505,000 lbs. VDX, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

2 x Caterpillar 3408C, 530 Hp ea. JC28/11 3 x Volvo – 530 HP ea. Motor – 650 HP, Torque 20,300 ft-lbs. None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x QZ 3NB-800 – 800 HP ea. 1300 bbl. 2 x Derrick 1 x GQC250II – 800 GPM 1 x ZQJ100 – 800 GPM 1 x GLW458-842N – 200 GPM 1 x ZCQ/4 – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, FKQ840-8, 224 gal. 3-1/8” San Yi Pet. Machinery, 5000 psi Cameron Type-D 13-5/8” Annular, 3000 psi Cameron Type-U 13-5/8” double ram, 3000 psi.

F)

Safety Equipment

:

50 Fire extinguishers, 4 H2S detectors, Cascade System, 10 SCBAs, 12SABAs, 2 portable gas / H2S monitors, 3 eye wash stations, 1 shower at mud pits, 1 Drager H2S sniffer,1 Breathable air compressor, 2 Hydrant

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

3-1/2” Grade E 13.3 ppf, 10,000 ft. 2-3/8” Grade E, 6.65 ppf, 8,000 ft. None 10 of 6-1/4”, 20 of 4-3/4”, 20 of 3-3/8”

H)

Depth Capacity

:

10,000 ft. with 3-1/2” Drillpipe

I)

DF-GL Elevation Clearance below DF

: :

C)

D)

E)

2. 3.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.3

SINO-3 (ONSHORE RIG)

A)

Year Built

:

2005

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

3H, JC40D – 1500HP with 336WCB2 Eton Brake 3H, JJ250/45K, 26 ft x 147 ft. 500,000 lbs with 10 lines None LPMP, ZP-275, 27 ½” – xxx Ton LPMP, YC250 (Hook/Block Combination) – 250 Tons LPMP, SL250 – 250 Ton 3H, Pyramid slingshot type, casing 500,000 lbs, setback 250,000 lbs. VDX, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x Caterpillar 3512B, 1749 HP ea. with 1778KVA generators 2 x Make? YJ13A motor, 500 HP ea. 4 x Make? YJ13A motor, 500 HP ea. YJ13A motor – 800 HP, Torque rating 24,000ft-lbs None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x BPMP F-1300 – 1300 HP ea. 1500 bbl. capacity, 70 bbl trip tank 2 x Derrick Flo-line cleaner Derrick 2 x 12” – 800 GPM Derrick 16 x 2” – 800 GPM None ZDRI, ZCQ/4 – 600 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs(CIW)

: : :

3000 psi WP, Beijing Pet. Machinery Plant, FKQ-800-8 stations 3-1/8”, 3H, 3000 psi WP, JLGH 3000 psi, sour service Cameron 13 5/8” annular 3000 psi Cameron U 13 5/8” double ram, 3000 psi Cameron U 13-5/8” single ram, 3000 psi All H2S trimmed

:

40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, 1 Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 showers, 4 wind socks, 1 breathable air compressor

HWDP Drill collars

: : : : :

5” Grade G-105, 19.5 ppf, 5000 ft. 3 ½”.Grade G-105, 15.5 ppf, 5000 ft. 2 3/8” Grade E, 6.6 ppf, 5000 ft. 20 of 5” 15 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”, 30 of 3 1/8”.

H)

Depth Capacity

:

8,000 feet

I)

DF – GL Elevation Clearance below DF

: :

29.6 ft. 24.0 ft.

C)

D)

E)

F)

G)

Safety Equipment

Drill Pipe & Drill Collars 1. Drill Pipe

2. 3.

67 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.4

SINO-5 (ONSHORE RIG)

A)

Year Built

:

2001

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Dreco D1500 AC 11 (1500 HP) with no Auxiliary Brake Pyramid 25’ x 142 ft. 750,000 lbs. (static) with 12 lines MH PTD-500-AC – 500 Ton National D375, 37 ½” – 650 Ton Dreco 650B-400 – 450 Ton (Hook/Block Combination) SL450 – 450 Tons Pyramid box-on-box type, casing 600,000 lbs, setback 450,000 lbs. Martin Decker, 6 pen with Mud Watch

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x Caterpillar 3512, 1750 HP ea. w/ 1150 KW generators 2 x GEB 22A1 motor – 1150 HP ea. 2 x GEB 22A1 motor – 1150 HP ea. GEB22A1 motor – 1150 HP, Torque 24,000 ft-lbs. Reliance motor, 400 HP, Torque 45,000ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Baoji China F1600 (1600 HP ea.) 2000 bbl. capacity with 120 bbl trip tank 3 x Derrick liner motion Flo-line Derrick 2 x 12” cone – 1200 GPM Derrick 16 x 2” cone – 1200 GPM None Baoshi China ZCQ/4 – 1050 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs (CIW)

: : :

3000 psi WP, CAD 14 stations 3-1/16” Yan Cheng China 5000 psi WP, sour service Cameron 13-5/8” Annular 5000 psi, Cameron 13-5/8” double ram, 5000 psi w/SBR, Cameron 13-5/8” single ram, 5000 psi, All H2S trimmed

Safety Equipment

:

60 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, cascade system, 14SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 shower, 4 wind socks, 1 breathable air compressor

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

4” Grade-G 14.0 ppf, 16,000 ft. 3 ½” Grade-G 13.3 ppf, 5,000 ft, 2 3/8” Grade-E 6.6 ppf, 5,000 ft. 60 of 5”, 60 of 4” 30 of 6 ¼”, 30 of 4 ¾”, 30 of 2 7/8”

H)

Depth Capacity

:

18,000 ft.

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft. 27.0 ft.

C)

D)

E)

F)

G)

68 of 102

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.5

SINO-6 (ONSHORE RIG)

A)

Year Built

:

2001

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Dreco D1500 AC 11 (1500 HP) with no Auxiliary Brake Pyramid 25’ x 142 ft. 750,000 lbs. (static) with 12 lines MH PTD-500-AC – 500 Ton National D375, 37 ½” – 650 Ton Dreco 650B-400 – 450 Ton (Hook/Block Combination) SL450 – 450 Tons Pyramid box-on-box type, casing 600,000 lbs, setback 450,000 lbs. Martin Decker, 6 pen with Mud Watch

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x Caterpillar 3512, 1750 HP ea. w/ 1150 KW generators 2 x GEB 22A1 motor – 1150 HP ea. 2 x GEB 22A1 motor – 1150 HP ea. GEB22A1 motor – 1150 HP, Torque 24,000 ft-lbs. Reliance motor, 400 HP, Torque 45,000ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Baoji China F1600 (1600 HP ea.) 2000 bbl. capacity with 120 bbl trip tank 3 x Derrick liner motion Flo-line Derrick 2 x 12” cone – 1200 GPM Derrick 16 x 2” cone – 1200 GPM None Baoshi China ZCQ/4 – 1050 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs (CIW)

: : :

3000 psi WP, CAD 14 stations 3-1/16” Yan Cheng China 5000 psi WP, sour service Cameron 13-5/8” Annular 5000 psi, Cameron 13-5/8” double ram, 5000 psi w/SBR, Cameron 13-5/8” single ram, 5000 psi, All H2S trimmed

Safety Equipment

:

60 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, cascade system, 14SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 shower, 4 wind socks, 1 breathable air compressor

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

4” Grade-G 14.0 ppf, 16,000 ft. 3 ½” Grade-G 13.3 ppf, 5,000 ft, 2 3/8” Grade-E 6.6 ppf, 5,000 ft. 60 of 5”, 60 of 4” 30 of 6 ¼”, 30 of 4 ¾”, 30 of 2 7/8”

H)

Depth Capacity

:

18,000 ft.

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft. 27.0 ft.

C)

D)

E)

F)

G)

69 of 102

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.6

SINO-7 (ONSHORE RIG)

A)

Year Built

:

2001

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Nan yang Pet. Machinery with Pneumatic Auxiliary Brake NPMC, 20’ x 147 ft. 396,000 lbs (static) with 10 lines. None Lan Zhou Pet. Machinery, ZP-275, 27 ½” YG-180 – 180 Ton Lan Zhou Pet. Machinery, SL225 – 225 Ton Nan yang Pet. Machinery, Slingshot. setback 200,000 lbs. M.D., 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

2 x CAT 3408C DITA – 475 HP ea. w/ 343 KW generators 2 x CAT 3408C DITA – 475 HP ea. 2 x CAT 3412EC DITA – 800 HP ea Nanyang Pet .Machinery – 700 HP, Torque 20,267 ft-lbs. None.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Oilwell F-800 (800 HP ea.) 1500 bbl. capacity with 60 bbl trip tanks 2 x Kemtron Liner Motion Flo-Line None None None Drilling Research Institute, ZCQ/4 – 800 GPM

: :

3000 psi WP, FKQ-800 with 8 stations 2 9/16” Yan Cheng San YIPEC Machinery, 3000 psi WP, sour

:

Shaffer 13 5/8” Annular 3000 psi, Shaffer 13 5/8” double ram, 3000 psi with SBR, Shaffer 11” single ram 3000 psi, Shaffer 11” double ram 3000 psi w/ blind rams, Shaffer 11” Annular 3000 psi, All H2S trimmed

:

40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, 1 cascade system, 14SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 shower, 4 wind socks, 1 breathable air compressor.

HWDP Drill collars

: : : :

3 ½” Grade-E, 13.3 ppf, 10,000 ft. 2 3/8” Grade-E, 6.6 ppf, 10,000 ft. None 10 x 6 ¼”, 20 x 4 ¾”, 20 of 3 3/8”

H)

Depth Capacity

:

10,000 feet

I)

DF – GL Elevation Clearance below DF

: :

20.0 ft. 16.0 ft.

C)

D)

E)

BOP Equipment 1. Accumulator 2. Choke manifold service 3. BOPs

F)

Safety Equipment

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. 3.

70 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.7

SINO-9 (ONSHORE RIG)

A)

Year Built

:

2005

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

ZJ50, Model3150D, 2180 HP with Eton WCBD336 Auxiliary Brake 3H, JJ315/45 –K3 700,000 lbs with 12 lines BPM DQ70BSC – 450 Ton LPMP, ZP-375, 37 ½” – 585Ton LPMP, TC350 (Hook/Block Combination) – 350 Tons LPMP, SL450 – 450 Ton 3H, Pyramid slingshot type, casing 700,000 lbs, setback 400,000 lbs. VDX, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x Caterpillar 3512 – 1820 HP ea. 2 x GE 752 motor, 1000 HP ea. 4 x GE 752 motor, 1000 HP ea. YZ08B motor – 800 HP, Torque 1150 Amps, 24,000 ft-lbs 2 x AC motor – 800 HP, Torque 36,000 ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x BPMP F-1600 – 1600 HP ea. 2000 bbl. capacity, 60 bbl trip tank 3 x Derrick Flo-line cleaner Centrifugal 6 x 8” – 1600 GPM Centrifugal 6 x 8” – 1600 GPM None ZDRI, ZCQ/4 – 880 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs(CIW)

: : :

3000 psi WP, Beijing Pet. Machinery Plant, FKQ1440-14stations 3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service Cameron 13 5/8” annular 3000 psi Cameron U 13 5/8” double ram, 3000 psi Cameron U 13-5/8” single ram, 3000 psi All H2S trimmed

:

60 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 showers, 4 wind socks, 1 breathable air compressor

HWDP Drill Collars

: : : :

5” Grade G-105, 19.5 ppf, 5000 ft. 4”.Grade G-105, 15.9 ppf, 5000 ft. 20 of 5”, 60 of 4” 9 of 9-1/2”,16 of 8 ¼”, 25 of 6 ¼”, 20 of 4 ¾”,.

H)

Depth Capacity

:

18,000 feet

I)

DF – GL Elevation Clearance below DF

: :

29.6 ft. 25.43ft.

C)

D)

E)

F)

G)

Safety Equipment

Drill Pipe & Drill Collars 1. Drill Pipe 2. 3.

71 of 102

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.9

SINO-10 (ONSHORE RIG)

A)

Year Built

:

2006

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

3H, JC70D, 2000HP with 336WCB2 Eton Brake 3H, JJ450, 26 ft x 147 ft. 1,000,000 lbs (static) with 10 lines Varco, TDS-11SA – 500 Ton LPMP, ZP-375, 37 ½” – 500 Ton LPMP, YC450 (Hook/Block Combination) – 450 Tons LPMP, SL450 – 450 Ton 3H, Pyramid slingshot type, casing 700,000 lbs, setback 350,000 lbs VDX, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512B, 1747 HP ea. w/ KATO 1778KW generators 2 x YZ08 motor, 1000 HP ea. 4 x YZ08 motor, 1000 HP ea. YZ08 motor – 100 HP, Torque 000000 Amps, 24,000 ft-lbs Make & Model? motor, 800 HP, Torque 000000 Amps, 00000 ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Make? 3NB100 – 1600 HP ea. 2000 bbl. capacity, 2 x 60 bbl trip tanks 3 x Derrick Liner Motion Flo-line Centrifugal 6” x 8” – 1600 GPM Centrifugal 6” x 8” – 850 GPM None ZDRI, ZCQ/4 – 880 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Beijing Pet. Machinery Plant, FKQ-1440-14 stations 3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service Cameron 21 ¼” annular 2000 psi, Cameron 13 5/8” annular 5000 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi All H2S trimmed

:

40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, 1 Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 showers, 4 wind socks, 1 breathable air compressor

HWDP Drill collars

: : : : :

5” Grade-G, 19.5 ppf, 10,000 ft. 4”.Grade-G, 14.0 ppf, 18,000 ft. 2 3/8” Grade-E, 6.6 ppf, 5000 ft. 80 of 5”, 100 of 4” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ½”, 30 of 4 ¾”, 30 of 2 7/8”.

H)

Depth Capacity

:

18,000 ft.

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft. 25.0 ft.

C)

D)

E)

F)

G)

Safety Equipment

Drill Pipe & Drill Collars 1. Drill Pipe

2. 3.

72 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.9

SINO-12 (ONSHORE RIG)

A)

Year Built

:

2006

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

3H, JC50DB, 1500HP with 336WCB2 Eton Brake 3H, JJ450, 26 ft x 148 ft. 750,000 lbs (static) with 10 lines Varco, PTD-500-AC – 500 Ton LPMP, ZP-375, 37 ½” – 500 Ton LPMP, YC350 (Hook/Block Combination) – 350 Tons LPMP, SL450 – 450 Ton 3H, Pyramid slingshot type, casing 700,000 lbs, setback 350,000 lbs VDX, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x Caterpillar 3512B, 1600 HP ea. w/ KATO 1778KW generators 2 x YJ31 motor, 1000 HP ea. 4 x YJ31 motor, 1000 HP ea. YJ31 motor – 750 HP, Torque 000000 Amps, 24,000 ft-lbs MH, AC motor, 800 HP, Torque 000000 Amps, 00000 ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National F1600 – 1600 HP ea. 2000 bbl. capacity, 2 x 60 bbl trip tanks 3 x Derrick Liner Motion Flo-line Centrifugal 6” x 8” – 1600 GPM Centrifugal 6” x 8” – 850 GPM None ZDRI, ZCQ/4 – 880 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Beijing Pet. Machinery Plant, FKQ-1440-14 stations 3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service Cameron 21 ¼” annular 2000 psi, Cameron 13 5/8” annular 5000 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi All H2S trimmed

:

40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, 1 Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 showers, 4 wind socks, 1 breathable air compressor

HWDP Drill collars

: : : : :

5” Grade-G, 19.5 ppf, 10,000 ft. 4”.Grade-G, 14.0 ppf, 18,000 ft. 2 3/8” Grade-E, 6.6 ppf, 5000 ft. 80 of 5”, 100 of 4” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ½”, 30 of 4 ¾”, 30 of 2 7/8”.

H)

Depth Capacity

:

8,000 ft.

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft. 25.0 ft.

C)

D)

E)

F)

G)

Safety Equipment

Drill Pipe & Drill Collars 1. Drill Pipe

2. 3.

73 of 102

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.7.10

SINO-18 (ONSHORE RIG)

A)

Year Built

:

2006

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

3H, JC70D, 2000HP with 336WCB2 Eton Brake 3H, JJ450, 30 ft x 148 ft. 1,000,000 lbs (static) with 10 lines Varco, PTD-500-AC – 500 Ton LPMP, ZP-375, 37 ½” – 500 Ton LPMP, YC450 (Hook/Block Combination) – 450 Tons LPMP, SL450 – 450 Ton 3H, Pyramid slingshot type, casing 700,000 lbs, setback 350,000 lbs VDX, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512B, 1749 HP ea. w/ KATO 1778KW generators 2 x YJ13A motor, 800 HP ea. 4 x YJ13A motor, 800 HP ea. YJ13A motor – 800 HP, Torque rating 24,000ft-lbs MH, AC motor, 800 HP, Torque rating 30,000ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x 3NB-1300 – 1300 HP ea. 2000 bbl. capacity, 2 x 60 bbl trip tanks 3 x Derrick Liner Motion Flo-line Centrifugal 6” x 8” – 1600 GPM Centrifugal 6” x 8” – 850 GPM None ZDRI, ZCQ/4 – 880 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Beijing Pet. Machinery Plant, FKQ-1440-14 stations 3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service Cameron 21 ¼” annular 2000 psi, Cameron 13 5/8” annular 5000 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi All H2S trimmed

:

40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, 1 Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 showers, 4 wind socks, 1 breathable air compressor

HWDP Drill collars

: : : : :

5” Grade-G, 19.5 ppf, 10,000 ft. 4”.Grade-G, 14.0 ppf, 18,000 ft. 2 3/8” Grade-E, 6.6 ppf, 5000 ft. 80 of 5”, 100 of 4” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ½”, 30 of 4 ¾”, 30 of 2 7/8”.

H)

Depth Capacity

:

18,000 feet

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft. 25.0 ft.

C)

D)

E)

F)

G)

Safety Equipment

Drill Pipe & Drill Collars 1. Drill Pipe

2. 3.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.8.1

SP-101 (ONSHORE RIG)

A)

Year Built

:

2006

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

3H, JC70D, 2000HP with 336WCB2 Eton Brake 3H, JJ450, 30 ft x 148 ft. 1,000,000 lbs (static) with 10 lines Varco, PTD-500-AC – 500 Ton LPMP, ZP-375, 37 ½” – 500 Ton LPMP, YC450 (Hook/Block Combination) – 450 Tons LPMP, SL450 – 450 Ton 3H, Pyramid slingshot type, casing 700,000 lbs, setback 350,000 lbs VDX, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3512B, 1749 HP ea. w/ KATO 1778KW generators 2 x YJ13A motor, 800 HP ea. 4 x YJ13A motor, 800 HP ea. YJ13A motor – 800 HP, Torque rating 24,000ft-lbs MH, AC motor, 800 HP, Torque rating 30,000ft-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x 3NB-1300 – 1300 HP ea. 2000 bbl. capacity, 2 x 60 bbl trip tanks 3 x Derrick Liner Motion Flo-line Centrifugal 6” x 8” – 1600 GPM Centrifugal 6” x 8” – 850 GPM None ZDRI, ZCQ/4 – 880 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Beijing Pet. Machinery Plant, FKQ-1440-14 stations 3-1/8”, 3H, 5000 psi WP, JLGH 5000 psi, sour service Cameron 21 ¼” annular 2000 psi, Cameron 13 5/8” annular 5000 psi, Cameron U 13 5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi All H2S trimmed

:

40 Fire extinguishers, 1 fire pump, 4 gas detector, 6 H2S Detector, 1 Cascade system, 14 x SCBAs, 2 Portable gas Monitors, 6 eye wash stations, 2 showers, 4 wind socks, 1 breathable air compressor

HWDP Drill collars

: : : : :

5” Grade-G, 19.5 ppf, 10,000 ft. 4”.Grade-G, 14.0 ppf, 18,000 ft. 2 3/8” Grade-E, 6.6 ppf, 5000 ft. 80 of 5”, 100 of 4” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ½”, 30 of 4 ¾”, 30 of 2 7/8”.

H)

Depth Capacity

:

18,000 ft.

I)

DF – GL Elevation Clearance below DF

: :

30.0 ft. 25.0 ft.

C)

D)

E)

F)

G)

Safety Equipment

Drill Pipe & Drill Collars 1. Drill Pipe

2. 3.

75 of 102

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.9.1

SSA-29 (ONSHORE RIG)

A)

Year Built

:

1980 (Sub Structure base cross members reinforced 2003)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE (1500 HP) w/ Elmagco 7838 Dynamic Brake Massarenti / Brenham 33 ft x 144 ft. 1,000,000 lbs (static) with 12 lines Varco-TDS9SA – 400 Ton National C-375 (37 ½”) – 590 Ton (static) Ideco – 525 Ton Ideco – 500 Ton Massarenti self erecting, Load casing 600,000 lbs. M.D. / Totco, 8 pen and Digital Mud Watch System

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, (1200 HP ea.) with Kato 900 KW Generators 2 x GE 752R motor – 1000 HP ea. 4 x GE 752R – 1000 HP ea. Ind. Dr. GE 752 motor – 1000 HP, Torque 1050 Amps / 65,000 ft-lbs 2 x Reliance AC motor – 350 HP ea, Torque 875 Amps / 48,000 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Ideco T1600 (1600 HP ea.) 2500 bbl. capacity with 100 bbl trip tank 2 x Derrick Flo Line Cleaner Derrick 3 x 12” cone – 800 GPM Derrick 16 x 2” cone – 800 GPM None Swaco Horizontal Vacuum – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey ABB 80, w / 3 stations and 24 x 10 gal bottles. 3 1/16” ECC 5000 psi WP, sour service Hydril 21 ¼” Annular / Diverter 2000 psi with 8” hydraulic valve, Hydril GK 13 5/8” Annular 5000 psi, Cameron U 13 5/8” double ram, 10,000 psi, Cameron 13 5/8” single ram 10,000 psi. All H2S trimmed.

F)

Safety Equipment

:

Complete H2S monitoring system, 75 Fire extinguishers, 1 Fire pump, Air Cascade System, 30 x 5-min Breathing apparatus, 10 x 30-min. Breathing Apparatus, 16 x SCBA, Fixed Gas detection System, Portable Gas Detection Equipment, 5 eye wash stations, 1 shower at mud pits 4 wind socks.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

HWDP Drill collars

: : : : :

5” Grade G 105, 26.5 ppf, 6,000 ft. 5” Grade G 105, 19.5 ppf, 10,000 ft 4” Grade XD, 14.0 ppf, 18,000 ft. 91 of 5”, 88 of 4” 10 of 9-1/2”, 21 of 8-1/2”, 30 of 6-1/2”, 3 of 4-3/4”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

29.65 ft 24.70 ft

C)

D)

E)

2. 3.

76 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.9.2

SSA-46 (ONSHORE RIG)

A)

Year Built

:

1980

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

Ideco E-2100 (2000 HP) w/ Elmagco 740 Dynamic Brake Pyramid 32 ft x 142 ft. 1,000,000 lbs (static) with 12 lines Varco-TDS – 400 Ton Ideco LR375 (37 ½”) – 650 Ton (static) National 660G500 – 500 Ton Ideco TL500 – 500 Ton Pyramid swing up, casing 1,000,000 lbs, setback 60,000 lbs. Totco, 8 pen and MD/Totco Digital Mud Watch System

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, (1000 HP ea.) with GE 1162 KVA Generators 2 x GE 752R motor – 800 HP ea. 4 x GE 752R – 800 HP ea Ind. Dr. GE 752 motor – 800 HP, Torque xxx Amps / 17500 ft-lbs 2 x make? AC motor, 350 HP ea, Torque 875 Amps / 32500 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x Ideco T1600 (1600 HP ea.) 2500 bbl. capacity, 100 bbl trip tank 2 x Derrick-Flo Line Cleaner Derrick 2 x 12” cone – 800 GPM Derrick 16 x 2” cone – 800 GPM None Burgess Magna Vac – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, CAD, w/ 14 stations 3 1/16” ECC 5000 psi WP, sour service Shaffer 21 ¼” Annular / Diverter 2000 psi w/ 8” hydraulic valve, Shaffer 13 5/8” Annular 5000 psi, Cameron U 13 5/8” single ram, 5000 psi, Cameron 13 5/8” double ram with shear booster, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

Complete H2S monitoring system, 75 Fire extinguishers, 1 Fire pump, Air Cascade System, 30 x 5-min Breathing apparatus, 10 x 30-min. Breathing Apparatus, 16 x SCBA, Fixed Gas detection System, Portable Gas Detection Equipment, 5 eye wash stations, 1 shower at mud pits 4 wind socks, PLEASE CHECK ALL.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

HWDP Drill collars

: : : : :

5 ½” Grade G, 26.5 ppf, 4,992 ft. 5” Grade G-105, 19.5 ppf, 9,734 ft 4” Grade XD, 14 ppf, 16,692 ft. 76 of 5”, 98 of 4” 11 of 9 ½”, 28 of 8 ½”, 30 of 6 ½”, 30 of 4 ¾”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

28.65 ft 23.70 ft

C)

D)

E)

2. 3.

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.9.3

SSA-91 (ONSHORE RIG)

A)

Year Built

:

1979

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE (1100 HP) with Baylor Dynamic Brake Lee C. Moore 32 ft x 142 ft. 750,000 lbs (static) with 12 lines Varco-TDS-9S National C-375 (37 ½”) – 500 Ton National Dynaplex 500T – 500 Ton National P500 – 500 Ton Lee C. Moore MD / Totco, 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399 – 1150 HP ea. 2 x GE 752R3A motor – 1000 HP ea. 4 x GE 752R3A – 1000 HP ea GE 752R3A motor – 1000 HP, Torque 800 Amps / 17500 ft-lbs. 2 AC motor, 350 HP ea, Torque 875 Amps / 32,500 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 12-P-160 (1600 HP ea.) 2000 bbl. capacity, 100 bbl trip tank 2 x Derrick-Flo Line Cleaner Harrisburg 2 x 12” cone – 800 GPM Harrisburg 16 x 2” cone – 800 GPM None Burgess Vacuum – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, ABB Type 80, TX-336-15SB 4 1/16” Cameron 5000 psi WP, sour service Cameron U 13-5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

85 Portable Fire extinguishers, 1 Fire pump, Air Cascade System, 12 x 5-min. Breathing apparatus, 14 x 30-min. SCBA, Fixed Gas detection System, Portable Gas Detection Equipment, 6 eye wash stations, 1 shower at mud pits 4 wind socks.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

HWDP Drill collars

: : : : :

5” Grade-G, 19.5 ppf, 15,000 ft. 4” Grade-CY 105, 14.0 ppf, 16,000 ft 2 3/8” Grade-E, 6.65 ppf, 3,000 ft. 60 of 5”, 80 of 4” 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ¼”, 30 of 4 ¾”, 15 of 3 3/8”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

29.5 ft xx.x ft

C)

D)

E)

2. 3.

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.9.4

SSA-95 (ONSHORE RIG)

A)

Year Built

:

1980

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 110-UE (2000 HP) w / Elmagco 6032 Dynamic Brake Lee C. Moore 32 ft x 142 ft. 1,000,000 lbs (static) with 10 lines Varco-TDS-9 – 400 Ton National C-375 (37 ½”) – 650 Ton National 660G500 – 500 Ton National P500 – 500 Ton LCM self-erect Canti, casing 1,000,000 lbs, setback 600,000 lbs. MD Totco, 8 pen with unitized Digital Mud Watch system

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D398 (1150 HP ea.) w/ KATO 1050KW Generators 2 x GE 752R motor – 1000 HP ea. 4 x GE 752R – 1000 HP ea GE 752R motor – 1000 HP, 800 Amps / 15,777 ft-lbs. 2 x AC motor, 350 HP ea, 875 Amps / 48,000 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x IDeco T-1600 (1600 HP ea.) 2500 bbl. capacity with 100 bbl trip tank 2 x Dual Derrick-Flo Line Cleaner Derrick 2 x 12” cone – 800 GPM Derrick 16 x 2” cone – 800 GPM None Swaco Horizontal Vacuum – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, ABB Type 80, TX-336-15SB w/ 14 stations 3 1/16” ECC 5000 psi WP, sour service Shaffer SPH 13-5/8” Annular 5000 psi, Cameron U 13-5/8” single ram, 10000 psi, Cameron U 13-5/8” double ram, 10000 psi, with Large Bore Shear Bonnet and tandem booster, All H2S trimmed. Shaffer 21 ¼” Annular 2000 psi Diverter w/ 8” Hydraulic valve,

F)

Safety Equipment

:

85 Portable Fire extinguishers, 1 Fire pump, Air Cascade System, 12 x 5-min. Breathing apparatus, 16 x 30-min. SCBA, Fixed Gas detection System, Portable Gas Detection Equipment, 4 eye wash stations, 1 shower at mud pits 4 wind socks .

G)

Drill Pipe & Drill Collars 1. Drill Pipe HWDP Drill collars

: : : :

5” Grade-G, 19.5 ppf, 10,000 ft, 5.5” Grade-G, 25.6 ppf, 5000 ft. 4” Grade-CY 105, 14.0 ppf, 18,000 ft 100 of 5”, 100 of 4” 12 of 9 ½”, 30 of 8”, 30 of 6 ¼”, 30 of 4 ¾”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

28.75 ft. 24.50 ft.

C)

D)

E)

2. 3.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.9.5

SSA 101 (ONSHORE RIG)

A)

Year Built

:

1979 (Modified mast rising sheaves 2005)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1320-UE (2000 HP) w/Baylor 7838 Dynamic Brake Derrick 32 ft x 142 ft. 1,110,000 lbs (static) with 12 lines Varco-TDS 11S – 000 Ton National C-375 (37 ½”) – 000 Ton National 660G500 – 500 Ton National P500 – 500 Ton Derrick Lo-lift Cantilever, casing xxxxxx lbs, setback xxxxxx lbs. Totco, 8 pen and MD/Totoco Digital Mud Watch System

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D398, with 5 x GE 800KW Generators 2 x GE 752 motor – 800 HP ea. 4 x GE 752 – 800 HP ea Ind. Dr. GE 752 motor – 800 HP, Torque 800 Amps / 17500 ft-lbs 2 x AC motor, 350 HP ea, Torque 875 Amps / 32500 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 12-P-160 (1600 HP ea.) 2500 bbl. capacity, 100 bbl trip tank 2 x Derrick-Flo Line Cleaner Derrick 2 x 12” cone – 800 GPM Derrick 16 x 2” cone – 800 GPM None Swaco Horizontal Vacuum – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, ABB Type 80, TX-336-15SB w/ xx stations 3 1/16” 10000 psi WP, sour service Shaffer 21 ¼” Annular 2000 psi, Cameron U 13-5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi, Shaffer 13-5/8” Annular 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

75 Fire extinguishers, 1 Fire pump, Air Cascade System, Breathing 5 min apparatus-12, Breathing 45 min SCBA -16, Fixed Gas detection System, Portable Gas Detection Equipment, 5 eye wash stations, 1 shower at mud pits 4 wind socks, PLEASE CHECK ALL.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

HWDP Drill collars

: : : : :

5 ½”” Grade G, 26.5 lbs/ft, 6,000 ft. 5” Grade G, 19.5 lbs/ft, 10,000 ft 4” Grade XD, 14 lbs/ft, 18,000 ft. 96 of 5”, 30 of 4” 11 of 9-1/2”, 24 of 8-1/2”, 30 of 6-1/2”, 30 of 4-3/4”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

30.1 ft 23 ft

C)

D)

E)

2. 3.

80 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.9.6

SSA-102 (ONSHORE RIG)

A)

Year Built

:

1979

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1320-UE (2000 HP) w/ Baylor 7838 Dynamic Brake Derrick 32 ft x 142 ft. 1,000,000 lbs (static) with 12 lines Varco-TDS 9SA – 000 Ton National C-375 (37 ½”) – 000 Ton National 660G500 – 500 Ton National P500 – 500 Ton Derrick Lo-lift Cantilever, casing xxxxxx lbs, setback xxxxxx lbs. Totco, 8 pen and MD/Totco Digital Mud Watch System

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D398, 925 HP ea. w/ GE 800KW Generators 2 x GE 752 motor – 800 HP ea. 4 x GE 752 – 800 HP ea GE 752R motor – 1000 HP, Torque 800 Amps / 17500 ft-lbs 2 x AC motor, 350 HP ea, Torque 875 Amps / 32500 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 12-P-160 (1600 HP ea.) 2600 bbl. capacity, 120 bbl trip tank 2 x Derrick-Flo Line Cleaner Derrick 3 x 12” cone – 800 GPM Derrick 16 x 2” cone – 800 GPM None Swaco Horizontal Vacuum – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, ABB Type 80, TX-336-15SB w/ xx stations 3 1/16” 10000 psi WP, sour service Shaffer 21 ¼” Annular 2000 psi, Cameron U 13-5/8” double ram, 5000 psi, Cameron U 13-5/8” single ram, 5000 psi, Shaffer 13-5/8” Annular 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

90 Fire extinguishers, 1 Fire pump, Air Cascade System, Breathing 5 min apparatus-12, Breathing 45 min SCBA -16, Fixed Gas detection System, Portable Gas Detection Equipment, 5 eye wash stations, 1 shower at mud pits 4 wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

HWDP Drill collars

: : : : :

5 ½”” Grade-G, 26.5 ppf, 5,000 ft. 5” Grade-G, 19.5 ppf, 10,000 ft 4” Grade-G, 14.0 ppf, 18,000 ft. 100 of 5”, 100 of 4” 12 of 9 ½”, 30 of 8 ½”, 30 of 6 ½”, 30 of 4 ¾”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

30.6 ft 23.8 ft.

C)

D)

E)

2. 3.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.9.7

SSA-201 (ONSHORE RIG)

A)

Year Built

:

1980

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-structure 9. Geolograph

: : : : : : : : :

National 1320-UE, w/ Baylor 7838 Dynamic Brake Pyramid 144’ x 33’ 1000,000 lbs. Varco-TDS 9S National C-375 (37-1/2”) National – 500 Tons (Hook/Block Combination) National P500 – 500 Tons Type of substructure with load capacity? Totco, 8 pen + SWACO Monitoring system

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 1215 HP ea. w/ xxxx KW Generator 2 x GE 752 motor – 1000 HP ea 4 x GE 752 – 1000 HP ea GE 752 motor – 1000 HP, Torque 000 Amps / xxxxx ft.-lbs 2 x AC Motor, 350 HP ea, Torque 875 Amps / 32500… ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 12-P-160 2000 bbl. capacity, 2 x 60 bbl trip tanks 3 x Derrick-Flo Line Cleaner Derrick 3 x 10” cones – 1000 GPM Derrick 20 x 3” cones – xxx GPM None TRI-FLO 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 24-15 Control System 4 1/16” 10000 psi WP, sour service 2 x Cameron U 13-5/8” double ram, 10000 psi, Hydril GK 13-5/8” x 5000 psi, Hydril MSP 21 ¼” 2000psi, Shaffer 20 ¾” 3000 psi, all H2S trimmed.

F)

Safety Equipment

:

100 Fire extinguishers, 1 Fire pump, Air cascade system, 12 Breathing 5 min apparatus, 19 SCBA 30 min Breathing Apparatus, Fixed gas detection system, Portable gas detection equipment, 5 x eye wash stations, 1 emergency shower, 4 x wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. 3.

HWDP Drill collars

: :

5 ½” Grade G, 24.7 lbs/ft, 12000 ft., 5” Grade G, 19.5 lbs/ft, 15000ft 3 ½” Grade G, 13.3 lbs/ft, 9000 ft. 15 x 6 5/8”, 30 x 5 ½”, 50 x 5”, 50 of 3-1/2” 18 of 9-1/2”, 30 of 8-1/2”, 30 of 6-1/4”, 30 of 4-3/4”

H)

Depth Capacity

:

19,000 feet

I)

DF – GL Elevation Clearance below DF

: :

34.5 ft 29.85 ft

C)

D)

E)

82 of 102

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Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

2.9.8

SSA-202 (ONSHORE RIG)

A)

Year Built

:

1980

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Sub-Structure 9. Geolograph

: : : : : : : : :

National 1320-UE (2000 HP) w/ Elmagco 7040 Dynamic Brake Pyramid 32 ft x 144 ft. 1,000,000 lbs (static) with 12 lines Varco-TDS – 400 Ton National C375 (37 ½”) – 590 Ton (static) National 660G500 – 500 Ton National P500 – 500 Ton Pyramid type?, casing 1,000,000 lbs, setback 60,000 lbs. Totco, 8 pen and MD/Totco Digital Mud Watch System

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D398, (1000 HP ea.) with GE 800 KVA Generators 2 x GE 752 motor – 800 HP ea. 4 x GE 752 – 800 HP ea Ind. Dr. GE 752 motor – 800 HP, Torque xxx Amps / 17500 ft-lbs 2 x make? AC motor, 350 HP ea, Torque 875 Amps / 32500 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 6. Centrifuge 7. Degasser

: : : : : : :

2 x National 12-P-160 (1600 HP ea.) 2500 bbl. capacity, 100 bbl trip tank 2 x Derrick-Flo Line Cleaner Derrick 2 x 12” cone – 800 GPM Derrick 16 x 2” cone – 800 GPM None Swaco Horizontal Vac – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomey ABB, w/ 14 stations 3 1/16” Make? 5000 psi WP, sour service Shaffer 21 ¼” Annular / Diverter 2000 psi w/ 8” hydraulic valve, Shaffer 13 5/8” Annular 5000 psi, Cameron U 13 5/8” single ram, 5000 psi, Cameron 13 5/8” double ram with shear booster, 5000 psi, All H2S trimmed.

F)

Safety Equipment

:

Complete H2S monitoring system, 75 Fire extinguishers, 1 Fire pump, Air Cascade System, 30 x 5-min Breathing apparatus, 10 x 30-min. Breathing Apparatus, 16 x SCBA, Fixed Gas detection System, Portable Gas Detection Equipment, 5 eye wash stations, 1 shower at mud pits 4 wind socks

G)

Drill Pipe & Drill Collars 1. Drill Pipe

HWDP Drill collars

: : : : :

5 ½” Grade G, 26.5 ppf, 5,210 ft. 5” Grade G-105, 19.5 ppf, 9,453 ft 4” Grade XD, 14 ppf, 18,000 ft. 62 of 5”, 98 of 4” 12 of 9 ½”, 30 of 8”, 30 of 6 ½”, 30 of 4 ¾”

H)

Depth Capacity

:

18,000 ft

I)

DF – GL Elevation Clearance below DF

: :

29.6 ft 24.5 ft

C)

D)

E)

2. 3.

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GENERAL INFORMATION RIG SPECIFICATIONS

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3.0

RIG SPECIFICATIONS DATA SHEETS (OFFSHORE RIGS) 3.1

ARABIAN DRILLING COMPANY 3.1.1 ADC-17

3.2

ENSCO ARABIA LIMITED 3.2.1 ENS-76 3.2.1 ENS-95 3.2.1 ENS-96 3.2.1 ENS-97

3.3

POOL ARABIA LIMITED 3.3.1 PA-145 3.3.1 PA-656 3.3.1 OS-655

3.4

PRIDE ARABIA COMPANY 3.4.1 PM-1 3.4.1 PND-1

3.5

ROWEN ARABIA DRILLING CO. 3.5.1 RM-22 3.5.1 CR-36 3.5.1 AR-37 3.5.1 RC-42

3.6

SAUDI ARABIAN SAIPEM LIMITED 3.6.1 PN-2 3.6.1 PN-5

3.7

SAUDI ARAMCO DRILLING CO. 3.7.1 SAR-201

84 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.1.1

ADC-17 (OFFSHORE RIG)

A)

Year Built

:

1991

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National 1320 UE (2000 HP) with xxxxxxx auxiliary brake DSI xx ft x 160 ft. 1,000,000 lbs static with 12 lines Varco TDS 3 National C 375, 37 ½” Make and model? – 550 Ton Make and model? – 650 Ton Totco, 7-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud Pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, 1215 HP ea. 2 x GE 752 motor – xxxxx HP ea. 2 x GE 752 motor – xxxxx HP ea 1 x GE 752 motor– Torque xxxxx HP ea, xxxxx Amps/ xxxxx ft-lbs. Power, make/model, HP – Torque xxxx HP, xxx Amps/xxxx ft-lbs

: : :

2 x National 12P-160 – 1600 HP ea. 1300 bbls capacity, 25 bbl trip tank 1 x Brandt dual tandem, 2 x Derrick Flo-Line Cleaners Derrick Hi-G Dryer, no. of cones and capacity xxxx GPM None Derrick Vacu Flo, xxx GPM?

C)

D)

E)

Mud System & Pump 1. Mud Pumps 2. Mud Pits & Storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: :

BOP Equipment 1. Accumulator 2. Choke Manifold 3. BOPs

: : :

3000 psi, Ross Hill C-180 4-1/16” Make? 10,000 psi WP, sour service Hydril MSP 21-1/4” annular, 2000 psi Hydril GL 13-5/8” annular, 5000 psi, Cameron U 13-5/8” double ram, 5000 psi, Cameron U 135/8” single ram, 5000 psi

F)

Safety Equipment

:

2 x 61-man Lifeboats, 6 x 25-man Liferafts, xxx Life Jackets, 18 Survival suits, 10 Working vests, xx 30-min. Scott air packs, xx x 15-min. Scott air packs, Fire/Smoke monitoring system, 000 fire extinguisher, 80 Fire extinguishers, 1 fire pump, 3 gas detector, 10 H2S detector, 1 cascade system, 97 Scott SCBAs, 4 portable gas monitors, 7 eye wash stations, 1 shower at mud pits, 3 wind socks, 1 foam units, 2 breathable air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

:

2. HWDP 3. Drill Collars (Spiral)

: :

5 ½” Grade-G, 24.7 lbs/ft, 5000 ft; 5” Grade-G, 19.5 lbs/ft, 12000 ft, 3 ½” Grade-G, 13.3 lbs/ft, 16,000 ft. 30 of 5 ½”, 60 or 5”, 60 of 3 ½” 12 of 9 ½”, 24 of 8 ½”, 18 of 6 ½”, 24 of 4 ¾”

H)

3.2.1

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever

: : : : :

4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

20,000’ 250 ft 40’ Max. forward / backward movement 10’ Transverse on each side from centerline of hole Upper – 29’ (Derrick Floor to Base of Cantilever) Lower – 49’ (Derrick Floor to Base of the Hull) xxxx Kips xx people

ENSCO-76 (OFFSHORE RIG) 85 of 102

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

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SECTION

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

A)

Year Built

:

1999 (Upgrade/Refurbishment completed in 2005)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National 1625 UDBE (3000 HP) with Baylor 7838 auxiliary brake Dreco Beam Leg 40’ x 32’ x 170 ft. 1,500,000 lbs static with 14 lines Varco TDS-8AS – 750 Ton National D-495, 49 ½” – 800 Ton National Oilwell B760GA650 – 650 Ton Integrated with Top Dive National Oilwell SDI Hi-Tech, 28-parameter recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3606 – 2514 HP ea. 3 x GE 752 – 1085 HP ea. 2 x GE 752 – 1085 HP ea GE 752 – 1085 HP, Torque 1050 Amps/ 52,654 ft.-lbs. Low Gear Varco Motor – 1200 HP, Torque 1200 Amps/ 62,500 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

3 x National 14-P-220, 2200 HP ea. 4563 bbls capacity (active & reserve), 297 bbl trip tanks 5 x Brandt, LCM 3D-CM2 – 500 GPM ea. Brandt, LCM 3D-MC – 2,000 GPM / LCM 2D-CMC – 1000 GPM 2 x Brandt HS-2172 – 600 GPM ea. 2 x Brandt DG-10, 1000 GPM ea.

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Massco SSB240-3S11, capacity 402 Gal. 3 1/16” Cameron 15,000 psi WP, sour service Hydrill GL 18 3/4” annular 5000 psi, Cameron Type-U 18 ¾ annular 10,000 psi, Cameron 18 ¾ Double Ram 10000 psi, Cameron DL 13-5/8” annular 10000 psi, 2 x Cameron Type-U 13-5/8” single ram 15000 psi, Cameron U 13-5/8” double ram, 15000 psi.

F)

Safety Equipment

:

3 x 50-man Lifeboats, 8 x 25-man Life Rafts, 1 Fast Rescue Craft, Heli-Deck Foam System, 80 Fire extinguishers, 2 x 700 GPM Fire pumps, 14 cascade system, 5 Scott Air Pack SCBAs general use. 23-30 min, 166-15 min packs for H2S service, 5 portable gas / H2S monitors, 4 eye wash stations w/ showers, 1 Drager H2S sniffer, 10 Fresh Air bug blowers, H2S & Combustible gas monitoring system. 34 fire hydrants, Fire / Smoke detectors through out rig

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5 7/8” Grade S-135, 29.5 lbs/ft, 24,000 ft. 5 7/8” Grade S-135, 57.42 lbs/ft, 2,500 ft. 24 of 10”, 24 of 8”, 24 of 6 ½, 24 of 4 ¾”

Sub-Structure

: : : : :

5. Variable Deck Load Accommodation

: :

30,000 ft 300 ft 86.6’ Max. forward / backward movement with load 750,000 lbs. 15’ Transverse on each side from center line of hole Upper – 46’ (Derrick Floor to Base of Cantilever) Lower – 72’ (Derrick Floor to Base of the Hull) – 58’ (Base of Hull to Top of Jack Housing) xxx Kips xxx people

C)

D)

E)

H)

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

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RIG SPECIFICATIONS

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3.2.2

ENSCO-95 (OFFSHORE RIG)

A)

Year Built

:

1982 (New Accommodation, Refurbished Drawworks and Mud Pits)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National Oilwell 1320 UE (2000 HP) with Baylor Auxiliary Brake Superior 30’ x 30’ x 160 ft. 1,000,000 lbs (static) with 12 lines. Varco TDS-4 – 650 Ton National C375, 37 ½” – 400 Ton National P650 – 550 Ton None (Becket Hook – 650 Ton) M.D./Totco – Rig Sense

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x EMD V-12-645 E8 – 1650 HP ea. w/ MD 1180 KW generators 2 x EMD D79, 1000 HP ea. 4 x EMD D79, 1000 HP ea. GE 752, 1085 HP, Torque 800 Amps / 43,200.ft.-lbs GE 751shunt motor, 1000 HP, Torque 1000 Amps / 29,200.ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 6. Centrifuge 7. Degasser

: : : : : :

2 x National Oilwell 12-P-160 – 1600 HP ea. 1602 bbl. capacity (active and reserve) with 2 x 40 bbl. trip tanks 3 x Derrick Flo-Line PMD-500 Derrick Hi-G, 2 x 10” cone / 20 x 4” cone – 1000 GPM None Derrick Vacu.-Flo 1000 – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey 80, 8 stations w/ 28 x 11 gal. bottles 10,000 psi WP, T-3 Energy Systems FC-3, sour service. Shaffer Spherical 21 ¼” annular 3000 psi, Shaffer Spherical 13 5/8” annular 5000 psi, Cameron U 13 5/8” single ram, 10000 psi, Cameron U 13 5/8” double ram, 10000 psi. All H2S trimmed.

F)

Safety Equipment

:

H2S and Combustible Gas Monitoring System, Fire/Smoke detection system, 2 x 58-man Lifeboats, 8 x 25-man Life Rafts, 1 Fast Rescue Craft, Sprinkler system, Heli-Deck Foam System, 75 Portable Fire extinguishers, 2 Fire pumps, 10 H2S detectors, 7 cascade system, 189 Scott Air Pack SCBAs, 6 eye wash stations, 6 emergency showers, 1 Drager H2S sniffer.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G, 19.5 ppf, 14,000 ft, 3 ½” Grade-G, 13.3 ppf, 14,000 ft. 60 of 5”, 100 of 3 ½” 12 of 9 ½”, 24 of 8 ½”, 24 of 6 ½” and 24 of 4 ¾”

: : : : :

25,000 ft 250 ft 40’ Max. forward / backward movement w/ 650,000 lbs setback load. 12’ Transverse on each side from center line of hole Upper – 28.5’ (Derrick Floor to Base of Cantilever) Lower – 51.3’ (Derrick Floor to Base of the Hull) – 46’ (Base of Hull to Top of Jack Housing)

C)

D)

E)

H)

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

5,020 Kips 103 people

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.2.3

ENSCO 96 (OFFSHORE RIG)

A)

Year Built

:

1982 (Refurbished in 2002)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National Oilwell 1320-UE (2000 HP) w/ Baylor 740W Auxiliary Brake Load Master 40’ x 32’ x 170 ft. 1,000,000 lbs static with 12 lines Varco TDS 4H – 500 Ton National C375, 37 ½”, – 650 Ton National Oilwell 660-H-500 – 500 Ton C. Emsco LB-650 – 650 Ton M.D./Totco - RF8, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x EMD V-12 645E8 – 1650 HP ea. w/ 1050 KW generators 2 x EMD D79, 1000 HP ea. 4 x EMD D79, 1000 HP ea. EMD D79, 1000 HP, Torque 800 Amps / 43,200 ft.-lbs GE 752, 1085 HP, Torque 1325 Amps / 58200 ft.-lbs in Low Gear

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 6. Centrifuge 7. Degasser

: : : : : :

2 x National Oilwell 12-P-160 – 1600 HP ea. 1753 bbls capacity (active and reserve) with 2 x 50 bbl trip tanks 3 x Derrick Hi-G Flo-Line 2000 Derrick Hi-G, 2 x 10” cone / 20 x 4” cone – 1000 GPM (2 KMC Rental) Derrick Vacu-Flo 1000 – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Shaffer 80, 8 stations w/ 32 x 11 gal. bottles 10,000 psi WP, T-3Energy Systems FC-3 1/16 x 10 K sour service Shaffer 13 5/8” annular 5000 psi, Cameron Type-U 13-5/8” single Ram, 10000 psi, Cameron Type-U 13-5/8” double rams, 10000 psi. All H2S trimmed

F)

Safety Equipment

:

H2S and Combustible Gas Monitoring System, Fire/Smoke detection system, 2 x 58-man Lifeboats, 9 x 25-man Life Rafts, Fast Rescue Craft, Sprinkler system, Heli-Deck Foam System, 79 Portable Fire extinguishers, 2 Fire pump, 6- H2S / 6 LEL detectors, 7 cascade system, 193 Scott Air Pack SCBAs, 2 portable H2S monitors, 6 eye wash stations, shower at mud pit, MSA H2S sniffer.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G, 19.5 ppf, 15,000 ft, 3 ½” Grade-G, 13.3 ppf, 15,000 ft. 52 of 5”, 100 of 3 ½” 12 of 9 ½”, 12 of 8 ½”, 25 of 6 ¾” and 14 of 4 ¾”

: : : : :

25,000 ft 246 ft 40’ Max. forward / backward movement w/ 650,000 lbs setback load 12’ Transverse on each side from center line of hole Upper – 30.30’ (Derrick Floor to Base of Cantilever) Lower – 51.33’ (Derrick Floor to Bottom of the Hull) – 25.0’ (Base of Hull to Top of Jack Housing) 5,060 Kips 100 people.

C)

D)

E)

H)

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Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.2.4

ENSCO 97 (OFFSHORE RIG)

A)

Year Built

:

1980 (Refurbishment, New Derrick and New Living Qtrs. in 2005)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

C. Emsco C-2 (2000 HP) with 7838 auxiliary brake Load Master 30’ x 30’ x 160 ft. 1,000,000 lbs. static with 12 lines Varco TDS 4H – 500 Ton National D375, 37 ½” – 650 Ton National Oilwell 750 FA – 650 Ton National Oilwell P650 – 650 Ton M.D. / Totco, RF8

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x EMD 1650 HP ea. 2 x EMD M79, 750 HP ea. 4 x EMD M79, 750 HP ea. 1 x EMD M79, 750 HP, Torque 800 Amps / 43,200 ft.-lbs 1 x GE 752, 1100 HP, Torque 1000 Amps / 29,200 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x Emsco FB-1600, 1600 HP ea. 1900 bbls capacity (active and reserve) with 86 bbl trip tanks 2 x National DTS-L1 and 3 x Derrick Flo-500/513 Derrick DSI 3 x 10” cone / DRND-CM 20 x 4” cones – 1000 GPM ea. Mission 6 x 8 x14 (Aramco Rental) Derrick Vacu-Flo – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Shaffer T20160-35ac-62 with 758 gal. capacity 5000 psi WP, T3 Energy Service FC/PSE3G, sour service Shaffer 21 ½” annular 2,000 psi, Shaffer 13 5/8” annular 5,000 psi, Cameron Type-U 13-5/8” single ram, 10,000 psi Cameron Type-U 13-5/8” double ram, 10,000 psi.

F)

Safety Equipment

:

2 x 50-man Lifeboats, 4 x 25-man Life Rafts, 1 Fast Rescue Craft, Sprinkler system, Heli-Deck Foam System, 59 Fire extinguishers, 3 Fire pump, 10 H2S detectors, 7 cascade system, 192 Sabrre Air Pack SCBAs, 2 portable H2S monitors, 6 eye wash stations, 6 shower at mud pits, 2 Rikei H2S sniffer.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade G, 19.5 ppf, 22,000 ft., 3 ½” Grade G, 13.3 ppf, 12,000 ft. 50 of 5”, 100 of 3 ½” 6 of 9 ½”, 23 of 8”, 24 of 6 ½”, 24 of 4 ¾”

: : : : :

20,000 ft 250 ft 40’ Max. forward / backward movement 10’ Transverse on each side from center line of hole Upper – 27’ (Derrick Floor to Base of Cantilever) Lower – 48’ (Derrick Floor to Bottom of the Hull) – 46’ (Base of Hull to Top of Jack Housing) 4,390 Kips 100 people.

C)

D)

E)

H)

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.3.1

PA-145 (OFFSHORE RIG)

A)

Year Built

:

1982

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

IDECO E1200 (2000 HP) w/ Dretech 250 (8042) Auxiliary Brake Pool Company, Square top, 13’ x 17’ x 139 ft.’ 700,000 lbs None (5 ¼” Hexagonal 42 ft Kelly) Ideco 162 LR375E, 37 ½” Ideco – 350 Ton C. Emsco LB-400 – 400 Ton Totco 6-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud Pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399 – 1215 HP ea. w/ 1030 KW generators 2 x GE752 motor – 1000 HP ea. 2 x GE752 motor – 1000 HP ea GE752 motor – 1000 HP, Torque 800 Amps / 11,800 ft-lbs. None

Mud System & Pump 1. Mud Pumps 2. Mud Pits & Storage 3. Shale Shakers 4. Desander/Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x Gardner Denver PZ-9 – 1000 HP ea. 1500 bbl. capacity with 68 bbl slig pit and 45 bbl trip tank 2 x Derrick 2E48-90F-3TA – 1600 GPM Derrick DSI-10-2, 3 x 12” cone / RND-CM4, 12 x 4” cone – 1000 GPM None SWACO vacuum type w/ 5 HP motor – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, CAD with 240 gal. capacity 3 1/8 “ Cameron 5000 psi WP w/ 2 x 2 9/16” adjustable super chokes Shaffer 11” annular – 5000 psi, Shaffer LWS, 11” single ram, 5000 psi, Shaffer LWS, 11” single ram, 5000 psi.

F)

Safety Equipment

:

H2S & Combustible Gas Monitoring System, Fire / Smoke detection system, Portable H2S & combustible gas monitors, 2 x 900 GPM fire pumps, 73 Fire Extinguishers, CO2 monitoring system, Sprinkler System in accommodations, 4 x Portable Foam system at HeliDeck, Cascade Breathing System, 2 x 58-man Lifeboats, 2 x 25man life rafts , 2 x 20-man life rafts, 1 x Fast Rescue Craft.

G)

Drill Pipe & Drill Collars 1. Drill Pipe

: : : :

5” Grade-E, 19.5 ppf, 10,000 ft, 3 ½” Grade-E, 13.3 ppf 10,000 ft. 3 ½” Grade-G, 13.3 ppf, 5,000 ft.’ 60 of 3 ½” 12 of 9 ½”, 30 of 8 ¼”, 30 of 6 ¼”, 30 of 4 ¾”

: : : : :

15,000 ft. 150 ft. 40’ Max. forward / backward movement 8’ Transverse on each side from centerline of hole Upper – 26.6’ (Derrick Floor to Base of Cantilever) Lower – 43.0’ (Derrick Floor to Base of the Hull) xxxx Kips xxx people

C)

D)

E)

2. 3. H)

90 of 102

HWDP Drill Collars

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.3.2

PA-656 (OFFSHORE RIG)

A)

Year Built

:

1975 (Upgrade/Refurbishment completed in 2005)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

Oilwell E 2000, xxxxx HP with xxxxxx auxiliary brake Pyramid x’W x x’L x 156’H 1,000,000 lbs static with xx lines Can Rig 1050E – xxx Ton Oilwell B37 ½” – xxx Ton Oilwell Model? – 500 Ton Integrated with Top Dive National Oilwell SDI Hi-Tech, 28-parameter recorder

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar 3606 – 2514 HP ea. 3 x GE 752 – 1085 HP ea. 2 x GE 752 – 1085 HP ea GE 752 – 1085 HP, Torque, ----- Amps/ 52,654 ft.-lbs Low Gear Varco Motor?, 1200 HP, Torque , ----- Amps/ 62,500 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander 5. Desilter 5. Centrifuge 6. Degasser

: : : : : : :

3 x National 14-P-220, 2200 HP ea. 4563 bbls capacity (active & reserve), 297 bbl trip tanks 5 x Brandt, LCM 3D-CM2 – 500 GPM ea. Brandt, LCM 3D-MC – 2,000 GPM Brandt, LCM 2D-CMC – 1000 GPM 2 x Brandt HS-2172, ----- GPM ea. 2 x Brandt DG-10, 1000 GPM ea.

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Massco SSB240-3S11 capacity 402 Gal. 15,000 psi WP, 3 1/16” Cameron, sour service Hydrill GL 18 3/4” 5K annular, 1-Cameron Type-U 18 ¾ 10K, Cameron 18 ¾ 10K Double, 13-5/8” Cameron DL 10K annular, 2 x Cameron Type-U 13-5/8” single ram, 15000 psi, Cameron Type-U 13-5/8” double ram, 15000 psi.

F)

Safety Equipment

:

3 x 50-man Lifeboats, 8 x 25-man Life Rafts, 1 Fast Rescue Craft, Heli-Deck Foam System, 80 Fire extinguishers, 2 x 700 GPM Fire pumps, 4 H2S detectors, 14 cascade system, 5 Scott Air Pack SCBAs general use. 23-30 min, 166-15 min packs for H2S service, 5 portable gas/ H2S monitors, 4 eye wash stations w/ showers, 1 Drager H2S sniffer, H2S & Combustible gas monitoring system

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G, 19.5 lbs/ft, 14000 ft, 3 ½” Grade-G 13.3 lbs/ft, 14000 ft. 60 of 5”, 100 of 3 ½” 12 of 9 ½”, 24 of 8 ½”, 24 of 6 ¼” 24 of 4 ¾”

: : : : :

20,000 ft xxx ft xxx’ Max. forward / backward movement with load 750,000 lbs. xx’ Transverse on each side from center line of hole Upper – xx’ (Derrick Floor to Base of Cantilever) Lower – xx’ (Derrick Floor to Base of the Hull) xxx Kips xxx people

C)

D)

E)

H)

3.3.3

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

OS-655 (OFFSHORE RIG) 91 of 102

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___________________________________________________________________________________________________________________________

A)

Year Built

:

1979

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

OIME 1200 HP, w/ Baylor Elmagco 6032 eddy current brake. Pyramid 147’ 750,000 lbs None National C-375 (37 ½”) Ideco TB-360-5-42 – 360 Ton National P-400 – 400 Ton M.D./Totco, 6-pen w/ Epoch Rig-Watch RW964 monitoring system

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x Caterpillar 3516B 1855 HP ea. w/ 1505 KW generators 2 x GE-752, 1000 HP ea. 4 x GE-752, 1000 HP ea. GE-752, 1000 HP None

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander./ Desilter 6. Centrifuge 7. Degasser

: : : : : :

2 x Gardner Denver PZ-10 – 1500 HP ea. 1500 bbls 2 x Derrick FLC-2000, 4 panel shale shakers. Derrick D-RND-CM-4-20 – 1000 GPM / DSI-10 – 1000 GPM None Swaco vacuum type – 750 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 Psi, M-series SB280-11SB3K w/ 28 x 11 gal. bottles 5000 psi WP, sour service Shaffer 11” annular 5000 psi Shaffer 11” single ram, 5000 psi Shaffer 11” double ram, 5000 psi.

F)

Safety Equipment

:

2 x 50 man Lifeboats, 4 x 25 Life Rafts, 1 Fast Rescue Craft, Sprinkler system-Accommodation, Heli-Deck Foam System, 51 Fire extinguishers, 1 Fire pump, 4 H2S detectors, cascade system, Scott Air Pack SCBAs, 2 portable gas/ H2S monitors, 3 eye wash stations, 1 shower at mud pits, 1 Drager H2S sniffer,

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade G, 19.5 ppf, 12,000’, 3 ½” Grade G, 13.3 ppf, 9,000 ft. 50 of 5”, 100 of 3 ½” 12 of 8 ½”, 24 of 6 ½”, 24 of 4 ¾”, 24 of 3 3/8”.

: : : : :

18,000 ft. 150 ft 40’ Max. forward / backward movement 10’ Transverse on each side from center line of hole Upper – 25.7’ (Derrick Floor to Base of Cantilever) Lower – 48.7’ (Derrick Floor to Base of the Hull) 3,741 Kips 112 person

C)

D)

E)

H)

92 of 102

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.4.1

PM-1 (OFFSHORE RIG)

A)

Year Built

:

1982 (New Accommodation, Refurbished Drawworks and Mud Pits)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National Oilwell 1320 UE (2000 HP) with Baylor Auxiliary Brake Superior 30’ x 30’ x 160 ft. 1,000,000 lbs (static) with 12 lines. Varco TDS-4 – 650 Ton National C375, 37 ½” – 400 Ton National P650 – 550 Ton None (Becket Hook – 650 Ton) M.D./Totco – Rig Sense

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

3 x EMD V-12-645 E8 – 1650 HP ea. w/ MD 1180 KW generators 2 x EMD D79, 1000 HP ea. 4 x EMD D79, 1000 HP ea. GE 752, 1085 HP, Torque 800 Amps / 43,200.ft.-lbs GE 751shunt motor, 1000 HP, Torque 1000 Amps / 29,200.ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 6. Centrifuge 7. Degasser

: : : : : :

2 x National Oilwell 12-P-160 – 1600 HP ea. 1602 bbl. capacity (active and reserve) with 2 x 40 bbl. trip tanks 3 x Derrick Flo-Line PMD-500 Derrick Hi-G, 2 x 10” cone / 20 x 4” cone – 1000 GPM None Derrick Vacu.-Flo 1000 – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, Koomey 80, 8 stations w/ 28 x 11 gal. bottles 10,000 psi WP, T-3 Energy Systems FC-3, sour service. Shaffer Spherical 21 ¼” annular 3000 psi, Shaffer Spherical 13 5/8” annular 5000 psi, Cameron U 13 5/8” single ram, 10000 psi, Cameron U 13 5/8” double ram, 10000 psi. All H2S trimmed.

F)

Safety Equipment

:

H2S and Combustible Gas Monitoring System, Fire/Smoke detection system, 2 x 58-man Lifeboats, 8 x 25-man Life Rafts, 1 Fast Rescue Craft, Sprinkler system, Heli-Deck Foam System, 75 Portable Fire extinguishers, 2 Fire pumps, 10 H2S detectors, 7 cascade system, 189 Scott Air Pack SCBAs, 6 eye wash stations, 6 emergency showers, 1 Drager H2S sniffer.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G, 19.5 ppf, 14,000 ft, 3 ½” Grade-G, 13.3 ppf, 14,000 ft. 60 of 5”, 100 of 3 ½” 12 of 9 ½”, 24 of 8 ½”, 24 of 6 ½” and 24 of 4 ¾”

: : : : :

25,000 ft 250 ft 40’ Max. forward / backward movement w/ 650,000 lbs setback load. 12’ Transverse on each side from center line of hole Upper – 28.5’ (Derrick Floor to Base of Cantilever) Lower – 51.3’ (Derrick Floor to Base of the Hull) – 46’ (Base of Hull to Top of Jack Housing) 5,020 Kips 103 people

C)

D)

E)

H)

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

93 of 102

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.4.2

PND-1 (OFFSHORE RIG)

A)

Year Built

:

1981

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

C. Emsco C-3 (3000 HP) with Elmagco 7838 Auxiliary Brake C. Emsco 20-RD, 160 ft. 1,300,000 lbs (static) with 12 lines. Maritime Hydraulics DDM 650C – 650 Ton C. Emsco Model T3750, 37 ½” C. Emsco RA-60-7 – 650 Ton None Petron IDS 2000, 10-channel computer data recorder

Rig Power 1. Engine Power

:

2. 3. 4. 5.

: : : :

4 x EMD 645 12E-8, 1520 HP ea. w/ 1120 KW generator ea. Emergency Cat 3508 with generator 3 x GE 752 Motor – 1000 HP ea. 2 x GE 752 Motor – 1000 HP ea. GE 752 Motor – 850 HP ea. Torque 1200 Amps / 38,455 ft-lbs. GE 752 HT Motor – 1130 HP; Torque 1060 Amps / 50,000 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x C. Emsco FB-1600 – 1600 HP ea. 1870 bbl. active system with 2 x 50 bbl. Trip Tank 2 x Derrick FLC 2000 super G, Brandt CDX-18-8340 Cleaner Demco 2x 12” cone – 1000 GPM / Brandt 16 x 4” cone – 960 GPM Brandt 1850 – 250 GPM Swaco Horizontal 6” x 8” vacuum type – 800 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Ross Hill C 180-2E25-2AG w/ 11 x 24 gal. bottles 3-1/16” Cameron 10000 psi WP sour service Shaffer 13-5/8” annular 5,000 psi, Cameron 13-5/8” single ram, 10,000 psi, Cameron U 13-5/8” double ram, 10,000 psi.

F)

Safety Equipment

:

5 x H2S portable Gas detectors & 4 x Multi Gas detectors, Portable gas monitors, Fire/Smoke Detection system, 102 x Fire Extinguishers, 2 x fire pumps – 300GPM, 140 SCBA’s, 3 x breathable Air Compressors, 4 x eye-wash stations, 2 x showers, 4 windsocks, CO2 system in Engine/SCR/E-Gen/Paint Locker rooms, Foam system at Heli-Deck, Cascade Breathing System, 2 x 50-man Lifeboats, 4 x 20-man Life rafts, Fast Rescue Craft.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

4” Grade CY, 14.5 ppf, 14,000 ft; 2-3/8” Grade E; 6.65 ppf, 9,000 ft. 101 of 4” 12 of 6-1/2”, 12 of 4-3/4”, 12 of 3-3/8”

: : : : :

30,000 ft 250 ft 40’ Max. forward / backward movement 10’ Transverse on each side from center line of hole Upper – 26.0 ft (Derrick Floor to Base of Cantilever) Lower – 51.0 ft (Derrick Floor to Base of the Hull) Lower – 47.0 ft (Base of the Hull to top of jack housing) 3,500 Kips

C)

D)

E)

H)

94 of 102

Drawworks Mud pumps Rotary Top Drive

Design Criteria 1. Drilling Depth Cap. 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5.

Variable Deck Load :

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

6.

3.5.1

Accommodation

:

85 people

RM-22 (OFFSHORE RIG)

A)

Year Built

:

1985

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National 1320 UE (1500 HP) with xxxxx Auxiliary Brake Pyramid 149 ft. 1,100,000 lbs (static) with 12 lines. VARCO TDS 3 B20 – xxx Ton National C375, 37 ½” – xxx Ton National 660 - G500 – 500 Ton National P-500 – xxx Ton M.D./Totco Spectrum 1000, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D399 – xxxx HP ea. with1250 KVA ea. 2 x GE 752 Motor – 1000 HP ea. 2 x GE 752 Motor – 1000 HP ea. GE 752 Motor – 1000 HP, Torque 1060 Amps / 5300.ft.-lbs GE 752 Motor – 1000 HP, Torque 1060 Amps / 5300.ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x National 12 P 160, 1600 HP ea. 1762 bbls – xx bbls Trip Tank 3 x Derrick FLC 2000 Brandt 12” x 2 cones / 4” x 12 cones – 1000 GPM None Swaco Vaccum type, model and capacity in GPM ?

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomy with xxx stations 3 1/8 “ Cameron 10000 psi WP sour servic Make And size? annular 5000 psi, Make And size? single ram, xxxxxx psi, Make And size? double ram, xxxxx psi.

F)

Safety Equipment

:

H2S & Combustible Gas Monitoring System, Fire / Smoke detection system, Portable H2S & combustible gas monitors, 2 x 0000GPM fire pumps, CO2 monitoring system in Engine Room/SCR/EGen/Paint Locker, Sprinkler System in accommodations, Foam system at Heli-Deck, Cascade Breathing System, 2 x 50man Lifeboats, 4 x 20man Life rafts, 1 x Fast Rescue Craft

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G 19.5 lbs/ft, 12,000 ft. 50 of 5”, 100 of 3 ½” 12 of 6 ½”, 21 of 4-3/4”, 12 of 3-3/8”

: : : : :

20,000 ft 160 ft 40’ Max. forward / backward movement 10’ Transverse on each side from center line of hole Upper – 25.7’ (Derrick Floor to Base of Cantilever) Lower – 48.7’ (Derrick Floor to Base of the Hull) – 49.0’ (Base of Hull to Top of Jack Housing) xxx Kips xx people

C)

D)

E)

H)

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

95 of 102

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GENERAL INFORMATION

F

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June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.5.2

CR-36 (OFFSHORE RIG)

A)

Year Built

:

1979

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National 1320 UE (xxxx HP) w/ xxxx Auxiliary Brake Dreco Derrick 1000000 lbs 1,100,000 lbs (static) with 12 lines. VARCO TDS 3 B20 – xxx Ton National C375, 37 ½” – xxx Ton National 660 - G500 – 500 Ton National P-500 – xxx Ton M.D./Totco Spectrum 1000, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D399 – xxxx HP ea. with1250 KVA ea. 2 x GE 752 Motor – 1000 HP ea. 2 x GE 752 Motor – 1000 HP ea. GE 752 Motor – 1000 HP, Torque 1060 Amps / 5300.ft.-lbs GE 752 Motor – 1000 HP, Torque 1060 Amps / 5300.ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x National 12 P 160, 1600 HP ea. 1762 bbls – xx bbls Trip Tank 3 x Derrick FLC 2000 Brandt 12” x 2 cones / 4” x 12 cones – 1000 GPM None Swaco Vaccum type, model and capacity in GPM ?

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, Koomy with xxx stations 3 1/8 “ Cameron 10000 psi WP sour servic Make And size? annular – 5000 psi, Make And size? single ram, xxxxxx psi, Make And size? double ram, xxxxx psi.

F)

Safety Equipment

:

H2S & Combustible Gas Monitoring System, Fire / Smoke detection system, Portable H2S & combustible gas monitors, 2 x 0000GPM fire pumps, CO2 monitoring system in Engine Room/SCR/EGen/Paint Locker, Sprinkler System in accommodations, Foam system at Heli-Deck, Cascade Breathing System, 2 x 50man Lifeboats, 4 x 20man Life rafts, 1 x Fast Rescue Craft

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G 19.5 lbs/ft, 12,000 ft. 50 of 5”, 100 of 3 ½” 12 of 6 ½”, 21 of 4-3/4”, 12 of 3-3/8”

: : : : :

20,000 ft 160 ft 40’ Max. forward / backward movement 10’ Transverse on each side from center line of hole Upper – 25.7’ (Derrick Floor to Base of Cantilever) Lower – 48.7’ (Derrick Floor to Base of the Hull) – 49.0’ (Base of Hull to Top of Jack Housing) xxx Kips xxx people

C)

D)

E)

H)

96 of 102

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 1 SECTION

F

DRILLING MANUAL June 2006

GENERAL INFORMATION RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

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GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.5.3

AR-37 (OFFSHORE RIG)

A)

Year Built

:

1981 (Major Upgrades 2006)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National 1625 DE (2,000 HP) with Elmagco 7820 auxiliary brake Lee C. Moore, (T Leg type) 30 ft x 160 ft 1,000,000 lbs National PS-2 650 – 650 Ton National C-375 (37 ½”) – 650 Ton National – 500 Ton National, 650 Ton None

Rig Power 1. Engine Power 2. Drawworks 3. Mud Pumps 4. Rotary 5. Top Drive

: : : : :

6 x Caterpillar.D399 – 1320 HP ea. + One D379 Emergency 2 x GE motor – 1000 HP ea. 6 x GE motor – 1000 HP ea Drawwork Driven – 1000 HP, Torque 1060 Amps / 53,000 ft-lbs. GE 752 motor – 1130 HP, Torque 1200 Amps / 55,511 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud Pits & Storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

3 x National 12-P-160, 1600 HP ea. 1759 bbl. Capacity, 54 bbl. Trip Tank 4 x Brandt Cobra-S Brandt Cobra-S 2 x 12“ cone / 16 x 4“ cone – 1000 GPM ea. None Swaco 255 type 30 – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi WP, CAD 523 with 15 stations 3 1/16” Energy Equipment Corp, 10,000 psi, H2S trimmed Shaffer 30” Annular, 1000 psi, Cameron D 13 5/8” Annular 5000 psi, Cameron 21 ¼ Annular, 2000 psi, Cameron U 13 5/8 Double Ram 10000 psi, Cameron U 13 5/8 Single Ram 10000 psi. All H2S trimmed

F)

Safety Equipment

:

2 x 54-man Lifeboats, 4 x 25-man Liferafts, 4 x 20-man Self Inflatable Life rafts, 130 Life Jackets, 10 Working vests, 10 x 30-min. Scott air packs, xx x 15-min. Scott air packs, Fire/Smoke monitoring system, 95 fire extinguisher, 2 fire pump, 8 x combustible / H2S gas detectors, Cascade system, 180 SCBA, 4 portable gas monitor, 4 eye station, 2 shower, 3 breathing air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G 19.5 ppf, 14,000ft, 3 ½” Grade-G 13.30 ppf, 14,000ft 30 of 5”, 100 of 3 ½” 12 of 9 ½“, 24 of 8 ½“, 24 of 6 ½“, 24 of 4 ¾”

: : : : :

25,000 ft. 275 ft. 45’ max. Forward / backward movement, Pipe Rack 800,000 lbs. 12’ transverse on each side from centerline of hole Upper - 30’ (derrick floor to base of cantilever) Lower - 56’ (derrick floor to base of the hull) xxxx Kips xxxx people

C)

D)

E)

H)

98 of 102

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1

GENERAL INFORMATION

F

SECTION

June 2006

RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.5.4

RC-42 (OFFSHORE RIG)

A)

Year Built

:

1983 (derrick extended in 1987, 5th engine installed in 1993)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National 1625 DE (1625 HP) with Elmagco 7838 auxiliary brake) Lee C. Moore 30 x 30 x 160 ft. 1,230,000 lbs with 12 lines National PS2 650/650 – 650 Ton National C 375 (37 ½”) National 660 H500 – 500 Ton None OEM computerized system with 2 monitors.

Rig Power 1. Engine Power 2. Drawworks 3. Mud Pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar.D399 – 1325 HP ea. + One D379 Emergency Gen. 2 x GE motors 752 – 1000 HP ea. 4 x GE motors 752– 1000 HP ea Draw works driven - Torque 1060 Amps / 5300 ft-lbs GE 752 motor – 1130 HP, Torque 1250 Amps / 47,860 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud Pits & Storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x National 12P-160 – 1600 HP ea. 1392 bbl. capacity, 45 bbl. trip tank 4 x Brant King Cobra Brant LCM, 3 x 12“ cone / 24 x 4“ cone – 1600 GPM None Swaco Total Mud Degasser – 1000 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 523 with 15 stations 3 1/16” EEC, 10,000 psi WP sour service Varco 30” Annular, 1000 psi, Hydril 13 5/8” Annular 5000 psi, Hydril 21 ¼ Annular, 2000 psi, Cameron U 13 5/8 Double Ram 10000 psi, Cameron U 13 5/8 Single Ram 10000 psi. All H2S trimmed.

F)

Safety Equipment

:

1 x 54-man, 1 x 38-man lifeboats, 4 x 25-man davit launched life rafts, 4 x 25-man throw over life rafts. 110 life jackets, 130 Survival suits, 12 Working vests, 23 Sabre 30-min. air packs, 139 x 15-min. Sabre air packs, Fire/Smoke monitoring system, 98 fire extinguisher, 2 fire pump, 9 x combustible gas / H2S gas detectors, 1 cascade system, 6 portable gas monitors, 4 eye station, 3 shower, 3 breathing air compressors.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G 19.5 ppf, 14,000ft, 3 ½” Grade-G 13.30 ppf, 14,000ft 50 of 5”, 100 of 3 ½” 12 of 9 ½“, 24 of 8 ½“, 24 of 6 ½“, 24 of 4 ¾”

: : : : :

25,000 ft. 280 ft. 45’ max. Forward / backward movement 12’ transverse on each side from centerline of hole Upper - 29’ (derrick floor to base of cantilever) Lower - 56’ (derrick floor to base of the hull) - 52’ (base of hull to top of jack housing) xxxx Kips xxx people

C)

D)

E)

H)

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

99 of 102

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F

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RIG SPECIFICATIONS

___________________________________________________________________________________________________________________________

3.6.1

PN-2 (OFFSHORE RIG)

A)

Year Built

:

1980 (Refurbished in 2002)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

Oilwell E2000 (2,000 HP) with Elmagco 7040 auxiliary brake Brenham 45 ft x 160 ft 1,000,000 lbs (static) with 12 lines Varco TDS-4 – 500 Ton Oilwell A 37 (37 ½”) Ideco UTB-525 – 475 Ton Oilwell PC-500 – 500 Ton Spectrum computerized system with 2 monitors, 6 pens

Rig Power 1. Engine Power 2. Drawworks 3. Mud Pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar.D399 – 1150 HP ea. + One D399 Emergency 2 x GE motors DM7661 – 1000 HP ea. 4 x GE motors DM7661 – 1000 HP ea GE motor DM7661 – 1000 HP, Torque 1060 Amps / 53,000 ft-lbs. Varco TDS-4 – 1100 HP, Torque 45,500 ft-lbs.

Mud System & Pump 1. Mud Pumps 2. Mud Pits & Storage 3. Shale Shakers 4. Desander/Desilter 5. Centrifuge 6. Degasser

: : : : : :

3 x Oilwell A-1700PT – 1600 HP ea. 2839 bbls Capacity with 69 bbl Trip Tank 3 x Derrick Flow Line Cleaners Derrick 10“ x 3 cones / 4“ x 20 cones – 1000 GPM ea. Derrick CV 1000 – 1000 GPM Brandt DG10 – 1200 GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

3000 psi, CAD 523 with 15 stations 3 1/16” Cameron 10,000 psi WP, sour service Shaffer 30” Annular, 1000 psi, Cameron D 13 5/8” Annular 5000 psi, Shaffer 21 ¼” Annular 2000 psi, Cameron U 13 5/8 Double Ram 10000 psi, Cameron U 13 5/8 Single Ram 10000 psi. All H2S trimmed.

F)

Safety Equipment

:

2 x 61-man Lifeboats, 6 x 25-man Liferafts, 1 x 20-man Self Inflatable boat, 223 Life Jackets, 18 Survival suits, 10 Working vests, 44 x 30-min. Scott air packs, 280 x 15-min. Scott air packs, Fire/Smoke monitoring system, 2 fire pump, 10 x combustible gas detector, H2S gas detector,1 cascade system, 180 SCBA, 4 portable gas monitor, 4 eye station, 4 shower, 3 breathing air compressor.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade-G 19.5 ppf, 14,000ft, 3 ½” Grade-G 13.30 ppf, 14,000ft 60 of 5”, 100 of 3 ½” 12 of 9 ½“, 24 of 8 ½“, 24 of 6 ½“, 24 of 4 ¾”

: : : : :

20,000 ft. 300 ft. 45’ max. Forward / backward movement, Pipe Rack 800,000 lbs. 12’ transverse on each side from centerline of hole Upper – 29’ (derrick floor to base of cantilever) Lower – 55’ (derrick floor to bottom of the hull) 4,234 Kips 112 people.

C)

D)

E)

H)

100 of 102

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

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3.6.2

PN-5 (OFFSHORE RIG)

A)

Year Built

:

1980 (Major maintenance / refurbishment in 2005)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

National 1320-UE (2000 HP) with Baylor xxxx Auxiliary Brake Dreco 30’ x 149 ft. 1,000,000 lbs. (static) with 12 lines Varco TDS 3 B20 – 500 Ton National Type C - 37-1/2” – 500 Ton National 750-FA & 760-FA – 500 Ton National P-500 – 500 Ton Martin Decker, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

5 x Caterpillar D399 – 1200 HP ea. with 1250 KW Generators 2 x GE 752 Motor – 1000 HP ea. 4 x GE 752 Motor – 1000 HP ea. GE 752 Motor 1000 HP, Torque 1060 Amps / 5300 ft.-lbs GE 752 Motor 1000 HP, Torque 1060 Amps / 5300 ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x National 12-P-160 – 1600 HP ea. 1450 bbl. capacity with 30 bbl. Trip Tank 3 x Derrick Flo-Line Cleaner 2000 Brandt SRS-2, 0 x 00” cone / 0 x 00” cone – 1000 GPM Mission Magnum 6” x 8”–1400 GPM (Brandt 1850 Solid– 250 GPM) Brandt DG 10 – 1000 GPM

C)

D)

E)

BOP Equipment 1. Accumulator : 3000 psi, CAD EE 14K 1NR 3 Stations (No. of control levers and no. of bottles with capacity in gallons) 2. Choke manifold : 3 1/8 “ EEC, 10000 psi WP Sour service? 3. BOPs : Hydril GK 13 5/8” annular 10000 psi Cameron U 13-5/8” single ram, 10000 psi Cameron U 13-5/8” double ram, 10000 psi.

F)

Safety Equipment

:

H2S & Combustible Gas Monitoring System, Fire / Smoke detection system, Portable H2S & combustible gas monitors, 2 x 600 GPM fire pumps, CO2 monitoring system, oo x Portable Fire Extinguishers, Sprinkler System in accommodations, Foam system at Heli-Deck, Cascade Breathing System, 2 x 60-man Lifeboats, 4 x 25-man Life rafts, 1 x Fast Rescue Craft.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

4” Grade-G 14.0 ppf, 14,000 ft, 2 3/8” Grade-E, 6.65 ppf, 8700 ft. 100 of 4” 12 of 6 ½”, 15 of 4 ¾”, 12 of 3 3/8”

Sub-Structure

: : : : :

5. Variable Deck Load 6. Accommodation

: :

13,000 feet 160 feet 40’ Max. forward / backward movement 10’ Transverse on each side from center line of hole Upper – 25.7’ (Derrick Floor to Base of Cantilever) Lower – 48.7’ (Derrick Floor to Base of the Hull) – 49’ (Base of Hull to Top of Jack Housing) 0000 Kips 000 people

H)

Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

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3.7.1

SAR-201 (OFFSHORE RIG)

A)

Year Built

:

1982 (Completely Refurbished in 1998)

B)

Rig Equipment 1. Drawworks 2. Derrick 3. Hook Load 4. Top Drive 5. Rotary Table 6. Blocks 7. Swivel 8. Geolograph

: : : : : : : :

Continental Emsco C2 – 2000 HP with auxiliary brake Pyramid 30’ x 160 ft. 1,300,000 lbs static with 12 lines Varco TDS 3 C. Emsco T3750, 37 ½”, xxx Ton C. Emsco Model, 500 Ton Make and Model? 500 Ton Martin Decker/Totco, 8-pen

Rig Power 1. Engine Power 2. Drawworks 3. Mud pumps 4. Rotary 5. Top Drive

: : : : :

4 x Caterpillar D399, xxx HP ea. with xxxx KW generator 2 x EMD M79 – 750 HP ea. 2 x EMD M79 – 750 HP ea. 1 x EMD M79 – 750 HP ea, Torque xxx Amps / xxxxx ft.-lbs 1 x GE 752 – 1000 HP, Torque xxx Amps / xxxxx ft.-lbs

Mud System & Pump 1. Mud Pumps 2. Mud pits & storage 3. Shale Shakers 4. Desander / Desilter 5. Centrifuge 6. Degasser

: : : : : :

2 x C. Emsco FB-1600, 1600 HP ea 1900 bbl. Capacity (active and reserve) 60 bbl trip tank 3 x Derrick Flo-Line Cleaner Brandt model? xxxx GPM? / None Mission Fluid, 11-1/2” impeller, xxxx GPM Brandt model?, xxxx GPM

BOP Equipment 1. Accumulator 2. Choke manifold 3. BOPs

: : :

Type 80, Koomey 5000 psi WP, sour service Shaffer 30” annular – xxx psi, Make? 13-5/8” annular – xxx psi, Cameron Type-U 13-5/8” single ram – 5000 psi Cameron Type-U 13-5/8” double ram – 5000 psi.

F)

Safety Equipment

:

H2S & Combustible Gas Monitoring System, Fire/Smoke Detection system, Portable H2S & Combustible gas monitors, 2 x 300 GPM fire pumps, CO2 system in Engine Room/SCR/Gen/Paint rooms, Sprinkler System in accommodations, Heli-deck Foam system, Cascade Breathing System, 2 x 50man Lifeboats and Life rafts, 1 x Fast Rescue Craft.

G)

Drill Pipe & Drill Collars 1. Drill Pipe 2. HWDP 3. Drill collars

: : :

5” Grade G, 19.5lbs/ft, 8000 ft. 3 ½” Grade G, 13.3 lbs/ft, 10,500 ft. 112 of 5”, 90 of 3 ½” 15 of 8 ½”, 20 of 6 ¼”, 20 of 4 ¾”

: : : : :

20,000 ft 230 ft 60’ Max. forward / backward movement 10’ Transverse on each side from center line of hole Upper – 32’ (Derrick Floor to Base of Cantilever) Lower – 18’ (Derrick Floor to Base of the Hull) – 42’ (Base of Hull to Top of Jack Housing) xxx Kips xxx people

C)

D)

E)

H)

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Design Criteria 1. Depth Capacity 2. Max. Water Depth 3. Cantilever 4.

Sub-Structure

5. 6.

Variable Deck Load : Accommodation :

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RIG CONTRACTS 1.0

GENERAL INFORMATION 1.1 The Document 1.2 Conditions 1.3 Amendments

2.0

CONTENTS OF A RIG CONTRACT 2.1 Schedule “A” 2.2 Schedule “B” 2.3 Schedule “C” 2.4 Schedule “D” 2.5 Schedule “E” 2.6 Schedule “F” 2.7 Schedule “G” 2.8 Schedule “H”

3.0

ABIDING BY THE RIG CONTRACT 3.1 Responsibilities

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RIG CONTRACTS 1.0

GENERAL INFORMATION 1.1

The Document The contract is an agreement between Saudi Aramco (the Company) and the Contractor, which clearly defines the equipment and services that are to be provided by the Contractor to the Company. It also documents the Company’s obligations towards the Contractor. The contract consists primarily of a signed document with attached schedules, drawings, standard specifications, and any other pertinent references/documents.

1.2

Conditions The following are some key conditions of the existing rig contracts: A)

B)

C)

D)

1.3

The contract has a specified time limit, which means that the conditions of the contract have to be met by both the Contractor and the Company for as long as the contract is in effect. At the end of the specified contract period, there usually is a provision to extend the contract at the discretion of the Company. At the end of the contract term, the Company has the option of not renewing the contract or renegotiating the contract for another term. When the Company decides to terminate a contract at its own convenience, prior to the term expiration date, the contract provides for compensation payment to the Contractor at a pre-determined rate. When there are disputes or different interpretation of the contract conditions by both parties, the contract provides for problem resolution through arbitration. The contract is very specific in identifying the minimum equipment and services that are to be provided by the Contractor for drilling and working over wells with a rig. At the same time, the Company has certain responsibilities and obligations that are also spelled out in the contract. Section 2.0 below summarizes the key items of the contract.

Amendments When an addition or change to the signed and approved contract is necessary, and waiting for end-of-term contract renewal is not an option, then an Amendment is issued. The Amendment can replace any clause or statement in the original contract and is valid until the contract is terminated

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or expires. It is important to note that an Amendment cannot take effect unless both the Company and the Contractor agree to the contents by signing the document.

2.0

CONTENTS OF A RIG CONTRACT 2.1

Schedule “A”, General Terms and Conditions This section of the contract addresses the following: A) B) C) D) E) F) G) H) I) J)

K) L)

M) N) O) P) Q) R) S) T)

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Definition of terms used in the contract Qualification and requirements of Contractor’s personnel Access to well location by contractor Housing and medical responsibilities of Contractor for its personnel Inspection and testing of Contractor equipment Contractor’s warranty of defect-free equipment, materials and workmanship Contractor’s and Saudi Aramco’s liabilities in cases of loss, damage, and injury. Required Insurance coverage of the contractor. Contractor’s responsibility to prevent pollution and liability in case it does occur. Both Contractor and Saudi Aramco will use tools, equipment or material that have valid patents, trademarks and are not trade secrets of another company. Claims settlement. Contractor’s and Saudi Aramco’s positions when work cannot be performed due to uncontrollable situations such as storm, strikes, etc. This is known as ‘Force Majeure’. Saudi Aramco’s recourse when the Contractor does not meet performance expectations. Termination of contract for cause. Termination of contract at Saudi Aramco’s convenience. Contractor’s obligation to keep Saudi Aramco information confidential. Limits of what the contractor can offer to Saudi Aramco employees so as not to influence the awarding of any contract. Conditions under which work can be subcontracted out to a third party. Contractor’s obligation to obtain approval prior to releasing any information from this contract for publicity reasons. Where possible, the contract should be translated into Arabic except for sections C & G which are highly technical in nature.

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U)

V) 2.2

Contractor is responsible for conducting all Government relations activities within Saudi Aramco. If requested, Saudi Aramco may provide general guidance. General provisions.

Schedule “B”, Scope of Work and Technical Provisions A) B) C)

D) E) F) G)

H) I)

J)

Introduction. Contractor’s responsibility to drill, core, test complete, workover, abandon and perform other rig operations. Well Programs: Saudi Aramco will provide the Well Programs, 18,000’ is the maximum drill depth unless agreed by both parties, some wells might be horizontal, Company shall notify Contractor at least 24 hours before rig release, and downhole tools and tubulars are subject to 0-8% H2S exposure. Casing: The Well Program will dictate the hole size, depth and size of casing to be run. The casing will be run and cemented per Program. Surveys: Sets the guidelines for single shot surveys in vertical and directional wells. Drilling Fluids: The Company will determine the type of drilling fluid to be used and the Contractor will maintain the fluid characteristics. Measurements: Contractor will measure drill string length with steel tape whenever requested by the Company. Contractor shall be ready to commence operations on the date specified in this section. Contractor shall perform the work on a 24 hour, 7-day a week basis. Contractor shall provide its own office and workshop facilities in a local community. Contractor shall provide all services, equipment, machinery, tools, instruments, materials, supplies, support personnel and labor when performing rig work. Contractor is obligated to make all reports to and receive from the Company Representative on rig activities. Contractor shall drill wells according to acceptable industry practices. Contractor will also clean location within 5 days of rig release or well abandonment. If a hole is damaged or lost due to Contractor’s negligence, then reimbursement payment will be made to the Company.

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2.3

Schedule “C”, Contract Price and Payment Provisions In this section of the contract, the following are covered: A) B)

C) D) E) F) G)

Contract pricing conditions Payable rates for mobilization, demobilization, daywork, special daywork rate, downtime, rig and camp move rates, meals, force majeure, equipment and services Termination for cause or at Saudi Aramco’s convenience Handling of Invoices and currency of payment Saudi Aramco’s rights to audit the contractor’s books and records Adjustment of rates and deductions/reimbursements of equipment and services Setoff. This is Saudi Aramco’s right to deduct amounts that are due and payable to the contractor

The appendix at the end of this section contains the actual rig rates for labor related items and services performed. 2.4

Schedule “D”, Safety, Health and Environmental Requirements The main topics covered in this section include:

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A)

General Provisions • Compliance with safety, health and environmental requirements • Deviations from Safety Requirements • Failure to comply • Saudi Aramco Assistance

B)

Safety and Health Requirements • Loss prevention program • Work permits • Well control • Personnel safety • Welding and cutting equipment • Personal protective equipment • Tools and portable power tools • Cartridge operated tools • Electrical installations and equipment • Cranes and rigging equipment • Mechanical equipment • Saudi Aramco plant operations • Transportation

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RIG CONTRACTS

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• • • • • • • C)

2.5

Injury and damage reporting Work over/or adjacent to water (Gulf) Fire Prevention Ionizing Radiation First Aid Facilities Explosives Contractor Camps

Environmental Requirements • Introduction • Applicable Saudi Aramco and/or other engineering requirements • Waste management program • Water supply protection • Wastewater management • Spill control • Solid waste management i) Waste disposal program ii) Containers and storage iii) Hazardous waste storage and handling iv) Method of collection v) Requirements for establishing a landfill disposal site vi) Classification of landfill disposal site vii) Solid waste disposal, site design and operations viii) Offshore disposal • Air pollution mitigation • Noise control

Schedule “E”, Settlement of Disputes, Arbitration and Choice of Law This section of the contract defines the procedures for the Contractor to file a claim against the company. It also addresses the steps involved towards settling a claim through arbitration.

2.6

Schedule “F”, Taxes, Duties and Obligations In this section, Contractor’s tax liabilities to the Kingdom are discussed, along with recourse when tax payments are delinquent. Also, custom clearance and duties, plus reimbursement to Saudi Aramco are presented.

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2.7

Schedule “G”, Saudi Aramco & Contractor Supplied Materials, Tools, Equipment and Services. In this section, the following main points are addressed: A) B) C) D) E) F) G) H)

Contractor’s and the Company’s obligation statement to supply items and services. The Company’s discretion of providing items for rent which the Contractor is responsible for. Contractor’s obligation to rent items at the Company’s request. Inspection and reporting of defective items when the Contractor rents items from the Company. Condition and maintenance of Contractor’s ancillary equipment. Care of materials, tools and equipment rented from the Company. Maintenance of Company supplied tools and equipment. Contractor’s right to obtain a refund on custom duties when re-exporting tools and equipment OOK.

Attachment 1 is a detailed listing of the Contractor supplied minimum equipment and services. This includes A) Rig and Ancillary Equipment Drawworks, power units, mud pumps, mast and substructure; BOP equipment, crown block, traveling block, hook, swivel; drill pipe elevators and slips; drill collar elevator and slips; kellys and kelly spinner; rotary table and top drive systems; spinning wrench; mud mixing unit, mud tanks, mud mixers, trip tank, flowline cleaners, desander, desilter, mud cleaners, rotary hoses, air hoist, etc. B) Other Supplies and Equipment Drilling water, fuel and lubricants, potable water, safety equipment, internal communication, and mud material storage boxes. C) Services Transportation for rig move and other equipment/materials, field camp facilities and requirements, and electrical repairs/maintenance of Company owned equipment at rig site. D) Deep remote desert additional requirements One 30-ton minimum grove rough terrain crane (or equivalent) with 24hour operator. Attachment 2 itemizes the equipment and services that the company shall provide. These are A) Wash pipe, wash over shoes, handling tools, etc. B) Fishing tools C) Roads and locations D) Drilling water

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E) F) G)

2.8

Radio equipment for communication Transportation Equipment not supplied by Contractor, as specified in the contract. Drill pipe elevators and slips, back pressure valves and kelly cocks, drill pipe safety valves, drill pipe, drill collars and subs, and heavy weight drill pipe.

Schedule “H”, Special Terms and Conditions This section covers the following: A) B) C) D) E) F) G) H) I)

3.0

Contractor workforce Saudization. The land which the Company has to provide to the Contractor for its use as a yard, storage area and office structure. Right of the Company to extend term of the contract by one year. Payment conditions to the Contractor in case of early termination of contract. Reaffirming Contractor’s handling and disposal of hazardous material in accordance with acceptable industry practices. Contractor approval requirements prior to camp move. Financial penalties in case Contractor cannot commence on specified date. The right for the Contractor to rent required tools/equipment from a third party. The Company’s option to elect not to utilize the Topdrive unit.

ABIDING BY THE RIG CONTRACT 3.1

Responsibilities The Drilling Foreman has the responsibility of ensuring the Contractor meets the contract obligations while drilling or working over a well. He should be very familiar with terms of the contract and ask his Superintendent for advice when unsure. He should know which piece of equipment or service is to be supplied by the Contractor, and which by the Company. Whenever he observes contract violations, it is his duty to notify the Contractor for immediate correction. If the violation is not corrected within a reasonable time, then the Drilling Foreman should highlight the problem to his Superintendent for further action.

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WELL LOCATIONS

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WELL LOCATIONS 1.0 INTRODUCTION 2.0 CONSTRUCTION REQUIREMENTS 2.1

2.2 2.3 2.4 2.5 2.6

General Specifications 2.1.1 Development Locations 2.1.2 Exploration Locations 2.1.3 Drilling Islands Location Specifications for Different Rigs Access Road Rig Campsite Cellar Clean Up Operations

3.0 WELLSITE SAFETY REQUIREMENTS 3.1 3.2

General Spacing Requirements Producing Wells in Populated Areas

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WELL LOCATIONS 1.0

INTRODUCTION Preparation of the drillsite location is a comprehensive process. It involves locating/building the site to (a) meet construction specifications, (b) accommodate rig dimensions, and (c) comply with well safety requirements. This chapter will discuss the construction and wellsite safety requirements for Saudi Aramco onshore well locations.

2.0

CONSTRUCTION REQUIREMENTS 2.1

General Specifications 2.1.1

Development Locations Surveying Services Division will set the preliminary positions of development well locations. A site review committee shall visit the location to determine the feasibility of wellsite construction at the proposed surface location. If the well location is moved for construction purposes, an authorized person from Reservoir Engineering and Facilities & Projects Division shall approve the move. Drilling and Workover Engineering will be informed of the magnitude and direction of move. Final survey sheets will indicate the direction and distance of move, reason for moving location, names of representatives from Wellsites, Facilities & Projects, and Loss Prevention. General specifications for Development well location construction are as follows: A)

The preferred orientation of the well location is East/West and drainage to South. If topography dictates a North/South orientation, drainage should be to the East. Drainage should never be West or North.

B)

The required well location sizes for the Saudi Aramco onshore rigs are as follows: SAR-151: SAR-153: SAR-103:

130m x 100m 122m x 117m 100m x 90m

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2.1.2

C)

Development well locations for active Nadrico rigs are constructed 122m x 91m, with the exception of NAD-212 which is 130m x 100m.

D)

Development well locations for active Pool Arabia rigs are constructed 122m x 91m in the local area and 122m x 122m in central area.

E)

Development well locations for active Arabian Drilling Company rigs are constructed 122m x 100m.

F)

Flare line and flare pit construction is in accordance with Saudi Aramco Engineering Standard; SAES-B-062 dated January 23, 1995 for Onshore Wellsite Safety.

G)

The finished location should be capped with 0.3m dry marl and 0.15m wet compacted marl.

Exploration Locations The Exploration Department will set the preliminary position of exploratory well locations. If the proposed location is in an inhabited area, a full site review committee will be required. The review will be limited to the Wellsites representative when the location is in a remote area. If the well location is moved for construction purposes, an authorized person from Exploration shall approve the move. General specifications for Exploration well location construction are as follows: A)

The preferred orientation of the well location is East/West and drainage to South. Drainage should never be West or North.

B)

Khuff/Pre-Khuff gas well locations for the current rigs are constructed 152m x 136m with cellar orientation East/West, drainage to South, and two flare pits. The only exceptions are the Santa Fe rigs, which require a 161m x 133m location.

C)

Each rig has its own designed drainage area and offset for flare line road.

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2.1.3

D)

Each Exploration location will have a water well location constructed 90m x 90m (a minimum of 500m North of the location) and a campsite 90m x 60m (a minimum of 1000 m North of location). All Khuff/Pre-Khuff gas well campsites should be 3-4kms, preferably North of drillsite location.

E)

The gas buster dike will be constructed on the South side of the location (305m long).

F)

The finished location should be capped with 0.3m dry marl and 0.15m wet compacted marl. Water well locations and campsites should be capped with0.3m dry marl.

G)

Flare line and flare pit construction is in accordance with Saudi Aramco Engineering Standard; SAES-B-062 dated January 23, 1995 for Onshore Wellsite Safety.

Drilling Islands A drilling island is a multiple well pad, which enables the drilling of more than one development well from the same well location. This practice is used in areas where topography limits feasible drillsites, as in the Shaybah Field. General specifications for drilling island construction are as follows: A)

The preferred orientation of the drilling island is East/West and drainage to South. If topography dictates a North/South orientation, drainage should be to the East. Drainage should never be West or North.

B)

The well spacing on the drilling island should be 50m minimum.

C)

Drainage area, flare line dike, and flare pit position/ dimensions should conform to the relevant drilling rig development location specifications.

D)

The finished location should be capped with 0.3m dry marl and 0.15m wet compacted marl.

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2.2

Location Specifications for Different Rigs The following diagrams illustrate the location layout and dimensions required for the active rigs currently operating in Saudi Aramco (also included are stacked rigs, which may be activated in the future).

Note: Location drawings with the second flare pit on Khuff/Pre-Khuff wells will be addressed in future manual updates.

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SAR-151 LOCATION: 130m x 100m ______________________________________________________________________________________ 5 of 32

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SAR-153 LOCATION: 122m x 117m ______________________________________________________________________________________ 6 of 32

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SAR-103 LOCATION: 100m x 90m

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ADC-3 LOCATION: 122m x 100m ______________________________________________________________________________________ 8 of 32

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ADC-4 and 12 LOCATION: 122m x 100m ______________________________________________________________________________________ 9 of 32

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ADC-14 LOCATION: 122m x 108m ______________________________________________________________________________________ 10 of 32

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NAD-60 and 88 LOCATION: 122m x 91m

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NAD-283, 284, & 288 LOCATION: 130m x 115m ______________________________________________________________________________________ 12 of 32

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NAD-211 LOCATION: 130m x 100m ______________________________________________________________________________________ 13 of 32

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NAD-212 LOCATION: 130m x 100m ______________________________________________________________________________________ 14 of 32

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PA-201 LOCATION: 122m x 91m

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PA-214 LOCATION: 122m x 91m

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PA-215 LOCATION: 122m x 91m ______________________________________________________________________________________ 17 of 32

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PA-235 LOCATION: 122m x 91m ______________________________________________________________________________________ 18 of 32

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PA-236 LOCATION: 122m x 91m

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ADC-15 and 21 LOCATION: 152m x 136m ______________________________________________________________________________________ 20 of 32

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DPS-43, 44, & 45 LOCATION: 152m x 136m ______________________________________________________________________________________ 21 of 32

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PA-202 LOCATION: 152m x 136m ______________________________________________________________________________________ 22 of 32

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PA-203 LOCATION: 150m x 130m ______________________________________________________________________________________ 23 of 32

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PA-304 LOCATION: 152m x 136m ______________________________________________________________________________________ 24 of 32

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NAD-70 LOCATION: 150m x 130m ______________________________________________________________________________________ 25 of 32

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NAD-117 LOCATION: 152m x 136m ______________________________________________________________________________________ 26 of 32

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SF-173 and 174 LOCATION: 161m x 133m ______________________________________________________________________________________ 27 of 32

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2.3

Access Road General specifications for access (skid) road construction are as follows:

2.4

A)

Development and Exploration skid roads should be 14m or 21.5m in width (depending on the size of rig) with marl 9m wide (0.30m thick) longitudinally along the center.

B)

The edge of 9m marl should be taken down at a 1 to 1 slope to shoulders.

C)

If the skid road is constructed over 1m above the existing ground level, then the embankment slopes should be at a maximum gradient of 1 to 4 (25 percent grade).

D)

The maximum inclination of the access road should be 1 to 20 (5 percent grade).

E)

Skid roads in Shaybah should be constructed with marl 1.0m thick for the full width of the skid road. Embankment slopes should be at a maximum gradient of 1 to 4 (25 percent grade).

F)

The minimum radius of curves should be 70m. In the case of SAR-151 and SAR-153, the minimum radius will be 152m. Access road curvature for larger Exploration rigs is not as critical, as all loads are broken down.

G)

Junctions with other skid and black top roads should be widened with a minimum filet size of 30m x 30m.

Campsites General specifications for campsite construction are as follows: A)

The standard campsite for all rigs consists of 90m x 60m with a 0.30m marl cap.

B)

The campsite should be within a distance of 5kms from the location. On Khuff gas wells, the campsite shall be no less than 3-4kms and preferably North of the location.

C)

Wellsites will determine if an existing campsite will fit the above specifications or if a new campsite is to be constructed.

D)

A garbage pit and sump pit will be constructed at the campsite.

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2.5

Cellar General specifications for cellar construction are as follows: A)

The Construction Engineering Supervisor should approve the final elevation of the well location before construction of the cellar begins.

B)

The cellar work should start prior to the actual pad construction. This will identify problems with hard rock in the cellar area.

C)

If the cellar is located over hard rock, the Construction Engineer will determine whether or not there is a need to excavate or raise the location elevation to save time.

D)

Excavation size should include 25m x 25m with cellar centrally located. The depth of cellar should be 0.30m deeper than required to allow for a pad of compacted marl, which will provide an adequate base for cellar. Ramps should be built on both sides of the cellar to allow for access of construction equipment.

E)

The Construction Engineering Supervisor will arrange for cellar delivery. An inspector will be assigned to escort the crane and cellar to location. A surveyor will be on site to ensure the cellar is properly set. Arab-D Cellar:

3m in diameter (fiberglass pipe) 4’ deep for vertical and horizontal wells

Hanifa Cellar:

3m in diameter (fiberglass pipe) 4’ deep for vertical wells 5’ deep for horizontal wells

Khuff/Expl. Cellar:

20’ x 12’ (steel box) 14’ deep

F)

Controlled fill procedures will be required over the area within 25m of the cellar. Marl should be placed in layers of uniform thickness not exceeding 15cm after compaction with a heavy vibratory drum roller. Each compacted lift should be tested for density and material gradation prior to placing additional lifts.

G)

The Construction Engineering Supervisor will arrange to install a fence around the cellar after completing construction.

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2.6

Clean Up Operations Wellsite clean up operations will begin the day the rig moves to the next drilling location. The goal of Wellsites Division is to complete the clean up no later than 7 days after the rig move. General specifications for clean up operations are as follows:

3.0

A)

Location and campsite will be graded if deeply rutted or badly marked.

B)

Any washouts or excavations on location will be filled with marl.

C)

All pits will be back filled after removing liquid with material from surrounding dikes (or sand if dike material is not adequate) for both location and campsite.

D)

All refuse, garbage, and debris will be collected within 90m of the well location and campsite.

E)

Cellars on Arab-D wells and Khuff wells should not be filled with sweet sand at rig release.

F)

Any re-usable drilling material remaining on the wellsite/campsite will be noted and reported to the Wellsites Supervisor.

WELLSITE SAFETY REQUIREMENTS 3.1

General Spacing Specifications The following spacing requirements regarding wellsite safety are taken from Engineering Standard SAES-B-062 (as shown in Appendix 2A). These specifications apply to onshore oil/gas wells with shut-in wellhead pressure < 3600 psi. All oil/gas wells with shut-in wellhead pressure > 3600 psi and all gas injection wells are to be determined by a case by case basis, with concurrence with the Chief Fire Prevention Engineer. A)

The minimum distance from an adjacent well to outer edge of wellsite location shall be 105m.

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B)

The minimum distances from flare pit to control point are as follows: Flare pit to overhead power lines (150m) Flare pit to cathodic protection (105m) Flare pit to highway/camel fence/paved road/railroad (105m) Flare pit to above ground pipelines (60m) Flare pit to under ground pipeline (15m)

3.2

C)

A minimum distance of 450m from wellsite to any of the following: process areas; major shipping pump, blending/booster pump, or fire pump areas; tetraethyl lead (TEL) facilities; LPG loading racks; atmospheric or pressured vessels; boilers and power generation facilities; major electric distribution centers; buildings, property lines, and residential areas.

D)

The minimum distance from oil/gas wells to overhead power lines is 200m.

E)

The minimum distance from oil/gas wells to cathodic protection or other noncritical power lines is 105m.

F)

A minimum distance of 105m from oil/gas wells to any of the following: right-of way, camel fence, Saudi Aramco or Government highway, paved roads, or railroads.

G)

The minimum distance from oil/gas wells to pipelines is 105m.

H)

Water gravity injectors, power injectors, or supply wells must have a 105m spacing requirement from all other facilities.

Producing Wells in Populated Areas The following requirements apply to producing wells in populated areas. In addition, these requirements may also apply to wells that are located near areas of potential concern, such as roads, parking areas, or campsites. The Proponent Operating/Engineering Department shall determine whether these additional precautionary measures are taken.

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A)

On oil wells, the upper wellhead master valve shall be a spring assisted fail-safe Surface Safety Valve (SSV), triggered when an abnormally low pressure is sensed. Triggering by abnormally high pressure is required only when necessary to protect the downstream flowline. A fusible device with a melting point 30 degrees Celsius above the higher of the flowing wellhead temperature or maximum design ambient temperature, shall be installed on the wellhead to trigger the SSV.

B)

A Sub-Surface Safety Valve (SSSV) per API RP 14B specification shall be installed more than 60m below ground level in oil/gas wells. The SSSV shall be controlled by the low pressure pilot. Closure triggered by an abnormal condition in the high pressure piping downstream of the choke shall be provided when required by the Proponent Operating Department. A fusible device with a melting point 30 degrees Celsius above the higher of the flowing wellhead temperature or maximum design ambient temperature, shall be installed on the wellhead to separately trigger the SSSV.

C)

Wellsites in populated areas shall be enclosed by a fence meeting the specifications of SAES-M-006 (Type III). The fence shall have four lockable vehicle gates, one in each quadrant. Two gates shall be 18m wide rig-access gates. The location of these rig-access gates will permit access to all wells on the wellsite.

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CASING 1.0

CASING DESIGN FACTORS

2.0

CASING POINT REQUIREMENTS 2.1 Abqaiq Field 2.2 Ain Dar Field 2.3 Abu Hadriya Field 2.4 Abu Jifan Field 2.5 Abu Safah Field 2.6 Berri Field 2.7 Dammam Field 2.7 Fadhili Field 2.9 Fazran Field 2.10 Haradh Field 2.11 Harmaliyah Field 2.12 Hawiyah Field 2.13 Khurais Field 2.14 Khursaniyah Field 2.15 Manifa Field 2.16 Marjan Field 2.17 Mazalij Field 2.18 Qatif Field 2.19 Qirdi Field 2.20 Rimthan Field 2.21 Safaniyah Field 2.22 Shaybah Field 2.23 Shedgum Field 2.24 Uthmaniyah Field 2.25 Zuluf Field

3.0

CASING INSPECTION 3.1 Khuff, Deep & Exploration Wells 3.2 Development Wells

4.0

SAUDI ARAMCO CASING DATA

5.0

KHUFF CASING & TUBING DATA

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CASING 1.0

CASING DESIGN FACTORS Exact values of loading are difficult to predict throughout the life of the well. For example, if mud of 75 pcf is on the outside of the casing during the running of the casing, this value cannot be expected to remain constant for the entire life of the well. The mud will become deteriorated with time and will reduce this value to perhaps a saltwater value of 64 pcf. Therefore, calculations of burst values assuming a column of mud at 75 pcf are not realistic throughout the life of the well. If the initial casing design is marginal, then over a period of time a tubing leak may result in casing burst. Since casing design is not an exact technique and because of the uncertainties in determining the actual loading as well as the deterioration of the casing itself due to corrosion and wear, a safety factor is used to allow for such uncertainties in the casing design and to ensure that the rated performance of the casing is always greater than any expected loading. In other words the casing strength is always down rated by a chosen design factor value. The minimum casing design factors for Saudi Aramco are as follows: Collapse: Tension: Burst:

1.125 1.6 1.33

The design factor is the ratio of the rated casing strength/resistance to the magnitude of the applied force/pressure. Note: x x x x

The biaxial effect to tension on casing collapse should be calculated in addition to using these design factors. The biaxial effect of tension on casing burst is not required as this is an additional safety factor. The minimum design factor for tension assumes bouyancy and applies to the weakest point (pipe body or joint strength). Other assumptions (such as the extent of casing evacuation, H2S service and maximum SICP) will vary with the well type and casing string.

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2.0

CASING POINT REQUIREMENTS 2.1

Abqaiq Field 26” Conductor Pipe This is set at 100’± below the surface. It serves to keep the unconsolidated sand from washing out under the rig. Actual size of the casing used for this may vary, depending upon the well program. 18-5/8” Casing Point Nominal casing point is the top of the RUS formation. Actual setting depths have varied widely over the years. It has been set as high as the top of the Eocene. Range is from 315’ above to 201’ below the top of the RUS, with most in the range of 25’ above to 50’ below the top. The purpose of the string is to separate the waters of the Alat and Khobar from the Umm er Radhuma water, and to support the hole after circulation is lost in the Umm er Radhuma) Static water level + 85’ mean sea level). The casing point is readily picked on samples, at the first occurrence of a chalky white gypsiferous anhydrite. This point may also be picked on drill time. Drill time decreases at the top of the RUS, as the lithology changes from blue and gray marl and the thin brown shale of the Midra to a thin limestone and the soft anhydrite. 13-3/8” Casing Point Nominal casing point for the string is 50’ into the Lower Aruma shale. Actual setting depths have varied from 990’ above the Lower Aruma shale (stuck casing) to 375’ below the top. The purpose of the casing is to shut off the lost circulation zone of the Umm er Radhuma from the water flow of the Wasia, and allow drilling the Wasia with mud to control the water. Since this interval is usually drilled without returns, the top of the lower Aruma shale must be picked on drill time. It is generally characterized by a gradual decrease in drill time and may be determined by comparison with nearby wells. The lithology at the upper portion of the Lower Aruma shale, as picked in the Abqaiq field, is actually limestone.

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In crestal part of the field the section between pre Aruma unconformity and K.S. Member is eroded and not possible to pick lower Aruma shale from drill time. In such cases setting 13-3/8” casing 50-100’ above the Pre Aruma unconformity or 600-800’ below Aruma will be adequate. 9-5/8” Casing Point Nominal casing point is 300’ into the greenish-gray shale (Biyadh formation). Actual setting depths have varied from 290’ above to 525’ below the top, with most in the range of 250-350’ below the top. The purpose of the casing is to shut off the lost circulation of the Dolomitic Limestone (Shu’aiba) and allow water drilling of the section below, to the top of the Arab-D zone. The section between the 13-3/8” and 9-5/8” casing points is drilled with mud to control the Wasia water, and prevent the Wasia shales from sloughing. Circulation is occasionally lost in the Wasia. If returns can not be gained by LCM pills or cement plugs, then drilling from this point to the casing point must be done with mud and mud cap across the Wasia. Circulation is commonly lost in the Dolomitic Limestone (Shu’aiba), and drilling from this point to the casing point is done with water and a mud cap across the Wasia. The upper portion of the greenish-gray shale is water sensitive, if exposed for more than a short period of time. In order to drill the section below with water, the casing must be set through this upper section. Probable minimum safe setting point for this is 200’ below the top. Since the actual thickness of the water-sensitive section may be variable, well programs should specify 300’ penetration. In recent injection and observation wells the 9-5/8” is programmed to be set in the Mid-Thamama L.S. This gets all the Biyadh sand and shales behind the casing and improves coring conditions in the formations below. Top of Mid-Thamama is a slight increase of drill time but it is not a good pick on the drill time log. A fairly good estimate can be made by projecting from the Biyadh top and by comparing with offset wells. The section to the top of the Arab zone may be drilled with water, but mud should be used in the Arab-D reservoir. The change may be made while drilling the anhydrite section just above the D reservoir, or at the casing point if 7” is to be set above the reservoir.

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7” Casing Point Nominal casing point is at the top of the Arab-D Reservoir, or below the base of the porosity if the set-through option is used, as in the more recent wells. Actual casing points have varied from 191’ above to 18’ below the top, with most in the range of 10-50’ above. Those that have been set through the reservoir have ranged from 219-301’ below the top. The top of the Arab-D may be picked on samples or drill time. The casing point can be determined readily by comparison of the drill time pattern through the Arab zones with nearby wells. In recent wells 7” casing is programmed to be set below the base of Hanifa Reservoir. The top of the Hanifa can be easily picked off the drill time log. The drill time shows a marked decrease. The base of porosity can also be determined readily by drill time comparison with offset wells.

2.2

Ain Dar Field 26” Conductor Pipe This is set at 100’± below the surface. It serves to keep the unconsolidated sand from washing out under the rig. Actual size of casing used for this may vary, depending upon the well program. 18-5/8” Casing Point Setting point for this casing is the top of the Eocene. Nominal point is 50’ below the Eocene-Neogene unconformity, but actual setting depths have varied from 23 to 236’ below the unconformity with most strings in the 50-100’ range. The lithologic unit directly below the unconformity may be either the Alat limestone or the Alat marl (“Orange Marl” depending on location. Actual size of casing used for this may vary. Most wells in the area have been drilled without setting casing in the Eocene using only a short conductor pipe, until setting 13-3/8” in the Lower Aruma shale.

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The purpose of the string is to separate the Neogene and Eocene aquifers, and to support the sides of the hole while drilling with lost circulation below the casing point. Obviously, in places where the Neogene is composed of competent beds, it is not needed for this purpose. The data below, taken from water well records, shows a marked difference in static water levels (SWL) of the aquifers in the area, with the lower units having the lower SWL’s. This means that if the aquifers are left in communication, some drainage of the upper aquifers may result, with the exception of the Neogene, which may be recharged. However, it is believed that the volumes concerned would be small. Water Data Aquifer Neogene Alat Khobar RUS Umm-er Radhuma Aruma

450’ 520’ 460’ 440’ 415’ 375’

SWL MSL MSL MSL MSL MSL MSL

Total Solids (ppm) 1600-7200 ±1800 ±1800 ±3600 ±1800 ±1800

Circulation has been lost in all of the above units at one place or another in Ain Dar. The top of the Eocene is picked on the change from sandy limestone or marl above the unconformity to non-sandy limestone or marl below. It can usually be picked on an increase in drill time at the contact. Where circulation is lost above the unconformity, drill time must be relied on. In high structural wells, where the unconformity cuts into the Alat marl, drill time may decrease sharply at the contact. 13-3/8” Casing Point Nominal casing point is 50’ into the Lower Aruma shale or Ahmadi limestone. Purpose of the casing is to separate the Wasia water sands from the overlying aquifers. The Wasia has a pressure about 190 psi greater than the overlying formations so that a large upward flow is possible. The casing point should be below possible lost circulation zones in the Aruma and Ahmadi formations so that circulation can be maintained while drilling the Wasia with mud.

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In several wells, circulation was lost while drilling the Upper Wasia after cementing 13-3/8” casing in the Lower Aruma Shale. If nearby wells show lost circulation in the upper Wasia, it is advisable to set the 13-3/8” casing 50’ into the Ahmadi limestone. The Lower Aruma shale may be difficult to pick from drill time, but a fair estimate can be made. The Ahmadi is a much clearer pick. 9-5/8” Casing Point The 9-5/8” casing is set in the top of the greenish-gray shale (Biyadh formation). Nominal point is 300’ below the top, but actual setting depths have varied with most wells in the 250-350’ range. Purpose of the casing is to shut off the lost circulation zone of the Dolomitic limestone (Shu’aiba formation) and/or the Wasia sands. It must also be set through the hydroscopic, sloughing shales at the top of the greenish- gray, so that the section below the casing point can be drilled with water. Thickness of these shales varies from place to place. Probable absolute minimum safe setting depth for this casing is 200’ below the greenish-gray top. Otherwise, mud will have to be used to control the shale, and drilling will be slower, particularly through the Hith anhydrite section. Top of the Dolomitic limestone (Shu’aiba formation) is easily recognized both on samples and drilling time from the fast drilling sands and shales of the Wasia above it. Loss of circulation shortly thereafter is also a sure indication, although circulation may also be lost above the contact in the Wasia. Top of the greenish-gray shale is less easy to pick, but usually is characterized by decreased drill time at the contact. Thickness of the Shu’aiba is usually 200-250’, which helps to locate the greenish-gray top. Drill time comparison with nearby wells serves to locate it. 7” Casing Point The 7” casing is the production string. It has normally been set just above the top of the Arab-D Reservoir but some trouble has been encountered with the so called sub-C stringer. This is a water bearing stringer just above the D reservoir, and as the reservoir pressure declines, the water has a tendency to break through into the oil zone around the casing shoe. Several wells have had to be worked over for this reason.

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The section from the 9-5/8” casing point to the top of the Arab-D is drilled with water. It consists of sand, some thin shales, and a thick section of limestone and anhydrite. The Yamama Detrital zone (Sulaiy formation) flows a modest amount of hot (180o) water, but this has no effect on the drilling operation. The change to mud is usually made while drilling the anhydrite just above the D reservoir. Relatively light mud must be used to drill in with to avoid lost circulation. Current practice is to set a liner rather than a full string of 7” casing. The 7” liner is set just above the top of the D reservoir, and below the sub-C stringer. The stringer is determined on the drill time as a decease for 5’+ and increasing again to the top of the D reservoir, which is 20’+ below the sub-C stringer. The 7” liner is set before drilling into the D reservoir. The D reservoir top and base can be easily picked from samples or drill time log. When picking 7” casing point, it is important to remember that the D reservoir is not to be penetrated and that the stringer should be behind the pipe when the casing is cemented. Drill with mud the last 50’ above the casing point.

2.3

Abu Hadriya Field 26” Conductor Nominal casing point for this string is 50’ into the Eocene. Actual setting depths have varied from 126’ above to 56’ below the top. The purpose of the casing is to shut off the loose unconsolidated sand of the Neogene. The top of the Eocene may be picked on drill time. It coincides in most instances with a considerable increase in drilling time, due to passing from the Neogene sand into the Eocene limestone. The lithologic break is also characteristic, either sand or sandy limestone, overlying the non-sandy Eocene limestone. The first Eocene member encountered is the Alat. Partial to complete lost circulation may be encountered in the underlying Khobar. 18-5/8” Casing Point Nominal casing point is 100’ into the RUS. Actual setting points have varied from 48’ above to 204’ below the top. Probable safe range is from 50-200’ below the top. Size of casing may vary depending on program.

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The purpose of the casing is to separate the Umm er Radhuma water flow, some 100,000 bbl per day of poor water (26,000 ppm total solids), from the overlying Alat and Khobar. If not separated, this flow would further contaminate the upper aquifers and might cause flooding in low places. The top of the RUS is picked either on samples or drill time. The lithologic change is from the blue and blue gray clays of the Alveoline zone to limestone or dolomite, followed within a few feet by anhydrite. The drill time pattern generally shows a slight decrease in drilling time at the top, followed by an increase as the anhydrite is penetrated. 13-3/8” Casing Point Nominal casing point is 200’ into the Lower Aruma shale. Actual casing points have varied from 196’ to 694’ below the top, with most in the 200’ range. The purpose of the casing is to shut off the water flow of the Umm er Radhuma, so that the Wasia formation below may be drilled with mud and full returns to control the sand and water in the Wasia. Higher wells in the field encountered intermittent lost circulation rather than a steady water flow from the Umm-er Radhuma, since the Umm er Radhuma static water level is 130’. The top of the Lower Aruma shale is characterized by a decrease in drill time, and by a lithologic change from light gray limestone to light gray pyritic shale. It may easily be picked on either samples or drill time comparison with nearby wells. 9-5/8” Casing Point Nominal casing point is 30’ into the mid-Thamama. Higher setting points may preclude the use of water to drill below the casing. The purpose of the casing is to shut off the lost circulation sometimes encountered in the dolomitic limestone and case off the water sensitive shales of the Biyadh. By setting deep enough, water may be used to drill the next section of the hole. Tops of the dolomitic limestone (Shu’aiba) and the greenish-gray shale (Biyadh) may be picked easily on either samples or drill time.

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The section above this casing point, drilled with mud, contains considerable sloughing shale in the Wasia, as well as a strong potential water flow. Some hole trouble from the sloughing shale may be encountered. The Dolomitic limestone (Shu’aiba) may be cavernous, or relatively compact. Some wells have maintained circulation throughout while others have had partial or complete loss. 7” Casing Point This string is a liner and is set in various places, depending on the type of completion. For routine wells designed to produce from the Hadriya zone, this point is about 100-200’ below the base of Hanifa Reservoir. The production string is set before penetrating the post Hadriya stringer, which is usually about 65’ above the top of Hadriya Reservoir and contains a high pressure, low volume gas zone in those wells where this porosity stringer is encountered. The purpose of setting the casing about Hadriya zone is to shut off the upper producing zones before encountering the gas zone. Attempt should be made to bleed down and deplete pressure in the stringer when drilling below the 7” casing. The Arab, Haifa and Hadriya Reservoirs can be easily picked on drill time. The base of porosity of all the reservoirs are also clear on drill time logs. In addition to the Hadriya zone, wells at Abu Hadriya have been completed in mid-jubaila and Arab zones.

2.4

Abu Jifan Field 18-5/8” or 20” Casing Point Nominal casing point is at top of Pre-Neogene unconformity which is sloughing after circulation is lost in the Umm er Radhuma. However, the Neogene is composed of competent limestone beds which will stand by themselves, so use of the casing depends on surface conditions. The Alat and Khobar are missing at Abu-Jifan, and the Eocene-Neogene unconformity cuts into the Umm er Radhuma formation. Circulation is commonly lost at about 100’ below the surface, and not regained until casing is set in the Wasia sand.

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13-3/8” Casing Point Nominal casing point is the Wasia-Aruma unconformity. Actual casing depths have varied from 150-200’ below the unconformity. The purpose of the casing is to shut off the lost circulation of the Umm er Radhuma formation and prevent the Wasia from charging the upper horizons. Circulation is frequently lost below the casing shoe in the Wasia. The Wasia is the main aquifer in the area; water quality is about 2000 ppm total solids. Static water level is about 1200’ mean sea level, surface elevations are about 1600-1700’. The unconformity may be picked on drill time. An increase of varying magnitude commonly occurs at, or just above, the unconformity. The lithology above the unconformity is limestone. Below it is a short section of shale or sandy shale and then the main Wasia sand is penetrated. Probable safe range for the setting depth is from 50’ to 150’ below the Wasia Aruma unconformity. 9-5/8” Casing Point Nominal casing point is 100’ into the Buwaib formation. Actual setting points have varied from 124’ to 345’ below the top. The purpose of the casing is to shut off the lost circulation zones of the Wasia, Shu’aiba and Biyadh formations. All are potential sources of trouble. Once this string is set, the remaining hole, to the top of the D member, may be water drilled. Top of the Buwaib may be easily picked either on samples or drill time. The lithologic change is from a long continuous sand section (Biyadh formation) to the compact limestones of the Buwaib. It is accompanied by a definite increase in drilling time. Main concern in setting the casing is to obtain a good cement job, so probable minimum penetration for this would be about 100’ below the top. 7” Casing Point Nominal casing point is below the base of the Arab-D reservoir. The purpose of the casing is to act as the production string. Top of the D or base of the C are distinctive picks on either lithology or drill time, and may be easily picked by correlation with other wells in the field.

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2.5

Abu Safah Field Conductor Pipe This is a 30” pile driven into the Gulf floor at the time that the well platform is installed prior to the rig moving on the location. The purpose of this conductor is simply to return the drilling fluid and cuttings to the surface while drilling to the first casing point in the RUS. 13-3/8” Casing Point Nominal casing point is 50’ into the RUS formation. The purpose of the casing is to protect the hole after circulation is lost in the Umm er Radhuma. Top of the RUS may be picked on samples or drill time. The lithologic change is from the light blue and light gray clay and marl of the Alveolina zone to the underlying light gray dolomitic limestone of the RUS. The RUS is 100-200’ thick, and contains no anhydrite. Circulation may be lost immediately below the RUS in the Umm er Radhuma. Definite information on the aquifers is not available, but indications are that the Alat is potable while the Khobar and Umm er Radhuma are not. The Umm er Radhuma pressure may be slightly higher than the Alat and Khobar, so that shut off’s should be established between them. 9-5/8” Casing Point Nominal casing point is 50” into the Ostracod Formation. The purpose of the casing is to shut off the lost circulation zone of the Umm er Radhuma so that the remaining section may be drilled with mud. The Ostracod Formation may be picked on drill time. This is readily done by comparison with nearby wells in the field. The drill time pattern shows a prominent decrease in drilling time in the Ostracod Formation after 50’± of higher drill time pattern. This is the last casing set before the production string. Circulation is maintained through the Shu’aiba and no casing is set in the Biyadh. In this field there is very little shale in the Biyadh, it being nearly all in a limestone facies.

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Small amounts of heavy (11-12° API) oil are encountered in the upper and lower Ratawi zones (Sulaiy). No abnormal pressure zones are encountered, so normal mud weights (74-78 pcf) are adequate. 7” Casing Point The producing zone is the Arab-D. Casing may be set either at the top of the zone, or set through it and perforated for production. Procedure had been to drill to TD, than set the 7” casing at the top of the zone, using a packer shoe and cementing in a single stage. The current practice is to set the 7” casing at the top of the ‘D’ reservoir and then drill out to total depth. Nominal casing point is 20’± above the Arab-D reservoir. The casing point can be determined readily by comparison of the drill time pattern through the Arab zones with nearby wells. A section of dense anhydrite and dolomite (about 30’ thick) immediately overlies the Arab-D porosity. This makes a good casing point.

2.6

Berri Field Conductor Pipe – 30” (Offshore) This is a conductor pile driven into the sea floor when the platform is set, prior to moving the rig on location. The purpose of the conductor is to return drilling fluid to the surface while drilling to the first casing point. Conductor Pipe –26” (Onshore) This is set at 100’± below the surface. It serves to keep the unconsolidated sand from washing out under the rig. Actual size of the casing used for this may vary, depending upon the well program. 18-5/8” Casing Point Normal casing point is 150’± above RUS. Actual casing points have varied from 250’ above to 100’ into the RUS. A hard section of 60’± is encountered below the Khobar which is 150-200’ above RUS, this section is adequate to set the casing.

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The purpose of the casing is to separate the relative potable water of the Alat and Khobar from the Umm er Radhuma water. Static water level of UER is 98’ so it flows at most Berri locations. This casing point is not easy to pick. The drill time shows a higher drilling time pattern in this section (60’±) compared to 50’± of section above and below. The size of this string might very depending on well program. 13-3/8” Casing Point Nominal casing point is 50’ into the Lower Aruma shale. Actual setting depths have varied. The purpose of the casing is to shut off the water flow or lost circulation of the Umm er Radhuma, so that Wasia may be drilled with mud to control the shale and water flow. It must be set low enough so that all possible water flows and loss circulation zones in Aruma are behind the pipe. The top of Lower Aruma shale may be picked on either samples or drill time. Lithologically, the Unit is a limestone rather than a shale. The drill time pattern shows a gradual increase at the top of Lower Aruma shale. The top can be picked by drill time comparison with nearby wells. Samples are composed of light gray pyritic limestones with some light gray marl. 9-5/8” Casing Point Nominal casing point is 50’ into Buwaib. Actual setting depths have varied from top to 180’ below top of Buwaib. In water injection wells which are drilled as a straight hole this string is omitted at this point if circulation is maintained. Producers and directional water injectors should be programmed to set 9-5/8” casing in Buwaib. The Buwaib is not a good pick, the drill time pattern shows a slight increase in drilling time. The top of Buwaib is 400’± below the top of Biyadh. The top of Shu’aiba may be easily picked on drill time. It coincides with a considerable increase in drilling time due to passing from the Wasia sand into the Dolomitic limestone. The top of Biyadh (greenish-gray shale) coincides with an increase in drilling time for about 30’ and then decreases gradually.

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7” Casing Point The 7” liner is set at various points depending on the objective reservoir. The Arab zones, Hanifa, and Hadriya reservoirs are easily picked from drill time. In vertical water injection wells the 9-5/8” casing is set at the top of the injection zone if no lost circulation is encountered in the Shu’aiba. In wells that are drilled to the base of lower Fadhili reservoir, the 7” liner is set at total depth and selectively perforated.

2.7

Dammam Field The Dammam field was Saudi Aramco’s original field discovery. Casing and drilling programs have been many and varied over the course of field development, and have been somewhat complicated by faulting in the field. The most recent wells drilled have been a deep test of the Khuff gas zone (DW-43) and a sweet gas supply well (DW-44). The casing program outlined here is recommended for a new well in the field. 13-3/8” Casing Point This casing is set at the Wasia/Aruma unconformity. Nominal casing point is 50’ below the unconformity in what is called the “Blue Shale”. The surface location is in either RUS or Umm er Radhuma formations, and circulation is lost within the first 300’ in the Umm er Radhuma. Drilling proceeds to the casing point with water. The purpose of the casing is to shut off the Umm er Radhuma so that drilling can proceed through the Wasia, which contains water and the sweet gas zone, with mud. The Wasia-Aruma unconformity can be picked on drill time by comparison with other wells in the field; and by inference from structural position.

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9-5/8” Casing Point Nominal casing point is 300’ into the Biyadh Formation (greenish-gray shale). In drilling to this point, circulation may be lost in the Shu’aiba (Dolomitic Limestone) or possibly in the Wasia section above. A mud cap must be kept in the hole to control the Wasia water, shales, and the gas zone. The Shu’aiba and Biyadh tops may be picked on drill time. The purpose of this casing is to shut off the lost circulation and the Wasia above, so that the remaining hole may be drilled with full circulation. The section to the top of the Arab zone may be drilled with water. The change to mud must be made above the Arab formation, as all of the zones may contain oil. 7” Casing Point This casing point is variable through the field, both in depth and casing size. In some cases it has been set in the Hith above the Arab zone to shut off lost circulation in the Yamama Detrital zone; in this case a liner was run and set either above or through the Arab D. In other cases, the casing has been set either at the top or base of the D member. The preferred completion, under present conditions, is to set through the D and then perforate for production in the C or D member, or both. Mud weight must be watched carefully to balance the Yamama Detrital without losing circulation either to it or the Arab zones. The purpose of the casing is to act as the production string, and to seal off the production zone or zones from the overlying water zones. A number of wells originally completed with a short liner across the Arab zones have been worked over to shut off casing leaks, etc. by running a full string from the top of the liner to the surface. Any new wells in the field should be completed with full strings rather than liners to avoid workovers. The Arab zones are distinctive on drill time and lithology and may be picked on either basis.

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2.8

Fadhili Field 26” Casing Point This is a surface conductor pipe and serves to case off unconsolidated sand. It is set in the first hard beds in the Neogene, commonly in marl. Nominal casing point is 100’± below surface. 18-5/8” Casing Point Nominal casing point 50’ above RUS. A 100’ thick section of chalky limestone 150’± below the top of Khobar extends to the top of RUS. Casing point in this section is adequate. The purpose of this string is to isolate the high salinity Khobar 15000 ppm) from the relatively fresh UER (2500 PPM) immediately below. Caution should be exercised not to penetrate the RUS formation before setting 18-5/8” casing. The drill time pattern shows an increase in drilling time in the Khobar as compared to the overlying Eocene. The casing point can be picked by comparison with nearby wells. 13-3/8” Casing Point Nominal casing point is 200’ above Lower Aruma shale. Probable safe range is from 300’ above to 100’ below the top of LAS which occurs in limestone. The purpose of the casing is to shut off the water flow or lost circulation of the Umm er Radhuma formation so that Wasia may be drilled with mud. The casing should be set low enough below any porosity so that a good cement job is obtained, and circulation will not be lost when drilling below the shoe. The top of Aruma can be picked on drill time by comparison with nearby wells. The casing point is 1100’± below the top of Aruma in limestone showing high drill time pattern. 9-5/8” Casing Point Nominal casing point is at the top of Mid Thamama limestone Earlier wells in the field have omitted this casing and a full string of 7” was run.

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The purpose of the casing is to shut off the lost circulation of Shu’aiba and to get all the Biyadh sand and shales behind the casing. This provides improved coring and drilling condition in the zones below. It is not possible to pick the top of Mid Thamama from drill time, however, a fairly good estimate can be made by comparison with nearby wells and projecting down from Shu’aiba and Biyadh. A section of shale about 40’ thick overlays the Shu’aiba (Dolomitic limestone). The contact of Wasia sands and the shale is distinct on drill time. The drilling time shows a marked increase at the contact. The Biyadh shows an erratic pattern but is usually about 150’ below Shu’aiba and can be picked by comparison with other wells. 7” Casing Point Nominal casing point is 80’ below the pre Hanifa unconformity (Tuwaiq mtn.) Upper Fadhili reservoir is about 110’ below the pre Hanifa unconformity and casing should be set before penetrating the Fadhili zone. The Fadhili field has two producing zones, the Arab-D and the Fadhili. The 7” liner is set between the two producing zones. The drill time pattern shows an increase below the pre-Hanifa unconformity. The overlying Hanifa and Arab zones are easily picked on drill time and samples and the casing point can be picked by comparison with other wells in the field.

2.9

Fazran Field 26” Casing Point This is a surface conductor pipe set at 100’± below the surface. It serves to keep the unconsolidated sand from washing out under the rig. 18-5/8” Casing Point Nominal casing point is 50’ into the RUS. Actual casing setting depths have varied.

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The purpose of the casing is to separate the lost circulation zone in the overlaying Khobar and case off the sloughing shales and marl of the RUS formation. The casing also separates the Umm er Radhuma from the overlaying aquifers. The RUS formation is not easy to pick on drill time. The drilling time increases at the top of Khobar and RUS and shows a low drilling time pattern in between. 13-3/8” Casing Point Nominal casing point is 50’ into the Lower Aruma shale. Probable safe range is from 50’ above to 100’ below the top of Lower Aruma shale. The purpose of the casing is to shut off the lost circulation of Umm er Radhuma from Wasia water flow and to allow mud drilling of Wasia. The casing point has to be picked from drill time as circulation is usually lost in Umm er Radhuma. The top of Lower Aruma shale occurs in limestone. The drilling time shows an increases at the top and gradually decreases. The Lower Aruma shale can be picked by comparison with other wells. 9-5/8” Casing Point The 9-5/8” casing is set in the Biyadh formation. Nominal casing point is 300’ below the top of Biyadh. The purpose of the casing is to shut off the lost circulation zone of the Shu’aiba or Wasia sands. It must also be set through the sloughing shales of Biyadh so that the formations below the casing may be drilled with water. The Biyadh shale is water sensitive, if exposed for more than a short period of time. If mud is conditioned with LCM prior to drilling is Shu’aiba lost circulation can be controlled to a large extent as has been exhibited on a few wells in the field and would reduce hole problems. The top of Sub’aiba and Biyadh is easily picked on drill time. The drilling time increases at the top of Shu’aiba as compared to the Wasia above. Drill time shows a gradual increase at the top of Biyadh.

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7” Casing Point Nominal casing point is at the base of D reservoir, or at the top of D reservoir if open hole option is used. The Arab zones in this field are very clear on drill time and can be picked easily by comparison with other wells in the field. The 7” is run as a liner.

2.10 Haradh Field 18-5/8” Casing Point Nominal casing point for the string is 50’ into the RUS formation. Setting depths have varied from above the RUS, in the Khobar, to below the top of the Umm er Radhuma. Many high structural wells were drilled without using this string. Since there is little water in the formations above the Umm er Radhuma, the casing is not needed there for hole support. However, the Neogene thickens rapidly going off structure, and becomes sandy. On flank wells or doubtful cases, the casing should be set in the RUS to prevent hole collapse when circulation is lost in the Umm er Radhuma. Static water level of the Umm er Radhuma is about 590’± mean sea level which brings it stratigraphically as high as the base of the Neogene on flank wells. Surface elevations range from 10001100’ in the area. 13-3/8” Casing Point Nominal setting point for this casing is 50’ into the Lower Aruma shale. On high structural wells this brings it somewhat below the Wasia-Aruma unconformity. The purpose of this casing is to shut off the lost circulation zone of the Umm er Radhuma so that the Wasia can be drilled with mud. This also separates the Wasia and Umm er Radhuma aquifers with their differing pressures. The casing point must be picked on drill time due to the lack of samples through the lost circulation zone above. The top of the Lower Aruma shale is not a distinctive pick on drill time.

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The drill time pattern shows a decrease in drilling time at the top of Lower Aruma shale. In crestal parts of the field it occurs about 200’ below a prominent increase in drill time and can be determined by comparison with nearby wells. On wells situated at the flank this section is less thick. 9-5/8” Casing Point The nominal casing point is 300’ into the Biyadh formation. Actual setting points have varied from more than 300’ below the top to below the top of the Mid-Thamama limestone. The purpose of the string is to separate the fresh (±1300 ppm total solids) waters of all the formations above the Biyadh top from the salty (21000 ppm total solids or more) waters of the Biyadh itself, and those below. It also shuts off the partial to complete lost circulation of the Shu’aiba or Wasia sand section and allows the next section of hole to be drilled with water. Those holes where no casing was set in the interval were mud drilled and had some difficulty with lost circulation. The drill time pick on the top of the Biyadh is not particularly distinctive. However, the top of the overlying Shu’aiba formation is easily picked at a distinct increase in drill time, and on samples by a change from sand to dolomite or dolomitic limestone. Thickness of this unit is relatively constant at about 200’, which enables the Biyadh top to be picked by drill time comparison with other wells. 7” Casing Point Nominal casing point is the top of the Arab-D member. Actual setting depths have varied with most in the range of 25-50’ above, in a dense anhydrite unit. The purpose of the string is to inject into, or produce the well, and separate the oil zone from the water bearing zones above. If desired, the casing may be run to TD through the Arab-D and perforated for production without encountering difficulty. In most parts of the field the top and base of Arab zones may be readily picked by either samples or drill time comparison with nearby wells.

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In the North Haradh area, some difficulty has been faced in picking Arab zones off drill time logs. This can be overcome if the top Sulaiy drill time break is used as a guide. The interval from the top of Sulaiy formation which is a very marked and easily recognized drill time break, to the base of C Reservoir (a fairly good pick) is fairly consistent at about 1450’. If the 7” casing is set 150’± below the base of C Reservoir, the sub C stringer (if present) should be behind the casing and shoe above the top of Arab-D reservoir. Present practice is to run a 7” liner rather than a full string and cement the liner before drilling out to total depth.

2.11 Harmaliyah Field 18-5/8” Casing Point Nominal setting point for this casing is anywhere from top of Khobar to top of RUS. The purpose of this casing is to shut off lost circulation above Khobar and to prevent hole collapse when circulation is lost in the Umm er Radhuma. The drill time pattern shows an increase at top of Khobar and decrease at top of RUS. 13-3/8” Casing Point Nominal setting point for this casing is 50’ into the Lower Aruma shale. The purpose of this casing is to shut off the lost circulation zone of the Umm er Radhuma so that the Wasia can be drilled with mud. This also separates the Wasia and Umm er Radhuma aquifers with their differing pressures. The casing point must be picked on drill time, due to the lack of samples through the lost circulation zone above. The top of the Lower Aruma shale is not a distinctive pick on drill time. The drill time pattern shows a decrease in drilling time at the top of Lower Aruma shale. In crestal parts of the field it occurs about 200’ below a prominent increase in drill time and can be determined by comparison with nearby wells. On wells situated at the flank this section is less thick.

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9-5/8” Casing Point Nominal casing point is 300’ into Biyadh. The purpose of the casing is to shut off the lost circulation of Shu’aiba or Wasia and to allow drilling below with water. The top of Shu’aiba can be picked on samples and drill time. The lithologic change is from sand above to dolomite below, and is accompanied by a marked increase in drill time. The top of Biyadh (greenish gray shale) is picked on drill time. It is less obvious than the Shu’aiba pick, but occurs about 300’ below the top of Shu’aiba and may be picked from drill time pattern comparison with other wells. 7” Casing Point Nominal casing point is the top of the Arab-D member. Actual setting depths have varied with most in the range of 25’–50’ above, in a dense anhydrite unit. The casing point is usually 150’± below the base of ‘C’ reservoir which puts it 10’± above the top of ‘D’ reservoir. The sub C stringer (if present) should be behind the casing and shoe above the top of Arab-D reservoir. The top and base of ‘D’ reservoir is easily picked on drill time. The other Arab members above are not very clear on drill time but can be picked from drill time pattern comparison with nearby wells. A fairly good estimate can be made if top of Sulaiy is used as a guide. Present practice is to run a 7’ liner rather than a full string and cement the liner before drilling out to total depth.

2.12 Hawiyah Field 26” Casing Point Nominal setting depth is 100’± below the surface. The purpose of the casing is to prevent unconsolidated sand from washing out under the rig. Use of this casing depends on surface conditions. 18-5/8” Casing Point Nominal setting point is 50’ into the RUS

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Neogene static water level is about +500’ mean sea level. Khobar and Umm er Radhuma are both about +555’ mean sea level, and water quality of all three is about 1200-1400 ppm total solids. No shut off is needed between them. 18-5/8” casing may be run if necessary to support the hole through the Neogene. Data from the few wells in the area indicates that the Neogene contains considerable running sand just above the Eocene/Neogene unconformity, so that casing should be run into the Eocene. Second unit below the unconformity is the RUS.. The top of the Eocene is easily picked at a marked increase in drilling time from the Neogene sands into the Khobar dolomite. Since circulation is lost near the top of the Neogene sandy section, no samples will be available. Drilling time increases at top of Khobar and decreases at top of RUS. Probable safe range is form top of Khobar to base of RUS. 13-3/8” Casing Point Nominal casing point is 50’ into the Ahmadi. The casing separates the Umm er Radhuma and Wasia aquifers and also the lost circulation zone in Umm er Radhuma or Mishrif. In the crestal part of the field no loss of circulation has occurred in the Mishrif but the section between Lower Aruma shale and Ahmadi is 100’±, therefore, it is a good practice to set casing in Ahmadi. Probable safe range for casing point on crestal wells is from the top of Lower Aruma shale to the Ahmadi. The wells situated on the flanks have had lost circulation in Mishrif and 50’ into Ahmadi is adequate for the casing point. The top of Lower Aruma shale may be picked on drill time. The drill time increases at or just above, the top and decreases gradually. The Praealveolina and Ahmadi are distinct on drill time. Three clear kicks are seen on drill time, the top of the second is Praealveolina dn. base of third is Ahmadi. 9-5/8” Casing Point Nominal casing point is 300’ into Biyadh. The purpose of the casing is to shut off the lost circulation of Shu’aiba or Wasia and to allow drilling below with water.

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The top of Shu’aiba can be picked on samples and drill time. The lithologic change is from sand above to dolomite below, and is accompanied by a marked increase in drill time. The top of Biyadh (greenish-gray shale) is picked on drill time. It is less obvious than the Shu’aiba pick, but occurs about 200-250’ below the top of Shu’aiba, and may be picked from drill time pattern comparison with other wells. Minimum safe depth for setting the 9-5/8” casing is 150’ into the Biyadh, as sloughing water sensitive shale is not a major problem in this area. 7” Casing Point Nominal casing point is at the top of the Arab-D reservoir at the base of porosity if set-through option is use. The casing point is usually 150’± below the base of C reservoir which puts it 10’± below the base of C reservoir which puts it 10’± above the top of D reservoir. The presence of sub C stringer in this area makes this point critical and care must be taken so that the sub C stringer should be behind the pipe. The top and base of D reservoir is easily picked on drill time. The other Arab members above are not very clear on drill time but can be picked from drill time pattern comparison with nearby wells. A fairly good estimate can be made if top of Sulaiy is used as a guide. The interval between top Sulaiy to base of C reservoir is about 1425’ thick on the crestal walls and about 1450’ thick at the flanks.

2.13 Khuff and Deep/Exploratory Wells (Casing sizes will be determined by the type of well drilled) Conductor This is set at 110’± below the surface. It serves to keep the unconsolidated sand from washing out under the rig. RUS Casing Point Nominal casing point for this string is 50’r into the RUS formation. Ahmadi Casing Point Nominal casing point is 50’r into the Ahmadi. The casing separates the Umm er Radhuma and Wasia aquifers and also the lost circulation zone in Umm er Radhuma or Mishrif.

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The top of Lower Aruma shale may be picked on drill time. The drill time increases at or just above, the top and decreases gradually. The Prealveolina and Ahmadi are distinct on drill time. Three clear kicks are seen on drill time, the top of the second is Prealveolina and base of third is Ahmadi. Arab-D Casing Point Nominal casing point is the top of the Arab-D member. Actual setting depths have varied with most in the range of 25-50’ above, in a dense anhydrite unit. In most parts of the field the top and base of Arab zones may be readily picked by either samples or drill time comparison with nearby wells. In the North Haradh area, some difficulty has been faced in picking Arab zones off drill time logs. This can be overcome if the top Sulaiy drill time break is used as a guide. The interval from the top of Sulaiy formation which is a very marked and easily recognized drill time break, to the base of C Reservoir (a fairly good pick) is fairly consistent at about 1450’. If the 7” casing is set 150’± below the base of C Reservoir, the sub C stringer (if present) should be behind the casing and shoe above the top of Arab-D reservoir. Note:

An alternate casing point is 100’ into the Hith may be selected if severe loss circulation in the Wasia/Shu’aiba persists.

Jilh Dolomite Casing Point Nominal casing point is 30’r below the base of the Jilh dolomite. This casing string isolates the major oil producing reservoir of the Arab-D in the Ghawar field and covers the probably lost circulation that may be encountered in the Arab-D, the Hanifa, and Hadriya formations. A10,000 psi WP BOP stack is nippled up after running this casing string. Khuff Casing Point If the lower Jilh is over pressured then the casing point is 15’r into the top of the Khuff formation, to isolate the high pressure. In normal cases, drilling would continue through the Khuff formation to a depth of at least 450’ below the base of the Khuff-D anhydrite. In certain wells targeted for the Pre-Khuff, this casing point is selected at +100’ above the pre-Khuff unconformity.

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Liner Point If the lower Jilh is over pressured then the liner point is 15’r into the top of the Khuff formation, to isolate the high pressure. Liner point is 450’r below the top of the Khuff D anhydrite or below the base of the pre-Khuff formation.

2.13 Khurais Field 18-5/8” or 20” Casing Point Nominal casing point is at top of Pre Neogene unconformity which is about 50’ below the surface. Its The purpose is to prevent the Neogene from sloughing after circulation is lost in the Umm er Radhuma. However, the Neogene at Khurais is composed of competent limestone beds which will stand by themselves, so use of the casing depends on surface conditions. The Alat and Khobar are missing at Khurais, and the Eocene-Neogene unconformity cuts into the Umm er Radhuma formation. Circulation is commonly lost at about 100’ below the surface, and not regained until casing is set in the Wasia sand. 13-3/8” Casing Point Nominal casing point is at the top of the Wasia-Aruma unconformity. Actual casing depths have varied from 746’ above to 459’ below the unconformity. The purpose of the casing is to shut off the lost circulation of the Umm er Radhuma formation and prevent the Wasia from charging the upper horizons. Circulation is frequently lost below the casing shoe in the Wasia. The Wasia is the main aquifer in the area; water quality is about 1200 ppm total solids. Static water level is about 930’ mean sea level, surface elevations are about 1400-1500’. In some cases, aerated mud has been used to maintain circulation. The unconformity may be picked on drill time. An increase of varying magnitude commonly occurs at, or just above, the unconformity. The lithology above the unconformity is limestone. Below it is a short section of shale or sandy shale and then the main Wasia sand is penetrated.

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Probable safe range for the setting depth is from 50’ above to 50’ below the Wasia Arum unconformity. 9-5/8” Casing Point Nominal casing point is 100’ into the Buwaib formation.

2.14 Khursaniyah Field 26” Casing Point Nominal casing point for this string is at the top of the Eocene. The purpose of the casing is to shut off the loose sand in the Neogene. The Neogene in Khursaniyah is exceptionally sandy, and can be very troublesome if not cased off. This sand may be particularly bad if circulation is lost in the Khobar, a not uncommon occurrence. Most recent wells have set this casing between 100’ and 200’ below the surface. 18-5/8” Casing Point Nominal casing point is 50’ into the RUS. Actual setting depths have ranged from 0 to 239’ below the top. The deeper points were actually set in the top of the Umm er Radhuma formation. The purpose of the casing is to separate the Alat and Khobar members from the water flow of the Umm er Radhuma. The Umm er Radhuma has a considerably higher pressure, and if not isolated, would flow into the upper zones. Top of the RUS is somewhat difficult to pick on drill time. Some wells show an increase, others a decrease, and still others have no character at all. However, by comparison with structurally similar wells, an approximate pick can be made. Lithologically, it is a dolomitic limestone quite similar to the overlying Khobar. Fortunately the safe setting range is fairly large, extending some 100’ into the top of the Umm er Radhuma, so an error of some magnitude may be made in picking the top without serious consequences.

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13-3/8” Casing Point Nominal setting point for this casing is 50’ into the Lower Aruma shale. Actual setting points have varied from 32’ above to 202’ below the top. The purpose of the casing is to shut off the water flow or lost circulation of the Umm er Radhuma and Aruma formations, and separate them from the high pressure water of the Wasia. It also allows the Wasia to be drilled with mud to control the shales and water flow. A small amount of 12° API oil is also present in the top of the Wasia. The top of the Lower Aruma Shale is not easy to pick on drill time. Lithologically, the unit is limestone similar to the overlying Aruma. Circulation may be lost in the Aruma, even though the Umm er Radhuma produces a water flow. Ditch samples caught from the water flow are generally poor. 9-5/8” Casing Point Nominal casing point is 400’ into the Biyadh formation. Actual casing points have varied. However, the minimum penetration which will allow drilling with water below the casing point is probably about 350’. The purpose of the casing is to shut off the lost circulation of the Shu’aiba and isolate the Wasia from the lower formations so that the next section of the hole can be drilled with water. Tops of the Shu’aiba and Biyadh can be picked on drill time from nearby wells. The lithological break is also distinctive from sand and shale to dolomite or dolomitic limestone at the Shu’aiba top, and then back into shale and sand at the top of the Biyadh. The upper shales of the Biyadh (greenish-gray) are very water sensitive, and must be cased off if the next section is to be water drilled. KW-6, with casing set 305’ into the Biyadh drilled out of the shoe with water and encountered such severe sloughing that the hole had to be abandoned. On wells which do not lose circulation in the Dolomitic, the string may be omitted, if drilling the next section of the hole with mud is acceptable. 7” Casing Point This casing point is variable depending on the desired completion. Nominal casing points have been either a few feet above the producing zone, or completely through the porosity into the dense limestone below, and selectively perforated.

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The tops and bases of the Arab zones may be picked easily from drill time or samples. If water is used to drill below the 9-5/8” casing point, a modest water flow will be encountered at the Sulaiy zone. The change to mud must be made in the upper portion of the Hith anhydrite, since this formation contains some calcarenite stringers which contain oil and gas.

2.15 Manifa Field 18-5/8” Casing Point Nominal casing point is 25’ into the pre-Neogene unconformity. The purpose of the casing is to shut off the considerable amounts of loose sand in the Neogene. Drill time at the unconformity is not diagnostic. The pick must be made on samples, at the change from sandy limestone or marl to non-sandy limestone or dolomite. If circulation is lost above the unconformity, then an approximation can be made on drill time. The Manifa field has both offshore and onshore wells. The casing string at the Pre-Neogene unconformity has been successfully omitted in four recent wells (two onshore and two offshore). These wells all had shallow conductors set. For onshore wells the 18-5/8” string set 25’ into the PreNeogene at 200-300’ will serve as a conductor. For offshore wells, where a large conductor is installed, the 18-5/8” casing can be omitted. Water data for the Neogene, Alat and Khobar are scarce, but indications are that all are non-potable so that no shut off is necessary between them. 13-3/8” Casing Point The purpose of the casing is to separate the highly saline sulfurous water flow of the Umm er Radhuma from the upper formations. The casing point is non-critical, any depth into the RUS is sufficient to assure a good cement job since circulation is not normally lost in either the Alat or Khobar. Thus, the range of safe setting points would be from the top to the base of the RUS, an interval of 300-400'.

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The drill time pattern is not distinctive, but the top may be picked by comparison with other wells in the field. On lithology, it occurs below the light blue gray marl and clays of the Alveolina zone. Anhydrite and gypsum are encountered at, or just below the top of the RUS, making the determination positive. Minor traces of oil have been noted in the overlying Khobar member. 9-5/8” Casing Point Nominal setting point for this casing is 50’ into the Lower Aruma shale. The purpose of the casing is to shut off the water flow of the Umm er Radhuma formation, so that the Wasia section can be drilled with mud to control the shales and water flow. The top of the Lower Aruma shale may be picked on drill time by comparison with other wells in the field, or on a lithologic change from an off-white limestone or dolomitic limestone to underlying light green or light gray calcareous shale. 7” Casing Point This is the production string. Setting depth varies according to the desired completion. Immediately above the Manifa zone, is approximately 250’ of dense limestone, while below is the anhydrite and limestone or calcarenite stringers of the Hith. Either makes a suitable casing seat, assuring isolation of the zone. The Wasia sands, productive in Safaniya, contain salt water at Manifa. This will flow to the surface, so that mud must be used to control it and the water sensitive Wasia shales as well. Circulation is normally maintained through this interval, including the Shu’aiba so that no casing is needed in the Biyadh. In those instances when circulation has been lost in the Wasia, it has been regained with lost circulation material and/or cement. The mud drilled interval from the 9-5/8” casing point to below the Manifa zone is about 4000’.

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2.16 Marjan Field Conductor Pipe – 30” This is a conductor pile driven into the sea floor when the platform is set, prior to moving the rig on location. It is driven to refusal, but not cemented. The purpose of the conductor is to return drilling fluids to the surface while drilling to the first casing point at the top of the Eocene. 13-3/8” Casing Point This is set at the top of the Pre-Neogene unconformity to shut off unconsolidated sands in the Neogene. Nominal setting depth is 50’ into the Pre-Neogene unconformity. It is cemented to surface. In instances where cement is not circulated, a surface bridge is established. The top of the Pre-Neogene unconformity is picked on samples and drill time. The change of lithology is from sand and marl, or sandy limestone of the Neogene, to a non-sandy limestone of the Eocene. There is usually, but not always, a distinct increase in drill time for a short interval at the change in lithology. This may be determined by comparison with nearby wells. 9-5/8” Casing Point The nominal setting point is 50-100’ into the Lower Aruma shale. Recent practice has been to set about 50’ below the Lower Aruma shale top. The interval between the 13-3/8” casing point and the 9-5/8” is composed of the RUS, the very porous limestones of the Umm er Radhuma formation, and the somewhat porous limestones of the Aruma formation. The section is drilled with water due to the large water flow encountered in the Umm er Radhuma. The purpose of the casing is to shut off this water flow and any lost circulation zones below it, so that mud, with full circulation, may be used to drill into the oil zones (Wasia formation). The casing point must be picked deep enough into the Aruma so that there is no chance of a water flow or lost circulation below the shoe.

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Thickness of the Lower Aruma shale is extremely variable. However, a relatively consistent increase in drilling time occurs in the lower portion of the Aruma formation. This represents a change to a more dense limestone, and casing may safely be set any time after penetrating about 100’ of this lithology. The increase in drilling time is a sufficient indicator of this point. Ditch samples are badly contaminated due to the water flow. The casing is usually cemented in two stages, using a DV packer collar inside 13-3/8” casing. 7” Casing Point Setting point of this casing varies according to the type of completion desired. It is set through the producing zone, and then perforated for production. Normal completions are either in the Safaniya or Khafji members, with lowest perforations about 100’ above the oil-water contact. The section below the 9-5/8” casing point consists mainly of the sandstones, shales, and then limestones of the Wasia formation. The section down to the top of the Caprock limestone may be drilled with water, but the drilling fluid should be changed to mud before drilling the Caprock and the producing zones below. Low water loss, fresh water mud is used to minimize formation damage and provide proper logging environment.

2.17 Mazalij Field 18-5/8” or 20” Casing Point Nominal casing point is at top of Pre Neogene unconformity which is about 50’ below the surface. Its The purpose is to prevent the Neogene from sloughing after circulation is lost in the Umm er Radhuma. However, the Neogene at Mazalij is composed of competent limestone beds which will stand by themselves, so use of the casing depends on surface conditions. The Alat and Khobar are missing at Mazalij and the Eocene-Neogene unconformity cuts into the Umm or Radhuma formation. Circulation is commonly lost at about 100’ below the surface, and not regained until casing is set in the Wasia sand.

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13-3/8” Casing Point Nominal casing point is the Wasia-Aruma unconformity. Actual casing depths can vary from 100’ above to 200’ below the unconformity. The purpose of the casing is to shut off the lost Radhuma formation and to prevent the Wasia horizons. Circulation is frequently lost below the The Wasia is the main aquifer in the area; water total solids. Static water level is about 1100’ elevations are about 1350-1550’.

circulation of the Umm er from charging the upper casing shoe in the Wasia. quality is about 1300 ppm mean sea level, surface

The unconformity may be picked on drill time. An increase of varying magnitude commonly occurs at, or just above, the unconformity. The lithology above the unconformity is limestone. Below it is a short section of shale or sandy shale and then the main Wasia sand is penetrated. 9-5/8’ Casing Point Nominal casing point is 100’ into the Buwaib formation. The purpose of the casing is to shut off the lost circulation zones of the Wasia, Shu’aiba and Biyadh formations. All are potential sources of trouble. Once this string is set, the remaining hole, to the top of the D member, may be water drilled. Top of the Buwaib may be easily picked either on samples or drill time. The lithologist change is from a long continuous sand section (Biyadh formation) to the compact limestones of the Buwaib. It is accompanied by a definite increase in drilling time. Main concern in setting the casing is to obtain a good cement job, so probable minimum penetration for this would be about 100’ below the top. 7” Casing Point Nominal casing point is below the base of the Arab-D Reservoir The purpose of the casing is to act as the production string. A full string has been set in all wells. Top of the D or base of the C are distinctive picks on either lithology or drill time, and may be easily picked by comparison with other wells in the field.

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2.18 Qatif Field 26” Casing Point Nominal casing point is 100± below the surface. The purpose of the casing is to case off the unconsolidated sand and prevent washing out under the rig. 18-5/8” Casing Point Nominal casing point is 25’ into the Alat. In some cases, this string has been 26”. The purpose of the casing is to separate the water zone of the Neogene from those of the Alat and Khobar. Without a shut off at this point, the Alat and Khobar waters tend to flow up and recharge the Neogene, causing flooding in some areas. This shut off is critical in this area due to the widespread habitation of the oasis. Without this shut off, water is wasted from the Alat and Khobar aquifers, and the reservoirs which are used locally for water supply are unnecessarily depleted. The top of the Alat, which is just below the pre-Neogene unconformity, is picked on sample evidence, where the lithology changes from sandy to nonsandy limestone. It is also characterized by an increase in drilling time, and may be picked on this basis by comparison with nearby wells. 13-3/8” Casing Point Nominal casing point is 50’ below the top of the RUS formation. Actual setting points have varied from 100’ above to 57’ below the top, with most in the range of 25’ above to 50’ below. The purpose of the casing is to isolate the potable water of the Alat and Khobar aquifers (2,000 ± ppm total solids) from the underlying non-potable (50,000 ± ppm total solids) Umm er Radhuma. This shut off is important to prevent contamination of the Alat and Khobar, which are the aquifers used by the local population for water supply. If it were possible to assure a good shut off of the aquifers by cementing, the 18-5/8” string above could be eliminated. However, circulation is normally lost in the Alat or Khobar, so that a continuous cement job across all zones is not readily obtainable.

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The top of the RUS must usually be picked on drill time since samples are not normally available due to the lost circulation. Drill time increases through the marls and clays of the Alveolina zone just above the RUS, and then decreases when the limestone of the RUS is penetrated. Casing set in the Alveolina zone is deep enough, although the cement job may be questionable if the base of the Khobar is porous. All these acquifers are probably in communication to some extent in some of the older wells. The RUS is all limestone in Qatif, no anhydrite. 9-5/8” Casing Point The nominal casing point is 25’ in the Pre-Aruma unconformity. The purpose of this casing is to shut off the lost circulation (or water flow, depending on surface elevation of the location) of the Umm er Radhuma from the underlying Wasia formation and permit drilling the Wasia with mud to control the sloughing shales and the Wasia water flow. The Pre-Aruma unconformity must be picked on drill time. It is picked at a decrease in drill time following a general increase over 50’± just above. Relative magnitude of this pattern varies, but the overall pattern is recognizable throughout the field. The point may be identified from comparison with nearby wells. The upper part of the Wasia is a thick section of water sensitive shale and the lower section is sand with water. Mud must be used to protect the shales and also to keep the water from flowing to the surface. 7” Casing Point (South Qatif) Nominal point is 300’ in the Biyadh. Probable minimum penetration is 250’ below the top of Biyadh. The purpose of the casing is to shut off the lost circulation of the Shu’aiba. It must be set far enough into the greenish-gray shale of Biyadh to case off the water sensitive portion, so that the section below may be drilled with water. In the event that circulation is maintained through the Shu’aiba, as is the case in North Qatif, the casing may be omitted if it is acceptable to drill the remaining hole with mud.

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The advantage is that a 7” completion results rather than a 4½”, with consequently greater well potential. The same thing may be accomplished by starting with one size larger casing at the top of the hold. This means drilling longer stretches of large hole. The drill time shows a distinct increase at the top of the Shu’aiba and just above or the top of the Biyadh. 4½” Casing Point (South Qatif) Nominal setting point for the string is the top of the D reservoir. Actual setting depths have ranged from 36’ above to 227’ below the top, with the more recent wells having the deeper settings. These were set through the zone. The deeper Fadhili zone is also productive in Qatif. The 4½” may be set through this zone and selectively perforated. The purpose of the casing is to produce the well and shut off the water zones above the oil. All four Arab zone reservoirs contain oil in Qatif, and many of the wells produce from both the C and D reservoirs, separated by down hole packers. Present practice is to use a liner rather than a full string, and to bring the top of the liner above the shoe of the string set in the Biyadh formation. The Arab and Fadhili zones have characteristic drill time curves and lithology, so that the casing point may be easily picked by either of these means. 7” Casing Point (North Qatif) In North Qatif circulation is usually maintained through the Shu’aiba formation and the casing in Biyadh formation is omitted. The 7” casing is set a few feet above the producing zone or completely through the porosity. Current practice is to set through the producing zone and perforate selectively. The tops and bases of Arab zones and Fadhili reservoir may be picked from drill time or samples.

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2.19 Qirdi Field 18-5/8” or 20” Casing Point Nominal casing point is at top of Pre Neogene unconformity which is about 30’ below the surface. Its The purpose is to prevent the Neogene from sloughing after circulation is lost in the Umm er Radhuma. However, the Neogene is composed of competent limestone beds which will stand by themselves, so use of the casing depends on surface conditions. The Alat and Khobar are missing at Qirdi, and the Eocene-Neogene unconformity cuts into the Umm er Radhuma formation. Circulation is commonly lost at about 100’ below the surface, and not regained until casing is set in the Wasia sand. 13-3/8” Casing Point Nominal casing point is the Wasia-Aruma unconformity. Casing setting depths can vary from 100’ above to 200’ below the unconformity. The purpose of the casing is to shut off the lost circulation of the Umm er Rahuma formation and prevent the Wasia from charging the upper horizons. Circulation is frequently lost below the casing shoe in the Wasia. The Wasia is the main aquifer in the area; water quality is about 1000 ppm total solids. Static water level is about 900’ mean sea level, surface elevations are about 1400-1500’. The unconformity may be picked on drill time. An increase of varying magnitude commonly occurs at, or just above, the unconformity. The lithology above the unconformity is limestone. Below it is a short section of shale or sandy shale and then the main Wasia sand is penetrated. 9-5/8” Casing Point Nominal casing point is 100’ into the Buwaib formation. The purpose of the casing is to shut off the lost circulation zones of the Wasia, Shu’aiba and Biyadh formations. All are potential sources of trouble. Once this string is set, the remaining hole, to the top of the D member, may be water drilled.

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Top of the Buwaib may be easily picked either on samples or drill time. The lithologic change is from a long continuos sand section (Biyadh formation) to the compact limestones of the Buwaib. It is accompanied by a definite increase in drilling time. Main concern in setting the casing is to obtain a good cement job, so probable minimum penetration for this would be about 100’ below the top. 7” Casing Point Nominal casing point is below the base of the D reservoir. The purpose of the casing is to act as the production string. Top of the D or base of the C are distinctive picks on either lithology or drill time, and may be easily picked by comparison with other wells in the field.

2.20 Rimthan Field 26” Casing Point Nominal setting depth is 100± below the surface. The purpose of the casings is to case off unconsolidated sand from washing out under the rig. Use of this casing depends on surface conditions. 13-3/8” Casing Point Nominal casing point is 50’ below the top of the RUS formation. The purpose of this string is to separate the incompetent sand and shale to the pre-Neogene unconformity and to support the hole after circulation is lost and separate the Umm er Radhuma from the Neogene and Dammam formation. The top of the RUS must usually be picked on drill time since samples are not normally available, due to the lost circulation. Drill time increases just about the RUS and then decreases when the limestone of the RUS is penetrated. The lower part of the RUS is anhydrite which is below the limestone.

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9-5/8” Casing Point Nominal casing point is 1500’ into the Aruma (i.e. 100’ into the Mid-Aruma shale). The purpose of this casing is to shut off lost circulation of the Umm er Radhuma formation, and to permit drilling the lower section with mud to control the sloughing shale of the Aruma. The Aruma is picked on drill time as a decrease in the drilling time and as lithology changes from limestone to shale. 7” Casing Point Nominal casing point is at total depth, which is 60’ below base of Arab-D reservoir. The purpose of this string is to produce from the zone of interest through perforation. Present practice is to run a full string of 7”. The tops and bases of Arab zones are readily picked on drill time.

2.21 Safaniyah Field Conductor Pipe 30” This is a conductor pile driven into the sea floor when the platform is set, prior to moving the rig on location. It is driven to refusal but not cemented. The purpose of the conductor is to return drilling fluids to the surface while drilling to the first casing point. 18-5/8” Casing Point This is set at the top of the Pre Neogene unconformity to shut off unconsolidated sands in the Neogene. Nominal setting depth is 25’ into the Pre Neogene unconformity. It is cemented to the surface. In instances where cement is not circulated, a surface bridge is established.

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It is not necessary from a geological or engineering standpoint except in North Safaniya wells, where oil and gas occur in the RUS. Wells in Central Safaniya have been drilled successfully without setting this string of casing. In North Safaniya, oil and gas occur in the RUS formation on top of the structure. Here, the casing must be set so that blowout equipment can be installed, and mud can be used to drill the oil and gas bearing zones. Heavy oil is also known in the Alat and Khobar (SW-37). The top of the Pre Neogene unconformity is picked on samples and drill time. The change in lithology is from sand and marl, or sandy limestones of the Neogene, to non-sandy limestone of the Eocene. There is usually, but not always, a distinct increase in drill time for a short interval at the change in lithology. This may be determined by comparison with nearby wells. 13-3/8” Casing Point This string of casing is set in the RUS formation at one of two nominal points, depending on location of the well. In North Safaniya, the nominal point is the top of the UER to shut off the oil and gas zones encountered in that area. See well records for SW-43 for a discussion of the gas and oil occurrences. In the other areas of Safaniya, nominal casing point is 25’ into the RUS. The section between the 18-5/8” and 13-3/8” casing point consists of the Alat limestones and marls. Khobar dolomite, limestone and marl, the thin limestones and marls of the Alveolina zone, and the anhydrite and thin limestones of the RUS formation. Circulation may be lost in the Khobar. The top of the RUS may be picked either on samples or drill time. The lithology changes abruptly from the blue-gray marl containing Alveolina, to calcarenitic limestone and then to anhydrite or gypsum. The top is picked at the top of the calcarenitic limestone. This is commonly porous and contains a showing of heavy oil. On drill time, the bit tends to ball up through the Alveolina zone, giving an increase in drilling time. The first few feet of the RUS usually drill faster, then the drill time may increase again as the gypsum and anhydrite are penetrated. This pattern varies somewhat from well to well, and nearby wells should be checked carefully when picking this point. Circulation is usually maintained to this casing point so samples are available.

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The casing is usually cemented in two stages, using a DV packer collar inside the 18-5/8” casing. If 18-5/8” is not run, the 13-3/8” is cemented in a single stage and a surface bridge is established if cement is not circulated. 9-5/8” Casing Point The nominal setting point is 50-100’ into the Lower Aruma shale. Actual setting points have varied from 227’ above to 257’ below the top of the Lower Aruma shale. Recent practice has been to set about 50’ below the Lower Aruma shale top. The interval between the 13-3/8” casing point and the 9-5/8” is composed of the lower part of the RUS, the very porous limestones of the Umm er Radhuma formation, and the somewhat porous limestones of the Aruma formation. The section is drilled with water due to the large water flow encountered in the Umm er Radhuma. The purpose of the casing is to shut off this water flow and any lost circulation zones below it, so that mud, with full circulation, may be used to drill into the oil zones (Wasia formation). The casing point must be picked deep enough into the Aruma so that there is no chance of a water flow or lost circulation below the shoe. Thickness of the Lower Aruma shale is extremely variable, due to the effect of the underlying Wasia-Aruma unconformity. However, a relatively consistent increase in drilling time occurs in the lower portion of the Aruma formation. This represents a change to a more dense limestone, and casing may safely be set any time after penetrating about 100’ of this lithology. The increase in drilling time is a sufficient indicator of this point. Ditch samples are badly contaminated due to the water flow. The casing is usually cemented in two stages, using a DV packer collar inside 13-3/8” casing. 7” Casing Point Setting point of this casing varies according to the type of completion desired. It is set through the producing zone, and then perforated for production. Normal completions are either in the Safaniya or Khafji members, with lowest perforations about 100’ above the oil-water contact.

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The section below the 9-5/8” casing point consists mainly of the sandstones, shales, and then limestones of the Wasia formation. The section down to the top of the Caprock limestone may be drilled with water, but the drilling fluid should be changed to mud before drilling the Caprock and the producing zones below. Low water loss, fresh water mud is used to minimize formation damage and provide proper logging environment.

2.22 Shaybah Field 18-5/8” Casing Point Nominal setting point for this surface conductor is 150’± below the surface. The purpose of this conductor is to keep the unconsolidated surface sand from washing out under the rig. 13-3/8” Casing Point Nominal casing point is 50’ into the RUS. The purpose of this casing is to isolate the Sabkah water just beneath the surface from the RUS and Umm Er Radhuma, which have possible water flow or loss of circulation. The UER water in this area flows to surface and is used for water supply. This casing point allows water to be used to drill the remaining RUS and UER. The kick-off point for horizontal wells is typically just below this casing point in the RUS formation. 9-5/8” Casing Point Nominal casing point is 180’ TVD into Aruma Carbonate. The purpose of this casing is to shut off lost circulation zone or water flow of the Umm er Radhuma from the underlying Wasia formation and permit drilling with oil base mud. The Aruma can be picked at an increase in drill time following a general decrease over 150’ just above. This can be identified from comparison with nearby wells. Oil base mud must be used to protect the exposed shales and to control the Shu’aiba reservoir where this producing zone is overlain with gas in the crestal area.

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SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 2 SECTION

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DRILLING MANUAL JUNE 2006

DRILLING PRACTICES CASING

__________________________________________________________________________________________________________________________

7” Casing Point Nominal casing point for a horizontal producer is the start of the horizontal section in the Shu’aiba reservoir. Total Depth Total depth is determined by the required lateral length and/or the base of the Shu’aiba reservoir. Horizontal wells are typically completed as open hole producers, with a production packer located in the 7” casing.

2.23 Shedgum Field 18-5/8” Casing In the Shedgum area, the Neogene, Alat, Khobar, RUS, Umm er Radhuma, and Aruma have nearly the same water quality and static water levels, so do not need to be separated by casing. In fact, some recharge of the Alat and Khobar may be taking place by having the zones in communication. The formations above the Umm er Radhuma are reasonably competent so that no casing is needed to support them after circulation is lost in the Umm er Radhuma. Some of the Umm er Radhuma is about 475’ above mean seal level, which is below the ground level throughout most of the Shedgum area. The only casing needed above the Lower Aruma casing point is the short surface conductor. This is commonly 18-5/8” casing and is set only in those wells where it is needed to support loose sand at the surface. 13-3/8” Casing Point This casing is normally set in the Lower Aruma shale or Ahmadi limestone. Its The purpose is to isolate the overlying lost circulation and water zones and permit drilling the underlying Wasia formation with mud and full circulation. It also prevents contamination of the Umm er Radhuma aquifer which supplies Abqaiq with raw water. Nominal casing point is 50’ into the Lower Aruma shale or Ahmadi limestone. The object is to pick a casing point which is below any possible water flow or lost circulation zone in the Aruma formation, so that circulation may be maintained while drilling the Wasia formation with mud. There must also be sufficient non-porous rock about the casing point to assure a good cement job around the casing.

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SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 2 SECTION

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DRILLING MANUAL JUNE 2006

DRILLING PRACTICES CASING

__________________________________________________________________________________________________________________________

Some wells on the South West and East flanks had lost circulation after setting the 13-3/8” casing in the Lower Aruma shale. In such areas it is advisable to set the 13-3/8” casing in Ahmadi. The top of Lower Aruma shale and Ahmadi are readily picked by comparison of drill time pattern with nearby wells. The drilling time decreases at Lower Aruma shale and Ahmadi. 9-5/8” Casing Point The section between 13-3/8” casing point and the 9-5/8” casing point consists of the remaining portion of the Lower Aruma shale, the hydroscopic shales and water sands of the Wasia formation, the Shu’aiba formation (Dolomitic limestone) and the upper portion of the Biyadh formation (greenish-gray shale). The Wasia shales are very water sensitive and a low water loss mud must be used to keep sloughing to a minimum. Even when the water loss is kept at 3cc or below, some sloughing is encountered. This tends to become worse as time goes on, so it is best to drill this section as rapidly as possible. Mud weight must also be great enough to prevent the water in the Wasia sands from flowing up the hole and contacting the shales. Static water level is 864’ mean sea level. Circulation is commonly lost in the Shu’aiba formation and drilling proceeds to the 9-5/8” casing point with water and a mud cap. The mud cap is held against the Wasia formation, and must be low water loss mud to control sloughing, as noted above. The Shu’aiba formation is very porous and even cavernous, so that attempts to regain circulation are expensive and usually futile. The nominal casing point is 300’ into the Biyadh. The purpose of this point is to assure that all the hydroscopic shales of the Biyadh will be behind casing, so that the next portion of the hole may be drilled with water. The casing also shuts off the lost circulation zone of the Shu’aiba, so that circulation may be maintained. Actual setting depths have varied from 137’ to 671’ below the top of the Biyadh with most wells in the 250-350’ range. Probable absolute minimum penetration of the greenish-gray shale which will allow water drilling is 200’. Nominal casing point should remain at 300’ penetration.

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SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 2 SECTION

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DRILLING MANUAL JUNE 2006

DRILLING PRACTICES CASING

__________________________________________________________________________________________________________________________

Key horizons for this casing point are the tops of the Shu’aiba and the Biyadh. Either may be picked on samples or drill time. The top of the Shu’aiba is represented by an abrupt change from sand to Dolomite. An accompanying increase in drilling time occurs about 30-50’ above the top. The Shu’aiba is 275-300’ thick in Shedgum. If circulation is maintained, the top of the Biyadh may be picked on the occurrence of shale. If circulation is lost, a general increase in drill time serves to locate the point. 7” Casing Point The 7” casing is the production string. It may be set at the top of the producing zone, or set through and perforated. The practice of setting on top of the zone and then drilling out and completing barefoot has been the most common. However, some difficulty has been experienced by setting too high and not getting a shut off of the sub C stringer, which contains salt water. The most foolproof completion is to drill through the producing zone, set casing through it, and then perforate. The section between the 9-5/8” casing point and the producing zone consists of the major portion of the Biyadh formation, the limestones of the Thamama group, including the Sulaiy zone, the High formation anhydrite and limestone, and the Arab-A, B and C zones. The section is commonly drilled with water to the top of the Arab-D zone. Minor amounts of shale sloughing from the Biyadh interval are common, and a water flow is encountered in the Sulaiy zone up to 5-6 MBPD. The change to mud is made while drilling the anhydrite above the top of the Arab-D reservoir. Reservoir pressure has been lowered due to withdrawals from the field, so lost circulation is possible. The key horizons for this casing point are the base of the Arab-C reservoir and the top of the Arab-D. The base of the C may be picked on a change from calcarenite to anhydrite, with an accompanying increase in drilling time. Top of the D reservoir is about 100’ below this point, and occurs at the change from anhydrite back to calcarenite with a decrease in drilling time. Care must be taken not to confuse one of the porous water bearing stringers immediately above the D reservoir with the top of the D reservoir itself, as noted above. Present completion practice is set to the 7” liner at the top of D reservoir prior to drilling out to the base of porosity.

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SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 2 SECTION

B

DRILLING MANUAL JUNE 2006

DRILLING PRACTICES CASING

__________________________________________________________________________________________________________________________

2.24 Uthmaniyah Field 26” Casing Point Nominal setting depth is 100’± below the surface. The purpose of the casing is to prevent unconsolidated sand from washing out under the rig. Use of this casing depends on surface conditions. 18-5/8” Casing Point This casing has been set in the top of the Eocene to separate the Neogene water (± 1500 ppm) and the Eogene water (± 1300 ppm) and to support the Neogene in those areas where it may be unconsolidated. Nominal setting depth is 50’ below the Eocene/Neogene unconformity; probable safe range is from Eocene-Neogene unconformity to the base of RUS. Since the waters of the Neogene, Alat, Khobar and Umm er Radhuma are similar, about 1300-1500 ppm total solids, and the formation pressures about the same; the casing is not needed for water separation. In fact, a slight recharge of the upper formations by the Umm er Radhuma will result if a separation is not accomplished. Therefore, in areas where the Neogene is competent, the string may be left out. This will be true in most cases in Uthmaniyah. Circulation may be lost in any of the formations down to below the pre-Aruma Unc, so setting the casing to regain circulation is futile. 13-3/8” Casing Point Nominal casing point for this string is 50’ into the Lower Aruma shale or Ahmadi limestone. Many wells on the flanks of the field lost circulation below the Pre-Aruma unconformity after drilling out of the 13-3/8” casing set in Lower Aruma shale. It is advisable to set 13-3/8” casing in the Ahmadi on wells located at the flanks. The purpose of the casing is to shut off all possible lost circulation zones or water flow, so that Wasia may be drilled with mud. The casing also serves to separate the flow of Wasia from the upper formations. A characteristic increase in drilling time occurs some 100-200’ above the top of Lower Aruma shale and may represent the minimum safe casing point. The top is usually indicated by a subsequent decrease in drill time, commonly followed by an increase. The pattern is reasonably consistent from well to well, so that it is not a difficult pick to make.

46 of 52

SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 2 SECTION

B

DRILLING MANUAL JUNE 2006

DRILLING PRACTICES CASING

__________________________________________________________________________________________________________________________

The top of Ahmadi limestone is also readily picked from drill time comparison. 9-5/8” Casing Point Nominal setting point for this casing is 300’ into the Biyadh formation (greenish-gray shale). Actual setting points have varied. The purpose of the string is to shut off the lost circulation of the Shu’aiba formation (Dolomitic Limestone). The casing also protects the hydroscopic shales in the upper portion of the Biyadh formation and must be set through these in order to drill with water below the casing point. Probable minimum penetration which will allow water drilling below is about 200’. However, since some difficulty is often encountered in washing casing to bottom, a minimum of 300’ penetration should be specified. The top of the Shu’aiba formation may be picked either on samples or drill time. The lithologic change is from sand to dolomite, and circulation is usually lost below the top. The top of the Biyadh occurs about 200-250’ below, and is less easily picked. Drill time pattern is irregular, but the pick can be made by comparison with nearby wells. The section down to the top of the producing zone (Arab-D) may be drilled with water. The change to mud may be made while drilling the anhydrite unit below the base of the C reservoir. 7” Casing Point Nominal casing point is the top of the Arab-D reservoir. The purpose of the casing is to case off all water zones above the producing zone and to get the overlying sub ‘C’ stringer behind pipe. Present practice is to run a liner rather than a full string. The casing is set prior to drilling into the ‘D’ reservoir. The presence of salt water in the sub ’C’ stringer which is 20-40’ above the Arab-D reservoir makes the casing point pick critical. The tops and bases of Arab zones are readily picked on drill time by comparison with nearby wells.

47 of 52

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

B

JUNE 2006

DRILLING PRACTICES CASING

__________________________________________________________________________________________________________________________

2.25 Zuluf Field 30” Conductor Pipe This is a conductor pile driven into the sea floor when the platform is set, prior to moving the rig on location. It is driven to refusal, but not cemented. The purpose of the conductor is to return drilling fluids to the surface while drilling to the first casing point at the top of the Eocene. 13-3/8” Casing Point Nominal setting depth is 25’ into the RUS formation. This section consists of the Alat limestones and marls. Khobar dolomite, limestone, and marl, the thin limestones and marls of the Alveolina zone, and the anhydrite and thin limestones of the RUS formation. Circulation may be lost in the Khobar. The top of the RUS may be picked either on samples or drill time. The lithology changes abruptly from the blue gray marl containing Alveolina, to calcarenitic limestone and then to anhydrite or gypsum. The top is picked at the top of the calcarenitic limestone. On drill time, the bit tends to ball up through the Alveolina zone, giving an increase in drilling time. The first few feet of the RUS usually drill faster, then the drill time may increase again as the gypsum and anhydrite are penetrated. This pattern varies somewhat from well to well, and nearby wells should be checked carefully when picking this point. Circulation is usually maintained to this casing point so samples are available. 9-5/8” Casing Point The nominal setting point is 50-100’ into the Lower Aruma shale. The interval between 13-3/8” casing point and the 9-5/8” is composed of the lower part of the RUS, the very porous limestones of the Umm er Radhuma formation, and the somewhat porous limestones of the Arum formation. The section is drilled with water due to the large water flow encountered in the Umm er Radhuma.

48 of 52

SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 2 SECTION

B

DRILLING MANUAL JUNE 2006

DRILLING PRACTICES CASING

__________________________________________________________________________________________________________________________

The purpose of the casing is to shut off this water flow and any lost circulation zones below it, so that mud, with full circulation, may be used to drill into the oil zones (Wasia formation). The casing point must be picked deep enough into the Aruma so that there is no chance of a water flow or lost circulation below the shoe. Thickness of the Lower Aruma shale is extremely variable due to the effect of the underlying Wasia-Aruma unconformity. However a relatively consistent increase in drilling time occurs in the lower portion of the Aruma formation. This represents a change to a more dense limestone, and casing may safely be set any time after penetrating about 100’ of this lithology. The increase in drilling time is a sufficient indicator of this point. Ditch samples are badly contaminated due to the water flow. This casing is cemented in two stages using a DV packer collar inside the 133/8” casing. 7” Casing Point Setting point of this casing varies according to the type of completion desired. It is set through the producing zone, and then perforated for production. Normal completions are in the Khafji member, with lowest perforations about 100’ above the oil-water contact. The section below the 9-5/8” casing point consists mainly of the sandstones, shales, and then limestones of the Wasia formation. The section down to the top of the Caprock limestone may be drilled with water, but the drilling fluid should be changed to mud before drilling the Caprock and the producing zones below. Low water loss, fresh water mud is used to minimize formation damage and provide proper logging environment.

3.0

CASING INSPECTION 3.1

Khuff, Deep & Exploration Wells

The 36”, 30” and 24” casing will be externally coated with FBE (fusion bonded epoxy). The 18-5/8” casing will be externally coated FBE from the shoe to the DV. The 13-3/8” casing will be externally coated FBE from 8500’ to the upper DV.

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

JUNE 2006

DRILLING PRACTICES

B

CASING

__________________________________________________________________________________________________________________________

The rig crew should inspect all casing and tubing after shipment as follows: x

Clean and visually inspect all threads. Use casing dope for thread compound. x Run API full length drift. x Visually inspect for overall damage. The contracted inspection company (PWS, Vetco or other) should inspect all casing and tubing (13-3/8” and smaller) before shipment to the rig as follows: x x x

Clean and inspect all threads. Visually inspect for overall damage. Electromagnetic inspection (4 functions); Longitudinal, Traverse, Wall Thickness, Grade Verification

3.2 Development Wells Prior to running the 13-3/8” casing and subsequent strings, insure that the following has been conducted. x x x x

NOTE:

[1] [2]

NOTE:

Run full-length API drift. Clean and visually inspect threads. Visually inspect tubes for damage. Use casing dope for thread compound.

TABLE 4.0

SAUDI ARAMCO CASING DATA

Internal yield values (*) listed on page 51 reflect the lower value for buttress couplings. Value provided is the minimum value, either pipe body strength or joint strength.

TABLE 5.0

KHUFF CASING & TUBING DATA

[1] [2] [3]

Internal yield values (*) listed on page 52 reflect the lower value for buttress couplings. Value provided is the minimum value, either pipe body strength or joint strength. The RL-4S connector ID is less than that of the LS connector.

[4]

The Hydril PH-6 connector ID is less than that of the pipe body.

(RL-4S = 22.250” ID, LS = 22.624” ID) (Conn. = 2.687” ID, Body = 2.750” ID)

i ’

50 of 52

Tubulars that are being phased out. Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly]

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

B

JUNE 2006

DRILLING PRACTICES CASING

__________________________________________________________________________________________________________________________

4.0 SIZE

SAUDI ARAMCO CASING DATA WEIGHT

GRADE

CONNECTION

I.D.

DRIFT

CONN. O.D.

BURST

COLLAPSE

in.

ppf

in.

in.

in.

psi

psi

JT/ YLD STRENGTH 1,000's lbs.

24 24

97.00 176.00

B X-42

SJ VETCO-LS

23.25 22.624

22.250

25.500

2170

1080

2,116

18-5/8 18-5/8

87.50 87.50

J-55 K-55

BTC BTC

17.755 17.755

17.567 17.567

19.625 19.625

2250 2250

630 630

1,329 1,367

13-3/8 13-3/8 13-3/8 13-3/8 13-3/8 13-3/8 13-3/8 13-3/8

61.00 61.00 68.00 68.00 68.00 68.00 72.00 72.00

J-55 K-55 J-55 K-55 J-55 K-55 L-80 S-95

STC STC STC STC BTC BTC STC BTC

12.515 12.515 12.415 12.415 12.415 12.415 12.347 12.347

12.359 12.359 12.259 12.259 12.259 12.259 12.191 12.250

14.375 14.375 14.375 14.375 14.375 14.375 14.375 14.375

3090 3090 3450 3450 3450 3450 4550 4930 *

1540 1540 1950 1950 1950 1950 2670 3470

595 633 675 718 1,069 1,069 1,040 1,935

9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8

36.00 36.00 40.00 40.00 40.00 40.00 43.50 47.00 53.50

J-55 K-55 J-55 K-55 L-80 13CR L-80 L-80 L-80 S-95

LTC LTC LTC LTC LTC LTC LTC LTC BTC

8.921 8.921 8.835 8.835 8.835 8.835 8.755 8.681 8.535

8.765 8.765 8.679 8.679 8.679 8.679 8.599 8.525 8.500

10.625 10.625 10.625 10.625 10.625 10.625 10.625 10.625 10.625

3520 3520 3950 3950 5750 5750 6330 6870 9160 *

2020 2020 2570 2570 3090 3090 3810 4760 8850

453 489 520 561 727 727 813 893 1,477

7 7 7 7 7 7 7 7 7 7

23.00 26.00 26.00 26.00 26.00 26.00 26.00 26.00 35.00 35.00

J-55 J-55 K-55 J-55 K-55 J-55 K-55 13CR L-80 L-80 L-80

STC LTC LTC VAM VAM NVAM NVAM LTC LTC VAM

6.366 6.276 6.276 6.276 6.276 6.276 6.276 6.276 6.004 6.004

6.241 6.151 6.151 6.151 6.151 6.151 6.151 6.151 5.879 5.879

7.656 7.656 7.656 7.681 7.681 7.681 7.681 7.656 7.656 7.681

4360 4980 4980 4980 4980 4980 4980 7240 9240 9960

3270 4320 4320 4320 4320 4320 4320 5410 10180 10180

284 367 401 415 415 415 415 511 734 725

5 5

15.00 15.00

K-55 13CR L-80

Spec. Cl. BTC Spec. Cl. BTC

4.408 4.408

4.283 4.283

5.375 5.375

5130 7460

5560 7250

241 350

4-1/2 4-1/2 4-1/2 4-1/2 4-1/2

11.60 11.60 11.60 12.60 13.50

J-55 J-55 13CR L-80 J-55 L-80

STC LTC LTC VAM VAM

4.000 4.000 4.000 3.958 3.920

3.875 3.875 3.875 3.833 3.795

5.000 5.000 5.000 4.892 4.862

5350 5350 7780 5790 8540

4960 4960 6350 5720 9020

154 162 212 198 211

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

JUNE 2006

DRILLING PRACTICES

B

CASING

__________________________________________________________________________________________________________________________

5.0 SIZE

KHUFF CASING & TUBING DATA WEIGHT

GRADE

CONN

LENGTH

wt.

I.D.

DRIFT

in.

psi

psi

JT/ YLD STRENGTH 1,000's lbs.

in.

48.000 36.000 25.500 25.250

1822 1890 2170 2170

254 768 1080 1080

2,116 2,116

17.249

20.000

3070

1511

1,850

12.347 " " " "

12.250 " " " "

14.375 14.375 14.398 14.398 14.375

4930 * 6390 6390 6390 6390

3470 3680 3900 3680 3890

1,935 1,935 1,935 1,935 1,973

0.625 " " "

12.125 " " "

12.000 " " "

14.375 14.398 14.398 14.375

7770 7770 7770 7760

6260 6560 6240 6500

2,333 2,333 2,333 2,333

R-3 R-3 R-3 R-3 R-3

0.545 " " " "

8.535 " " " "

8.500 " " " "

10.625 10.625 10.650 10.650 10.625

9160 * 8920 9410 9410 9410

8850 9330 8960 9350 8940

1,477 1,386 1,477 1,477 1,477

NS-CC

R-3

0.595

8.435

8.375

10.625

11900

12050

1,739

NS-CC N-VAM N-VAM NK-3SB

R-3 R-3 R-3 R-3

" " " "

" " " "

" " " "

10.625 10.650 10.650 10.625

11960 11900 11900 11900

12870 11880 12800 12860

1,857 1,857 1,857 1,857

NS-CC NVAM-MS NVAM-MS NK-3SB

R-3 R-3 R-3 R-3

0.453 " " "

6.094 " " "

6.000 " " "

7.656 7.732 7.732 7.772

10760 10760 10760 10760

11380 11160 11190 11150

885 885 885 885

L-80

NS-CC

R-3

0.498

6.004

5.879

7.656

9960

10180

814

L-80

NVAM-MS

R-3

"

"

"

7.805

9960

10180

814

35

L-80

NK-3SB

R-3

"

"

"

7.772

9960

10180

814

23 20 20 20 20

L-80 NT-95HSS C-95VTS SM-95TS NKAC-95T

N-VAM NS-CC N-VAM N-VAM NK-3SB

Tbg. Hngr R-3 R-3 R-3 R-3

0.415 0.361 " " "

4.670 4.778 " " "

4.545 4.653 " " "

6.075 6.050 6.075 6.075 6.050

10560 10910 10910 10910 10910

11160 11580 11410 11450 11400

478 554 554 554 554

in.

ppf

range

in.

in.

48 36 30 24 24

253 236 234 176 176

B X-60 X-42 X-42 X-42

BE BE SJ LS RL-4S

40’ 40' 55-60' R-3 R-3

0.500 0.625 0.750 0.688 0.688

47.000 34.750 28.500 22.624

18-5/8

115

K-55

BTC

R-3

0.594

17.437

13-3/8 13-3/8 13-3/8 13-3/8 13-3/8

72 72 72 72 72

S-95 NT-95HS C-95VT SM-95T NKHC-95

BTC NS-CC N-VAM N-VAM NK-3SB

R-3 R-3 R-3 R-3 R-3

0.514 " " " "

13-3/8 13-3/8 13-3/8 13-3/8

86 86 86 86

NT-95HS C-95VT SM-95T NKHC-95

NS-CC N-VAM N-VAM NK-3SB

R-3 R-3 R-3 R-3

9-5/8 9-5/8 9-5/8 9-5/8 9-5/8

53.5 53.5 53.5 53.5 53.5

S-95 NT-90HSS C-95VTS SM-95TS NKAC-95T

BTC NS-CC N-VAM N-VAM NK-3SB

9-5/8

58.4

9-5/8 9-5/8 9-5/8 9-5/8

58.4 58.4 58.4 58.4

NT105HSS NT-110HS P-110VT SM-110T NKHC-110

7 7 7 7

32 32 32 32

NT-95HSS C-95VTS SM-95TS NKAC-95T

i7 i7 i7

35 35

’

5-1/2 5-1/2 5-1/2 5-1/2 5-1/2

22.250 22.25 (con) 22.125

CONN. O.D.

BURST

COLLAPSE

’

15.1

L-80

N-VAM

Tbg. Hngr

0.337

3.826

3.701

5.010

10480

11080

353

NT-95HSS C-95VTS SM-95TS NKAC-95T L-80 D-95HC KO-105T

NS-CC N-VAM N-VAM NK-3SB N-VAM HYDRIL TS HYDRIL TS

R-3 R-3 R-3 R-3 R-3 R-3 R-3

0.290 " " " 0.290 " "

3.920 " " " 3.920 "

i4-1/2

13.5 13.5 13.5 13.5 13.5 13.5 13.5

3.840(con)

3.795 " " " 3.795 " "

5.000 4.961 4.961 5.000 4.961 4.719 "

10710 10710 10710 10710 9020 10720 10710

11330 11090 11120 11080 8540 12070 11280

364 364 364 364 307 300 295

3-1/2

12.95

L-80

HYDRIL PH-6

R-2

0.375

2.687(con)

2.625

4.313

15000

15310

295

4-1/2 4-1/2 4-1/2 4-1/2 4-1/2 4-1/2 4-1/2

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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

C

June 2006

DRILLING PRACTICES RUNNING CASING AND LINERS

___________________________________________________________________________________________________________________________

RUNNING CASING AND LINERS 1.0 CASING RUNNING GUIDELINES 1.1

1.2 1.3

1.4 1.5 1.6 1.7 1.8

1.9 1.10 1.11

1.12 1.13 1.14 1.15

Hook Load Requirement 1.1.1 Hoisting System 1.1.2 Determining Maximum Pull Equipment Inspection Casing Inspection 1.3.1 Electromagnetic Inspection 1.3.2 Grade Verification 1.3.3 Thread Inspection 1.3.4 Drifting Casing Tally Float Equipment Centralizers Elevators Casing Setting Depth 1.8.1 Wiper Trip 1.8.2 Strapping Out 1.8.3 Conditioning Trip 1.8.4 Pulling Wear Bushing 1.8.5 Drifting Inner String Changing and Testing BOP Rams Threadlock vs. Welding Casing Make-up 1.11.1 Thread Lubricants 1.11.2 Make-up Torque Fill Requirements Running Speed Breaking Circulation Landing Casing 1.15.1 Setting Slips 1.15.2 Landing Load

2.0 ADDITIONAL GUIDELINES FOR RUNNING LINERS 2.1 2.2 2.3 2.4 2.5 2.6 2.7

General Instructions Float Equipment and Landing Collar Wiper Plugs Liner Hanger Cement Manifold Fill Requirements Running Speed

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2.8 2.9

Breaking Circulation Setting Liner Hanger

3.0 FLOAT EQUIPMENT 3.1 3.2 3.3 3.4

Inner String Cementing Float Shoe Float Collar Plug Set

4.0 MULTI-STAGE PACKER COLLAR 4.1 4.2 4.3

Tool Illustrations/Technical Data Free Fall Plug Set Displacement Type Plug Set

5.0 CENTRALIZERS 5.1 5.2 5.3

Collapsible Rigid SpiraGlider

6.0 LINER HANGERS 6.1 6.2 6.3

Mechanical-Set Liner Hanger Hydraulic-Set Liner Hanger Associated Equipment 6.3.1 Setting Collar/Tieback Sleeve 6.3.2 Liner Top Packer 6.3.3 Polished Bore Receptacle 6.3.4 Cementing Manifold

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RUNNING CASING AND LINERS The purpose of this chapter is to present (1) casing running guidelines, (2) additional liner running requirements, and (3) down-hole equipment associated with these operations. 1.0

CASING RUNNING GUIDELINES Casing has become one of the most expensive parts of a drilling program. Post well evaluations have shown that the average cost of tubulars is approximately 20% of the completed well cost. More importantly, if these tubulars are not run properly, the success of the entire well could be jeopardized. Thus, an important responsibility of the Drilling Engineer and Drilling Foreman is to develop and execute a casing running procedure that will result in minimal risk and ensure the success of the operation. The following casing running guidelines are provided to aid the Drilling Engineer and Drilling Foreman in developing a sound work plan for running casing. It must be noted that these guidelines are subject to specific well conditions. 1.1

Hook Load Requirement The hoisting system capacity (mast, hook, traveling block, as well as the number and condition of lines) should be checked and compared to the calculated hook load for the next casing string. If additional lines are required, the string-up shall be done at least one trip prior to running casing. 1.1.1

Hoisting System A hoisting system is a way of lifting heavy loads with a lighter lead line pulling force. As with a simple pulley system, the line strung through the blocks creates a mechanical advantage. This mechanical advantage is equal to the number of lines strung between the crown and traveling block. Thus for a 12-line system, without friction, a given weight can be lifted with a pulling force of 1/12 of the weight as shown in Figure 2C-1.

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Dead Line

Fast Line

12 LINE HOISTING SYSTEM

Figure 2C-1

1.1.2

Determining Maximum Pull The fast line during hoisting has a somewhat greater load than the weight divided by the number of lines. This results from the friction of the sheave bearings and the bending of the line around the sheave. Since the fast line experiences the accumulation of frictional forces from all of the rotating sheaves, its load is the greatest and should be used when calculating design factors.

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The fast line load can be calculated as follows,

where,

L

= W x Ks (K-1) Kn -1

L W K n s

= = = = =

Load on Fast Line (lbs) Total String Weight with *Overpull (lbs) 1.04 (coefficient of friction of roller bearing sheaves) Number of Lines Number of Sheaves

Note: s = n (for most rigs; since the deadline does not rotate) * Overpull = 50,000 -100,00lbs (margin for working stuck pipe)

Thus, the design factor can be calculated as follows,

where,

DF = B L DF = Design Factor for Drilling Line B = Nominal Catalog Breaking Strength (lbs) L = Load on Fast Line (lbs)

Note:

Minimum Design Factor = 2.0 (when setting casing)

When a drilling line is operated near its minimum design factor, care should be taken that the line and related equipment is in good operating condition. The Drilling Manager‘s approval is required for casing loads resulting in a design factor < 2.0 with maximum line capacity. Floating the casing to bottom may be a consideration.

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DESIGN FACTORS FOR VARIOUS NUMBER OF LINES AND HOOKLOADS (ALL CALCULATIONS BASED UPON NEW 6 x 19 IWC WIRE ROPE)

Design Factor HOOK LOAD

LINES

FAST LINE LOAD

I.P.

200 M

EIPS

6 8 10

(LBS) 38,200 29,600 24,600

2.3 3.0 3.6

2.7 3.5 4.2

3. 3.8 4.6

3.4 4.4 5.3

3.6 4.7 5.6

4.2 5.3 6.5

4.4 5.6 6.8

5. 6.5 7.8

5.2 6.7 8

6. 7.7 9.2

250M

6 8 10 12

47,750 37,000 30,750 26,500

1.9 2.4 2.9 3.4

2.1 2.8 3.4 3.9

2.4 3. 3.7 4.2

2.8 3.5 4.2 4.9

2.9 3.7 4.5 5.2

3.3 4.3 5.2 6.

3.5 4.5 5.3 6.3

4. 5.2 6.2 7.2

4.2 5.3 6.4 7.5

4.8 6.1 7.4 8.6

300 M

6 8 10 12

57,300 44,400 36,900 31,800

2. 2.4 2.8

2.3 2.8 3.2

2. 2.5 3. 3.5

2.3 2.9 3.5 4.1

2.4 3.1 3.7 4.4

2.8 3.6 4.3 5.

2.9 3.7 4.5 5.2

3.3 4.3 5.2 6.

4. 4.5 5.3 6.2

5.1 6.2 7.1

6 8 10 12

66,850 51,800 43,050 37,100

1.7 2.1 2.4

2. 2.4 2.8

2.2 2.6 3.

2.5 3. 3.5

2.1 2.7 3.2 3.7

2.4 3.1 3.7 4.3

2.5 3.2 3.9 4.5

2.9 3.7 4.5 5.2

2.9 3.8 4.6 5.3

3.4 4.4 5.3 6.1

4.4 5.3 6.2

5.1 6.0 7.1

5.1 6.2 7.1

5.9 7.1 8.2

8 10 12

59,200 49,200 42,400

1.8 2.1

2.1 2.4

1.9 2.4 2.7

2.2 2.6 3.

2.3 2.8 3.3

2.7 3.2 3.8

2.8 3.4 3.9

3.2 3.9 4.5

3.3 4. 4.6

3.8 4.6 5.3

3.9 4.6 5.3

4.5 5.3 6.2

4.5 5.4 6.3

5.2 6.2 7.2

8 10 12

66,600 55,350 47,700

2.0 2.3

2.3 2.7

2.0 2.5 2.9

2.4 2.8 3.3

2.5 3.0 3.5

2.8 3.4 4.0

2.9 3.6 4.1

3.4 4.1 4.8

3.4 4.2 4.8

4.0 4.8 5.5

4.0 4.8 5.5

4.7 5.5 6.4

8 10 12 14

74,000 61,500 53,000 47,500

1.8 2.1 2.3

2.1 2.4 2.7

1.9 2.2 2.6 2.9

2.1 2.6 3. 3.3

2.2 2.7 3.1 3.5

2.6 3.1 3.6 4.0

2.7 3.2 3.7 4.1

3.1 3.7 4.3 4.8

3.1 3.7 4.2 4.8

3.6 4.3 5.0 5.5

3.6 4.3 5.0 5.6

4.1 5.0 5.7 6.4

8 10 12 14

88,800 73,800 63,600 57,000

1.8 2.0

2. 2.2

1.9 2.2 2.4

2.1 2.5 2.8

1.9 2.2 2.6 2.9

2.1 2.6 3. 3.3

2.2 2.7 3.1 3.4

2.5 3.1 3.6 4.0

2.6 3.1 3.6 4.0

3.0 3.6 4.1 4.6

3.0 3.6 4.2 4.6

3.4 4.1 4.8 5.3

8 10 12 14

103,600 86,100 74,200 66,500

1.8 2.0

2.1 2.4

1.9 2.2 2.5

2.2 2.6 2.8

1.9 2.3 2.7 2.9

2.2 2.6 3.1 3.4

2.2 2.7 3.1 3.4

2.5 3.0 3.5 3.9

2.5 3.1 3.6 4.0

3.0 3.5 4.1 4.6

8 10 12 14

118,400 98,400 84,800 76,000

1.7 1.97 2.2

1.95 2.28 2.53

2.0 2.3 2.6

2.3 2.7 3.0

1.9 2.3 2.7 3.0

2.2 2.6 3.1 3.4

2.2 2.7 3.1 3.5

2.6 3.1 3.6 4.0

8 10 12 14

133,200 110,700 95,400 85,400

1.75 1.96

1.74 2.01 2.25

1.79 2.08 2.32

1.70 2.05 2.39 2.67

1.87 2.41 2.7

1.9 2.3 2.7 3.1

2.0 2.3 2.8 3.1

2.3 2.7 3.2 3.58

10 12 14 16

123,000 106,000 95,000 86,000

1.81 2.02

1.86 2.08 2.3

1.85 2.15 2.4 2.6

1.89 2.17 2.42 2.6

2.14 2.5 2.78 2.8

2.16 2.51 2.80 2.8

2.49 2.89 3.22 3.5

350 M

400 M

450 M

500 M

600 M

700 M

800 M

900 M

1000 M

Note:

1” I.P.

1-1/8” EIPS

I.P.

1-1/4” EIPS

I.P.

1-3/8” EIPS

I.P.

1-1/2” EIPS

I.P.

1-5/8” EIPS

I.P.

1-3/4” EIPS

1. This table is based upon Extra Improved Plow and Improved Plow drilling line (with independent wire rope cores). 2. If a well is highly deviated (with high drag forces), an overpull (50,000 to 100,000 lbs) may be desired. In this case, the overpull margin must be added to the calculated casing weight to determine the maximum hook load.

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1.2

Equipment Inspection A complete field inspection by magnetic particle method of elevators, bails, spiders, slips, and hook shall be performed on each rig at least annually. This inspection should be carried out prior to the job on extremely heavy casing loads where minimum design factors are approached.

1.3

Casing Inspection 1.3.1

Required Electromagnetic Inspection

Be aware of the required casing inspection and that it is detailed in the drilling program. If electromagnetic inspection is required, this must be specified by the Drilling Foreman when the casing is ordered from the Dispatcher and performed by the inspection company prior to delivery to the rigsite. 1.3.2

Visual Casing Grade Verification

The API color codes listed below are used for all sizes/weights of casing and tubing to identify the grade. This color code identification is located on the casing coupling. Casing Grade Verification: P110 - One White Band C95 - One Yellow Band N80 - One Red Band C75 - One Blue Band K55 - One Green Band H40 - No Marking

Weight and grade identification may also be stenciled on the pipe body.

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1.3.3

Visual Thread Inspection When the casing is delivered and racked by grade, remove protectors and thoroughly clean casing threads. Visually inspect threads for damage or manufacturing defects. Re-install thread protectors if pipe is to be moved.

1.3.4

Drifting Drift casing with API full-length drift. Defective joints are to be clearly marked and removed to a separate area.

1.4

Casing Tally The casing is tallied by layer and numbered appropriately, in order in which the joints are to be run. The casing tally should be independently checked by both the Toolpusher and Drilling Foreman. Thread protectors shall be replaced to avoid damage during handling. A running list is essential and should include the following: ♦ ♦ ♦ ♦ ♦ ♦ ♦ ♦

1.5

Joints to be excluded. Amount of stick-up above rotary table. Position of casing collar in BOP stack. Location of centralizers. Change points for casing grade. Location of DV’s (if required). Location of marker joints (if required). Location of Float Equipment.

Float Equipment The float equipment should be made-up and threadlocked (along with the entire shoe track) in the rotary table with power tongs to ensure the proper torque is applied. This procedure involves only threadlocking the field-end of the casing coupling (as the mill-end of the coupling is not threadlocked). Historically, this procedure has proven effective. If casing back-off is a concern, casing couplings on the shoe track should be removed, threadlocked, and retorqued at float equipment vendor’s facility. As an alternative, multi-stage packer collars (DV’s) could also be made-up with (2) short joints at vendor’s facility to reduce rig time while handling and making up. All float equipment, multi-stage packer collar(s), opening bombs, and associated plugs shall be visually checked once on location.

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1.6

Centralizers Install centralizers on the rack in the middle of the appropriate joints as per running list.

1.7

Elevators All casing lifting/setting equipment shall be visually inspected prior to the job. If ‘side door’ elevators are to be used, check for uneven wear and verify that the casing load will be uniformly distributed over the face of the casing coupling. When ‘side-door’ elevators are in use, avoid impact loading which can open this type of elevator. Care must be taken when running centralizers through the BOP stack and wellhead. If ‘side door ‘ elevators are used to start a heavy casing string, always switch to ‘slip type’ elevators before entering the open hole. The ‘slip type’ elevator is recommended for long heavy casing strings. If ‘slip type’ elevators are to be used, the spider and elevator slips should be examined and verified for even distribution. The spider must be level for proper operation and load distribution. If the slips contact unevenly, there is a possibility of denting or slip-cutting the pipe. Also, the spider and elevator slips should be clean and sharp.

1.8

Casing Setting Depth Casing setting depth is generally referenced to a formation top. Occasionally the drill bit will quit or experience extremely low ROP just prior to reaching the projected depth. In these situations, the Drilling Engineer should consult with Geology or Reservoir Engineering regarding the following options: ♦ Obtaining approval for a revised casing point. ♦ Logging at this depth and drilling additional rat hole, if required. ♦ Continuing drilling to original casing point. 1.8.1

Wiper Trip

The mud shall be conditioned to the desired properties. Controlled fluid loss and Torq-Trim additions are required on deviated/horizontal wells where differential sticking is a concern. A flow check should performed prior to pulling out of the hole. The wiper trip shall be made to the previous casing shoe and the trip tank monitored to ensure the hole is stable. After running back to bottom, circulate bottoms-up and pull out of the hole. A flow check should also be conducted at the casing shoe and again at the drill collars.

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1.8.2

Strapping Out The casing setting depth must be checked by strapping-out of the hole at least once prior to logging or running casing. If this measurement does not agree with hole depth, the pipe should be restrapped.

1.8.3

Conditioning Trip A conditioning trip should be planned prior to running casing if hole problems were encountered during logging or if the logging program required additional time (>10 hours). This decision is made on location by the Drilling Foreman.

1.8.4

Pulling Wear Bushing The wear bushing must be retrieved after the last trip out of hole with the drill string prior to running casing.

1.8.5

Drifting Inner String On inner string cementing operations, all drill pipe being used as the inner string should be drifted with the correct size ‘rabbit’ to ensure adequate clearance for the drill pipe latch down plug.

1.9

Changing and Testing BOP Rams Casing rams shall be installed on all Class ‘A’ BOP stacks prior to running casing. The pressure test will consist of testing the casing rams with a joint of casing connected to the test plug with appropriate crossover. The annular will be used as casing rams on all Class ‘B’ BOP stacks, since the blind rams are on top of the master pipe rams.

1.10 Threadlock vs. Welding All heat treated casing (C75 and above) shall not be welded, as mechanical properties can be altered through welding operations. The shoe track should be welded (for H40, X42, J55, K55, material) and threadlocked (for C75, L80, N80, C95, S95, etc.). Apply ‘threadlock’ to the pin-end only and wipe off excess to prevent threadlock from falling inside the float equipment. Threadlock has a greater friction factor than thread compound; consequently, a higher make-up torque is required (see Section 1.11.1 of this chapter).

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1.11 Casing Make-Up The actual casing make-up is a function of the applied make-up torque and the thread lubricant used. This assumes the torque gauge is properly calibrated. 1.11.1 Thread Lubricants An API Modified thread compound with a friction coefficient of 1 shall always be used. All published make-up torque values assume a friction factor of 1. Thread protectors should be removed on the rig floor and thread lubricant applied to pin-end only prior to stabbing each joint. The table below shows the associated friction factors for thread compounds and threadlock used by Saudi Aramco. Thread Compound Wfd Lube Seal Bestolife 270 Wfd Tube Lok

Friction Factor 1.0 1.0 1.5

Note: Actual Torque = Torque Reading x Friction Factor 1.11.2 Make-Up Torque Use only the recommended make-up torque and ensure that each joint of casing is correctly made up. The optimum make-up torque value is recommended at all times. Although if several threads are exposed when the optimum torque is reached, apply additional torque to the maximum torque value. In addition, if the make-up is such that the thread vanish point is buried two thread turns and the minimum torque value is not reached, the joint should be treated as a bad joint and moved to a separate area. Make-up for Buttress Thread Connections (BTC) should be determined by carefully noting the torque required to make-up several connections to the base of the triangle. Having established this torque value, the remainder of that weight and grade of pipe in the string can be made up accordingly. The make-up tolerance is + 3/8” measured from the base of the triangle, providing that the make-up torque is reached.

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The following table below shows the recommended make-up for the casing and tubing commonly used by Saudi Aramco. RECOMMENDED MAKE-UP TABLE SAUDI ARAMCO NON-PREMIUM CASING/TUBING CONDUCTOR CASING

Minimum (ft-lbs.)

Optimum (ft-lbs.)

Maximum (ft-lbs.)

-

WELD WELD

-

26,000

WELD WELD 29,000

32,000

24,000 24,000

WELD 26,000 26,000

28,000 28,000

18-5/8” 87.50# K-55, R-3, BTC 18-5/8” 115.00# K-55, R-3, BTC

Base of Triangle Base of Triangle

Base of Triangle Base of Triangle

Base of Triangle Base of Triangle

13-3/8” 13-3/8” 13-3/8” 13-3/8” 13-3/8”

61.00# 61.00# 68.00# 72.00# 72.00#

J-55, K-55, K-55, L-80, S-95,

R-3, R-3, R-3, R-3, R-3,

STC STC BTC STC BTC

4,460 4,750 Base of Triangle 7,720 Base of Triangle

5,950 6,330 Base of Triangle 10,290 Base of Triangle

7,440 7,910 Base of Triangle 12,860 Base of Triangle

9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8”

36.00# 36.00# 40.00# 40.00# 40.00# 43.50# 47.00# 53.50#

J-55, K-55, J-55, K-55, L-80, L-80, L-80, S-95,

R-3, R-3, R-3, R-3, R-3, R-3, R-3, R-3,

LTC LTC LTC LTC LTC LTC LTC BTC

3,400 3,670 3,900 4,210 5,450 6,100 6,700 Base of Triangle

4,530 4,890 5,200 5,610 7,270 8,130 8,930 Base of Triangle

5,660 6,110 6,500 7,010 9,090 10,160 11,160 Base of Triangle

7” 7” 7” 7” ♦7”

23.00# 26.00# 26.00# 26.00# 26.00#

J-55, R-3, LTC J-55, R-3, LTC K-55, R-3, LTC K-55, R-3, NVAM K-55, R-3, OLD VAM

2,350 2,750 3,010 6,510 8,000

3,130 3,670 4,010 7,230 8,700

5”

15.00#

K-55/L-80, R-3, BTC

Base of Triangle

Base of Triangle

Base of Triangle

4-1/2” 4-1/2” 4-1/2” ♦4-1/2” ♦4-1/2” 4-1/2”

11.60# 11.60# 11.60# 12.60# 12.60# 12.60#

J-55, R-3, L-80, R-3, J-55, R-3, J-55, R-2, J-55, R-3, L-80-13CR,

1,160 1,670 4,300 3,190 4,300 -

1,540 2,230 4,700 3,540 4,700 4,120

1,930 2,790 5,100 3,890 5,100 -

48” 36”

0.500" wt. 253.65# GR-B, R-3, BE 0.625" wt. 236.15# GR-B, R-3, BE

30” 30” 30”

0.500" wt. 157.50# X-42, 55/60', SJ 0.750" wt. 234.30# X-42, 55/50', SJ 0.750" wt. 239.00# X-42, 55/60', JV-LW

24” 97.00# GR-B, R-3, SJ ♦24” 0.688” wt. 176.00# X-42, R-3, V-LS 24” 0.688” wt. 176.00# X-42, R-3, V-RL4S

CASING and TUBING

STC LTC OLD VAM NVAM OLD VAM R-3, FOX

3,910 4,590 5,010 7,950 10,100

3-1/2”

9.30# J-55,

R-2, EUE

1,710

2,280

2,850

2-7/8”

6.50# J-55,

R-2, EUE

1,240

1,650

2,060

2-3/8”

4.70# J-55,

R-2, EUE

970

1,290

1,610

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SAUDI ARAMCO PREMIUM CASING and TUBING

♦13-3/8” 72.00# C-95VT/ SM-95T, R-3, NVAM 13-3/8” 72.00# NKHC-95, R-3, NK-3SB 13-3/8” 72.00# NT-95HS, R-3, NS-CC ♦13-3/8” 86.00# C-95VT/ SM-95T, R-3, NVAM 13-3/8” 86.00# NKHC-95, R-3, NK-3SB 13-3/8” 86.00# NT-95HS, R-3, NS-CC

♦9-5/8” 53.50# C-95VTS/SM-95TS, R-3, NVAM 9-5/8” 53.50# NKAC-95T, R-3, NK-3SB 9-5/8” 53.50# NT-90HSS, R-3, NS-CC ♦9-5/8” 58.40# P-110VT/ SM-110T, R-3, NVAM 9-5/8” 58.40# NKHC-110, R-3, NK-3SB 9-5/8” 58.40# NT-105HS/-110HS, R-3, NS-CC

♦7” ♦7” 7” 7” ♦7” ♦7” ♦7” ♦7” ♦7”

26.00# 32.00# 32.00# 32.00# 35.00# 35.00# 35.00# 35.00# 35.00#

K-55, R-2, NVAM C-95VTS/ SM-95TS, R-3, NVAM NKAC-95T, R-3, NK-3SB NT-95HSS, R-3, NS-CC L-80, R-3, NS-CC L-80, R-3, NK-3SB L-80, R-3, NVAM MS L-80, R-3, HYDRIL SUPER-EU L-80, R-3, AB IJ-4S

♦5-1/2” 20.00# C-95VTS/SM-95TS, R-3, NVAM 5-1/2” 20.00# NKAC-95T, R-3, NK-3SB 5-1/2” 20.00# NT-95HSS, R-3, NS-CC ♦∇ 5-1/2” 23.00# L-80, R-3, NVAM

♦4-1/2” 12.60# J-55, R-2, NVAM ♦4-1/2” 13.50# L-80, R-3, NVAM ♦4-1/2” 13.50# C-95VTS/ SM-95TS, R-3, NVAM 4-1/2” 13.50# NKAC-95T, R-3, NK-3SB 4-1/2” 13.50# NT-95HSS, R-3, NSCT ♦ 4-1/2” 13.50# KO-105T, R-3, HTS ♦∇ 4-1/2”15.10# L-80, R-3, NVAM

Minimum (ft-lbs.)

Optimum (ft-lbs.)

Maximum (ft-lbs.)

14,400 16,000 13,100

15,900 20,000 14,800

17,400 24,000 16,600

14,400 16,000 13,100

15,900 20,000 14,800

17,400 24,000 16,600

14,400 13,200 9,500

15,900 16,500 10,800

17,400 19,800 12,300

14,400 14,400 10,200

15,900 18,000 11,700

17,400 21,600 13,300

6,510 9,850 8,800 6,600 6,900 9,600 9,500 8,500 -

7,230 10,850 11,000 7,600 8,000 12,000 10,500 9,560 10,000

7,950 11,850 13,200 8,600 9,000 14,400 11,500 10,625 -

6,120 5,760 5,100 7,170

6,800 7,200 5,900 7,960

7,480 8,640 6,800 8,750

3,190 4,430 5,080 3,520 2,900 4,200 5,210

3,540 4,920 5,640 4,400 3,600 4,725 5,790

3,890 5,410 6,200 5,280 4,300 5,250 6,370

3-1/2” 12.95# L-80, R-2,

HYDRIL PH-6

5,500

6,185

6,875

2-7/8” 6.40# J-55, R-2, 2-7/8” 8.70# L-80, R-2,

NSCT-SC HYDRIL PH-6

1,160 3,000

1,340 3,375

1,520 3,750

500 ♦2-3/8” 4.70# L-80, R-2, AB FL-4S 2-3/8” 4.70# L-80, R-2, HYDRIL CS 1,500 1,685 2-3/8” 5.80# L-80, R-2, NVAM 1,500 1,660 2-3/8” 5.90# L-80, R-2, HYDRIL PH-6 2,200 2,475 Note: ♦ Tubulars that are being phased out. ∇ Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly].

1,875 1,820 2,750

The use of a make-up monitoring system (Jam, Torque/Turn, etc.) should be used on all production tubing strings with specialty connections to ensure a more accurate make-up.

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1.12 Fill Requirements The casing string should be filled every joint while running and topped off every 10 joints, or otherwise dictated by casing collapse calculations (based on evacuated casing and a full column of mud in the annulus). In no case shall the hydrostatic pressure inside the casing be less than reservoir pressure due to infrequent filling (this could result in a kick if the float equipment fails while running the casing). Note: The Khuff/Pre-Khuff rigs with top drives have installed a short joint on the top drive to fill the casing faster and reduce mud spillage on the rig floor. 1.13 Running Speed Casing should be run smoothly. Avoid high acceleration and deceleration, which can cause high surge/swab pressures. The casing running speed should be regulated to approximately 30 seconds per joint or otherwise dictated by surge pressure calculations. The Driller should be aware of tight spots on the previous trip out of the hole and any problem zones, which could result in stuck pipe or loss circulation while running casing. If tight hole is encountered while running with the casing, a circulating sub should be installed to wash the casing down. •

•

If the casing can not be run deeper due to hole conditions, the Drilling Foreman should inform the Drilling Superintendent and Drilling Engineer. Drilling Engineering and the Superintendent will determine if (1) the casing can be set at this depth or (2) the casing should be laid down and a clean out trip made. If the casing is stuck, the grease pills should be spotted in an attempt to free the pipe. If unsuccessful, the casing must be cemented in place at the stuck point. Cementing the pipe high is not desirable, as it increases the risk of successfully drilling the next hole section with more zones exposed. This has led to abandoning the well and skidding the rig on some situations where the entire RUS and UER had to be drilled together. Sticking problems have occurred in the following formations: RUS Wasia Shale Wara Shale Khafji Stringer

(Arab-D and Khuff/Pre-Khuff wells) (Arab-D and Khuff/Pre-Khuff wells) (Shaybah wells) (Offshore Horizontal wells)

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1.14 Breaking Circulation Circulation should be established while running casing as follows, ♦ ♦ ♦ ♦

After running in with the shoe track. Upon reaching casing shoe depth. Upon encountering tight hole (if any). Upon reaching 1-2 joints before TD (for circulating down).

Note: Break circulation slowly. Once total depth is tagged, the casing should be picked up 1-2 feet and free hanging weight recorded. Circulate hole at least one full circulation while recording circulating pressures and rates. Reciprocate casing as specified in the drilling program. 1.15 Landing Casing Once the casing has been cemented, the BOP stack will be nippled down and raised to set the casing slips. On multi-stage cement jobs, the slips will be set prior to cementing the last stage. 1.15.1 Setting Slips Do not drop casing slips through the BOP stack. The following problems can occur with this practice, ♦ Slips hanging up in the BOP stack. ♦ Slips stopping on a casing collar (if collar is positioned in stack). ♦ Slips misaligned preventing improper setting. On single stage cementing, set casing slips as follows, A) B) C) D)

Displace cement and bump plug. Check for flow-back and verify well is stable. Pick-up BOP stack. Set casing slips.

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On multi-stage cementing, set casing slips as follows, A) B) C) D) E) F)

Displace 1st stage (and 2nd, if 3 stage job) cement with mud. Open upper most DV. Circulate hole clean with mud. WOC. Verify well is static. Pick-up BOP stack. Set casing slips prior to cementing final stage.

1.15.2 Landing Load A proper casing landing load is required to avoid excessive or unsafe tensile stresses during the life of the well. The casing should be landed in the casing spool in approximately the same “as cemented” position (no pick-up or slack-off) unless otherwise dictated by landing calculations. A casing string pick-up of less than 6” to set the casing slips is recommended. This pick-up will allow setting the casing slips in the “as cemented” position and will not damage or release the multi-stage packer collar. Cementing the production casing to surface and setting the casing slips in the “as cemented” position will avoid buckling problems (associated with excessive slack-off and changes in well temperature during production). Khuff and Pre-Khuff wells utilize a reinforced support unit which is attached to the casing head to distribute excessive casing loads directly to the cellar floor.

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2.0

ADDITIONAL GUIDELINES FOR RUNNING LINERS Liners are casing strings that do not extend to the surface but are suspended from the bottom of the previous casing string. A drilling liner is similar to intermediate casing in that it serves to isolate troublesome zones (abnormally pressured zones, weak formations, borehole instability, etc.) during the drilling operation. A production liner is set through the productive interval of the well. Production liners may be tied back to the surface, if required. Advantages of liners as compared to casing are as follows, ♦ ♦ ♦ ♦

Lowers tangible cost. Reduces tensile running load (may overcome rig limitation). Eliminates a casing spool requirement on the wellhead. Allows use of larger production tubing above liner top (if no tie-back).

The following discusses the additional guidelines associated with running drilling or production liners. These guidelines are subject to well conditions and the specific liner hanger equipment utilized. 2.1

General Instructions A)

When running short liners, be aware of the buoyant conditions. If floating is anticipated, consider using hold-down slips on the liner hanger or loading the liner with weighted mud to offset the buoyant force.

B)

Drift all drill pipe, crossovers, liner hanger, and setting tools required in running the liner with the correct size drift to ensure the passage of the drill pipe wiper plug. Rabbit the drill pipe on the conditioning trip prior to running the liner. If the rabbit hangs up in any joint, leave that joint out of the string. Ensure the exact quantity of drill pipe in the derrick is known.

C)

The Drilling Foreman, Toolpusher, and Liner Company serviceman should compare all pipe figures and displacement calculations.

D)

Check the length of the liner versus the drill pipe and collars to be left out of the hole. As soon as the liner is landed, the number of remaining joints of drill pipe in the derrick should be counted to verify that the liner is on bottom.

E)

Install a drill pipe wiper rubber on the drill pipe string while running in the hole to prevent foreign objects from falling into the wellbore.

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F)

2.2

The liner cement shall be batch-mixed and displaced using the cement company pump truck. Further details on cementing operations are covered in Chapter 2D of this manual.

Float Equipment and Landing Collar Visually inspect all liner float equipment and ensure that they are compatible with the liner hanger equipment and running procedures. The liner company service representative on location should verify the proper ‘shear pressure’ of the ballseat in the landing collar and that the ball is compatible with the seat.

2.3

Wiper Plugs Visually inspect wiper plugs and ensure the drill pipe wiper plug is compatible with the liner wiper plug.

2.4

Liner Hanger The liner hanger will be inspected, measured, and pre-assembled on the setting tool (complete with liner wiper plug) at the liner shop prior to shipping to the rig. Once the complete liner assembly is on location, a visual inspection should be made and no damage has occurred during transportation. The liner company service representative on location should ensure the proper ‘liner setting’ shear pins are installed. In addition, be aware of the liner hanger operation, method of make-up, running procedure, and procedures to follow in the event of an equipment failure, as directed by the Liner Company serviceman on location.

2.5

Cement manifold Visually inspect the cement manifold along with the liner assembly when it arrives on location. Load the drill pipe wiper plug in the manifold after performing the torque/drag test at the casing shoe (before going into open hole with the liner). Pick up the cement manifold approximately + 30’ from TD. Install the manifold and circulate down to TD. Ensure that lines are hooked-up and ready for immediate reversing (once the cement job is complete).

2.6

Fill Requirements The liner should be filled every 10 joints or otherwise dictated by liner collapse calculations (based on evacuated casing and a full column of mud in the annulus). Fill the drill pipe at least every 5 stands and check to ensure that the correct amount of fluid required is pumped.

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In no case shall the hydrostatic pressure inside the liner be less than reservoir pressure due to infrequent filling (this could result in a kick if the float equipment fails while running the liner). 2.7

Running Speed Control the running speed to reduce high surge pressure created by the small annular clearances associated with liners. The running speed should be regulated to approximately 30 seconds per joint for the liner and 60 seconds per stand for the drill pipe, or otherwise dictated by surge pressure calculations. The Driller should be aware of tight spots on the previous trip out of the hole and any potential loss circulation zones that could be affected by high running speed.

2.8

Breaking Circulation Circulation should be established while running the liner as follows, ♦ ♦

♦

♦ ♦

After running in with the shoe track. After installing the liner hanger, pick up one stand of drill pipe and slack off until the liner hanger assembly is below the BOP stack. Circulate one complete liner capacity plus 25%. Ensure that the circulating pressure does not exceed 75% of the pressure required to set the liner hanger. Record the weight on the liner on the weight indicator.

Upon reaching casing shoe depth, break circulation and ensure that the circulating pressure does not exceed 75% of the pressure required to set the hanger. Perform torque/drag test and record data. Load the drill pipe wiper plug.

Upon encountering tight hole (if any). Upon reaching approx. 30’ from TD (for circulating down).

Note: Break circulation slowly as high pump rates can break down weak formations due to small annular clearances. Once total depth is tagged, the liner should be picked up 1 to 2 feet. Record the free hanging weight of liner and drill pipe. Circulate hole at least two full circulation volumes while ensuring that the pump pressure does not exceed 75% of the pressure required to set the hanger. Pump at reduced rate until

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bottoms-up is past the liner top. Rotate and/or reciprocate liner as specified in the drilling program. 2.9

Setting Liner Hanger The liner hanger should always be set higher than the deepest depth achieved while circulating or reciprocating. This will ensure the liner is hung and not merely standing on bottom. The specific liner hanger setting procedure will vary with the type of well, cementing program, and type of hanger used. These setting instructions will be provided by the liner hanger serviceman on location or will be detailed in the drilling program. Mechanical-set and hydraulic-set liner hangers are utilized within Saudi Aramco’s drilling operation. The following summarizes four different well types and liner hanger applications, ♦ Arab-D Vertical Well 7” Mechanical-Set Liner Hanger with Pack-Off (Lindsey, BOT) Hanger Set Prior to Cementing Set after Cement Job ♦ Offshore/Shaybah Horizontal Well (BOT, and TIW) 4-1/2” Hydraulic-Set Liner Hanger Set After Cementing ♦ Khuff Vertical Well (BOT and 1st Generation TIW) 7” and 4-1/2” Hydraulic-Set Liner Hangers Set Prior to Cementing ♦ Khuff Horizontal Well (2nd Generation TIW) 7” and 4-1/2” Hydraulic-Set Liner Hanger Hanger Set After Cementing Further information regarding details on mechanical-set, hydraulic-set, and associated liner hanger equipment is listed in Section 6 of this chapter.

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3.0

FLOAT EQUIPMENT 3.1

Inner String Cementing Inner string cementing (ISC) is utilized to reduce rig time and cementing cost. The method provides for the cementing of large diameter casing through an inner drill pipe string, virtually eliminating cement contamination and the drill out of large quantities of cement. This system is primarily used on Khuff wells where the 30” casing is cemented at approximately 600’ (with ISC and stab-in float shoe) and 24” casing is cemented at approximately 2200’ (with ISC and stab-in float collar).

Casing collapse must be considered on the deep casing strings cemented with ISC. *The maximum surface pressure should be calculated to avoid casing collapse in the event of the hole bridging-off near the casing shoe. On critical depth strings, the surface pump pressure plus the cement hydrostatic pressure (ISC) can exceed the casing collapse rating, even though the casing is supported by mud hydrostatic pressure inside. The following alternatives can prevent casing collapse while ISC at a critical cementing depth: ♦

♦ *

Increasing mud weight inside the casing prior to cementing. Utilizing a pack-off cementing head (which enables holding additional pressure on the casing). Max. Surf. Press. = Collapse Rating – [Cmt Hydrostatic Inside ISC – Mud Hydrostatic Inside Csg] 1.125

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3.2

Float Shoes The float shoe reinforces the lower end of the casing string and guides the string away from ledges to cementing depth. It includes a springloaded backpressure valve that prevents reverse flow of cement back into the casing following the cementing operation. The outside body of the float shoe is made of steel of the same strength as the casing. The backpressure valve is made of plastic and is enclosed in concrete for easy drill-out.

3.3

Float Collars The float collar serves as a back up to the float shoe in the event the backpressure valve in the float shoe fails to provide a seal. The float collar is normally located 2 to 3 joints above the float shoe. The construction of float collar is similar to the float shoe and also enables easy drill-out.

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3.4

Plug Set The standard plug set consists of a bottom wiper (rupture) plug and top wiper (solid) plug. The primary purpose of bottom wiper plug is to wipe the mud from the casing wall ahead of the cement to minimize contamination. The purpose of the top wiper plug is to isolate the cement slurry from the displacement fluid. In most cases, the bottom wiper plug is not used to avoid confusion or a potential problem with the bottom plug not rupturing. If the top wiper plug is dropped first, the plug will bump with the cement still inside the casing. A similar result would be experienced if the bottom plug did not rupture. This procedure of ‘not using the bottom wiper plug’ is a Drilling & Workover policy. The only exception would be a possible situation where the top wiper plug might wipe enough mud from a long, small diameter casing string and exceed the capacity of the shoe track (resulting in a wet shoe).

TOP WIPER PLUG

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4.0

MULTI-STAGE PACKER COLLAR The multi-stage packer collars are hydraulically operated and provide for 2-stage and 3-stage cementing operations. Applications for multi-stage packer collars include the following: ♦ ♦

♦

Cementing a high-pressure gas zone and loss circulation zone. (Example: Isolating abnormal Lower Jilh pressure from the Hanifa and ArabD reservoirs.) Cementing above a loss circulation zone. (Example: Cementing to surface above UER.) Cementing a deep casing string back to surface. (Example: Cementing to surface from the Jilh Dolomite casing point.)

The multi-stage packer collar (DV) is typically located inside the previous casing string to ensure a good packer seat for the 2nd stage cementing. On a 3-stage cement job, the lower DV is run in the open hole section where the hole size is close to gauge. The actual packer depth can be picked from the caliper log, when available, or by rate of penetration. A 3-stage cement job requires two multi-stage packer collars and two different size plug sets. A conversion kit is installed in the lower DV to accommodate the smaller plug set. The actual DV tool is the same for both 2-stage and 3-stage applications except for the conversion kit installation.

4.1

Tool Illustrations/Technical Data The following provides tool illustrations and technical data for the multi-stage packer collars commonly used within Saudi Aramco drilling operation. The actual tool application will be specified in the drilling program based upon casing size, connection, rated service, and other factors.

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C losing S eat O pening S eat

18-5/8” T yp e P E S In flatab le P acker C o llar w /M etal B lad d er P acker (E S IP C ) E xternal P orts w /R upture D isk Internal P orts

P acker E lem ent

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HALLIBURTON DV PACKER COLLARS SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description

Pkr (HES P/N) Pkr Description Plug Set (HES P/N) Plug Set Description Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

45-664-789-00 813.30226 18.625 ESIPC-P 813.30226 CEMENTER SET - SAMS #45-664-789-00 - 18-5/8" BUTTRESS 115# - ESIPC W/METAL BLADDER PKR W/2-STG, W/RD FREE FALL PLUG SET 813.78965 COLLAR - TYPE P ES INFL PKR - 18-5/8 BUTTRESS 115# METAL BLADDER PKR 813.16870 PLUG SET - FREE FALL - 18-5/8 8RD & BUTTRESS 87.5-115# 2-STAGE CMTR - W/9.81 ID BAFFLE 320 76000 1450 475 114000 3000 2000 22.750 23.200 20.800 75.750 17.467 14.250 16.000 4 1.125 23.800 N/A 24.250

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Multiple Stage Inflatable Packer Collar (MSIPC) External Ports Internal Ports

Closing Seat

Opening Seat

Packer Element

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HALLIBURTON DV PACKER COLLARS SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description Pkr (HES P/N) Pkr Description Plug Set (HES P/N) Plug Set Description Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

45-734-380-00 N/A 13.375 MSIPC N/A SEE BELOW 813.31060 COLLAR - MULT STAGE INFL PKR - 13-3/8 NEW-VAM 6172# -16.75 OD SUITABLE F/ USE W/ C-95 SEE NOTES AT BOTTOM SEE NOTES AT BOTTOM 675 81000 1450 675 81000 3500 17.500 16.750 56.800 12.359 10.400 11.250 4 1.250 18.500 N/A 19.540 Description PLUG SET - FREE FALL - 13-3/8 NEW VAM, 54.5-72#, 2-STAGE CMTR - W/7.40 ID INSERT BAFFLE ADAPTER SUITABLE F/USE W/C-95 PLUG SET - FREE FALL - 13-3/8 NEW VAM 54.5-72# 3-STAGE CMTR - W/7.40 ID SHUTOFF BAFFLE F/813 & 854 SERIES TOOLS-SUITABLE F/USE W/C-95 PLUG SET - DISPLACEMENT TYPE - 13-3/8 PREMIUM THD 48-85# 3-STAGE CMTR W/3.25 ID BYPASS BAFFLE -

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HALLIBURTON DV PACKER COLLARS SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description

Pkr (HES P/N) Pkr Description Plug Set (HES P/N) Plug Set Description Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

45-734-777-00 813.30215 13.375 MSIPC 813.30215 CEMENTER SET - SAMS #45-664-777-00 - 13-3/8 BUTTRESS61-72# SUITABLE F/USE W/L-80 - MSIPC & 2-STAGE FREE FALL PLUG SET W/7.4 ID SHUTOFF BAFFLE 813.31058 COLLAR - MULT STAGE INFL PKR - 13-3/8 BUTRESS 61-72# -16.75 OD - SUITABLE F/USE W/L-80 813.16821 PLUG SET - FREE FALL - 13-3/8 8RD & BUTTRESS 48-85# 2-STAGE CMTR W/11.25 ID CLSG SEAT - W/7.40 ID BAFFLE 675 81000 1450 675 81000 3500 17.500 16.750 56.800 12.359 10.400 11.250 4 1.125 18.500 N/A 19.540

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External Ports w/Rupture Disk Internal Ports

Closing Seat

Multiple Stage Inflatable Packer Collar w/Rupture Disk (MSIPC)

Opening Seat

Packer Element

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HALLIBURTON DV PACKER COLLARS SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description Pkr (HES P/N) Pkr Description Plug Set (HES P/N) Plug Set Description Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

45-733-942 N/A 9.625 MSIPC N/A SEE BELOW 813.30937 COLLAR - MULT STAGE INFL PKR - 9-5/8, NEW-VAM 43.5-53.5# - 11.75 OD - W/ RD - SUITABLE F/USE W/C-95 SEE NOTES AT BOTTOM SEE NOTES AT BOTTOM 925 54000 1800 650 38000 4000 12.250 11.750 64.100 8.619 6.926 7.750 2 1.125 14.000 N/A 15.000 Description PLUG SET - FREE FALL - 9-5/8 NEW VAM 45.5-53.5# 2-STAGE CMTR - W/5.00 ID INSERT BAFFLE ADAPTER - SUITABLE F/USE W/C-95 PLUG SET - DISPLACEMENT TYPE - 2-STAGE - 9-5/8 PREMIUM THD 40-53.5# MULT STAGE CMTR PLUG SET - FREE FALL - 9-5/8 PREMIUM THREAD 43.5-53.5# MULTI STAGE CMTR PLUG SET - DISPLACEMENT TYPE - 9-5/8 PREMIUM THD 36-53.5# & 9-7/8 62.8# 3-STAGE CMTR - W/3.25 ID BYPASS BAFFLE

HALLIBURTON DV PACKER COLLARS

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SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description

Pkr (HES P/N) Pkr Description

Plug Set (HES P/N) Plug Set Description

Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

45-733-932-00 813.30290 9.625 MSIPC 813.30290 CEMENTER SET - SAMS #45-733-932-00 - 9-5/8, 8RD, 29.3-40# SUITABLE F/USE W/P-110 W/ RD - MSIPC W/ 2-STG FREE FALL PLUG SET 813.30854 COLLAR - MULT STAGE INFL PKR - 9-5/8, 8RD29.3-40# - 11.75 OD - W/RUPTURE DISK, SUITABLE F/USE W/P-110 813.16710 PLUG SET - FREE FALL - 9-5/8, 8RD, 32.3-53.5#2STAGE TYPE P CMTR - W/5.90 ID BAFFLE - REF: 813.16720 860 54000 1800 610 38000 4000 12.250 11.750 64.150 8.927 6.926 7.750 2 1.125 14.000 N/A 15.000

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HALLIBURTON DV PACKER COLLARS SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description

Pkr (HES P/N) Pkr Description

Plug Set (HES P/N) Plug Set Description

Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

45-664-786-00 813.30214 13.375 MSPCC 813.30214 CEMENTER SET - SAMS #45-664-786-00 - 13-3/8, 8RD 48-72# SUITABLE F/USE W/P-110 - MSPCC & 2-STG FREE FALL PLUG SET W/7.40 ID SHUTOFF BAFFLE 854.08441 COLLAR - MULT STAGE PKR CMTG - 13-3/8, 8RD, 48-72#, 16-3/4 OD PKR - 11.25 ID CLSG SEAT - SUITABLE F/USE W/P-110 813.16821 PLUG SET - FREE FALL - 13-3/8 8RD & BUTTRESS 48-85#, 2STAGE CMTR W/11.25 ID CLSG SEAT - W/7.40 ID BAFFLE 560 81000 N/A 560 81000 1000 17.500 16.750 49.400 12.579 10.400 11.250 6 1.310 17.750 17.500 21.560

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HALLIBURTON DV PACKER COLLARS SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description

Pkr (HES P/N) Pkr Description Plug Set (HES P/N) Plug Set Description Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

45-664-776-00 813.30272 7.000 MSPCC 813.30272 CEMENTER SET - SAMS #45-664-776-00 - 7-INCH 8RD 17-23# SUITABLE F/USE W/P-110 - MSPCC W/2-STAGE FREE FALL PLUG SET 854.0519 COLLAR - MULT STAGE PKR CMTG - 7 IN., 8RD, 17-23# 81/2 OD PKR SUITABLE F/USE W/P-110813.16571 PLUG SET - FREE FALL - 7 IN. 8RD & BUTTRESS 20-38# 2-STAGE CMTR - W/3.80 ID BAFFLE 930 35400 N/A 620 25600 1000 8.750 8.500 45.830 6.433 4.370 5.120 3 1.310 9.000 8.750 10.120

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Type H ES Inflatable Packer Collar (ESIPC) Closing Seat Opening Seat

External Ports w/Rupture Disk Internal Ports

Packer Element

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HALLIBURTON DV PACKER COLLARS SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description Pkr (HES P/N) Pkr Description Plug Set (HES P/N) Plug Set Description Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

N/A Trial Test 7.000 ESIPC-H N/A SEE BELOW 813.78101 COLLAR - TYPE H ES INFL PKR - 7 IN., LG, 8RD, 26# -3 FT PKR - SUITABLE F/USE W/K-55 813.16571 PLUG SET - FREE FALL - 7 IN. 8RD & BUTTRESS 20-38# 2-STAGE CMTR - W/3.80 ID BAFFLE 1650 12300 2200 1280 38400 4000 9.000 8.250 192.000 6.079 4.375 5.120 2 1.125 11.900 N/A 12.875

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HALLIBURTON DV PACKER COLLARS SAMS No. SA Set No. Size (in) Tool Type HES Set No. Description Pkr (HES P/N) Pkr Description Plug Set (HES P/N) Plug Set Description

Open Press (psi) Open Force (lbs) Inflation (psi) Closing Press (psi) Closing Force (lbs) Pkr Differential (psi) Hole Size (in) Pkr OD (in) Pkr Length (in) Min ID after Drillout (in) Opening Seat ID (in) Closing Seat ID (in) No. of Circl. Ports Size of Ports (in) Recom. Max Hole Size (in) Recom. Min Hole Size (in) Actual Max. Expansion (in)

45-733-930-00 N/A 4.500 ESIPC-H N/A SEE BELOW 813.78010 COLLAR - TYPE H ES INFL PKR - 4-1/2, 8RD, 9.5-11.6# 10 FT PKR - 5.62 OD - SUITABLE F/USE W/K-55 809.50100 & 809.52100 PLUG SET - SR TYPE H - 4-1/2 9.5-13.5# CSG W/3-1/2 (2.00 TO 2.75 ID) DP RELEASING DARTS - W/2-7/8 EUE 8RD SUITABLE F/USE W/K-55TBG BOX THD - F/2.00 MIN ID HANGER SYSTEM ADAPTER - BAFFLE - 4-1/2 8RD 9.5-11.6# - 2.375 ID LATCHDOWN INSERT - 2-STAGE CMTR 1650 6000 2200 1080 13500 4000 1000 5.875 9.000 5.750 276.000 3.985 2.750 3.370 2 0.685 9.000 N/A 10.000

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4.2

Free Fall Plug Set A free-fall plug set is used on most of multi-stage cement jobs. This plug set consists of the following: ♦ ♦ ♦ ♦

Closing Plug (closes the DV ports) Free Fall Opening (opens the DV ports) Shut-Off Plug (acts as top wiper plug on 1st stage cement) Shut-Off Baffle (provides seat for Shut-Off Plug)

T w o -S ta g e F r e e F a ll P lu g S e t w ith B a ffle A d a p te r

Shut-Off Baffle

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4.3

Displacement Type Plug Set A displacement type plug set is used in situations where high mud weight limits the use of free-fall plugs (where fall time may exceed the remaining thickening time of the cement). This plug set consists of the following: ♦ ♦ ♦ ♦

Closing Plug (closes the DV ports) Opening Plug (opens the DV ports) By-Pass Plug (acts as top wiper plug on 1st stage cement) By-Pass Baffle (provides seat for By-Pass Plug and allows for continued circulation until the Opening Plug bumps)

Displacement Type Plug Set

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5.0

CENTRALIZERS The following centralizers are utilized in Saudi Aramco’s drilling operation. These centralizer designs exceed the requirements of API specification 10D for starting and restoring force. Centralizer placement for deviated and horizontal well applications should be calculated using a software program. 5.1

Collapsible The collapsible centralizer is a non-welded, hinge type, bow centralizer. This centralizer is used in all vertical well applications. The centralizer should be positioned around a stop collar in the middle of the desired joint (as opposed to locating the centralizer around the casing coupling).

5.2

Rigid The rigid centralizer is a non-welded, hinge type, rigid bow centralizer. This centralizer is run primarily in the liner lap interval. This centralizer design can provide approximately 100 percent standoff when run inside a cased hole, as in the liner lap application. A stop collar is also recommended for centralizer placement.

5.3

SpiraGlider The spiraglider centralizer is a steel spiralbladed centralizer. This centralizer is required on highly deviated or horizontal wells to improve cement flow and provide maximum standoff from the borehole. The spiraglider system consists of a steel centralizer and two beveled stop collars designed to minimize the running resistance.

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6.0

LINER HANGERS 6.1

Mechanical-Set Liner Hanger The mechanical-set liner hanger is mainly used in vertical or low-angle wellbores. This liner hanger is designed for heavy-duty service and is capable of suspending short as well as long, heavy liners. The tandem cone version (as shown) with staggered slips, provides maximum bypass and heavy load hanging capacity. The increased bypass lessens pressure build-up during the running and cementing operations, which reduces the chance of loss circulation in pressure sensitive formations. The mechanical hanger is set by picking up on the liner and rotating to disengage the J-slot. As the liner is lowered, the springs hold the cage stationary. This allows the barrel to move downward engaging the cones against the slips, which move outward against the casing wall. This liner hanger does not have hold-down slips; consequently, buoyancy must be calculated for short liner applications to avoid the possibility of floating.

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6.2

Hydraulic-Set Liner Hanger The hydraulic-set liner hanger is primarily used in deep, highly deviated, and horizontal well applications. The setting mechanism of the hydro-hanger (as shown) is pressure activated, after a ball is seated in the landing collar. The pressure shears the pins in the setting piston, which pushes the slips up and around the cones. Additional pressure shears the ball-seat in the landing collar, releasing the ball and restoring circulation. The typical shear pin and ball-seat strengths are listed below: Arab-D Deviated Shear Pin Ball-Seat

Shear Pressure 1200 psi 2500 psi

Khuff/Pre-Khuff Shear Pin Ball-Seat

Shear Pressure 2250 psi 3500 psi

This liner hanger also does not have hold-down slips; consequently, buoyancy must be calculated for short liner applications to avoid the possibility of floating.

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6.3

Associated Equipment 6.3.1

Setting Collar/Tieback Sleeve The setting collar/tieback sleeve is a basic releasing collar used to carry the liner into the well. It also provides a receptacle which permits the liner to be extended to a point farther up-hole or to surface.

The setting collar (as shown) is made up on top of the liner hanger. A right-hand releasing thread ensures easy release of the liner setting tool from the setting collar.

The tieback sleeve (as shown) is attached to the setting collar. The receptacle’s polished bore facilitates the entry and seating of the seal nipple, when a tieback is required. The tieback sleeve is provided in optional lengths depending on the well type. The standard lengths for development wells and Khuff/PreKhuff wells are 6 feet and 12 feet respectively.

Tie-Back Sleeve

Setting Collar

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6.3.2

Liner Top Packer The liner top packer combines the basic features of the setting collar with the addition of a pack-off at the top of the liner. The packer provides a secondary mechanical seal against gas migration and prevents well fluids from entering the wellbore in uncemented or poorly cemented liners; thus, creating an effective liner lap seal. The liner top packer is optional in most liner applications but is recommended on liners cemented across an abnormally pressured formation, as the Lower Jilh. The liner top packer (as shown) is mechanically set by applying weight to the top of the packer after releasing the liner setting tool and opening the packer setting dogs. The liner top packer also includes a sleeve (as shown) for future tiebacks.

Tie-Back Sleeve

Packer Element

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6.3.3 Polished Bore Receptacle The polished bore receptacle (PBR) is a seal bore with a honed and coated ID to receive production seals for a packer-less completion. The PBR is made up on top of the liner hanger and below the setting collar/tieback sleeve. The polished bore receptacle (as shown) provides for free tubing movement during production. The use of Teflon coating prevents the cement from sticking to the ID during cementing operations and minimizes seizing of the seals during production. The PBR is primarily used on Khuff/Pre-Khuff wells and is a standard length of 24’.

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6.3.4

Cementing Manifold The cementing manifold provides a means of circulating and cementing the liner. The manifold consists of a swivel and plugdropping head with elevator handling sub. The plug-dropping head facilitates the dropping the drill pipe wiper plug and liner hanger setting ball (if a hydraulic-set liner hanger is utilized). The cementing manifold is provided by the liner hanger company as part of the liner hanger equipment

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CEMENTING 1.0

CEMENT TYPES, SPECIFICATIONS & ADDITIVES 1.1 Cement Types 1.2 Specifications 1.3 Performance of Cement Slurry 1.4 Additive Functions 1.5 Cement Additives

2.0

SLURRY DESIGN 2.1 Factors That Influence Cement Slurry Design 2.2 Limitations of Thickening Time 2.3 Fluid Loss Test 2.3.1 HT/HP Fluid Loss Tests (BHCT190 0F) 2.4 WOC (Waiting on Cement) Time 2.4.1 Ultrasonic Cement Analyzer (UCA Test) 2.4.2 Static Gel Strength Analyzer (SGSA Test) 2.5 Pressurized Mud Balance & Densitometers 2.6 Free Fluid Test 2.7 Rheology Test 2.8 Mud-Spacer-Cement Compatibility Test 2.9 Gas Migration Additives 2.10 Cementing: Pre-Job Considerations for Slurry Design 2.11 Pre-Job Meeting 2.12 Cementing Information Form

3.0

LAB TESTING OF CEMENT 3.1 Types of Tests 3.2 When To Send Samples For Testing 3.3 Initial Pilot Testing 3.4 Pilot Testing prior To Mixing 3.5 Field Sample Confirmation Testing

4.0

MIXING CEMENT 4.1 Mix Water Quality 4.2 Type Of Chemicals And Quantity To Be Blended 4.3 Mix Water Blending And Storage System 4.4 Cement Job Quality 4.5 Pre-Mixing Additives 4.6 Sampling and Sample Sizes 4.6.1 Sample Containers

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4.6.2 4.6.3 4.6.4 4.6.5

Dry Cement Sampling Sampling of Mix Fluid Sample Size for Lab Testing Sample Labeling

5.0

BALANCED PLUGS 5.1 Loss Circulation Plugs 5.2 Kick-Off / Sidetrack Plugs 5.2.1 Kick-Off Plugs 5.2.2 Sidetracking 5.3 Isolation/Abandonment Plugs

6.0

DISPLACEMENT PROCEDURES 6.1 Casing 6.2 Liners 6.3 Turbulent Flow

7.0

REMEDIAL CEMENTING 7.1 7.2

8.0

Bradenhead Squeeze Packer Squeeze

CEMENTING EQUIPMENT (PICTURES)

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CEMENTING The Saudi Aramco Oilwell Cement Lab monitors quality of Class G cement sold to the Company. Cement consignments that fall out of specification are not approved for purchase to Saudi Aramco. The Company cement lab technicians sample and test all cement consignments prior to approving the purchase of any consignment of oilwell cement. It is not the intention of this manual to provide cementing recipes. Cement deteriorates with age. As dry cement ages, moisture collects on the particles and partially hydrates the outside covering of the particle. The physical properties of the cement slurry change when this occurs. Generally the thickening time increases, the free fluid increases and the final compressive strength decreases. Any concerns about Cement or Cement formulations contact Drilling Engineering or the Saudi Aramco Oilwell Cement Lab.

1.0

CEMENT TYPES, SPECIFICATIONS & ADDITIVES 1.1

Cement Types Class G (HSR)* cement is used exclusively in Saudi Aramco operations as the basic oilwell cement. This cement can be blended with many additives to cover a wide range of well conditions. The five normal slurry compositions are as follows: *High Sulfate Resistant CEMENT

Class G Neat Class G +35% Silica Flour Class G + 1.5% Bentonite (Prehydrated), 6.6 Lbs. Gel/bbl Of Mix Water Class G +35% Silica Sand Class G +35% Silica Sand + 5% Expanding Additive A) B)

C)

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SLURRY WEIGHT (PCF) 118 118 101

SLURRY YIELD (FT3/SK) 1.15 1.52 1.69

WATER REQUIREMENT GAL/SK 5.03 6.28 8.96

125 125

1.35 1.40

5.01 5.25

All the above figures refer to a 94 lb sack. Slurry weights listed above are absolute weights. Weight of cement measured from the cement tub in a non-pressurized mud balance may be as much as 15 pcf lighter due to entrapped air. Modifications of the basic slurries will be specified by Drilling Engineering.

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1.2

Specifications API Specification 10A “Specification for Cement and Materials for Well Cementing” is used for the approval of the purchasing of class G (HSR) cement. API Recommended Practice 10B is used for the basic test procedures for the physical testing of cement slurries. Many instruments in the cement lab are not listed in API RP 10B. Procedures for testing cements are located in the labs procedures manual.

1.3

Performance of Cement Slurry Data given for the effectiveness of any additives is only valid for the cement, water and additives used for the test. Different cement brands, and even different production runs of the same brand of cement, react differently to the various additives. When there is any doubt, have the actual job cement, water and cement additives tested. Most cement additives from the various service companies are completely compatible with each other. Testing is always recommended if additives from different service companies are being used. Almost all of Schlumberger/Dowell's products are completely compatible with Halliburton’s and BJ’s products and vice versa. Before making any substitutions, consult with the Cement Lab, Drilling Engineering or the Service Company. Many additives have more than one function. For example, a dispersant (friction reducer) can be added to a slurry design to help make the mixing easier for a class G cement slurry that is mixed at a density greater than 118 pcf. The physical effects of adding the dispersant will be reduced the rheology, and lengthen the thickening times. Lists of the more common cement functions and additives used by Saudi Aramco are included in the following pages:

1.4

Additive Functions: 1.4.1

Retarders The function of retarders is to increase the thickening time (pumping time) of the cement slurry being pumped. Lignosulfonates and their derivatives make up the majority of the cement retarders for use in low and medium temperatures. (80 0F – 220 0F) Higher temperature retarders are composed of Polyhydroxy Organic Acids and sugar derivatives. It has been observed that combinations of low and high temperature retarders are effective in extending thickening times for high temperature applications. High temperature retarders should

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never be used in cements with BHCT lower than 180 0F, unless confirmed by lab tests. 1.4.2

Fluid Loss Additives The function of fluid loss additives is to reduce the water loss from the cement slurry. This class of cement chemicals and gas migration additives are generally the most expensive part of the cementing invoice. If high fluid loss occurs the following can happen: •

•

•

Premature dehydration of slurry, which can cause annulus plugging and incomplete placement of slurry. Changes in slurry flow properties (rheology) and increased slurry density. Damage to production zones by cement filtrate

Most fluid loss additives also retard the thickening time. On the 4 ½” and 7” liner jobs for vertical Arab D wells, no retarder is used. Adequate retardation is produced from the synergetic effects combining the fluid loss additive with the dispersants. 1.4.3

Dispersants (Friction Reducers) The functions of dispersants are: A) to thin the slurry in order to reduce the turbulent flow rate or enable easy mixing of slurry B) to densify cement slurry (increase the solid-to-liquid ratio). C) to aid in fluid loss control. Over dispersing the cement slurry can cause high free fluid and density settling in the cement column. This must be avoided at all times and especially when cementing deviated or horizontal section of the well. Pumping slurry that is not up to the designed weight (density) can easily settle after placement. Pressurized mud balances must be used to confirm correct cement density. Pumping cements that are heavier than the planned density doesn’t cause settling problems. However, the thickening times are generally shorter.

1.4.4

Accelerators The function of accelerators is to reduce the thickening time and decrease the (WOC) time. Calcium Chloride is the most common accelerator used. Calcium Chloride does not increase the final strength of cement and may perhaps lower the final compressive strength a little. Most fluid loss additives do not work well with Calcium

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Chloride in the cement slurry. Sodium Silicate is recommended if low fluid loss is required with fluid loss control in most cases. Special mixing is required for sodium silicate slurries 1) if accelerator is used then the accelerator must be added first. 2) if a retarder is to be used then the Sodium Silicate should be added first and the retarder must be added last. 1.4.5

Non-Foamers The function of non-foamer (defoamers) in cement slurry is to release trapped air in the slurry as it is being mixed. Entrapped air cause viscosity increases, which make the cement slurry more difficult to mix. Entrapped air also makes the density of the slurry more difficult to measure. Special non-foamer are used for Latex cement slurries. The addition of excess non-foamer may stabilize foam. Bentonite cement slurries usually require twice as much non-foamer than conventional cements. Latex cements may require as much as five times more non-foamer than conventional cement slurries.

1.4.6

Strength Retrogression Preventers The function of silica flour and silica sand in cement is to prevent strength retrogression of the set cement. Exposure temperatures of 250 0F to 300 0F require 25% silica flour or silica sand by weight of cement. When cement is exposed to temperatures from 300 0F to 450 0 F, 35% silica flour or silica sand is required. At temperatures above 450 0F only silica flour should used. Service companies recommend 35% silica at temperatures over 235 0F. This recommendation is conservative with built in safety factors for improper blending ratios of cement-silica flour and inaccurate temperature data.

1.4.7

Heavy Weight Additives The function of Heavy weight additives is to increase the slurry density above the level that can be achieved with dispersants. The maximum density achievable with Saudi Class G cement + dispersant is 130-135 pcf. Hematite (a form of Iron Oxide) is normally used to densify cement. The highest density cement pumped in Saudi Aramco is 170 pcf using 185% Hematite. MicroMax, (Manganese tetraoxide), a relatively new product, is available for increasing the density of cement slurries. This product has a lower specific gravity than Hematite but is spherical and small in size. It has two primary advantages 1) it is ground small (less than 1 micron) which allows it to

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be blended in the mix water, and 2) it is spherical which makes the gel strengths much lower, thus reducing the viscosity. 1.4.8

Gas Migration Additives The function of Gas migration additives is to help prevent fluids (gasses & Liquids) from migrating to the surface during the loss of hydrostatic pressure that occurs prior to the setting of cement. The most popular additive is Liquid Latex. Latex provides low fluid loss to the slurry and lower initial permeability to the set cement. Expanding additives are often included in the slurry design to reverse any shrinkage that occurs during the setting of cement. Special mixing instruction for latex systems: add the stabilizer to the water after the bactericide but prior to any other cement additives.

1.4.9

Extenders The function of the extenders is 1) to decrease the slurry density or 2) to increase the slurry yield decreasing the total cost. Pre-hydrated Bentonite is the best example of cost saving of a neat cement slurry. However, if low fluid loss is required, the cement can become more expensive as the increased water in the system requires more chemicals to prevent it from escaping from the slurry. Sodium Silicates have also been used to lower the density of cement but are more expensive than pre-hydrated Bentonite. Foam cement and Micro spheres have been utilized with limited success.

1.4.10 Expanding Additives The function of expanding additives is to increase the bonding strength of the set cement. After cement goes through hydration reaction, the cement shrinks. Expanding additives primarily MgO and CaO or combinations of the two are dry blended in cement to take the set cement out of shrinkage and provide up to 2.5% expansion. This expansion may take up to two weeks to reach completion. Salt (NaCl) is not recommended as an expansion additive in cement due to the higher permeability that high concentrations of salt in cement produce. On the other hand MgO and CaO are not as water soluble as NaCl and provide a lower permeability once the cement has set.

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1.4.11 Bactericide The function of the Bactericide (biocide) is to kill significant quantities of bacteria in the cement mixing fluid to prevent chemical degradation of cement additives. Bacteria reproduce exponentially and if not controlled will reduce the cement additives to an ineffective level.

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DRILLING PRACTICES

D

CEMENTING

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1.5

Cement Additives:

HALLIBURTON CEMENT ADDITIVES RETARDERS Name

Temp. range 172 0F, BHCT

Normal concentration Up to 1.0%, BWOC

Mixing procedure Added to mix water or dry blended

Packing

Comments

50 lb. sack

HR-5

220 0F, BHCT

Up to 1.0%, BWOC

Added to mix water or dry blended

50 lb. sack

Can be added to cement containing high temp. retarder to extend thickening time. Can be added to cement containing high temp. retarder to extend thickening time

HR-12

320 0F, BHCT

Up to 2.0%, BWOC

50 lb. sack

HR-15

380 0F, BHCT

Up to 2.5%, BWOC

TB-41

250 - 450 0F, BHCT

Up to 3.0%, BWOC

Compon ent R

250 - 450 0F, BHCT

Up to 3.0%, BWOC

Added to mix water or dry blended Added to mix water or dry blended Added to mix water or dry blended Added to mix water or dry blended

HR-4

50 lb. sack 50 lb. sack 50 lb. sack

Added with high temp. retarders to extend thickening time. Added with high temp. retarders to extend thickening time.

FLUID LOSS ADDITIVES Name

Temp. range 125 0F 0 360 F

Normal concentration Up to 1.5%, BWOC

Halad-322

Up to 180 0F

Up to 1.5%, BWOC

Halad-344

Up to 330 0F

Up to 1.0%, BWOC

Halad-413

80 0F 400 0F

Up to 3.0%, BWOC

Halad-22A

Mixing procedure Added to mix water or dry blended Added to mix water or dry blended Added to mix water or dry blended Added to mix water or dry blended

Packing

Comments

50 lb. sack 50 lb. sack 50 lb. sack 50 lb. sack

DISPERSANTS (Friction Reducers) Name CFR-3

8 of 48

Temp. range Up to 350 0 F

Normal concentration Up to 1.0%, BWOC

Mixing procedure Added to mix water or dry blended

Packing

Comments

50 lb. sack

Can be used to help increase the density of cement.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2

DRILLING PRACTICES

D

SECTION

June 2006

CEMENTING

___________________________________________________________________________________________________________________________

HALLIBURTON CEMENT ADDITIVES (continued) ACCELERATORS Name CaCl2

CAL-SEAL LIQUID ECONOLITE NaCl

Temp. range Up to 120 0F

Normal concentration Up to 2.0%, BWOC

Up to 170 0F Up to 200 0F Up to 0 360 F

Up to 90.0%, BWOC Up to 1.0 GPS

Mixing procedure Added to mix water or dry blended dry blended Added to mix water Added to mix water or dry blended

Up to 5.0%, BWOC

Packing

Comments

100 lb. sack 100 lb. sack 52 gallon drum 80 lb. sack

Sodium Chloride

NON-FOAMERS Name NF-1 D-AIR-3

Temp. range Up to 500 0F Up to 500 0F

Normal concentration 1 PT/10 BBLS 0.02 GPS - 0.20 GPS

Mixing procedure Added to mix water Added to mix water

Packing

Comments

5 gallon can 54 gallon drum

2 PT/10 BBLS IN BENTONITE SLURRIES 5 PT/10 BBLS IN LATEX SLURRIES

STRENGTH RETROGRESSION PREVENTERS Name

Temp. range

SSA-1

250 0F – 700 0F

SSA-2

250 0F – 700 0F

Normal concentration 25%-100%, BWOC 25%-100%, BWOC

Mixing procedure dry blended dry blended

Packing

Comments

100 lb. sack 100 lb. sack

Silica Flour Silica Sand

HEAVY WEIGHT ADDITIVES Name Hi-Dense No.4

Temp. range Up to 500 0 F

Micro-Max

Up to 500 0 F

Hi-Dense No.3

Up to 500 0 F

Normal concentration Depends on required slurry density Depends on required slurry density Depends on required slurry density

Mixing procedure dry blended

Packing

Comments

100 lb. sack

Hematite

Added to mix water or dry blended dry blended

1,500 lb. Big Bag

Soluble in HCl

100 lb. sack

Hematite

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

June 2006

DRILLING PRACTICES

D

CEMENTING

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HALLIBURTON CEMENT ADDITIVES (continued) GAS MIGRATION ADDITIVES Name Latex 2000 Stabilizer 434B

Versa-SET

Temp. range Up to 400 0 F Up to 320 0 F

Normal concentration 0.5 – 3.0 GPS

Up to 140 F

Up to 2.0%, BWOC

0

0.05 – 0.5 GPS

Mixing procedure Added to mix water Added to mix water

Packing

Comments

54 gal drum 5 gal can

Order of mixing critical Order of mixing critical, Does not tolerate Salt

Added to mix water or dry blended

50 lb. bags

Mixing procedure Added to mix water

Packing

Comments

1.5 ton super sacks 52 gallon drum

Wyoming Bentonite, Nonbenificiated Order of mixing critical

EXTENDERS (LIGHT WEIGHT ADDITIVES) Name Bentonite (PH)

Liquid Econolite

Temp. range Up to 400 0 F Up to 200 0 F

Normal concentration Up to 6.0%, BWOC, when prehydrated Up to 1.0 GPS

Added to mix water

EXPANDING ADDITIVES Name MICROBO ND-HT

Temp. range Up to 350 0F

Normal concentration Up to 10.0%, BWOC

Mixing procedure dry blended

Packing

Comments

50 lb. sack

Normal concentration 5.0%

Mixing procedure Added to mix water Added to mix water

Packing

Comments

5 gal can

Add to tank prior to filling with water

BACTERIACIDES Name BE-3 BE-6

10 of 48

Temp. range Up to 120 0F Up to 120 0F

Normal concentration 0.5 gal/1000 gals 1 lb/500 bbls

1 lb bag

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

June 2006

DRILLING PRACTICES

D

CEMENTING

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SCHLUMBERGER / DOWELL CEMENT ADDITIVES RETARDERS Name

Normal concentration Up to 0.25GPS

Mixing procedure Added to mix water

Packing

Comments

D-81

Temp. range Up to 0 180 F, BHCT

5 gal. can

Liquid version of D-13. Can be added to cement containing high temp. retarder to extend thickening time.

D-800

250 0F, BHCT

Up to 2.0%, BWOC

50 lb. sack

D-801

250 0F, BHCT

Up to 0.5 gps

Added to mix water or dry blended Added to mix water

D-109

175 - 300 0F, BHCT 200 - 400 0F, BHCT

Up to 0.5 gps

5 gal. can

250 - 450 0F, BHCT

Up to 3.0%, BWOC

Added to mix water Added to mix water or dry blended Added to mix water or dry blended

D-28

D-93

Up to 2.5%, BWOC

5 gal. can

Liquid version of D-800. Can be added to cement containing high temp. retarder to extend thickening time.

50 lb. sack 50 lb. sack

Added with high temp. retarders to extend thickening time.

FLUID LOSS ADDITIVES Name D-60

D-112

D-604 AM D-900

Temp. range Up to 200 0F, BHCT Up to 200 0F, BHCT 120 0F – 250 0F Up to 400 0F, BHCT

Normal concentration Up to 1.5%, BWOC Up to 1.5%, BWOC Up to 1.0 gps Up to 0.8%, BWOC

Mixing procedure Added to mix water or dry blended Added to mix water or dry blended Added to mix water Added to mix water or dry blended

Packing

Comments

50 lb. sack

For use water

50 lb. sack

For low density slurries, good in sat. Salt & f. H2O strong dispersant

8 gal. cans 50 lb. sack

in

fresh

H.T. Fluid Loss Additive

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

D

June 2006

DRILLING PRACTICES CEMENTING

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SCHLUMBERGER / DOWELL CEMENT ADDITIVES (continued) DISPERSANTS (Friction Reducers) Name

Temp. range

D-80

Up to 350 0F

D-606

Up to 400 0F

D-135

Up to 375 0F

Normal concentration Up to 0.4 gps Up to 1.0%, BWOC Up to 0.3 gps

Mixing procedure Added to mix water Added to mix water Added to mix water

Packing

Comments

8 gal. cans 50 lb. sack 5 gal. cans

Liquid D-65 Sodium Sulfate Stabilizer for D-600

ACCELERATORS Name CaCl2

Temp. range Up to 100 0F

Normal concentration Up to 2.0%, BWOC

D-53

Up to 100 0F

D-75

Up to 200 0F

Up to 10.0%, BWOC Up to 1.0 GPS

NaCl

Up to 360 0F

Up to 5.0%, BWOC

Mixing procedure Added to mix water or dry blended dry blended Added to mix water Added to mix water or dry blended

Packing

Comments

100 lb. sack

Calcium Chloride

50 KG sack 52 gallon drum 50 Kg. sack

Order of mixing is critical Sodium Chloride

NON-FOAMERS Name D-47 D-144

Temp. range Up to 0 500 F Up to 500 0F

Normal concentration 1 PT/10 BBLS 2 PT/10 BBLS

Mixing procedure Added to mix water Added to mix water

Packing

Comments

5 gallon can 5 gallon can

2 PT/10 BBLS IN BENTONITE SLURRIES 5 PT/10 BBLS IN LATEX SLURRIES

Packing

Comments

100 lb. sack 100 lb. sack

Silica Flour

STRENGTH RETROGRESSION PREVENTERS Name

Temp. range

D-66

250 0F – 500 0F

D-30

250 0F – 500 0F

12 of 48

Normal concentration 25%-100%, BWOC 25%-100%, BWOC

Mixing procedure dry blended dry blended

Silica Sand

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

June 2006

DRILLING PRACTICES

D

CEMENTING

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SCHLUMBERGER / DOWELL CEMENT ADDITIVES (continued) HEAVY WEIGHT ADDITIVES Name D-76

Temp. range Up to 500 0F

Micro-Max

Up to 0 500 F

D-76.1

Up to 0 500 F

Normal concentration Depends on required slurry density Depends on required slurry density Depends on required slurry density

Mixing procedure dry blended

Packing

Comments

100 lb. sack

Hematite (Fe3O4)

Added to mix water or dry blended dry blended

100 lb. sack

Soluble in HCl

100 lb. sack

Ferrosilicon

GAS MIGRATION ADDITIVES Name

Temp. range

D-600

Up to 400 0F

Normal concentration 0.9 – 2.5 GPS

D-135

Up to 400 0F

0.1 – 0.25 GPS

D-500

Up to 200 0F

0.9 – 2.5 GPS

Mixing procedure Added to mix water Added to mix water Added to mix water

Packing

Comments

55 gal drum

Gas Block, Order of mixing critical Gas Block Stabilizer Order of mixing critical Low Temp. Gas Block (Cem-Seal)

5 gal can 55 gal drum

EXTENDERS (LIGHT WEIGHT ADDITIVES) Name

Temp. range

D-20

Up to 400 0F

D-75

Up to 200 0F

Normal concentration Up to 6.0%, BWOC, when prehydrated Up to 1.0 GPS

Mixing procedure Added to mix water Added to mix water

Packing

Comments

1.5 ton super sacks 52 gallon drum

Bentonite (PH) Order of mixing critical

EXPANDING ADDITIVES Name B-82

Temp. range Up to 0 350 F

Normal concentration Up to 10.0%, BWOC

Mixing procedure dry blended

Packing

Comments

50 lb. sack

Normal concentration 5.0%

BACTERIACIDES Name M-290

Temp. range Up to 0 120 F

Normal concentration 0.5 gal/1000 gals

Mixing procedure Added to mix water

Packing

Comments

5 gal can

Add to tank prior to filling with water

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

June 2006

DRILLING PRACTICES

D

CEMENTING

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BJ SERVICES CEMENT ADDITIVES RETARDERS Name

Normal concentration Up to 1.0%, BWOC

Mixing procedure Added to mix water or dry blended

Packing

Comments

R-3

Temp. range Up to 210 0F, BHCT

50 lb. sack

Can be added to cement containing high temp. retarder to extend thickening time.

R-8

200 - 400 0F, BHCT

Up to 2.5%, BWOC

50 lb. sack

R-9

250 - 450 0F, BHCT

Up to 3.0%, BWOC

Added to mix water or dry blended Added to mix water or dry blended

50 lb. sack

Added with high temp. retarders to extend thickening time.

FLUID LOSS ADDITIVES Name FL-25

BA-10

Temp. range Up to 200 0F, BHCT Up to 240 0F, BHCT

Normal concentration Up to 1.5%, BWOC Up to 2.0%, BWOC

Mixing procedure Added to mix water or dry blended Added to mix water or dry blended

Packing

Comments

50 lb. sack

For use in fresh water

50 lb. sack

For low density slurries, good in sat. Salt & f. H2O

DISPERSANTS (Friction Reducers) Name CD-32

Temp. range Up to 350 0 F

Normal concentration Up to 2.0%, BWOC

Mixing procedure Added to mix water

Packing

Comments

8 gal. cans

Liquid D-65

ACCELERATORS Name A-7

A-10 A-3L A-5

14 of 48

Temp. range Up to 100 0F

Normal concentration Up to 2.0%, BWOC

Up to 100 0F Up to 200 0F Up to 360 0F

Up to 10.0%, BWOC Up to 1.0 GPS Up to 5.0%, BWOC

Mixing procedure Added to mix water or dry blended dry blended Added to mix water Added to mix water or dry blended

Packing

Comments

100 lb. sack

Calcium Chloride

50 KG sack 52 gallon drum 50 Kg. sack

Gypsum cement Order of mixing is critical Sodium Chloride

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

June 2006

DRILLING PRACTICES

D

CEMENTING

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BJ SERVICES CEMENT ADDITIVES (continued) NON-FOAMERS Name FP-6L FP-9L FP-12L

Temp. range Up to 500 0F Up to 500 0F Up to 0 500 F

Normal concentration 1 PT/10 BBLS 2 PT/10 BBLS 2 PT/10 BBLS

Mixing procedure Added to mix water Added to mix water Added to mix water

Packing

Comments

55 gal. drum 55 gal. drum 55 gal. drum

2 PT/10 BBLS IN BENTONITE SLURRIES 5 PT/10 BBLS IN LATEX SLURRIES 5 PT/10 BBLS IN LATEX SLURRIES

Packing

Comments

100 lb. sack 100 lb. sack

Silica Flour

STRENGTH RETROGRESSION PREVENTERS Name

Temp. range

S-8

250 0F – 500 0F

S-8C

250 0F – 500 0F

Normal concentration 25%-100%, BWOC 25%-100%, BWOC

Mixing procedure dry blended dry blended

Silica Sand

HEAVY WEIGHT ADDITIVES Name

Temp. range

W-5

Up to 500 0F

Micro-Max

Up to 500 0F

Normal concentration Depends on required slurry density Depends on required slurry density

Mixing procedure dry blended

Packing

Comments

100 lb. sack

Hematite (Fe3O4)

Added to mix water or dry blended

1,500 lb. Big Bag

Soluble in HCl

GAS MIGRATION ADDITIVES Name BA-86L

Temp. range Up to 400 0F

Normal concentration 1.0 – 3.0 GPS

LS-1

Up to 400 0F

0.1 – 0.35 GPS

Mixing procedure Added to mix water Added to mix water

Packing

Comments

55 gal drum 5 gal can

order of mixing critical B-86L stabilizer, order of mixing critical

EXTENDERS (LIGHT WEIGHT ADDITIVES) Name

Temp. range

Bentonite (PH)

Up to 400 0F

Sodium Silicate

Up to 200 0F

Normal concentration Up to 6.0%, BWOC, when prehydrated Up to 1.0 GPS

Mixing procedure Added to mix water

Packing

Added to mix water

55 gallon drum

Comments

1.5 ton super sacks Order of mixing critical

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

June 2006

DRILLING PRACTICES

D

CEMENTING

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BJ SERVICES CEMENT ADDITIVES (continued) EXPANDING ADDITIVES Name EC-2

Temp. range Up to 350 0F

Normal concentration Up to 10.0%, BWOC

Mixing procedure dry blended

Packing

Comments

50 lb. sack

Normal concentration 5.0%

BACTERIACIDES Name X-CID

16 of 48

Temp. range Up to 0 120 F

Normal concentration 1 lb/100 bbls

Mixing procedure

Packing

Added to mix water

6 lb can

Comments

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

June 2006

DRILLING PRACTICES

D

CEMENTING

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NOWMCO CEMENT ADDITIVES RETARDERS Name NR-1

NR-5

Temp. range Up to 200 0F, BHCT 200 - 350 0F, BHCT

Normal concentration Up to 1.0%, BWOC Up to 2.5%, BWOC

Mixing procedure Added to mix water or dry blended Added to mix water or dry blended

Packing

Comments

50 lb. sack 50 lb. sack

FLUID LOSS ADDITIVES Name NFC-3

NFC-4

Temp. range Up to 220 0F, BHCT Up to 0 220 F, BHCT

Normal concentration Up to 2.0%, BWOC Up to 2.0%, BWOC

Mixing procedure Added to mix water or dry blended Added to mix water or dry blended

Packing

Comments

50 lb. sack 50 lb. sack

DISPERSANTS (Friction Reducers) Name DFR-1

Temp. range Up to 350 0 F

Normal concentration Up to 2.0%, BWOC

Mixing procedure Added to mix water

Packing

Comments

50 lb. sack

ACCELERATORS Name CaCl2

DAL-1 SODIUM SILICATE SALT

Temp. range Up to 100 0F

Normal concentration Up to 2.0%, BWOC

Up to 100 0F Up to 200 0F Up to 360 0F

Up to 10.0%, BWOC Up to 1.0 GPS Up to 5.0%, BWOC

Mixing procedure Added to mix water or dry blended dry blended Added to mix water Added to mix water or dry blended

Packing

Comments

100 lb. sack

Calcium Chloride

50 KG sack 52 gallon drum 50 Kg. sack

Gypsum cement

Packing

Comments

5 gal can

2 PT/10 BBLS IN BENTONITE SLURRIES

Order of mixing is critical Sodium Chloride

NON-FOAMERS Name DAF-1

Temp. range Up to 0 500 F

Normal concentration 1 PT/10 BBLS

Mixing procedure Added to mix water

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Drilling & Workover Engineering Department CHAPTER 2 SECTION

D

June 2006

DRILLING PRACTICES CEMENTING

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NOWMCO CEMENT ADDITIVES (continued) STRENGTH RETROGRESSION PREVENTERS Name

Temp. range

SFA200 SFA100

250 0F – 500 0F 250 0F – 500 0F

Normal concentration 25%-100%, BWOC 25%-100%, BWOC

Mixing procedure dry blended dry blended

Packing

Comments

100 lb. sack 100 lb. sack

Silica Flour Silica Sand

HEAVY WEIGHT ADDITIVES Name

Temp. range

Hematite

Up to 500 0F

Normal concentration Depends on required slurry density

Mixing procedure dry blended

Packing

Comments

100 lb. sack

Hematite (Fe3O4)

EXTENDERS (LIGHT WEIGHT ADDITIVES) Name

Temp. range

Bentonite (PH)

Up to 400 0F

Sodium Silicate

Up to 200 0F

18 of 48

Normal concentration Up to 6.0%, BWOC, when prehydrated Up to 1.0 GPS

Mixing procedure Added to mix water

Packing

Added to mix water

55 gallon drum

Comments

1.5 ton super sack NOWCHECK, Order of mixing is critical

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

D

June 2006

DRILLING PRACTICES CEMENTING

___________________________________________________________________________________________________________________________

2.0

SLURRY DESIGN 2.1

Factors That Influence Cement Slurry Design Lab tests are run prior to pumping cement in a well. Collecting accurate data prior to designing the cement ensures a good cement design. The following factors will effect the cement slurry design: • • • • • • • • • • • •

2.2

Well depth Well temperature Mud column pressure Viscosity and water content of cement slurry Strength of cement require to support the pipe Quality of available mixing water Type of mud & density Slurry density Cement shrinkage Permeability of set cement Fluid loss requirements Resistance to corrosive fluids

Limitations of Thickening Time Test Data The thickening time test is a dynamic test. While the cement slurry is being tested, measurements are being made of the consistency (viscosity) under downhole circulating conditions. The thickening time test does not give information on how the cement slurry performs under down hole static conditions. The thickening time test does not give useful information on the following: • • • •

The setting profile of the cement after the plug is bumped. The compressive strength of the cement. How the fluid loss to the formation affects the cement slurry. How long the cement will be pumpable during a shutdown. This is different for each cement slurry and the particular well conditions.

To determine theses parameters, tests that simulate the slurry’s environment under static/dynamic conditions must be performed.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

D

June 2006

DRILLING PRACTICES CEMENTING

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Typical Thickening Time 120 100 80

Temp deg F Pres. psi

60

Cons. Bc

40

1:50

1:42

1:34

1:25

1:17

1:09

1:01

0:53

0:45

0:36

0:28

0:20

0

0:00

20

Time (HRS:MINS) Shown above is a typical thickening time curve for Class G cement + 1% CaCl2 @ 118 pcf, 0 a BHCT of 100 F. When the consistency reaches 100 Bc the thickening time is terminated.

The Aramco Oilwell Cement lab has five HT/HP Consistometers for the determination of thickening time.

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Drilling & Workover Engineering Department CHAPTER 2 SECTION

D

June 2006

DRILLING PRACTICES CEMENTING

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2.3

Fluid Loss Tests Cement is like drilling mud in some aspects, as it is a suspension of solids. Chemical reactions occur on the surface of the solid particles of cement after water has been added. The rate that a cement slurry loses water through a high permeability zone under pressure is called fluid loss or filtration rate. The water that is lost from the slurry does not give the cementing properties that were originally designed. When water is lost from the cement slurry, the slurry property’s change: • Viscosity increases which increases friction or pump pressures. – High loss of water will result in a highly viscous cement slurry which is unpumpable. • Thickening time decreases • Higher solids to liquid ratio – cement bridges may form in areas of narrow clearances The water that is lost from the cement slurry will have higher compressive strengths. High fluid loss cement slurries can be used when squeezing high injection rate leaks or perforations. Two types of tests are preformed for cement slurries. 1) HT/HP Fluid loss test and 2) Stirred fluid loss test. The permeable medium for both tests is a 325 mesh screen. 2.3.1

HT/HP Fluid Loss Tests (BHCT190 0F) The cement slurry is condition in the test apparatus at bottom-hole circulating temperature and 1100 psi. The cell is then rotated 180 degrees and the test cement slurry falls on to the 325 mesh screen. Back pressure (100 psi) is maintained through out the testing period. The filtrate collected is used to calculate the fluid loss. Cements tested with the Stirred fluid loss cell generally give higher fluid loss values as compared to the same cements tested on the HT/HP fluid loss cell.

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DRILLING PRACTICES CEMENTING

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The stirred fluid loss cell gives more accurate fluid loss values than the conventional fluid loss test.

2.4

WOC Time The industry accepts a compressive strength of 500 psi for drilling out the casing shoe. This is also true for testing and drilling out the top of the liner. On Arab-D wells, where the top of the liner is shallow and the cement density is low the 500 psi compressive strength may take up to 10 hours to develop. On deep gas wells with long liners, up to 30 hours may be required for the cement to develop 500 psi compressive strength. 2.4.1

Ultrasonic Cement Analyzer (UCA Test) The UCA is a non-destructive test that gives sonic (compressive) strength data as a function of time. This test is usually run for 24 hours. The test is run for longer periods of time depending on the setting profile of the cement. The most important use of the data from the UCA is WOC (waiting on cement) time. It should be noted that this test uses uncontaminated cement slurry unless otherwise specified. Mud contamination in cement slurries can either shorten or lengthen the initial set of the cement. Mud contamination also reduces the final compressive strength.

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D

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DRILLING PRACTICES CEMENTING

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ULTRASONIC CEMENT ANALYZER 3000 2000 1000 0 0

50

100

150

TIME (HOURS) Shown above is the compressive strength of a 7” liner jobs for a Khuff gas well

2.4.2

Static Gel Strength Analyzer (SGSA Test) The SGSA/UCA is a non-destructive test that gives static gel strength & sonic (compressive) strength data as a function of time. The most important use of the data from the SGSA are 1) the time that the cement slurry begins to gel (zero gel) and the time that the slurry reaches a gel strength of 1200 lb/100 ft2 (maximum gel) and 2) sonic strength which WOC (waiting on cement) time is determined. Hydrostatic pressure from the cement slurry is being lost at the Zero Gel point. At the maximum gel point the cement is so thick that fluids (including gases) can not pass through the cement column. For gas and fluid migration control, the shorter the time between zero gel and maximum gel the better the chance for preventing migration of downhole fluids through annulus to surface. Some literature states that gel strength of 500 lb/100 ft2 is the point that gas leakage can be contained. It should also be noted that this test uses uncontaminated cement slurry unless otherwise specified.

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DRILLING PRACTICES CEMENTING

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SGSA/UCA Data 3500 Temperature (°F)

2800

ZERO GEL

2100 1400

Static Gel Strength (lb/100ft2)

MAX GEL

700

Compressive Strength (psi) 15:54

14:08

12:22

10:36

8:50

7:04

5:18

3:32

1:46

0:00

0

Time

This Static gel strength data is for a 150 pcf cement used to cement across abnormal pressure Jilh formation

The Saudi Aramco Oilwell Cement lab has three SGSA/UCA units for the determination of static gel strength.

2.5

Pressurized Mud Balance & Densitometers A pressurized fluid density balance is used to monitor the density of cement slurry that is mixed in the field. Non-pressurized fluid

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density balances (mud balance) should be avoided as errors of up to 15 pcf can occur due to entrapped air in the cement slurry. The pressurized density balance greatly reduces the volume of trapped in the slurry. High density cement slurries that are mixed with latex additives tend to trap more air than conventional cements. A pressurized fluid density balance should be used to calibrate any densitometers on the cementing units. Calibration should be made at two densities. It is recommended to calibrate the densitometer at the cement density and either the spacer or mud density. Once the calibration is complete, it should not be re-adjusted before or during the cement job unless confirmed by the pressurized density balance. The densitometers should be placed on the pressure side of pumps to guaranty accurate density measurements.

Pressurized Mud Balance

2.6

Free Fluid Test (free water) If excess water is added to the cement beyond the requirement for fluidity or chemical reaction the solid particles separate from the slurry leaving the lighter excess water on top. This excess fluid is called free fluid. Neat class G cement mixed at 118 pcf should have a maximum free fluid of 1.4% according to API Spec 10A, Specification for Cements and Materials for Well Cementing, 22nd Edition, January 1995.

2.7

Rheology Test Measuring the rheological properties of a cement slurry provide information of the cement slurry’s flow properties and settling tendency. The Fann model 35 rotational viscometer is the most widely used instrument used for determination of rheological properties for well cements. The rheological model is first determined from the Fann readings. Two models are considered for cement slurries (Power Law and Bingham Plastic). Turbulent flow is more easily achieved if n’ (power law) approaches 1 and YP (Bingham Plastic) approaches 0 or negative. Density settling is possible if n’ >1.0 or if YP 2200F • Khuff wells: K2 wells, 13 3/8” casing and deeper, • K1 wells, 9 5/8” casings and deeper • All CTU Cement Jobs • Abnormal well conditions that may adversely affect the cement job. • Remote locations * *For remote locations, cement and rig water should be sent to Saudi Aramco and Service Company labs at least three days before the cement job.

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3.3

Initial Pilot Testing This test is performed on lab cement, raw water (rig water if in stock) and lab additives. The most recent batch of cement from the factory is used to perform these tests. The standard tests are carried out. The most important function of performing this test is to save lab and rig time. Lab tests are performed to determine the retarder and fluid loss additive concentrations to meet the thickening time and fluid loss requirements. Pilot tests are not always performed prior to the writing of the program. Database searches are usually a good starting point in the design of the cement slurry.

3.4

Pilot Testing prior To Mixing Samples of rig cement blend and rig water are collected and tested for the critical physical properties. This test is used to compare test results from the Aramco oilwell cement lab with the Service company’s lab. When comparing the thickening time results of both labs the following rule should apply: The thickening time results that have the highest concentration of retarder for the shortest acceptable thickening time is the cement formulation that should be mixed in the field. This applies only if all other tests like fluid loss, compressive strength development, etc. are within the requirements set by Drilling Engineering. These requirements are usually listed on the drilling program.

3.5

Field Sample Confirmation Testing Samples of cement blend and mixing fluid (water plus cement additives) are sent in by the Service Company to both Saudi Aramco and service company oilwell cement labs. The results are usually faxed to the rig as soon as the thickening time is finished. The compressive strength data is usually sent the next day. For sample sizes see section 4.6.

4.0

MIXING CEMENT The most important cement slurry property that can be measure in the field is slurry density. All lab tests are performed at the designed slurry density. Variation in slurry density in the field will produce cement slurry that may be unpredictable with respect to thickening time, fluid loss, rheology, free fluid, settling, static gel strength and compressive strength. The pressurized density balance is the best device readily available to field personnel to measure cement density. Batch mixing is the most effective way to ensure accurate slurry density.

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4.1

Mix Water Quality The water used as pre-blended cement mix water should be reasonably fresh. If the water is too hard (high Calcium & Magnesium concentration) then alternative sources of water should be located. If the proposed water is high in Chloride then alternative sources of water should be located. If no acceptable water can be found send a sample of the proposed water to the cement lab and a softening treatment can be recommended in most cases. Softening treatments usually include adding Soda Ash and or Caustic causing a heavy white precipitate to settle to the bottom of the tank. The clear water should be skimmed off the top after the precipitate has settled to the bottom of the tank. Sometimes there are exceptions to this rule and they should be clearly defined in the drilling program. Biocide should be added to all mix waters that contain retarders, friction reducers or fluid loss additives. If any mix water is questionable then verify that such water is acceptable with the Drilling Superintendent / Engineer / Oilwell cement lab prior to blending chemicals.

4.2

Type of Chemicals and Quantity to Be Blended The type of chemicals and quantity to be blended in the mix water will be specified in the drilling program or separate cementing procedure (supplement to the program) based on lab data. Mix those chemicals in the water on location. This allows an "on site" check of the water quality and type and quantity of chemicals blended. The Drilling Foreman is personally responsible for confirming that the proper types and amounts of chemicals and water are utilized in preparing the "mix water” blend.

4.3 Mix Water Blending and Storage System Mix water must at all times be completely isolated from any source of contamination. The fluid handling system used to blend and pump the cement mix water should be completely isolated from all other fluid systems. A common manifold for the pre-flush, mix water, wash water and mud systems is not acceptable. It is acceptable to utilize a manifold for other fluids than cement mix water; i.e., pre-flush, wash water and mud. An individual fluid handling system of tanks and lines to the cementing unit is necessary for the mix water system. This will usually involve rigging up special lines and tanks. Rig up as necessary to achieve the above.

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4.4

Cement Job Quality The preparation work prior to performing a complicated cement job is crucial to the success of the cement job. Batch Mix cement when possible. This gives you a positive check of the total batch of cement slurry before it goes downhole. On large jobs (where you can't batch mix), mix and pump a small amount to the desert before pumping cement downhole. This short 'pump test' will exercise the pump system and prove that the system can blend cement slurry with the fluid properties and weight desired. On large critical jobs, where one particular service company does not have the sufficient batch mixing capacity, employ the use of other service company batch mixers. It is recommended that only one Service Company pump the cement job. The Foreman should completely satisfy any question he might have regarding the mechanical reliability of the equipment, cementing technique to be used, mix water blend and mix water system reliability, well conditions, etc. before mixing cement. Don't hesitate to discuss any question with the Drilling Superintendent and eliminate as many problem areas as possible.

4.5

Pre-mixing additives The tanks that the mixing fluid will be stored should be clean. Lines filling the tank should be flushed if used for purposes other than transporting water. Liquid Bactericide (biocide) should be poured on the bottom of the tank prior to filling the tank. Most resident bacteria colonies will be on the tank bottom. Bacteria thrive on cement chemicals like retarders, fluid loss additives and dispersants. Fill the tank with water. Mixing water should be cool. If Wasia water is used, it must be allowed to cool in open tanks for at least 24 hours. Past experience has indicated that many 'flash sets' were the direct result of using a Hot, saline water. The calcium & chloride content of the mixing water should be checked prior to mixing. Temperature, calcium and chloride content of the mix water should be recorded. Biocides generally have short half-lives. Additional biocide should be added every eight hour during the hotter months (April through October). During the cooler months (November through March) add biocide every 12 hours. Check with the Service Company or the Aramco cement lab for proper order of addition of cement chemicals prior to pre-mixing additives to the water.

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4.6

Sampling and Sample sizes 4.6.1

Sample Containers All sample containers should be clean and free of moisture. The sample containers for dry cement should be air tight. The sample containers for water and the mixing fluid should be leak proof. Saudi Aramco Material Stock number (25-008-865) One-gallon wide mouth plastic bottles are good for both dry cement and mix fluid.

4.6.2

Dry Cement Sampling For sampling dry cement either of two methods are acceptable. 1) First Aerate the cement for five to ten minutes, then open the hatch on the bulk storage unit and sample the cement blend approximately one foot (12”) below the top level. 2) Pressurize the bulk storage unit, then blow out a volume of cement that would represent the volume left in the line, then catch the required sample of dry cement.

4.6.3

Sampling of Mix Fluid After all the cement additives have been mixed in the water, continue to circulate the fluid for thirty minutes. At this point sample the fluid from the top of the tank. Do not sample from a valve. If any fisheyes (dry additive that have gelled due to improper hydration) are floating on the top, do not include them in the sample.

4.6.4

Sample Size of Lab Testing For pilot testing purposes, each lab should receive a minimum of two gallons of water from the same source that will be used for cementing. The minimum dry cement sample size for lab testing is one gallon for each laboratory and each stage. For a three stage cement job, where all three stages are requested to be tested, the samples should be distributed as follows: Three dry cement samples would go to the Saudi Aramco Cement lab and the other three would go to the Service Company lab. The minimum mix water sample size is one gallon. This is approximately twice the amount required to mix with one gallon of cement. Additional water is required because adjustments may be needed to lengthen the thickening time of the field mixed sample. Usually, the labs will have some leftover cement blend from the pilot

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tests performed prior to mixing. The lab will only resort to using that sample as a last resort. 4.6.5

Sample Labeling All samples should be labeled as follows: • Well Name & No. • Rig Name & No. • Date • Job Description & Stage • Description of Sample • Include all the additives that are mixed in the water or blended in the cement. • Name of Lab (Saudi Aramco or Service Co.)

5.0

BALANCED PLUGS Many operations require that a cement plug be set in the open-hole or casing to plug back a well to a shallower depth for a number of reasons. The most important and common applications include the following: A)

Balanced Plug Method The ideal cement plug is placed so there is no tendency for the cement slurry to continue to flow in any direction at the time pumping is stopped. This involves balancing the hydrostatic pressures inside and outside the drill pipe or tubing so that the height of cement and displacing fluid inside the drill pipe or tubing equals the height of fluids in the annulus. The pipe or tubing is then pulled slowly from the slurry, leaving the plug in place. To allow the pulling of a "dry" string of tubing, common field practice is to cut the displacement volume short by 1/2 to 1 barrel. The characteristics of the mud are very important when balancing a cement plug in a well, particularly the ability to circulate freely during displacement. Whenever possible, the mud should be conditioned thoroughly to uniform densities and rheological properties and the same mud used as the displacement fluid. Movement of well fluids while the cement plug is setting may affect the quality of the plug, therefore, it is imperative that care be taken in accurately spotting the slurry and moving the pipe slowly out of the slurry to avoid backflow, slugging, or swabbing action. The amount of pre-flush or spacer, cement

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slurry, and volume of displacement fluid must be carefully calculated to ensure equal volumes of fluid ahead of and behind the cement plug as it is being placed in the hole. The quantities that must be calculated are as follows: A) B) C) D) E)

Determine the drill pipe or tubing capacity, the annular capacity, and hole or casing capacity. The length of the cement plug or the number of sacks of cement for a given length of plug. The volumes of spacer needed before and after the cement to balance the plug properly. The height of the plug before the pipe is withdrawn. The volume of the displacement fluid.

M M

M

W

W

M

M

M

W

W

W

(a) Displacing cement.

M

M

M M

W

W

M

M

M

(b) Cement, water and mud balanced.

(c) Pulling string above top of cement.

W

M

M

M

(d) Reversing out.

M = Mud Balanced Plug Technique

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Balanced Plug Formulas

Cement requirements: N = L * Ch Y

Spacer Volume behind the slurry to balance plug:

Length of balanced plug before pulling pipe from slurry:

Mud Volume for pipe displacement:

where:

Vb = Cp* Va Ca

N = sacks of cement L = plug length, ft. Ch = hole or casing capacity, cu ft/ft Y = slurry yield, cu ft/sack

where: Va = spacer volume ahead, bbl Vb = spacer volume behind, bbl Ca = annulus capacity, cu ft/ft Cp = pipe capacity, cu ft/ft

Lw = N * Y where: Lw = Plug length before pulling the (Ca+Cp) pipe from the slurry, ft

Vd = [(Lp - Lw) * Cp] - Vb where: Vd = displacement volume, bbl Lp = total pipe length, ft *Cp = pipe capacity, bbl/ft Vb = spacer volume behind, bbl * Note pipe capacity, Cp, is expressed in different units.

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5.1

Loss Circulation Plugs When mud circulation is lost during drilling, it is sometimes possible to restore lost returns by spotting a cement plug across the thief zone and then drilling back through the plug. Thixotropic cements or low thickening time cements are usually recommended for this application. See Chapter 2, Section F for more details.

5.2

Kick-Off/Sidetrack Plugs 5.2.1

Kicking Off: For Deviated and Horizontal wells, cement Kick-off plugs can be used. Generally these plugs are not as effective as using a whip stock. Kickoff cement plugs are set in open hole. Additives are mixed in the cement to both densify and lower the ROP in the cement plug. Removing the water (higher density cements) reduces the porosity which lowers the ROP in the set cement. Frac proppants or frac sand can be added to the cement slurry to aid in reducing the ROP in the cement plug to obtain a more successful Kick-off. Ample curing (WOC) time should be given to the cement plug so that the plug obtains at least 90 % of its final strength. It is very difficult to get a cement plug that is harder than the formation unless the kick-off point is in a weak unconsolidated sand or very high porosity zone.

5.2.2

Sidetracking: In sidetracking a hole around unrecoverable junk, such as a stuck drillstring, it is necessary to place a cement plug above the junk at a required depth that will allow sufficient distance to kick off the cement plug and drill around, bypassing, the original hole and junk. Highdensity cement plugs are usually recommended for this application.

5.3

Isolation/Abandonment Plugs For more details on Abandonment guidelines and cement plugs, see Chapter 2, section G. Zone Isolation: One common reason for plugging back is to isolate a specific zone. The purpose may be to recomplete a zone at a shallower depth, to shut-off water, or to prevent fluid migration into a low-pressure depleted zone.

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Abandonment: To seal off selected intervals of a dry hole or abandon an older, depleted well, a cement plug is placed at the required depth to prevent zonal communication and migration of fluids in the wellbore.

Producing Zone

Cement Plug Depleted Zone

PLUG BACK DEPLETED ZONE

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6.0

DISPLACEMENT PROCEDURES 6.1

Casing Rig pumps will normally be used to displace the cement in full string cement jobs. When using the rig pumps, pre-calibrate the number of strokes per barrel using a trip tank. This will insure that the pump rate can be reduced prior to the plug bumping. Pump displacement fluid until the plug has bumped but DO NOT OVER DISPLACE MORE THAN ½ THE SHOE TRACK CAPACITY. Record whether circulation was maintained. Record the plug bumping pressure. After the plug bumps, hold pressure for a few minutes and then slowly release pressure to make sure the float equipment is holding. On Multistage Cementing jobs where displacement type plugs are used the same displacement rule applies. Usually the bypass plug is displaced 10 barrels short of the bypass baffle. In this case the over displacement would equal 10 barrels plus half the shoe track volume. If the plug has not bumped (landed or seated in the DV) by this time then hold pressure until the cement has set. The Saudi Aramco cement lab has many compressive strength records on the setting behavior (WOC time) of class G cement at many different conditions. They can provide the rig with a WOC time.

6.2

Liners On all liner jobs, the pumps on the cement truck will be used for displacement, unless under emergency conditions (volumetric displacement is more accurate than a stroke counter). Additional mud de-foamer is usually required to remove entrapped air from the mud and get more accurate volume on the displacement. If you can see the pressure build up (usually about 800 psi) as the 'dart' shears the brass pins before releasing the 'wiper 'plug'; make a note of this volume. This volume added to the liner volume can be used to more accurately determine when the 'wiper plug' will seat in the baffle. If you miss the shear pressure and the 'wiper plug' does not bump after the calculated displacement, DO NOT OVER DISPLACE. It is far easier to drill out cement than it is to squeeze the shoe! Generally, it is recommended to pull three to five stands before reversing out excess cement. Special instructions will be included in the drilling program should alternative procedures be required after the cement is pumped on liner liner jobs. Do not displace cement with oilmud, or water based mud or brine that has high Calcium content.

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6.3

Turbulent Flow Turbulent flow is always the best flow regime for cleaning mud off casing and formation face. Unfortunately, turbulent flow can not be achieved easily due to formation frac gradient, balance pressure or horsepower required to achieve turbulent flow. Lab reports show the rate required to achieve turbulent flow. Turbulent flow is easier achieved in smaller cross sectional areas. The same cement slurry would reach turbulent flow faster in a 4 ½” liner in 6 inch hole than a 13 3/8” casing in a 17.5” hole.

7.0

REMEDIAL CEMENTING 7.1

Bradenhead Squeeze The original method of squeezing was the Bradenhead method, which is accomplished through tubing or drillpipe without the use of a packer. BOP rams are closed around the tubing or drill pipe and the injection test carried out to determine the formation breakdown pressure. The cement slurry is then spotted as a balanced plug, and the work string is pulled up and out of the slurry. The annulus is then shut off by closing the annular preventers or pipe rams around the cementing string. Displacing fluid is pumped down the tubing forcing the cement slurry into the zone until the desired squeeze pressure is reached or until a specific amount of the fluid has been pumped. This method is used extensively in squeezing shallow wells and sometimes when squeezing off zones of partial lost circulation during drilling operations.

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Sp ot Cemen t

A pp ly Sq ue ez e Pressu re

Rev erse Circulat ion

Br adenhead Squeez e

When shallow wells are squeezed by this method, fluids in the tubing are displaced into the formation ahead of the cement. In deeper wells, the cement may be spotted halfway down the tubing before the annulus is shut in at the surface. The applicability of Bradenhead squeezing is restricted because the casing must be pressure tight above the point of squeezing and because maximum pressures are limited by the burst strength of the casing and the pressure rating of the wellhead and BOP equipment at the surface. Also, it is sometimes difficult to spot the cement accurately across the interval without using a packer. 7.2

Packer Squeeze Packer Squeeze The main objective of this method is the isolation of the casing and wellhead while high pressure is applied downhole. The selective testing and cementing of multiple zones is an operation where isolation packers are commonly used.

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The packer squeeze method uses either an expendable, drillable, packer such as a cement retainer or a retrievable packer tool run on a work string and positioned near the top of the zone to be squeezed. This method is generally considered superior to the Bradenhead method since it confines pressures to a specific point in the hole. Before the cement is placed, an injection test is conducted to determine the formation breakdown pressure. When the desired slurry volume has been pumped or squeeze pressure is obtained, the remaining cement slurry is reversed out. Squeezing objectives and zonal conditions will govern whether high pressures or low pressures are used.

Displacement Brine Fresh Water Spacer

Brine Pumped

Cement Slurry Brine Fresh Water Spacer

Fresh Water Pre-Flush

Cement Retainer Brine Water

Cement Slurry at Perfs

Perfs

PACKER SQUEEZE JOB

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There are two common methods for placing the cement at the zone of interestBullheading

BU L L H EA D I N G

Ap p lie d Casi ng Pressu re

Ap p lie d Casi ng Pressu re

Di spl ace me nt Fl ui d

Sometimes it is necessary to bullhead cement between casing strings into the annulus in order to bring cement back to surface and to seal off the annulus. If this is required, precautions must be taken not to exceed the collapse rating of the inner casing string when squeezing the cement slurry down the casing annulus.

Cem en t Cem en t

Mud

Mud

P u m p Ce m en t w i t h P a c ke r se t D i sp l a c e M u d i n t o F o r m a t i o n Ho l d A n n u l u s P r e ss u r e

In this method, a packer is set and pressure is applied to the annulus. An injection rate is established into the zone; then the cement is mixed and pumped down the work string. The mud, or brine, as well as the cement is then forced into the zone under pressure until the desired squeeze pressure is obtained. The packer is not released until the job is completed.

A p p ly Sq u e e z e P r e ss u r e

Spotting SPOT T I N G

Ap p lie d Casi ng Pressu re

Di spl ace me nt Fl ui d

Cem en t

Cem en t

Mud Mud

S p o t Ce m en t

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S t a b i n t o P ac k e r A p p l y C as i n g P r es s ur e D i sp l a c e C e m e n t A p p l y S q u e e z e P r e s su r e

In this method, after establishing an injection rate into the zone, the packer is released or the by-pass opened. The cement slurry is circulated down the work string to just above the packer. The packer is then re-set or the bypass closed, and the cement slurry is squeezed away into the zone until the desired squeeze pressure and volumes are reached. With this method, the amount of mud or brine that will be forced into the perforations ahead of the cement is kept to a minimum.

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Packer Squeeze Tools The use of squeeze packers makes it possible to apply higher pressures to specific downhole points than can be applied with the Bradenhead method. The two commonly used packers are the drillable and the retrievable. Drillable Squeeze Packers Drillable packers, which are expendable, are left in the well and can be drilled out after the squeeze operation. The drillable packer contains a poppet-type backpressure valve to prevent backflow at the completion of displacement and a sliding valve for when it is desirable to hold pressure in either or both directions. The sliding valve makes it possible to support the weight of the hydrostatic fluid column and relieve the cement of this weight while it is setting. Excess cement can be reversed out of the drillpipe without applying the circulating pressure to the squeezed area below the packer. The tubing or drillpipe can also be withdrawn from the well without endangering the squeeze job. Another advantage is that they can be set close to the perforations or between sets of perforations and are easily drilled if required. Cement retainers set on drillpipe or wireline are used instead of packers to prevent backflow when no cement dehydration is expected or when high negative differential pressures may disturb the cement cake. In certain situations, potential communication with upper perforations could make use of a retrievable packer a risky operation. When cementing multiple zones, the cement retainer will isolate the lower perforations, and subsequent zone squeezing can be carried out without waiting for the cement to set. Cement retainers are drillable packers provided with a two-way valve that prevents flow in either or both directions. The valve is operated by a stinger run at the end of the work string.

Drillable Squeeze Packer

Drillable bridge plugs are normally used to isolate the casing below the zone to be treated. They are of similar in design to the cement retainer, and they can be set on wireline or on drillpipe. Bridge plugs do not allow flow through the tool.

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Retrievable Squeeze Packers Retrievable packers are usually rented on a job basis and, after the squeeze job, is removed from the well. Unlike drillable packers, the retrievable packer can be set and released as many times as necessary. Retrievable packers with different design features are available on the market. Most are of a non-drillable material and are available in most API sizes. The ones used in squeeze cementing, compression or tension set packers, have a bypass valve to allow the circulation of fluids when running in and once the packer is set. This packer feature permits the spotting of pre-wash fluids and cement down to the zone, cleaning of tools after the job, reversing of excess cement without excessive pressures, and prevents a piston or swabbing effect when tripping the packer in or out of the hole. Retrievable bridge plugs are easily run and operated tools with the same function as the drillable bridge plugs. They are generally run in one trip with the retrievable packer and retrieved later after the cement has been drilled out. Most operators will spot frac sand or acid soluble calcium carbonate on top of the retrievable bridge plug before doing the squeeze job to prevent cement from settling over the top of the retrievable bridge plug.

Retrievable Squeeze Packer

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8.0

CEMENTING EQUIPMENT

Schlumberger/Dowell Cementing Equipment

Left: 200 barrel Batch Mixer, Right: Batch Mixer inside view

Left: Cement Pump Truck

Right: Field Bulk Cement Storage Unit

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Halliburton Cementing Equipment

Left: 100 barrel Batch Mixer

Right Cement Pump Truck

Left: Bulk Cement Storage Unit (2000 cubic feet)

Right: 18 5/8” Cementing Head

BJ Services Batch Mixer

Above: 120 barrel Cement Batch Mixer

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WELLHEADS 1.0

INTRODUCTION 1.1 Wellhead Function 1.2 Tree Function 1.3 Ring Joint Flanges 1.3.1 Ring Gaskets 1.4 Typical Wellhead 1.4.1 Casing Head 1.4.2 Casing Spool 1.4.3 Tubing Spool 1.4.4 Tubing Bonnet (Tubing Head Adapters) 1.4.5 Tree Assemblies

2.0

STANDARD SAUDI ARAMCO WELLHEAD COMPONENTS 2.1 Casing Heads (Landing Base) 2.2 Casing Spools 2.3 Tubing Spools 2.4 Tubing Hangers (Extended Neck) for Oil Service 2.5 Tubing Hangers (Extended Neck) for Gas Service 2.6 Tubing Bonnets for Oil Service 2.7 Tubing Bonnets for Gas Service (With Master Valve) 2.8 Tubing Bonnets for Special Service (Electric Penetrators) 2.9 DSDPO Flange, Double Studded Double Pack-Off Flange 2.10 Trees 2.11 Loose Valves 2.12 Valve Bores and End-To-End Dimensions

3.0

INSTALLATION AND TESTING PROCEDURES 3.1 Primary and Secondary Seals 3.2 Casing Head 3.3 Slip Type Casing Hangers 3.4 Casing and Tubing Spool 3.5 Tubing Hangers 3.6 Tubing Bonnet and Trees 3.7 Trees

4.0

BACK PRESSURE VALVE INSTALLATION PROCEDURES 4.1 Back Pressure Valves for Oil Well Service 4.2 Back Pressure Valves for Khuff Gas Service 4.3 Type ‘H’ Back Pressure and Two Way Check Valve 4.4 Running Procedures for Type ‘H’ plugs. 4.1.1 Method 1: Installation Using the Retrieving/Running Tool 4.1.2 Method 2: Installation Using the Running Tool

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WELLHEADS 1.0

INTRODUCTION 1.1

Wellhead Function The wellhead performs three important functions: A) Provides connection and support for blow out preventers and other well control equipment. B) Provides a sealed connection and support for each tubular string. C) Provides a connection and support for the tree.

1.2

Tree Function The tree also performs three functions: A) Controls the flow of fluids from the well bore. B) Provides a means of shutting on the well. C) Provides a means of entering the well for servicing and workover.

1.3

Ring Joint Flanges Flanges are the most commonly used end connections in the oil industry apart from welds and threads (Figure 2E-1). API has standardized flanges that are covered in API Spec 6A. ASME/ANSI has standardized flanges that are covered by ASME/ANSI Spec 16.5. Because Saudi Aramco uses both API and ANSI flanges, knowledge of the similarities and differences is required. Some ANSI ring joint flanges will mate with API flanges but the pressure ratings are different. 24.0000

1.500" X 20 BOLT HOLES

21.000

15.47

3.44

14.53 13.66

RING GROOVE

Figure 2E-1: API 13-5/8" 3,000 psi Flange

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June 2006

DRILLING PRACTICES

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WELLHEADS

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ANSI Class 600 flanges will mate to API 2,000 psi, ANSI Class 900 flanges will mate to API 3,000 psi and ANSI Class 1500 flanges will mate to API 5,000 psi. If an ANSI flange is connected to an API flange, the connection is DERATED to the pressure rating of the ANSI flange because it will not hold as much pressure as the API flange. A comparison of some common flange sizes is given in Table 2E-1 and working pressures of ANSI flanges by temperature is given in Table 2E-2. Table 2E-1

Comparison of Common API and ANSI Flanges

Size/WP

Ring

OD

Bolt

No. of Bolts

Bolt Circle

API

12"/3M

R-57

24

1 3/8

20

21

ANSI

12"/900

***

24

1 3/8

20

21

API

11"/5M

R-54

23

1 7/8

12

19

ANSI

10"/1500

***

23

1 7/8

12

19

API

11"/3M

R-53

21 1/2

1 3/8

16

18 1/2

ANSI

10"/900

***

21 1/2

1 3/8

16

18 1/2

API

7"/5M

R-46

15 1/2

1 3/8

12

12 1/2

ANSI

6"/1500

***

15 1/2

1 3/8

12

12 1/2

API

7"/3M

R-45

15

1 1/8

12

12 1/2

ANSI

6"/900

***

15

1 1/8

12

12 1/2

API

4"/3M

R-37

11 1/2

1 1/8

8

9 1/4

ANSI

4"/900

***

11 1/2

1 1/8

8

9 1/4

API

3"/3M

R-31

9 1/2

7/8

8

7 1/2

ANSI

3"/900

***

9 1/2

7/8

8

7 1/2

API

2"/5M

R-24

8 1/2

7/8

8

6 1/2

ANSI

2"/1500

***

8 1/2

7/8

8

6 1/2

*** The ring groove size must be checked for each flange.

Note:

•

•

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Only API flanges are used on producing wellheads, trees and drill through equipment such as blowout preventers. ANSI flanges, fittings and valves are used on water wells, pipelines, gas plants and some surface production units.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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June 2006

DRILLING PRACTICES WELLHEADS

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Table 2E-2 Ratings for Group 1.1 Materials

Working Pressure by ANSI Class, psig Temperature ° -20 to 100 200 300 400 500

150 285 260 230 200 170

300 740 675 655 635 600

400 990 900 875 845 800

600 1,480 1,350 1,315 1,270 1,200

900 2,220 2,025 1,970 1,900 1,795

1500 3,705 3,375 3,280 3,170 2,995

2500 6,170 5,625 5,470 5,280 4,990

4500 11,110 10,120 9,845 9,505 8,980

Only API flanges are used on producing wellheads, trees and drill through equipment such as blowout preventers. ANSI flanges, fittings and valves are typically used on water wells, pipelines, gas plants and on some surface production units. 1.3.1

Standard Ring Gaskets: At Saudi Aramco our standard is the type R ring gasket for low pressure connections and the BX for high pressure applications. The oval ring and octagonal ring are both API type R ring gaskets as shown in Figure 2E-2. These gaskets are designed to be used in 2,000, 3,000 and 5,000 psi flanges only. Stud bolts used with type R gaskets must perform the double duty of holding pressure while keeping the gasket compressed. When making up the flanges, the curved surface of the relatively soft oval ring is mated with the flat surfaces of the harder flange ring groove. A small flat is pressed on the curved section of the oval ring. The size of this flat depends on the bolt make-up torque. This is the main reason that ring gaskets can only be used one time and must be replaced with a new gasket each time a flange is made up.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

E

June 2006

DRILLING PRACTICES WELLHEADS

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R OVAL

R OCTAGONAL

RX

BX

Figure 2E-2: API Ring Gaskets As normal tightening proceeds, forces accumulate and deform the ring to produce a seal. By the time all bolts around the flange have been tightened, the first bolt is loose again. In most API flanged connections with type R gaskets, it is necessary to tighten bolts around the flange several times to reach a stable condition. The octagonal R does not have to deform as much as the oval R to create a seal. When internal pressure forces become great enough to cause flexing in an API connection that uses either of the type R gaskets, the bolting contact force on the seal ring begins to decrease. If flange separation forces exceed the limited resilience of the seal, leakage will occur. External shock loads, such as drilling vibration, add to the compressive loading of the stud bolts. This further deforms the gaskets and can cause leaks making repeated tightening necessary. The API type BX ring gasket has been developed primarily for use in 10,000 psi and greater working pressure equipment. There are certain exceptions to this where the BX type gasket is used in 5,000 psi flanges. This pressure energized ring joint gasket is for use with type BX flanges only and is not interchangeable with type R or RX gaskets. The BX flanges are designed to make up face to face at the raised face portion of the flanges. Figure 2E-2 illustrates the BX flanges at initial contact.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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June 2006

DRILLING PRACTICES WELLHEADS

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1.4

Typical Wellhead: The typical wellhead for a three string well will consist of: (Figure 2E-3): A) B) C) D) E)

The casing head (sometimes referred to as the Landing Base or Bradenhead). The Intermediate casing head (or Casing Spool); The Tubing Head (or Tubing Spool); The Tubing Bonnet (or Tubing Head Adapter); The Tree.

TREE

TUBING BONNET

TUBING SPOOL

INTERMEDIATE CASING HEAD

CASING HEAD

Figure 2E-3: A Three String Wellhead

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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1.4.1

Casing Head: The casing head is attached to the top of the surface casing (Figure 2E-4). Since the other tubular strings are tied to the casing head, the surface casing must support the weight of all the subsequent casing and tubing strings, along with the entire wellhead system. CASING STUB CASING HANGER

CASING HEAD

BASE PLATE

CONDUCTOR PIPE

SURFACE CASING

CASING - HOLE ANNULUS

CEMENT

INTERMEDIATE CASING

Figure 2E-4: The Casing Head The casing head is welded onto the surface casing. The base plate (support unit) is installed under the casing head and is not welded to the conductor or casing head. The casing head accepts the next string of casing, either a protective string or the production string depending on the well design. The next string of pipe is hung by means of a casing hanger in the casing head. The intermediate string is hung in the casing head with a casing hanger and cemented in place. The casing hanger holds the intermediate casing and seals the casing to casing annulus. Hangers are discussed in more detail later in this chapter.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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June 2006

DRILLING PRACTICES WELLHEADS

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1.4.2

Casing Spool: The casing spool is bolted onto the casing head (Figure 2E-5). It can be used to suspend either the production casing string, as shown, or an additional string of protective casing. For each additional protective string, an additional casing spool is required. CASING STUB

CASING SPOOL

CASING HEAD

SURFACE CASING

INTERMEDIATE CASING

PRODUCTION CASING

Figure 2E-5: The Casing Spool

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Drilling & Workover Engineering Department CHAPTER 2 SECTION

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The casing spool consists of a lower flange for connection to the casing head and an upper flange for connection to the subsequent wellhead section. A cylindrical bore with shoulders is machined into the upper half to receive the casing hanger. The casing spool contains a primary seal (the casing hanger) inside the top flange and a secondary seal (the packoff) located inside the lower flange (Figure 2E-6). The names primary seal and secondary seal were derived from a pressure change situation. If the casing spool has a 3,000 psi bottom flange and a 5,000 psi top flange, the casing hanger seal is the first seal to prevent the 5,000 psi fluid from getting to the 3,000 psi flange face. The packoff bushing is the second preventive seal. The secondary seal performs essentially the same function as the primary seal of the casing head. Aramco has two wellhead manufacturers supplying wellhead material. Each system has its own secondary seals. Cooper (makes Cameron & McEvoy) supplies an Xbushing and Vetco Gray supplies an AK bushing. The AK bushing is redesigned from the original CWC bushing so that regardless of which spool is installed, the casing stub (Figure 2E-10) is cut to the same height for the Vetco Gray spool as for the Cameron or McEvoy spool.

RING GASKET

RING GASKET GROOVE CASING HANGER

TEST PORT

INJECTION PORT

RING GASKET GROOVE SECONDARY SEAL

Figure 2E-6: The Casing Spool with Secondary Seal

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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June 2006

DRILLING PRACTICES WELLHEADS

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A ring gasket, made of a special metal alloy, is placed between all flanged connections. The ring gasket fits into specially machined grooves in the upper flange of the casing head and the lower flange of the intermediate casing head. The gasket serves to contain pressures in the wellhead in the event that either or both the primary and secondary seals should fail. Each ring gasket is designed to withstand a maximum pressure that the tubulars will be exposed to during the life of the well. A further explanation of ring gaskets and pressure ratings is discussed later. The side outlets on the casing spool are used to check and relieve pressure inside the casing - casing annulus. 1.4.3

Tubing Spool The tubing head suspends the production tubing and seals off the tubing casing annulus (Figure 2E-7). Like the casing spool, the tubing head includes a secondary seal and side outlets. The top flange of the tubing head is used to connect blowout preventers during conventional workover operations; that is, workovers that require pulling the tubing. The lower flange connects to the top flange of the section below it. A ring gasket is also used between the flanged connections. POLISHED NIPPLE

TUBING HEAD TIE DOWN PIN TUBING HANGER

PRODUCTION CASING TUBING

Figure 2E-7: The Tubing Head

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DRILLING PRACTICES WELLHEADS

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The tubing hanger assembly performs essentially the same function as the casing hanger; i.e., it suspends the tubing and seals off the tubing - casing annulus. The full weight of the tubing string is virtually supported by the tubing hanger. The tubing hanger is usually equipped with a polish nipple to seal inside the tubing bonnet (Figure 2E-8). However, sometimes the tubing hanger is equipped with an extended neck that is an integral part of the hanger. The polish nipple is a separate item threaded into the tubing hanger. The side outlets of the tubing head can be accessed to; (1) inject a fluid into the tubing casing annulus, as in a gas lift operation; (2) monitor annulus pressure; (3) test annulus for leaks; (4) relieve pressure in the tubing - casing annulus; and (5) supply an exit for the sub-surface safety valve control line. The tie-down pins serve to secure the tubing hanger in the spool. If the tubing is attached to a downhole packer, there is a possibility that the tubing will expand under flowing conditions causing a force large enough to break the seal between the hanger and the spool. For a more detailed view of a tubing hanger refer to Figure 2E-12. 1.4.4

Tubing Bonnet (Tubing Head Adapters): The tubing bonnet (Figure 2E-8) is the equipment that allows the tree to be attached to the wellhead. It has a sealing mechanism, extended neck or polish nipple, which keeps wellbore fluid from coming in contact with the tubing head or the tubing hanger. The tubing bonnet configuration is usually equipped with studs on top and a flange on the bottom although it can be supplied flange by flange or stud by stud. Ring gaskets are installed on top and on the bottom.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

E

June 2006

DRILLING PRACTICES WELLHEADS

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TUBING BONNET

TUBING HEAD TUBING HANGER WITH POLISH NIPPLE

PRODUCTION CASING TUBING

Figure 2E-8: Tubing Bonnet and Polish Nipple 1.4.5

Tree Assemblies: The tree is a system of gate valves that regulates the flow of fluids from the well, opens or shuts production from the well, and provides entry into the well for servicing. The tree is connected to the uppermost flange of the wellhead that, typically, is the upper tubing head flange. A typical tree includes several gate valves, a flow tee and a tubing bonnet. This system routes well production into the flow line. The flow line then conducts the fluids from the tree to surface treating facilities. The gate valves are technically the same but are referred to by different names. They include the master valve, the wing valve and the crown valve. Each valve can have a backup and the valves can operate manually or hydraulically. Each valve has only two operating positions; fully open or fully closed. They are used to open or shut the flow from the well.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

E

June 2006

DRILLING PRACTICES WELLHEADS

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2.0

SAUDI ARAMCO STANDARD WELLHEAD COMPONENTS Saudi Aramco currently purchases wellhead components from four manufacturers. These are Cameron, FMC, Gray and WGI. These components are interchangeable as wellhead sections, that is you may use a Cameron Casing Head, then install a FMC Casing Spool, then a Gray Tubing Spool with a WGI Tubing Bonnet. You cannot, however interchange casing or tubing hangers. A Cameron head must have a Cameron hanger, a FMC head must have a FMC hanger etc. Saudi Aramco stocks all of the major components to drill, complete and workover our wells. The following sections are a listing of the major components by size, pressure rating and service type. Refer to the Drilling and Workover Materials list for current Stock Numbers. 2.1

2.2

2.3

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Casing Heads (Landing Bases): Top Flange Bottom 13” 3M 13-5/8” Socket Weld 13” 5M 13-5/8” Socket Weld 20” 3M 18-5/8” Socket Weld 26” 3M 24” Socket Weld 26” 3M 26” Socket Weld Casing Spools: Top Flange 11” 3M 11” 5M 11” 5M 11” 10M 13” 3M 13” 3M 13” 5M 13” 10M 20” 3M

Bottom Flange 13” 3M 13” 3M 13” 5M 13” 5M 13” 3M 20” 3M 13” 5M 16” 5M 26” 3M

Casing Hanger 9-5/8” Automatic 9-5/8” Automatic 13-5/8” Automatic 18-5/8” Automatic 18-5/8” Automatic

Packoff 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 13-3/8” 9-5/8” 13-3/8” 18-5/8”

Casing Hanger 7” Automatic 7” Automatic 7” Automatic 7” Automatic 7” Automatic 9-5/8” Automatic 7” Automatic 9-5/8” Automatic 13-3/8” Automatic

Tubing Spools:

Top Flange

Bottom Flange

Packoff

Outlet Size

11” 3M 11” 3M 11” 3M 11” 3M 11” 5M 11” 10M

11” 3M 11” 3M 13” 3M 13” 3M 13” 5M 13” 10M

7” 7” 9-5/8” 9-5/8” 9-5/8” 9-5/8” Metal Seal

2” X 2” 6” X 2” 2” X 2” 6” X 2” 2” X 2” 3” X 3”

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Drilling & Workover Engineering Department CHAPTER 2 SECTION

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2.4

2.5

2.6

2.7

2.8

Tubing Hangers (Extended Neck) for Oil Service: Bowl Size Tubing Size Thread 11” 2-3/8” EUE 11” 2-7/8” EUE 11” 3-1/2” EUE 11” 4-1/2” New Vam 11” 7” New Vam

BPV Prep 2” Type ‘H’ 2-1/2” Type ‘H’ 3” Type ‘H’ 4” Type ‘H’ 7” Type ‘J’

Tubing Hangers (Extended Neck) for Gas Service: Bowl Size Tubing Size Thread 11” 3-1/2” PH-6 11” 4-1/2” New Vam 11” 5-1/2” New Vam 11” 7” New Vam Tubing Bonnets for Oil Service: Studded Top Bottom Flange Flange 2” 3M 11” 3M 3” 3M 11” 3M 4” 3M 11” 3M 7” 3M 11” 3M 7” 5M 11” 5M

BPV Prep 3” Type ‘H’ 4” Type ‘H’ 5” Type ‘H’ 7” Type ‘K’

Seal Neck Diameter (inches) 5-1/2 5-1/2 5-1/2 7-5/8 7-5/8

Tubing Bonnets for Gas Service (with Master Valve): Valve Bore Studded Top Flange 4-1/2” 7” 10M 5-1/2” 7” 10M 7”nom. (6-3/8” act.) 7” 10M

Bottom Flange 11” 10M 11” 10M 11” 10M

Tubing Bonnets for Special Service (Electric Penetrators):

Studded Top Flange 7” 3M 3” 3M 4” 3M

Bottom Flange 20” 3M 11” 3M 11” 3M

Penetrator Genco Model 1 Genco Model 1 Genco Model 1

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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2.9

DSDPO Flanges:

Casing Size 4-1/2” 4-1/2” 5” 5” 7” 7” 7” 7” 7” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 13-3/8” 13-3/8” 13-3/8” 18-5/8”

Studded Bottom Flange 11” 3M 13” 3M 11” 3M 13” 3M 11” 3M 11” 5M 11” 5M 11” 10M 13” 3M 13” 3M 13” 3M 13” 5M 13” 5M 13” 10M 13” 3M 13”5M 16” 5M 26” 3M

Studded Top Flange 11” 3M 13” 3M 11” 3M 13” 3M 11” 3M 11” 5M 11” 10M 11” 10M 13” 3M 13” 3M 13” 5M 13” 5M 13” 10M 13” 10M 20” 3M 20” 3M 20” 3M 26” 3M

2.10 Trees:

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Size

Working Pressure

Service

2” 3” 4” 7” 4” 7” 7” 3” 4” Size 5” 7” 10”

3M 3M 3M 3M 3M 3M 5M 10M 10M Working Pressure 10M 10M 3M

Onshore Onshore Onshore Onshore Offshore Offshore Offshore Khuff Block Khuff Service Block Khuff Block Khuff Power Water Injection

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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June 2006

DRILLING PRACTICES WELLHEADS

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2.11 Loose Valves: Size 2” 3” 4” 7” 2” 3” 4” 3” 4” 7” 2” 3” 4” 7” 2”

Working Pressure 3M 3M 3M 3M 5M 5M 5M 10M 10M 10M 3M 3M 3M 3M 10M

2.12 Valve Bores and End-To-End Dimensions Nominal Size (inches) Valve Bore (inches) 3,000 psi Working Pressure 2-1/16 2-9/16 3-1/8 4-1/16 5-1/8 7-1/16

Type Manual Manual Manual Manual Manual Manual Manual Manual Manual Manual Hydraulic Actuator Hydraulic Actuator Hydraulic Actuator Hydraulic Actuator Hydraulic Actuator

End-to-End (inches)

2.06 2.56 3.12 4.12 5.12 6.38

14.62 16.62 17.12 20.12 24.12 24.12

2.06 2.56 3.12 4.12 5.12 6.38

14.62 16.62 18.62 21.62 28.62 29.00

2.06 2.56 3.12 4.06 5.12 6.38

20.50 22.25 24.38 26.38 29.00 35.00

5,000 psi Working Pressure 2-1/16 2-9/16 3-1/8 4-1/16 5-1/8 7-1/16

10,000 psi Working Pressure 2-1/16 2-9/16 3-1/8 4-1/16 5-1/8 7-1/16

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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June 2006

DRILLING PRACTICES WELLHEADS

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3.0

INSTALLATION AND TESTING PROCEDURES: 3.1

Primary and Secondary Seals: We mentioned in section 1 that one of the purposes of wellhead is to support the tubular strings. Another purpose of wellhead is to seal and isolate the tubular strings from one another. This is done by installing a minimum of two seals on each string of pipe. These are the Primary Seal and the Secondary Seal. The Primary Seal is on the casing or tubing hanger. The secondary seal is in the bottom of either the next spool section, the tubing bonnet or the DSDPO, if one is used. We use three types of secondary seals at Saudi Aramco. First the injectable seal. This is a seal that is activated by injecting plastic packing behind it as we do in X and AK bushings. The second type is the interference fit seal. This type is activated by simply bolting up the flange, the seal energizes automatically. The third type is the metal-to-metal seal. The pack-offs that use this seal have sized metal rings that must be installed by a Service Hand. The metal-to-metal seal is also used as the tubing hanger primary and secondary seal on 10,000 psi (Khuff) tubing hangers. The table below lists all three types and where they are used: Interference Seals

Injectable Seals

Sized Metal to Metal Metal-to Metal

3.2

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Bottom of casing and tubing spools to seal on 9-5/8” and smaller pipe. All 3,000 psi and 5,000 psi tubing bonnets. Bottom of spools to seal on 13-3/8” and larger pipe. All Double Studded Double Pack-off flanges (DSDPO) Bottom of 10,000 psi (Khuff) tubing spools Tubing hanger primary and secondary seals for 10,000 psi (Khuff) equipment

Casing Heads: The casing head is installed on the conductor casing by slipping the socket in the bottom of the head over the casing and welding inside and outside. The assembly is then pressure tested through a ½” NPT test port between the welds, the O.D. of the casing and the I.D. of the socket. This area is marked in red in Figure 2E-9. A detailed installation procedure, WRS-602, issued by DMD is contained in the Appendix, section D of this manual. Test pressure is determined by taking 80% of the rated collapse of the casing or the working pressure of the top flange, whichever is less. Maximum test pressures are tabulated below.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

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Figure 2E-9: Installed Casing Head

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Maximum pressures for testing Casing Heads

3.3

Casing Size

Casing Grade

13-3/8 13-3/8 13-3/8 13-3/8 13-3/8 13-3/8 18-5/8 18-5/8 24 24 26 26

J-55 J-55 L-80 NT-95-HS S-95 NT-95-HS K-55 K-55 GR-B X-42 X-42 X-42

Casing Weight 61# 68# 72# 72# 72# 86# 87.5# 115# 97# 176# 105# 136#

Rated Collapse 1,540 1,950 2,670 2,820 2,820 6,240 630 1,140

Maximum Test Pressure 1,200 1,550 2,100 2,250 2,250 5,000 500 900

1,080

850

Slip Type Casing Hangers At Saudi Aramco we commonly use the slip type casing hanger. There are two styles of these hangers the Automatic and the Manual. Automatic and Manual refer to the way that the seal on the hanger is activated. The Automatic seal is energized by setting casing weight on the hanger, it usually requires around 50,000 lbs to effect a seal. The Manual hanger will not seal until cap screws in the top of the hanger have been tightened. All of the casing hangers we use may be installed from the drill floor through a BOP stack or the stack may be picked up, secured, and the hanger installed from underneath. There are some considerations when installing a hanger through the BOP stack: • •

• •

The casing must be well centered in the stack. There can be no casing couplings in the stack. The hangers will not go over them. The hanger should be lowered through the stack with soft line. It is usually not recommended that any hanger larger than 13-5/8” X 7” be set through the stack. This is because of the weight of the hanger.

We currently use four manufacturer’s casing hangers these are Cameron, FMC, Gray and WGI. You may not mix hangers and spools. If you have a Cameron head or spool you must use a Cameron hanger, a Gray spool must use a Gray hanger etc. This is because the profile on the outside of the hanger must match the profile of the head. These profiles are propriety to the manufacturer and are never interchangeable.

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All of our casing hangers basically operate the same way. First lay boards or metal straps across the opening; either the rotary table or the top flange of the casing spool as appropriate. The hanger splits open to allow you to wrap it around the casing. Be careful when doing this so as not to tear the seal element. Set the hanger on the boards or straps so that it is level. Remove the shipping retaining pins or screws that hold the slip segments in place. Coat the casing and the outside of the hanger with light oil. Ensure that the side outlet valve on the casing head or spool is open and that all fluids have drained to the level of the outlet. Remove the boards and lower, do not drop, the hanger into the bowl. Only after the hanger is in the proper position, top of the hanger 1 to 2 inches below the top flange, can casing weight be set on the slips. Pick up the BOP stack and make the rough cut six to eight inches above where the final cutoff will be. Nipple down the BOP. Installing the next wellhead section is discussed in Chapter 2E, section 3.4 Casing and Tubing Spools below. Figure 2E-10 shows a Casing Head with the hanger installed. 3.4

Casing and Tubing Spools The tubing spool is identical to the casing spool except at Saudi Aramco we have lock screws installed in the top flange of the tubing spool. These lock screws serve two main purposes. First they help energize the primary seal especially when there is a very light tubing string. Second they act as a retention device for the tubing hanger. The retention device would be necessary if, for example, the tubing string parted. Since the tubing hanger is locked in place you could still set a back-pressure valve and retain control of the well.

Figure 2E-10: Casing Head with Hanger Installed

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Before installing the spool, lay it on its side and wash the inside of the spool thoroughly, removing all grease and dirt. Visually check the secondary seals in the bottom of the spool for damage or cuts, replace the seal if any are found. Next, measure from the face of the bottom flange to the shoulder just above the secondary seal. This is the final cut-off height for the casing stub. Saudi Aramco’s standard cut-off is 4-1/2 inches, but this should always be verified before making the final cut. After the final cut is made bevel both the inside and outside of the casing stub. Beveling helps the spool slide on more easily and ensures that there are no burrs or lips on the I.D. that would cause a tool to hang up. Rig pick-up lines to the top flange of the spool so that it hangs level, suspend it over the casing stub. Clean ring grooves and install a new ring gasket. Coat the casing stub and the secondary seal with light oil. Install two studs under each valve orient the spool as required and lower the spool slowly over the casing stub. Fill the bowl above the casing hanger with hydraulic oil. Take care that the stub does not hang-up and cut the secondary seal. Install the rest of the studs and nuts and tighten the flange using normal oilfield practice.

Figure 2E-11: Casing Spool Nippled up on Casing Head

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After the flange is tightened, activate the secondary seals (see section 3.1 above). Now hook up the test pump to the test port and apply test pressure using hydraulic oil. Test pressure is generally 80% of the rated collapse pressure of the casing or the working pressure of the flange, whichever is less. Hold the test pressure for 15 minutes then bleed all pressure to zero. Install the blind plug in the test port. Figure 2E-11 is a depiction of a casing spool installed on a casing head the area in red indicates the void being pressure tested. 3.5

Tubing Hangers All of the tubing hangers used by Saudi Aramco (Figure 2E-12) are mandrel type hangers with extended necks. They are shipped to the field with a pup joint installed to ease make-up onto the tubing string. After the tubing string has been spaced-out pick up the tubing hanger in install on the top joint of the string. Take care not to damage the O.D. of either the hanger or the extended neck as deep scratches or gouges in this area can prevent the hanger from sealing. Check that all of the lock screws in the top flange of the tubing spool are fully retracted and do not extend into the head. Install a landing joint in the top of the hanger then slack-off on the tubing string and land the hanger in the bowl. Tighten the lock screws, remove the handling joint and install the Back Pressure Valve. Now you may nipple down the BOP stack and you are ready to install the tubing bonnet and tree.

Figure 2E-12: Tubing Spool with Tubing Hanger Installed

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3.6

Tubing Bonnet Before installing the tubing bonnet turn it on its side and wash thoroughly, removing all grease and dirt. Visually inspect the bore of the bonnet and the seals for damage. Rig slings to the bonnet so that it picks up level, suspend it over the extended neck of the tubing hanger. Clean all ring grooves and install new ring gasket. Coat the extended neck of the hanger and the seals in the bonnet with light oil. Fill the bowl on top of the hanger with hydraulic oil. Install four studs 90o from each other to help line up the bonnet. Turn the bonnet to the required orientation and lower over extended neck. Install all studs and nuts and tighten using good oil field practice. Test the connection using hydraulic oil for 3,000 psi and 5,000 psi equipment and nitrogen for 10,000 psi completions. NOTE: Gray has a portable nitrogen test unit that should be used for these tests. Hold test pressure for 15 minutes then bleed all pressure to zero. Figure 2E-13 shows the test area of a bonnet and tubing hanger.

Figure 2E-13: Tubing Spool with Bonnet Installed

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3.7

Trees Rig slings to the tree (Figure 2E-14) so that it will pick up level. Clean the ring grooves and install a new ring gasket. Orient the tree as required and land. Tighten studs using good oil field practice before removing the slings. Rig down the slings. Retrieve the Back Pressure Valve and install a two way check valve, or test plug. Rig up pump to the wing valve and with all valves open test to the working pressure of the tree. Bleed pressure to zero, close master valve and pressure up to working pressure. With master valve closed test each valve in turn. After tree has been tested pull the two way check valve, or test plug and install back pressure valve, if required by the Drilling Program. Close all valves to secure well.

Figure 2E-14: Tree, Bonnet and BPV Installed

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4.0

BACK-PRESSURE VALVES AND TUBING TEST PLUGS: Saudi Aramco uses three types of Back-Pressure valves on new wells. These are the type ‘H’ the type ‘K’ and the type ‘J’. 4.1

Back Pressure Valves for Oil Well Service: Size 2-3/8” 2-7/8” 3-1/2” 4-1/2” 7”

Profile Type ‘H’ Type ‘H’ Type ‘H’ Type ‘H’ Type ‘J’

Note: Please be reminded that the old style hangers had the Gray Type ‘K’ profile or the type ‘H’ profile depending on which company manufactured the hanger. The well file must be checked to determine which BPV should be installed during workover operations. All drilling rig Foremen should check 23/8” through 4-1/2” hangers prior to installation, only those with Type ‘H’ profiles should be used. 4.2

Back Pressure Valves for Khuff Gas Service: All new hangers for Khuff service have the following profiles: Size 3-1/2” 4-1/2” 5-1/2” 7”

Profile Gray Type ‘K’ Type ‘H’ Type ‘H’ Gray Type ‘K’

Note: Please be reminded that the older hangers had the Gray Type ‘K’ profile. The well file must be checked to determine which BPV should be installed during workover operations. All rig Foremen should check 3-1/2” and 4-1/2” hangers prior to installation, only those with Type ‘H’ profiles should be installed.

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4.3

Type ‘H’ Back-Pressure and Two Way Check Valves The threaded style Back-Pressure Valve (BPV) and Two-Way Check Valves (TWCV) combine internal running threads, external setting threads and an internal stinger. The type ‘H’ BPV is designed to hold pressure from the wellbore, or below, only. Cameron rates these BPV’s at 20,000 psi. They have an internal, female, right hand running thread that mates with the running, or retrieving tool, and an external, male, left-hand ACME setting thread that mates with the tubing hanger. Please refer to Figure 2E-15, below. The internal plunger consists of a valve and spring assembly that will seal and hold pressure from below. When offset this plunger, see Figure 2E-16, allows pressure to by-pass and equalize above and below the BPV. This plunger also allows fluid to be pumped through the BPV in the event that it is necessary to pump kill fluid into the well with the plug installed. The external seal is a lip type seal on the O.D. of the BPV. This seal is energized when the plug is rotated into the mating profile in the tubing hanger. The type ‘H’ BPV should not be overtightened. Over-tightening this type of plug will not help it seal, but can make it hard to remove.

Figure 2E-15: BPV, Plunger Closed

Figure 2E-16: BPV, Plunger Open

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The type ‘H’ TWCV is designed to plug the tubing in order to test the tree or the BOPE. It will also seal pressure from below. Refer to Figures 2E-17 and 2E-18 below. The plug uses a two-way plunger that will hold tubing pressure from below or moves down and seals test pressure from above. The tubing pressure can be bled down by inserting the retrieving/running tool, which will offset the plunger and allow pressure to by-pass. This plug is not to be used for nipple-up or nipple-down operations! When performing these operations the BPV shall be installed. When nipple down, nipple up, operations are complete the BPV shall be removed and the TWCV installed and the equipment can be tested.

Figure 2E-17: TWCV; Pressure from Below

Figure 2E-18: TWCV; Pressure from above

There are two tools available to install and remove these plugs. Figure 2E-19 shows a running/retrieving tool and Figure 2E-20 shows a running tool. The running/retrieving tool can be used to install and remove the plugs. The running tool can only be used to install the plugs and should never be used to remove any plug.

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WELLHEADS

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Figure 2E-19: Retrieving/Running Tool

4.4

Figure 2E-20: Running Tool

Running Procedures for Type ‘H’ Plugs Before Starting: • • • • •

Thoroughly clean the plug with solvent. Inspect the lip seal, replace if damaged or cut. Inspect the running threads and setting threads for damage. Inspect the plunger and spring to ensure that they are not damaged. If possible set the plug in the hanger (before the hanger is installed).

4.4.1

Method 1: Installation using the Retrieving/Running Tool (Figure 2E-19) A)

Measure from the lock-screws on the top flange of the tubing spool to the top of the tree connection (if installing through a tree), or to the drill floor (if installing through BOPE). To this dimension add 18 to 36 inches. This is the length of polished rod required. B) Assemble the polish rod and attach the Retrieving/Running tool to the bottom piece. C) Thread the plug onto the Retrieving/Running tool (8 to 8-1/2 rounds) and tighten with two 18” pipe wrenches. The connection should be tight enough that when threading the plug into the hanger it will not break out before it is seated. D) Coat the plug threads and lip seal with an even application of never-seize.

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E)

Lower the assembly through the tree, or BOP, and stab plug into the hanger. F) Turn to the right one turn to align the threads. G) Turn to the left 4 to 6 rounds until the rod becomes hard to turn. This is the break-over point and indicates that the plug has seated. H) With an 18” pipe wrench, continue to rotate the rod to the left until they become easy to turn. This indicates that the Running/Retrieving tool is now backing out of the plug I) Continue to turn 8 to 10 rounds to completely disengage the Running/Retrieving tool. J) Remove the rod assembly from the tree, or BOP.

4.4.2

Method 2: Installation using the Running Tool (Figure 2E-20) A)

B) C) D) E) F)

G)

H)

I) J) K)

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Measure from the lock-screws on the top flange of the tubing spool to the top of the tree connection (if installing through a tree), or to the drill floor (if installing through BOPE). To this dimension add 18 to 36 inches. This is the length of polished rod required. Assemble the polish rod and attach the Running tool to the bottom piece. Thread the plug onto the Running tool and make it up until it bottoms out, no torque is required. Coat the plug threads and lip seal with an even application of never-seize. Lower the assembly through the tree, or BOP, and stab plug into the hanger. Turn to the right one turn to align the threads. Watch for the rod to drop about ½ inch; this indicates that the torque pin has engaged the slot on the top of the plug. Turn to the left 4 to 6 rounds until the rod becomes hard to turn. This is the break-over point and indicates that the plug has seated. With an 18” pipe wrench, continue to rotate the rods to the left until a maximum of 50 ft lbs. has been applied. Under no circumstances should the plug be over-tightened. Pick up the rod about ½ inch and continue to turn to the left to thread the running tool out of the plug. Continue to turn 8 to 10 rounds to completely disengage the Running tool. Remove the rod assembly from the tree, or BOP.

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DRILLING PRACTICES LOST CIRCULATION

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LOST CIRCULATION 1.0

INTRODUCTION

2.0

CONVENTIONAL LOSS CIRCULATION MATERIAL 2.1 2.2

3.0

ACID SOLUBLE GROUND MARBLE 3.1

3.2

4.0

Characteristics Procedures

CEMENT PLUG 8.1 8.2

9.0

Characteristics Slurry Volume Calculations Pilot Testing Pumping, Displacement Rates and Equipment Procedures

THIXOTROPIC CEMENT 7.1 7.2

8.0

Types of Polymer Plugs Flo-Chek Temblok-100 High Temperature Blocking Gel Protectozone

BARITE PLUG 6.1 6.2 6.3 6.4 6.5

7.0

Characteristics Procedures

POLYMER PLUG 5.1 5.2 5.3 5.4 5.5

6.0

Characteristics 3.1.1 Selection of CaCO3 Particle Size Basis 3.1.2 Typical CaCO3 Pill Formulation 3.1.3 Average Properties of CaCO3 Carrier Fluid Recommended Procedures

GUNK PLUG 4.1 4.2

5.0

Characteristics Procedures

Characteristics and Precautions Procedures

FOAM CEMENT 9.1 9.2

Characteristics Procedures

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LOST CIRCULATION 1.0

INTRODUCTION 1.1

Loss of circulation occurs when the formation drilled is extremely permeable and a pressure differential is applied toward the formation. The mud loss rate dramatically increases by the excessive overbalance pressures created by the hydrostatic head of the column of mud in the hole. In some cases, decreasing the differential pressure by reducing the fluid density and pumping rate or pressure will stop fluid losses and regain circulation. However, the most effective method for combating lost circulation is to reduce the permeability of the borehole wall by introducing properly sized bridging material, commonly known as loss circulation material (LCM) into the rock pores with a high viscosity pills. Bridging particles contained in the mud will not seal the zone if they are smaller than the formation pores. Potential loss of circulation zones usually encountered in Saudi Aramco’s fields include Pre-Neogene Unconformity (PNU) Umm Er Redhuma (UER) Wasia Formation Shuaiba Arab-D Reservoir Hanifa Reservoir Lower Fadhili Resrevoir Haurania Zone Below the base of the Jilh dolomite

1.2

Major losses Major losses Major losses

Major losses

Loss circulation material (LCM) is normally added to the circulating drilling mud, or in a high viscosity pill to be spotted across the lost circulation zone. The LCM includes, but is not limited to A)

Conventional bridging agents; Fibrous Material ............................................Cedar Fiber Flake Material ...............................................Mica coarse and fine Cellophane Granular Material ..........................................Walnut shells Cotton seed hulls

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B)

Acid soluble sized Calcium Carbonate (CaCO3); Ground marble fine .......................................(10 microns) Ground marble medium ................................(150 microns) Ground marble coarse ..................................(600 microns) Marble chips .................................................(2000 microns) Note: Acid soluble CaCO3 is also a granular material

C)

Reinforcing plugs, cement and others; Gunk Plug Barite Plug Polymer Plug Cement Plug Foam Cement Thixotropic Cement

D)

1.3

Approximate Size of Opening Sealed (Inches)

Severity of Loss

0.125 – 0.250

Seepage to Complete

0.250 – 12.00 12.00 up

Severe Complete Losses Complete (cavernous) Complete (cavernous)

• • • • • • • •

Materials and Size ranges Medium to Coarse Granular Fibrous Material. Fine to Coarse Flakes Marble Chips Barite Plug Cement Plug Gunk or Polymer Plug Drill “Blind”

Drilling may continue without full returns through PNU and UER, using water and gel sweep to ensure hole cleaning. If circulation is lost while drilling through the Wasia Aquifer with mud, circulation must be regained (do not switch over to water and drill ahead) by using one or a combination of the following techniques: A) B) C) D) E)

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The size of the bridging agents are very important, providing consideration is given to the type of loss zone and the severity. The following list provides a general guide for LCM applications:

Conventional LCM pill. Cement Plug. With open-ended drill pipe +50’ above the LC zone, spot 118 pcf Class-G neat cement; plug length not to exceed 500’. Gunk Plug. Thixotropic Cement. Foam Cement. Only to be used when all above techniques have failed to regain circulation.

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1.4

If loss of circulation is anticipated while drilling a potential hydrocarbonbearing zone, run large jet nozzles and BHA without mud motor. 1.4.1

If case loss of circulation is encountered, attempt to regain with at least two consecutive LCM pills: A) B)

C)

1.4.2

If unable to regain circulation, continue drilling with mud cap to the next casing point. A)

2.0

Sized CaCO3 LCM pills. Do not use any other damaging nonacid soluble materials in this pill. Polymer plugs such as Flo-Chek, Zone-lock, FlexPlug and others. Detailed mixing and pumping procedures for this type of plug should be provided by the Service Company in order to tailor the pill to the specific well conditions. Cement or gunk plugs should not be considered unless severe loss of circulation is encountered just below the shoe and could not be regained utilizing Sized CaCO3. In this case, cement plugs or gunk plugs will have to be utilized to regain circulation to enable drilling to continue.

The only exception to this policy applies when experiencing complete loss of circulation in the Arab-D reservoir while drilling Khuff/Pre-Khuff well. In these wells, circulation must be regained before proceeding to the casing point (base of Jilh Dolomite).

CONVENTIONAL LOSS CIRCULATION MATERIAL 2.1

2.2

Characteristics 2.1.1

Materials used generally include Mica Course, Mica Fine, Cotton Seed Hulls, Basco Cedar and Walnut shells.

2.1.2

Prepare LCM pill by isolating the desired volume from the active mud system and mixing 30 to 150 lbs./bbl of LCM. Any combination of the above LCM can be included in this mixture.

Procedures A)

Establish the approximate point of the loss, type of formation, mud level in the hole and rate of loss.

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3.0

B)

Run in hole with open-ended drill pipe 25 to 50’ above the lost circulation zone.

C)

Pump LCM pill down drill pipe until it clears the bottom.

D)

Pick up drill pipe 2 to 4 stands and wait for LCM to settle.

E)

Establish circulation to determine extent of healing and if a second LCM pill is needed.

ACID SOLUBLE GROUND MARBLE 3.1

Characteristics 3.1.1

Various sizes of ground marble are used to stop lost circulation during the drilling operations. Selection of the proper particle size distribution is dependent on the nature of the formation and the severity of the lost circulation. To seal off a rock with large diameter pores, particles larger than the pore size will be more effective than smaller ones. Any particle smaller than one third the pore size will pass through the pore pattern and will not effective in stopping the losses. Note: The sealing characteristic of the lost circulation pill is governed not by the concentration of particles but by the shape and size distribution of the particles carried in the pill. Properly sized bridging material must be selected to block the formation pores effectively at the wellbore face. The particles should have a broad size range, and 20 - 50 percent of the particles should be at least one-third the average formation pore size to establish the desired bridging mechanism. The reservoir engineer or geologist should be consulted for the proper particle size selection required for a non-penetrating fluid. The lost circulation pills must be spotted at the pay-zone by pumping the pill down hole at a rate that will jam the particles quickly at the entrance of the formation flow channels. Slow pumping may allow the bridging particles to seep into the Arab-D vugular and/or fractured rocks.

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3.1.2

A typical example of a sized CaCO3 pill formulation for Arab-D payzone is as follows: Order of addition

• • • • • • • •

for one barrel

Fresh water Defoamer Suspending polymer (XC-Polymer) Primary viscosifier (HEC) Filtrate control polymer (starch) Lime or MgO Ground marble medium (150 microns) Ground marble coarse (600 microns)

0.01 - 0.02 0.50 - 1.00 1.00 - 2.00 2.00 - 4.00 0.50 - 1.00 30 - 80 100 - 120

gal lb lb lb lb lb lb

Note:

3.1.3

1.

Add polymers slowly through the hopper to avoid the formation of lumps or fish eyes and achieve high viscosity and gel strength.

2.

The concentration and the size distribution of the ground marble can be tailored or varied according to the severity of losses. Medium and Coarse can be pumped through the bit nozzles.

3.

When attempting to stop severe lost circulation with large size (2000 micron) Marble Chips, use open-ended drill pipe. Due to the large size of the Marble Chips, the bit nozzles will be plugged.

Average properties of the carrier fluid prior to adding the CaCO3 should be in the following ranges: ♦ ♦ ♦ ♦ ♦

3.2

Funnel Viscosity PV YP Gels pH

150 - 200 sec/qt 30 - 40 cp 2 40 - 50 lb/100 ft 2 12 - 18 lb/100 ft 10 - 11

Recommended Procedures A)

Establish the approximate depth of the thief zone, type of formation (porosity and permeability - is it “super k”?), height mud stands in the hole and rate of losses.

B)

Run in hole with large size jet nozzles or open ended drill pipe to the top or near the top of the lost circulation zone. 5 of 26

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4.0

C)

Pump the Marble chip or sized CaCO3 pill through the drill pipe at normal rate and speed the pump as the pill clears the drill pipe.

D)

Pick up drill pipe 3 stands and wait on bridging particles or chips to settle and a cake to build up.

E)

Circulate to determine if the lost circulation zone has been sealed. If full circulation can be established, run in hole slowly to bottom and resume normal drilling operation. If partial losses still exist, continue drilling for a while to generate some drilled cuttings which in many cases have helped as a sealing mechanism.

F)

Repeat the above procedure and modify the bridging particles size distribution if required. Perhaps larger particles are needed or the carrier fluid viscosity should be increased.

GUNK PLUG 4.1

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Characteristics 4.1.1

Gunk Plug is bentonite-in-diesel slurry. When dry bentonite is mixed into diesel oil, the bentonite will not yield and the slurry remains a relatively thin fluid. This allows the slurry to be pumped to the bit with relatively low pressure. When the slurry leaves the bit and becomes exposed to water in the annulus, the bentonite will rapidly hydrate, causing the slurry to become extremely viscous or gunk like. This extremely viscous gunk will have high resistance to flow through the rock pores or channels and in many situations it will provide a complete seal.

4.1.2

Gunk Plugs will lose strength with time under downhole conditions and should be followed by a cement plug to provide a permanent seal.

4.1.3

The slurry is jet mixed with a cement unit to 82 lbs./cu.ft. This normally requires 300 pounds of bentonite per barrel of diesel. Additions of Mica at (about 15 lbs/bbl) will increase the strength of the plug, but is optional. The slurry volume to be pumped normally ranges from 20 to 150 barrels, and is based on the rate of loss circulation and amount of open hole.

4.1.4

Gunk Plugs may become commingled with water inside the drill string. If this occurs, pump pressure will become excessive, resulting in a plugged drill string. For this reason, sufficient diesel spacers are required ahead and behind the slurry.

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4.2

Procedures A)

B)

5.0

Run with closed end drill pipe and mixing sub to 20 feet above loss circulation zone. Rig up both the cementing unit and the rig pumps so that either can be used to displace the slurry. A third pump should be connected to the annulus. Pump 10 to 20 barrels of diesel into the drill pipe for the spearhead spacer. This step is critical to separate the slurry from the waterbased mud.

C)

Jet-mix the slurry to 82 pcf. The slurry can be batch mixed or pumped on the run.

D)

Tail in with a 10 to 20 barrels diesel spacer.

E)

Displace the slurry at a rate of 3 to 5 barrels per minute with mud.

F)

Begin pumping water-based mud down the annulus at a rate of 1.0 bbl per minute as soon as the slurry reaches end of the drill pipe.

POLYMER PLUG Polymer plugs are commonly used for temporarily or permanently healing of loss circulation. The following are polymers that are available through the in-Kingdom Service Companies. It is important to emphasize the need to (a) tailor the plug design for the well conditions, (b) laboratory test the plug to fine-tune the polymer additive concentrations, and (c) ensure satisfactory polymer plug performance.

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5.1

Types of Polymer Plugs

Service Company B.J. Services

Product Name Remarks High Temperature It is pumped as a low viscosity liquid which turns to a rigid polymer plug Blocking Agent when subjected to heat, after a controlled time delay. Can be broken down with 15% HCl or water containing oxidizers. Can be jetted out using coiled tubing or drill pipe. It is a solids-free solution with a very Dowell-Schlumberger Permablok low initial viscosity that can easily penetrate formation matrix. It is then activated by temperature to produce a strong, coherent gel.

Zonelock S and Zonelock SC

LCM D111

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Note: the Maximum temperature that the hardened gel can withstand is 356oF. Zonelock S, a solution of liquid extender D75 and water, forms a rigid semi-permeable gel when in contact with a heavy calcium or sodium brine. Zonelock SC utilizes Zonelock S followed by a spacer and then cement slurry. When the slurry contacts the gel resulting from the D75/calcium chloride solution, the cement will set very rapidly (less than 2 minutes). The Zonelock SC forms a permanent seal that can only be drilled out. Extends the use of RFC (Regulated Fill-Up Cement) to offshore platforms or areas where solid additives is impractical. It imparts thixotropic properties, characteristic of RFC slurries. D111 slurries do not expand upon setting. D111 can be used with any Portland cement and either fresh or seawater.

Limitation -Highly sensitive to diesel and low pH contamination

-On-site mixing should only be performed with fresh water. -Max. temp. for D140 hardener is 225oF.

- A spacer of fresh water or Trisodium Phosphate M8 must always be used between the D75 solution and cement

-Can only be used with limited number of additives. -Dispersants & fluid -loss control additives destroy the thixotropic properties

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Service Company

Product Name InstanSeal

Protectozone

Halliburton

Flo-Chek

Flex-Plug-W

Temblok-100

Remarks An unstable inverted emulsion that flips spontaneously to hard solid gel when exposed to a pressure drop of 650 psi or above across the bit nozzles. A rigid aqueous gel with controlled setting and breakdown times. Note: Oilfield brine should not be used; only use fresh water or prepared NaCl brine.. A two-fluid system; lead slurry consists of Flo-Chek Chemical A (Injectrol A) to which may be added sand and TUF Additive No. 2. The Flo-Chek Chemical A is followed by a fresh water spacer and a predetermined amount of cement slurry. The latter is used to obtain the final and permanent squeeze. Non-particulate material that reacts with the drilling mud, resulting in a nonbrittle bridge at the opening of the loss zone. Note: Must not contact aqueous fluids in the mixing equipment. Long-life viscous gel which is affected by temperature and pH. 225oF max BHST; above 225oF use Temblok-90.

Limitation 180oF maximum allowable BHST. 325oF Max. allowable BHST.

Injectrol is highly alkaline. 200oF max allowable BHST.

Cannot use as additive in a cement slurry.

Easily removed with acid. Cannot be used in CaCl2 brine.

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5.2

Flo-Chek: Typical Mixing and Pumping Procedures A)

Run In Hole with open ended drill pipe to just above the loss circulation zone. Pump rate should be maintained between 3 to 5 bpm.

B)

Pump 1000 gals (24 bbls) of 15% CaCl2 water. Add 62 lbs. of Calcium Chloride to one barrel of water. Need 1488 lbs of CaCl2 to make 1000 gallons of 15% CaCl2 water.

C)

Pump 5 bbls of fresh water.

D)

Pump 500 gals (12 bbls) of Flo-Chek polymer.

E)

Pump 5 bbls of fresh water.

F)

Pump 50 sacks (10.2 bbls) of cement, mixed at 118 pcf, 5 gals/sack, and 1.15 cu. ft./sack.

G)

Pump 5 bbls of fresh water.

H)

Pump 500 gals (12 bbls) of Flo-Chek polymer.

I)

Pump 5 bbls of fresh water.

J)

Pump 150 sacks (30.7 bbls) of cement mixed at 188 pcf, 5 gals/sack, and 1.15 cu. ft./sack.

K)

Displace cement with drill water to the end of drill pipe.

L)

Pull out of hole with drill pipe.

Note:

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The Flo-Chek and cement must be suitably separated from each another by fresh water. It is advisable to pump CaCl2 with rig pumps while the fresh water spacer, Flo-Chek and cement is mixed and pumped by Halliburton. The Halliburton pumps must be isolated to prevent intermixing of cement and Flo-Chek.

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5.3

Temblok–100: Typical Mixing and Pumping Procedures A)

Run In Hole with open-ended drill pipe to circulate and condition the hole.

B)

Ensure all equipment that will be used during the job is completely free of acid or other contaminants that may affect the pH of the fluid. The tanks, blenders and pumping equipment must be neutralized by circulating a K-35 solution, which is made up of 100 pounds of K-35 per 1000 gallons of fresh water.

C)

Prepare all fluids into neutralized equipment as follows:

D)

1.

K-35 spacer (per1000 gallons), made up of 1000 gals of Fresh Water 100 lbs of K-35

2.

Temblok-100 (per 1000 gallons) made up of 1000 gallons of Fresh Water 6 lbs TB-41 40 lbs K-35 425 lbs WG-11 35 lbs WG-17

The Temblok-100 system should be prepared as follows: 1.

Mix the saturated salt water as outlined above.

2.

Add the proper amount of TB-41 to the saturated salt water and mix for 10 minutes.

3.

Load into neutralized mixing tank the proper amount of fresh water.

4.

Add the appropriate amount of K-35 based on lab tests, to the mix water and circulate until dissolved. Check the pH to ensure it is 10.5 to 11. If it is less, add small amounts of K-35 until the correct pH is achieved.

5.

Add the proper amount of WG-11 and circulate to mix all the gel, try to avoid any air entrapment.

6.

Add the proper amount of WG-17 SLOWLY. The slurry will become more viscous at this point. Slowly circulate the slurry until ready to pump. 11 of 26

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Note: The slurry should not be mixed for more than 1-1/2 hours prior to pumping as the fluid may become too viscous to pump. E)

Pump the Temblok-100 system, spot and balance as follows: 1.

Pump K-35 spacer (usually 500 linear feet of drill pipe).

2.

Pump Temblok plug (Volume to be determined by plug length desired).

3.

Pump K-35 spacer (usually 500 linear feet of drill pipe).

4.

Pump the required amount of displacement fluid as fast as practical to minimize the residence time in the pipe.

F)

Balance the plug as best as possible to reduce any U-tubing or stringing of the fluid.

G)

Shut down and SLOWLY pull the drill pipe from out of the plug so as not to cause any swabbing.

H)

Pull the drill pipe up above the plug and reverse circulate until bottom up are seen to ensure there is no Temblok remaining in the pipe. Note: Pull far enough above the plug in order not to disturb the Temblok plug.

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I)

Shut down to allow the Temblok to hydrate for at least 2 hours.

J)

Run in hole with drill pipe and make an attempt to tag the plug in order to confirm its position. This will allow the placement of a second pill should the first pill be unsatisfactory or not in the correct place.

K)

Pull out of hole with drill pipe if the plug is found to be satisfactory.

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5.4

High Temperature Blocking Gel The following is a general recipe for the BJ Services High Temperature Blocking Gel. The recipe should be modified depending on the severity of the Loss Circulation. Ingredients for 1000 gallons (500 pptg System) GW-38 Suspending Gel) BF-7 (Delay Buffer) Boric Acid (Crosslinker) GW-38 (Main Polymer) Breaker

20 – 50 pounds5 12 pounds1 5 pounds 480 – 450 pounds2 Note 3

Note: 1.

2.

3.

4. 5.

5.5

The BF-7 will vary according to the temperature and delay time required. Delay times can be set from as low as 20 minutes to as high as 4 hours. At 200oF, the above loading will provide 75 minutes pumping time and 120 minutes setting time. The GW-38 loading will vary as required. The suspension gel may be raised (see note 5) to minimize polymer settling at the higher loading and control leak-off. An external breaker of either 15% HCl or water containing oxidizers can be used. The system can be jetted out using coiled tubing or drill pipe. The system is highly sensitive to diesel and low pH contamination. Use the higher loadings to achieve a more viscous base gel. This will reduce fluid leak-off to the formation.

Protectozone 5.5.1

Protectozone WL300 Plug U803 and WL500 Plug U804 are gel systems that work at bottom hole static temperatures between 50 and 200oF. The gels are formed by adding varying amounts of LowTemperature Plugging Agent J170 to the appropriate volumes of fresh water or prepared sodium chloride brine. A water-soluble catalyst Sodium Dichromate M6 is added for control of setting times. Specific breakdown times are obtained by using either Breaker J134 or PROTECTOZONE M24 additive as an internal chemical breaker. Breaker down times of one day to three weeks can be obtained.

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5.5.2

Ingredients for 500 gallons of gel mix:

1.

2. 3. 4.

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Order of Addition Add fresh water to a clean, acidfree tank. Prepare NaCl brine, if needed. Add J170 within 5 min. to reduce lumping. Add chemical breakers and continue agitation. Prior to pumping, add M6 catalyst and mix for 2 to 3 minutes

Amounts of Materials WL300 WL500 488 gal 480 gal

J170 150 lbm Add J134 Add M6

J170 250 lbm Add J134 orM24 Add M6

5.5.3

Protectozone WH500 Plug U805 and WH750 Plug U806 are gel systems that work at bottom hole static temperatures between 200 and 325oF. The gels are formed by adding varying amounts of HighTemperature Plugging Agent J171 to the appropriate volumes of fresh water or prepared sodium chloride brine. PROTECTOZONE M24 additive is used when well temperature is between 200 and 255oF. When well temperatures are between 240 and 325oF, FIXAFRAC J59 Diverting agent is used. Diverting agent FIXAFRAC J66 or J66S rock salt is recommended to prevent excessive loss to the formation. Gel life of up to 20 days is possible at temperatures above 200oF.

5.5.4

General Guidelines on Ingredients and Mixing A)

When using J66 and J66S rock salt, the base fluid for PROTECTOZONE WH must be prepared 9.5 lbm/gal NaCl brine. The salt will slightly increase the thickening time of the WH500/wh750 system.

B)

Do not run J66/J66S in the first 10% of the slurry. This should allow the slurry to penetrate deeper in the larger fractures and vugs.

C)

Do not add diverting agent in the last 10% of the slurry (but not more than the capacity of 500 feet of tubing). This is a safety measure to avoid solids in that portion of the slurry that may remain in the tubing during hesitation-squeeze operations. This length will very for drill pipe depending on the size in use.

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D)

Add J66/J66S to the middle 80% of the slurry, do not exceed 0.5 lbm/gal. In large-volume treatments, the diverting agent can be added in stages during the treatment.

E)

M24 breaker is used for temperatures up to 260oFand J59 for temperatures from 240 to 325oF.

F)

Add 25 lbm of Synthetic polymer J166 per 1000 gallons for temperatures to 215oF and 50 lbm for temperatures greater than 215oF.

G)

Add 3.5 lbm of Soda Ash M3 for each 25 lbm of J166 used.

H)

Use 500 lbm of High-Temperature Plugging Agent J171 per 1000 gallons at temperatures above 250oF and 750 lbm of J171 per 1000 gallons at temperatures between 240 and 325oF.

Note: Do not use oilfield brines because such waters contain excessive amounts of calcium and magnesium salts, which can unpredictably accelerate the setting time.

6.0

BARITE PLUG A barite plug is very effective in stopping underground blowouts and severe loss circulation. The important fact is that an underground blowout cannot be controlled by conventional methods because the wellbore will not stand full of kill-weight mud. Usually, the first step to shutting off the underground flow is the spotting of a high density barite pill between the flowing and lost returns zones. The barite pill slurry is usually mixed with cementing equipment and is spotted on bottom where the high density of the plug (18 – 22 ppg or 119 – 164 pcf) holds additional pressure on the formation, eventually stopping underground crossflow. After the crossflow is stopped, barite settles out and forms a pressure competent bridge. Sometimes sloughing of the shale also occurs as a result of the fresh filtrate that is created as a result of the barite settling out. This shale sloughing helps in bridging the hole, thus creating zonal isolation. A barite pill can also be used to control high pressure, low permeability formation so that another string of casing can be set. This type of formation will cause severely gas-cut returns, but will not usually cause appreciable well flow; however, the casing seat usually will not hold the mud weight required to contain the formation.

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6.1

Composition and Density 6.1.1

The Barite plug consists of barite, water, a thinner and pH controller. The thinner is needed to deflocculate the barite slurry, which results in improved pumpability and allows the barite to settle from the slurry at a predictable rate. Common deflocculating agents include A)

SAPP (Sodium Acid Pyrophosphate) which is stable up to 180o F temperature. Usually SAPP has high fluid loss (≈25cc). It is ineffective with some barites and cannot tolerate excessive salt or calcium in the mix water. Pilot testing of the barite plug in the lab is highly recommended prior to field use.

B)

Lignosulfonate is stable up to 350o F temperature. It has a low fluid loss characteristic of ≈5cc.

6.1.2

Caustic soda is used as a pH controller. It provides the alkaline environment (pH 10-11) necessary for the lignosulfonate to be effective.

6.1.3

The recipe for one barrel of 157 pcf barite slurry includes: A) B) C) D)

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0.54 bbl water 691 lbs barite 8 lbs lignosulfonate 1 lb caustic soda

6.1.4

The lignosulfonate recipe above will work for all barites and in brines up to sea-water salinity and hardness, provided the pH is kept up close to 11. For mix waters with hardness above 250 ppm, the hardness should be reduced by raising the pH to 11 and then adding soda ash as necessary. With any high salinity brine, pilot testing is recommended to insure the final slurry meets the requirements.

6.1.5

Since SAPP will deflocculate some, but not all, barite slurries, it may occasionally be substituted for the lignosulfonate in the recipe. Proper concentrations would be 1/2 ppb SAPP and 1/4 ppb caustic soda.

6.1.6

A 157 pcf slurry density usually provides a good balance between maximizing slurry density and adequate pumpability. In some cases pilot testing may indicate a more appropriate density and the recipe may be modified accordingly.

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6.2

Slurry Volume Calculations 6.2.1

Slurry volumes depend on the amount of open hole and the severity of the kick. These volumes normally range from 300 sacks (40 bbls) to 3000 sacks (400 bbls).

6.2.2

If the kick pressure is know or can be estimated, then the height of the barite slurry needed to kill the kick can be calculated as follows H = KD/B Where

H = Barite pill height (feet) K = Excess kick pressure equivalent above mud weight (in pcf). For example, a “ten pcf kick” is K = 10 D = Depth of kick (feet) B = Excess barite slurry density above mud density (pcf)

The slurry volume should be 125 to 150% of the annular capacity necessary to give the height of the plug desired, but should not be less than 40 barrels (300 sacks). If a second barite plug is required, then the slurry volume should be greater than the first. 6.3

Pilot Testing Because of variations and possible contamination of ingredients, it is always advisable to pilot test a barite slurry in the field prior to pumping in the well. Prepare a sample of the slurry using the above recipe and ingredients (section 7.1.3) at the wellsite. After stirring well, the sample should have the expected density and be pumpable. If the brine needs to settle in the wellbore, the pilot test should reflect so. Reasonable settling is 2 inches in a mud cup after 15 minutes. The settled cake should be hard and somewhat sticky, not soft and slippery. The settling test is not a guarantee that the barite pill will form an effective plug under downhole conditions, but will certainly give an indication of the settling characteristics.

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6.4

Pumping, Displacement Rates and Equipment 6.4.1

Pumping and Displacement Rates A barite pill should be pumped and displaced at a rate somewhat higher than the kick rate. If the kick rate is unknown, a reasonable rate (5 – 10 barrels per minute) should be used for the first attempt, although prolific blowouts can ultimately require kill fluid placement greater than 100 barrels per minute.

6.4.2

Equipment The equipment needed on location to prepare and pump a barite plug is as follows: (a) (b) (c)

A cementing unit equipped with a high pressure jet in the mixing hopper A means of delivering the dry barite to the cementing unit Sufficient clean tankage for the mix water so that the lignosulfonate and caustic soda can be mixed in advance

The barite slurry may be pumped into the drill pipe either through a cementing head or through the standpipe and Kelly. In either case, the pump tie-in to the drill pipe should contain provisions for hooking up both the cementing unit pump and the rig pump so that either can be used to displace the slurry. If this is not done and the cementing unit breaks down, the barite may settle in the drill pipe before the mud pump tie-in can be made or the cementing unit repaired. Blockage of the drill string by barite settling will complicate the well control problem. 6.5

Procedures 6.5.1

If Pipe is Free If pipe is free at the end of the pumping operation, it may be possible to pull out of the plug. The risk of pulling out of a plug that is set to contain an underground blowout is high, especially if a second barite plug becomes necessary. The risk considerations are as follows:

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A)

The pipe may become stuck at the shallower depth. This limits the effectiveness of subsequent barite plugs if required.

B)

A stripping operation may be necessary to pull the pipe or to return to bottom.

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6.5.2

Leave Pipe in Place (Underground Blowout) A)

Mix and pump the slurry at the appropriate rate. Monitor the slurry density with a densometer in the discharge line or a pressurized mud balance. Displace the slurry immediately at the same rate.

B)

Overdisplace the slurry by 5 barrels to clear the drill string. Continue to pump 1/4 barrel at 15 minute intervals to keep the drill string clear unless pressure remains on the drill pipe.

C)

To verify whether the underground flow has been stopped, a noise log can be used. Temperature surveys can be used in addition for confirmation or if the noise log is not available, however the noise log is more definitive than temperature logs. If temperature surveys are to be used, wait 6 to 10 hours for the temperature to stabilize. The survey will show a hotter than normal temperature in the shallower zone of lost returns. After 4 hours. a second temperature survey will show a decrease in temperature (cooling) across the zone of lost returns.

D)

After confirming that underground crossflow has been stopped, bullhead a cement slurry through the bit to provide a permanent seal. Observe the annulus during pumping. If the casing pressure begins to change a lot or a sudden change in pumping pressure is observed, the barite plug may have been disturbed. In this case, over-displace the cement to clear the drill string. Additional cementing might be desirable to obtain a squeeze pressure.

E)

Plug the inside of the drill string. This can be accomplished by either under-displacing the cement plug in step (D) above, or preferably setting a wireline bridge plug near the top of the collars. Cement should be dump bailed on top of the wireline bridge plug for additional safety.

F)

Pressure test the plug, inside the drill pipe.

G)

Perforate the drill string near the top of the barite plug and attempt to circulate.

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♦ It may be difficult to tell whether the well is circulating or flowing from the charged formation. Pressure communication between the drill pipe and annulus is one clue. Another is that a pressure increase should have appeared on the drill pipe from the annulus pressure or on the casing from hydrostatic pressure in the drill pipe when the perforation was made. ♦ Consideration should be given to circulating with lighter mud because of the known zone of lost returns. 1.

2.

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Well will circulate i)

Use drill pipe pressure method to circulate annulus clear of formation fluid.

ii)

Run a free-point log.

iii)

Begin fishing operations.

Well will not circulate i)

Squeeze cement slurry through perforation(s). Cut displacement short on final stage to provide an interior plug or set wireline bridge plug. WOC and pressure test plug.

ii)

Run free-point log.

iii)

Perforate the pipe near the indicated free point.

iv)

Circulate using drill pipe pressure method until annulus is clear. If well will not circulate, squeeze perforation(s) with cement or set a wireline bridge plug above perforation(s), and reperforate up the hole.

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6.5.3

Pull Out of Plug (High Pressure, Low Permeability Formation) A)

Mix and pump the slurry. Monitor the slurry weight with a densometer in the discharge line or a pressurized mud balance. If mixing is interrupted for any reason, immediately begin displacement of the slurry using either the cement unit pumps or the rig pumps. Work the pipe while pumping and displacing.

B)

Displace the slurry with mud at the same rate. Cut the displacement short by 2 or 3 barrels to prevent backflow from the annulus. If a drill pipe float is in the drill string, overdisplace the slurry.

C)

Immediately begin pulling the pipe. It may be necessary to strip the pipe through the annular preventer. Pull at least one stand above the calculated top of the barite slurry.

E)

1. If no pressure is recorded on the annulus, continue working the pipe while observing the annulus mud level. i) ii)

Annulus full: Begin circulating at a low rate keeping constant watch on the pit levels. Annulus not full: Fill annulus with water and observe. If annulus stands full, begin circulating at a slow rate. Consider cutting the mud weight if feasible.

2. If pressure is recorded on the annulus, circulate the annulus clear using normal well control techniques. Continue working the pipe. i) ii)

If returns become gas free, the barite pill was successful and the well is dead. If returns do not become essentially gas free after circulating two or three annular volumes, the barite pill was not effective. A second plug will be necessary.

E)

After determining that the well is dead, go back in the hole to near the top of the barite slurry. Set a balanced cement plug and pull out a few stands. This step is sometimes eliminated.

F)

After waiting for the cement to set up, run back in hole and tag the top of the cement plug.

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7.0

THIXOTROPIC CEMENT 7.1

Characteristics Thixotropic slurries have the shear-thinning characteristic. This means that the slurry under shear will stay in fluid phase but develops a gel structure when the shearing force stops.

7.2

Procedures Typical Thixotropic cement job.

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A)

Run in hole open-ended to 25 feet above loss circulation zone.

B)

Pump desired volume of a selected polymer plug.

C)

Follow with Thixset cement slurry. i)

Slurry mix: Class-G Cement + 1.0% Comp A + 0.25% Comp B + fresh water + defoamer.

ii)

The above mix is a Halliburton recipe. Equivalent chemicals and mixes can be used from the other In-Kingdom pumping service companies.

D)

Continue pumping cement until the agreed upon volume has been pumped or until squeeze pressure is noted. A pressure increase of 250 psi is sufficient for squeeze applications of this nature.

E)

Displace the cement with fresh water. Shut down, pull at least four stands and clear drill pipe.

F)

Once the drill pipe and annulus are clean, pull out of hole.

G)

Wait on cement 6 to 8 hours to give the cement time to set.

H)

Run in hole with drill pipe and tag top of cement. Attempt to fill annulus. If returns are noticed, resume drilling, otherwise, consider repeating process or attempting different process.

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8.0

CEMENT PLUG When mud circulation is lost while drilling, it is sometimes possible to restore returns by spotting a cement plug across the thief zone, and then drill back through the plug. The balanced cement plug is usually preferred and it is the most common method. 8.1

Characteristics When placing a cement plug across a thief zone to combat lost circulation, it is important to take every precaution to ensure that the cement sets properly. The following are general preventive measures: A)

Use neat cement with 0.25 lbs/sack of Cellophane Flakes (optional). Thickening time should be checked against the estimated cement placement time.

B)

In shallow thief zones, avoid circulating cement extensively. Extensive circulation will retard the development of cement strength. It is desirable to achieve early strength and allow the cement to set without agitation.

C)

Use sufficient spacer that is compatible with the mud ahead of the cement (water spacer is usually used).

D)

When calculating cement volume, include 50 to 100 feet of cement height above the thief zone depending on the severity of the losses.

E)

Place the plug with care and move the pipe slowly out of the cement to minimize swabbing action and mud contamination.

F)

Allow ample time for the cement to set prior to drilling out.

Note: Cement placement failures commonly occur due to fluid backflow, slugging or improper displacement volumetric calculations. 8.2

Procedures A)

Determine the severity of circulation loss to decide on the cement plug length above the thief zone. Maximum plug length is 500 feet.

B)

Run in hole with open-ended drill pipe to 10 feet below the bottom of the loss zone. Spot a 100 bbl LCM pill (50 #/bbl) across loss zone.

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C)

Pick-up 30-50’ above the circulation loss zone. Pump down the drill pipe the calculated spacer, cement, spacer and kill fluid. This involves balancing the hydrostatic pressure inside and outside the drill pipe so that the height of the cement and displacing fluid inside the drill pipe equals the height of fluids in the annulus (see sketch below). Note: Do not use a water spacer if loss circulation is in the Wasia.

M

M

M

W

W

M

M

M

W

W

W

M

W

M

(a) Displacing cement.

M

(b) Cement, water and mud balanced.

M

M

M

M

W

W

M

M

(c) Pulling string above top of cement.

M

(d) Reversing out.

M = Mud Balanced Plug Technique

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W = Water

D)

Pick up drill pipe to +400 feet above the top of the calculated spacer. While pulling out of the cement, pull slowly to avoid swabbing and mud contamination.

E)

Pump mud down the casing-drill pipe annulus and reverse circulate (if possible) to insure pipe is clean of cement.

F)

POH to casing shoe. WOC. Attempt to fill hole. If unsuccessful, RIH with open-ended drill pipe and tag top of cement. Set a second cement plug on top of Plug #1. Repeat process as described above.

G)

If the hole can be successfully filled, pull out of hole with open ended drill pipe. Run in hole with bit and drill out cement plug while keeping a close watch on the mud level in hole. If hole starts taking fluid, note depth and consider spotting of another cement plug or other type of plugs.

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9.0

FOAM CEMENT 9.1

Characteristics Foam Cement is a mixture of cement slurry, foaming agents, and a gas (usually nitrogen). When properly mixed, the process forms an extremely stable, lightweight, low permeability slurry that looks like gray shaving cream. Foam cement slurries can be prepared in the range of 30 to 112 pcf, which develop relatively high compressive strength in a minimum period of time. Although Foam Cement is mainly used in primary cementing, it may be used as a plug to regain lost circulation in zones where all other loss circulation methods have failed.

9.2

Procedures: (Foam Cement with Flo-Chek or Flo-Chek 1:1) A)

The fluid level should be determined as close as possible with an estimate of the fluid density in the well bore.

B)

All personnel should be prepared for N2 gas cut returns and a method of choking the well flow should be installed. It is not advisable to take Foam Cement returns through the rig’s choke manifold. A disposable adjustable choke should be installed if possible. Due to the viscous nature of Foam Cement, it is likely that a cement sheath will be left in the drill pipe. To help reduce this effect, a drill pipe wiper plug and catcher attachment should be installed so that the drill pipe may be cleaned during displacement.

C)

RIH with open ended drill pipe, with a plug catcher if available, to a depth that is at least 50’ above the loss circulation zone. Note:

It is advisable to lead in with a slug of mud containing LC material.

D)

Flush and fill lines with fresh water. Pressure test lines to 3000 psi.

E)

OPTIONAL: Pump the following sequence with the annulus open at +3BPM: 1. 2. 3. 4. 5. 6. 7. 8.

24 bbls CaCl2 Brine Water as an activator solution 5 bbls Fresh Water as a spacer 12 bbls Flo-Chek or Flo-Chek 1:1 5 bbls Fresh Water as a spacer 24 bbls CaCl2 Brine Water as an activator solution 5 bbls Fresh Water as a spacer 12 bbls Flo-Chek or Flo-Chek 1:1 5 bbls Fresh Water as a spacer 25 of 26

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F)

Follow the Flo-Chek system with Foam Cement consisting of Class G mixed at 118 pcf. Add N2 on the fly to bring the combined slurry weight to 63.5 – 67 pcf. The cement pump rate should be held to +3BPM. The foaming solution, consisting of 1.5% BWOMW HOWCO SUDS and 0.75%BWOMW HC-2, will be injected at a combined rate of 0.6 gal/bbl of slurry. Foamer FDP-C552 may be substituted for the HOWCO SUDS & HC-2 at the same loading. Note: At any time during the pumping process, with the annulus open, be sure to close it once returns are noticed. Monitor the pressure closely after the annulus has been closed and be prepared to shutdown quickly.

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G)

Continue pumping Foam Cement until the agreed upon volume has been pumped or until squeeze pressure is noted. A pressure increase of 250 psi is sufficient for squeeze applications of this nature.

H)

Drop the drill pipe wiper plug, if available, and displace the Foam Cement with fresh water.

I)

Shut down, pull at least four stands, shear plug catcher and allow the rig to reverse out any remaining cement that may be in the drill pipe. Be prepared to reverse out under pressure. If Foam Cement is reversed out, it will exit at an extremely high velocity. Control and regulate the return rate using surface valves or choke manifold.

J)

Once the drill pipe and annulus are clean, POOH.

K)

Wait on cement 12-14 hours to allow the cement time to set.

L)

RIH with drill pipe and tag top of cement. Attempt to fill annulus. If returns are noticed, resume drilling. Traces of N2 will be seen at surface while drilling through the Foam Cement column.

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DRILLING PRACTICES ABANDONMENT GUIDELINES

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ABANDONMENT GUIDELINES 1.

CEMENT PLUGS 1.1 Introduction 1.2 Open Hole 1.2.1 Hydrocarbon Bearing Formations 1.2.2 Porous Aquifers 1.2.3 Last Casing Shoe 1.2.4 Extended Open Hole 1.3 Cased Hole 1.3.1 Casing-to-Formation Annulus 1.3.2 Hydrocarbon Zones 1.3.3 Water Source Zones 1.3.4 Injection Zones 1.3.5 Extended Cased Hole 1.3.6 Casing-To-Casing Annuli 1.3.7 Other Protective Plugs

2.

MARKERS 2.1 Onshore 2.2 Offshore

3.

RADIOACTIVE TOOLS (Lost in Hole) 3.1 General Information 3.2 Procedures

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ABANDONMENT GUIDELINES 1.0

CEMENT PLUGS 1.1

Introduction Wells may be abandoned for any one of a number of reasons. Abandonment procedures in newly drilled wells are largely dictated by individual well conditions. Factors affecting abandonment programming include: A) B) C) D) E) F) G) H) I)

Mechanical condition Hole problems while drilling Location Casing configuration and cementation integrity Productive nature and interrelation of porous hydrocarbon bearing zones Corrosion considerations Local development plans Governmental directives Economic considerations

aquifers

and/or

Proper abandonment is therefore a combination of sound judgment and applicable oilfield practices tailored to a particular well. The guidelines presented herein are intended to establish uniform abandonment objectives while recognizing practical limits often imposed by well conditions. 1.2

Open Hole 1.2.1

Hydrocarbon Bearing Formations Cement plugs are placed across all hydrocarbon bearing formations and extend at least 100’ below and 100’ above each formation. The presence of the plug across the hydrocarbon formation nearest the last casing shoe is to be confirmed by setting down the string weight on the plug after waiting on cement (WOC). Presence of all plugs isolating gas reservoirs should be checked in the same manner.

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1.2.2

Porous Aquifers Porous aquifers are to be isolated by cement plug placed across and/or between zones resulting in at least 100' of plug height separation between zones where possible. Check integrity (drill string weight) of the plugs as follows: A) B)

C) 1.2.3

Separating aquifers from uphole hydrocarbon zones Separating aquifers, which are potable or suitable for irrigation purposes. The workover engineer should check with the Hydrology Dept. for this information Separating all abnormally pressured water bearing zones

Last Casing Shoe A 300' cement plug should be placed across the last casing shoe and will extend at least 150' above the shoe. The plug should be tagged with the drill string and pressure tested to at least the maximum equivalent mud weight used in the open hole plus 25%. The tag up and pressure test should be witnessed by the Aramco representative on the rig and noted in the tour report.

1.2.4

Extended Open Hole In long sections of open hole which would not be plugged for reasons above, a 300' cement plug should be placed at no greater than 2000' intervals. The plug placement should be tagged with the drill string. Long open hole sections are common on deep exploratory wells.

1.3

Cased Hole 1.3.1

Casing to Formation Annulus A)

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Where cement is not returned to surface during a cement job, the top of cement can be estimated from volumes of cement pumped, fluid returned and the hole diameter. Cement bond logs and/or temperature surveys can be run to determine the cement top and should normally be adequate confirmation of annular shut off integrity in critical situations. Under certain circumstances, however, perforating, cement squeezing and a dry test may be warranted.

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B)

1.3.2

If the bond is questionable, the annulus should be cement squeezed between hydrocarbon reservoirs, between hydrocarbon and separate porous aquifers, and between separate porous aquifers. The UER is usually isolated from the Khobar by cement squeezing the RUS whereas the Wasia is isolated from the upper aquifers by cement squeezing the LAS.

Hydrocarbon Zones All hydrocarbon zones tested or commercially produced then abandoned should be squeeze cemented after ensuring annular shut off and pressure tested to at least 50% above the balance mud weight equivalent (not to exceed the derated casing burst pressure). Gas zones are to be squeezed through a cement retainer, capped with at least 50' of cement, tagged and pressure tested as above. Depending upon the condition of the casing, a retrievable isolation test packer may be run for this pressure test if required.

1.3.3

Water Source Zones Annular shut-off (formation to casing) should be ensured prior to squeeze cementing water source zones. If squeezing is unfeasible, an interior cement plug extending at least 100' below and 100' above will be placed, tagged, and pressure tested to the safe casing limit.

1.3.4

Injection Zones Abandoned injection zones (water injection, disposal, product injection) should be cement-squeezed after confirming annular shut off above and below the zone. Squeeze integrity should be pressure tested to BH injection pressure + 25% equivalent.

1.3.5

Extended Cased Hole In long sections of cased hole which would not be plugged for reasons above, a 300' cement plug should be placed at no greater than 3000' intervals. The plug placement should be tagged with the work string.

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1.3.6

Casing to Casing Annuli In some cases, an attempt should be made to cement sections of previously uncemented casing to casing annuli particularly when such section lie opposite hydrocarbon zones or corrosive aquifers having no cement rise on the outside string.

1.3.7

Other Protective Plugs Abandonment cement plugs should be spotted across other susceptible points in the well as follows: A) B) C)

D)

2.0

300' cement plug centered on any exposed liner top(s) 300' cement plugs centered across exposed stage cementing equipment Cement plug having adequate height to extend 100' below and above any problem points (casing parts, splits, patches, prior remedial perforations, etc.) in the innermost string From surface to 300' depth (onland) and to 300' below mudline (offshore)

MARKERS Once a well has been plugged with cement to the surface, an abandonment marker is installed for future identification. 2.1

Onshore Onshore abandoned wells should have the landing base removed and salvaged. A steel plate will be welded on the casing cut-off and a 4-1/2" OD steel post is to be welded on top of the steel plate; a sign marker will be installed on top of the post. The post should be at least 4' long and extend at least 4' above ground level. The well name and abandonment date should be clearly embossed on both the post and sign marker, with weld material.

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Abandonment Marker Well Number and Abandonment Date

4-1/2” Steel Post (with Well Name and Abandonment Date)

Sweet Sand Ground Level

Cellar

Conductor Cement Plug #3

Surface Casing Cement Plug #2

Intermediate Casing

Cement Plug #1

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2.2

Offshore Offshore markers are similar to onshore markers except there is no post or abandonment marker. The blind flange is labeled with the well name and abandonment date.

3.0

RADIOACTIVE TOOLS 3.1

General Information When a radioactive source becomes stuck in a well during drilling operations, every reasonable attempt should be made to recover the source. If the attempt fails, the source should be abandoned properly per the following procedure in section 3.2. This procedure does not call for the well to be entirely abandoned, only the radioactive source. The decision whether or not to salvage the upper portion of the well should be made on a case-by-case basis.

3.2

Procedures The following procedure conforms to the rules and regulations set forth by the United States Nuclear Regulatory Commission, specifically Title 10, Chapter 1, Part 39 (Licenses and Radiation Safety Requirements for Well Logging). 3.2.1

The Manager of Drilling and Workover Engineering Department will submit a statement to the logging company. A copy of this statement will be forwarded to Government Affairs representative. The statement is to include the following: A) B) C) D)

3.2.2

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Source description; radio-isotope, quantity & activity The depth at which the source is stuck A summary of the attempts to retrieve the source A plan for the abandonment of the source in the well

Spot a +120 pcf cement plug directly above the fish. The plug is to be dyed red (use AMS No. 09-612-747) and dressed to a minimum of 50’ above the radioactive source.

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3.2.3

Place a steel object of adequate size, such as a used bit or whipstock, on top of the plug to prevent the inadvertent reentry of the abandoned hole interval. The bit or whipstock may be placed using a shear sub. See wellbore schematic below.

3.2.4

Install a permanent plaque on the wellhead. It must include: A) B) C)

The word “Caution” The radiation symbol The words “Saudi Aramco”

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D) E) F) G) H) I)

The field name and well number Total depth of the well Date that the source was abandoned Depth of the source Depth of the plug Radio-Isotope, quantity & activity of the source

The plaque is to be corrosion resistant. It is usually made of engraved stainless steel, provided by the logging company and is to be installed by Saudi Aramco. See schematic below.

3.2.6

The Drilling Engineer is to include at least 3 references to the lost radioactive source in the well’s Completion Report. A) B) C)

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Lost tools section on the Cover Page (page 1) Plugs/junk section in the Summary of Operations (page 2) Discussion section in the Summary of Operations

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CORING 1.0

CORING APPLICATIONS AND TECHNOLOGY 1.1 Coreheads 1.2 Conventional Core Barrel 1.3 Fiberglass Inner Tubes 1.4 Stabilization 1.4.1 Corehead Stabilization 1.4.2 Inner Barrel Stabilization 1.4.3 Drill Collar Stabilization 1.5 Operating Procedures: Conventional Coring 1.5.1 Starting Practice 1.5.2 Jamming 1.5.3 Making a Connection 1.6 Operating Parameters 1.6.1 Circulation rate 1.6.2 Rotary Speed 1.6.3 Weight on Bit 1.7 Coring with Lost Circulation Material

2.0

PROCEDURES 2.1 Handling a Standard Core Barrel 2.2 Core Barrel Pick-Up 2.3 Coring Practices

3.0

WELLSITE GEOLOGIST REQUIREMENT 3.1 Conventional Core Using a Metal Inner Barrel 3.1.1 Equipment Requirements 3.1.2 Operations 3.1.3 Numbering 3.1.4 Marking 3.2 Conventional Core Using a Fiberglass Inner Barrel 3.3 Preserved Cores 3.3.1 Procedure 3.3.1.1 Material Needed 3.3.1.2 Mixing Procedure 3.4

Transporting Cores to Dhahran

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CORING 1.0

CORING APPLICATIONS AND TECHNOLOGY Coring is the removal of formation from the wellbore through mechanical means in as nearly as possible, an undamaged or physically unaltered state. A core sample is only as good as the formation data that can be derived from it. Detailed information from target formations is essential for the successful evaluation of both primary and secondary recovery programs. Core samples can yield this critical subsurface information. With quality cores, oil companies can more fully understand formation characteristics and more efficiently achieve production objectives. High quality cores provide the most accurate lithology, porosity and permeability information for building the geologic model of the reservoir. Such models are important tools, for example, in evaluating horizontal and vertical permeability. Core samples can provide the petrophysicist and the reservoir engineer with accurate saturation, wettability and electrical properties of the formation. When secondary displacement is the objective, core sample data are essential. Core quality is the key. The sample must be obtained without altering its native (or in-situ) properties. It is therefore essential that every coring job is correctly planned and programmed with well-defined objectives, so that all the wellsite personnel know their individual roles. A written program should be available, setting out the type and size of core, drilling mud to be used, documentation requirements, and geological description, packing and storage instructions, and the destination of the core.

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1.1

Coreheads There are three types of core heads that are used by Saudi Aramco. They are the polycrystalline diamond compact (PDC), the natural diamond and the thermally stable polycrystalline (TSP) bits.

Natural Diamond

TSP

PDC

The following table shows the coreheads available for use by Saudi Aramco along with the corresponding formations of each corehead type

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Formation

Formation Description

Rock Type

Bit IADC Code

Recommended Christensen Coreheads

Corehead Type

Recommended Corepro Coreheads

SHU’AIBA

Soft formation with low compressive and high drillability. Soft to medium formation with low compressive strength interbedded with hard layers.

Marl, Chalk, Carbonate

417-447

ARC-412

PDC

CM-468FRS CM-369FS

Sand, Anhydrite, Dolomite

517- 537

ARC-435 ARC-325

PDC

CM468FRS CM369FS

KHUFF

Medium to hard formation with high compressive strength.

Limestone, Dolomite, Anhydrite

537-627

C-201 SC-777

Natural Diam. TSP

CD3X5/9 CT3X8

UNAYZAH JAUF

Hard and dense formation with very high compressive strength and some abrasive formation layers.

Siltstone, Sandstone

627-737

SC-777 C-23 SC-279 SC-280

TSP Natural Diam. Impregnated

CD3X5/15 CD4X5/15 (Nat. Diam.)

UNAYZAH SAQ

Extremely hard and abrasive formation.

837

SC-279 SC-280

Impregnated

No. Impreg. Avail. CD4X5 (Nat. Diam.)

KHAFJI-SD ARAB-D HANIFA

1.2

Quartzite Sandstone

Conventional Core Barrel The Christensen 250P core barrel is reliable, easy to use and maintain. It is available in many different sizes in order to accommodate the various hole sizes drilled and to match the availability of fishing tools. The following table lists the various conventional core barrel sizes most commonly used in Saudi Arabia.

Barrel Size

Std. Length (ft)

# Turns in Safety Joint

Make-up torque (ft-lb.)

Fluid Cap. (GPM)

Recommended Max. Pull (k-lb.)

4-3/4 x 2-5/8 6-3/4 x 4

60 60

13 6

4,700 11,100

164 387

232 407

Because of the standardization of parts, any outer tube, inner tube that should become damaged can easily be replaced out of stock without costly machine shop work. There are also high-torque core barrels that can be used when deep coring is required. These are equipped with HT-30 threads for the 6-3/4 in. tool with a

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make-up torque of 30,000 ft-lb. and a HT-10 thread on the 4-3/4 in. barrel that is made up with 10,000 ft-lb. All conventional core barrels, with the exception of the 3-1/2 in. conventional slim hole, come equipped with a safety joint. The safety joint allows the inner tube to be removed with the core if the core barrel should ever become stuck in the hole. A drop ball arrangement is used to vent mud to the region between the inner and outer tubes when the core enters the barrel. The drop ball can either be run in place or dropped after the hole has been cleaned out by circulating (see diagram below). In caving holes where mud can readily drop solids, or where fill can settle on bottom, it is necessary to circulate through the inner tube extensively until bottom is reached. When this is the case, the drop ball can be left out of the barrel to allow full circulation through the inner tube when washing to bottom. After bottom is clean, the ball is dropped to divert mud around the inner tube before starting to core. It is best to cut the largest diameter core while still being able to wash over and fish for the tool in the event it becomes necessary to fish. The larger the core, the faster the penetration rate will be. When coring naturally fractured or broken formations, the larger core tends to hole the natural position and causes fewer jamming problems.

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1.3

Fiberglass Inner Tubes Where formations are soft and unconsolidated, a fiberglass inner core barrel is used to ensure higher recovery rates. The fiberglass inner tube is fully interchangeable with the conventional steel barrel. The fiberglass makes a smooth internal wall with a low co-efficient of friction, allowing easy entrance of the core into the barrel and core jamming in fractured formations is minimized, resulting in higher core recovery. The fiberglass is strong and corrosion proof. It is resistant to the corrosive actions of acids, chemicals and salts from the mud system or core material. The strong but light weight glass fiber-reinforced epoxy allows easy handling of the fiberglass inner-tube on the rig site. The pin and box standard threaded steel connectors on both the lower and upper ends, make the fiberglass inner tube fully compatible with a conventional steel system using standard spare parts. Coring with fiberglass inner tube does not create any additional difficulties when making up, adjusting or breaking out the core barrel. Overall, coring with the fiberglass inner tube is performed in exactly the same manner as coring with the conventional steel inner tubes. Due to a higher co-efficient of thermal expansion, the fiberglass inner tube expands with heat faster than the steel outer tube. When spacing the fiberglass inner tube, the gap between the inner shoe and the core head must allow for this difference. The following table gives spacing compensation for different temperatures. Temp Differential °F 50 100 150 200 250 300 350

30 ft In. 0.07 0.15 0.22 0.30 3.37 0.44 0.52

60 ft In. 0.15 0.30 0.44 0.59 0.74 0.89 1.03

The fiberglass inner tube sections are adjusted the same way as the conventional steel liner, by adding or removing shims. Pressure drop through the annular space between the outer tube and the inner tube may become important when coring with fiberglass inner tubes of more than 90 ft. in length. Besides the core barrel geometry, pressure drop

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depends on mud weight, flow rate, and viscosity of the mud. The following equation yields a fairly good approximation of that pressure drop.

⎛Q⎞ ∆P/ft = (1.01) × (a) × ( ∂ ) × ⎜ ⎟ × (1 − (PV − 12 )/200 ) ⎝b⎠ 2

Where:

a, b are geometric constants ∂ = pcf PV = centipoise Q = gpm ∆P/ft = psi

The table below was based upon a 73-pcf mud with a PV of 15. a

b

gpm

∆P/ft

4.75 x 2.62

229

10,335

90 120 164

1.26 2.24 4.25

6.75 x 4.00

164

18,808

180 250 340

1.09 2.10 3.89

The fiberglass is easily cut with a power saw. After the core has been recovered, the fiberglass inner-tube containing the core is cut to length, numbered and sealed with rubber end caps. 1.4

Stabilization 1.4.1

Corehead Stabilization

Coring in deviated holes should be performed with a corehead equipped with a tandem mounted stabilizer, whenever possible. This will keep the corehead flat on bottom, providing sufficient cooling and correct removal of cuttings, resulting in good core recovery. 1.4.2

Inner Barrel Stabilization

The inner barrel should be stabilized preferably with a stabilizer in the center. 1.4.3

Drill Collar Assembly Stabilization

The first stabilizer should be placed directly on top of the core barrel, followed by a stabilizer at 30 ft. and one at 60 ft. above the barrel. The remaining stabilizers should be evenly spaced out over the rest of the assembly as required.

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1.5

Operating Procedures: Conventional Coring

Before completing the assembly of a core barrel, it should be determined whether a ball will be run in place or dropped from the surface after bottom is reached. When hole conditions dictate that circulation is going to be required in order to reach bottom, the ball should be left out of the barrel when it is assembled. After the bottom is clean, the barrel should be raised several feet off bottom while circulating to insure the inner barrel is clean. When the ball is dropped to its seat in the barrel, after bottom is reached, the circulation fluid passes around the outside of the inner tube in the conventional manner. Precautionary procedures should be completed before running the core barrel in the hole for removal of the float from the drill collar unless a flap type float or full flow drill pipe is used. It is also imperative that the bore of the jars be checked to assure passage of the ball (usually 1-1/4 in. diameter). When the last stand of drill pipe has been lowered into the well, and the kelly attached, circulation should be established. In full hole coring, entry into the hole should be methodical. Caution should be exercised in all tight places to avert core head sticking. Tight places must be reamed out. Reaming of long intervals should not be done with core bits. When nearing the bottom and contact is made with cavings, it is necessary to rotate and circulate. Be sure all measurements are correct to determine bottom exactly. After bottom has been reached and the hole circulated, the kelly should be raised to the first joint of the drill pipe. The kelly is then removed and the ball dropped. 1.5.1

Starting Practice

Once the ball has been dropped, replace the kelly and pump the ball down at a good circulation rate. Allow one minute per 1000 ft. While the ball is falling, record the pump rate and standpipe pressure. As the ball nears bottom, slow the pumps down to allow the ball to seat properly. As soon as the ball is seated, record the increased standpipe pressure and return to bottom. Once on bottom, begin rotating slowly (30-40 rpm), and start adding weight in increments of 2000 lbs. Gradually increase WOB, rpm, and fluid volumes until optimum coring conditions are found.

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1.5.2

Jamming

Blocking the inner barrel or jamming is one of the most common problems of coring. Jamming of the inner barrel is usually caused by a formation condition (fractures, unconsolidated material, swelling shales). If the barrel jams in soft unconsolidated formations the penetration rate may remain the same but most likely will decrease. The stand pipe pressure will increase initially and then decrease as the core bit drills off. A change in torque, pump strokes, or a decrease in pump pressure will also indicate a jammed core barrel. Plugging of the core barrel from an accumulation of foreign particles in the mud system such as rubber, LCM, or other junk in the mud system may cause an abrupt increase in standpipe pressure. 1.5.3

Making a Connection

When it is necessary to pull off bottom to make a connection or remove the core barrel, the following procedure is recommended. Stop the rotation and shut off or idle the pump, raise the core barrel until the weight indicator shows the core spring has gripped the core and the core breaks, or until a strain begins to exceed the pull below. For a 2-5/8 in. core, 10,000-lb. pull and for a 4-in. core 20,000-lb. pull. If the core does not break with the maximum strain, then start the pump and hold the strain on the core until it breaks. It may be necessary to hold the strain for 10 minutes or longer for the core to break. After the core has broken, raise the bit 10 feet and then lower slowly back to within one foot of bottom. A constant check of the weight indicator should be made to see that its readings drop gradually with out any obstruction caused by any core left in the hole.

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If the core appears to be properly caught in the barrel, pick up and make a connection, if not come out of the hole. It is advisable when making a connection to lock the rotary table and back the kelly out with tongs. Then the coring assembly can be placed back on bottom, after the connection, exactly as it was before. When coring is to be resumed after the connection, go back to bottom without rotating. With the pump on, apply normal weight to release the core catcher so the core can enter the core barrel. Pick up to starting weight then start rotating slowly and gradually return to normal coring operations. In those instances when there is a possibility of loose junk or pieces of core on the bottom, it is best to use lighter weight for the first 6 inches. The pump can then dispose of small pieces of junk, or fractured formation before normal coring weight is resumed. It is after a connection that most inner barrel jamming occurs. Therefore, be alert to the rig floor indicators.

1.6

Operating Parameters 1.6.1

Circulation Rate

Diamond core bits will function very satisfactorily with a wide variety of circulating, including fresh water, salt water, crude oil, as well as various other water and oil based muds. Sand content of the mud should be kept at a minimum (less than 1%) to keep fluid damage to parts of the core barrel, bit shank, and bit crown to a minimum. The volume of liquid to be circulated is determined by well condition, the size and design of the bit, type of mud, depth of hole, drill pipe and core barrel, pump capacity, but most important, the fluid characteristics. Annular velocities as low as 90 ft./min. have been used without creating problems when coring with good mud. Sufficient high velocities prevent the settling of cuttings.

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Core bits of the same size but differing designs are made for the same circulating rate. Special requirements however for high mud weights or plastic viscosities may affect these circulation rates. The average circulation rate should be used with varying bit weights and rpm to determine the optimum penetration rate. Circulation rates can be varied to provide efficient cleaning and cooling, thus maximizing core bit life. Too low a volume may not clean the entire face of the bit, resulting in the regrinding of the cuttings or the possible burning of the bit, reducing the bit’s penetration rate. High fluid volumes may be detrimental when the bit is starting. Too high of a volume may cause the bit to lift off bottom and bounce with subsequent diamond fracture reducing penetration rate and bit life. High volume can also cause the inner barrel to rotate, which can create jamming problems. When coring in soft formations, consideration should be given to the cutting of short cores. Soft, unconsolidated formations can support very little weight and if the weight of the core above the throat of the bit exceeds the formation strength, any further attempts to cut more core will result in grinding up and washing away the core. 1.6.2

Rotary Speed

The best rotational speed for coring is usually established by the limitations of the drilling equipment. Depth and size of hole, size and condition of the drillpipe, size and number of drill collars and the formation being cored all must be considered when establishing the rotational speed. The following chart depicts recommended rotary speeds for core bits.

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RPM

___________________________________________________________________________________________________________________________

Recommended Rotary Speed for Core Bits

Generally core bits are run with lower rotary speeds than diamond drilling bits. Core barrels have been operated at on downhole motors with rotary speeds in of 300 rpm to 400 rpm. However, this is only recommended in homogeneous formations where there are minor jamming probabilities. Penetration rates can be increased with higher rotary speeds. Slow rotary speeds have been beneficial when coring fractured formations. Using speeds of 30 to 40 rpm produces less disturbance of the core. As long as sufficient hydraulics are used to keep the bit clean, the best rotational speed can be found by either reducing or increasing rotational speed while keeping the weight on the bit constant. Certain formations such as sticky shales or anhydrites can cause excessive torque. By using a different combination of weight and RPM, a smooth coring operation can be obtained. 1.6.3

Weight on Bit

Consistent with good oilfield practice, the weight on bit should never exceed the weight of the drillcollars. This condition keeps the drillpipe in tension and helps to eliminate undesired whip and vibration of the drill string. In unstabilized situations, whipping of the drill string causes

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shock loading of the diamonds, and premature bit failure. Using a stabilized barrel and drillstring can eliminate this whipping. The proper weight on bit for each core run can be determined by increasing the bit weight in steps of 1,000 to 2,000 lbs., with a constant rpm. Coring should continue at each interval while carefully observing the penetration rate. Optimum weight on bit has been reached when continued increases in weight do not increase penetration rate, or requires excessive torque to rotate the bit. Using too much weight can cause the diamonds to penetrate too deeply into soft formations and with an insufficient amount of mud flowing between the diamonds and the formation, could result in poor removal of cuttings. The core bit could clog or even burn, resulting in poor penetration rate and bit life. In harder formations excessive weight can cause the tips of the diamonds to burn or shearing off, both which reduce the bit life.

Weight on bit (pounds)

After the desired bit weight is determined, every effort should be made to keep the weight constant. The brake should be tended at all times. Do not apply more weight then let it off only to apply more weight again. Automatic drillers normally do a good job of maintaining a constant weight on bit. The following chart depicts recommended weights on bit for core bits.

har

o ati orm f d

fo soft

S 3, C2 n(

i rmat

on

8 C2

0)

1, (C20

4 ARC

12)

Bit Size (inches)

Recommended Drilling Weight for Core Bits

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1.7

Coring With lost Circulation Material

Core barrels have effectively operated using muds with large quantities of lost circulation material (LCM). Close attention to the thorough mixing of the mud to prohibit any large concentration of the LCM into masses or lumps, which may subsequently block the various parts of the core barrel or plug the waterways of the bit. LCM could also get on top of the core and prevent it from entering the barrel. LCM should not be mixed while coring operations are in progress, unless absolutely necessary. When coring with LCM, the core barrel is usually run in the hole without the drop ball in place. This prevents clogging of the bearing assembly. The drop ball is used while coring to deter LCM from accumulating between the core and the inner-barrel which could result in a jammed core. It may be necessary to break circulation several times on the way down the hole to keep from plugging the barrel and allowing lost circulation material to accumulate in it. When LCM is used in the mud system, circulation should begin 60-ft off bottom. After circulation is established, the core barrel should slowly be washed to the bottom. If the lost circulation zone is very close to the bottom of the hole, a minimum of fluid circulation may be required. When this is the case, the rpm of the core bit should be kept as low as possible because the lost circulation material together with the cuttings, could cause clogging of the bit. 2.0

PROCEDURES 2.1

Handling a Standard Core Barrel

The following is the recommended procedure for handling a standard core barrel. A) B)

C) D)

E)

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Make up all inner barrel joints by hand with chain tongs. Make up all outer barrel joints with pipe tongs. No more than three wraps on the cat-head are recommended. If a torque indicator is available on the rig floor then the make up values below should be observed. All threads on Eastman Christensen core barrels are right hand threads. When the barrel is to be transported or laid down for a long period, all outer barrel threads should be broken loose in order to facilitate the maintenance and removal. When making up all joints clean and dope threads.

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Core Bbl. Size (Inches) 4.75 x 2.625 6.75 x 4.0

2.2

Normal Make-up Torque (ft-lb) 4,700 11,100

Rough Drilling Make-up Torque 5,800 13,900

Yield Torque (ft-lb) 7,900 18,500

Core Barrel Pick-up

The following is a step by step procedure on how to pick up a core barrel. A) B) C) D) E) F) G) H)

I) J)

K)

2.3

Pick up the lower section. Run the lower section through the rotary table and set the slips and safety clamp on the outer section. Remove the pickup sub from the outer barrel. Lift the inner barrel one-foot above the outer barrel, and place the clamp on the inner barrel. Remove the pick up sub from the inner barrel. Tighten the pickup sub into the upper section at the safety joint, and pickup with elevators. Remove the protector sub from the outer barrel and the inner tube cap from the inner barrel, and tighten the inner barrels. Raise the elevators and remove the inner barrel clamp. Lower the upper barrel and tighten the outer barrel. Remove the safety clamp on the outer barrel. Lower the barrel to the stabilizer and tighten, then attach the safety clamp. Remove the inner barrel at the safety joint. If the barrel has been run, check the points to be checked before each core is cut, and inspect the bearing. If undue damage or wear is apparent, then the bearing should be replaced. Tighten the safety joint and remove the barrel from the hole. Remove the protector sub, place the core bit on the barrel and tighten. On the first run or after each bit change, the adjustment shims should be checked. To run a 90-ft. barrel, it is suggested that a top section be used. Lay down the safety joint and the bearing assembly and add one top section. Recheck spacing if possible.

Coring Practices

The diamond bit or corehead should only be run into the well after the hole is free of all obstructions and reaming is not necessary. If reaming is necessary, ream with a drill bit. This should be done if any increased overpull is experienced other than normal while pulling the bit out for the coring run, or if the bit is pulled out undergauge. Repeat reaming procedure until no further hole problems are experienced. This is due to the fact that reaming creates

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heavy loads and excessive heating that the watercourses are not designed to cope with. If reaming is unavoidable, circulate at maximum rates, limit rotation to 30 rpm, and weight on bit should be minimal. Use a 60-ft. core barrel when cutting cores. If poor recovery is experienced, consider using a 30-ft. core barrel, or core only 30 ft. with a 60-ft. barrel. When cutting a large core, i.e. 5-1/4 in., 7-3/4 in., or 8 in., 30 ft. may be the maximum core length because of potential handling constraints. When coring is performed, in an 8-1/2 in. hole, use a 6-1/8 in. drilling jar in the drill string. Space out using pup joint is necessary to ensure that coring begins with a full kelly. After breaking the core, it frequently jams, therefore maximum core recovery will be obtained in this manner. Decreasing torque and increasing pump pressure are indicative of a formation change. Decreases in pump pressure, torque and penetration rate together indicate that the core has jammed. If pump pressure and torque have increased simultaneously, an ‘O’ ring groove has developed. There is no point in continuing to core if the rate of penetration (ROP) is slow, because the core has jammed. If this is the case, the formation is being ground away and not recovered. When pulling out with a core barrel, do not rotate out. Use a pipe spinner.

3.0

WELLSITE GEOLOGIST REQUIREMENTS 3.1

Conventional Core Using a Metal Inner Barrel 3.1.1

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Equipment Requirements A) Core trays B) Core tags C) Wire for tags D) Rapidograph for marking tags E) Magic marker for marking core trays F) Clip board G) Geologic hammer H) Tape measure, calibrated in feet and tenths of feet I) Core tray covers (wooden), wire, pliers J) Personal safety equipment i. Long sleeve shirt and pants ii. Safety hat iii. Safety glasses iv. Safety shoes

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v. 3.1.2

Operations

A)

B)

3.1.3

Work gloves

Mark one end of each core tray with the tray number using the magic marker (see figure below). Core trays are numbered in sequence. Tray number 1 is the bottom of the core. Core number 1 may have 10 trays, numbered 1-10, core #2 may have 24 trays marked 1 through 24, etc. Record this information on the coring data sheet, an example is attached. Arrive at the rig floor with trays and hammer in time to handle the core as it is extracted from the barrel.

Numbering

Cores are numbered in sequence as they are cut. Core #1 will always be the first core cut, core #2 the second core cut, etc. in each well. 3.1.4

Marking

Handling conventional cores during transport, examination and analysis presents many opportunities to misplace or disorient core samples. Marking conventional cores at the rig site with vertical lines and depths will preserve the vertical orientation of the cores. Wellsite geologists will be responsible for marking the core for orientation and depth using the following procedure: The core should be laid out, wiped dry, fitted and measured. Using black and red felt tip magic markers, two adjacent vertical lines should then be inscribed which should run the entire length of the core. When viewed in the upright position, the red line should be on the right and the black line on the left. Depths should be marked every six feet. The above procedure should be carried out by wellsites as soon as a core is laid down.

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Top of Core

Core Barrel

4 3 2 1

Bottom of Core

Core Trays with Bottom Ends Numbered

AW XXX Bottom End of Core Tray

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CORE-3

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Extracting Core and Arranging Trays FIELD:

WELL:

CORE#

FROM:

TO:

CORE CUT:

FT.

RIG:

CORE ENGINEER:

TRAY NO. 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1

AMOUNT

CORE FROM

DATE:

RECOVERED:

FT. FT.

INTERVAL TO

GEOLOGIST:

%RECOVERED: CORE HEAD:

REMARKS

N.R. TOTAL

Coring Data Sheet Form

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RED LINE

BLACK LINE

6221'

6222'

Marking Conventional Cores

CORE DATA DATE .................... FIELD ............................... WELL NO ......................... CORE NO ......................... FROM ........... TO............ RECOVERED ........................FT. GEOLOGIST ......................... DEPTH OF CORE THIS TRAY

FROM ......... TO .............

TRAY ___ OF ____ TRAY NO. 1 IS BOTTOM CORE

Standard Aramco Core Tag

3.2

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Conventional Core Using a Fiberglass Inner Barrel

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After the core has been cut, the barrel is pulled to the surface. The outer barrel with the diamond corehead attached to its lower end is held in the slips and the inner barrel containing the core is taken out of the outer barrel and laid down on the catwalk. Then the fiberglass with the core inside is marked and cut in 2.7-ft. sections. Each section should be properly marked with ‘T’ for top and ‘B’ for bottom, to keep the orientation in order (see diagram below). The numbering of each section of the tube should be the same as previously mentioned for the trays. Generally in Exploration wells the core from each fiberglass tube is transferred to the metal trays and labeled as mentioned previously above. In Development wells the cores are kept in the fiberglass, closing both ends with rubber caps and marked as shown below. 11 Rubber Cap

10

T

9

7

HWYH-200 C#1

TUBE#6

8

6

B

5

Rubber Cap

4 3 2

Cut Here

1

Schematic Diagram Showing How to Mark, Cut and Label Fiberglass Core 3.3

Preserved Cores

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Preserved cores preserve freshly cut cores against drying, oxygen exposure and bacterial action by sealing the cores immersed under deoxygenated brine. The core is preserved to maintain reservoir characteristics of core samples and consequently to improve the quality of data obtained through laboratory core analysis.

3.3.1

Procedure

A)

Materials Neededi. PVC core tube for each section (2.7-3.0 ft. lengths) ii. Sodium Chloride iii. Calcium Chloride iv. Magnesium Chloride v. Sodium Metabisulfite vi. Nitrogen Cylinder vii. Regulator with plastic hose viii. Water ix. Strap wrench x. Magic markers xi. Bucket xii. Weighing balance

B)

Mixing Procedure1)

Prepare the brine by combining the following components in the following proportions. i. NaCl 58.5 lbs. for each barrel (42 gallons) ii. CaCl2, 2H2O 12.6 lbs. For each barrel iii. MgCl2, 6H2O 4.2 lbs. For each barrel iv. Na2S2O5 1.3 gms. (for each tube, added before closing the tube. This is not added with the bulk mixture)

2)

PVC tubes are labeled with the following information:

3)

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i. Well Name & Number ii. Core Number iii. Tube Number iv. Interval (amount of core in the tube) As the core is removed from the core barrel, it is laid in the metal core trays which are filled with water (preferably the same brine which will be used to preserve) to prevent from drying and oxygenating.

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3.4

4)

Place the core in the PVC tube and fill the tube with brine. Leave only a small gas space to allow for thermal expansion.

5)

Deoxygenate the brine in the tube and displace air from the top of the tube by bubbling Nitrogen into the bottom of the tube for 10 minutes.

6)

Shortly before the nitrogen purge is completed, add Sodium metabisulfate to the tube (amount mentioned above) as an oxygen scavenger.

7)

Close the cap tightly.

Transporting Cores to Dhahran

Cores are very expensive and contain valuable information, so the proper handling of them is essential. The following steps should be observed when shipping cores: A)

B)

C) D)

Each metal tray with core should be covered with a wooden top and tied up properly so that no piece of core can fall during loading and unloading. Cores collected in fiberglass tubes should be capped from both ends with the right size of cap and re-inforced with metal rings. The fiberglass tubes should be strapped on a wooden palette before shipping. Preserve core tubes should be kept in an upright position in a metal basket. The rig foreman arranges for sending the cores and he should prepare a shipping manifest stating the number of tubes/trays and address the shipment to:

CORE STORAGE BUILDING # 3170, DPC-155, DHAHRAN The well site geologist will report details of the shipment in his morning report.

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DRILLING OPTIMIZATION 1.0

DRILL BITS 1.1 IADC Bit Classification 1.2 Bit Selection 1.3 PDC Bit Running Procedure

2.0

MOTORS & TURBINES

3.0

DRILL-OFF TESTS

4.0

HYDRAULICS 1.1 Hydrostatic Pressure 1.2 Frictional Pressure Determination 1.3 Optimization of Bit Hydraulics 1.4 Onsite Nozzle Selection

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DRILLING OPTIMIZATION 1.0

DRILL BITS 1.1

IADC Bit Classification Roller cone drill bits are classified by a three-digit IADC code. The first number is called the series. Series 1 through 3 is for milled tooth bits. Series 4 through 8 is for insert bits. The following table depicts what type of formation each series is best suited to drill.

SERIES 1 2 3 4 5 6 7 8

FORMATIONS Soft formations with low compressive strengths and high drillability. Medium to medium hard formations with high compressive strength. Hard semi-abrasive and abrasive formations. Soft formations with low compressive strengths and high drillability. Soft to medium formations with low compressive strength. Medium hard formations with high compressive strength. Hard semi-abrasive formations with high compressive strength. Extremely hard & abrasive formations.

The second numeral in the bit IADC classification is the bit type, these numbers range from 1 to 4 and sub-divide each series from soft to harder. For example a 1-2 type bit is slightly softer than a 1-3 type bit. The third and final number in the bit IADC classification is the feature. The following table shows what each feature represents. Features 1

2

3

4

5

6

7

8

9

Standard roller bearing.

Roller bearingAir.

Roller bearing, gage protected.

Sealed roller bearing.

Sealed roller bearing, gage protected.

Sealed friction bearing

Sealed friction bearing, gage protected.

Directional

Other

Therefore, a bit with an IADC code of 5-3-7 is for a bit that will drill soft to medium formations with low compressive strengths and has a sealed friction bearing with gage protection.

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1.2

Bit Selection The selection of the best available bit for a given job, like the selection of drilling fluid or drilling cement composition, can only be determined by trial and error. Fortunately in Saudi Aramco, there is sufficient offset information to effectively select the proper bits types for given formations, see chart on the following page for some generalized IADC codes for given formation types.

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The initial selection of bit type in a wildcat area can be made on the basis of what is known about the formation characteristics and its drillability. The drillability of a formation is its measure of how easy the formation is to drill. It is inversely related to the compressive strength of the rock. Drillability tends to decrease with depth in a given area. The abrasiveness of the formation is the measure of how rapidly the teeth of a milled tooth bit will wear when drilling the formation. Shown in the following table is a listing of bit types often used to drill various formations.

IACD Bit Classification 1-1 1-2 5-1 6-2 1-3 6-1 2-1 6-2 2-3 6-2 3-1 7-2 3-2 3-4 8-1

Formation Description Soft formations having low compressive strength and high drillability (soft shales and clays and soft limestone and unconsolidated formations, etc.)

Soft to medium formations or soft interspersed with harder streaks (firm, unconsolidated or sandy shales, anhydrite, soft limestones, etc.) Medium to medium hard formations (harder shales, sandy shales, shales alternating with streaks of sand and limestone, etc.) Medium hard abrasive to hard formations (high compressive strength rock, dolomite, hard limestone, hard slaty shales, etc.) Hard semi-abrasive formations (hard sandy or chert bearing limestone, dolomite, granite, chert, etc.) Hard abrasive formations (chert, quartzite, pyrite, granite, hard sandstone, etc.)

When using a rollercone bit: • Use the longest tooth size possible. • A small amount of tooth breakage is tolerable rather than selecting a shorter tooth bit. • When enough weight cannot be applied economically to a milled tooth bit to cause self-sharpening tooth rear, a longer tooth size should be selected. • When the rate of tooth wear is much less than the rate of bearing wear, select a longer tooth size, a better bearing design or apply more bit weight. • When the rate of bearing wear is much less than the rate of tooth wear, select a shorter tooth size, a more economical bearing design or apply less bit weight.

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Since bit selection is done largely by trial and error, it is important to carefully evaluate a dull bit when it is removed from the well cannot be over stressed. PDC bits are becoming more and more utilized for deep drilling applications. When a PDC bit is called for in a drilling program the following procedure should be followed. 1.3

PDC Bit Running Procedure A)

Step I – Preparing the Hole Preparation to run a PDC bit begins with examination of the previous bit in the hole. If the old bit has just a few lost or damaged cutters/inserts, there should be no problem as they will probably have been broken up and embedded in the hole wall, or washed out during hole cleaning. More severe damage, or a grossly undergauge bit means that the hole should be conditioned with a roller cone bit and a junk basket. It is generally a good drilling practice to use a junk basket during the last run before going into the hole with a PDC bit.

B)

Step II – Preparing the PDC Bit •

• •

• C)

Carefully remove the bit from its box and place it on a piece of plywood or a rubber mat. Never roll or stand a PDC bit directly on steel decking, like the rig floor, as PDC cutters are brittle and easily chipped. The bit serial number should be recorded, together with the bit type and diameter. The bit should be closely examined for damage possibly caused during transit or if it’s a re-run bit. The inside of the bit should also be inspected at this stage, in case any debris, which might block a nozzle, is left inside. Check that correct size nozzles are already in place.

Step III – Breaking In the PDC Bit •

The bit should be rotated at low speed with no more than 60 RPM to avoid premature damage to cutters while creating the bottom hole pattern.

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•

•

The bit should be slowly set on bottom with no more than 4,000 lbs. weight on bit to establish a bottom hole pattern. If the bit does not drill off after a few minutes, then the weight should be increased until it does. This weight should be maintained until the bit has drilled at least its own length. The weight on bit can then be increased (up to the recommended maximum weight on bit) until the desired penetration rate is reached, or until an increase in weight no longer improves the rate of penetration.

As a general rule, the optimum weight necessary for a PDC bit is less than one-half that required for a roller cone bit. In extremely soft or plastic formation, even at the light weight on bit and slow rotary speed applied to establish the bottom hole profile, the bit will drill off quickly, making the first few feet in only a few minutes. In harder formations it may take considerably longer to drill the first foot. Since only some of the cutters will initially be in contact with the formation until the bit has bedded in, it is crucial that weight not be added too quickly, otherwise these cutters may be overloaded and fail. Other Useful Notes Making Connections When making connections, full flow should be maintained as the kelly is raised. After the connection has been made, the bit should be washed back to bottom slowly at full flow rate. The bottom must be approached with care. Dropping the kelly too rapidly and the sudden braking of the string, can cause the bit to tag bottom violently and be damaged as the drill pipe stretches. Optimizing Drilling Conducting a series of tests at various weights on bit and rotary speeds is the most reliable method of assessing the optimum values to achieve the most satisfactory rate of penetration. If a formation change occurs when drilling a long interval, the penetration rate usually changes as well. If the rate decreases, the formation is probably harder, in which case the rotary speed should be reduced and more weight applied to the bit. If this results in a severe rise in torque, the weight should be reduced and rotary speed increased. In essence, optimization results

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from experimenting with the parameters available. Bits will often yield dramatic rates of penetration in the right application without being run at optimum drilling parameters. It must be remembered that optimizing the parameters (and thereby increasing rate of penetration) as conditions change, can result in high overall cost per foot savings achieved by the bit.

2.0

MOTORS & TURBINES The phrase “Performance drilling” is a term used throughout the industry to describe a downhole drilling system that is used to increase ROP. It is commonly used to refer to high performance positive displacement motors (PDM’s) and turbines utilized for straight hole drilling. High performance PDM’s are motors that have extended power sections. The additional power sections offer significantly higher torque - while maintaining bit rpm - than conventional motors. The main advantages to using these types of motors for drilling straight holes are as follows: A)

Increase in penetration rates with associated rig cost savings.

B)

Reduced casing and drillstring wear and fatigue from lower rotary ROP. This helps lower overall maintenance costs for the equipment involved.

C)

Accurate bottom hole positioning and lower survey costs (when MWD is used in conjunction with a performance motor).

D)

Availability of personnel and equipment in remote areas to carry out quick and accurate geological and/or mechanical sidetracking operations.

2.1

Considerations In order to maximize the penetration rate the drilling parameters used must be analyzed and agreed upon prior to starting the job. The primary factors that influence performance will be the type of motor, the bit and the hydraulics. Based on availability the bit should be matched to the motor or vice versa. Factors to consider are: • •

Bit Type – number of blades, cutters, type and size of cutters, nozzles Motor type – maximum speed and torque for the required bit and hole size

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•

•

Hydraulics – attention should be paid to hole cleaning, pressure drops and motor performance Rig Pumps and pressure ratings – the rig must be able to offer consistently high flow rates in order to maximize the speed and torque available from the motor.

If the above factors are not optimized for the job then the maximum benefit may not be derived from using a performance motor. As with all drilling operations it is imperative that comprehensive pre-job planning is done involving the PDM company, the bit supplier, the operator’s drilling engineers/foreman and the drilling contractor in order to ensure the highest probability of success.

3.0

DRILL-OFF TESTS Frequent changes in lithology with depth can make it difficult to maintain a optimum weight on bit. The drill-off procedure is a good method in which to determine the optimum bit weight to use when drilling through a given formation type. A drill off test consists of applying a large amount of weight to the bit, then locking the brake and timing each 4 thousand pound decrease in the weight at a constant RPM. The times are then plotted on graph paper and the optimum weight on bit can be determined. The following is a recommended drill off test procedure followed by an example. A)

Choose a depth to run the drill off test where a section of uniform lithology is expected.

B)

While drilling increase the bit weight approximately 20% over the weight that was being drilled used and lock the brake.

C)

While maintaining a constant rotary speed, record the time it takes each time the bit drills off 4,000# of bit weight. If the weight indicator is fluctuating, use the mid-point. Continue the test until at least 50% of that weight is drilled off.

D) E)

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Make a plot of ∆t vs. W. If time permits repeat the test using a different rotary speed and compare the results.

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Example of a drill off test analysis. B it W e ig h t (1 0 0 0 # ) 76 72 68 64 60 56 52 48 44 40 36

T o ta l T im e (s e c ) 0 52 105 152 210 281 352 432 522 626 746

D e lta -t 52 53 47 56 63 71 80 90 104 120

130 110 90 70 50 30 72 68 64 60 56 52 48 44 40 36 Bit Weight From this example the optimum weight on bit for this formation type would be 64,000#.

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4.0

HYDRAULICS 4.1

Hydrostatic Pressure The hydrostatic pressure of the drilling fluid is an essential feature in maintaining control of a well and preventing blowouts. It is defined as the static pressure of a column of fluid. The hydrostatic pressure of a mud column is a function of the mud weight and the true vertical depth of the well. Remember that the true vertical depth is used and not the measured depth. The formula to calculate hydrostatic pressure in the units common for Saudi Aramco is: PH, psi = (mud weight, pcf) x (depth, ft) /144, in2/ft2 Where: PH = hydrostatic pressure, psi Drilling operations often involve several fluid densities, pressures resulting from fluid circulating and induced surface pressures during kick control operations. For practicality these different pressures are put into a common descriptive system called “equivalent mud weight” or EMW. This provides the same pressures in a static system with no surface pressure. EMW = (total pressures X 144) / true vertical depth Where: EMW is equivalent mud weight in pcf

4.2

Frictional Pressure Determination The determination of pressure losses in the circulating system has been an objective for almost as long as rotary drilling has been in existence. Pumping a drilling fluid requires overcoming frictional drag forces from fluid layers and solids particles. The summation of pressure losses in the entire circulating system is shown at the surface pressure gauge, normally located on the standpipe. The summation of pressure losses is:

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Ps= Pse + Pdp + Pdc + Pbit + Pdca + Pdpa Pse

Circulation System and Normal Flow Patterns

As indicated in the above diagram, the total pressure is a result of frictional pressure losses from the surface equipment, the drillpipe, the drillcollars, the bit, the drillcollar annulus, and the drillpipe annulus. The total pressure gives no indication whether the flow pattern in the system is laminar or turbulent. The flow patterns inside the drillstring are usually turbulent while the flow pattern in the annulus can be either. The pressure drop in the bit results from fluid acceleration and not solely frictional forces. Equivalent circulating density (ECD) is the fluid pressure the bottom of the hole experiences while the mud is being circulated and should be considered, especially when the formation being drilled through allows only small mud weight tolerances and mud weights are critical. ECD = Mud Density +

(PDPA + PDCA )× 144 Depth

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4.3

Optimization of Bit Hydraulics 4.3.1

Introduction

The design of a hydraulics program is based upon maximizing bottomhole cleaning using the least horsepower. Methods of design being used include hydraulic horsepower and jet impact force. The use of hydraulic horsepower is associated with the use of smaller jet bits. Little attention was directed towards fluid circulation programs before the introduction of jet bits in 1948. A comparison comes to mind of someone cleaning sand off the driveway with a garden hose. By using his thumb at the end of the hose, in front of the stream of water and creating a jetting stream, he can more effectively clean the sand off the driveway than by not using his thumb. In affect as he reduces the nozzle size so he can blast more sand away then by not reducing it. For many years engineers have known that hydraulics play an integral roll in cleaning the face of the formation so that a bit can drill faster. This first became evident when larger pumps were introduced. They increased the penetration rates because more fluid was being pumped through the bit, thereby cleaning more cuttings away from beneath the bit. This same theory can be applied at the bottom of a drill string with bit jet nozzles. The purpose of the jet nozzles is to improve the cleaning action of the drilling fluid at the bottom of the hole. Before jet bits were introduced, rock chips were not removed efficiently and much of the bit life was consumed regrinding the rock fragments. Jet nozzles help to rid the bottom of the hole of these cutting more effectively. There are two hydraulic models that should be followed in order to optimize bit hydraulic horsepower, they are listed below. Neither model has a clear advantage over the other, the model used depends on the preference of the company man on the rig. 4.3.2

Jet Impact Force Model

Field studies have shown that cross flow beneath the face of the bit is the most effective parameter in hole cleaning. Cross flow is maximum when jet impact force is maximum. The pressure loss across the bit is simply the difference between the standpipe pressure and the circulating pressure. For maximum jet impact force the pressure loss across the bit should approximate 48% of the available surface pressure. In other words if the available pump pressure is 3000 psi,

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for a jet impact force hydraulic model, size the jet nozzles to create a 1440 psi pressure drop across the bit at the required flow rate. This hydraulic model is usually applied where there is a limited amount of available pump horsepower or surface pressure. For example, maybe the kelly hose is only rated to 3000 psi or the pumps can only deliver a limited amount of horsepower. In any case, the hydraulic model to be used would be the impact force model. 4.3.3

Hydraulic Horsepower Model

Optimum bit hydraulics is obtained when, for a given flow rate, the bit hydraulic horsepower assumes a certain percentage of the available surface horsepower. For the maximum hydraulic horsepower model the pressure loss across the bit should approximate 65% of the total available surface pressure. In other words if the available pump pressure is 3000 psi, for a hydraulic horsepower hydraulic model, size the jet nozzles to create a 1950 psi pressure drop across the bit at the required flow rate. This hydraulic model is usually applied where there is an unlimited amount of available pump horsepower or surface pressure. 4.3.4

Nozzle Selection

Smaller nozzles are always obtained when the hydraulic horsepower model is used, it gives larger values of Pbit than those given with the impact force model. The following equations may be used to determine total flow area and nozzle sizes: AT (in2) = 0.00342

dN = 32

ρQ 2

P bit

⎞ ⎛ 4A T ⎟ ⎜⎜ 3π ⎟ ⎠ ⎝

Where: AT is total flow area in (in2) and dN is nozzle size in multiples of 1/32 in.

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Example:

Calculate the bit nozzle sizes required for the following set of conditions: Mud weight: Pump rate:

75 pcf 300 gpm

Solution:

AT (in2) = 0.00342

dN = 32

Pbit:

(75 )300 2

(4(0.281))

3(3.14 )

1000

1000 psi

= 0.281 sq. in.

= 11.05

Therefore three 11/32’s will jet this bit up properly. 4.4

Onsite Nozzle Selection

The flow regime through a rig’s mud system is disturbed by discontinuities in the flow path (tool joints, jars, crossover subs, safety valves, washouts, tight holes, etc.) Sometimes the flow is laminar, sometimes it’s turbulent. Each drill string has it’s own unique flow path. For this reason hydraulic programs developed prior to the well being drilled frequently call for the wrong bit nozzles. As the well is drilled, pressure losses can be determined with an experiment at the rig after each bit is dulled. This is accomplished by the following procedure: Standpipe pressure is measured and recorded at three different pump rates, one rate can be the drilling rate. Standpipe pressure (Psurf) consists of two parts: (1) the pressure drop across the bit (Pbit), and (2) the rest of the pressure loss through the system (Pcirc). Pbit can be determined from any hydraulics manual. Subtracting the known values of the pressure drop across the bit from the standpipe pressure leaves the pressure drop through the system. If Pcirc values are plotted on a log-log graph as a function of flow rate, the slope u can be measured from the graph. In the graph below, pressures recorded by the driller are shown with squares. The pressure drop through the bit, Pbit, is subtracted at each flow rate. In this example, the line drawn

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through these points has a slope (u) of 1.6, that is the system pressure varies as the 1.6 power of the flow rate (instead of 1.82). On the same graph with Pcirc, the maximum pressure (Pmax) and available hydraulic horsepower (Phhp) line should be added. The intersection of these two lines determines the critical flow rate Qcrit. With the value of u, calculate

u +1 u Phhp and Pmax and draw u+2 u+2 these optimum lines on the graph. The intersection of the Pcirc line with one of these lines specifies the optimum circulating rate and pressure drop across the bit. See the example below. Example:

Given the following standpipe pressures and flow rates, graph the data then determine the optimum pressure drop across the bit. Q, gpm 200 300 500

Psurf, psi 621 1,245 3,000

hhp=1071 hp

5000

Pmax

3000

Pbit 2000

If the three nozzles in the bit were 16/32 in., the pressure drop through the bit for 112 pcf mud would be:

Pressure drop through the system

Press, PSI 1000 800

Flow Rate, gpm 200 300 500

Pbit, psi 160 360 1,000

If these values are subtracted from the standpipe pressure recorded by the driller, the pressure drop through-out the rest of the system is obtained: Flow Rate, gpm 200 300 500

Pcirc, psi 461 885 2,000

600 400 300 Slope = 8/5 U = 1.6 200

100 100

200

300

400

Flow Rate, GPM

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The pressure drop accounts for all the hole discontinuities, changes in mud rheology throughout the circulating system, changes and discontinuities in the drillstring configuration, and all surface pressure losses. These data are plotted in the figure above. Data also recorded by the driller are also plotted but is not necessary to be plotted. Corresponding bit pressure drops are subtracted from each point and a straight line is drawn through the points (represented as circles in the above graph). Because the configuration of the borehole and the drillstring currently being used is known, pressure losses can be anticipated for any flow rate. Unlimited surface pressure (or hydraulic horsepower limit) will be considered in Case 1 and limited surface pressure in Case 2. To find the optimum pressure at the bit, the following equations can be used:

Case 1

Pbit=

u +1 Phhp u+2

= 0.772 Phhp

Case 2

Pbit opt =

u Pmax u+2

= 0.444 Pmax

For Case 2 the optimum pressure drop across the bit is 44.4% of the maximum pressure instead of 47.6%, which would be the drop if a u value of 1.82 is used. If the maximum standpipe pressure is 3,300 psi then: Pbit = (0.444) (3,300) = 1,465 psi The pressure drop in the circulating system (Pcirc) should be 1835 psi. Looking at the graph, a pressure drop of 1835 psi through the system indicates that the flow rate must be 474 gpm. Although 1,071 hhp is available, only a portion can be used because of the maximum surface pressure limitation. Therefore using equation 28, hhp = (3,300 psi) (474 gpm) / 1714 = 913 hp For a bit pressure drop of 1465 psi, a flow rate of 474 gpm and with 112 pcf mud, using:

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AT (in2) = 0.00342

ρQ 2

Pbit

AT (in2) = 0.448 in2

dN = 32

4A T

3π

dN = 13.96, or three 14’s.

Therefore the next bit will require three 14’s instead of the three 16’s that are currently in the bit. When the surface pressure reads 3,300 psi, the flow rate has to be 530 gpm through the 16/32 in. nozzles, instead of the 474 gpm through the 14/32 in. nozzles. Nozzle inside diameter tolerances are not very tight, therefore for the most accurate results, the nozzles should be measured with a micrometer prior to running in the well. At very high flow rates, a small difference in the diameter could result in several hundred psi difference in pressure. Field Implementation

Using this method in the field can best be accomplished by the engineer providing the foreman with a graph having the limits already drawn. For example, for a rig that has two 1,200-kW motors, each driving a triplex pump. The maximum standpipe pressure permitted is 3,000 psi. Assume that the driller has just drilled to a depth of 8294 ft with 74.8 pcf mud in the hole and is ready to pull out for a bit trip. If the drilling engineer has been thoughtful enough to provide a chart, the foreman’s next steps are easy. First, the electrical power driving the pumps is translated to horsepower:

⎡

⎤

= 1,609 hp 1,200kW ⎢ ⎣ 0.7457kW ⎥⎦ hp

Second, the efficiencies of the mechanical drive and the volumetric displacement of the pump are used to reduce input power to output hydraulic horsepower:

(1,609hp )(0.85 )(0.93 ) = 1,272 hhp

Third, the hydraulic horsepower is drawn on the log P-log Q graph (see figure below). Arbitrary flow rates are selected and the associated pressures calculated, providing the points to draw the chart.

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The maximum hydraulic horsepower curve is generated from equation 28:

PQ = 1,272hhp 1,714 For example, if Q = 1000 gpm,

P=

(1,272hhp) (1,714) = 2,180psi 1000

And at Q = 300 gpm,

P=

(1,272hhp) (1,714) = 7,267psi 300

Maximum surface pressure was given as 3,000 psi, therefore the hhp line is constructed on the graph. As a check Qcrit may be calculated then checked on the graph. Q

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crit

=

(1,272hhp) (1,714) 3000psi

= 727gpm

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Minimum and maximum flow rates could be included. These values are usually arbitrary guidelines set up by each company. Actual minimum flow rates to clean the hole must be determined on site.

8000 7000 5000

Maximum Surf. Press.

3000

1,272 hhp Line

2000

Suppose that just before the driller pulls out of the hole, he determines the standpipe pressure at several pump rates with jet nozzle sizes of one 14/32-in and two 15/32-in nozzles in the bit. The rig is equipped with Emsco-FA-1300 pumps with 6-1/2” liners. With pump rates of 70, 90, and 100 spm, the standpipe pressures were 1,180, 1,840, and 1,210 psi respectively. The driller’s normal operating pump rate is 120 spm with 3,000 psi standpipe pressure. He determined from a hydraulics book that:

Stroke rate, spm Flow rate, gpm Standpipe pressure, psi Bit pressure, psi Circulation pressure, psi

70 361 1,225 490 735

Press, PSI 1000 800 600 400 300

200

100 100

200

300

400

600 Qcrit 1000

Flow Rate, GPM

90 465 1,850 810 1,040

100 517 2,200 1,000 1,200

120 620 3,000 1,440 1,560

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The slope is found to be 1.4 after plotting Pcirc verses the flow rate. ⎡

⎤

⎞ P max indicates that the Calculation of the optimum bit pressure loss ⎢⎛⎜ ⎟ ⎥ ⎣⎝ u + 2 ⎠ ⎦ maximum hydraulic impact will be achieved if the 1,235 psi drop occurs at the bit. This leaves 1,765 psi for the pressure loss through the circulating system (Pcirc), which can be obtained by pumping 680 gpm. With this flow rate, 680 gpm, and the 1,235 psi bit pressure drop, therefore:

AT (in2) = 0.00342

dN = 32

u

75 × 680 2 = 0.573 1235

4 × ( 0.573) = 15.8 3 × 314 .

the nozzle sizes are determined to be three 16/32-in. nozzles. 8000 7000 5000

Maximum Surf. Press.

3000

1,272 hhp Line

2000

Press, PSI

∆P circ opt

1000 7 in.

800 600 P circ

400

5 in. Slope=7in/5in = 1.4

300

u ∆P = P bit opt u + 2 max

200

=

1. 4 3. 4

( 3000 psi ) = 1, 235 psi

∆P = 1, 765 psi circ

100 100

200

300

400

Flow Rate, GPM

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600

1000

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SURFACE AND DOWNHOLE PLUGS 1.0

TYPES OF PLUGS 1.1 Back Pressure Valves 1.2 Polymer Plugs 1.3 Cement Plugs 1.4 BOP Test Plugs 1.5 Mechanical Downhole Plugs

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SURFACE AND DOWNHOLE PLUGS 1.0

TYPES OF PLUGS

Several types of plugs are used for many purposes in the Oil Industry. Saudi Aramco Drilling and Workover commonly uses Back Pressure Valves and Two-way Check Valves, Chemical Plugs, Balanced Cement Plugs, BOP Test Plugs and Mechanical Downhole Plugs. These different plugs are used as safety barriers while installing, or removing, well control and production equipment and as test plugs when pressure testing equipment. When removing surface control equipment it must be replaced with downhole isolation barriers. Plugs are the most commonly used isolation barrier. Please refer to GI 1853.001, Isolation Barriers For Wells During Drilling and Workover Operations (With and Without Rig) for the required number and type of plug to be used. 1.1

Back Pressure Valves Back Pressure Valves are set in a special profile in the tubing hanger. They are normally used while installing or removing production trees and BOP equipment. Two way check valves can be installed in the same profile and are used to test the equipment. A two way check valve shall only be used to test equipment after it is installed, not during installation or removal operations. This is because it is possible to pump kill weight fluids through a back pressure valve but not through the two way check valve. More details on these plugs and installation and removal procedures may be found in Chapter 2-E, WELLHEAD, Section 4.0.

1.2

Polymer Plugs Polymer plugs may be spaced across perforations and used as an additional safety device when performing unusual well servicing. They are more commonly used for temporarily or permanently healing lost circulation. More details on these plugs may be found in Chapter 2-F, LOST CIRCULATION, Section 5.0, Polymer Plugs. Whenever using polymer plugs it is important to emphasize the need to (a) tailor the plug design for the well conditions, (b) laboratory test the plug to fine-tune the polymer additive concentrations, and (c) ensure satisfactory polymer plug performance.

1.3

Cement Plugs Cement plugs may be spotted in casing or, in some cases tubing, and used as an additional barrier during unusual well servicing operations. More details on these plugs may be found in Chapter 2-F, LOST CIRCULATION, Section 5.0, Cement Plugs.

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1.4

BOP Test Plugs BOP Test plugs are designed to be installed in a casing head, casing spool or tubing spool to provide a bottom seal while testing BOPE. They are designed and built to fit one size head or spool made by one Manufacturer. For example, if you have a Cameron 13-5/8” 3M casing head you must use a Cameron 13-5/8” BOP test plug. If you have a Gray 13-5/8” 3M casing head you must use a Gray 13-5/8” BOP test plug. These plugs may not be interchanged. The preferred running procedure is to make up at least one stand of drill pipe below the plug, preferably hevi-weight. The elastomer seal on the O.D. of the plug should be visually inspected and a coat of grease or pipe dope applied prior to running.

1.5

Mechanical Downhole Plugs Downhole or “wireline” plugs are used on a daily basis in Saudi Aramco operations. These types of plugs, along with the back pressure valve, are used as isolation barriers after the completion string has been run. The most commonly used wireline plugs are the X locking mandrel and the R locking mandrel. In order to use these plugs there must be a mating X or R landing nipple installed in the completion string. Typically the X nipple is installed in normal weight tubing strings and the R nipple in heavy weight tubing strings. Figure 2J-1 shows the R and X models of landing nipples and lock mandrels. The nipples are selective nipples as they will allow a plug to pass through them and it can be set in a nipple below, or in the selective nipple. Figure 2J-2 shows XN and RN no-go landing nipples and lock mandrels. These nipples are termed no-go because they have an internal profile that will not allow the plug to pass below the nipple, and thus it can only be set in that specific nipple.

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Figure 2J-1: Selective Nipples and Lock Mandrels

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Saudi Aramco uses the PX and PXN plugs almost exclusively. These plugs come equipped with a pressure equalization valve and matching prong. They are set in X, selective, and XN, no-go, nipples. These plugs are installed in two trips. On the first trip the plug is ruin without the prong. The prong is then inserted on the second trip, sealing the equalization ports and preventing sand or fill from falling into the interior of the plug. The plugs are retrieved in two trips, the prong on the first. This provides an equalization path and prevents the plug from being blown uphole. IF it is desirable to make only one trip XX or XXN plugs may be run. These plugs are run or retrieved and the equalizing ports opened or closed in one trip. All of these plugs may be run and retrieved on coiled tubing. This method would be desirable in a horizontal or highly deviated well. Figures 2J-3 and 2J-4 are tables listing the common sizes of landing nipples and lock mandrels available. Remember to always double check the size before attempting to run a plug.

Figure 2J-2: No-Go Nipples and Mandrels

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Figure 2J-3: X and XN Nipple and Mandrel Dimensions X® and XN Landing Nipples and Lock Mandrels Specifications For Standard Tubing Weights XN Profile X® Profile Lock Mandrel ID Packing Bore Packing Bore ID Drift No-Go ID in. mm in. mm in. mm in. mm in. mm in. mm 0.824 20.93 0.730 18.54 Available on Request 1.049 26.64 0.955 24.26

Tubing Size in. mm 1.050 26.67 1.315 33.40 1.66 42.16 1.900 48.26 2.063 52.40 2.375 60.33 2.875 73.03 3.500 88.90 4.000 4.500 5.000 5.500

101.60 114.30 127.00 139.70

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Weight Ib/ft kg/m 1.20 1.79 1.80 2.68 2.30 3.43 2.40 3.57 2.40 3.57 2.76 4.11 2.90 4.32 3.25 4.84 4.60 6.85 4.70 7.00 6.40 9.53 6.50 9.68 9.30 13.85 10.20 15.34 11.00 16.38 12.75 18.99 13.00 19.36 17.00 25.32

1.38

35.05

1.660

42.16

1.29

32.66

1.250

31.75 1.250 31.75 1.135 28.83

1.610

40.89

1.751

0.620

15.75

1.516

38.51

1.500

38.10 1.500 38.10 1.448 36.78

0.750

19.05

44.48

1.657

42.09

1.625

41.28 1.625 41.28 1.536 39.01

1.995

50.67

1.901

48.29

1.875

47.63 1.875 47.63 1.791 45.49

1.000

25.40

2.441

6,200

2.347

59.61

2.313

58.75 2.313 58.75 2.205 56.01

1.380

35.05

2.992 2.922 3.476 3.958 4.494 4.892

76.00 74.22 88.29 100.53 114.14 124.26

2.867 2.797 3.351 3.833 4.369 4.767

72.82 71.04 85.10 97.36 110.97 121.08

2.813 71.45 2.813 2.750 69.85 2.750 3.313 84.15 3.313 3.813 96.85 3.813 4.313 109.55 4.313 4.562 115.87 4.562

1.750

44.45

2.120

53.85

2.620

66.55

3.120

79.25

71.45 69.85 84.15 96.85 109.55 115.87

2.666 2.635 3.135 3.725 3.987 4.455

67.72 66.93 79.63 94.62 101.27 113.16

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Size in. 1.660 1.900 2.375

2.875

3.500

4.000

4.500

5.000 5.500 6.000 6.625

7.000

8.625

Landing Nipples And Lock Mandrels Selective By Running Tool R® And RN® Landing Nipples And Lock Mandrels Specifications For Heavy Tubing Weights Tubing Lock Mandrel ID R® Profile RN® Profile Weight ID Drift Packing Bore Bore ID Ib/ft in. in. in. in. in. in. 3.02 1.278 1.184 1.125 1.125 1.012 on Req. 3.64 1.500 1.406 1.375 1.375 1.250 0.620 5.30 1.939 1.845 1.781 1.781 1.640 0.880 5.95 1.867 1.773 1.710 1.710 0.750 1.560 6.20 1.853 1.759 7.70 1.703 1.609 1.500 1.500 1.345 0.620 7.90 2.323 2.229 2.188 2.188 2.010 1.120 8.70 2.259 2.165 2.125 0.880 2.125 1.937 8.90 2.243 2.149 9.50 2.195 2.101 2.000 0.880 2.000 1.881 10.40 2.151 2.057 11.00 2.065 1.971 1.875 0.880 1.716 1.875 11.65 1.995 1.901 12.95 2.750 2.625 2.562 2.562 2.329 1.380 15.80 2.548 2.423 2.313 1.120 2.131 2.313 16.70 2.480 2.355 17.05 2.440 2.315 2.188 2.188 2.010 1.120 11.60 3.250 3.303 3.250 3.250 3.088 1.940 13.40 3.340 3.215 3.125 3.125 2.907 1.940 12.75 3.958 3.833 3.813 3.813 3.725 2.120 13.50 3.920 3.795 3.688 2.380 3.456 3.688 15.50 3.826 3.701 16.90 3.754 3.629 3.437 1.940 3.260 3.437 19.20 3.640 3.515 15.00 4.408 4.283 4.125 4.125 3.912 2.750 18.00 4.276 4.151 4.000 4.000 3.748 2.380 17.00 4.892 4.767 4.562 2.850 4.445 4.562 20.00 4.778 4.653 23.00 4.670 4.545 4.313 4.313 3.987 2.620 15.00 5.524 5.399 5.250 5.250 3.500 5.018 18.00 5.424 5.299 24.00 5.921 5.795 3.500 5.625 5.625 5.500 28.00 5.791 5.666 17.00 6.538 6.431 20.00 6.456 6.331 23.00 6.366 6.241 3.750 5.963 5.770 5.963 26.00 6.276 6.151 29.00 6.184 6.059 32.00 6.094 5.969 35.00 6.004 5.879 5.875 5.875 5.750 3.750 7.050 7.050 6.925 5.250 36.00 7.825 7.700 7.250 7.250 7.125 5.250 7.450 7.450 7.325 5.250

Figure 2J-4: R and RN Nipple and Mandrel Dimensions

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POSITIVE DISPLACEMENT MOTORS 1.0 INTRODUCTION 2.0 POSITIVE DISPLACEMENT MOTORS 2.1 2.2

PDM Operating Principles Aramco Utilization

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POSITIVE DISPLACEMENT MOTORS

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POSITIVE DISPLACEMENT MOTORS 1.0

INTRODUCTION Two of the most intriguing questions for drilling personnel are (1) what bit, bottom hole assembly and rotational method (drilling system) is optimal for a given hole section and (2) what are the optimal operating parameters for that system? For Saudi Aramco drilling operations the short list of drilling systems include: 1) 2) 3) 4) 5)

Rotary and Rock Bit Rotary and PDC PDM and Rock Bit PDM and PDC Turbine and PDC

The purpose of this section and the following sections on Turbines and Performance Drilling Systems Optimization is to present the essential operating parameters and requirements which best utilize each drilling system.

2.0

POSITIVE DISPLACEMENT MOTORS

The Moineau Pump was patented in 1926 by the French Engineer Rene Moineau. The Moineau pump or more commonly called the progressing cavity pump gained wide scale utilization in artificial lift applications for shallow to medium depth oil and water wells. It is also used for surface transfer of solids laden fluids. The progressing cavity pumps were found capable of handling, high viscosity, solids and sand laden fluids more effectively than conventional oilfield rod pumping units and Electric Submergible Pumps (ESP). A Progressing Cavity pumping system is shown in Fig 2K-1. Figure 2K-1 Progressive Cavity Pumping System ____________________________________________________________________________________

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The progressive cavity pumps work by turning a single external-helix steel rotor inside a double internal helix elastomeric stator. The rotary action of the steel rotor forms cavities that progress upward from the bottom of the hole through the pump and tubing to the surface. The Positive Displacement Motor, (PDM), which was commercially introduced in 1966 by Smith Tool Co. as the "Dynadrill" motor, works on the reverse application on the Moineau pump principle. Instead of turning a rotor inside a stator assembly from the surface to pump fluid through the tubing up-hole, fluid is pumped from the surface into the Drillstring to turn a rotor inside a stator assembly down-hole. The PDM rotor is attached to a transmission and drive shaft assembly that in turn impart rotational motion to the drill bit. PDM's were field tested in California in 1962 as part of a directional drilling system. The application of the PDM and bent-sub assembly provided the first practical capability for developing offshore California fields from onshore. PDM usage quickly spread to the Gulf of Mexico where they were used for directional applications from offshore drilling rigs. PDM's continued to evolve over the next 30 years with the development of Tandem, Extended Power Section and Articulated motors into the steerable systems we know today.

2.1

Principles of Operation In a positive displacement motor, pressurized circulating fluid is pumped into a progressing axial cavity formed between a helically lobed metallic rotor and a helically lobed elastomeric stator. The force of the pressurized circulating fluid pumped into the cavity between the rotor and the stator cause the rotor to turn inside the stator. The action of the rotor and stator converts the hydraulic energy of the circulating fluid to mechanical energy (rotation) which is transferred to the drill bit via a transmission and drive shaft assembly. Modification of lobe numbers and geometry at the design stage provides for variation of motor input and output characteristics to accommodate various drilling requirements. PDM's consist of six main components: (1) Dump Sub (2) Power Unit (Rotor & Stator), (3) Bent Housing, (4) Transmission Unit, (5) Bearing Section Assembly and (6) Tubular Housings and Stabilizers as shown in Fig 2K-2.

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Figure 2K-2 - Positive Displacement Motor (5/6 Lobe Configuration with fixed bent housing)

Dump Sub The geometry of the rotor/stator power unit prevents fluid flow between the Drillstring and annulus during tripping operations. A dump sub can be incorporated above the power unit in the motor assembly to allow the Drillstring to fill when tripping in the hole and empty when tripping out of the hole, thereby avoiding wet trips. The dump sub also permits low rate circulation if required. The dump sub contains a valve, which is ported to allow fluid flow between the Drillstring and annulus. The dump valve assembly is of a sliding piston and spring design, with all parts manufactured from high quality steels. When circulation rates are low or when there is no circulation rate for the motor, the piston moves down, closing the bypass ports. Drilling fluid is then directed through the motor section. When circulation stops, the bypass piston is released and the bypass ports reopen. Most multi-lobe motors 3-3/8" and larger are equipped with hollow rotors, thus lessening the requirement for the dump sub.

Figure 2K-3 - Dump Sub Assembly ____________________________________________________________________________________

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For performance drilling in larger diameter hole sections, adding a rotor nozzle allows increasing the total flow rate to clean the hole and remove cuttings. Nozzled rotors cause more fluid to be circulated around the bearing assembly and less directly through the rotor/stator cavity, thereby reducing rotational speed. This decrease in bit speed while maintaining high circulation rate is necessary for special applications such as spudding, under-reaming or hole opening in large hole sizes. A simple hydraulics calculation is used to determine the size of the rotor nozzle required. RTFA=

Q2 x MW 0.5 P x 10,858 ..........................................................................Eq. 2K-1

Where: RTFA = total flow area for Rotor Nozzle (nozzle size, sq. in.) Q = amount of flow to bypass (gpm) MW = mud weight (lb/gal) P = expected differential drilling pressure + friction pressure (psi) Friction pressure is generally 125 psi for motors and 150 psi for 3.5" and smaller motors.

4.75"

and

larger

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Figure 2K-3 - Nozzled Rotor

Power Section In the power section of a PDM, a rotor/stator pair convert the hydraulic energy of the pressurized circulating fluid to mechanical energy in the rotating shaft. In addition, the action of the circulating fluid imparts hydraulic downthrust on the rotor. Like the Progressive Cavity Pumps, PDM's can accommodate various circulating fluids, including oil-based muds; water based muds, water, air and foam while producing the output characteristics required to achieve successful drilling operations. However, high fluid corrosivity and abrasiveness tend to accelerate stator wear. The rotor and stator lobe profiles are similar; with the steel rotor having one less lobe than the elastomeric stator. Motors are generally available in 1:2, 3:4, 4:5, 5:6, 7:8 and 9:10 configurations, as depicted in Fig 2K-4.

Figure 2K-4 - Common Rotor/Stator Configurations

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Figure 2K-5 – 4-3/4, 6-3/4, 8 and 9-5/8” PDM Rotors prior to installation

In most cases, the higher the number of lobes, the higher the torque output of the motor and the slower the speed.

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Power units are generally categorized with respect to the number of lobes and effective stages. One power unit stage is represented by the linear distance of a full " wrap" of the stator helix, as shown in Fig 2K-6. Figure 2K-6 - Spiral Stage Length

The difference between the number of lobes on the rotor and the number of lobes in the stator results in an eccentricity between the axis of rotation of the rotor and the axis of the stator. The rotor/stator lobes and helix angles are designed such that the rotor/stator pair seal at discrete intervals. This results in the creation of axial fluid chambers or cavities, which are filled by the pressurized circulating fluid. The action of the pressurized circulating fluid causes the rotor to rotate and precess within the stator. The lobe geometry and amount of eccentric rotor movement is designed to minimize contact pressure, sliding friction, abrasion and vibration thus reducing rotor and stator wear. The movement of the rotor inside the stator is called nutation. For each nutation cycle made by the rotor inside the stator the rotor turns/ratchets the distance of one lobe width. The rotor must nutate for each lobe in the stator to complete one revolution of the bit box. For example, a motor with a 5:6 rotor/stator lobe configuration and a speed of 100 rpm at the bit box will have a nutation speed of 500 cycles per minute. The elastomeric stator is injection molded with detailed attention given to elastomer composition consistency, bond integrity and lobe profile accuracy. The stator is molded directly to the power unit housing. The metallic rotor is precision machined to close axial and radial tolerances and can be coated with chromium or ceramics to maximize wear and corrosion resistance. Most rotors used in Saudi Aramco operations are coated with a thin, typically 0.01" layer of hardened chromium to provide a smooth outer surface which minimizes wear and abrasion to the elastomeric stator. However, corrosive drilling fluids may cause pitting of the chrome layer as shown in Figure 2K-11. This type of damage actually accelerates stator wear. If drilling fluid properties cannot be altered, then tungsten carbide rotors may yield longer stator life. ____________________________________________________________________________________

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Within the specified motor operating ranges, bit rotation speed is directly proportional to the circulating fluid flow rate between the rotor and stator. Above the maximum specified operating differential pressure, fluid leakage occurs between the rotor and stator seals and bit rotation speed decreases. Excessive fluid leakage results in "stalling", as the rotor stops rotating within the stator. Similarly, within the specified motor operating ranges, motor output torque is directly proportional to the differential pressure developed across the rotor and stator. If the motor is operated above the maximum specified torque production values, there can be a tendency for accelerated rotor/stator wear and stalling may occur. The power developed by the rotor and stator is directly proportional to both rotational speed and torque. Motor horsepower and related values of rotational speed and torque should be fully evaluated with respect to specific drilling applications. Adjustable and fixed Bent Tubular Housings PDM's can be configured with adjustable bend, fixed bend, straight, or eccentric housings for a full range of build rates. An Adjustable bent housing with a setting range of from 0 to 3° is shown in Fig 2K-7. When using an adjustable bent housing the desired setting can be set on the rig floor. A rough estimate of the build rate achieved with a particular bent housing setting can be obtained using the following equation: Build Rate, deg./100 ft = 200 x Bent Housing Setting, deg. ..........Eq.2K-2 Distance from bit to Motor top, ft. Equation 2K-2 assumes ideal bottom hole assembly behavior in gauge hole. The harder the formation, the closer field performance approaches ideal BHA behavior, as long as an acceptable ROP can be achieved. Further, achievable build rates with a given bent housing setting typically decrease with increased washout and softer formations.

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Figure 2K-7 - Adjustable Bent Housing

Transmission Unit The transmission unit eliminates all rotor eccentric motion and the effects of fixed or adjustable bent housings while transmitting torque and downthrust to the drive shaft. The drive shaft is held in place concentrically by the bearing assembly. The transmission unit must also allow the correct axial relationship of the rotor to the stator to ensure efficient rotor to stator sealing and minimize rotor and stator wear. A variety of constant velocity transmission unit designs are employed, providing maximum transmission efficiency for differing rotor/stator configurations. Transmission units are of multi-element design consisting of a central shaft connected at either end with universal couplings. The couplings contain many specialized components housed in an oil-filled environment. Component design and environment are selected to promote efficiency, reliability and longevity. ____________________________________________________________________________________

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Figure 2K-8 - Transmission Unit

Bearing Section The bearing assembly consists of multiple thrust bearing cartridges, radial bearings, a flow restrictor and a drive shaft. The thrust bearings support the downthrust of the rotor and the reactive upward loading from the applied weight on bit. For larger diameter motors the thrust bearings are of multi-stack ball and track design. Small diameter motors utilize carbide friction bearings. Metallic and non-metallic radial ______________________________________________________________________________________

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bearings are employed above and below the thrust bearings to absorb lateral side loading of the drive shaft. Side loading of the drive shaft can be significant in steerable and correction run applications. The radial bearing materials are selected and manufactured to provide reliable operation. The bearings are normally repacked in the service companies shop after each motor run as shown in Figure 2K-9.

Figure 2K-9 - Repacking of Bearing Assembly after PDM run

The bearing assembly is cooled and lubricated by approximately 5-8% of the circulating fluid flow; however this value can be altered through the use of nozzled rotors as previously mentioned. The drive shaft transmits both axial and torsional loading to the bit. The drive shaft is a forged component, which has a threaded connection at the bottom end to facilitate connection to the drill bit. The drive shaft is the only external rotating component. Fluid is supplied to the drill bit through the center of the drive shaft. All bearing assemblies are designed such that the drive shaft and bearings can not strip out of the bearing housing in the event of the Drillstring becoming stuck and the maximum downhole overpull for a particular motor exceeded. ____________________________________________________________________________________

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Performance Motors Performance or "extended power section motors" have power head sections with from 1.25 to 2.0 times the number of stages of standard PDM's. These motors have improved torque output compared to standard motors, without the long length of Tandem Power Head Motors. The maximum bend on some extended power section motors is only 1.83° because the larger diameter shaft required for the high torque leaves less clearance in the transmission section. Bend settings greater than 1.83° would cause the transmission in the motor to rub against the inner diameter of the adjustable bent housing. Tandem Motors Tandem motors utilize two standard power sections joined by a transmission unit, effectively doubling the number of stages compared to the standard PDM. By doubling the number of stages - the tandem power head motor, increases torque output, maintains a higher bit speed over a wider range of operating differential pressures and extends bit motor life. However due to their longer length, the tandem motors are more difficult to steer and require higher standpipe pressures to operate. Figure 2K-10 - Dual Rotor configuration on Tandem PDM

PDM Operating Characteristics The effectiveness of a PDM in a specific operating environment can be related to its Mean Time Between Failure (MTBF) and Mean Time Between Maintenance (MTBM). Operators can lower their cost by implementing subtle changes in drilling fluid properties and operating practices to improve these micrometers of PDM performance. Drilling Fluid Properties Chlorides Chlorides in mud can severely corrode the chrome plating on standard rotors. As a result of corrosion, the rough edges left on the rotor lobes damage the stator by cutting the top off the elastomer in the stator/lobe profile. Corrosion damage to a chrome-plated rotor from a 6-5/8" motor is shown in Fig 2K-11.

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Figure 2K-11 - Corrosion Damage to Chrome Plated Rotor, Saudi Arabia

Lost Circulation Material Lost circulation material can cause two problems when pumped through a motor. The material can plug off inside the motor, usually at the dump valve if one is used at the top of the output shaft or the radial bearing, and it can cause stator wear. However, LCM can be used with most PDM's if certain precautions are followed. ¾ Add the LCM evenly - avoid pumping a large slug of material. ¾ Minimize the use of hard, sharp-edged materials such as nut plug, coarse mica and calcium carbonate chips because they can cause stator wear by abrasion. Corrosion Inhibitors The Napha base of many pipe corrosion inhibitors can cause excessive swelling of the elastomeric stator. Particularly when added to the mud system in slugs. Salt Saturated Muds Severe corrosion problems have occurred in Salt Saturated Muds, apparently as a result of galvanic action between the dissimilar metals of the motor, drill collars and the conductive drilling mud. Sacrificial anodes have been found to work well in the motors, when galvanic corrosion is a problem. Oil Based Muds & Water Based Muds with Diesel Added Stators are occasionally subjected to chemical attack by aromatic hydrocarbons in the diesel phase of oil mud systems. Diesel fuels are typically "winterized" by the addition of aromatic compounds to lower the temperature at which the fuel gels. The aniline point of a diesel fuel-the temperature at which aniline becomes soluble in the diesel - is an inversely

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related indicator of aromatic content. Fuels with aniline points less than 155° F are potentially detrimental to PDM stators. Limit Surface Rotary Speed Rotating motors at surface speeds above 80 rpm can damage the elastomer in the stator. The larger the bend setting the more susceptible motors are to damage. Motor Failure Modes The elastomeric lining of the stator tube is usually the element that fails first in the power section. The central causes of rubber failure in a stator are chunking, debond and junk damage. Chunking Chunking (or chunk out) describes a stator in which the rubber across the top of the lobes has apparently ripped away. Chunking occurs when the strength of the friction force between the rotor lobe and the stator lobe exceeds the strength of the rubber in the stator. The magnitude of the friction force between the rotor and the stator is affected by the lubricity of the mud, interference fit between the rotor and stator, nutation speed and pressure drop. Most stator failures result from chunking for various reasons. De-Bonding Two bonding agents are used in stators. One-agent bonds to the steel tube, the other agent bonds to the stator elastomer, and both agents bond to one another. Debond is defined as the failure of any one, two or all three bonds in the stator: Steel tube to bonding agent Bonding agent to bonding agent Bonding agent to elastomer Stators failing from debond typically shed large sheets of loose elastomer. These sheets of rubber usually have a smooth back surface where the stator was molded against the steel tube. Motor failures from debonding are relatively rare. Junk Damage Junk damage is caused by pumping "junk" through the motor. The stator will have sharp cuts along a spiral path, and the rotor may also have damage along the same path. It is difficult to prevent debond failures, which fortunately are rare. Measures can be taken to prevent chunking failures and junk damage. The most obvious prevention technique is to prevent junk damage by ensuring that junk ______________________________________________________________________________________

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can't get into the mud system or Drillstring. Chunking prevention is a combination of techniques involving the rotor/stator fit, bottom hole temperature, drilling fluid selection, proper operation (use of performance curves), lost circulation material usage, nozzled rotors, dogleg severity and stator age tracking.

Figure 2K-12 - Removal of worn Chromed PDM Rotor and Installation of New one

Figure 2K-13 – Chrome & Tungsten Carbide rotors from 2-7/8” Short Radius PDM's

2.2 Saudi Aramco Utilization of Positive Displacement Motors

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Saudi Aramco began using PDM's in the early 1970's. They purchased about 40 PDM's of various sizes and configurations and serviced them out of the Toolhouse. The PDM's were used mainly for Top-Hole drilling. Aramco continued running and servicing their own PDM's until about 1994, when it was no longer deemed economically advantageous. All PDM's currently utilized by Aramco fall under the Directional Drilling Contracts. The Anadrill and Sperry-Sun PDM's currently used for directional and performance drilling are shown in Table 2K-1. More detailed information on motor specifications and performance can be obtained from PDM Service Company Handbooks. They have specification sheets for each of their motors which detail the motor dimensions, fishing limitations and maximum operating parameters. The motor handbooks also include nomographs from which predicted rotational speed, output horsepower and torque can be obtained from the actual Motor pressure differential (On-bottom pressure - off bottom pressure) at given flow rates. Example Motor specification sheets for Anadrill and Sperry-Sun PDM's are shown in Fig. 2K-13 and 2K-14 respectively. Figure 2K-13 - Anadrill Specification Sheet for 6-3/4" 4/5 lobe Standard PDM

Figure 2K-14 - Sperry Sun 9-5/8” O.D. ¾ Lobe Extended Power Section PDM

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+0.

Table 2K-1 - Commonly used PDM's in Saudi Aramco Drilling Operations POSI TI VE DI SPLACEMENT MOTORS CURRENTLY USED I N SAUDI ARAMCO OPERATI ONS

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MODEL (N0)

SIZE

LOBE

FLOW RATE

STAGES OD, IN. COFIG (NO)

RPM

HOLE SIZE RUNS/

GPM

RANGE

INCHES

YEAR

SS287B

2-7/8

5/6

3.3

20-100

120-600

3-3/4-4-1/4

12

SS287L

2-7/8

5/6

3.3

20-100

120-600

3-3/4-4-1/4

6

MAJOR APPLICATION SHORT RADIUS BUILD SECT. 60-130 deg/100' SHORT RADIUS LATERAL SECTION

KICK OFF BUILD & TANGENT SECTION

A475M

4-3/4

4/5

3.5

100-250

105-262

5-7/8-7

49

A475XP

4-3/4

4/5

6.0

100-250

105-262

5-7/8-7

0

SS475B

4-3/4

4/5

3.5

100-250

105-262

5-7/8-6-1/8

12

SS475M

4-3/4

4/5

3.5

100-250

105-262

5-7/8-7-7/8

4

DEVIATED AND HORIZONTAL WELLS

SS475M

4-3/4

4/5

3.5

100-250

105-262

5-7/8-6-1/8

6

SHORT RADIUS LATERAL SECTION

SS475XP

4-3/4

4/5

6.3

100-250

105-262

5-7/8-7-7/8

4

DEVIATED AND HORIZONTAL WELLS

A475M

4-3/4

7/8

2.2

100-250

54-140

5-7/8-7

0

KICK OFF BUILD & TANGENT SECTION

A475XP

4-3/4

7/8

3.8

100-250

54-140

5-7/8-7

1

PERFORMANCE RUNS IN TANGENT SECTION

SS475M

4-3/4

7/8

2.2

100-250

56-140

5-7/8-7-7/8

55

DEVIATED AND HORIZONTAL WELLS

A675M

6-3/4

4/5

4.8

300-700

150-300

8-3/8-9-7/8

89

KICK-OFF, BUILD & TANGENT

A675XP

6-3/4

4/5

7.0

300-700

150-300

8-3/8-9-7/8

44

PERFORMANCE RUNS & TANGENT SECTION

SS675M

6-3/4

4/5

4.8

300-600

150-300

8-3/8-8-1/2

2

DEVIATED AND HORIZONTAL DRILLING

SS675XP

6-3/4

4/5

7.0

300-600

150-300

8-3/8-8-1/2

2

VERTICAL/DEVIATED/HORIZONTAL DRILLING

SS675XP

6-3/4

6/7

5.0

300-600

87-173

8-1/2-9-7/8

12

A675M

6-3/4

7/8

3.0

300-700

86-165

8-3/8-9-7/8

0

KICK-OFF BUILD AND TANGENT

A675XP

6-3/4

7/8

5.0

300-700

86-165

8-3/8-9-7/8

0

PERFORMANCE RUNS & TANGENT SECTION

SS675M

6-3/4

7/8

4.8

300-600

86-172

8-3/8-8-1/2

65

PERFORMANCE RUNS & TANGENT SECTION SHORT RADUIS W/60-120 deg/100' BUR

KHUFF PDC APPLICATIONS

DEVIATED AND HORIZONTAL DRILLING

A800M

8

4/5

3.6

300-1100

75-225

9-7/8-14-3/4

22

KICK-OFF, BUILD & TANGENT

A800XP

8

4/5

5.3

300-1100

75-225

9-7/8-14-3/4

15

TANGENT AND PERFORMANCE

SS800XP

8

4/5

5.3

300-900

75-225

9-5/8-14-1/2

2

VERTICAL/DEVIATED/HORIZONTAL DRILLING

SS800XP

8

6/7

4.0

300-900

50-150

9-5/8-14-1/2

6

KHUFF 12" SECTION W/PDC & INSERT BITS

A800M

8

7/8

3.0

300-1100

48-145

9-7/8-14-3/4

0

KICK-OFF, BUILD & TANGENT

32

DEVIATED AND HORIZONTAL

SS800M

8

7/8

3.0

300-900

48-144

9-5/8-14-1/2

SS962XP

9-5/8

3/4

6.0

600-1200

132-264

12-26

8

VERTICAL/DEVIATED/HORIZONTAL

SS962M

9-5/8

5/6

3.0

600-1200

67-134

12-26

6

DEVIATED AND HORIZONTAL

A962M

9-5/8

5/6

3.0

600-1500

67-134

12-1/4-26

19

A962XP

9-5/8

5/6

4.0

600-1500

67-134

12-1/4-26

7

KICK-OFF, BUILD AND TANGENT PERFORMANCE RUNS & TANGENT SECTION

CODE: A = ANADRILL; SS=SPERRY SUN; M=STD. POWER SECT.; XP=EXTENDED POWER SECT.; B=BUILD SECT.; L=LATERAL SECT.

The PDM Performance curves are typically used by entering the base of the graphs at the X axis with the observed or predicted PDM pressure differential; proceeding up the

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graph vertically until the applicable flow rate or torque line is intersected and proceeding horizontally to read its value on the Y axis. Example Problem 2K-1: Predict the Rotational Speed, Torque, and Horsepower developed for a Sperry-Sun 4-3/4" 4/5 lobe, 3.5 stage PDM when operated at 420 psi motor differential pressure and cirulation rate of 175 gpm from the applicable performance specfication sheet. Figure 2K-15 - Performance Graph for Sperry-Sun 4-3/4" - 4/5 Lobe - 3.5 Stage PDM

From the chart above it can be seen that Shaft Rotational Speed = 170 rpm, Horsepower = 25 Hp and Torque output = 690 ft-lb.

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TURBINES

1.0 CONVENTIONAL DOWNHOLE TURBINES 1.1 1.2 1.3 1.4

2.0

Principles of Operation Turbine Components Saudi Aramco Utilization Operating Guidelines

LOW SPEED-HIGH TORQUE TURBINES

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TURBINES 1.0

CONVENTIONAL DOWNHOLE TURBINES The first known turbines were "water wheels" used by the ancient Greeks more than 2000 years ago. Turbines are currently used for a wide range of industrial applications, including hydroelectric, steam, gas, fuel oil and nuclear power generation; compression, pumping, propelling systems and high efficiency engines. Turbines were developed and trial tested for downhole drilling applications in the former Soviet Union (FSU) in 1934. By 1949 "Turbodrills" as they began to be called, were receiving wide-scale utilization in the FSU. They found limited success elsewhere until a successful application was achieved in Southern France in 1959. Most of the turbine runs during this period were made utilizing non sealed bearing two or three cone rock bits, in spite of the roller cone bits inherent limitations for bearing life and the turbines inability to support the required bit weight to obtain optimal penetration rates. With the development of diamond and PDC bits in the 1960's and 70's Turbine usage became increasingly popular in the US Gulf Coast, Africa, Asia, South America, parts of Europe, the North Sea and several Middle Eastern countries including Syria, Egypt, Bahrain, UAE and Qatar. Many of the newer applications utilizing natural diamond and TSP diamond bits either surface set or impregnated were in hard to very hard formations. The advent of PDC bits extended the range of Turbine drilling into softer formations. By nature of their cutting structure drag bits remove a comparatively small amount of rock per revolution compared to tricone bits. For a given weight on bit more revolutions per minute equates directly to more rock removed and faster ROP. The characteristics of the Turbodrill; high torque output and rotational speeds from 300-1100 rpm make possible substantially higher, and sometimes two-fold increases in penetration rates compared to those previously achieved with rotary drilling. However, in some areas Turbodrills were found advantageous in softer rock such as in Qatar, where Turbodrills were used exclusively to drill 17-1/2" surface hole sections from 1979 to 1995. These surface holes were previously plagued by sulfide stress cracking of the Drillstring causing numerous twist-offs when Drillstring rotational speeds exceeded 50 rpm adjacent to H2S laden formations. By drilling the surface holes with turbines, the surface rotary speed could be limited to about 40 rpm while downhole bit speeds exceeding 800 rpm were achieved. This resulted in fast surface hole drilling without the previously high incidence of twist-off.

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There was however, a high risk of bearing failure and cone loss from the nonsealed bearing bits being used. Accordingly, stipulations were set that on bottom rotating time with non-sealed bearing bits run on turbine not exceed 12 hours. Nonetheless, tangible drilling cost reductions were made for the surface hole sections using turbines. However, In 1995, they began using PDM's to drill the surface hole, since the PDM's served the function of limiting surface rotary speed and provided slower downhole bit speeds, in the 200 rpm range, which were more compatible with the sealed bearing motor bits which had become available. Steerable Turbodrills gained global application in the tangent sections of deviated and horizontal wells. Unfortunately, as more applications were found, the PDM emerged as a fierce competitor for vertical and directional applications as well. Turbodrills continued to hold a significant penetration rate advantage over PDM's do to the higher rotational speeds achievable, which frequently equated to an economic advantage when diamond or PDC bit drilling prevailed. A major disadvantage of the Turbodrill is the high surface pump pressures and flow rates required to operate them. Where as a 9-1/2" PDM develops a 500 psi pressure drop circulating 75 pcf water base mud at 500 gpm, a 9-1/2", three power section turbine develops a 1315 psi pressure drop. Typically two 1600 hp mud pumps in good mechanical working order are required for Turbodrilling. Moreover, downhole torque and bit speed can be monitored at the surface with PDM's, since with PDM's downhole torque is directly proportional to differential operating pressure and bit speed is proportional to flow rate. Conversely, in Turbines, the rotational speed of the drive shaft, is dependent not only on the flow rate of the drilling fluid but also on the formation, bit configuration and bit weight, i.e., the torque developed at the rock face. Since exact knowledge of formation characteristics and bit configuration effects cannot be discerned accurately, the exact rotational speed at which a turbodrill is operating at any given juncture is generally unknown, unless a surface readout tachometer is used. However, in circumstances where bit speeds from 300 to 1100 rpm are required to maximize penetration rates, the turbine remains the only field proven tool available.

1.1

Principles of Operation Turbodrills are "dynamic motors". They are driven by a continuous flow of fluid pumped through numerous rotor/stator stages. The hydraulic power of the fluid under pressure (kinetic energy of the water, drilling mud, oil, etc.,) which is flowing through the motor is converted into mechanical power (rotational motion) by the drive stages. For turbines to function properly the fluid must attack the "driving blades" (rotors) at precise angles, this is accomplished by the "distribution units" (stators). The flow leaving the rotor is parallel to the axis of the stators.

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Rotors and stators are "symmetrical"; they resemble an object and its mirror image. The rotor/stator pair has a "degree of reaction". Approximately 50% of the fluid flow leaving the rotor is parallel to the axis. Numerous rotor/stator stages are required to develop the needed downhole torque. For instance, a 9-1/2" T3 (three power section) turbine is composed of 276 individual rotor/stator stages. The Neyrfor 9-1/2" turbines contain 92 stages per power section. Turbines are completely modular in that one, two or three power sections can be made up on and run on a bearing/drive shaft assembly, dependent on the required torque output. The power section accounts for most of the turbines length. A single turbine drive stage is depicted in Fig 2K-1. Fig 2K-1 - Turbine Rotor/Stator Drive Stage

While drilling, a dynamic balance exists between the torque created by the pressure drop of the flow passing through the rotors and the resisting torque that opposes it. This balance is disturbed when one or more of the three parameters, flow rate, pressure or resisting torque, varies which results in a change in rotational speed. Turbine Operational Characteristics Rotating speed of the Rotor and in turn the drive shaft is directly proportional to the flow rate: S ≈ K1Q ............................................Eq. 2L-1 Where: S = Rotating speed of rotor, RPM ______________________________________________________________________________________

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K= Calculated constant for blade characteristics Q= Mud flow supplied to the Turbodrill The mechanical characteristics of each turbodrill are measured at the nominal flow rate and from it calculated for other flow values. In practice and for a given flow the actual speed depends on the torque developed at the rock face by the bit. The drive torque is proportional to the mud flow rate squared, the specific gravity and to the radius of the blading discs. T ≈ K2 R Q2 d .........................................Eq. 2L-2 Where: T = Torque delivered by the turbodrill R= Average radius of blading disc and d= mud specific gravity The drive torque of a complete turbodrill is directly proportional to the number of drive stages. In practice, and for a given flow rate, the drive torque varies from zero with the turbodrill and bit off bottom (Runaway speed) to a maximum value when the turbodrill stalls. Delivered Power The power delivered by the turbodrill is equal to the torque times the rotating speed. Therefore, the power of the turbodrill, P is proportional to the cube of the flow rate: P ≈ K3 R Q3 d .....................................Eq. 2L-3 For the nominal flow, the maximum delivered power is the nominal power. The corresponding torque and rotating speed are the nominal values. For a given flow rate the maximum power is obtained when rotating speed is one half of the runaway value. At this point the available torque is about half of the torque produced at the stalling point. The optimum turbodrilling conditions are close to this point and should generate maximum penetration rates.

Fig 2L-2 - Typical Characteristic curves for Neyrfor Turbodrills

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Efficiency The efficiency of the turbodrill is defined as, "mechanical power delivered by turbodrill divided by given hydraulic power to the turbodrill. Dependent on the type of blades used in a turbodrill, friction in the bearings, drillstring rpm, mud flow rate, wear on the bearings and mud rheological properties, actual turbodrill efficiencies usually range between 55 and 60%. Pressure drop The pressure drop through the turbine is proportional to the square of the mud discharge, to the density of the mud and to the number of drive stages. The actual rotating speed of the turbodrill has a negligible effect on pressure drop across the turbodrill. 1.1 Turbine Components All Conventional Turbodrills possess the following essential components:

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• • •

•

• •

One housing (with a top connection for coupling to the drill string). One shaft (with a bottom connection for coupling to the bit). A stack of turbine stages, the rotors are locked on the shaft, the stators on the body. A set of radial bearings guiding the rotor assembly inside the stator assembly. A set of double-acting axial thrust bearings. A lower bearing section to divert the fluid inside the bottom shaft and through the bit.

Contemporary Turbodrills are multi-sectioned with the motor section(s) connected directly above the bearing section, they are equipped with: • • • • • • •

A system of shaft couplings for rapid connection of Turbodrill elements. Stabilization with rig replaceable integrated spiraled blade stabilizers. The "steerable" Turbodrills have additional features: An articulated shaft either flexible (titanium) or fitted with universal joints. A bent housing (fixed or rig floor adjustable). A balance drum device to compensate for hydraulic thrust. Drive stages with a greater "coefficient of circulation", i.e., efficiency shifted toward lower speed.

A Neyrfor SBS Turbine is shown in Fig 2L-2. The SBS series have fixed bent housing settings from 1/2 to 1-1/4°. Build rates of up to 2.5°/100' are achievable in the 9-1/2" tool and up to 12°/100' in the 3-3/8" tool, with tolerable dog-leg severities of 5°/100' & 17°/100' respectively.

Figure 2L-2 SBS - Turbodrill with Fixed Bent Housing

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Figure 2L-3 - Turbodrill Balance Drum Assembly

Figure 2L-4 - Turbodrill Motor Section Construction

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Figure 2L-5 - Turbodrill Bearing Section Construction

Saudi Aramco Utilization Approximately 30 Neyrfor Turbine runs have been made in Saudi Arabia over the last three years. All of the runs have been with either two or three power section straight hole turbodrills. The turbines are completely modular, in that either one, two or three power sections can be run dependent on the available mud pump capability and downhole torque output requirement. Table 2L-1 reflects current Neyrfor Turbine usage for Saudi Aramco. ______________________________________________________________________________________

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Table 2L-1 - General Specifications for Neyrfor Turbodrills Used in Saudi Aramco TURBINE TYPE 9-1/2" T3

SECTIONS

(No.) 3

STAGES (No.) 276

HOLE SIZE, IN 12-16

FLOW (GPM) 525-750

SPEED (RPM) 550-800

9-1/2 T2

2

184

12-16

550-550

500-600

6-5/8" T2

2

172

400-445

800-1050

4-3/4 T2

2

199

7-5/89-7/8 5-5/89-7/8

170-195

1100-1300

WHERE USED ALL FIELDS HIGH MW

RUNS/YR

ALL FIELDS SLIM HOLE

4-5

4-5 1

1

Table 2L-2 Typical Bottom Hole Assemblies for Neyrfor Turbodrills 5-7/8" HOLE SECTION

8-3/8" HOLE SECTION

12" HOLE SECTION

BIT SAFTEY SUB TURBODRILL CIRCULATING SUB FLOAT (12) 4-3/4" DRILL COLLARS JARS (2) 4-3/4" DRILL COLLARS (6) HWDP (OPTIONAL)

BIT SAFETY SUB TURBODRILL CIRCULATING SUB CROSSOVER FLOAT (NEYRFOR) (12) 6-1/4" DRILL COLLARS JARS (2) 6-1/4" DRILL COLLARS CROSSOVER (9) HWDP

BIT SAFETY SUB TURBODRILL CIRCULATING SUB CROSSOVER FLOAT (9) 8-1/4" DRILL COLLARS JARS (2) 8-1/4" DRILL COLLARS CROSSOVER (9) HWDP

Fig 2L-6 - Operating Specs for 9-1/2" Neyrfor Turbodrill with three power sections

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Figure 2L-7 - SBS Turbine Length Vs. Two Power Section Straight Hole Turbine Length

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Figure 2L-8 - Steerable Turbodrill Operating Characteristics

1.2 Operating Guidelines Pre-run Considerations To avoid reaming when running in the hole, the rotary run just prior to the turbodrill run should be made with string stabilizers similar to those to be used with the turbodrill. A junk sub should be run in the string prior to running the turbodrill and diamond or PDC bit to prevent junk from damaging the diamond bit cutters.

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Proceed carefully when running into open hole, especially for the first turbodrill run. When reaming, the weight on the bit is low, providing less compensation of the hydraulic thrust through the turbodrill. A lower flow rate, (25-50% of normal) allowing adequate power to the bit but reduced hydraulic thrust, is therefore recommended while reaming to avoid premature thrust bearing wear. Stabilizers and the thrust bearing section should be inspected between turbodrill runs. They may need replacing before running back in hole. Make up of Turbodrill Sections The steerable turbodrills are composed of only one section which includes all the motor blading disks and thrust bearings. The straight hole turbodrills are composed of one bearing section and two or three motor sections. Turbodrills arrive on location in separate sections. They are made up on the rig floor under the supervision of a Turbodrilling Specialist who makes up the required stabilizers; usually one stabilizer per turbine section. The motor section stabilizers can be interchanged on the rig floor. The bearing section stabilizer is mounted in the service companies workshop. Wear Measurements Before every run, the turbodrill should be checked as follows: •

With the turbodrill hanging free above the rotary table, the measurement of the clearance Ch1 minus the clearance Ch0 taken prior to turbodrill run, gives the wear of bearings in the hydraulic thrust position. A specified length, based on turbodrill size and model, should not be exceeded. • With the turbodrill set onto the rotary table, under its own weight, the difference between the clearance Cm1 thus measured and the clearance Cm0 measured prior to the turbodrill run, gives the wear of bearings in the mechanical thrust position. Since typically, the turbodrill is running in the hydraulic thrust position, the wear is noticeable as shown in Fig 2L-9. Figure 2L-9 - Thrust Bearing Check Measurements for Neyrfor Turbodrills

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By-passing the Turbodrill In order to be able to circulate LCM or cement slurry without plugging the turbodrill, a circulating sub above the motor section can be run. However, very fine LCM mixed in the mud can be pumped through the turbodrill, if the concentration is not too high. A Neyrfor circulating sub is shown in Fig - 2L-10. Figure – 2L-10 - Neyrfor Circulating Sub

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Use of Drill Pipe Screen To avoid any plugging of the turbodrill by large particles or junk in the mud, a drillpipe screen is placed in the box connection of the first joint below the kelly. At each connection, the screen is replaced at this position. Normally drillpipe filters are provided by the turbine service company to suit the type of pipe in current use. The center of the screen can be removed with a small wire line overshot; to allow the running of a free point indicator or other wireline tools if required. Figure 2L-11 - Neyrfor Drillpipe Screen

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Mud Properties - Mass Flow The mud flow through the turbine blades is turbulent. Thus, for water based muds it may be assumed in practice that the flow through the turbodrill and bit is independent of viscosity. The plastic viscosity of oil based drilling fluids is considerably higher and experimental pressure drops show an increase of about 15%. It is difficult to express the increase in exact physical terms owing to the complexity of the flow. Number of Drive Stages Power and drive torque are directly proportional to the number of drive stages. Turbodrills should be sized based on the existing mud pump and surface circulating equipment capabilities and projected bit and circulating system pressure losses. Rotational Speed The blades of the turbine are designed so that the velocity triangle is optimal, i.e.; the nominal flow rate corresponds to a nominal speed of rotation at which the power is maximum - nominal power. In practice, the nominal speed is usually only reached for a given value of the reactive torque exerted by the formation on the bit. In other words, the speed of rotation depends not only upon the mass flow of the mud but also on: ¾ ¾ ¾

The formation The bit configuration The weight on bit

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As factors (a) and (b) cannot be controlled, the exact speed at which a turbodrill is drilling if often unknown unless a surface reading tachometer is used. During circulation, the formation and bit don't provide any resisting torque and the turbodrill speeds up to its runaway speed, (i.e., the speed at which power and effective drive torque are zero). Runaway speeds lie between 1000 and 2000 rpm depending on the model of turbodrill. During drilling, an increase in the weight on bit causes the turbodrill to stall, the power to drop back to zero, and the effective torque to rise to its maximum value. The highest penetration rates are usually obtained at speeds between 400-1000 rpm corresponding to maximum turbodrill power. Mud Pressure The pressure drop corresponding to the energy driving the turbine is proportional to the square of the mud flow rate, to the density of the mud and to the number of drive stages. Projected pressure drops for several water and oil base drilling fluid weights are given on the respective Neyrfor data sheets. Drilling Fluids Rotary drilling fluids may be used with turbodrills provided: ¾ The fluid consists of neither lost circulation materials or undesirable plugging materials. ¾ Sand content as measured with a standard centrifuge is less than 1%. ¾ Drillstring filters are used. Most drilling fluids are suitable for turbodrilling including, water base, polymer, oil base and emulsion muds. Crude aromatic series petroleum tends to attack synthetic rubber in the thrust bearing section more than other fluids. However the newer Neyrfor turbines are an all-metal design and consequently not adversely affected by aromatics. Bit Weight The rotational speed of the turbodrill diminishes as the weight on bit increases. As weight on bit increases to a certain point, the turbine will eventually stall. However, permissible WOB increases with the hydraulic power available. The drill collars used to apply weight to the bit are generally the same as those used in rotary drilling. However, the greater rotational speed of turbodrill bits enables a smaller weight to be applied even though penetration rates are higher.

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As a result fewer drill collars are required with turbodrills than for rotary drilling or drilling with PDM's. Drillstring Rotation The drillstring is rotated by the rotary table or top drive to eliminate axial drag between the drillstring and the hole wall. This allows the required drill collar weight to be transmitted to the bit. Rotation of the drillstring, which prevents sudden variations in torque from being applied to the rotary table or top drive, is indispensable whenever the turbodrill is stabilized. Stabilization Turbodrills may be equipped with stabilizers for both vertical and deviated drilling. Jars It is advisable to place a jar in the drillstring for holes in which sticking tends to be a problem. Bit Pressure Drop When drilling with a turbine, the minimum bit pressure drops in terms of HSI for the specific bit and formation type are usually used. An increase in bit pressure drop lowers the power input to the turbodrill for a given surface pressure and also causes an increase in the quantity of fluid passing through the turbodrills lower bearing section, thus increasing the volume of mud passing across the face of the bit. In hard formations, the pressure drop should normally be as low as possible. In soft rock, (e.g., marl and clay) it should be high enough to permit satisfactory removal of cuttings. Figure 2K-12 - Recommended Rig make-up Torque for Neyrfor Turbodrills

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2.0 LOW-SPEED HIGH TORQUE TURBINES To meet the increasingly stringent demands of current directional, horizontal and performance drilling applications, Tiebo-Tiefborservice, a German directional drilling company in conjunction with the Russian VNIIBT Perm institute jointly developed a Low-Speed High-Torque Turbodrill. A gear reduction section located immediatly below the power section of the turbine, is incorporated to decrease shaft rotational speed and increase the torque output. The contention being that these features will optimize drilling performance in numerous applications for diamond and PDC bits. A series of 9-1/2" Low-Speed, High-Torque, Gear Reduction Turbines (LSHT) runs were made with PDC bits in 12" intermediate and production hole sections to appraise the LSHT's applicability in Saudi Aramco's Khuff drilling program. Outstanding penetration rates and minimal footage cost had previously been achieved with conventinal turbodrills and PDC bits, albeit with a high probability of bit sticking. The bit sticking phenomena is envisaged related to the high downhole ______________________________________________________________________________________

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rotational speeds, up to 1100 rpm, with which conventional turbodrills operate. The problem has been partially alleviated by running a safety sub immediately above the bit and utilizing more wear resistant stabilizers on the turbine housing to avoid drilling a spiral hole. The gear reduction section of the 9-1/2" Tiebo Turbine has a gear ratio of 3.05 to 1 which reduces the output shaft's speed while increasing its torque. The reduced bit speed delivered by the LHST turbodrill and its greater available torque has greatly reduced the occurrence of bit stall-out and bit sticking in the runs made. The observed operating characteristics of the LSHT Turbine indicate it is competitive with conventional positive displacement motors. The LSHT turbines were typically operated at 200-250 rpm and delivered 4000 ft-lb of torque. It was hoped that they would offer more reliable operation at the elevated downhole temperatures encountered in deep Khuff wells than conventional turbodrills and PDM's. A recurring twist-off/in hole failure problem in the LSHT turbodrill housing near the top of the gear reduction section has temporarily interrupted their use. The interrelationships between bit torque, flow rate, power output, penetration rate, bit weight, bit speed, pump pressure and bit hydraulics are similar to those of conventional turbines. Although Tiebo provides conventional two and three power section Turbodrills and Gear reduction turbines in several sizes. Saudi Aramco's test trial was limited to the 9-1/2" 1TR-240, a one-power section LSHT turbodrill as shown in Fig 2L-13. The LSHT Turbodrill consists of three main sections, which are the Power Section, Gear Reduction Section and Bearing Section. From the power section the energy is transferred through the gear reduction section to the drive shaft. Figure 2L-13 - Tiebo Low-Speed High Torque Turbine

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Both the bearing and gear reduction sections operate in a sealed, pressure compensated oil bath. The gear reduction section is equipped with thrust bearings to absorb the hydraulic loading from the power section. Figure 2K-14 - Tiebo LSHT Upper Turbine Section Assembly

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Figure 2K-15 - Available Tiebo Turbine Blade Types

i. S: increasing pressure-losses with increasing torque ii. B: decreasing pressure-losses with increasing torque iii.P: blade form like type B with a special flange at the exit of flow pressing stages against each other, so that fluid losses decrease, decreasing pressure-losses with increasing torque. Figure 2K-17 - Performance Curves for Tiebo "1 TR-240-S" LSHT Turbine

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Figure 2K-18 - Tiebo "1 TR-240S" Performance Data at various Mud Weights

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PERFORMANCE DRILLING SYSTEMS OPTIMIZATION

1.0 TURBINE SELECTION AND OPTIMIZATON 1.1

Turbine Selection - Analysis of Existing Circulating System

1.2 Optimization of Selected Turbine Performance 2.0 POSITIVE DISPLACEMENT MOTOR SELECTION AND OPTIMIZATION 3.0 PERFORMANCE DRILL BIT AVAILABILITY AND ANALYSIS 3.1 3.2 3.3

4.0

Performance Drill Bit Availability Breakeven Analysis Expected Value Cost Analysis

PERFORMANCE DRILLING SYSTEMS OPTIMIZATION 4.1

Development of Minimum Cost Drilling Plan

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PERFORMANCE DRILLING SYSTEMS OPTIMIZATION 1.0

TURBINE SELECTION AND OPTIMIZATION The purpose of this section is to provide methodology for the analysis, selection and optimization of Performance Drilling Systems. Those systems include; Turbine and PDC, PDM & PDC, PDM & TCI, Rotary & PDC and Rotary & TCI. 1.1

Turbine Selection - Analysis of Existing Circulating System A thorough analysis of the existing rig pump capability, circulating system and expected downhole pressure losses should be made prior to selecting a turbine to be run. The results of the analysis may show that a turbine run is unfeasible, due to the lack of available pump power. If sufficient rig pump power is available then the turbine can be sized, selected and the flow rate and bit nozzle configuration modified to optimize performance. The final consideration is then the economics in terms of overall cost per foot as compared to the other available drilling systems. The first step in selecting a Turbine is to analyze the existing circulating system excluding the turbine as follows: 1. Compute the component pressure losses at several flow rates, such as 100, 200, 300, 400, 500 and 600 gpm. Add the component losses to determine the total standpipe pressure for each rate. 2. Plot the standpipe pressure vs. flow rate. Mark a horizontal line at the maximum recommended standpipe pressure. 3. Determine the remaining available standpipe pressure that could be used to power the turbine at each flow rate. 4. Compute the available hydraulic horsepower at each flow rate, and plot on the same graph, available power is equal to available pressure times gallons per minute divided by 1714. 5. Locate the maximum available power on the curve, and note the flow rate at which it occurs. This is the flow rate at which the Turbine should be sized. The corresponding available pressure is the pressure drop for which the turbine should be sized. It may not agree with the flow rate and pressure at which a turbine is designed to operate, in which case the turbine is unsuitable for the system and a different turbine, PDM or rotary run must be considered.

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6. From the graph of Power vs. Flow rate, define the optimal flow rate. This is the flow rate at which the most hydraulic horsepower is delivered to a downhole motor or turbine for conversion to mechanical horsepower in its drive shaft. Example Problem 2M-1 - Size and optimize performance for a Turbodrill, to drill an open hole section from 10,500 to 12,500' with a 12" PDC bit based on the following pertinent data: Drillpipe: 5" 19.5 ppf Grade E Heviwate: 450' of 5" OD x 3" ID Upper Drill Collar Section: 180' of 8.5" OD x 2.81" ID Lower Drill Collar Section: 120' of 9.5" OD x 3.00" ID Mud Weight: 95 pcf; PV: 22 YP:28 lbf/100 sq.ft. Bit TFA=0.90 in. Surface equipment case #3; equiv. to 816' of 5" Drill Pipe Mud Pumps: Two Gardner-Denver PZ-11's with 7" liners. Maximum Pressure is 3458 psi @ 130 spm & 5.5 gal/stk. Assume mud pump efficiency of 95% equal to 5.23 gal/stk & Maximum Pump Pressure of 3400 psi. If the available 6-1/2" liners were used the pump would be rated to 4006 psi @ 130 spm & 4.7 gal/stk; and 4702 psi with 6" liners @ 130 spm & 4.0 gal/stk. System Pressure Loss Calculations Acceptable accuracy can be obtained in this case by assuming turbulent flow down the drill-bore and laminar flow up the annulus at the near optimum circulation rates. This allows system pressure losses to be calculated quickly in a straightforward manner with hand/calculator calculations as follows: Drillbore Assume turbulent flow through the drillpipe, heviwate and drill collars. From the Drilling Practices Manual the equation for turbulent flow in the drillstring is given: Pt = 7.7(10-5) ρ0.8 Q1.8 PV0.2 lf ................................................Eq. 2M-1 Di4.8 Where: Pt = Pressure Loss inside pipe, psi ρ = Mud density, lb/gal (divide pcf by 7.48 to get lb/gal) Q = Circulation rate, gpm PV= Plastic viscosity, cp lf = Length of pipe, ft Di = Inside diameter of pipe, in For 12,235' of 5" drillpipe, (4.23 in. ID) we have the following: ______________________________________________________________________________________

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Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 12,235 = 4.234.8

53,166.35 = 52.39 psi 1,014.92

For 465' of 5" OD x 3" ID Heviwate Drillpipe: Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 450 = 34.8

1955.44 = 10.02 psi 195.07

For 180' of 8" OD x 2.81" ID Drill Collars: Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 180 = 2.814.8

728.18 = 5.11 psi 142.49

For 120' of 9.5" OD x 3" ID Drill Collars: Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 120 = 521.46 = 2.67 psi 3.04.8 195.07 Total Drillbore Pressure Losses are calculated: Pressure Loss in Drillpipe............................53.39 psi Pressure Loss in Heviwate DP....................10.02 psi. Pressure Loss in Upper DC Section .............5.11 psi. Pressure Loss in Lower DC Section .............2.67 psi. Total Drill Bore Pressure Losses:............71.19 psi Surface Equipment Since the surface equipment case is #3, the surface losses are equivalent to those produced by 816' of 5" OD x 4.23" ID drillpipe: Pt = 7.7(10-5) (95/7.48)0.8 1001.8 220.2 816 = 4.234.8

3545.87 = 3.49 psi 1014.92

Laminar Flow is assumed in the annulus, and due to the wellbore geometry, divided into 5 sections. From the Drilling Practices Manual, the power law fluid pressure loss equation for laminar annulus flow is: Pla =

2n + 1 2.4v Dh-Dop 3n

N

Klf 300(Dh-Dop) ........................Eq. 2M-2

Where: ______________________________________________________________________________________

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Pla = Pressure Loss in Laminar flow, psi. v = average annular velocity, ft/sec Dh= Diameter of hole or casing, in. Do= Drill String OD, in. lf = length of annulus under consideration Mud Rheological Properties need only be calculated once: θ300 = PV + YP = 22 + 28 = 50

θ600 = θ300 + PV = 50 + 22 = 72

n = 3.32 log θ300/θ600 = 3.32 log (50/72) = 0.526 K = θ300/(511n) = 50/(5110.526)= 1.88

Where: n = slope of the viscometer data on log paper K= intercept of viscometer data on log paper θ= viscometer reading, lbf/100 sq. ft Section # 1: Drillpipe inside cased hole. For the 10,500' section of 5" drillpipe inside 13-3/8" casing. Annular velocity should be calculated for each hole section: v = 24.5 Q/(Dh2-Dop2) = 24.5(100)/(12.3472-52)= 19.22 fps Pla =

2.4(19.22) 12.347-5

2(0.526) + 1 3(0.526)

0.526

1.88 (10,500) 300 (12.347-5)

= 3.0177 x 8.956 = 27.03 psi Section # 2; (1735'):

Drillpipe in the 12" open hole section from 10,500 to 12,235'

v = 24.5 Q/(Dh2-Dop2) = 24.5(100)/(12 2-52)= 20.59 fps Pla =

2.4(20.59) 12-5

2(0.526) + 1 3(0.526)

0.526

1.88 (1735) 300 (12-5)

= (3.2096 x 1.55) 0.526 = 4.97 psi

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Section # 3: For the 450' section of 5" OD x 3" ID Heviwate DP in the 12" open hole section from 12,235 to 12,685': v = 24.5 Q/(Dh2-Dop2) = 24.5(100)/(12 2-52)= 20.59 fps Pla =

2.4(20.59) 12-5

2(0.526) + 1 3(0.526)

0.526

1.88 (450) 300 (12-5)

= (3.2096 x 0.4086) = 1.29 psi Section # 4: 180' section of 8.5" OD x 2.81" ID Drill Collars in the 12" open hole section from 12,685 to 12,865': v = 24.5Q/(Dh2-Dop2) = 24.5(100)/(12 2-8.52)= 34.15 fps Pla =

2.4(34.15) 12-8.5

2(0.526) + 1 3(0.526)

0.526

1.88 (180) 300 (12-8.5)

= (6.03 x 0.3229) = 1.94 psi Section # 5: 120' section of 9.5" OD x 3.00" ID Drill Collars in the 12" open hole section from 12,865 to 12985': v = 24.5Q/(Dh2-Dop2) = 24.5(100)/(12 2-9.52)= 45.58 fps Pla =

2.4(45.58) 12-9.5

2(0.526) + 1 3(0.526)

0.526

1.88 (120) 300 (12-9.5)

= (8.3778 x 0.3008) = 2.52 psi Total Annular Pressure drop = 27.03 + 4.97 +1.29 +1.94 + 2.52 = 37.75 psi Bit Nozzle Pressure Losses From the Applied Drilling Engineering textbook, pressure losses through the bit nozzles may be calculated as follows: Pb =

8.311 x 10-5ρ Q2 Cd2 At2

...........................................................Eq. 2M-3 Where: Pb = pressure loss through bit nozzles, psi Cd = nozzle discharge coefficient, (0.95 for conventional nozzles) ρ = mud density, ppg Q = circulation rate, gpm ______________________________________________________________________________________

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Pb =

0.00008311 (95/7.48) 1002 (0.95)2 (0.9)2

= 14.44 psi

Total System Pressure Losses (excluding Turbine) are summed as follows: Surface Pressure Losses................................. 3.49 psi Drillbore Pressure Losses................................ 71.19 psi Bit Nozzle Pressure Losses............................ 14.44 psi Annulus Pressure Losses................................. 37.75 psi Total System Pressure Losses Without Turbine=127 psi Available pressure for the Turbine is calculated: Available Pressure = Maximum Standpipe pressure - System Pressure Loss = 3400 psi - 127 psi = 3273 psi. Available Pump Horsepower = (Available Pressure x Flow Rate)/1714 = (3273 x 100)/1714 = 191 Hhp. The calculations are repeated for 200, 300, 400, 500, and 600 gpm, resulting in the following tabulated data: Table 2M-1 - Available Pressure and Horsepower for a Turbine Circulating System Component

Surface Drillbore Bit Annulus Total Standpipe Available Pressure for Turb. Available Hhp for Turbine

Pressure Loss @100 gpm

Pressure Loss @ 200 gpm

Pressure Loss @ 300 gpm

Pressure Loss @ 400 gpm

Pressure Loss @ 500 gpm

Pressure Loss @ 600 gpm

3 71 14 38 126

12 246 57 54 370

25 510 129 67 732

42 856 229 78 1206

63 1279 358 88 1789

88 1775 516 97 2476

3274

3030

2668

2194

1611

924

191

354

467

512

470

323

The analysis indicates the optimum flow rate for the system is 400 gpm at which the maximum available power (512 Hhp) would be available for the turbine with available pressure drop of 2194 psi. A plot of the data is shown in Fig 2M-1.

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Figure 2M-1 - Plot of Available Power Vs. Flow Rate

Available Power, Hhp

Available Power Vs. Flow Rate 600 500

467

400

512

470

354

323

300 200

191

100

54

0

0

0

100 200 300 400 500 600 700 800 Flow Rate, gpm

Operating requirements for Neyrfor and Tiebo Turbines are listed in Table 2M-2 for 9-1/2 to 9-5/8" tools capable of drilling 12" hole. Table 2M-2 - Available Turbines for Example Problem 2M-1. Turbine Model 9-1/2" SBS w/one power section 9-1/2" FBS w/one power sect. 9-1/2" T2 w/two power sections 9-1/2" T3 w/three power sect. Tiebo 1TR240-S, one power sect.

Required flow Rate, gpm 450-725

Turbodrill Pressure Drop, psi 976-2204

Shaft Speed, RPM 300-800

Nominal Power Output, Hp 269

Nominal Torque, ftlb 3676

500-700

2048-3019

600-1200

512

5000

500-650

1175-1980

520-900

379

7960

500-800

1700-2450

520-800

568

9370

476-793

653-1813

272-453

216

3250

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Of the available turbines, all require a flow rate greater than the optimal flow rate of 400 gpm for the system. Since the Gardner Denver PZ-11 mud pumps can handle up to 4702 psi with 6" liners, run the calculations again with a maximum stand pipe pressure of 4000 psi and see if a higher circulation rate can be obtained which produces peak Hhp. At 4000-psi standpipe pressure the optimum flow rate is 450 gpm which produces 661 Hhp and leaves 2516 psi available for the pressure drop across the turbine. With two mud pumps, a circulation rate of 1040 gpm is achievable, which well exceeds our requirement. Typically only 55 to 60% of the hydraulic energy of the mud flow is converted to mechanical energy in the turbine. For this case the Mechanical energy produced in the turbine from the mud flow is; 661 Hhp x 0.55 = 364 Hp. A flow rate of 450 gpm meets the minimum requirements for the one stage 91/2" Neyrfor SBS Turbine with one power section utilizing mixed blades. The circulating system is capable of generating 364 Hp in the turbine, which exceeds the SBS Turbine's Nominal horsepower output of 279 Hp. Note that this is the only available turbine in which the flow rate, available pressure drop and nominal horsepower requirements are met by the existing circulating system. Accordingly, it is selected. 1.2 Optimizing Performance of Selected Turbine Although the rest of the circulating system will tolerate a higher pressure drop across the bit, which would be effected by smaller jets, the turbine specifications limit the pressure drop across the bit to a maximum of 450 psi. The nozzle total flow area (TFA) which generates a 450 psi pressure drop can be calculated after the flow rate for the selected turbine is optimized. At the optimum system circulating rate of 450 gpm the following pressure losses are effected: Surface.....................................................................52 psi Drillbore pressure losses......................................1058 psi Bit Nozzle Pressure Loss..................................... 450 psi Annulus................................................................ 83 psi Total System Pressure loss excluding Turbine = 1643 psi

This leaves (4000-1643)= 2357 psi; to operate the turbine when only 976 psi is required. Review of the governing Turbine performance equations shows

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that rotational speed is directly proportional to flow rate, torque is proportional to flow rate squared and power is proportional to flow rate cubed. S ≈ K1Q ....................................................................Eq. 2M-4

T ≈ K2 R Q2 d ............................................................Eq. 2M-5

P ≈ K3 R Q3 d ............................................................Eq. 2M-6

Where: S = Rotating speed of rotor K= Calculated constant for blade characteristics Q= Mud flow supplied to the turbodrill T = Torque delivered by the turbodrill R= Average radius of blading disc d= Mud specific gravity P = Power delivered by the turbodrill Note that in all cases increasing flow rate serves to increase turbine parameters of performance. With the selected turbine, flow rate will be maximized within the constraints of maximum standpipe pressure and parasitic pressure losses in the existing circulating system. The Optimum flow rate for the existing system can be obtained by plotting the required pressure drop across the turbine and the pressure available for the turbine Vs. flow rate. The intersection of the two curves denotes the optimum flow rate for the system. Pressure drops across the turbine are taken directly from the specification sheet for the 9-1/2" SBS Turbine with mixed blades shown in Figure 2M-4. The System pressure losses used to calculate the available pressure loss for the turbine assume a bit pressure loss of 450 psi. The tabulated data and resulting plot are shown in Table 2M-3 and Fig 2M-2. Table 2M-3 - Tabulated Pressure Loss Data for Example Problem 2M-1 Flow Rate gpm 450 500 550 600 650 700

Surf, DB & Ann PL, psi 1193 1430 1686 1960 2254 2564

Bit Nozzle PL, psi 450 450 450 450 450 450

System PL exclud. Turbine 1643 1880 2136 2410 2704 3014

Maximum Standpipe Press, psi 4000 4000 4000 4000 4000 4000

Available Press for Turb. psi 2357 2120 1864 1590 1296 986

Required Turbine Press.,psi 976 1167 1373 1593 1827 2075

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Figure 2M-2 - Cross-plot of Required and Available Pressure Vs. Flow rate to Obtain Optimum flow rate for Turbine Run

Required and Available Pressure Vs. Flow rate for a Turbine

Pressure, psi

2900 2400 Available Pressure for Turbine

1900

Required Turbine Pressure

1400 900 400 400

500

600

700

Flow Rate, gpm

Intersection of curves denotes optimum Flow Rate of 600 gpm

With the planned (optimum) flow rate of 600 gpm known, the bit nozzles can now be sized to effect a 450 psi pressure drop at the bit using the following equation from the Applied Drilling Engineering Textbook. At =

8.311 x 10-5ρ Q2 Cd2 Pb

0.5

............................................................Eq. 2M-7

where: At = Total nozzle flow area, sq. in. Q= Flow rate, gpm Cd= Nozzle discharge factor Pb= Bit pressure drop, psi ρ = Mud density, ppg At =

.00008311 (95/7.48) 6002 0.952 450

0.5

= 0.9673 sq. in.

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The 12" PDC bit utilizes six nozzles, so from the Nozzle Selection Chart in Fig. 2M-5, the closest TFA is 1.035 sq. in. for (six)15/32" nozzles. A slightly larger, as opposed to slightly smaller TFA was selected to avoid exceeding the maximum allowed bit pressure drop of 450 psi for the turbine. With the slightly larger TFA the pressure drop at the bit is recalculated: Pb =

0.00008311 (95/7.48) 6002 (0.95)2 (1.035)

= 407 psi

The HSI is checked to assure the minimum value of 1.0 Hhp/sq. in. is achieved. Bit Hhp = (Pb Q)/1714 Bit HSI = Bit Hhp/(Bit diameter2 ∏/4) Bit Hhp = (407 x 600)/1714 = 142.47 Hhp Bit HSI = 142.47/(144 x 0.7854) = 1.26 Hhp/in2 This value is acceptable, being slightly higher than the required 1.0 Hhp/in2. Most importantly, it is the best achievable with the given constraints on bit pressure drop. As a final check, system pressure losses are summed to arrive at the final circulating pressure at the end of the planned section; 12,500': Surface..............................................................88 psi Drillbore pressure losses...............................1775 psi Bit................................................................... 407 psi Turbine......................................................... 1593 psi Annulus......................................................... 97 psi Total System Pressure/Standpipe Pressure = 3960 psi The Hydraulic horsepower developed by the circulating system is: Hhp = 1593 x 600/1714 = 558 Hhp Mechanical Horsepower developed by the Turbine = 558 x 0.55 = 307 Hp Accordingly the 9-1/2" SBS, (one power section) turbine with mixed blades is run at 600 gpm with (6) 15/32" jets. Expected pump pressure is + 3960 psi. The calculation procedure for optimizing flow rate is readily adaptable to Excel spreadsheets as shown in Figure 2M-3. ______________________________________________________________________________________

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Figure 2M-3 – Spreadsheet for Turbine Flow rate Optimization

Fig 2M-4 - Neyrfor Specification Sheet for 9-1/2” SBS with mixed blades Figure 2M-4 - Specification Sheet for Neyrfor 9-1/2" T-2 Turbine with mixed blades ______________________________________________________________________________________

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Table 2M-5 - Nozzle Selection Chart, TFA's are in sq. inches.

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Size (inches) 7/32 8/32 9/32 10/32 11/32 12/32 13/32 14/32 15/32 16/32 18/32 20/32 22/32 24/32

1 Jet 0.038 0.049 0.062 0.077 0.093 0.110 0.130 0.150 0.173 0.196 0.249 0.307 0.371 0.442

2 Jets 0.075 0.098 0.124 0.153 0.186 0.221 0.259 0.301 0.345 0.393 0.497 0.614 0.742 0.884

3 Jets 0.113 0.147 0.186 0.230 0.278 0.331 0.389 0.451 0.518 0.589 0.746 0.920 1.114 1.325

4 Jets 0.150 0.196 0.249 0.307 0.371 0.442 0.518 0.601 0.690 0.785 0.994 1.227 1.485 1.767

5 Jets 0.188 0.245 0.311 0.383 0.464 0.552 0.648 0.752 0.863 0.982 1.243 1.534 1.856 2.209

6 Jets 0.225 0.295 0.373 0.460 0.557 0.663 0.778 0.902 1.035 1.178 1.491 1.841 2.227 2.651

7 Jets 0.263 0.344 0.435 0.537 0.650 0.773 0.907 1.052 1.208 1.374 1.740 2.148 2.599 3.093

8 Jets 0.301 0.393 0.497 0.614 0.742 0.884 1.037 1.203 1.381 1.571 1.988 2.454 2.970 3.534

9 Jets 0.338 0.442 0.559 0.690 0.835 0.994 1.167 1.353 1.553 1.767 2.237 2.761 3.341 3.976

10 Jets 0.376 0.491 0.621 0.767 0.928 1.104 1.296 1.503 1.726 1.963 2.485 3.068 3.712 4.418

Figure 2M-5 - Ring out possibly caused by inadequate hydraulics and high rotational speed on a 9-1/2” Turbine run in 12” hole (left). Right, outside cutter wear due to high rotational speed and inadequate hydraulics to cool the outside cutters on the 17” PDC run on a PDM.

Once Turbine performance has been established in a homogeneous formation under a given set of operating conditions, new parameters can be estimated for a new set of operating conditions as shown in Example Problem 2M-2.

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Example Problem 2M-2: Estimate the change in Turbine operating parameters effected by simultaneously increasing mud weight from 75 to 100 pcf and decreasing flow rate from 634 to 528 gpm.

2.0

POSITIVE DISPLACEMENT MOTOR SELECTION AND OPTIMIZATION

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Since Positive Displacement Motor pressure drops are typically only a fraction of those developed by turbodrills, their selection and optimization of operating parameters is by comparison significantly less complicated. PDM's require more bit weight to drill effectively than do turbine assemblies due to their slower rotational speeds. The wide range of rotor/stator lobe configurations, standard, extended and tandem power sections and resulting range of rotational speed and torque ratings does however, render their selection rather challenging. Hydraulics calculations can generally be performed for PDM's by bit supplier hydraulics programs. This is usually accomplished by adding the PDM and if present MWD pressure losses to the drill-bore pressure losses. The system is then optimized for Hydraulic Horsepower (65% system pressure losses at the bit) or Impact force (48% of system pressure losses at the bit) in conventional fashion as described in Chapter 2-I. However, with a motor in the hole these values are rarely achieved. Most motors have a bit pressure drop restriction of from 1000-1200 psi, which precludes conventional hydraulics optimization with standpipe pressures above 2500 psi. Typically, 10-40% system pressure losses at the bit are achievable and run with good results on PDM drilling assemblies. In many cases hydraulics are planned to achieve a minimum HSI, generally 2.5 Hhp/sq.in. of bit diameter for Tri-Cone bits and an HSI of 1.0 Hhp/sq. in. or greater for PDC bits. It is also important to maintain as high a flow rate as possible when drilling with a motor in order to cool the TCI and PDC cutters, to avoid heat checking and premature failure. Major considerations in PDM selection are: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Rotational Speed at which PDM will operate Pressure Drop across Motor Hydraulics which can be generated at the rock face with the motor in the hole Time that the PDM can stay in the hole without a high probability of failure Directional capability Torque and power output of the motor Economics of running a motor as opposed to turbine or rotary Type of Bit to be run Downhole Temperature Effect on motor elastomers Drilling fluid type, weight and additives

In lieu of the preceding considerations, the data from example problem 2M-1 will be used to select and optimize performance for a Positive Displacement Motor.

Example Problem 2M-3 Select and optimize performance for a Positive Displacement Motor from Table 2K-1, to drill an open hole section from 10,500 to 12,500' with a 12" Matrix body PDC bit, based on the following pertinent data: ______________________________________________________________________________________

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Drillpipe: 5" 19.5 ppf Grade E Heviwate: 450' of 5" OD x 3" ID Drill Collar Section: 360' of 8.5" OD x 2.81" ID Mud Weight: 95 pcf; PV: 22 YP:28 lbf/100 sq.ft. Bit Type: 12" M-432 PDC with 6 nozzles Surface equipment case #3; equiv. to 816' of 5" Drill Pipe Required Downhole Rotational Speed: 250 rpm Required HSI: 1.0 Hhp/sq. in. Required Operating Torque: 4000 ft-lb Required Weight on Bit: 15-35,000 lb Mud Pumps: Two Gardner-Denver PZ-11's with 6" liners rated to 4702 psi with 6" liners @ 130 spm & 4.0 gal/stk. Bit Weight requirement: The BHA is checked to see if its weight is adequate to supply the needed weight when buoyancy and a 20% safety factor are applied. Air Weight of 8.5" drill collars = 360 x 172 ppf = 61,920 lb Buoyancy Factor, Bf = 1-(MW/65.44) Where MW = Mud Weight, lb/gal 65.44 = Weight of 1 gallon of steel Bf = 1- (95/7.48)/65.44=0.806 Available bit weight, Abw is calculated; Abw = (Cw x Bf x 1-SF) Where Cw=Calculated Air Weight of Drill Collars, lb. SF=Safety Factor, fraction Abw= (61,920 x 0.806 x 0.8) = 39,926 lb., which is a little more than required but nonetheless acceptable to avoid breaking a 90' stand. Minimum required flow rate to adequately cool the cutters for a PDC bit, Qpdc can be estimated as follows from Lapeyrouse; Qpdc = 13 x Db1.5 ......................................................................................Eq. 2M-8 Where Db = Bit diameter in inches Qpdc = 13 x 121.5 = 540 gpm

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Assume a minimum flow rate of 550 gpm. Select a motor that will develop 200 rpm and generate the needed torque, 4000 ft-lb. The latter assumes the surface rotary will be turned at 50 rpm. Both 8" and 9-5/8" motors are available but none of the 8" motors develop the required torque at the estimated 400 psi motor differential pressure. The only PDM available which can meet all requirements is the 9-5/8" SS-962XP, which has a 3/4 lobe configuration with extended power section, as shown in Fig 2K-14. However this PDM requires a flow rate of at least 600 gpm. Estimated shaft speed for the PDM operated at 600 gpm = 600 gpm x 0.22 rev/gal = 132 rpm. At this circulation rate the motor should develop about 4250 ft-lb of torque. To achieve the desired 200 rpm the circulation rate would have to be increased to 200/.22= 909 gpm. This is too high, so plan to circulate at 700 gpm and make up the difference with surface rotary. At 700 gpm; shaft speed = 700 x 0.22 = 154 rpm. Required Surface RPM= Required Bit Speed-PDM Speed = 250-154 = 96 rpm. At a flow rate of 700 gpm the Selected PDM should produce 154 rpm, 120 Hp and 4250 ft-lb of torque. The hydraulics program should be run to ensure the system is functional and the planned HSI of 1.0 Hhp/sq. in. is achievable. The Reed Hydraulics program is run with a forced flow rate of 700 gpm. By trial and error through manipulation of the maximum allowable pump pressure an acceptable solution is achieved. By increasing the allowable pump pressure to 3630 psi an HSI of 1.076 Hhp/sq. in. achieved with a flow rate of 700 gpm and TFA of 1.387 inches, as shown in Fig 2M-7. The Reed Hydraulics program makes calculations for the end of the bit run which in this case was 12,500'. In practice, the flow rate for this problem would have been limited to about 650 gpm. The key to success in performance drilling is to avoid letting any one parameter, HSI, Flow Rate, Torque etc., control the system and cause it to fail due to minimization of similarly important parameters. Moderation and flexibility are central to the functionality of most performance drilling systems.

Figure 2M-7 - Reed Hydraulics Program Output for Example Problem 2M-3

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2M-3

3.0

PERFORMANCE DRILL BIT AVAILABILITY AND SELECTION

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A wide variety of approved performance drill bits are currently available at Saudi Aramco, as a result of successful implementation of the Test Trial and approval system. The purpose of this section is to show what performance bits are available and provide tools to aid in their selection. 3.1

Performance Drill Bit Availability

Table 2M-5 list all of Saudi Aramco's currently approved performance drill bits. Table 2M-5 - Saudi Aramco Approved, PDC and Diamond Drill Bits

SUPPLIER

SIZE

TYPE

IADC CODE

REMARKS

Hughes Hughes Hughes Hughes Hughes Hughes Security Security Security Security Hughes Hughes Hughes Hughes Hughes Hughes Hycalog Hycalog Geodiamond Security Security Security Hycalog Hughes Hughes Geodiamond

3-3/4 5-7/8 5-7/8 5-7/8 5-7/8 5-7/8 5-7/8 8-3/8 8-3/8 8-3/8 8-3/8 8-3/8 8-3/8 8-3/8 8-3/8 8-3/8 8-3/8 8-3/8 8-3/8 12 12 12 12 12 12 17

S-226 D-411ST R-60ST S-279G S-248 G-486G FM-2563 FM-2841 FM-2941 LX-19HSB AG-437 AG-547 S-279G S-725G R-60ST D-411ST DS-107D DS-43ST MGR-32PX FM-2863 FM-2844 FM-2943 DS-66 AG-437 AG-547 M29-PX

M-723 ST ST M-841 M-723 M-433 M-323 M-432 M-433 M-312 M-432 M-432 M-841 M-723 ST ST S432 ST M-433 M-424 M-233 M-333 M-432 M-432 M-432 M-432

Ballaset Natural Diam. Side-Track Impregnated Ballaset 13 mm PDC 13 mm PDC 13 mm PDC 13 mm PDC 19 mm PDC 13 mm PDC 19 mm PDC Impregnated Ballaset Sidetrack PDC Sidetrack Dia. PDC PDC ARCS PDC 13 mm PDC 13/19 mm PDC 13 mm PDC 13 mm PDC 13 mm PDC 19 mm PDC 13/16 mm PDC

3.2

Breakeven Analysis

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Bit breakeven analysis gives a general indication of the required rotating time and footage for a bit of a different price to equal the performance, in terms of cost per foot of a reference bit run. The standard procedure assumes that the new bit being evaluated drills at the same overall average penetration rate as the reference bit for the breakeven time calculated. With the aforementioned constraints, breakeven time, T2, can be calculated: T2 = B2 + R(t) C1 (F/T)-R

.......................................................................Eq. 2M-8

Where: T2 = Breakeven time, hrs B2 = Cost of new bit, $ R = Rig cost, $/hr t = Trip time, hrs, C1 = Reference bit cost, $ F/T = Original ROP, ft/hr Example Problem 2M-4: Calculate the breakeven rotating time and footage for a 12" IADC Code 517 sealed bearing TCI bit which cost $9650 compared to the lower priced ($2450) non-sealed bearing reference bit, normally used to drill the section. Pertinent data is as follows: Previous bit rotating time = 35 hrs Footage drilled = 1175 ft Rig operating cost = $37,500/day Round trip time = 12 hrs Reference bit footage cost, C1 is calculated with the conventional footage cost equation: C1 =B + R (T + t) F

T2 =

= 2450 + (37,500/24) (35 + 12) 1175

9650 + (37,500/24) 12 = 28,400 64.59 (1175/35) - 1562.50 605.79

= $64.59/ft

= 46.88 hrs

Breakeven footage = Breakeven hours x Reference bit ROP = 46.88 x (33.57) = 1574 ft Frequently, we need to know what penetration rate is required for a performance drilling system such as a Turbine/PDC assembly, to match the cost per foot of a ______________________________________________________________________________________

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conventional drilling system, such as rock bit and rotary. To account for the increased operating cost of the motor or turbine and the fact that their charges are only incurred while drilling and circulating, the procedure shown in Example Problem 2M-5 can be used to calculate the breakeven ROP. Example Problem 2M-5: Offset drilling data indicates a Turbine/PDC performance drilling system can reduce drilling cost from that achieved with a conventional Rotary/PDC assembly which averaged 9.0 fph. The contention is based on the higher ROP's achievable with the high rotational speeds of the turbine. What penetration rate is required by the more expensive Turbine/PDC system to achieve breakeven cost per foot based on the following: 12" PDC cost = $60,000 Turbine Charges (Only on rotating time) = $250.00/hr Rotary/PDC bit run data: Bit Cost = $55,000 Rig Cost = $25,000/day Footage Drilled = 1035' Average ROP = 9.0 fph

Trip time=12 hrs Rotating time = 115 hrs

First calculate the previous bits footage cost, C1: C1 = 55,000 + (25,000/24) (115 + 12) = $180.96/ft 1035 Since the turbine charges are only incurred while rotating, its cost must be calculated as follows: C2 = [B2 + (Ct x T2)] + R (T2 + t) .........................................Eq. 2M-9 F2 Where: Ct= Rental Cost for turbine or motor, $/hr F2= Footage drilled by the second bit, ft T2= Rotating time for second bit, hrs Setting the turbine footage cost equal to the reference bit runs footage cost and solving for T2, turbine rotating time, yields the following equation: T2 = (C1 x F) - [B2 + (t x R)] = (180.96 x 1035) - [60,000 + (12 x 1041.66)] R + Ct (1041.66 + 250) = 88.87 hrs Breakeven ROP = Footage/Breakeven Hrs = F/T2 = 1035/88.87 = 11.65 fph This is the minimum ROP at which the Turbine/PDC assembly would match the reference bits footage cost. Anything faster would result in lower footage cost.

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3.3

Expected Value Cost Analysis

The expected value technique is often used to arrive at a justifiable economic decision based on historical cost of events and the probability of their occurrence. The basic expected value equations are as follows: EV = C1P1 + C2P2 ..............................................................................Eq. 2M-10 P1 + P2 = 1 .........................................................................................Eq. 2M-11 Where: P1 = Probability of the first event occurring P2 = Probability of the second event occurring C1 = Cost of the first event C2 = Cost of the second event Expected value footage cost, Evf can be calculated by letting Cg equal the calculated cost of a bit run without severe hole problems, i.e., twist offs, stuck pipe, side-tracking etc., and letting Pg equal its probability of occurrence. Fg represents the footage drilled on the trouble free run. Cb represents the mean cost of bit runs in which severe hole problems occurred and Pb represents the probability of a bad bit run occurring. From the review of recent historical drilling data the probability of a bad bit run occurring, Pb can be calculated along with the mean cost of the occurrence. Fb represents the mean footage drilled on problematic bit runs. Expected value footage cost, Evf, can then be calculated as: Evf = Cg Pg + Cb Pb Fg Fb ...................................................Eq. 2M-12 An expanded version of the conventional drilling footage cost equation should be used to calculate footage cost for all runs. The footage cost equation should use actual trip time to account for excessive reaming observed with some PDC/PDM or PDC/turbine assemblies. It should also take into account any trouble time experienced with a given bit run. Cpf = (Bc + Mc +Tc + Cc + Fc) + Rc(Tt + Wt + Rt +St + Ct) ............Eq. 2M-13 F Where: ______________________________________________________________________________________

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Cpf =actual cost per foot, $ Bc = bit cost, $ Mc = drilling fluid cost for the interval, $ Cc = rotating and circulating cost for the PDM or Turbine, $ Tc = cost of tools or repairs to tools, $ Fc = fishing or any related trouble cost, $ Rc = rig operating cost, $/hr Rt = bit rotating time, hrs Tt = round trip time, hrs Wt = time for wiper trips required to drill ahead, hrs St = directional survey time, hrs Ct = connection time, hrs F = Footage drilled, Example Problem 2M-6: Calculate and compare the actual footage cost for PDM/PDC and Turbine/PDC performance drilling systems based on the following: PDM/PDC Drilling Assembly: Drilled 1400' in 104 hrs. Bit Cost; $55,000, Mud cost = $11,400, PDM cost = 104 hrs x $250/hr = $26,000, Trip time = 13 hrs, Rig cost = $30,000/day, one wiper trip had to be made which consumed 6 hrs. Turbine/PDC Drilling Assembly: Drilled 1624' in 97 hrs. Bit Cost; $55,000, Mud cost = $13,750, FBS Turbine cost = 97 x $350 per hour = $33,950, Trip time = 13 hrs, Rig cost = $30,000/day, no wiper trips were made. For the PDM/PDC run of 1400': Cpf = (55,000 +11,400 + 0 +26,000) + [(1250(13 +6 +104 +0 + 2.9)] = $178.41/ft 1400 For the Turbine/PDC run of 1624': Cpf = (55,000 +13,750 + 0 + 33,950) + [(1250(13 + 0 + 97+0 + 0)] = $147.91/ft 1624 The Turbine/PDC assembly offers the lowest actual cost for the two runs evaluated.

Example Problem 2M-7: Three performance drilling systems have recently been used to drill the massive Cotton Valley Formation.

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Seven runs have been made with a Turbine/PDC bit assembly. The best run to date has been with the Turbine/PDC assembly for a startling $145.35/ft. Average cpf for all of the good runs was $187.50/ft. Bit sticking problems were encountered on two of the runs, with average footage cost of $795.00/ft. Five PDM/PDC runs have been made, with motor failure occurring on one well. Average cpf for the good runs was $259.23/ft and $358.67/ft on the well where stuck pipe was incurred and had to be worked free. Two Rotary/TCI bit runs have been made with average cost of $290.00/ft and no major problems. Which performance drilling system will offer the lowest expected value footage cost? Turbine/PDC Pg = 5/7 = 0.714 Pb= 2/7 = 0.286 EVcpf = (0.714 x $187.50) + (0.286 x $795.00) = $ 361.25/ft PDM/PDC Pg = 4/5 = 0.8 Pb= 1-0.8 = 0.2 EVcpf = (0.8 x $259.23) + (0.2 x $358.67) = $ 279.12/ft Rotary/TCI Pg = 2/2 = 1.0 Pb= 1-1 = 0 EVcpf = (1.0 x $290.00) + (0 x 0) = $ 290.00/ft The PDC run on a PDM offers the lowest expected value cost per foot of $279.12/ft.

4.0

PERFORMANCE DRILLING SYSTEM OPTIMIZATION 4.1

Development of the Minimum Cost Drilling Plan

A tremendous amount a drilling data is generated by Saudi Aramco Drilling operations. Approximately 2000 bit runs are made each year. The M-204 Database, Spreadsheet Programs and graphical analysis techniques can be availed to access, interpret and optimize bit and drilling system performance on a broad, representative and meaningful scale. Example Problem 2M-8: Fabricate a minimum cost bit program for HWYH-958, a K-2 Vertical Jauf Well to be drilled to 15,150' utilizing all relevant available data:

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Step One: Use the M-204 data base Well Search Option to review all the wells drilled to at least 12,000' in a 20 km radius around HWYH-958. Step Two: Print out bit records from the well search, for the wells which have been drilled within the last three years. Step Three: Enter the bit records into an Excel Spreadsheet Program. The data needed from the bit records for this analysis are Well number, Bit Run Number, Bit size, type, manufacturer, IADC Code, bit cost, depth in, depth out, remarks, rotating time, circulation rate, pump pressure, mud weight, nozzle sizes, PV, YP, rotational mode, cost of motor or turbine if used, dull grading, pertinent remarks, bit weight and rotary speed. The spreadsheet should be set up to calculate, drilling cost per foot, footage, ROP, mean drilling depth, bit Hhp/sq. in., bit pressure loss, hydraulic impact force, jet velocity and WR product. Separate spreadsheets should be made for each hole size, such as 22, 17, 12, 8-3/8 and 5-7/8" hole. Figure 2M-7 - Excel Spreadsheet used to analyze offset bit run data

Step Four: Once the data has been input into the spreadsheets, it can be manipulated to statistically and graphically analyze the data. The sort data function can be

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availed to sort the bit runs by cost per foot, (ascending) such that the best bit runs in each section appear at the top of the spreadsheet as shown, in Fig 2M-7. For a quick look at bit and drilling system performance, calculated cost per foot should be plotted against mean drilling depth as shown in Fig 2M-8 for 12" bit runs in the HWYH-958 Area. The Excel chart options function can be used to perform linear, logarithmic, polynomial, power, moving average or exponential curve fits of the data, generate equations for the line, along with correlation coefficients to check the goodness of fit. The equation which best fits the data can be used as a benchmark for footage cost vs. depth for the given hole size and area. Figure 2M-8 - Plot of Cost per foot Vs. Mean Drilling Depth for 12" bit runs

S-86F

M-84F

M-89F

HP-62A

AG-547

M-84F

Step Five:

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Circle the bits that offered the lowest cost per foot at each depth. Connect the points. The line drew represents the unrefined minimum cost bit program for the given hole section. Step Six: Pencil in the estimated formation tops. Draw vertical lines representing each on the graph. Investigate all available aspects of the selected minimum cost bit runs with the daily drilling reports and bit records. Avail compressive strength charts to aid in determining exactly where specific bit runs should be made. Formulate and refine the minimum cost bit plan from casing point to casing point. Step Seven Repeat the procedure in Step Six for each hole size. Use the detailed run information from the actual bit records and morning reports to "emulate the operating parameters" such as bit weight, rotary speed and hydraulics; under which highly successful bit runs were made. Use scatter plots of various drilling parameters such as per cent pressure loss at the bit vs. ROP and Weight on Bit vs. ROP, to further refine the program. Step Eight Compile the data in the form of a minimum cost bit program and include it in the drilling program, as shown in Figure 2M-9. Step Nine When the bits are run, run drill-off test, as detailed in section 2-I, to confirm that the weight and speed being used is optimum. If the formation is too heterogeneous to get a competent drill-off test, a prior low-cost bit run of the same type can be emulated, and should yield very similar results. Alternatively, iso-cost graphs, contoured from plots of Rotary Speed vs. Bit Weight as shown in Fig. 2M-11 can be used to select the optimum weight and speed. Step Ten As the bit run is being made, a plot of rotating time Vs. Cost per foot should be maintained as shown in Figure 2M-12. When footage cost reach a minimum, then start to increase, in the absence of an acute changes in formation drillability, the bit should be pulled. The latter will yield minimum footage cost.

Fig 2M-9 - Example Minimum Cost Drilling Program with Optimum Bit Weights, Rotary Speeds and Hydraulics

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Fig 2M-11 - Iso-cost graph to determine optimum Weight & Rotary Speed

C ost P er F oot

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Figure 2M-12 - Plot of Cost per foot vs. Rotating time for Berri - 402 C o s t p e r F o o t V s . R o ta tin g T im e - B e r r i-4 0 2 9 -1 /2 " T e ib o T u r b in e R u n in 1 2 " H o le

Drilling Cost, $/Ft

3000 2500 2000 1500 1000 500 0 0

20

40 60 80 R o ta tin g T im e , H o u r s

100

120

Figure 2M-13 - Cost per foot vs. per cent pressure loss at bit

% Pressure Loss

$ /F t v s . %

P re s s u re L o s s @

B it

1 0 0 .0 y =

8 0 .0

-0 . 1 0 0 6 x + 4 4 . 6 5 3 R 2 = 0 .0 2 8 6

6 0 .0 4 0 .0 2 0 .0 0 .0 0

20

40

60

80

$ / ft

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INTRODUCTION TO DRILLING FLUIDS 1.0

FUNCTION OF DRILLING FLUIDS 1.1 Hydrostatic Pressure 1.2 Cuttings Transport 1.3 Filtration Control 1.4 Mechanical Stabilization 1.4.1 Shale Instability 1.4.2 Chemical Inhibition

2.0

PROPERTIES OF DRILLING FLUIDS 2.1 Density 2.2 Rheological Properties 2.3 Filter Cake Quality

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INTRODUCTION TO DRILLING FLUIDS Drilling operations success depends significantly on the performance of the fluid being circulated down the rotating drill pipe, through the bit, and up the annular space between the pipe and the formation. The drilling fluid design, formulation and reactions with the subsurface formation are crucial. “Drilling mud” is a more widely accepted name for drilling fluids prepared by mixing water with natural formation clays or commercial bentonite. “Drill-in fluids” are special drilling fluids formulated without bentonite, barite and other insoluble materials. The absence of barite helps to ensure that the Drill-in fluids are less damaging to the pay zone natural permeability. A large number of the formation damage mechanisms can arise from the interaction between the reservoir rock minerals and the induced fluids. Drilling fluids have solid and liquid components. There is no such thing as a universal “non-damaging” drilling fluid. Each reservoir to be drilled should be taken on a case by case basis and the least impairing “Drill-in fluid” formulation can be selected. Laboratory methods of examining the residual damage caused by the different fluid formulations are available and should be carried out prior to actually drilling the well. 1.0

FUNCTION OF DRILLING FLUIDS Drilling muds have many functions in the drilling operations. At any one time in the operation, one function may be more important than the other functions for that drilled interval, which is why a mud program is essential in well planning. Drilling Muds should provide: • • • • • • •

Control of subsurface pressures to overcome gas, oil, and water flows. Removal and suspension of drilled cuttings and weighting material. Proper borehole stability. Reliable geological and reservoir rock information. Lubrication and cooling of the bit and drill string. Minimum formation damage. Corrosion control.

Some publications may list ten to fifteen different functions of a drilling fluid. Many of these are variations of the same function. This section will discuss: • • • •

Generating hydrostatic pressure downhole. Removing cuttings a head of the bit and transporting them to the surface. Controlling invasion of filtrate into the formation. Stabilizing the formation mechanically and chemically.

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1.1

Hydrostatic Pressure Filling a hole with a fluid will inevitably generate a hydrostatic head or pressure as illustrated in Figure 3A-1. This is calculated by the use of the following equation:

Hydrostatic Head HH (psi) or HH (psi)

= =

(Conversion Constant) 0.0695 0.052

X X X

(Mud Density) MW (lb/cu.ft.) MW (lb/gal)

X X X

True Vertical Depth TVD (feet) TVD (feet)

Downhole pressure needs to be controlled for two reasons: • •

The drilled rock must be supported and stabilized. The pressure of gases and fluids in the rock must be exceeded so they do not enter the wellbore. This is particularly important for safety.

As the mud density supports the rock, excessive downhole pressure can also damage it by “fracturing” it in the manner that a hose pipe can be split by too high a pressure. A key to a successful operation is the knowledge of the formation stresses, formation strength, and pore pressures, so that the correct mud weight and casing depths can be selected. Hopefully, the casing depths will isolate problem sections. The pressure applied by the mud column will depend on whether the mud is static or being pumped. Drill Pipe Drilling Fluid Cement Casing Hydrostatic Head

Casing shoe

Drill Collars Drill Bit Water Flow High Pore Pressure

Figure 3A-1- Hydrostatic Head

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The additional pressure used to overcome frictional losses and viscosity effects generates additional pressure, and the sum is referred to as Equivalent Circulating Density (ECD). ECD = Hydrostatic Head + ∆P 1.2

Cuttings Transport One of the most important functions of the drilling fluid is to efficiently remove the freshly drilled rock fragments from around the bit and transport them to the surface, where they can be discarded. The ability to achieve this objective is dependent on the annular velocity and the properties of the fluid. The speed at which the fluid is pumped up the annulus should be greater than the slip velocity [the rate at which the cuttings will settle through the moving fluid]. Annular velocities between 100 and 200 ft/min are frequently used. The density of the fluid has a buoyant effect on the cutting particle so that an increase in density will increase the fluid carrying capacity. Also, the viscosity related characteristics considerably influence the fluid carrying capacity. Drilling progress can only be made if the cuttings are removed from the wellbore and separated and discarded at the surface. Cuttings removal involves four steps: • • • •

Removing the cuttings away from the area of the bit where the cuttings are generated Transporting the cuttings to the surface in the annular space between the drill pipe and the wall of the hole Suspending the cuttings at the surface to allow separation Suspending the cuttings in the hole when the pump is off

Moving cuttings away from the bit is controlled by the pump rate and bit hydraulics. The mud properties can only improve the mud lifting capability and ensure cuttings and solids suspension. Enough volumetric flow is needed to sweep the bit and move the cuttings out of the hole. Figure 3A-2 shows a typical chip removal from the face of the bit. Fast drilling rates can overload the volumetric flow past the face of the bit, resulting in re-grinding the chips cut by the bit. High drill rates, especially at shallow depths, can load up the annulus, resulting in excessive hydrostatic head. Annular flow rate, therefore, is critical for proper hole cleaning. Transporting the cuttings up the annulus is also dependent on having the 3 of 16

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proper rheological properties (viscosity) as well as flow rate. regime, turbulence or laminar, is important for good hole cleaning.

The flow

In high angle and horizontal wells, maintaining both drilled cuttings and weight material in suspension requires progressive gel strengths and high "low-shear rate viscosity".

Wall cake Drill Pipe Cuttings

Drill Bit Bit Jet Bit Teeth

Figure 3A-2- Chip removal from the face of the bit. Drilling fluids should have the ability to form a reversible gel structure when circulation is stopped (Thixotropic properties), so that the cuttings and weighting material remain suspended. Upon resumption of circulation the fluids revert to there initial flow properties. 1.3

Filtration Control The fluid loss properties of mud may effect the penetration rate, hole instability, formation damage, and differential sticking. The total amount of fluid lost to the formation is dependent upon: • • • • •

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Pressure difference between mud column and pore pressure (∆P) Base fluid viscosity Formation permeability Filter cake permeability Temperature

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Mud filtration is even more critical when drilling depleted zones and higher permeability formations. Fluid invasion can also occur in fractured formations, especially if the mud hydrostatic head is significantly higher than the formation pressure. Filtrate invasion into producing zones is one of the leading causes of formation damage, resulting in reduced production. Not only the amount of filtrate but the type is important. For this reason, an inhibitive fluid may be used. Brine-based muds are often used to minimize damage. The filter cake quality is essential in maintaining good fluid loss control. Poor filter cakes and high fluid losses can lead to excess drag and differential sticking. Figure 3A-3 shows the formation of the filter cake. The basis of good filtration control in high temperature water-based muds is to have the optimum concentration of high quality bentonite particles. Bentonite forms a tight, low-permeability thin filter cake. High temperature fluid loss control additives must be used to reach very low fluid loss levels. Also at high temperatures, further additives may be needed to overcome temperature degradation. If high concentration of poor quality bentonite is used in a high temperature well, excessive mud thickening will develop, which can cause dramatic increase in the surge pressures while moving the drill string in and out of the hole. In gas wells, this causes well control problems and blowouts.

Mud Pressure Pm

Drill solids Mud Filtrate

Pore Fluid Pressure PO

Pressure Forcing Fluid into Formation ∆P= Pm - Po

Bentonite Particle

Figure-3A-3 Formation of the wall cake

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1.4

Mechanical Stabilization 1.4.1

Shale instability takes many forms and can result in a variety of problems while drilling. These problems range from minor delays and increased daily costs to stuck pipe and lost wellbores. The following list contains some of the more common problems experienced: •

•

• • •

Fill and bridges: Mud solids and cuttings settled on bottom after trips or connections are called fill. Bridges are tight spots encountered higher up the hole on trips. These problems result in expensive reaming operations, mud treatment, and possibly excessive bit wear or damage. You must be certain that this problem is not caused by lack of proper hole cleaning, either from poor rheology or low pump output. Ineffective hole cleaning: Additional formation cavings entering the wellbore due to the rock failure and collaps may overload the capacity of the annular circulating flow rate to carry all the rock fragments out of the wellbore. Stuck pipe : Probably the most costly result of hole instability is a stuck pipe. If the pipe is stuck, it will, at the least, take some rig time to correct and, at worst, result in the hole being lost. Increased hole volume: Severely washed-out holes may result in higher mud costs, increased cement requirements, and poor cement jobs. Logging difficulties: Washed-out hole, fill and bridges can seriously interfere with getting good electric logs and sidewall cores. Wellbore Drilling Terms Through the years, various terms have been used to describe the problems associated with wellbore instability while drilling. Different parts of the world use different words to describe the same phenomena. The following are some of the terms and their usual interpretation.

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Sloughing, Running, Heaving: These words describe the general condition of excess pieces of formation showing up on the shale shaker. They are usually associated with hard dewatered shales. Mud Making Shales, Gumbo, Bentonitic Swelling, Plastic Flow: These conditions usually refer to drilling through formations high in bentonite or other swelling clay content such as recent volcanic sediments. These clays may disperse into the mud or extrude into the wellbore. Plastic flow also is encountered when drilling massive salt sections. Fractured Shales: This term is usually applied to tectonically stressed areas (mountainous) with known highly faulted or highly dipped formations. Pressured Shales, Gas-bearing Sands: These terms are applied when excess shale volume is experienced along with gas intrusions. It is usually caused by insufficient mud weight. •

Sloughing: Sloughing consists of unconsolidated, weak, or loose formation that may fall into the wellbore due to the geological nature of the formation. Sloughing usually occurs at shallow depths. The hole may or may not be enlarged, since weak formations will flow and fill in the areas being washed away.

•

Induced sloughing: This refers to formation that falls into the wellbore as a result of water-wetting clays or washing out cementitious materials (salts, etc.). Dissolving cementitious materials usually occurs at shallow depths and results in a washed-out hole. Water wetting and clay swelling may occur at greater depths when hydratable clays are present.

•

Heaving: This formation instability is caused by formation pressures higher than the hydrostatic head from the mud. Hydratable clays in the formation may aggravate this condition. The pieces of heaving shale crossing the shaker are usually square or rectangular and vary in size from cuttings size to several inches. Often the pieces have rounded edges. This indicates that the piece is slipping and tumbling in the annulus, causing the edges to wear.

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•

Spalling: Spalling or splintering occurs when pressures in the formation cause the hole to close radially. This can occur at any depth and typically is found in highly tectonically stressed areas. Plastic flow of massive salt sections is a special case of this phenomena. Splintered shale pieces are usually long and narrow with sharp edges and points. Many times they are slightly curved, showing the shape of the wellbore.

The most common cause of unstable formations is mechanical instability resulting from the imbalance of formation stresses. The stress balances created in the earth over millions of years is disrupted when a hole is drilled into it. These internal formation stresses have to be rebalanced or the wellbore will collapse. Most formations have enough strength that they do not immediately collapse. Given sufficient time, however, most formations will eventually start collapsing. There is a time-value associated with hole instability based on the geology of the formation, the mud density, and the type of mud in the hole. The subsurface stresses being applied are: •

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Overburden pressure, S: The overburden pressure is the pressure exerted by the weight of the earth's rocks above the element. The overburden pressure depends upon the mineral make-up of the rocks and, in general, can be assumed to be about 1.0 psi/ft. It is not linear, however, because the formation density tends to increase with depth as a result of compaction and reduction in porosity.

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Surface

Column of Pore Fluid

S Overburden Pressure (Mass of overlying Formation rocks & Pore Fluids)

σ

Matrix or intergranular stress between grain boundaries

S = PO + σ

PO Pore Fluid Under Pressure

Figure 3A-4- Origin of Stress in Subsurface Rocks •

•

Pore pressure, Po: The pore pressure is the fluid pressure within the pore spaces of the formation helping to support the overburden pressure. If the fluids in the pore spaces are interconnected and have not been trapped, the pore pressure is equivalent to the hydrostatic head of the water column above the formation element shown in Figure 3A-4. Pore fluids are predominantly salt water, so the pore pressure in normally pressured formations is taken to be a column of water with seawater salinity. This is equal to a gradient of about 0.046 psi/ft. On a graph, the pressure gradient is approximately a straight line although the temperature gradient will influence the density. Matrix stress, σ: The matrix stress is the portion of the overburden pressure that is supported by the physical structure of the formation. It can be resolved into three components that are perpendicular to one another (one vertical stress and two horizontal ones). In most cases, only the overall matrix stress

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can be examined since the three components must be measured in situ. (Approximations of the three principal stresses have been done in the past from log and seismic-derived data). The total matrix stress for normally pressured formations is about 0.054 psi/ft. •

Wellbore stress: The drilling of a hole in the stressed rock generates a new higher stress field or “hoop stress”, which is related to the stresses at right angles to the wellbore. These stresses decay to the initial stress as you move away from the wellbore. Filling the hole with mud exerts a pressure (Pm) that reduces the tangential stress.

The drilling technique uses the minimal mud weight to balance additional weight to the pore pressure and then to reduce the rock stress to a level where it is stable. No attempt is made to balance the stress perfectly, as the higher mud weight will slow down the rate of penetration. This technique puts the rocks under stress and leads to failure. Subsequent reaction of rocks with the drilling fluid is often enough to stress the rocks to a point where they fail. The adsorption of water takes some time and contributes to the time dependency of the stability of rocks. Formations that contain high levels of the clay mineral montmorillonite will retain the water while under the overburden pressure. This means that the pore fluids will bear a disproportionately high amount of the overburden pressure. Also, the matrix stress will be low. The mud weight will have to be increased to hold back the formation. Tectonically stressed areas pose a special problem since these formations have been fractured and folded. Fractures may allow the penetration of whole fluid that can transmit pressures into the formation, causing it to weaken and fall in. Also, when folded formations are drilled, part of the wellbore face may be highly compressed while another part may be in tension. It is nearly impossible to calculate the relative principal stresses in this case, but there is usually one that will approach zero. Mud weights higher than indicated by pore pressure analysis (gas pressure) are usually needed to stabilize the formation in this situation. The amount of mud weight needed should be determined in the field only on a case-bycase basis. Whenever the stresses at right angles to the wellbore are not equal, the wellbore will fail in the direction of least stress and produce an oval or elliptically shaped hole. This situation will often be 10 of 16

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encountered when drilling deviated holes because the vertical stress tends to be larger than the horizontal stress. Tectonically stressed areas may also show the same phenomena. Directional drilling in an oval hole is difficult, but this problem cannot be overcome. The following factors are involved in shale instability from physical causes: • Density: The proper density is the most important factor in shale stability. • Erosion: Proper hydraulics, annular and bit, must be maintained in formations prone to instability. Once instability started, by erosion or other factors, it can be difficult to stop. • Pressure surges/swabs: Excessive surges and swabs when tripping or running pipe can initiate instability. Rocks are much weaker in tension so they are prone to fracture, which can occur when running pipe too fast into the hole. The fractured rock is more likely to produce problems later on. • Direct contact: Minimize pipe whip by maintaining the proper pipe tension and rotation. • Fluid invasion: In fractured formations, whole mud can invade and cause instability. In some cases, high fluid losses can also help weaken a formation. 1.4.2

Chemical Inhibition The consolidation process and the overburden pressure force water out of the shales. Relief of the confining force and re-exposure to water causes the water to adsorb very strongly onto the clay surfaces. The following changes also occur. Stress increases around the wellbore. • The shale swells and weakens. • Lubrication is provided for slippage planes. • Plastic shales deform into wellbore, giving tight hole conditions. • Harder shales generate cavings. • Time related instability occurs as water migrates into rock •

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A)

These changes in rock properties inevitably result in many problems, including: • • • • • • • • • • •

B)

Poor directional control Washed out hole More solids to be removed at surface Reaming Stuck pipe due to hole collapse Bit balling Additional solids into the mud Hole failure Poor hole cleaning in washed out sections Tight hole Dispersion of solids into mud

The magnitude of this problem depends on: •

•

Type of formation: Shales with montmorillonite or mixed layer clays are more susceptible to dispersion, swelling, and bit balling. Type of drilling fluid: Fresh water is most reactive

A lot of effort has gone into designing mud systems with “inhibition” or increased ability to minimize the reaction between the mud and the shales. The approach is to change the exchangeable cation or to expel water from the clay surface. • • • • • •

Exchange sodium ion for calcium Exchange sodium and calcium for potassium Exchange sodium and calcium for low molecular weight cationic polymers Adsorb high molecular weight polymers such as (PHPA) to coat the clay surfaces and displace water Add polyglycerol to displace water Plug fractures with asphalt and gilsonite

Specific mud formulations and additives are discussed in the Waterbased Drilling Fluids section 3-B.

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Formulating the drilling fluid with oil can eliminate the problem with the reaction of the shale with water. The adsorption forces are so well developed that high levels of salt have to be dissolved in the water, which is present as an emulsion, to prevent the shale from hydrating. Oil-based Drilling Fluids formulation and application will be discussed in a separate section 3-B C)

The following field practices are used to minimize problems from unstable formations: •

Density control: Maintain the proper density. If in mountainous areas, more mud weight may be needed than indicated by gas pore pressures. Surges and swabs must be avoided in formations susceptible to falling in. Keeping the wellbore full of fluid on trips is also good practice for wellbore stability as well as blowout protection.

•

Rheology: Adequate hole cleaning is needed to remove any formation pieces falling into the hole and to differentiate between unstable formations and a hole cleaning problem. Turbulence may wash out unconsolidated and weak formations. Turbulence may also aggravate a formation in which hydratable shales have started falling into the wellbore.

•

Fluid loss: The API fluid loss by itself is not an indication of relative formation protection. The level of fluid loss control must be based on field experience for each individual drilling area.

•

Hole deviation: In high angle wellbores, and fractured formations with deviation problems, extra care must be taken to protect against unstable formations.

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2.0

MAIN PROPERTIES OF DRILLING FLUIDS Mud engineers use standardized tests to measure the physical and chemical properties of the drilling fluid. The well site data generated determine if the mud is functioning properly. The American Petroleum Institute's Drilling Fluids Standardization Committee administers these test procedures (API Committee 3, subcommittee 13). This section discusses the following common properties and how these properties relate to the mud performance: • • • •

Density Rheological properties Filter cake quality Inhibition

2.1

Density is the weight of a given volume of fluid. It can have units of: A) B) C) D)

Pounds per cubic foot, lb/ft3 Pounds per gallon, lb/gal Kilograms per cubic meter, kg/m3 Grams per cubic centimeter, g/cm3 3

Mud Density lb/ft lb/gal

0

0

37.4

5

Air Mist Foam Oil

62.4 Water Oil/Water Emulsion

74.8

10

Salt saturated

56–62 lb/ft3 3 CaCO3 CaCl2 87 lb/ ft 110 lb/ft3

112.2

15

149.6

20

74.8 lb/ft3 Barite (BaSO4 )

Iron Oxide

187.0

Fe2O3

Galena (PbS) 156 lb/ft3

25 194 lb/ft3

224.4

30

>220 lb/ft3

Figure 3A-5 The range of mud weights that can be achieved using various types of weighting materials (salts, calcium carbonate, barite, iron oxide, and galena).

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2.2

Rheological Properties: Rheology is the study of the viscosity characteristics of a mud. Viscosity (the internal resistance of a fluid to flow) is a measure of thickness or thinness. On a drilling rig, the viscosity is measured in several different ways, including: •

• • •

Funnel viscosity: Used for quick and easy indications of viscosity changes Plastic viscosity: Related to the solids content of the mud Yield point: Related to the chemical forces acting on the mud solids Gel strengths: Related to suspension and time-based thickening tendencies

Rig personnel can measure the funnel viscosity of the mud, but the mud engineer using a viscometer must measure the other viscosity properties. 2.3

Filter Cake Quality: Control of mud filtrate loss is directly related to the filter cake quality. The factors that affect cake quality are: • • • •

Particle size distribution Long-chain polymers Compressibility State of flocculation of the mud

To get a filter cake with low permeability, mud solids particle size distribution from submicron to multimicron is needed. Of all the particles in a mud, the flat, platelike bentonitic particles form the most smooth, even, and least permeable bridging material. Drilled solids normally change this distribution to larger, more permeable cakes. Commercial bentonite and long-chain polymers help in making a tougher and thinner wall cake. Filter cakes from drilling fluids have a wide range of compressibility. The nature and size of the solid particles in the cake determine the amount of compression. Filter cakes that are highly compressible will be compacted as the differential pressure goes up. This gives a lower permeability and reduced filtrate volume into the formation. Incompressible cakes will not compact, and the filtrate into the formation will increase in direct proportion to the differential pressure. Bentonite forms the most compressible cake, compared to cakes with drilled solids and barite. Therefore, in addition to the total solids content of the mud, the solids content of the mud should be analyzed for high and low gravity solids and bentonite content. The barite content is set by the mud weight being used. Adequate bentonite content should be maintained and the drilled solids content should be minimized to obtain a compressible filter cake

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The compressibility of the cake can be measured in the field. Simply use a High Temperature / High Pressure (HTHP) filter press at two pressures, the higher twice the pressure of the lower. A slight increase, or lowering of the filtrate at the higher pressure, indicates a compressible cake. Flocculated solids in a mud result in thick, weak filter cakes. Salts or saltwater, cement contamination, cause flocculation. In addition, higher temperatures cause clays to flocculate. Polymeric dispersants are used to deflocculate the mud system. The submicron sizes created by many of these chemical thinners give low API fluid loss values. A build-up of these particles, however, tends to reduce drilling rates. Note: Drilling fluid properties such as density, viscosity, solids content and fluid loss can influence the rate of penetration. Drilling fluid transmits hydraulic horsepower to the bit and should have minimum suspended solids to achieve maximum drilling rate.

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TYPES OF DRILLING FLUIDS 1.0

INTRODUCTION 1.1 Base Fluids 1.1.1 Air 1.1.2 Water 1.1.3 Oil 1.2 Common Additives 1.2.1 Weight Contol Additives 1.2.2 Clay 1.2.3 Polymers

2.0

WATER–BASED DRILLING FLUIDS 2.1 Overview 2.2 Bentonite Mud 2.3 Lime-Treated Mud 2.4 Summary

3.0

OIL-BASED DRILLING FLUIDS 3.1 Balanced Activity 3.2 Rite Site Procedures 3.3 System Problems/Solutions 3.4 Advantages/Disadvantages 3.5 Summary

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TYPES OF DRILLING FLUIDS 1.0

INTRODUCTION

Drilling muds are composed of a base fluid and additives. The additives perform certain functions or adjust one or more of the mud’s properties. Common Base Fluids:

Air, Water, and Oil.

Common Additives:

Weight Control Additives (barite, calcium carbonate…etc), Viscosifiers (bentonite, polymers…etc), Deflocculants or Thinners (fluid loss/filter cake controllers).

1.1

Base Fluids 1.1.1

Air Air is used to lower the hydrostatic head to drill depleted and underpressured formations. Fast drilling rates can be maintained with ultralow densities. High volume air compressors are needed to maintain the volumetric flow required for cleaning the hole. If water is encountered in formations being drilled with air, the fluid must be converted to mist by adding surfactants. Water flows are best handled by converting the fluid to foam with foaming agents and a stabilizer. Foam stabilizers are usually drilling fluid polymers such as xanthan gum or hydroxyethyl cellulose (HEC). Air is not currently used in Saudi Aramco's fields, but nitrogen is frequently used in well completion operations.

1.1.2

Water By far, most of the muds in the world use water as the base fluid. Usually it is fresh water, but brackish and salt waters are often used for supply or economic reasons. A chloride content of about 5000 ppm is the upper limit for mud to be considered fresh water mud. The hydration and dispersion of bentonite is inhibited above that chloride level, therfore freshwater should be made available to prehydrate bentonite. In Shaybah field, over saturated brine "Sabkha water" was used as the make up water for a polymer system instead of bentonite to drill the water supply wells.

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Dissolved chemicals can modify the properties of water. • Salt: Sometimes the available supply of water for making a drilling fluid is not fresh water. In offshore drilling, for example, you may have to use seawater. At other times you may want to add soluble salts, such as sodium chloride (NaCl), potassium chloride (KCl), or calcium chloride (CaCl2). In addition to these chloride salts, drilling carbonates or sulfates (gypsum or anhydrite) can add soluble ions to the water phase. In some cases, these soluble materials cause mud instability and are considered as contaminants.

• Alkali: The pH of the mud systems is usually run in the alkaline range by the addition of alkali materials. Lime [calcium hydroxide or Ca(OH)2] and caustic soda [sodium hydroxide or NaOH] are the most commonly used alkalis. Caustic potash [potassium hydroxide or KOH] is used in KCl inhibitive muds. Lime is used in CaCl2 brine-based fluids and in oil-based muds. • Polymers: Several water-soluble polymers are used to change the properties of water and suspended solids. They can be used to derive the essential properties of viscosity, viscosity reduction, and fluid loss control. • Surfactants: Surfactants change the wettability of water and solids through adsorption. They are used to prevent foaming or to emulsify oil. Other surfactants will adsorb onto steel and act as lubricants. 1.1.3

Oil Oil is used as the continuous phase in invert emulsions or oil-based drilling fluids. Considerations of safety, low viscosity, and availability has made diesel oil the most common base oil. Where environmental concerns are high, special oils such as the SAFRA OIL have been prepared through the removal of aromatic fractions. Other environmentally acceptable oils are mineral oils and esters/ethers. These oils are very expensive and require expensive modifications of the drilling rigs, new handling and recovery procedures, and special transportation and storage facilities.

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Oil soluble and oil dispersible components are essential chemicals used to stabilize the water or brine-in-oil emulsions. The emulsified water adds to the viscous properties of the mud and the fluid loss control properties. 1.2

Common Additives 1.2.1

Weight Control Additives (High Density Solids) The most common weight material for drilling fluids is barite (BaSO4). It has a relatively high density, is not abrasive, and is available. Ground marble fine (CaCO3,CaMgCO3) processed as weighting material has an average particle size of 10 microns.

Ground Marble Physical & Chemical Constants (CaCO3,CaMgCO3) Hardness, Moh's Scale: Specific Gravity, gm/cc: Bulk density, lb/ft3 : Total carbonates (Ca, Mg): Impurities: (A12O3, Fe2O3, SiO2, Mn)

3.0 2.7 - 2.78 168.3 98.0 % Minimum 2.0 % Maximum

Weighting materials characteristics, and maximum practical density achievable by each for a drilling fluid. High concentrations of weighting material in a mud system have a significant influence on the properties of the muds, and is a major cost element. Material

Specific Gravity

Characteristics

Maximum Mud Density lb/ft3

Barite

4.2 -4.3

Cheap, non-abrasive, available

156

Marble fine

2.7 - 2.8

Inexpensive, acid soluble

110

Hematite

5.0 - 5.05

Available, abrasive, fewer fine particles in the mud

190

Illmenite

4.6 - 5.1

Less available

190

Galena

7.4 - 7.7

Expensive, not readily available

220

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Saudi Aramco’s Lab R&D Center routinely monitors barite quality.

X-ray fluorescence analysis: Barite, barium sulfate(BaSO4) 90%wt., Minimum Specific gravity: 4.20 gm/cc, Minimum Water soluble alkaline earth metals: Calcium 250 mg/kg, Maximum Soluble carbonates 3000 mg/l, Maximum Soluble sulfides 100 mg/l, Maximum Clay contamination: CEC(MBT) 0.50 meq/100g, Maximum Cement contamination: pH after aging 10, Maximum Particle size: Residue greater than 75 microns Particles l e s s than 6 microns Abrasion and performance index:

3%wt. Maximum 25%wt. Maximum

Equivalent to or less than the API test calibration barite

1.2.2

Clay The primary viscosifier for water-based muds is sodium bentonite. SaudiAramco's specifications for bentonite were developed for nontreated, good commercial quality. The specifications make certain that high yielding sodium montmorillonite clay is provided. A derivative of bentonite is used in oil-based muds for viscosity control. Bentonite reacted with cationic surfactants so that it can disperse in oil (becomes organophilic clay). Saudi Aramco’s Lab R&D Center routinely monitors bentonite quality:

Yield, bbls/short ton 90 Moisture content, % by weight 13 Yield point / plastic viscosity ratio 1.5 Dispersed plastic viscosity, cp 10 Dispersed filtrate, API ml/30 min. 12.5 pH, 9 Methylen blue capacity, meq/100gm 65 Residue on 200 mesh (wet), % by weight 2.5 Residue on 100 mesh (dry), % by weight 2

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Clay Dispersion and Aggregation A unique feature of the clays is their sheet-like structure that resembles a book. Dispersion describes a process in which the number of particles is increased by breaking off sheets of clay from the book. High shear mixing, perhaps at high clay solids content, tears the sheets apart. Chemical conditions that encourage hydration of the sheets are fresh water, sodium-based systems, and high pH conditions. Often, a combination of both mechanical and chemical forces is used to disperse bentonite. Time and temperature are additional factors. Aggregation describes a process when the number of particles decreases. An example of this is face-to-face flocculation. Aggregation is the result of chemical changes such as conversion of sodium montmorillonite to calcium montmorillonite or the addition of sodium chloride to a fresh-water dispersion of sodium montmorillonite. Clay Flocculation and Deflocculation The terms flocculation and deflocculation refer to the energy of interaction of particles rather than the number. Flocculation describes the situation when the particles are attracted to each other. Deflocculation describes the situation where the net forces are repulsive. The major attractive forces are short-range electrostatic forces called Van der Waals forces. These short-range forces are important in holding sheets of clay crystals together. The forces are weak and only operate over short distances. However, they can be significant for relatively large surfaces such as clay platelets. These forces are independent of salt content and pH. The attraction between clay platelets can also be increased by polyvalent cations such as calcium or aluminum. The cations cannot associate with more than one charge on a single sheet. If the ions carry more than one charge, they will form a bridge between the particles, increasing the level of structure. Edge-to-edge and edge-toface associations may be formed quickly. Face-to-face association will be a more stable form of association but will take time and may require higher levels of calcium.

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Long chain polymers may also form bridges between the clay platelets. This increases the degree of interaction between the clay platelets, resulting in higher viscosity.

Ca

Polymer

Flocculation of clays by calcium (from the lime) and long chain polymer

Clay particles

Repulsive Forces Forces repelling two clay crystals apart are due to the fact that they are both negatively charged, rather in the way the north poles of a magnet repel each other. The repulsion force will be increased if the negative character of the clays is increased. The force gets bigger as the particles are brought closer together. The negative charge can be increased by raising the pH or by adsorption of low molecular weight polymers. The charges on broken edges of clays are influenced by the pH. The clays are more negative at higher pH values. Thus high pH conditions will encourage dispersion of clays. Caustic addition to the make-up water is essential to ensure the maximum yield of bentonite. Alternatively, lower pH conditions create less dispersive or more inhibitive conditions. The negative charges of the particle and, hence, the repulsion can be increased by the adsorption of negatively charged, low molecular weight molecules or polymers. These negatively charged molecules are termed “deflocculants” as they increase the repulsive forces between the particles. The decrease in interparticle forces will also decrease the viscosity so these molecules are also called thinners. This repulsion energy, however, can be reduced through the addition of salt. The charges are “shielded” by the salt, and the particles can come closer together before they repel each other.

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Net Forces between Particles The overall reaction will be the summation of the attractive and repulsive forces. The situation is quite complicated because of the large number of factors involved. They are summarized in the following table. Summary of Conditions That Lead to Flocculation or Deflocculation Environment

Flocculated

Deflocculated

Salt Concentration

Over 2000 mg/l

Below 200 mg/l

Fast at 20,000 mg/l pH

Below 6

Above 9

Cation

Calcium and Aluminum

Sodium

Polymer

High molecular weight cationic, anionic, non-ionic

Low molecular weight, anionic.

This close look at the forces that bring particles together or cause them to repel each other gives an explanation to many important features of bentonite-based muds. ¾ Sodium bentonite (as a mud additive or a drilled rock mineral) will swell and disperse in fresh water with a “cloud” of closely associated water around the clay sheets. The large surface area and the large volume of tied-up water generate the viscous properties. ¾ Addition of salt to sodium bentonite causes the clay to flocculate and so prevents dispersion and development of viscosity. Bentonite should be mixed in fresh water with up to about 0.035% sodium chloride (200 mg/l chlorides). At higher levels, the dispersion is hindered, and the viscosity is decreased. ¾ Seawater with about 10 lb/bbl (3%) sodium chloride totally prevents the hydration of bentonite. This result demonstrates the use of high salt levels as the basis of the design of inhibitive drilling fluids.

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¾ Sodium bentonite muds are sensitive to contaminants, such as cement and anhydrite (calcium sulfate), that dissolve in water to release the calcium ion. The calcium ion exchanges with the sodium ion and initially causes rapid flocculation and thickening of the mud. Given time, the calcium exchange continues, and the clay platelets rearrange to form face-to-face aggregates. This arrangement reduces the surface area and number of particles so the viscosity decreases. ¾ Calcium contaminated muds can be converted back to the sodium form by treatment with sodium carbonate or bicarbonate or converted to a calcium mud. ¾ Calcium muds provide a level of increased borehole stability or inhibition through conversion to the low level of swelling systems. They are also resistant to contaminants. 1.2.3

Polymers Many of the “specialty” products used in formulating water-based muds can be described as “water soluble polymers”, a special group of chemicals that owe their properties to their relatively large size. Through their association with water and with the small colloidal clay particles, relatively small quantities of material can significantly alter the physical properties of the mud. These include viscosity, fluid loss, and inhibitive character. The large size of the molecule makes the polymers difficult to define with absolute precision, but enough is known to characterize them and describe them in general terms. There is also a very close relationship between the structure and performance of the polymer. Sufficient detail of the structure can be given; however, to explain how they perform and show the relationship between structure and their influence on mud properties. This understanding will allow for a better appreciation of their application and limitations. General Structure Polymers are made by chemically joining simple molecules (monomers) to form a chain. The “join” is in the form of a chemical bond. The chemical character of the monomer and the number of units joined will also be important characteristics of the polymer.

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The polymers used in drilling muds come in two groups: natural and synthetic. Natural polymers are derived from nature where the monomer is a sugar-like molecule. These molecules tend to be large and have a complicated structure and are generally described as polysaccharides. The linkage is susceptible to both being broken down at temperatures above 300°F and biological degradation. In synthetic polymers, the monomer group is a small molecule based on different vinyl monomers. The molecules are built up from a small molecule to a larger one. A range of structures is possible through the use of different monomers. The bond between the monomer units is a carbon-carbon bond that is stable to higher temperatures than the polysaccharide polymers. They are also resistant to biological degradation. Molecular Weight Polymer molecules are quite large. This property makes them special. Their size approaches the size of the clay sheets. The molecular weight or size of the molecule is related to the number of the monomer groups joined together. The number of units ranges from about 25 to hundreds of thousands. Molecular weight, obviously a very important feature of the polymer, influence properties and the way the polymer reacts in the mud system. For example, very high molecular weight molecules are longer than the clay particles. They can bridge or bond more than one particle to another one. This reaction increases the bonding between the particles so it would be classified as flocculation. Shorter molecules will not be able to bridge between the platelets. If the molecules are negatively charged, then their adsorption on the clay will make the clay more negative. Thus, the repulsion between the molecules increases, or the system deflocculates. Chemical Character The chemical character of the polymer will be due to the chemical character of the individual monomer groups on the chain. The groups may have all the same character or more than one. Three categories of groups may be in the chain. • Non-ionized groups such as hydroxide (–OH) or amide (–C=O• NH2) • Negatively charged or anionic groups such as carboxylic acid (–C=O• O-Na+)

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•

Positively charged groups such as quaternary nitrogen (–N+(CH3)3Cl-)

For example; the structure of a synthetic polymer “polyacrylate”, has only anionic or negatively charged groups, and the Partially Hydrolyzed Polyacrylamide (PHPA), has both negative and non-ionic groups. Shape of polymers in Solution The polymers are made soluble in water through association of water with the polymer. The polymer has a structure or shape in solution. The shape depends on the polymer and the degree of flexibility and rotation of the bonds. Another factor that is important in charged molecules is the interaction between the charged groups. In fresh water, the groups repel each other. This causes the polymer to be extended in a “rigid rod”-like structure. If salt is added, the electrostatic repulsion is reduced, and the polymer starts to curl up on itself. This action reduces the size of the molecule. A reduction of viscosity is normally observed. Polyacrylate, has a flexible structure, and will change with salt content. The cellulose derivative CMC (carboxy methyl cellulose) is negatively charged and will also curl up in salt. This obviously limits its application. A similar derivative, with a higher level of negative charges and sold as PAC (polyanionic cellulose), increases the solubility in water and reduces the effect of salt on the viscosity. One polymer, Xanthan gum (XC-Polymer) is stable to salt because the polymer twists into a double helix shape. This gives the molecule some rigidity, and the viscosity of the polymer is resistant to the effects of salt. Non-ionic polymers will not be subjected to this effect and will be used in brine systems. As solutions of salt will be found in some drilling situations, the response of the system to salt will be a factor to consider The initial slow response to a change in properties as the concentration of the polymer is increased is often observed in drilling mud formulation. Care must be taken not to overdose the polymer when making additions if the initial change in properties is slow.

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The viscosity will also decrease rapidly if the polymer is removed from solution, by adsorption onto solids, for example. Similarly, if mechanical degradation or microbial action decreases the molecular weight, a relatively large decrease in viscosity will also occur. Mixing different polymer types may increase polymer-polymer interaction. The resulting viscosity may be greater than the sum of the viscosities of the two systems. This “synergistic” effect is observed for a number of polymer systems, notably guar gum and xanthan gum. Any factor that causes the polymer molecule to shrink or coil up also reduces the viscosity of that solution. The shape of a polymer molecule containing ionized groups (such as CMC and partially hydrolyzed polyacrylate) changes in size from a rigid rod to a collapsed coil in higher concentrations of salt. This reduction in size also reduces the viscosity. Not all polymers exhibit viscous properties that are salt sensitive. Non-ionic polymers such as hydroxyethyl cellulose (HEC) or guar gum do not exhibit these effects. Neither does xanthan gum, due to its unique molecular structure. Polymers may also react with solids, such as bentonite or fine drilled solids, to increase the viscosity by increasing the clay-clay interactions. High molecular weight polymers have the physical size approaching that of the clay particles themselves. Therefore, they can form a bridge between particles by adsorbing onto more than one clay particle. Only low concentrations of polymer are required. Polymers Used in Drilling Muds Polymers are identified by such features as charge character, molecular weight, and shape of the solution in water. How a polymer is used is related to its properties.

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The following table summarizes the polymers used in formulating drilling fluids. Organic Polymers Used in Water-based Drilling Muds Polymer Chemical Character Functions Carboxymethyl Cellulose (CMC) High Viscosity CMC

Cellulose derivative linear No gels or viscosity at low polymer. Anionic COO-groups. shear rates High molecular weight

Low Viscosity CMC

Different degrees of purity

Fluid loss control

Polyanionic Cellulose (PAC)

Cellulose derivative similar to CMC but with more anionic groups. Always sold in pure, salt-free form

Better stability than CMC towards calcium salt and temperature. Viscosifier, and fluid loss control agent

High Viscosity PAC High Viscosity PAC Hydroxy Ethyl Cellulose (HEC)

Polysaccharide, polymer. Non-ionic group, High MW

linear Viscosifier, particularly for ether brines. No gels or viscosity at low shear rates

Carboxy Methyl, Hydroxy Ethyl, Cellulose (CMHEC)

Cellulose derivative with non- Fluid loss and viscosity, ionic and anionic groups particularly at high temperature and high calcium

Guar Gum

Polysaccharide.

(natural plant gums)

Branched High MW

Non-Fermenting Potato Starch

Polysaccharide, Highly Fluid loss in salt solutions branched. Normally non-ionic or anionic

Xanthan Gum [XC-Polymer] (fermentation products)

Branched complex Viscosifier, particularly in salt polysaccharide. High MW water and brines and where suspension properties are required

Polyacrylate

Low molecular weight

Thinner, Deflocculant

(Polymer of acrylic acid)

High molecular weight

Flocculant , Bentonite extender

High MW Synthetic Polymer

Co-polymer of acrylic acid and Flocculant & Shale stabilizer acrylamide

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Viscosifier Cross linked

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2.0

WATER-BASED DRILLING FLUIDS This section will describe the formulation, application, advantages, and disadvantages of water-based drilling fluids in general terms and for specific muds. 2.1. Bentonite Mud Drilling fluids used to spud and drill the upper hole sections are typically formulated with fresh or brackish water. They often get many of their properties from dispersed drilled solids and bentonite flocculated with lime. These systems would not normally be weighted to above 68 lb/ft3. In Shaybah field, up to 75 pcf is needed for controlling the UER high-pressure water zone. The flow properties are maintained with water and lime as a flocculant after prehydrating and dispersing the bentonite in freshwater. The fluid loss is controlled by the addition of bentonite and modified potato starch. A typical spud mud formulation for surface hole is as follows:

A Typical Formulation of a Fresh-Water Bentonite Drilling Mud Constituent Fresh water

Amount 1 bbl

Soda ash (reduce total hardness to 200mg/l)

0.25 – 1.00 lb

Bentonite (allow hydration time)

15 - 30 lbs

Lime (for pH, and flocculation)

0.25 - 1 lb

Or Caustic soda (for pH, and dispersion) 1 Modified Potato Starch (for filtrate and filter cake control)

0.25 - 1 lb

2

HEC (for additional viscosity at low temperature polymer)

Barite or CaCO3 (for density)

1. 2.

2 - 4 lbs 1 - 2 lbs As required

To reduce the filtration rate and wall cake thickness when needed for temperatures below 220ºF. To stabilize the viscosity, specially when the prehydrated bentonite is added to brackish water, seawater, or saturated brines

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Within the limitations of the system, treatments are straightforward and may be summarized as follows. •

Solids: Excessive concentrations of solids can produce unacceptable high densities, high viscosity and gel strengths. This can lead to an excessive consumption of chemicals. The mechanical solids removal equipment and dilution are used to minimize the undesired solids content in the mud.

•

Viscosity: The plastic viscosity is decreased by water additions and increased by bentonite and solids. The yield point and gel strengths are decreased by the addition of water and / or deflocculant and increased by bentonite or polymers.

•

Fluid Loss Control: Often properly hydrated and dispersed bentonite alone will give a fluid loss rate in the region of 12 ml/30 min API. If lower levels are required, use modified starch.

The following trends should be analyzed when running bentonite muds: • • • • • • • •

• •

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Mud weight or solids tend to increase rapidly. pH 9 -11 requires continual addition of lime or caustic soda. Water loss may deteriorate due to drilled solids contamination. Gel strengths becomes low and causes poor cuttings suspension. Carrying capacity and lifting is not sufficient at YP less than 10 lb/100 ft2. Alkalinity is maintained with lime to remove any CO2 contamination. Excessive dilution increases consumption of chemicals, such as barites. The uninhibited nature can promote the hydration, or swelling, of water sensitive shales. This may cause heaving or sloughing conditions, balling of the bit or the formation of “mud rings”. Dispersion of the clays can lead to severe hole erosion, which will produce problems in directional drilling and cementing of casing. The uninhibited nature may disperse or mobilize clays in sandstone reservoirs, impairing the production of oil or gas. Drilling rates are slow due to high solids in hard rock formations.

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2.2

Lime Treated Muds Calcium ions can inhibit hydratable formation clays in the Wasia section by exchanging with the sodium ions in the formation clays. This produces a hydrated but nonexpanding complex with a much reduced volume of entrained water. The calcium ion competes very effectively for sodium. It only has to be present in relatively low concentrations of 500 to 2000 mg/l calcium ion. An advantage of this type of mud is the stability to calcium in the form of anhydrite and cement. The calcium is maintained in solution by either adding lime or gypsum. Since these salts have only a limited solubility in water, they may be maintained in excess to replace the calcium ion as it is used up in the exchange process. Lime muds are available in three concentrations: •

• •

Low-lime, low-alkalinity muds are used for higher temperature applications and high mud weight. (Filtrate alkalinity, 0.8 to 2.0 ml / Excess lime, 0.2 to 1.0 lb/bbl) Medium-lime, most commonly used. (F. alk., 2 to 5 ml / Ex. lime 2 to 4 lb/bbl) High-lime, most inhibitive. (F. alk., 4 to 8 ml / Ex. lime, 4 to 10 lb/bbl) Calcium Hydroxide is only partially soluble. The dissociation of lime is decreased by the addition of sodium hydroxide, and the level of calcium ions can be adjusted. The level of alkalinity is measured by acid titration of the filtrate. Potassium Lime Muds: Potassium lime muds use KCl and potassium hydroxide instead of sodium hydroxide for pH. This provides additional inhibition from the potassium ion. The mud is referred to as the KLM system and should be formulated without bentonite or clay dispersants. Caustic soda, soda ash, sodium bicarbonate, and lignosulfonate should not be used in this system. This system is used for drilling the water sensitive sections of the Central Area and the pre-Khuff formations in the deep exploration wells.

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Basic Formulation of a Potassium-Lime (KLM) Drilling Fluid 1 bbl Freshwater 0.01 gal Defoamer (non-toxic) 0.5 – 1 lb Xanthan gum (XC-Polymer) Modified Starch 2 – 4 lbs Potassium Chloride (KCl) 12 – 15 lbs Potassium Hydroxide (KOH) 0.5 – 1 lb Lime Ca(OH)2 0.5 - 1 lb CaCO3 “Fine” (for filter cake build up) 5 – 10 lbs CaCO3 “Fine” (for density up to 100 pcf) As required

The low-lime mud systems are less susceptible to high temperature solidification because of its low clay content (4 – 8 lb/bbl) and low alkalinity. If its alkalinity is kept low, the mud can tolerate high temperatures and high calcium, which is usually encountered while drilling the Jilh formation. Sodium sulfite is added to remove the oxygen and minimize the polymers oxidation. When the static bottom hole temperatuer reaches 280ºF, the starch is phased out and polyanionic cellulose (Drispac or PAC) is used instead. However, the mud usually require the addition of high temperature deflocculant such as ThermaThin, and high temperature filtrate control polymer such as ThermaCheck to control the fluid loss and cake thickness. Surfactants, effective in high calcium mud, are also used for stabilizing the drilled clay aggregates and prevent their dispersion in the mud system. The low-lime muds are the most practical and economical mud to use when large sections of gypsum or massive anhydrite are to be drilled, and formation salt water flow with acidic gases are encountered. These areas generally require low weight mud systems with no chemical treatment and low solids concentrations. High, flat gel strengths may exist, but being fragile gels, they are generally not too objectionable. If the gel strengths become excessive, regular chemical treatment with deflocculant will restore it to normal. The carbonate sections (limestone and dolomite) drilled in Saudi Aramco’s fields have high carbon dioxide (CO2) and Hydrogen sulfide (H2S). The lime treated mud proved to be the most effective and economical system to use in this environment.

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2.4

Advantages ¾ Easy to prepare and maintain. ¾ Low cost inhibitive system for reactive, water-sensitive shale formations. ¾ Calcium inhibitive system for high temperatures. ¾ Tolerant to contamination from salt, anhydrite, cement, and carbon dioxide. ¾ Stable, low viscosity at high mud weights and high solid levels. ¾ High resistivity for good log results. ¾ Good cement bonding logs.

3.0

OIL-BASED DRILLING FLUID Oil-based drilling fluids best meet the design requirements of a mud, mainly because they will not react with rock. The hole will only be subjected to the mechanical stresses for stability. Also, the cuttings are stable when they come to the surface, so they can be easily and efficiently removed at the surface. The mud also forms an impermeable filter cake and provides good lubricity. The inertness makes the mud stable to contaminants and makes it easy to run. The formulation and operation of this “ideal” mud are unique. In some muds, when oil is the main component with less than 5% water, the mud would be called an oil-based mud. The most common type of mud used today, is formulated with at least 5% water as an emulsified phase and is called an invert emulsion mud. Water not only adds to the viscosity and fluid loss control functions but also reduces the fire hazard of the mud.

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Components and Properties An invert emulsion mud consists of a mixture of oil and water. Oil and water are incompatible fluids but can be mechanically mixed under high shear to form emulsions where one phase exists as small droplets (dispersed phase) in the other phase (continuous phase). Invert emulsions consist of water droplets in a continuous oil phase and normally contain higher volumes of oil.

Water

Oil Water Water Water

Mechanically Formed Water-in-Oil Emulsion Such emulsions are unstable because the droplets will collide to form a larger droplet. The instability is due to the much stronger polar interaction between water molecules than between water molecules and oil, as illustrated above. The stability of the emulsion can be drastically improved by the addition of chemicals called surfactants. They have the special ability to concentrate between the oil and water phases to form a rigid skin, and so stabilize the emulsion. In practice, oil-based muds from the field are more stable than ones prepared in the laboratory. Here the solids in the mud also form at the water-oil interface and further add to the stability. Oil Phase Oil is the largest single component of the system. The chemical and physical properties of the oil influence many properties of the system, including: • • • • •

Solubility of the surfactants Viscosity Performance of the organophilic-clays Flash point Toxicity of the mud

All the solids of the mud must remain strongly oil wet and contained in the oil.

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A widely used oil is diesel oil (number 2 straight run). Diesel oil has a flash point of 165°F or above and an aniline number between 140°F to170 F. It contains a high level of aromatic hydrocarbons, which give good solubility for the surfactants and allow the organic clay to disperse easily. Diesel oil is widely distributed and readily available. The high content of aromatic hydrocarbons (20 - 40%) gives diesel oil an unpleasant odor and makes it toxic to both the environment and the operators. The so-called low toxicity mineral oils (LTMOs) are more highly refined oils that have had the aromatic fraction removed. There are over 50 different grades of LTMOs with slightly different characteristics. The performance of different oil-mud formulations (surfactants, fluid loss additives, and organo-clay) must be evaluated with any proposed oil. In order to comply with the environmental protection regulations which specifically address the disposal of drilling fluids and their associated cuttings in the Arabian Gulf, a locally produced low aromatic oil was chosen and used for formulating the oil-based mud. Laboratory tests indicated that it had an LC50 value of 180,726 ppm which was substantially less toxic than a white mineral oil used worldwide as the diesel oil substitute. All the oil mud additives were found to be compatible with the low aromatic oil and the desired mud characteristics were easily achieved The US EPA have regulated the discharge of drilling fluids from offshore drilling rigs by setting a numerical limit of three percent (30,000 ppm) on the toxicity of the fluid to be discharged. Toxicant Classification Practically non-toxic Toxic Very toxic

LC50 Value, ppm > 100,000 < 30,000 < 10,000

Regional Organization for the protection of the Marine Environment ( ROPME ) February 1990 protocol States : “Drilling fluids discharged from offshore operations must not contain persistent systemic toxins ”

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A low toxicity oil (SAFRA OIL) is used for offshore operations. Laboratory analysis indicated that the Safra oil is almost identical to mineral oil.

Mineral Oil Safra Oil Specific Gravity 0.7967 0.7896 o Flash point, F 165 179 Aromatics 99 Olefeins Nil Nil Sulfur < Det.limit < Det.limit Kin-vis at 70 oF,Cst 2.16 2.21 o 120 F,Cst 1.45 1.476 212 oF,Cst 0.79 0.800 Aniline point,oF 173 168

Diesel Oil 0.8398 159 30 - 50

1 wt% 4.84 2.56 156

Saudi Aramco’s Industrial Hygiene concluded that the health hazard rating of the Safra oil was H-1 (slight health hazard). The recommended exposure limit for this oil on a time weighted average (TWA), according to Fisher Scientific material safety data sheet (MSDS), is 100 mg/m3. At this exposure level, the low-toxicity Safra oil causes irritation and only minor, reversible injury. Diesel Oil No.2 has a TWA of 5 mg/m3 and is classified H-2, a moderate health hazard, i.e. one which can cause temporary incapacitation or injury on intense or continued exposure. Property TWA, mg/m3 Health hazard rating Fire hazard rating Reactivity rating Flash point,°F

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Diesel No.2 5 2 2 1 165

Low-Toxicity Safra oil 100 1 2 1 179

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Water Phase The shales being drilled can develop very strong adsorption forces that can draw the water out of the emulsion. Water has a very low level of solubility in oil and, thus, can escape from the droplet into the oil. If the adsorption forces for the water are greater than the forces keeping the water in the droplet, then the water will wet the shale. These forces are countered by using brine as the water phase. The water content of invert emulsion muds is normally less than that of the oil content. The solids in the mud are normally in the oil phase and the surfaces are oil wetted rather than water wetted. Emulsifiers Emulsifiers are surface-active molecules (surfactants) that orient themselves between interfaces of incompatible liquids or surfaces and lower the surface or inter-facial energy or tension. A common example is soap. The chemical structure of these surfactants is characterized by a special molecule that has both a hydrophilic or water loving “head”, which is polar and ionized, and an organophilic or oil loving “tail”. The properties of surfactants are determined by the chemical nature of these two groups and the relative ability of these two groups to either pull the molecule into water so that it is water soluble, or to pull the molecule into oil so that it is oil soluble. The surfactants used to make oil muds are oil soluble. Surfactants concentrate at interfaces between incompatible surfaces and lower surface energy or tension. The oil soluble invert mud surfactants position itself at the interface forming a skin around the emulsified dispersed phase. The rigid skin prevents droplets from coalescing and breaking when colliding. Special surfactants (oil wetting agents) are also added to react with the surfaces of the minerals barite and clay to make them oil wet. 3.1

Balanced Activity Balanced activity occurs when the formation’s thirst for water is equal to the oil-based mud’s thirst for water. Shale Activity The forces for the adsorption of water are complex and very powerful. The important contributing factors, identified by Mondshine and Chenevert, were: • • •

Mineral composition of the shale Salinity of the pore fluid Inter-granular or confining stress of the shale

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The concept of shale activity can be explained by imagining a situation where shale could be sampled at depth and the confining stress can be kept on the sample. The sample is then brought up to the surface and placed in a closed container. As the stress is removed, shale expands, and the water in the shale will eventually reach equilibrium. The greater the adsorption forces, the lower the concentration of water vapor in equilibrium. This water vapor concentration is expressed as a percentage of the saturated water vapor of pure water and can be measured by an instrument called a hygrometer. The measured value for the shale is called the “activity”. Formation clays such as montmorillonite and illite have a very strong adsorption of water. High salinity pore water creates osmotic adsorption. The inter-granular stress relates to the work that has been done in expelling the water from the clay surfaces. The activity of the shale can be calculated from knowledge of the inter-granular stress and pore solution salinity. It is typically 0.75 to 0.85 for tertiary shales to 0.60 for shales at greater depth. Activity of Brine When salt is added to water, it lowers the number of water molecules in the vapor phase due to close association with the ions, particularly the cation. Thus the “activity” of the water can be reduced from 1.0 to 0.75 by saturation with sodium chloride and to 0.34 by saturation with calcium chloride. In practice, the use of calcium chloride brines (350,000 mg/l) is preferred. These brines allow adjustment of activity over a wider range, and the calcium ion is compatible with the salts of the surfactants. Factors Determining Oil/Water Ratio The minimum quantity of oil in the mud will depend on the mud density. The oil content should increase as the mud density increases to provide room for the solids. The normal ranges of oil to water ratios for different mud weights (solids contents) are as follows:

Relationship Between Mud Weight and Oil-water Ratio

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Mud Weight PCF

Mud Weight SG

Oil/WaterRatio

62-75

1.00-1.20

50/50

75-82

1.20-1.32

65/35

82-95

1.32-1.50

70/30

95-105

1.50-1.68

75/25

112-120

1.80-1.92

80/20

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Oil Determination in Mud Since low toxicity oil is expensive, accurate measurement of the ratio of oil to water in the mud is very important. Changes in the ratio will give important indications of changes in the mud properties, for example, an invasion of formation water due to an imbalance in the activity of the brine phase or a brine flow. The mud is retorted to distill over the water and oil, leaving the solids and salts. A large 50-ml still should be used. Viscosity Control Viscosity control in oil-based muds is potentially more difficult than in waterbased muds because the strong polar interactions and ionic bonds are eliminated in the continuous oil phase. The bonds between components in oil are very weak hydrogen bonds, which are very easily broken with thermal energy. Therefore, viscosity tends to decay rapidly with elevation of temperature. To resolve this problem, bentonite treated with organic cationic surfactants is used to displace the inorganic ions (calcium and sodium) and make the clay wettable by oil rather than water. This allows the organo-clays to disperse in the oil. Water plays an important role in fully developing viscous properties. Water wets the edges of the clay platelets so the clays can associate through polar edge-to-edge bonds. The viscosity in field muds is controlled through the use of organo-clays to increase the low shear viscosity (yield point and gels). The grade of organoclay should be tested further with the type of base oil to be used. Adding a very small stream of water when the organo-clay is mixed with the mud is sometimes advantageous. The plastic viscosity will increase as the weight of the mud and the water content increases. Oil soluble polymers have been recently introduced to control viscosity. These polymers may have application in muds with high oil content or in high temperature conditions. The influence of temperature on the viscosity of oil-based muds is much greater than with water-based muds. The viscosity/temperature profile has a much greater gradient due to the weak nature of the bonds in oil-mud systems. Care must be taken to measure the rheological properties at a defined temperature that is close to the downhole parameters.

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The mud is subjected to significant pressures downhole. These pressures compress the mud, forcing the components closer together and increasing the viscosity. This effect tends to compensate for the loss of viscosity due to the higher temperatures downhole. In critical wells, the pressure/temperature profiles of viscosity should be determined on a high temperature/high pressure viscometer. Fluid Loss Control Fluid loss control is a measure of the ability of the mud to lay down an impermeable filter cake that can retain the fluid fraction in the wellbore and minimize the buildup of a thick filter cake.

Colloidal Size Emulsified Water Droplets

Oil-based Mud

Oil Wet Solids Build Mud Cake All Oil

Filtrate

Wall cake build up Invert emulsion muds can either be formulated so that this property is well developed or poorly developed. Invert mud with well-developed fluid loss control has an important advantage in preventing differential sticking when drilling overbalanced into production sands. In cases where a low fluid loss would drastically lower the penetration rate, the mud can be formulated so that the fluid loss is as high as that of a water-based mud. The many sub-micron sized water droplets, surrounded with surfactants, act as colloidal particles to seal the filter cake. The tiny droplets are repelled from the oil wetted filter cake built up from the oil wet solids, such as barite, organo-clay, fine drilled solids, and oil wet solids specifically added to improve the oil wet character of the filter cake. Thus, the fluid loss is low. The filtrate will only consist of oil if the emulsion system is well developed with the correct concentration of surfactants.

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The concentration of the surfactants in the oil filtrate is likely to be much lower than in the whole mud because they are closely associated with the water phase and the solids. This ensures that the invading filtrate will not alter the wettability of the formation and so cause formation damage. The repulsion of the oil from a water wet capillary will also contribute to a lowering of the fluid loss. The fluid loss test of an oil-based mud is one of the most important indicators of the stability of the emulsion. The test has to be carried out at high temperature and pressure in order to obtain a measurable level of filtrate. The temperature is normally about 20 F higher than the bottomhole temperature and at 500 psi pressure. This description of the fluid loss mechanism shows that emulsifiers play an important part in repelling the water from the filter cake. The presence of water in the filtrate is a clear indication that the level of emulsifiers is too low. Addition of emulsifiers should be made in the same proportion as recommended in the initial formulation. This will be particularly important for muds that have a relatively high proportion of water. The permeability of the filter cake may be further reduced by the addition of colloidal oil wettable solids such as amine treated lignite. The level of addition of these “dark brown powder” will be in the region of 3 to 8 ppb. Oilbased systems used for drilling through oil reservoir rocks should not contain any asphaltic material. Asphaltic additives will contribute both to the toxicity of the oil mud and to the residual formation damage. A mud will be formulated for high fluid loss when field experience has indicated that the low fluid loss severely reduces the drilling rate. This may be observed in harder, older formations where the inter-granular cementation is very well developed. The level of emulsifiers will be restricted to the minimum required for stability, and the oil wettable colloidal solids would not be added. The API fluid loss of these formulations will be in the region of 5 to 20 ml.

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Typical Formulation of an Invert Oil Mud Components

Quantity

Base Oil,

bbl:

0.573

Primary Emulsifier,

gal:

1

Lime,

lbs:

4

Filtrate control agent “amin lignite” , lbs: Water ,

6

bbl:

Viscosifier “Organophilic clay” ,

0.253

lbs:

4

Secondary Emulsifier,

gal

0.2

Barite,

lbs:

174

CaCl2 ,

lbs:

32.3

Property

Value

Electrical Stability (volts)

1000-1200

600 Fann Reading

75

300 Fann Reading

48

Plastic Viscosity (cps)

27

Yield Point (lbs/100 ft2)

21

Gels 10 sec/10 min (lbs/100 ft2) HTHP Fluid Loss 200º F/500 psi

3.2

8/16 (ml all oil)

1.8

Rig Site Procedures The following rig site procedures for oil-based drilling fluids application: • • • • •

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Mixing Mud testing Engineering of properties Maintenance Rig preparation

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Mixing Ideally, the volume of oil-based mud will be built up completely in a separate tank rather than be built “on the fly”. This ensures that the expensive components are in the correct proportions and that the salinity and oil-towater ratio are accurately prepared. New volumes will be needed for additions to the active mud system to maintain volume due to the hole volume generated and to compensate for the mud lost with the cuttings. The ideal sequence of addition of the components is as follows: 1. 2. 3. 4. 5. 6. 7. 8.

Transfer all the calculated oil volume in the mixing tank Add the primary emulsifier Mix Lime [not in the same hopper where the emulsifier is added] Disperse the filtrate control agent “amin treated lignite” Mix for 30 minutes Transfer all the calculated water volume with the CaCl2 (CaCl2 brine prepared in separate tank ) Disperse the viscosifier “organophilic clay” Add the Secondary emulsifier Mix for 30 minutes Mix the weighting material - barite or calcium carbonate fine

This order of addition ensures that the clay is fully dispersed and the polar activator (water) is added before the secondary emulsifier. The formulation is always aided by heat and energetic mixing so maximum shear should be applied. Care should be taken to measure the components accurately to ensure that the desired properties are obtained. Mud Testing The viscosity related characteristics are measured using a Fann-35 viscometer. Oil-mud viscosity is very sensitive to temperature, so the test temperature must be defined closely through the use of a thermostatically controlled mud cup. The temperature used should be stated in the test results. The temperature is normally 120 F but should be higher if flowline temperatures or bottomhole temperatures are higher. The mud should not be tested at temperatures higher than 190°F. The fluid loss test is normally measured at elevated temperature and pressure. The bottomhole temperature plus 20°F is normally selected to make the measurements with 200 F as a practical minimum. Normally the test is carried out with a pressure of 600 psi on the top and 100 psi on the bottom to prevent the evaporation of any water that may be in the filtrate.

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If the mud is specially formulated to have a high fluid loss, then the API fluid loss test is conducted at room temperature at 100 psi. The ratio of oil to water is determined by analysis of the retort reading. Care has to be taken to ensure that this is accurately carried out. This value is used with the titration results of the aqueous phase to calculate the salinity of the brine phase. The density of the solids in the mud can also be calculated from this measurement. The stability of the emulsion is measured by applying an alternating voltage between two electrodes and measuring the voltage when 2 milliamps of current flows through the electrode. The electric current polarizes and coalesces the droplets so that they conduct electricity. This voltage is expressed as “volts for electrical breakdown”. There are two instruments designed to take the electrical stability measurement. The older version had a manual adjustment of the increase in voltage and other features that made reproducibility of the readings difficult. A more advanced instrument increases the voltage automatically and offers improved reproducibility although the readings are lower. In general, electrical stability increases as the emulsifier concentration increases. However, other factors such as oil-water ratio, viscosity, and salt content also influence the reading. It is best taken as an indication of trends. Values over 400 volts are acceptable, with readings typically in the range of 400 to 1200 volts. Engineering of Properties Typically the rheological properties of oil-based mud have higher plastic viscosities than the yield point. This is due to the higher level of solids and the low energy of interaction in the nonpolar oil environment. The yield points can be increased by the addition of organo-clay and oil soluble polymers. Increased water content will have the same effect if the ratio of water to oil does not exceed 50/50. The viscosity is very sensitive to temperature. Properties must be measured at a fixed temperature (120 °F) or higher, as appropriate. Viscosity is reduced by the addition of oil and strong oil-wetting surfactants (oil-wetting agents). The fluid loss should be determined at elevated temperature and pressure with typical values of 2 to 5 ml for a normally formulated mud. The relaxed fluid loss muds will have a measurable fluid loss under API conditions of 5 to 15 ml, which should be all oil.

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Water in the filtrate and increased surface mud volumes are both important indications that the emulsifier strength is low. The water content and solids content should be checked to determine whether there was an influx of brine or solids. The initial treatment would be to increase the emulsifier concentration. The ratio of water to oil and the salinity of the water phase should be constant. If the water content is decreasing and the cuttings are water wet and sticky, then calcium chloride should be added. If the activity is too low, then the mud will extract water from the shale to establish an equilibrium with the shales. The alkalinity of the mud is maintained by the addition of an excess of lime. If the alkalinity falls, there may be an invasion of hydrogen sulfide (H2S), carbon dioxide (CO2), or a magnesium-rich brine. Lime must be added to restore the alkalinity. Checks should be made to determine the level of water wetting. Maintenance Oil-based mud maintenance is much easier than with water-based muds. This is mainly because the drilled solids are building up slower in the mud. The properties, therefore, stay much more stable. Maintenance essentially requires new volumes to replace the volume of the new hole and the mud removed with the drilled solids. The fluid-loss test is the most indicative test of changes in emulsifier level. A change in the fluid loss and, particularly, water in the filtrate, is a good indication that the emulsifier level is becoming depleted. The treatment should be with the range of emulsifiers normally used. The total water content of the mud should be carefully monitored, and additions of new volume should be made as accurately as possible, to ensure that the water activity of the brine is correct. Oil-based muds can apparently run with very little problems and tend to be neglected. However, if the neglect leads to a water wet situation, the consequences can be DISASTROUS. Barite will settle, mud density will be reduced, and the hydrostatic head will be lost. Well control problem will develop or a BLOWOUT.

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Rig Preparation A number of operational aspects of oil-based muds are quite different from those of water-based muds. The following issues should be of major concern: ¾ The rubber components in the circulating system (Hydril rubber hoses, pump seals, impellers, etc.) need to be changed to a grade that is stable in the oil used for preparing the mud. Check and verify the rubber quality through the Lab R&D Center. ¾ Water additions to the mud need to be controlled strictly. The mud tanks may need to be covered to minimize rain water contamination. The tanks may need to be covered and additional ventilation added to minimize vapor and misting problems. Oil wastes and run-off from the drill floor and cellars need to be collected and contained. ¾ Oil-based mud viscosity changes with temperature considerably more than that of water-based mud. Thus, when cold, it is very viscous and may be difficult to pump. Care should be taken not to lose the mud over the shaker screen. 3.3

Systems Problems/Solutions Oil-based mud system problems and recommended solutions: • • •

Unstable Emulsions Water Wet Solids Cement Displacement

Unstable Emulsions The emulsion can become unstable if the emulsifiers concentration used is not effective or too low for the level of solids and water or brine in the system. This may be the result of too little addition or due to water influx and solids build up. Usually this problem occurs when weighting the mud up fast. A change in the water content from the retort test data and a decrease in the electrical stability (voltage readings) are indicators that the emulsifier level is too low. However, the most sensitive indicator is the presence of increased levels of water or emulsion in the filtrate.

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Water Wet Solids All the solids in the mud are in the oil phase. The solids and minerals surfaces are treated with surfactants so that they can remain strongly oil wet. This keeps viscosity effects of the solids low so that high levels of weighting materials and drilled solids can be easily incorporated into the mud. The most serious problem that can befall an invert emulsion is for the emulsion mud to “flip”. This happens when a mud converts from an oil-continuous fluid to a water-continuous mud. The solids become water wet quickly and adhere to each other. The solids may clump together and be removed by the shaker screen. Barite is a particular problem. Because barite is present in large quantities, it will contribute significantly to the requirement for oil-wetting surfactants. The mud will most often “flip” when there is a rapid change in composition. For example, flipping can occur during rapid weighting-up of the mud without the addition of an oil-wetting agent or during rapid drilling of a wet shale sequence. The condition is treated by the addition of oil-wetting agents, secondary emulsifier, and additional oil. The situation is best avoided by paying attention to the mud condition and adding surfactants to maintain the emulsifier level recommended in the initial formulation. Sometimes it is more economical to dispose of the mud than treat it. Cement Displacement Oil-based muds usually drill a gauge hole that can significantly improve the efficiency of the displacement of mud by the cement. However, for a good cement bond to take place, the cement crystals must grow into the formation and steel surface. This process will not be favored in oil-wet pores, so the oil mud must be removed and the rock and the metal surfaces should be cleaned with a water-wetting surfactant prior to the cement. 3.4

Advantages/Disadvantages of Using Oil-Based Mud Oil muds, like other drilling fluids, must be properly applied to derive all the benefits associated with them. There are obvious advantages in using these systems, or they would have ceased to exist in the industry. Likewise, there are disadvantages that limit oil mud use to those applications where it is best suited.

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Advantages Lubricity; Torque and drag problems due to deviated wellbore, crooked hole, and side-tracks can be reduced considerably by the use of oil muds. Since oil is the external phase, the bore hole and tubulars are exposed to a much better lubricating fluid than any water mud can provide. Temperature Stability; Oil muds have application on wells with high bottomhole temperatures. Oil muds have remained stable in wells with a logged bottomhole temperature (BHT) of 585 F. Shale Stabilization; A properly conditioned oil mud should have no effect on a shale formation. Therefore, a gauge hole can be drilled through watersensitive shales. Resistance to Chemical Contamination; Carbonate, evaporite, and salt formations do not adversely effect the properties of an oil mud. CO2 and H2S can be easily treated out with lime. Improved Screening with Shale Shakers; Since drill cuttings are inert to oil muds, they remain more competent. Therefore, the shakers remove a higher percentage of solids than is possible with water-based muds. Solids Tolerance; Because drill solids are inert in an oil environment, oil muds have a much higher solids tolerance. This reduces dilution requirements, thereby reducing costs. Less Damaging to Sandstone Oil Production Zones; Oil muds normally have a low fluid loss when the filtrate is oil. The filtrate invades only a short distance into the production zone and causes little or no damage in the formation clays and permeability. Note, however, that Oil muds can cause sever damage to carbonate gas production zones Less Chance of Differential Sticking; Due to the thin, slick filter cake formed by an oil mud, the chance of differential sticking is minimal. Note, however, that differential sticking is still possible if drilling highly overbalanced, especially with a “relaxed filtrate” system. Drilling Underbalanced; In some instances where rock matrix strength is sufficient, drilling underbalanced to increase R.O.P. is possible when using oil mud. The advantage of the oil mud is good wellbore stability through sand shale sections.

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Re-use; Due to the excellent stability and solids tolerance of a wellconditioned oil mud, it can sometimes be used for more than one well. Although the initial make-up cost is normally high, the re-use of oil mud can actually be cheaper than water-based muds in some cases. Reduced Cement Costs; Gauge hole drilling can substantially reduce cement volume needed and costs. This can benefit in two ways; far less excess cement is required and a more constant flow regime can be achieved, giving a better primary cement job. However, cementing with oil mud in the hole can be tricky due to the vast difference in the continuous phase of the mud and cement. “Relaxed Filtrate” Oil Muds; Invert oil muds are now being run with high fluid loss and low electrical stability values. This type of oil mud is showing very high rates of penetration and has broadened the use of oil muds considerably. Low Toxicity Oil Muds; Replacing diesel in both the mud and chemicals with a mineral oil has allowed the usage of oil muds in some environmentally sensitive areas. These muds also have the flexibility of being run either conventionally or “relaxed filtrate”. Flexibility; With the advent of both “relaxed filtrate” oil muds and low toxicity oil muds, application has increased dramatically. Any size hole, any environment, and any lithology can be drilled with specially tailored oil mud. Reduction of Metal Stress Fatigue; Stress fatigue of tubulars is reduced considerably when using oil muds. Reduced Corrosion; Oil muds are not corrosive since oil, instead of water, is in contact with all metal surfaces. However, care must be taken to ensure that the CaCl2 from the internal phase does not come into contact with these same surfaces. Performance with PDC Bits; Higher rates of penetration are achieved drilling homogeneous shale formations

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Elimination of Gas Hydrate Potential; Gas hydrates, ice-like structures, form under pressure above the freezing point of water in mixtures of gas and water muds. Drilling in deep water increases the potential risk of hydrate formation due to the cooling of the mud around the BOPs by the sea water. The most suppression of the temperature of hydrate formation is achieved by additions of sodium chloride. Twenty-seven-degree suppression is achieved at saturation. Beyond this, oil-based mud is the only method of eliminating the potential of hydrate formation. Disadvantages High Initial Cost per Barrel; The oil fraction alone of a barrel of oil mud may cost US $50 to $80 per barrel. This is a considerably higher cost than most water-based muds at any weight. Therefore, initial make-up costs will be high. Low toxicity oil-based mud may cost US $ 120 to $ 370 per barrel. Slow Rates of Penetration; Oil muds historically have produced lower R.O.P.s when compared directly to water muds and rock bits. Two theories have been proposed to explain this: •

Oil muds have a higher viscosity at the bit. A greater pressure drop through the bit results in increasing the loss of hydraulic horsepower.

•

The chip hold-down effect. Normal oil muds have no spurt loss. Therefore, the chips created by the rock bit are held in place by differential pressure.

If the oil mud has a higher overall viscosity than water-based mud, which is the normal case, the ECD will be higher, therefore, reducing the R.O.P. (Note that “relaxed” oil muds have reversed this condition in some instances.) Mechanical Emulsification; To achieve the emulsion quality needed, mechanical shearing is required to supplement chemical emulsifiers. This can be accomplished by either pumping the mud at a high rate through the bit or by using a shearing device. Pollution Control Required; Because of ever-tightening environmental restrictions, rig modifications may be necessary to contain spills, clean oilmud cuttings, and handle whole mud without dumping. Burning of whole mud may also be required. Fire Hazard; Since both the base oil and oil mud made with it can burn, extra precautions are required for fire prevention. Additional gas, smoke, fire detectors, and protection devices may be necessary.

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Disposal Problems; As mentioned previously, oil mud cuttings may have to be cleaned before dumping. Some environments require that cuttings be sent to proper disposal areas. Also, whole mud cannot be dumped. Therefore, if solids need to be reduced, dilution with new mud is the only answer, which will increase the active mud volume. Oil mud volumes only increase. At some point in time, the oil mud must be disposed of. Centrifugation for Solids Control; Less Effective Oil muds have inherently higher viscosities than water-based muds. Also, the oil is compressible, which again increases the viscosity under pressure. Hydrocyclones and centrifuges have a higher cut point with oil muds. Gas Stripping; Intrusion of gas into an oil mud can cause the weight material to settle. This is a particular problem in using oil muds as packer fluids on gas wells.

Magnitude of Mud Problems; Mud problems with oil muds can be disastrous. Emulsion breakdown and water wetting are extremely costly and time consuming. Special Logging Tools; Required Electric logs do not work in an oil mud environment. In some instances, this can preclude the use of oil mud on an exploration well. Lost Circulation; Lost circulation with oil muds is very expensive. Also, the problem may not be curable. Therefore, it may not be practical to consider oil muds in possible lost-circulation zones. Effect on Rubber; Oil muds can cause either shrinkage or swelling of normal rubber parts. Therefore, it may be necessary to change out BOP parts, the Hydril, etc., to either neoprene or Buna N, depending on the base oil. Rig Cleanliness; Extra effort is required to keep a rig clean when oil muds are used. Measures such as special dressing areas and steam cleaners on the rig floor may be required Hole Cleaning; Hole cleaning is more difficult with oil muds. Some reasons for this include: • • •

Cuttings do not disperse into the mud as they do in water mud. Oil muds are more Newtonian and therefore have minimal carrying capacity. Oil muds are less thixotropic than water muds.

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Kick Detection; H2S, CO2, and methane (CH4) are all soluble in oil mud. If gas enters the wellbore, it can go into solution under pressure. As the gas moves up the hole, it reaches its bubble point and will come out of solution. If this occurs at a shallow depth, it may be too late to prevent a BLOWOUT.

Planning; In most cases, extensive planning and training are required for successful oil mud use. Rig crews should be briefed, and reporting procedures and contingency plans must be decided upon beforehand. Planning takes time, but it is essential.

3.5

Summary ¾ Oil-based muds uniquely cancel hydration reactions with the formation, especially water sensitive shales. Hydration of shales can be prevented by addition of CaCl2 to the emulsified water phase. ¾ Polar or ionic reactions are eliminated so the mud is more tolerant to contaminants that can be detrimental to water-based muds such as anhydrite, cement, hydrogen sulfide, carbon dioxide, and drilled solids. ¾ The mud is stable at high temperatures.

¾ The surfactant/water droplets act as “ball bearings” to lower the friction between the drill pipe and the wall of the hole. ¾ Fluid loss characteristics are well developed so differential sticking is minimized. ¾ The mud is expensive and different from water-based muds, so rig equipment and mud-handling practices must be modified to take this into account. ¾ The mud must be carefully maintained to ensure that the continuous phase is maintained as oil. ¾ Due to the high unit cost, the mud should not be used where lost circulation is an anticipated serious problem. ¾ The means of disposal of oil contaminated cuttings and mud must be considered and appropriate action taken.

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DRILLING FLUIDS PLANNING A DRILLING FLUID PROGRAM

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PLANNING A DRILLING FLUID PROGRAM 1.0

INTRODUCTION

2.0

DRILLING FLUID PROGRAM PLANNING 2.1 Information for Offset Wells 2.1.1 Geological Characteristics of the Formation 2.1.2 Previous Well Reports 2.2 Casing Programs 2.2.1 Pore Pressure and Fracture Gradient 2.2.2 Casing Depths 2.3 Drilling Fluid Program Preparation 2.3.1 Mud Weight for Each Casing Interval 2.3.2 Selection of Fluid Types 2.3.3 Specification of Properties 2.4 Technical and Cost Objectives 2.5 Mud Formulation 2.6 Mud Properties

3.0

APPLYING A DRILLING FLUIDS PROGRAM 3.1 Implementation 3.2 Trend Analysis

4.0

DRILLING FLUID MANAGEMENT

5.0

DUTIES AND RESPONSIBILITIES 5.1 The Foreman’s Responsibilities 5.2 The Contractor Mud Engineer’s Responsibilities 5.3 The Saudi Aramco Drilling Engineer’s Responsibilities

6.0

BASIC FIELD TESTING EQUIPMENT

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DRILLING FLUIDS PLANNING A DRILLING FLUID PROGRAM

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PLANNING A DRILLING FLUID PROGRAM 1.0

INTRODUCTION A good drilling program ensures that the essential decisions affecting its success are correctly made. The drilling fluid is a critical component during the drilling and completion of a well. At the planning stage, three factors greatly influence the success or failure of a well. They are: • • •

Establishing a casing program Determining the desired mud weights Selecting the mud types

Time spent preparing a drilling fluids program will often be repaid. The drilling operation is often critical. The boundary between success and failure may be quite small. The hole stability is often time-dependent. Therefore, time saved in drilling, perhaps by changing the bit and improving solids removal practices, may bring about other benefits apart from the obvious financial ones.

2.0

DRILLING FLUID PROGRAM PLANNING Drilling fluids programs are designed and based on a collection of information from a specific drilling area. This information comes from many sources. The selection of the appropriate drilling fluid cannot be made until all relevant information has been gathered. A comprehensive drilling fluids program anticipates potential problems. Such a program provides an engineer with the information to identify problems discovered while drilling. Seismic sections and geophysical charts provide much information and should be examined carefully. The stratigraphic tops and the approximate depth at which they will be encountered should be identified. The overall process of planning a drilling fluids program for a well include the following: • • • •

Review data from offset wells including geological information, mud recaps, and bit records Review casing programs Determine desired mud weights Select mud types

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• • •

Determine mud properties Establish important mud and solids control operational details Integrate with mechanical aspects of drilling, including hydraulics, directional drilling, and bit types

2.1

Information from Offset Wells This section will discuss information from offset wells including: • • 2.1.1

Geological characteristics of the formation Previous well reports Geological Characteristics of the Formation When designing a mud program, pay close attention to the geology of the drilling site. Information from adjacent wells and seismic sections provide a guide to the formations that may be encountered. The following procedure should be observed before deciding on a mud program. • • • • • • • • • •

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Define lithology List formation tops Characterize formation composition Estimate hardness and strength of the rocks Estimate potential to hydrate and disperse Estimate bedding plane orientation Review tectonic history to estimate direction and magnitude of stresses in the formation Locate abnormal pressure zones and determine fracture gradients Determine probable production intervals Determine temperature gradient and bottom hole temperature (BHT). Certain drilling fluid formulations are temperature sensitive. These include polymer-based systems and lime and gypsum muds. The expected bottom hole temperature may influence the choice of drilling fluid. Temperature also effects the rate of fluid loss. Generally, an increase in temperature results in greater fluid loss. This must be considered when calculating the fluid loss properties of a drilling fluid. Corrosion of drilling hardware increases as the temperature increases.

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•

The corrosion rate can double with every 55°F increase in temperature. Confirm casing points as these often correlate with formation changes and formation tops

A particularly difficult shale sequence such as the Sudair, Unayzah, and Qusaiba may justify further analysis using the techniques of XRD analysis or determination of the cation exchange capacity. This will allow a more accurate definition of the problem and show where the problems with water sensitivity may be most critical. 2.1.2

Previous Well Reports Attention should be paid to wells that have been drilled in the area of the proposed well. If there is no radical change in the geology between one site and another, then it can be expected that problems encountered in previous wells may also occur in a new well. Points that should be examined include: • • • •

• • • •

•

Time spent on well Mud type used Suitability of mud used Properties of the mud -Mud weight -Rheology (PV, YP, gels) -Fluid loss (API, HTHP) Type and configuration of solids control equipment Types of bit Penetration rates Hydraulics -Pumps and jets -Weight on bit and RPMs Hole problems -Correlation with mud composition and properties -Lost circulation -Shale problems -Differential sticking -Key seats

Causes of problems in previous wells should be analyzed carefully. These problems can then be “designed out” of future wells.

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2.2

Casing Program This section will discuss the development of a casing program including: • •

Pore pressure and fracture gradient Casing depths

2.2.1

Pore Pressure and Fracture Gradient An accurate determination of the formation pressures to be encountered is critical to the drilling operations. Abnormal pressure environments may be detected and evaluated by several methods summarized in Table 3C-1. As the table indicates, the data may be obtained before the well is drilled, refined during the drilling, and refined even more after the well is drilled and logged.

Table 3C-1, Techniques Used to Detect and Evaluate Over-pressure Source of Data Geophysical methods Drilling parameters

Drilling fluid

Drilled cuttings

Well logging

Direct pressure measuring devices

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Formation “Formation” velocity, Gravity, and Magnetics Electrical prospecting methods Drilling rate “d” exponent Torque, Drag Drilling porosity log Gas content, Flow line mud weight,“Kicks” Flow line temperature Chloride variation. Drill pipe pressure technique. Pit level, volume. Flow rate and Hole fill-up Shale cuttings. Bulk density. Methylene blue adsorption. Electrical resistivity Volume, shape and size of cuttings Electrical surveys – Resistivity – Conductivity – Shale formation factor – Salinity variations – Interval transit time – Bulk density – Hydrogen density – Thermal neutron capture cross-section Downhole gravity data Pressure bombs. Drill stem test. Wireline formation test

Time of Recording Prior to spudding well While drilling

While drilling but delayed by the time required for mud return While drilling but delayed by the time required for mud return After drilling

While well is tested or completed

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Fracture gradients can be calculated using one of three methods. • • • 2.2.2

Hubert and Willis Mathew and Kelly Ben Eaton

Casing Depths After the formation types, formation pressures, and pore pressures have been considered, the most suitable positions for the casing shoes can be determined. The number of casing strings will be decided by factors such as the depth and the required diameters of the production tubing. A mechanically competent rock should be selected for the casing shoe so that it may be cemented in to take the pressures of the next open hole. Casing intervals should try to isolate formation types on the basis of the pressure requirements or formation type that may require a particular type of drilling fluid. For example, shales may require inhibitive mud, such as a salt-polymer mud, to control hydration and dispersion. Evaporite sections often require separation. Consideration has to be given to using salt-saturated mud. If the mud is not saturated, it will be washed out. This may be tolerated, otherwise the mud should be saturated to salt. For these conditions, a minimum density of 75 pcf should be considered. If this density is too high, consideration should be given to oil-based mud. If the casing program introduces compromise situations where the mud weight will be too high or too low for the formation, problems will occur in drilling the section.

2.3

Drilling Fluid Program Preparation • • •

Mud weights for each casing interval Selection of fluid types Specification of properties

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2.3.1

Mud Weights for Each Casing Interval The required mud weight is determined by • • • •

Formation pressures Mechanical characteristics Potential for lost circulation Potential for the formation to flow

The mud weights should be very carefully chosen since weight materials can contribute 50 to 70 percent of the mud cost. If the mud weight is too high, then • • • • • •

Mud costs will be excessive Drilling rate will be impaired Potential for fracturing the formation will be greater Potential for lost circulation will be greater Risk of formation damage will be greater Risk of differential sticking will be greater

If the mud weight is too low, then • •

Problems may be caused by borehole instability Risk from fluid invasion or a blow out may be increased

When the borehole is unstable, try to distinguish between instability due to insufficient mud weight and instability due to low levels of inhibition. 2.3.2

Selection of Fluid Types Selection of drilling fluid types should be based on consideration of: • • • • • •

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Environmental factors, which will determine the list of acceptable muds Bottom hole temperatures Optimum penetration rates Formation composition and stability related to inhibitive property Availability and properties of the continuous fluid phase Producing formation evaluation to determine the potential for formation damage

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•

Availability and quality of formulation and treatment chemicals

The selection of the appropriate drilling fluid for a well must also consider environmental concerns for the area in which drilling is taking place. Care should be taken to minimize the effects of drilling on the environment by selecting nontoxic drilling additives, providing adequate disposal of waste mud, etc. Certain drilling fluid formulations are temperature sensitive. These include polymer-based systems and lime and gypsum muds. Therefore, the expected bottom hole temperature is required beforehand, as it may influence the choice of drilling fluid. Temperature also effects the rate of fluid loss. Generally an increase in temperature results in greater fluid loss. This must be taken into account when calculating the fluid loss properties of a drilling fluid. Corrosion of drilling hardware increases as the temperature increases. The corrosion rate can double with every 55 F increase in temperature. The inhibitive requirements largely determine the formulation. Freshwater muds offer the lowest level of inhibition but the lowest cost. Increased inhibition will move the mud towards the calcium-based muds and then on to the polymer muds. 2.3.3

Specification of Properties The physical and chemical properties of the drilling fluid are specified for each selection based on optimum drilling and economic performance. Of particular importance are • • • •

Rheology for optimum hole cleaning and hydraulics Filtrate loss and filter cake quality for optimum formation stability, penetration rate, and formation productivity Alkalinity and salt content for optimum mud performance and formation inhibition Solids type and concentration

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2.4

Technical and Cost Objectives The costs of individual components should be distinguished from the cost of the overall well. For example, using more expensive inhibited mud may allow a hole to be drilled quicker or casing to be set lower. Efficient hole cleaning in the larger hole sizes may require purchase of a larger diameter drillstring, installation of additional mud pumps, and more shaker screen capacity. These expensive capital items can be justified if the hole section can be drilled without any problems. A reduction in the drilling time due to fewer hole-cleaning problems brings further benefits as time-related instability is reduced. Protection of the productivity of the producing zones should also be considered. A tighter specification and inclusion of bridging agents may reduce the formation damage caused by invasion of incompatible filtrate and mud solids. Detailed drilling fluid formulation design for each hole interval The hole should be considered section by section. The mud is defined for each section. Each section should begin with a statement detailing the objectives of the mud program and an explanation of how and why the particular properties and system were chosen.

2.5

Mud Formulation General points to be taken into consideration are as follows:

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•

In areas of soft rock and high ROP, large volumes of mud will usually be required, and inhibition is unimportant. Preference should be given to inexpensive mud systems with high solids tolerance. This include bentonite / lime muds, or polymer-extended bentonite muds.

•

In areas where temperature is a problem, such as when using highdensity muds, systems with high temperature tolerance should be used. These include low clay deflocculated polymer systems (where there is close control of drilled solids content), synthetic high temperature polymer muds, or oil-based systems.

•

In medium to large diameter holes (12-1/4 inch and larger) with unweighted muds, both hole cleaning and hole enlargement are usually primary concerns. Simple flocculated bentonite systems with high structural viscosity should be considered.

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The required inhibitive properties are an essential consideration controlling the character of the mud and the formulation. The formulation should be derived from a combination of laboratory and field experience. The mud products should be closely specified so that their performance in the field is well defined. This section should specify the material concentrations (usually in lb/bbl units) of all the mud additives during the particular interval. If major variations in the mud density are expected during the hole interval, then more than one formulation should be included in the program. For example, if during the interval the mud density is programmed to increase from 10.5 to 14.5 ppg, then formulations should be given for muds with densities of 10.5, 12.0, 13.0, and 14.5 ppg. 2.6

Mud Properties In many areas, there are “standard” drilling fluid programs. Deviation from this standard system should be justified. The expected advantages and differences between the chosen mud and the standard program should be described. The rheological properties are designed as a consequence of the hydraulic considerations and the mud weight. The formulation should include only those properties considered necessary to the success of the mud program. There is no need to include all those properties listed on the API Mud Report form. It should state which properties are critically important and which properties are less important. Usually it should state the reason for controlling the property and, if applicable, how to control the property.

3.0

APPLYING A DRILLING FLUIDS PROGRAM Application of a drilling fluid program in terms of implementation and trend analysis. 3.1

Implementation The mud materials should be ordered and delivered to the rig site. The mud engineer and drilling crew should be familiarized with the aims and objectives of the mud systems and any special requirements. The solids removal equipment should be specified and installed on the rig.

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3.2

Trend Analysis During the process of drilling a well, the wellbore and the drilling fluid provide valuable information and feed back on the overall operation. Sometimes the feed back is immediate and straight forward. Other times it is subtler, and the trend can only be spotted by careful analysis of trends over a longer time period. The trends that should be analyzed include: • •

• •

• • •

Basic mud properties to see if they are changing Contaminants identified from the changes in chemical and physical properties. Mud chemical usage to see if there are deviations from the program and initial formulation Additions of water to monitor mud volumes built and to correlate with solids build up and operation of the solids removal equipment Volumes of cuttings and type of cuttings over the shaker to see if the hole is being cleaned efficiently and to detect hole failure in the form of cavings coming to the surface Tight connections, an indication that the mud weight may be too low or that the hole is not being cleaned properly Connection gas, an indication that the mud density is too low Torque and string weights on tripping, indications that the lubricity of the mud should be changed or of deterioration in the hole condition

When a trend is detected, the mud can be treated before a problem emerges.

4.0

DRILLING FLUID MANAGEMENT The Foreman is directly responsible for the daily conditioning of the mud. To deviate from the mud program as outlined in the well program, the Foreman must obtain prior approval from the Drilling Superintendent. Technical analysis and treatment of the drilling fluids may be obtained from various sources: 4.1

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A Contract Mud Engineer may be utilized with the prior approval of the Drilling Superintendent.

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4.2

Drilling Fluids Specialist, Lab R&D Center in Dhahran may be contacted for technical assistance. He can aid in locating materials, and suggesting possible mud treatments and alternative chemicals. The Lab R&D Specialist can further coordinate with the contract Mud Engineers, and with the Shedgum Mud Plant when needed.

4.3

Saudi Aramco Drilling Fluid Laboratory, Lab R&D Center in Dhahran , can provide extensive field and/or laboratory analysis of field muds and can further assist in recommending treatments for problem muds.

4.4

Saudi Aramco Drilling Engineer assigned to the rig should analyze the solids control equipment, and make recommendations to improve the rig performance.

4.5

Shedgum Mud Plant should be used to store and recycle the drilling and completion fluids. Also, pre-mix a special drilling fluid.

RESPONSIBILITIES AND DUTIES 5.1

The Foreman’s Responsibilities: A)

The Foreman will make certain that the mud type and properties as specified in the drilling program are developed and maintained.

B)

The Foreman will consult his Drilling Superintendent to determine the extent to which the various Mud Engineering Services will be used.

C)

The Drilling Foreman will personally inspect the contractor’s rig to make certain that all mud equipment as specified in the contract is on location and is operating satisfactorily. This tour will include inspecting the shale shakers to make certain that the proper size screens are in place, that the proper cone liners are installed in the Hydrocyclones and that the latter are functioning properly. The Foreman should also inspect the mud cleaner and the centrifuge (if one is installed), make certain that the mud pit volumes specified in the contract are correct, and in general, make sure that everything is ‘as it should be’. If he has any doubts concerning the solids control equipment and/or its operation, he may request assistance from Drilling Engineering.

D)

The Foreman will keep an inventory of all mud materials used in the following manner:

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E)

1.

The transfer of drilling materials is to be completed and submitted for each well (see Aramco Form # 5518).

2.

Use the daily drilling report form to state the actual amounts of materials used that day. DO NOT USE AVERAGES OVER A PERIOD OF TIME.

The Foreman will maintain a record of the following fluid properties: 1.

2.

3. 4.

5.

6.

5.2

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HOURLY: • Weight (pcf) • Funnel viscosity (Sec) TWICE A TOUR: • API water loss (ml/30 mins) • pH ONCE A TOUR: (with Mud Engineer on site) • PV / YP ONCE A TOUR: (with oil based muds & Mud Engineer on site) • Electrical stability (volts) • Alkalinity (Pm) • HTHP water loss (ml/30 mins @ 300oF and 500 psi) Daily (with Mud Engineer on site) • Methyl Blue Test (lbs. of Bentonite/bbl mud) • Alkalinities (Pm, pf/Mf) DAILY: (below 10,000 ft. with Mud Engineer on site) • HTHP fluid loss (ml/30 mins @ 300oF and 500 psi)

The Contract Mud Engineer’s Responsibilities A)

The Mud Engineer on location shall perform the standard API drilling fluid analysis at least once a day. This test will be completed on the API Mud Drilling Mud Report Form and submitted to the Foreman prior to 0500 hours. The mud engineer may be required to run more than one test a day.

B)

The Mud Engineer shall complete his own Company’s Report Form in full and shall include the flowline and suction temperature and the temperature(s) at which the PV, YP, and gels are measured. When desanders, desilters, mud cleaners, or centrifuges are in use, both the underflow and the overflow mud weights shall be recorded for each device in use. The feed header pressure will also be recorded for each device in use. The shale shaker screen size(s) and other equipment specifications are to be reported, including any non-functioning or mal-

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functioning solids removal equipment. The frequency of sand trap dumping and the total volume of mud dumped each day shall also be reported. All materials used, and the method of addition (how dispersed, length of time to disperse, problems encountered, etc.) shall be included as comments on the API Mud Report. C)

D)

5.3

The Mud Engineer shall use the Saudi Aramco rig mailing system to transfer a copy of each day’s mud report to the Drilling & Workover Engineering Division office, Dhahran. The mud engineer on location shall make all recommendations as to mud treatment in writing, using the Mud Report Form. This form will be given to the Drilling Foreman.

The Saudi Aramco Drilling Engineer’s Responsibilities A)

The Aramco Foreman is encouraged to refer any mud problems to the Drilling Engineer(s) assigned to his rig for consultation.

B)

The Aramco Drilling Engineer should maintain a current diagram of the entire circulating system with all pipes, valves, solids equipment, transfer pumps, tanks and degasser clearly marked. The make and size of pertinent equipment shall be shown. A copy of this diagram should be provided to the Foreman who is encouraged to make appropriate corrections and/or comments. This diagram could be invaluable during an emergency operation.

The Foreman is encouraged to enlist the services of the Aramco Drilling Engineer as to the performance of the solids control equipment.

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6.0

BASIC FIELD TESTING EQUIPMENT The required field tests are listed on the API Drilling Mud Report form (API RP 13G, Second Edition, May 1982 and Third Edition, February 1992). Standard field testing for water-based drilling fluids (API 13B-1, June 1,1990 &/or future revisions)

TEST

EQUIPMENT

Mud weight (density): Viscosity: Rheology & Gel Strength:

Atmospheric Mud balance and Pressurized Mud balance Marsh Funnel, Graduated Cup (one-quart) and Thermometer Six- speed Viscometer (3,6,100,200,300&600 rpm) and heated cup 220ºF

Filtration: Filtration:

Low-Temperature / Low-Pressure cell High-Temperature/High-Pressure with pressure & heating system) Retort instrument (50-cm3) 200-mesh sieve, funnel and glass measuring tube (Sand content set)

Water, oil and solids: Sand content:

Reactive Clays: Mud or filtrate pH:

Methylene blue capacity (MBT) pH meter (0-14), for 150ºF, resolution 0.1 unit & calibration solutions pH Paper (0-14)

H2S test: Alkalinity & lime content: Chloride: Total hardness Ca & Mg): Calcium, Magnesium: Calcium sulfate: Aldehyde: Sulfide & carbonate:

Hydrogen sulfide detection kit (Lead acetate paper discs) Chemical analysis kit Chemical analysis kit Chemical analysis kit Chemical analysis kit Chemical analysis kit Chemical analysis kit for monitoring the biocide treatment Garrett Gas Train and Drager tubes for low and high CO2 and H2S

Potassium above 5000 mg/l:

Chemical analysis kit for monitoring potassium ion concentration

Formulation Pilot Tests :

Pilot test kit ( balance, Hamilton beach mixer.......etc. )

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Standard field testing for Oil-based drilling fluids (API 13B-2, Dec. 1,1991 &/or future revisions) TEST

EQUIPMENT

Whole mud alkalinity:

Chemical analysis kit for oil-based mud to measure “ excess” lime. Chemical analysis kit for oil-based mud to measure chloride in the aqueous phase. Chemical analysis kit for oil-based mud. Electrical stability meter with calibration resistors / diodes. Retort instrument (50-cm3) and a hand-held calculator for. correctly performing mathematical operations detailed in the API procedure.

Whole mud chloride: Whole mud calcium: Emulsion stability: Solids content:

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SOLIDS CONTROL 1.0

INTRODUCTION 1.1 Description of Solids in Drilling Fluids 1.2 Lost Circulation Solids 1.3 Weighting Agent 1.4 Colloidal Clays 1.5 Formation Solids

2.0

SOLIDS CONTROL EQUIPMENT 2.1 Shaker Screens 2.2 Hydrocyclones 2.3 Mud Cleaners 2.4 Centrifuges 2.4.1 Centrifuging Unweighted Mud 2.4.2 Centrifuging Weighted Mud 2.4.3 Dual Stage Centrifuging 2.4.4 Centrifuging Hydroclone Under Flow

3.0

SELECTION OF EQUIPMENT AND CONFIGURATION 3.1 Design Considerations 3.1.1 Type of Formation 3.1.2 Inhibitive Properties of the Mud 3.1.3 Density of the Mud 3.1.4 Size of the Hole 3.1.5 Drilling Rate 3.1.6 Availability of Equipment 3.1.7 Dumping Restrictions 3.1.8 Equipment Selection 3.1.9 Low-Density Muds 3.1.10 High-Density Muds 3.1.11 Oil-Base Muds

4.0

PERFORMANCE ASSESSMENT 4.1 Identification & Correction of Malfunctions

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SOLIDS CONTROL 1.0

INTRODUCTION An important key to successful and economic drilling operations is the effective removal of the drilled formation solids. If these solids are incorporated into the mud, they will have a detrimental effect on many critical mud properties, such as the rheological and fluid loss properties, which in turn may adversely affect the drilling operation. The higher surface area of the fine entrained solids increases the chemical treatments such as the fluid loss additive, and dramatically increases the mud costs. Fine drilled solids build up make management of the mud rheological properties difficult. The hydrodynamic volume of the solids increases, which increases the plastic viscosity and the gel characteristics. These changes reduce penetration rates, increase circulation pressure losses, and lessen the carrying capacity of the mud. The higher solids content gives thicker wall cake, increasing the frequency of differential sticking problems. The pump parts and bit also wear out faster. 1.1

Description of Solids in Drilling Fluids The solids in the drilling fluid can be divided into lost circulation solids, weighting agents, colloidal clays added as mud additives, and drilled solids as cuttings or dispersed solids. The essential properties of solids can be described in terms of: • • • •

Size Density Shape Hardness

Consideration of both the size and density of the solids determines the type of solids removal equipment to be used. The size of the solids is usually measured in microns (µ) where one thousand microns = 1 millimeter (mm) = 0.03937 inches. The human hair is about 50 µ in diameter. The size of the solids that come to the surface range from particles measured in millimeters (mm = 1000 microns) down to clays with sizes less than a micron. Table 3D-1 gives the terms normally used to describe the particle

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size. Consideration of both the size and density of the particle determines the methods used to separate the particles.

TABLE 3D-1. Size Definitions in Drilling Fluids Size(Microns, µ)

API Name

2000

Common Name

Coarse

Large

250

Intermediate

Sand

74

Medium

44

Fine

2

Ultra fine

Below 1

Colloidal

420

1.2

Silt Clays

Lost Circulation Solids Lost circulation solids are added to prevent loss of whole mud to the formation. They are designed to bridge large pores in highly permeable sands and vugs and fractures. Essentially three types of material are added, defined as fiber (such as wood or hair), flakes (mica, cellophane), and granular (walnut shells, marble chippings). The size ranges are summarized in Table 3D-2.

TABLE 3D-2. Size Ranges of Lost Circulation Material Material

Size Range (µ)

Cellulose fiber

2 - 200

Ground marble

2 - 600

Mica flakes

150 - 1,200

Walnut

150 - 4,800

Marble chips

2,000 - 5,000

The addition of these materials to the mud can seriously affect the performance of the shaker screen by blinding it. If so, the screens may have to be by-passed.

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1.3

Weighting Agent These solids are intentionally added to the mud to increase the density of the finished mud. The range of materials that may be added, the density of the material, and the maximum mud weight is summarized in Table 3D-3

TABLE 3D-3. Weighting MaterialsUsed to Increase Mud Density Material Calcite & Dolomite

Specific Gravity

Maximum Mud Weight

2.70 – 2.78

1.40 SG

110 pcf

3.74

2.28 SG

142 pcf

Barite

4.2-4.3

2.65 SG

156 pcf

Illmenite

4.5-5.0

3.11 SG

190 pcf

Hematite

4.7-5.05

3.11 SG

190 pcf

Galena

7.4-7.7

3.6 SG

220 pcf

Siderite

The selection of the material will relate to the required density. Barite is most widely used above a density of 1.2 SG (74 pcf). Calcium carbonate is used as an alternative for low density muds. Iron oxide, such as hematite, are used for higher density fluids and in oil muds over 1.8 SG (112 pcf). The size ranges of the weighting agents is in the range of 10 to 80 µ, and the median size is in the range of 12 to 16 µ. The level of coarse material (above 50 µ) is limited to about 10% to minimize losses in desander/desilter units. The level of fines (less than 10 µ) is limited to about 20 to 30% to minimize problems with the rheological properties of the mud, such as excessive plastic viscosities, yield points, and gels. Solids removal techniques, such as hydrocyclones and centrifuges, depend on gravitational forces that are related to the size and density of the particle. Even though barite is approximately twice as dense as drilled solids, a smaller barite particle will be removed with the same ease as a larger formation solid. This mixture of particles with different size ranges and different densities makes efficient separation impossible. The use of more than one type of weighting agent should be avoided for the same reason.

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1.4

Colloidal Clays Bentonite clay is specifically added to derive viscosity with minimal solids increase. Bentonite provides filter cake quality and will break down or disperse to fine plate-like particles. Accumulation of colloidal-sized drill solids is detrimental to the mud. •

Increase in chemical treatment costs

•

Cause poor filter cake quality

•

Create greater risk of differential sticking

•

Decreased drilling rate in hard formations

Bentonite treated with fatty quaternary amines is used to derive viscosity in oil-based muds. Clays can also be derived from the drilled solids, particularly when drilling dispersible, young sedimentary rocks that contain significant quantities of montmorillonite. Such clays often do not have the desirable properties to form good filter cakes. The main means of removal of clays is through disposal of the mud. 1.5

Formation Solids The formation solids enter the mud system mainly as the result of bit action, but hole erosion as colloidal particles and cavings may be significant in certain formations and mud types. The size of the drilled solids will depend on a number of factors. • • • • • •

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Type of formation in terms of mineralogy, porosity, and hardness Type of bit – large in medium-soft formation and tends to get smaller as shale gets harder Degradation of shales by dispersion forces to colloidal size clays Mechanical degradation in annulus Specific density – grain density 2.6 (sand) - 2.7 (calcium carbonate) Bulk density of shales ranging from 1.7 to 2.5 depending on degree of dewatering

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The solids removal equipment will be directed towards removing the formation solids. Figure 3D-1 reviews the size range of the particles. This highlights the main problem of solids removal, which is the overlap of the sizes of undesirable drilled solids with desirable weighting agents and colloidal bentonite

PERCENT SIZE RANGE

25 20 15 10

Drilled solids

5 Barite

Bentonite 0 0.01

0.1

10 8µ

100

SHAKER

40µ 25µ

1000

74µ

Centrifuge Mud Recovery

Centrifuge Barite Recovery

Desander Desilter Microclone

FIGURE 3D-1. Size Distribution of Typical Solids in Drilling Mud And Size Range of Solids Removal Equipment

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2.0

SOLIDS CONTROL EQUIPMENT The following types of solids control equipment and the characteristics of this equipment. • • • • 2.1

Shaker screens Hydrocyclones Mud cleaners Centrifuges Shaker Screens Shale shakers are the most cost-effective pieces of solids control equipment. They are absolute gauges, allowing no solids larger than the largest, screen hole opening to pass through the screen. Shakers are positioned so they can process the mud first as it comes out of the flowline. This is the most effective place for removing solids before they are broken down any further by agitation or centrifugal pump action. Screening provides a relatively low cost method of primary solid removal. For proper use of the shakers: • Shear thin the drilling mud so it flows better • Clear the holes in the screen • Move the solids across the screen Circular motion shakers have a higher capacity for handling solids than the other types of motion. This type of shaker moves solids rapidly with less drying of the solids than with other types of shaker. Therefore, circular motion shakers have a wetter discard than other motion types. The main application of circular motion shakers is in large diameter holes and high penetration rates with fairly inexpensive mud. The motion pattern handles the high solid load well, and the low mud cost makes the relative wetness of the discard tolerable. Circular motion shakers are poor choices for drilling small holes and low penetration rates. Other motions are capable of handling the low solid load. The low solid retention time causes too much expensive mud to be lost with the solids. The elliptical motion shakers move solids off the mud entrance end quickly, but the reverse motion on the solid discard end causes the solids to be driven back onto the shaker. This motion is compensated by a downward slope of this of this portion of the screen deck. The effect of the deck angle is only slightly greater than the effect of the reverse motion. This causes the solids

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to move very slowly on this portion of the screen. The high retention time on the screen dries the solids out more than other types of motion. If expensive mud is used, this additional dryness is cost effective. Straight line or linear motion shakers do not move solids as far on each stroke as do circular motion shakers. They cannot, therefore, handle high solids loads as well. The elliptical motion shakers retain cuttings longer than straight line shakers, so the cuttings are wetter from straight line shakers. The straight line shaker is theoretically more efficient at forcing liquid through the screen than other types of motion. The wire mesh screen is a key element in the screening operation. It can be defined in terms of Opening size • Range of size openings • Median cut point • Open area of screen or conductivity • Mechanical durability of the screen • Modern multilayer screens and bonded screens have improved the life of the screen. The major cause of early failure is improper tensioning during installation. The finest screens that drilling conditions and available equipment will permit should be used. Weighting agents are ground fine enough to pass through a 200-mesh (74-µ) screen so their removal is minimal. See Table 3D-4 for details. Screens finer than 200 mesh should not be used on weighted muds because large quantities of barite or hematite will be lost.

Table 3D-4 Opening Widths of Mesh Screens Mesh Size

Opening Widths (micron)

Mesh Size

Opening Widths (micron)

Mesh Size

Opening Widths (micron)

8

2,463

20

863

100

140

10

2,108

30

515

120

117

12

1,524

40

381

200

74

14

1,229

50

279

250

60

16

1,143

60

234

325

44

18

965

80

178

The following guidelines apply to the operation of shale shakers.

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Screen mesh size should be fine enough for mud coverage of 75 per • cent of the surface area. If mud is being dumped due to excess volume or high drilled solids content, slight mud losses over the screen can be tolerated. Mud lost in this manner will have a higher drilled solids content than the rest of the mud in the active system. The shaker should be level and tack-welded to the pits or its own • support structure. Provide the proper voltage and frequency for the drive motor. Low line • voltages reduce electrical system life. Be certain the vibration is rotating in the proper direction. The top of the • shaft should rotate towards the solids discharge end. •

Take special care to install proper and clean screen-support cushions.

Take special care to tension screens properly in accordance with • manufacturer’s recommendations. Improperly tensioned screens last a fraction of their expected life. A water hose should be available in the shaker area so the screens can • be washed and inspected during trips. A water spray is occasionally used on shaker screens to remove • gummy particles (gumbo) from the screen. It should not be used routinely. Water from the spray dilutes the mud and drives smaller particles through the screen that would have otherwise been removed. Never bypass the shaker even during a trip. Bypassing the shaker • allows slugs of large solids past the shakers and into the system. These will plug the equipment downstream.

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2.2

Hydrocyclones Hydrocyclone is a generic term for the equipment referred to as “desanders” or “desilters”. A hydrocyclone develops centrifugal forces by circulating the fluid in a circular path.

Feed chamber (actual diameter of cone at this point)

Slurry rotation develops centrifugal forces in cyclone Solids are driven to the wall and are moved downward in an accelerating spiral

Solids discharge

The mud is pumped by centrifugal pumps to enter the cone tangentially near the top of the cone. The spiral motion generates centrifugal forces that throws the larger, denser particles to the outside of the cone, which are then discharged at the bottom. A hollow cylinder, called the vortex finder, extends from the top of the cone and forms the overflow for the cleaned mud. The diameter of the cone, the feed rate, pressure, mud density, the relative diameters of the solids discharge opening, and the vortex finder are all critical parameters that determine the performance of the hydrocyclone. The effect of solids is to reduce the cut point of the hydrocyclones. Therefore, the number of cones and pump rate are ideally set at about 125% of the mud flow rate so that the cleaned mud can dilute the incoming mud. The size of a hydrocyclone determines its flow capacity and the size of the solids that it can remove effectively. The relationship between hydrocyclone diameter and cut point is shown in the following table (3D-5):

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Table 3D-5, Specifications of Hydrocyclones Size (inch)

Volume (gpm)

Micron Cut Point (µ)

Desanders

12

450

100

Desanders

8

200

50

Desanders

6

100

30

Desilters

4

60

15-30

Desilters

2

25

10-25

Desanders and desilters were first used to reduce sands, a cause of excessive weight and viscosity problems, and fine silts, believed to promote side wall sticking. Once in use, other benefits became apparent. • • • •

Increased bit life Reduced fluid end expenses Increased ROP Lower mud cost

Hydrocyclone underflows normally contain the highest percentage of fluid of any solids control equipment discard. The advantage of running hydrocyclones on unweighted mud is that they concentrate solids. As long as the hydrocyclone underflow is heavier than its feed, solids are being concentrated. If mud is being displaced from the system, it is always advantageous to run the hydrocyclones and displace as much mud as possible through the clones with higher solids than the active system. For a hydrocyclone to perform efficiently, it needs to be fed at the correct “constant feed head pressure”. The centrifugal feed pump must have the correct impeller and horsepower. The formula to convert pressure at any mud density is given below. This pressure should be read at the feed header of the hydrocyclone and not at the pump due to the pressure losses incurred though the piping between the pump and the feed header manifold.

Head (feet) =

10 of 23

( psi )

( 0.052 ) × ( Mud density Pressure

( ppg ) )

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The arrangement of hydrocyclones in a surface mud system is shown in Figure 6. The desander should take its suction from the closest compartment to the shaker. Its overflow should feed the next downstream compartment where the desilter pump should take its suction. The desilter overflow should discharge into the next downstream compartment. Processing capacity should be 125% of the maximum circulating rate. The excess capacity ensures no mud bypasses a particular unit. The following recommendations apply to hydrocyclone feed pumps. Each bank of hydrocyclones should have its own feed pump. • Mud entering the suction compartment should come only from upstream • equipment and equalizing backflow from the downstream compartment. Use the manufacturer’s specifications to size the pump impeller and • motor. Select the proper size feed and suction lines. Oversized lines cause • solids settling in horizontal sections, and undersize lines cause excessive erosion. The use of elbows, tees, and valves should be minimized. One valve in • the suction (for pump repair) and one in the discharge (to reduce the load on the electric motor at start-up) is sufficient. Anything that deforms or reduces the hydrocyclone’s apex opening • should be removed. By reducing the fluid volume lost, it reduces the amount of fine solids removed and causes excessive wear in the apex area of the cones. 2.3

Mud Cleaners A mud cleaner is a combination of hydrocyclones and a shaker screen. Mud cleaners discharge the underflow from 2- to 4-inch hydrocyclones onto a fine mesh screen (200-325 mesh – 74-44 microns). The greater density of barite results in the separation of a 30-micron barite particle with a 45-micron drilled solid. The underflow from the screen will thus contain the barite and be returned to the mud. This is usually a compromise because some fine drilled solids will pass through the screen, and some weight material is lost off the screen. It is more desirable to upgrade to fine-screen primary shakers than to equip the rig with mud cleaners. The mud cleaner screen’s relative dryness and the concentration of barite by the hydrocyclone causes the barite loss over the same size screen as run on a shale shaker to be many times greater.

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Only the hydrocyclones of a mud cleaner should be used on unweighted muds. The mud cleaner should be run when the sand content is unacceptable and turned off again when it is reduced to a reasonable level. Some of the effluent from the cones can be directed onto the screen if barite loss is high. 2.4

Centrifuges A centrifuge generates centrifugal forces by mechanically rotating the mud in a steel bowl. A mechanical scraper continually discharges the sedimented solids by means of a scroll, as shown in Figure 8. The centrifugal force can be from about 400 to 2000 times the force of gravity by changing the rotational speed and bowl diameter. The formula for calculating G force is G Force = Bowl Diameter (inches)

RPM2

0.0000142

The type of centrifuge and the arrangement of the equipment in the solids treatment system depends on the application and is described below

2.4.1

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Centrifuging Unweighted Mud

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On unweighted mud, a centrifuge rejects drilled solids and returns the liquid to the active system. It should be adjusted for maximum solids removal but may be slowed down to prevent plugging of the bowl. 2.4.2

Centrifuging Weighted Mud The primary use of centrifuges on weighted mud is for viscosity control. The centrifuge strips coarse solids, which include the majority of the barite, and returns them to the mud. It discards the liquid containing the treating chemicals and colloidal solids that contribute most to viscosity. To maintain mud density and fluid-loss control while reducing viscosity, liquids and chemicals equal to those discarded must be added back to the mud. The plastic viscosity (PV) is the best indicator of when a centrifuge should be turned on or off. When the PV has increased above an acceptable maximum, the machine should be turned on. The feed rate should be adjusted to match the rate that fresh liquids and chemicals can be added to replace those discarded. When the PV reaches an acceptable level, the machine should be turned off. There is never a need for more than one barite recovery centrifuge on a circulating system. Periodically, the quality of the retained solids should be checked to determine their value as weight material. This is done by running two simple pilot tests. One mud sample is weighted up with solids from the centrifuge and the other with commercial barite. The two samples are then compared to see which has the lower plastic viscosity. The economics of using salvaged barite versus fresh commercial material may then be compared.

2.4.3

Dual Stage Centrifuging Two centrifuges are often used in series for oil-base muds. The arrangement is shown in Figure 3D-9. The first centrifuge salvages the barite and some coarse drilled solids. The second cleans the liquid phase of finer solids and returns it to the mud system. The correct choice of centrifuges is essential for this operation. The first centrifuge does not need to be one that produces a high G force because it will save unwanted fines along with the barite. A machine that produces 600 to 1000 G force is sufficient. The second centrifuge should be capable of producing a G force ≥ 1800. A dual-

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stage centrifuge system should be run continuously. Excessive barite or oil losses indicate that the equipment is not adjusted correctly. Periodically, the quality of the solids and liquid returned to the system by the centrifuges should be checked to determine their value. This can be done by running simple pilot tests. First, build barrel equivalents using the solids and liquid from the centrifuges. Then compare the mud properties obtained in these pilot tests to those obtained from barrel equivalents built using fresh oil and barite. A judgment call can then be made on the economics of displacing some liquid and/or barite that the centrifuge returns to the system with fresh oil and barite in order to restore mud properties. Positive displacement pumps should be used to feed centrifuges to better control feed rates. The only possible exception is processing large volumes of unweighted mud. In this case, a centrifugal pump can sometimes be used. 2.4.4

Centrifuging Hydrocyclone Under Flow In areas where water or fluids disposal is expensive, a centrifuge can be used to concentrate the underflows of hydrocyclones. Typically, a 2-inch hydrocyclone bank is sized to process the circulating mud system. The underflows from these units contain a high percentage of liquid, which would be expensive to discard. This fluid is caught in a holding tank, where it is fed to a centrifuge. The effluent from the centrifuge is returned to the mud and the underflow discharged. The advantage of this in a relatively low solids (unweighted) mud is that a far greater volume of solids can be fed and removed by the centrifuge than if only mud were fed to the centrifuge. Using the hydrocyclones is a first step in concentrating the solids. This is done at the cost of returning some unwanted (with some commercial) solids in the centrifuge effluent that have already been removed back to the mud. It is not advisable to attempt to secondary process if the rig does not have fine-screen shakers and properly sized desilter cones upstream of the 2-inch hydrocyclones. Otherwise, the small hydrocyclones may become plugged. In some applications the underflows from desanders and desilters are centrifuged. These underflows need to be screened before being processed to remove coarse particles, which will erode and possibly pack off the centrifuge.

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3.0

SELECTION OF EQUIPMENT AND CONFIGURATION 3.1

Design Considerations An engineer determines the optimum design and policy towards formation solids disposal dependent on the design considerations discussed below. 3.1.1

Type of Formation Some “mud-making” formations react strongly with an uninhibited mud, such as a fresh-water dispersed mud, to produce a large proportion of colloidal fines that will not be easily removed from the mud, particularly if it is weighted. This factor may be exploited to “make mud” by simply incorporating the solids and adding drill water. A “dump and dilute” policy is appropriate if •

There is no restriction on water supplies.

•

There is no restriction or financial penalty on dumping.

•

The mud weight is low.

The solids removal equipment may be simple in these situations. The drilling rates may be fast and the capacities of the system may be inadequate. The degree of sophistication will have to increase if the muds are weighted. Hard rock drilling will not present so many problems. 3.1.2

Inhibitive Properties of the Mud An inhibited mud such as an oil-based mud or polymer system can improve the size and mechanical integrity of the cuttings coming to the surface and reduce the amount of colloidal solids being generated into the mud. Such systems are significantly more expensive than simpler. The economical advantages of the system can only be achieved if the volume of mud can be minimized by efficient solids removal.

3.1.3

Density of the Mud The cost of the mud, and hence the requirement to conserve volume, increases with the mud weight.

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3.1.4

Size of the Hole The larger sized hole requires larger volumes of mud and also higher flow rates. The solids equipment should be sized to handle the volume efficiently.

3.1.5

Drilling Rate The drilling rate and hole failure are generating solids that have to be treated at the surface with appropriately sized equipment . The most important solids control equipment, the shaker screen, should have enough surface area and be efficient so that the full flow can be treated through the finest screens.

3.1.6

Availability of Equipment The equipment and spares should be available so that the performance can be maintained. When selection of a rig is made, consideration should be given to matching the solids removal equipment to the mud systems that will be in use. The solids control equipment must be properly sized and selected for the mud type and hole size. Figure 1 summarizes the different types of solids removal equipment and the size range in which they operate. This information is superimposed on the size distribution of the solids to be removed and highlights one of the main problems – the removal of barite from the drilled solids

3.1.7

Dumping Restrictions In environmentally sensitive areas, there may be restrictions on the type of mud that can be used, weighting agent, solids disposal, or mud disposal. This situation can dominate any decisions about the mud type and solids removal.

3.1.8

Equipment Selection This section discusses the selection of solids removal equipment for the following mud types: • • •

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Low density muds High density muds Oil-based muds

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3.1.9

Low Density Muds The sequence of equipment for unweighted muds should be in descending size of solids being removed as shown in Figure 11. The shaker screen, fitted with as fine a screen size as possible, is followed by an unstirred sand trap, degasser unit, desanding hydrocyclones, desilting hydrocyclones, mud cleaner, and possibly a centrifuge for sand removal recovery. In unweighted muds, the shaker screen plays an important role in removing the drilled solids. The finest screens should always be used. The flow rate will depend on the hole size with the highest flow rates in the larger sized holes. Ideally the screen area should be large enough so that the finest screens could be used. Some losses of mud over the end of the screen is preferable to fitting finer screens. Low density flocculated muds are used for drilling large diameter holes due to the flat velocity profile. These fluids also shear thin well in the hydrocyclones, which are effective for treating this type of drilling fluid. In unweighted dispersed drilling muds, medium to fine screens can be used, and hydrocyclones will also have a role to play.

3.1.10 High Density Muds The sequence of equipment for weighted muds is shown in Figure 12. In these systems the primary screening becomes much more important as the size range, 10 to 100 µ, is occupied by the weighting agent. The desander can be used, but the desilter does not operate efficiently and throws away too much barite. The centrifuge is used to conserve barite or to control the mud weight. 3.1.11 Oil-Base Muds Oil-based muds are a special case because the liquid phase is very expensive. The two key elements are to conserve the drilling fluid and to minimize the mud discharge. The major advantage of oil-based mud is its highly developed inhibitive properties. This means that cuttings come to the surface almost unaltered, intact and large enough to be removed by the shaker screen. This is where the emphasis must be placed. The type of shaker, screen area, and

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screen size must all be optimized. Linear motion screens give dry discharges and have application. A centrifuge should be used to reduce weight and control the density. While this may be wasteful of the barite, it is preferable to dumping the expensive mud. Dual operating centrifuges have application with high density oil muds. Cuttings washing units may also be in operation. These are operated on a number of different principles. Fines control becomes the most difficult problem, and high speed centrifuges again play an important role here.

4.0

PERFORMANCE ASSESSMENT Economical evaluation has to be made to balance the costs of the equipment, its maintenance, possible hire of specialized technicians, and cost of discharged barite against the benefits of reduced mud volumes being built and improved mud properties. Increasing concern about the environmental impact of mud and drilled cuttings removal, however, changes the balance and makes conservation of mud volumes and selective discharge of cuttings essential. Solids removal equipment must be assessed so that the selection and operation of equipment can be optimized. Data may be needed to justify the capital expenditure or hire of new equipment, for example. Previously, the efficiency of drilled solids removal system was generally reported as the percentage of the drilled rock that was removed by the equipment. It did not take into account the amount of fluid lost in the process. By this definition, simply jetting the mud would give you 100% removal efficiency but would not be a desirable method due to the amount of mud lost. Thus, to describe more accurately the performance of a system, we need a term that will take into account both the percentage of drilled solids removed and the wetness of the drilled solids. Dilution tends to occur continually as liquid phase (oil or water or both) is added to maintain the volume as the hole is drilled and to replace the liquid phase that is lost through filtration and adsorption. Dilution fails to remove the detrimental solids from the mud system.

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Disposal of whole mud is the only way that the fine solids are removed from the circulating mud solids. Dumping the sand trap when making connections is a satisfactory operation. In some operations, it is possible to flocculate the whole mud with polymers and then separate the liquid and solid phases using centrifuges or plate presses. This operation minimizes the mud dilution volumes. The dilution factor is a term created to describe the drilled solids removal system performance. Total dilution is defined as the volume of mud that would be built if there was no solids removal system. In this case, all drilled solids would be incorporated into the mud system with dilution being the only form of solids control. The mud quality and drilling performance would remain equal whether using dilution exclusively or a solids removal system. The dilution factor (DF) is the ratio of the volume of mud built (Vmb) to total dilution. It is the volume of mud actually used to drill an interval using a solids removal system as compared to only using dilution. In both cases, the level of drilled solids in the mud remains constant and appears in both calculations. The lower the factor, the more efficient the system. The average drilled solids concentration by volume maintained in termed the drilled solids fraction (Fds). This fraction is the retorted corrected for salt, bentonite, barite, and commercial additives. The this value is dependent on the correction methods, but consistency comparing well-to-well results.

the mud is solids value accuracy of is critical in

The drilled solids removal system is defined as all processes used while drilling a well that removes the solids generated from the wellbore from the active fluid. These processes consist of dumping of whole mud (including lost circulation), settling, screening, desanding, desilting, and centrifuging. Total dilution is the amount of mud required to dilute all drilled solids generated during the interval to the actual drilled solids fraction (Fds) by volume maintained during the interval (bbls). This is the volume of mud necessary to build if no solids removal equipment was used and the same quality of mud and drilling performance was achieved. The key to a performance analysis of a drilled solids removal system is an accurate analysis of the amount of mud mixed. This technique relies on the accurate measure of a tracer, which is a mud component such as water or oil that is measured to determine the volume of mud built.

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Volume of mud built (Vmb) is determined from measurement of the actual volume of mud built . The actual volume of mud used to drill an interval can be calculated using the tracer. Tracer volume (Vt) is the total volume of tracer added to the mud (bbls). Once the tracer volume is recorded, the volume of mud built can be calculated by determining the volume fraction of the tracer maintained in the mud for the interval. This value is normally calculated from solids analysis methods using retort and salt measurements. The tracer fraction (Tf) is an average for the interval in question. Therefore, the averaging method is critical. Comparisons are valid from well to well only when using identical methods of calculation. To calculate the drilled solids fraction, several methods are available from simple solids analysis, which correct for salt and bentonite concentrations, to complex material balance methods, which correct for additional components, such as commercial additives, in order to improve accuracy. The drilled solids fraction is an average for the interval. Therefore, the averaging method is again critical. Volume of drilled solids (Vds) is the volume of drilled solids generated for the interval (bbls). Volume of mud built. (Vmb) is the actual volume of mud used to drill an interval (bbls). The symbols used in this calculation procedure are summarized in the following table, 3D-6:

Table 3D-6, List of Symbols Used in Evaluation of Drilled Solids Removal System Performance DF

Dilution factor

Tf

Tracer fraction

SP

Drilled solids removal system Vt performance

Tracer volume (bbls)

Fds

Drilled solids fraction

Vds

Volume of drilled solids (bbls)

Dt

Total dilution

Vmb

Volume of mud built (bbls)

Different methods of calculating the effect of the drilled solids fraction on the dilution factor yield significantly variable results. Therefore, comparisons are valid from well to well only when using identical methods of calculation. The procedure requires the following data to be recorded or calculated as summarized in the following table.

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Table 3D-7, Procedure Used in Evaluation of Drilled Solids Removal System Performance Step

Procedure

Calculation

1

Record all tracer additions to mud.

Tracer fraction

2

Record all fluid data.

Tracer volume (bbls)

3

Determine the tracer fraction.

4

Determine the volume of mud built (Vmb).

5

Determine the drilled solids fraction (Fds).

6

Calculate the total dilution.

7

Calculate the dilution factor.

8

Calculate the drilled solids removal system performance.

Vmb = Vt Tf

Dt = Vds Fds DF = Vmb Dt SP = (1-DF)

(100)

Example Mud Report Data Vds (bbls) 250

Fds 0.05

Tf 0.80

Vt (bbls) 2,000

Solution 1. Volume of Mud Built = Vmb = Error!= 2500 bbls 2. Total Dilution = Dt = Error!= 5000 bbls 3. Dilution Factor = DF = Error!= 0.5 4. Drilled Solids Removal System Performance = SP= (1 - 0.5) (100) = 50% The analysis described above should be carried out for each section and over a number of wells so that a trend can be established. There is often a reluctance to

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accurately determine the concentration of water used to make up the volume of mud. This a major part of the process. 4.1

Identification and Correction of Malfunctions The procedure for determining the performance of the solids removal system helps analyze the malfunctions of the system as a whole. The individual pieces of equipment should be supervised as the drilling progresses. The equipment is subject to wear and tear, requiring constant supervision. The shaker screens should be washed periodically and closely inspected to see if there are any tears in the screen. Finer screens should be tried to see if they can take the flow rate. A change in formation type will often allow a change in screen. The performance of the centrifuges should also be monitored carefully. If they are used extensively, they should be attended by a specialist technician. In addition to assessing the performance of the equipment, the effects of solids on the mud should be monitored. The mud properties that are indicators of solids content and effects are summarized below.

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•

Mud weight – The weight of the mud should be monitored. Increases related to the volumes of dilution and weighting materials should be added. The level of solids should be kept to within the guidelines given in Figure 1. Barite is the desired weighting agent.

•

Methylene blue titration – This is a measure of the colloidal clay fraction added to the mud.

•

Retort values – The retort values should be corrected for salt content (from the chloride level). The ratio of drilled solids to barite should be calculated.

•

Drilled solids concentration – This is determined from the retort. The objective of the solids management should be to increase the relative concentrations of barite and bentonite (if it is added) and minimize the low gravity drilled solids.

•

Plastic viscosity – The plastic viscosity is a measurement of a fluid’s resistance to flow and is a relative measurement of the amount of fine solids in a mud.

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•

Sand content – An increase in the sand content indicates the requirement for the desanding hydrocyclones or finer screens efficiency

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COMPLETION PRACTICES PACKER AND PBR COMPLETIONS

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PACKER AND PBR COMPLETIONS 1.0

PACKER COMPLETIONS 1.1 Types of Packers 1.1.1 Permanent vs. Retrievable 1.1.2 Permanent Packers 1.1.3 Retrievable Packers 1.1.4 Single vs. Dual 1.2 Seal Assembly 1.3 Tail Pipe Assembly

2.0

PBR COMPLETION

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PACKER AND PBR COMPLETIONS 1.0

PACKER COMPLETIONS The central component of any tubing-packer completion is the production packer, whose primary function is to provide a hydraulic seal between the tubing and casing. The hydraulic seal isolates the casing above the packer from high production and stimulation pressures and corrosive fluids. Major production packer functions can be summarized as follows: A) B) C) D) E) F) G)

1.1

Protect casing from bursting under conditions of high production or injection pressures. Protect casing from corrosive fluids. Isolate casing leaks, squeezed perforations or multiple producing intervals. Eliminate inefficient “heading” or surging of production fluids. Provide better well control by keeping kill or treating fluids in casing annulus. Prevent fluid movement between productive zones. Keep gas lift pressure off the formation for more efficient gas lift production operations. Types of Packers Production packers are generally classified as either retrievable or permanent. They can also be categorized according to the manner in which force is applied to activate the sealing element, as compression packers, tension packers or combination tension and compression packers. Packers can further be classified by their setting mechanism, as Hydraulic, Mechanical, Electric Wireline or Slickline set. Evaluation of packer objectives is required to select the proper packer for a given application. Future well operations, such as initial completion, production, stimulation, artificial lift and probable workover procedures should be considered. The packer that offers the lowest overall cost over the projected life of the well, should be selected. Basic Packer Components A permanent Halliburton WB packer is shown in Fig. 4A-1, and in Fig. 4A-2, a retrievable Halliburton Versa Trieve packer. They have the following components in common: • Sealing element • Slips • Cone

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• •

Setting and releasing mechanism Flow mandrel

Figure 4A-1 Permanent Packer

Figure 4A-2 Retrievable Packer

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A)

Sealing Elements: Sealing elements are normally constructed of nitrile-rubber, except in such special applications as thermal-injection or sour-service operations. Nitrile-rubber seals have proved superior for use in moderate temperatures under normal service conditions. The compound characteristics required for a particular job can be achieved through control of the constituents in the compound and the degree of vulcanization. The ability of a seal to hold differential pressure is a function of the elastomer pressure or stress developed in the seal, i.e., the stress must exceed the differential pressure across the packer.

B)

Slips: Slips are serrated or “tooth-like” parts of the packer. Once forced outward by the setting action, the slips “bite” into the casing wall preventing the packer from moving when pressure differentials exist across the packer. Some packers have two sets of opposing mechanical slips. The top set of slips prevents the packer from moving uphole while the bottom slips prevent downward motion. Some packers incorporate bi-directional slips, that is, one set of slips which prevent motion in either direction. There are a few packer designs with a set of lower slips and a set of hydraulically activated hold-down button slips.

C)

Cone: The cone is simply that part of the packer, which forces the slips to move outward and bite into the casing during the setting of the packer. The cone is known by several other names such as the wedge, expander, or expander cone.

D)

Mandrel: The flow mandrel (sometimes called the packer mandrel) is the "tube" part of the packer which allows production to enter the tubing and, in turn, flow on to the surface. It can be generally stated that a packer consists of external components built around the flow mandrel. In many instances, the pressure differential rating of a packer is dependent on the strength of the flow mandrel. Down hole conditions will dictate the type of alloy used to make the flow mandrel.

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E)

1.1.1

Setting and Releasing Elements: The setting mechanism on retrievable packers generally consists of a Jlatch, a shear pin, or some other clutch arrangement to allow the packer to be engaged. The various mechanisms employed are actuated by a number of different methods, including upward or downward movement, placing weight on the packer, pulling tension in the tubing, or rotating to the right or left. Hydraulically actuated retrievable packers are set with pressure inside the tubing using pump-out plugs, wireline plugs, or flowout balls. The releasing mechanisms on a retrievable packer involve another wide range of actuation methods - straight pickup, rotating to the right or left, slacking off and then picking up, or picking up to shear pins. Releasing a packer by rotation is difficult to achieve in highly deviated wells. Tubing movement due to changes of pressure and temperature should be evaluated when selecting setting and releasing mechanisms of a retrievable packer. To select a particular type of setting or releasing mechanism, it is necessary to know the conditions existing in the particular wellbore when the packer is set and the operations anticipated during its stay in the hole. Permanent Vs. Retrievable When selecting the optimal packer type for a given application, retrievability is often a key factor. Permanent packers are readily milled out in a few hours milling time using a flat bottom mill or in several hours using a rock bit. By comparison removal of a stuck retrievable packer may require two or three days of rig time and considerable expense. Packer milling and retrieving tools, “packer pickers” are also available to recover the permanent packers by cutting the upper slips and catching the remainder of the packer. Most production packers currently used in Saudi Aramco Operations are the single string, permanent, hydraulic set type. However, a pilot project to evaluate the feasibility of dually completed producers, is ongoing in the Berri Field offshore. Two wells have already been successfully worked over and converted to dual Hanifa/Hadriyah producers utilizing 9-5/8” Baker GT dual string-selective setretrievable hydraulic packers in conjunction with 7” Baker FB-1 permanent packers. Five Dual Arab-D Horizontal/Vertical Completions have recently been run onshore in the Uthmaniyah and Hawiyah fields utilizing Dresser Oil Tool's Lateral Re-entry System.

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1.1.2

Permanent Packers Figure 4A-1 shows a Halliburton WB permanent packer which is frequently used by Saudi Aramco. The packer can be run and set on wireline or drill pipe. Selection of the setting mechanism depends on cost (rig cost and service company charges) and wellbore conditions. When the packer is run on drill pipe a hydraulic setting tool is attached to the top of the packer. Once the packer is on depth, a ball is dropped into the setting tool. Pump pressure activates the setting tool which forces the upper slips, upper cone and lower cone to move downward thus compressing the seal element between the cones against the casing. As the slips slide over the cones they are forced to move outward and "bite" into the casing preventing movement of the packer. When the packer is run on wireline, setting is accomplished by firing an explosive charge to create the necessary pressure required to set the packer. Permanent packers cannot be retrieved from the well. A flat bottom mill is used to mill the top slips and part of the sealing element. The packer is then pushed to the bottom and retrieved by using a taper tap or a spear. The packer may also be retrieved by using a millingretrieving tool. The tool consists of a burn shoe and a collet or a spear. The collet or spear engages the inside of the packer while the top slips are milled by the burn shoe. Once the top slips are milled the packer is pulled to the surface. A)

Characteristics of Permanent Packers:

General characteristics common to permanent packers are: i) Permanently set. Once set, no tubing weight or tension is required to keep it in set position. ii) Economical. Permanent packers have, by design, very few components. As a result, these packers are less costly than other packers of comparable size. iii) Highest pressure rating. Permanent packers due to their simple design can be built sturdier than other types of packers. Pressure differential ratings as high as 15,000 psi are possible. iv) High-temperature rating. Element packages are available to withstand temperatures in excess of 500°F. v) Popularity. Worldwide, permanent packers are the most frequently used of all packer types. vi) Floating seal assembly can be used to accommodate tubing movement. B)

Disadvantages:

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The main objection to the permanent packer is the necessity for milling and destroying the packer for removal. A permanent packer can be milled and retrieved in 12 hours using a millingretrieving tool or in 24 hours using a flat bottom mill. Permanent packers can be sub-divided according to the method required to set the packer. Electric wireline, hydraulic and tubing rotation are the three setting methods available. The electric wireline and hydraulic are by far the most common methods used to set permanent packers. Tubing rotation is rarely used. C)

Electric Wireline Set Packer The electric wireline set packer is the most commonly used of any type of packer. It can be run and set quickly and accurately at a pre-determined depth. After the packer is set, a production seal assembly and production tubing is then run into the well. Once the seal assembly seals into the packer, tubing length is adjusted at the surface (spaced out) and the well is then completed.

D)

Hydraulic Set Packer There are instances when it is desirable to run a wireline set packer, however, hole conditions may prevent using electric line. To accommodate the running of an electric wireline set packer, a hydraulic setting tool may be used. The hydraulic setting tool takes the place of the electric line setting tool when conditions so dictate. The packer is attached to the hydraulic setting tool and run in the well on pipe. Once on depth, a ball is dropped through the pipe into the setting tool. Hydraulic pump pressure activates the setting tool causing the packer to set. The hydraulic setting tool and workstring are then pulled out of the well and production seals and tubing are run to complete the well. Some conditions which may require using a hydraulic setting tool are: i)

Assembly weight. If the packer and attached equipment weighs more than the electric wireline can support, the assembly may be run and set on pipe using the hydraulic setting tool.

ii)

Seal assembly on bottom of the packer assembly. If a previously set lower packer is in place, the seals for the

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lower packer may have to be pushed into that packer using the workstring weight.

1.1.3

iii)

High angle of deviation. As the angle of deviation becomes greater, a point is reached, generally 55-60°, where the packer will no longer "slide" down the well. This condition requires running the packer on pipe.

iv)

Heavy mud in the well. A thick, viscous mud may prevent the packer assembly from falling on its own. Again, pipe weight may be required to push the packer assembly down hole.

Retrievable Packers A Halliburton Versa-Trieve retrievable packer is shown in Fig 4A-2. The packer is designed to be set on wireline or tubing. It has bidirectional slips located below the packer elements to prevent debris from settling on them. During the setting sequence, the packer's guide tube is forced downward while the packer's mandrel is pulled upward. This motion drives the top and bottom wedges under the slips to force them out into the casing wall. Additional setting stroke compresses the packer's elements to form a seal against the casing wall. The packer is maintained in the set position until a shear piston located in the lower end of the packer is moved up to release the packer's mandrel from the packer's shear sleeve. A VRT retrieving tool is used for this operation. Once the packer's mandrel is free to move, a set of shear pins in the VRT tool is sheared, allowing the pulling forces to be transmitted to the packer's mandrel. As the packer's mandrel is moved upward, a snap ring catches the lower end of the element mandrel to release the compression in the packer's elements. Additional upward movement pulls the top wedge from under the slips allowing the slips to move in and release their bite in the casing wall. The main advantage of retrievable packers is that they can be retrieved without destroying the packer. This saves rig time and the cost of replacing the packer. If the old packer is in satisfactory mechanical condition and is not corroded it can be redressed and rerun in the well. Retrievable packers, however, cost more than permanent packers. Sometimes retrievable packers get stuck and cannot be retrieved by conventional retrieving tools. In this case they have to be milled and retrieved by taper tap. Retrievable packers generally take longer time to mill than permanent packers because their slips are made of harder metal.

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1.1.4

Single vs. Dual Most production packers currently used in Saudi Aramco operations are the single string, permanent, hydraulic set type. The single permanent packer has historically proven to be the most economical choice for Saudi Aramco in terms of handling high production rates and accommodating periodic workover and stimulation operations. However, with the success of the Berri Field dual completions, additional duals are planned. The general procedure for the Berri field dual completions is to first run in the hole with the single FB-1 packer and tailpipe assembly on drillpipe and set it + 250’ above the lower zone (the Hadriyah perforations). The setting tool is released and then pulled out of the hole. The top dual Baker GT retrievable packer is run made up on the long tubing string with the lower seal assembly and tail pipe assembly attached to the bottom. The long string seal assembly is stung into the bottom (FB-1) packer. The dual packer is then hydraulically set and pressure tested. The long tubing string is permanently attached to the top packer. Expansion joints are run in both tubing strings to allow for tubing movement. The tubing strings are hung on a special dual tubing hanger. A dual production tree is installed on top of the tubing spool which facilitates producing the two zones separately. Both the short and long strings of the offshore Berri Field Dual Completions contain blast joints, expansion joints, sliding sleeves and wireline retrievable subsurface safety valves (SCSBV), which are not usually run in onshore single string completions. A)

Sliding Sleeves: The sliding sleeves, sometimes referred to as sliding side doors, are used to displace the tubing and annulus to diesel and inhibited diesel respectively after the dual packer is set. A sliding sleeve is simply a port that can be opened or closed by wireline. It can also be used to kill and circulate out a well without removing the Christmas tree. However in wells with sand laden or highly corrosive fluids, sliding sleeves may fail or become stuck in the open or closed position. In certain applications sliding sleeves are utilized to selectively produce or stimulate targeted zones.

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B)

Expansion Joints: Expansion joints are used to compensate for tubing contraction and elongation due to temperature and pressure changes caused by producing and stimulation operations. Most have maximum stroke lengths from 10 to 20 ft. The Berri Dual completions utilize full bore Baker Model–M expansion joints in the short and long strings.

C)

Blast Joints: Blast joints are used in multiple completion wells to protect the area of tubing that remains opposite the upper perforations and exposed to abrasive, corrosive and sand laden fluids. The blast joint is externally coated with rubber, tungsten carbide, ceramics or is itself a special alloy. These coatings serve to reduce abrasion caused by the flow of produced fluid.

D)

Subsurface Safety Valve: A subsurface safety valve is a device installed in the tubing of a well below the wellhead that can be actuated to prevent uncontrolled well flow. This device can be installed and retrieved by wireline (wireline retrievable) or it can be an integral part of the tubing string (tubing retrievable). They can be subsurface or surface controlled.

Figure 4A-3 - Blast Joint, Subsurface Safety Valve and Sliding Sleeve

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Figure 4A-4 - Dual Hanifa/Hadriya Completion on Berri-98

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Four dual - Arab-D Short Radius Horizontal Producer/Vertical Open hole observation wells and one dual short radius Arab-D Horizontal Producer/Arab-D Vertical Producer have recently been drilled and completed by Saudi Aramco in the Utmaniyah, Haradh and Hawiyah Fields using Dresser Oil Tool's Lateral Re-entry System (LRS). Seven more are planned for the near future. Haradh-159 was recently recompleted in this manner utilizing an upper 7" DOT G-10 permanent packer, a 7 x 2.50" DOT LRS-SL Window, a lower DOT 7" Slim-GT Packer and 4-1/2" production tubing as shown below. Figure 4A-5 - Dual Arab-D Horizontal Producer/Arab-D Vertical Observation Well

Haradh Well No. 159 (P) Cross Section after WO-1 North 320° AZ M 320 7” Liner Hanger @ 1712’ 4-1/2” Tubing 9- 5/8” Casing @ 3717’

‘G-10’ Packer @6299’

LRS Window @ 6394’ - 6400’

7” Casing Window 6388’ - 6401’

‘Slim GT’ Packer @ 6429’ with e nd of 2- 3/8” Tailpipe @ 6472’

Zone-2A

KOP @ 6406’ TVD Landing Point @ 6736’ MD, 6537’ TVD (top Zone-2A)

TD @ 8736’ MD, 6582’ TVD (30’below top of Zone-2A) 88.7° Inclination, 320° AZM.

7” Liner @6532’

4 1/2” Liner ( 6452’ - 6832’) Vertical PBTD @ 6820’

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1.2

Seal Assembly Since permanent packers cannot be pulled out of the well, the tubing cannot be attached directly to a permanent packer. Occasionally, the tubing may have to be retrieved and repaired or replaced. A pressure tight seal must exist between the tubing and the packer bore forcing the production into the tubing. This is accomplished by using a seal assembly, which attaches to the tubing and seals in the packer. The seal assembly is designed such that it can move in the packer to accommodate tubing elongation or contraction which can result from changes in temperatures and pressures in the tubing and tubing-casing annulus. The basic seal assembly used in Saudi Aramco wells consists of a locator, a spacer bar, a seal unit and a mule shoe guide, as shown below.

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A)

Locator: The locator is attached at the top of the seal assembly and at the bottom of the tubing. It is designed to prevent any further downward travel of the seal assembly once the locator encounters the top of the packer. A Halliburton straight slot locator used by Saudi Aramco is shown above. It is used when a free-to-move seal assembly is required. The jay-slot locator is used when small tubing movement or forces are expected. The jay slots of the locator latch onto the lugs in the packer's head preventing tubing movement.

B)

Spacer Bar: A spacer bar is a length of pipe without seals attached to the bottom of the locator and above the seals. It is used as an extension to space out the locator above the packer and at the same time keep the seals inside the bore of the packer and sealbore extension.

C)

Seals: The seal unit forms a seal in the bores of the packer and sealbore extension. A Halliburton standard molded seal unit is used in most Saudi Aramco completions. The seal is made of nitrile rubber and is used in wells where the pressure is less than 10,000 psi and temperatures are less than 275°F. Each seal unit is one foot long and longer seal assemblies can be made by simply attaching the seal units together. Premium seals are used for harsh conditions of high temperatures, high pressures and in severe environments such as hydrogen sulfide, carbon dioxide and amine inhibitors. The Kalrez/Chemraz-Teflon-Rytex, (KTR) premium, self-energized, Chevron “V” shaped seals are currently used on all Khuff Gas Well PBR and Tubing-Packer completions.

D)

Mule Shoe: A Mule shoe is installed at the bottom of the seal assembly to facilitate entry into the packer bore. The shape of the mule shoe is designed such that if the seal assembly hangs up at the top of the packer or liner hanger, a simple rotation of the assembly will allow it to pass through.

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1.3

TAIL PIPE ASSEMBLY The tailpipe assembly is the part of the tubing that is connected to the bottom of the packer. It serves the following functions: A)

Provides a seal bore for the seal assembly.

B)

Contains landing nipples for setting wireline plugs used for well control and pressure testing tubing.

C)

Contains no-go landing nipples used for hanging bottom hole pressure gauges.

d)

Facilitates re-entry of wireline tools. The standard tailpipe assembly used in Saudi Aramco oil producers consists of the following components:

• • • • •

Sealbore extension Millout extension Selective landing nipples No-go landing nipples Re-entry guide

A) Sealbore Extension: A sealbore extension is a length of pipe with polished bore that is connected at the bottom of the packer. It is designed to extend the polished surface of the packer bore to permit use of longer sealing units to compensate for the contraction and elongation of the tubing. A Halliburton sealbore extension used by Saudi Aramco is shown in Fig 4A-6. It is ±12' long and has the same bore ID as the packer. B) Millout Extension: A millout extension is a length of pipe ±5' long which is connected to the bottom of the sealbore extension. The purpose of the millout extension is to facilitate the retrieval of the packer and tailpipe assembly after the packer is milled. It has a larger inside diameter than that of the sealbore extension. The difference in the diameters provides a shoulder where a special plucking tool can engage and retrieve the packer and tailpipe assembly. The use of a millout extension is

Figure 4A-6 – Halliburton Sealbore Extension ______________________________________________________________________________________ 14 of 19

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optional. When not used the packer can be milled out and then retrieved by taper tap or spear. C)

Landing Nipples: A landing nipple is a device connected to the tubing or tailpipe assembly used for setting wireline plugs or flow control devices. Halliburton selective nipples are used in Saudi Aramco's well completions. Type 'X' nipple shown in Fig 4A-7 is used for standard weight tubing, type 'R' nipple is used for heavy weight tubing. The bore size of the nipple should be compatible with the size and weight of the tubing. The first 'X' nipple in the tailpipe assembly is installed at the bottom of a tubing pup joint which is connected to the sealbore extension or millout extension. The nipple is used for setting wireline tubing plugs to stop the flow into the tubing. This is normally done during workovers before the tree is removed or when Well Services replaces a damaged tubing master valve.

Figure 4A-7 - Landing Nipples used in Saudi Aramco's Well Completions

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In Southern Area well completions two 10' perforated tubing pup joints are connected below the 'X' nipple. During flow tests pressure gauges are hung inside the tailpipe below the ‘X’ nipples, which partially block the flow into the tailpipe. The purpose of the perforated pup joint is to

Figure 4A-8 - Halliburton Re-entry Guide

allow the fluids to enter into the tubing during the flow test. A second 'X' nipple is installed at the bottom of the perforated joints. This nipple is used by S. A. Wireline Services for hanging bottom hole pressure gauges (Normally 'X' nipples are not designed for hanging pressure gauges). ______________________________________________________________________________________ 16 of 19

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D) No-Go Landing Nipples: The no-go or 'XN' landing nipple is installed on a 10' tubing pup joint below the bottom 'X' nipple. Like the 'X' nipple it has a polished bore for setting wireline tubing 'PXN' plugs. In addition, the 'XN' nipple has a no-go ID at the bottom to prevent pressure gauge hangers from dropping to the bottom of the well. The nipple is used for hanging pressure gauges and other flow control devices. E) Re-entry Guide: The re-entry guide is installed at the bottom of the tailpipe assembly. Its bell shaped design facilitates re-entry of wireline tools into the tailpipe. An Otis reentry guide is shown in Fig 4A-9

Fig. 4A-9 Packer Seal and Tailpipe Assemblies

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2.0

PBR COMPLETION A polished bore receptacle (PBR) is another type of packer system that can be used in place of a permanent packer. It is frequently used in deep gas well completions or other situations where casing or liner diameter is limited and maximum packer bore is desired. The PBR accepts an inner seal assembly that seals off between the tubing and the PBR Fig 4A-10 and 4A-11. The PBR is commonly used in a liner completion, where it is installed as an integral part of the liner hanger. When the completion string is run, the seal assembly, similar to that used on a permanent packer, is run on the end of the tubing string. The seal assembly is either latched onto the PBR, or left floating to allow tubing movement. Frequently tubing weight is slacked off on the PBR to eliminate seal movements during the producing life of the well, while allowing free upward movement during stimulation treatments. The bore of the seal assembly is equal to the ID of liner below, which facilitates free passage of wireline tools. Normally, the PBR diameter is larger than the diameter of the liner below it. Most workover tools and procedures can be run through the PBR with ease.

Figure 4A-10 - PBR installed in Liner Completion

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In a PBR completion, the sealing characteristics and capabilities between the tubing and PBR are the same as between the tubing and packer body of a permanent packer completion.

The PBR has a disadvantage that the permanent packer does not. The position of the PBR is fixed in the hole, generally in the liner hanger, which may be several hundred feet above the zone of interest. As stated previously, one of the functions of the packer system is to protect the casing string from the corrosivity of wellbore fluids by sealing off the tubing annulus. Since the PBR is set at the top of the liner, the entire length of the liner is exposed to potentially corrosive fluids when the well is produced. For example, in a well with a 500 ft. liner and a producing interval 50 ft in length, the entire liner is exposed to the effect of the production fluids, as opposed to a typical installation in which the packer would be located just above the pay.

Figure 4A-11 - PBR and Seal Assembly

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PACKER AND PBR SELECTION 1.0

SELECTION CRITERIA 1.1 Cost 1.2 Well Conditions 1.3 Running and Setting Considerations 1.4 Retrieving Considerations 1.5 Production & Treating Considerations 1.6 Compatibility with Downhole Equipment 1.7 Maximum Packer Bore

2.0

TYPICAL COMPLETION DIAGRAMS 2.1 Onshore Arab-D Horizontal 2.2 Offshore Arab-D Vertical 2.3 Onshore Arab-D Vertical 2.4 Dual Arab-D Horizontal /Vertical 2.5 Shaybah Horizontal 2.6 Vertical Khuff Packer Completion 2.7 Vertical Khuff PBR Completion

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PACKER AND PBR SELECTION 1.0

SELECTION CRITERIA The best approach for selecting a packer is to first examine well conditions and desired operational capabilities and then determine which packer features meet those well conditions and best fulfill those operational requirements. Some of the factors that should be considered in selecting a packer are: 1.1

Cost The packer of minimum cost that will accomplish the objective should be selected. Initial packer price should not be used as the only criterion. Rig time cost for running and retrieving the packer should also be taken into consideration.

1.2

1.3

Well Conditions 1.2.1

Packer should be selected to withstand the pressure differentials between the tubing-casing annulus and wellbore below packer during producing and acidizing.

1.2.2

Packer should be made of alloys that will withstand the corrosivity of well fluids.

Running and Setting Considerations Packer setting mechanisms are tubing-set, electric-line-set or hydraulic-set. Tubing-set packers should not be used in deep wells because of increased possibility of tubing manipulation problems with increased depth. Electric line set packers should not be used in highly deviated holes (greater than 5055O) because it is not possible to run the packer to the required depth.

1.4

Retrieving Considerations Retrievable packers can be retrieved by a rotational release mechanism or straight pickup release mechanism. A rotation release packer should be avoided in deviated wells because of difficulty in transmitting rotation downhole.

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1.5

Production & Treating Considerations Packers must be able to accommodate tubing movements (elongation and contraction) as a result of changes in temperatures and pressures. Packers set in tension allow for tubing movement due to expansion whereas packers set in compression accommodate tubing contraction. Tubing movement due to both expansion and contraction can be accommodated using a floating seal assembly with sealbore extension.

1.6

Compatibility with other Downhole Equipment If wireline equipment or perforating guns are to be run in the tubing, it is desirable to use packers that do not require weight to keep them set. Wireline operations can be more successfully completed if tubing is kept straight by landing it in tension or neutral. Furthermore, the bore of the packer or the seal assembly should be large enough to allow for running through-tubing, perforating guns, production logs and tubing plugs.

1.7

Maximum Packer Bore. In deep gas wells or other situations where casing or liner diameter is limited and maximum packer bore is required, the PBR Completion may have application.

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2.1

Typical Onshore Arab-D Horizontal Completion with 7” Baker Permanent Packer

FB-1

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2.2

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Typical Offshore Arab-D Vertical Completion with Permanent and Subsurface Safety Valve at + 300’.

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2.3

Typical Onshore Arab-D Vertical Completion with DOT 7” Magnum GT Permanent Packer

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2.4

Dual Arab-D Horizontal/Vertical Producer

Dual Arab-D Horizontal/Vertical Producer

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2.5

Typical Shaybah Horizontal Completion with Baker FB-1 Permanent Packer

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2.6

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Typical Khuff Vertical Completion with 9-5/8” Halliburton TWS Permanent Packer and Ratch-Latch Assembly

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2.7

Typical Khuff Vertical 7” Liner/PBR Completion

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RUNNING AND SETTING PROCEDURES 1.0

GENERALIZED PACKER RUNNING PROCEDURE 1.1 Onshore Arab-D Well With Permanent Hydraulic-Set Packer 1.2 Dual with Upper Retrievable/Lower Permanent Packer - Workover Procedure for Dual Arab-D Horizontal Producer/Vertical Arab-D Vertical Observation Well 1.3 Khuff Completion with 9-5/8" Permanent Packer with Tubing Anchor Seal Assembly

2.0

GENERALIZED RUNNING PROCEDURE FOR KHUFF PBR COMPLETION

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COMPLETION PRACTICES RUNNING AND SETTING PROCEDURES

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RUNNING AND SETTING PROCEDURES The minimum requirement for barriers/shut-offs to be in place prior to rig release for all completions shall adhere to (G.I. #1853.001) as follows: Oil Wells (GOR less than 850 scf/bbl); Oil Wells (GOR more than 850 scf/bbl): Gas Wells:

2 shut-offs (1 mechanical) 3 shut-offs (2 mechanical) 3 shut-offs (2 mechanical)

The packer fluid density used in the TCA shall never be less than kill mud weight. If annular operated tools are required, a brine of kill weight density (CaCl2/CaBr2 for Khuff/Pre-Khuff wells) is recommended to avoid mud solids settling, which can result in operational problems with the annular operated tools and freeing the packer. 1.0

GENERALIZED PACKER RUNNING PROCEDURE 1.1

Onshore Arab-D Well With Permanent Hydraulic-Set Packer. COMPLETION PROCEDURE A)

B)

After logging at TD, RIH with 6” bit, 7", 26# casing scraper and two 61/8" string mills. Space out scraper to be at 100’ above the 7” liner shoe, when bit at TD. Ream and clean 7" liner hanger and circulate hole clean. Make a wiper trip to check for fill, circulate out if any. Before POH, sweep with HV polymer pills & spot 100 bbl of clean acidic water (pH 5-6) treated w/ 0.5 drum of MORFLO-II surfactant across the open hole. POH. Note: i) The estimated acid required to reduce pH from 7.3 to 5 is approximately 1.0 bbl of 15% HCL per 100 bbl of water. ii) Add 1/2 drum of MORFLO-II to water just prior to pumping downhole to avoid foaming. iii) Pass water through 200 mesh screen. Install strainer screen at pump intake.

C) D)

RU WL and run 5.95" AC-DC for 7", 26 # liner to 7400' MD (at 50° inclination). Run until two clean runs. RIH and set 7", 26 # Baker FB-1 packer & tailpipe assembly on DP as follows:

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AMOUNT 1 650 1 30' 1 2 x 10' 1 1 x 10' 1 1 1 1

DESCRIPTION 3-1/2 " Wireline re-entry guide w/fluted guide 3-1/2" 9.3 lb/ft, J-55, EUE Tubing 3-1/2" “XN” Nipple (2.635" No Go ID) 3-1/2" 9.3 lb/ft, J-55, EUE Tubing as above 3-1/2" ‘X’ Nipple (2.75" ID) 3-1/2" 9.3 lb/ft, J-55, EUE Perforated pup joints 3-1/2" ‘X’ Nipple (2.75" ID) 3-1/2" 9.3 lb/ft, J-55, EUE Pup Joint 3-1/2" EUE Pin X-Over to seal bore extension Millout Extension Seal Bore Extension 7" Baker FB-1 Packer (ID = 4.0", OD = 5.875")

Note: • Drift the tail pipe with a 2.867" x 3' drift except the 'X' & 'XN' nipples. • Caliper all nipples before installation. • Run with the XPO (Pump Thru) plug in place in the first X-nipple below the packer. (2500 psi pressure is required to shear the XPO plug with diesel in the tubing) E)

Set the packer at ± 7180' (MD), 6486' (TVD), angle ± 46°. Make sure the end of tubing is ± 30' below the liner shoe into the horizontal section. Test the packer to 1000 psi. POH. Do not rotate the pipe while pulling out and laying down drill pipe. Note: Nipple above the perforated pup joints should not be set at an angle greater than 55°.

F)

RIH with the seal assembly on 3-1/2" x 4-1/2" tubing as follows: AMOUNT 1 1 1 1 1-jt 1 1-jt 1 As required 1 – 2 jts 1

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DESCRIPTION Mule Shoe guide (OD = 3.95" ID = 3.0” ) Packer Seals (set of 3), OD = 4" ID = 3.0” Spacer Bar, OD = 3.95" ID = 3.0” G – 22 Locator (OD = 4.5”, ID = 3.0”) 3-1/2", 9.3 lb/ft, J-55, EUE Tubing 3-1/2" , Otis X Nipple (2.813" ID) 3-1/2", 9.3 lb/ft, J-55, EUE Tubing as above 3-1/2" x EUE x 4-1/2" NEW VAM x-over 4-1/2", 11.6 lb/ft, J-55, NEW VAM Tubing 4-1/2”, 12.6#, J-55 VAM pups 11" x 4-1/2 " Tubing Hanger with Polish Nipple

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Note: • Inspect EUE and NEW VAM threads while on the rack, and clean the threads using degreasing solvent (AMS 26-301-798) and nylon brushes just prior to job. • Apply the dope evenly and ensure the use of a stabbing guide. • Drift the 3-1/2 inch tubing with a 2.867" x 3' drift. Drift seal assembly with 2.867" x 5.5' except 'X' nipple. • Drift the 4-1/2 inch tubing with a 3.875" x 5.5' drift every 1000' & at landing depth. • Have various lengths of 4-1/2", 12.6 lb/ft NEW VAM pup joints on location for space out. G)

H)

I)

J)

Tag packer. Pick up and circulate hole clean to remove any debris and pipe dope. Sting into the packer until the locator bottoms out. Pick up 3' and space out. Unsting from the packer. Displace tubing to diesel with 3% Coat-415. Sting into packer and bleed U- tube pressure and observe well for 15 minutes. If test is good, unsting from packer, displace TCA to inhibited diesel and tubing to diesel. Sting into packer and land tubing. Test TCA to 1500 psi and tubing to 1000 psi separately. Install BPV. ND BOPE. NU 4", 3000 psi tree. Orient the wing valve to the West. Pack off and pressure test bonnet and tree to 2500 psi. Plug the control line outlet. Retrieve the BPV. Complete the wellhead report and return to Drilling Engineering. RU and pump down the tubing to shear out the XPO plug at 2500 psi with diesel in tubing. (Do not exceed 3000 psi surface pressure). Note: After displacing the hole to diesel, the estimated BHP below the plug is 2483 psi with brine below the packer.

K)

L)

RU SAWL. Pressure test lubricator to 1000 psi. RIH and retrieve lock mandrel. RD SAWL. Flow the well for clean-up until the flow parameters stabilize. Record the flow parameters and collect representative fluid samples. Shut in and record the SIWHP. Secure wellhead, fill cellar with sand & release rig.

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1.2

Dual with Upper Retrievable/Lower Permanent Packer - Workover Procedure for Dual Arab-D Horizontal Producerl/Vertical Arab-D Vertical Observation Well WORKOVER PROCEDURE A) B) C) D) E) F) G) H) I) J) K) L) M) N) O) P)

Q)

R)

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The well is first decompleted. The Wellbore integrity is tested to 2000 psi. Orient and set 5-1/2" Whipstock in 7" casing 16' below the base of Arab-C Reservoir. Cut 2' window in 7" casing with starting mill. Cut an additional 6' with window mill. Drill 6' of open hole to Kick off point and circulate hole clean. Pressure test formation to 1500 psi to insure isolation from the Arab-C reservoir. Displace hole to 69 pcf Gypsum mud. Ream window with tandem window mill and watermelon mills. Drill short radius curve with short radius angle build BHA with 80°/100' BUR until 66.4° is reached. POH. RIH with short radius angle holding BHA. Ream curve section, then build to 90° at 10°/100'. Hold 90° inclination to the end of build section. RIH with Smith Whipstock retrieving tool and retrieve Whipstock. Run back in parent hole (vertical hole below sidetrack). Mill and push Bridgeplug to bottom. Ream out window with string mills. Run AC-DC tool to 16' above window. RIH with 7" Dresser "Slim GT" Packer and lower 3-1/2" Tailpipe assembly with "PX" plug in place, on Drillpipe. Set Packer and Tailpipe assembly +71 above 7" shoe (26' below casing window). Release hydraulic setting tool and POH. A 7" HDCH-5 test packer is run and set 14' below the 7" casing in order to test the Slim GT packer (12' below) to 1000 psi. The Hydraulic test packer is then POH. The upper packer assembly including a 7" Dresser G-10 packer with tailpipe assembly, Lateral Re-entry sub with self locator tool with isolation sleeve installed and 7" G-10 torque locked retrievable packer is RIH. This assembly is RIH to 12' above setting depth, then slowly rotated until the self-locator enters the window and locks in place. At this point the landing coupling should be 5' above the 7" Slim-GT packer. The assembly is then released, POH 13' and the locating procedure repeated to insure proper orientation. The assembly is pressure tested to 1000 psi after which a 1-1/4" steel ball is dropped and the packer set. The packer is re-tested to 1000 psi, setting tool released and POH.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 4 SECTION

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S)

T) U)

V) W)

X) Y)

1.3

The seal assembly for the upper G-10 packer is then RIH on the 4-1/2" production tubing. The packer is located, stung into and the TCA and tubing tested to 1000 psi. The isolation sleeve is Wireline retrieved from the LRS and a DOT Tubing Exit Whipstock set at the LRS sub. The Whipstock facilitates entry into the upper zone with coiled tubing such that the entire horizontal section can be stimulated with acidic brine. The Whipstock is then retrieved on Wireline with a GS-pulling tool. A "XPO” plug is set in the X-nipple above the LRS. The seal assembly is unstung from the upper packer. The tubing is displaced to diesel and TCA to inhibited diesel. TCA and tubing are tested to 1500 psi. Install BPV in tubing hanger. ND BOPE and NU single 4-1/16" 3M tree. After testing the tree and tubing to 3000 psi, the XPO plug is removed and the well brought on production. The "PX" plug set in the tailpipe of the lower packer is left in place to isolate the original vertical open hole.

Khuff Completion with 9-5/8" Permanent Packer with Tubing Anchor Seal Assembly COMPLETION PROCEDURE After pressure testing the 9-5/8” casing to 4000 psi with mud at PBTD, proceed as follows: A) B)

C)

D)

Flush hole clean with High-Vis pill and circulate hole clean with water. Observe well for one hour. POH. RIH with 8-3/8” bit and 9-5/8”, 58.4# scraper with 9-5/8”, 58.4# HedgeHog brush and work same one stand across packer setting depth of 10,784’. Cont. RIH to PBTD @ 11,615’. Pump and circulate 25 gal Rinse-Aid mixed with 20 bbl fresh water. Circulate clean. Spot 100 bbl of inhibited water (1% Coat B-1400) on bottom POH. RU SAWL 5M lubricator and WL BOPE. Test lubricator to 5000 psi with water. Run the following: i) ii)

8.25” ACDC to 10,884’ (100’ below packer setting depth) until two clean runs. 8.25” x 3’ drift to to 10,884’.

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E)

RIH with Halliburton 9-5/8” TWS packer and tail pipe assembly on DP as follows: WL guide, 4-1/2” 15.1# L-80 N-VAM Box Pup joint 4-1/2” 13.5# N-VAM Box x Pin (10’ long) RN nipple 4-1/2” Halliburton Perf. Pup jt. 4-1/2” 13.5#N-VAM Box x Pin (20’ long) R nipple 4-1/2” Pup Joint 4-1/2” 13.5# New VAM Box x Pin X-Over 5” 18# N-VAM Box x 4-1/2” 15.1# Pin M/Exten. 5” Halliburton 18# N-VAM Pin X Pin Packer Halliburton 9-5/8” TWS (AMS# 45-735-760)

(ID=3.826”, OD=5.68”) (ID=3.920”, OD=4.98”) (No Go ID=3.343”, OD=5.03) (ID=3.920”, OD=4.98”) (ID=3.688”, OD=5.030) (ID=3.92”, OD=5.0”) (ID=3.826”, OD=5.587”) (ID=4.23”, OD=5.00”) (ID=3.72”, OD=8.12”)

Position tail pipe at + 10,838’ (150’ above the top of the Khuff-B, with Packer 204’ above the Khuff-B). Drop ball, apply +2500 psi surface pressure, and set packer at 10,784’. PT packer to1500 psi. Shear out of packer. POH with drill string and setting tool. Note: • Exercise caution while RIH with the Packer assembly. • Packer depth at 10,784’ in vertical hole. • Prior to running the 5-1/2” production tubing, ensure the following procedures have been carried out: Full Vetco inspection, including API drift, and hydroblast the tubing at the Vetco yard (to remove any rust and scale build up). • • • F)

G)

Prior to RIH with tubing, install test plug and test tubing hanger bowl to 8000 psi with water. Mark test assembly at rotary. Measure from this mark to bottom of test plug while POH to obtain accurate measurement from the rotary table to the tubing hanger bowl. Pick up PBR/Seal Assembly and RIH on 5-1/2” 20 # NK-AC95ST w/NK3SB Connections to top of packer as follows: i) ii)

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Clean the threads w/ a nylon brush and cleaning solvent. Visually inspect all threads. Have Franks inspect and clean the threads prior to make-up.

Hal. Ratch/Latch with KTR Seals, 4-1/2”, 15.1# L-80 (H2S) N-VAM Box (OD=5.25”, ID=3.720”) Hal. PBR (5.875” OD x 5.00” seal bore ID) PBR-30’ unit, 15.1#, L80, N-VAM pin DN complete with “KTR” seals for 25’ stroke w/3.72” min ID and 4-1/2”, 15.1# L-80 (H2S) locator N-VAM Box up. (AMS# 45-753-150).

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 4 SECTION

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June 2006

COMPLETION PRACTICES RUNNING AND SETTING PROCEDURES

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iii)

Adapter, 5-1/2” 23.0# New Vam Box x 4-1/2” 15.10 # New Vam Pin AMS# 45-666-545 & AMS PEND 0706. iv) Pup joint 5-1/2” 20# N-VAM Box x Pin (6’) (ID=4.778”, OD=6.1”). v) X/O 5-1/2” 20# N-VAM Pin x 5-1/2” 20# NK-3SB Box vi) As required.(+8200’) 5-1/2”, 20#, NK-AC95ST/NK-3SB tbg. (AMS# 45-950-740) vii) X/O 5-1/2” 20# NK-3SB Pin x 20# N-VAM Box viii) 1 each Flow Cplg; 5”, 23.0# N-VAM, (OD=6.10, ID=4.56”) (AMS# 45-664-998) ix) 1 each Hal. “R” landing nipple, (OD=6.1”, ID=4.313”) (AMS# 45-717-310) x) 1 each (6’) Flow Cplg; 5-1/2”, 20# N-VAM, (OD-6.1”, ID=4.56”). xi) X/O 5-1/2” 20# N-VAM Pin x 5-1/2” 20# NK-3SB Box xii) + 2,500’ 5-1/2”, 20#,. NK-AC95ST/NK-3SB tubing (AMS# 45-950-740) xiii) X/O 5-1/2” 20# NK-3SB Pin x 20# N-VAM Box xiv) Tubing Hanger; 11” x 5-1/2” 20.1# N-VAM P X ACME (AMS# 401-822-45-9915-005). Note: • Have Enough 5-1/2” 20# NK-AC95ST/NK-3SB pup joints for space out. • Optimum make-up torque for 5-1/2” 20#NK-3SB =7200 ft-lb; N-Vam = 6800 ft-lb • Drift tubing w/4.653” x 3’ every 2000’ and @ landing depth. • Caliper “R” nipple before installing. • Use API modified tubing dope. Apply to pin ends using paint brush. • Use Franks torque-turn service to run the tubing. H)

I)

RIH to + 100’ above packer. Circulate @ 1-2 BPM to clean packer top. Slowly lower and latch into packer. Slack off + 10,000 lb. Pick up + 30,000 lb over string weight to shear from PBR. Wait two hours for temperature to stabilize if bottoms up were circulated. PU and space out. As per SAGED recommendations the final space out will be with 24” of slack-off from neutral weight. Test the annulus to 1500 psi. Bleed off pressure and mark tubing at the rotary (Mark-1). PU and measure from the mark made in step #8 (Mark – 1), the distance from rotary table to the tubing hanger bowl. Mark the tubing at this point (Mark-2).

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J)

K) L) M) N) O) P) Q)

PU and measure the length between Mark – 2 and the next tubing collar below Mark –2. This length less the length of the pup joint on the bottom of the tubing hanger will be the length of the pup joints needed for space out. Install two (2) full joints below the tubing hanger. Land tubing and check space out. RU WL Lubricator and WL BOP on top of Landing joint and test same to 6500 psi. RIH with Halliburton 3.688” Selective Test Tool and set same in “R” nipple in Tailpipe Assembly @ +10,805’. Pressure test tubing to 6000 psi with water for 15 minutes. WL retrieve 3.688” Selective Test Tool and RD WL. Unsting from PBR. Mix and pump the following pickling treatment down the tubing. i) 25 gal Rinse Aid mixed with 20 bbl water; followed by, ii) 5 drums (6.55 bbl) of Super Pickle. iii) Displace Super Pickle with water ½ bbl short of Seal Assembly. Do not over displace. Reverse Super Pickle and Rinse Aid solution out. Check returns for debris and dissolved pipe dope. Collect representative samples (Lab R&D will send technician). iv) Pump 1000 gal of 15% HCl Acid Pickle solution with the following Halliburton additives: Acid Pickle Formulation 442 gal Raw HCl (20 Be°) 20 gal HAI-85, Corrosion Inhibitor 55 lb HII-124C, Corrosion Inhibitor Intensifier 20 lb Fercheck, Iron Control 2.00 gal Losurf-300, Surfactant 536 gal Fresh Water v) vi)

Displace acid with water ½ bbl short of Seal Assembly. Do not over displace. Reverse out the spent acid pickle from tubing until hole is clean. Note: All the above will be performed using the choke manifold holding back pressure.

R)

Reverse circulate 240 bbl of diesel in tubing and 445 bbl of diesel inhibited with 3% SA- 193 in TCA. Observe well for one hour. Note: Pump + 50 bbl weighted (65 pcf) EZ-Spot spacer ahead of the diesel when reversing out. Formulate as follows: 25 bbl diesel + 20 bbl H20 + (3) 55 gal drums EZ-Spot.

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COMPLETION PRACTICES RUNNING AND SETTING PROCEDURES

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S)

T) U) V)

W)

2.0

Sting back into packer and land tubing. Screw in the lock down screws on the tubing spool. Test tubing to 6,000 psi with diesel & monitor TCA for 10 minutes. Re-test the TCA to 6,000 psi and observe tubing for 10 minutes. RU WL w/5M lubricator and test to 5000 psi with water. RIH and set “RO” plug in “R” nipple at + 2500’. POH and RD WL. Install BPV in Tubing Hanger. ND BOPE. NU 11” 10M Tubing Bonnet with 5” 10M Manual Lower Master Valve (MLMV gear box facing East with hand wheel facing North). NU 5” 10M Block Tree Assembly. Orientation of tree: Wing Valve to face East; Hydraulic actuator to face North and Tubing Kill Valve to face West (See Attachment). Pack off and test to 7500 psi with N2. Note: Have N2 unit with 4000 gal N2 available. Secure well and release rig.

GENERALIZED RUNNING PROCEDURE FOR KHUFF PBR COMPLETION COMPLETION PROCEDURE After running & cementing the 7” liner w/PBR (AMS# 45696-060), proceed as follows: A)

B)

RIH with 8-3/8” bit. Tag top of cement. Clean out to 7” liner top @ ±9,410’ MD/9,256’ TVD. Check for flow. Test TOL and 9-5/8” casing to 145 pcf EMW (3,700 psi surface pressure with 88 pcf mud). POH. RIH with 5-7/8” bit and drill out 7” liner to LC @ ±13,054’ MD/12,335’ TVD (PBTD). Test to 145 pcf EMW (4,920 psi with 88 pcf mud). Flush hole with High-Vis pill and circulate hole clean. Circulate well to water. Observe well for 1 hour. Pressure test well to 5000 psi with water. Note: Exercise caution when entering the 7” liner top. RIH slowly inside 7” liner.

C)

D) E) F)

RIH with 5-7/8” bit, 7”, 35# scraper with 7”, 35# Hedge Hog brush and 9-5/8”, 53.5# scraper w/9-5/8”, 53.5 # Hedge Hog brush to PBTD @ ±13,054’ MD (spaced out such that 9-5/8” scraper is at TOL when 5-7/8” bit is at PBTD). Circulate hole clean. Pump and circulate 25 gal of Rinse Aid mixed with 20 bbl of fresh water and circulate hole clean. Spot 140 bbl of 87 pcf saturated CaCl2 Brine (7” liner volume) on bottom. POH. RIH with 7-23/32” polish mill and ream the TIW LG-12 TBR (12’ X 7.75” ID). POH. RIH with 6-15/32” polish mill and ream the TIW PBR (24’ X 6.5” ID). Observe well for 1 hour. POH & LDDP. Prior to running the 5-1/2” production tubing, ensure the following procedures have been carried out: • Full Vetco inspection, including API drift, and hydroblast the tubing at the Vetco Yard to remove any rust and scale build up.

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Perform the following pipe inspection on the racks at the rig site: • • • G)

Clean the threads with nylon brush and cleaning solvent. Visually inspect all threads. Have Weatherford inspect and clean the threads prior to make-up.

Prior to RIH with tubing, install test plug and test tubing hanger bowl to 8,000 psi with water. Mark test assembly at rotary. Measure from this mark to bottom of test plug while POH to obtain accurate measurement from the rotary table to the tubing hanger bowl. RIH with 5-1/2”, 20.0#, C-95, N-VAM completion tubing to top of packer PBR @ ±9,410’ as follows: A)

B) C) D) E) F) G) H)

TIW PBR Seal assembly, 24’ w/KTR seal (3 sets), 8.25” OD x 4.778” Min ID, 7”, +35#, N-Vam -MS Locator Box X 5.5”, 23# Spacer Bar, L-80 (H2S) - 10M. (AMS# 45-696-062). 1 each X-Over, 7” 35#, L-80, N-VAM Pin X 5-1/2”, 20#, N-Vam L-80 Box. As required + 6,900’ 5-1/2”, 20 #, C-95 N-VAM tubing (AMS # 45-950-77-00) 1 each (6’) Flow Cplg; 5-1/2”, 23# C-95, N-VAM, Box X Pin (OD=6.098”, ID=4.560”) (AMS#45-664-998) 1 each Halliburton “R” landing nipple, 23# N-Vam(OD=5.5”, ID=4.313”) (AMS#45-717-310) 1 each (6’) Flow Cplg; 5-1/2, 23#, C-95 N-VAM. 2,500’ 5-1/2”, 20#, C-95 N-VAM tubing. 1 each Tubing Hanger; 11” x 5-1/2” 20# N-VAM P X ACME (AMS# 401-82245-9915-005).

Note: i) ii) iii) iv) v) vi) vii) viii) ix) x)

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Have enough 5-1/2” 20# N-VAM pup joints for space out. Optimum torque for 5-1/2” 20# N-VAM = 6,800 ft/lb. Drift tubing with 4.653” x 3’ Drift every 2,000’ and @ landing depth. Caliper “R” nipple before installing. Use Weatherford Lubeseal API modified tubing dope. Apply the dope to the pin ends using paint brush. Use Weatherford JAM service to run the tubing. Pump 25 gallons of Rinse Aid mixed with 20 bbl of fresh water, followed by 5 drums (6.55 bbl) of Super Pickle. Displace the Super Pickle with water to the end of tubing. Note: Avoid Super Pickle contact with PBR seals. Reverse circulate at maximum rate. Check returns for debris and dissolved pipe dope. Collect representative samples. Acid pickle the tubing string with 1,000 gal 15% HCl + additives. Reverse circulate the hole until it is clean.

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June 2006

COMPLETION PRACTICES RUNNING AND SETTING PROCEDURES

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Formulate Acid Pickle as follows: 442 gal Raw HCl (20 Be°) 20 gal HAI-85, Corrosion Inhibitor 55 lb HII-124C, Corrosion Inhibitor Intensifier 20 lb Fercheck, Iron Control 2.00 gal Losurf-300, Surfactant 536 gal Fresh Water xi)

Sting into the PBR seal assembly. Set down 10-15,000 lb of tubing weight on PBR. The final space out measurement will be at Neutral Weight. Test the annulus to 5,000 psi. Bleed off pressure and mark tubing at the rotary (Mark - 1). xii) PU and measure from the mark just made (Mark - 1), the distance from rotary table to the tubing hanger bowl. Mark the tubing at this point (Mark-2). xiii) PU and measure the length between Mark - 2 and the next tubing collar below Mark - 2. This length less the length of the pup joint on the bottom of the tubing hanger will be the length of the pup joints needed for space out. Install two (2) joints below the tubing hanger. xiv) Unsting from the PBR and reverse circulate 210 bbl diesel (one tubing volume) followed by 400 bbl diesel inhibited with 3% SA-193 (TCA volume). Observe well for one hour. xv) Sting back into packer and land tubing. Screw in the lock down screws on the tubing spool. Test tubing to 5,000 psi with diesel & monitor TCA for 10 minutes. Re-test the TCA to 5,000 psi and observe tubing for 10 minutes. xvi) RU WL w/5M lubricator and test to 5000 psi with water. RIH and set “RO” plug in “R” nipple at + 2500’. POH and RD WL. xvii) Install BPV in tubing hanger. ND BOPE. xviii) NU 11”, 10M tubing bonnet with 5” MLMV. NU 5”, 10M production tree with wing valve orientation to the EAST. Pack off & test to 7,500 psi with Nitrogen.

Note: Have Nitrogen unit with 4,000 gal N2 available. xix)

Secure well and release rig.

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TUBING DESIGN 1.0

SAUDI ARAMCO DESIGN FACTORS

2.0

DESIGN CONSIDERATIONS 2.1 Tubing Size Selection 2.2 Anticipated Production Rate 2.3 Nature of Produced Fluids 2.4 Accommodation of Through Tubing Tools 2.5 Economic Considerations 2.6 Tubular Availability

3.0

PICK-UP AND SLACK-OFF GUIDELINES 3.1 Tubing Movement and Force Analysis 3.1.1 Basic Pressure and Temperature Effects 3.1.2 Piston Effect 3.1.3 Pressure Buckling Effect 3.1.4 Ballooning Effect 3.1.5 Temperature Effect 3.2 Tubing Movement Formulas

4.0

SAUDI ARAMCO TUBING AND CASING TABLES

5.0

EXAMPLE TUBING MOVEMENT/FORCE PROBLEM 5.1 Landing Condition 5.2 Well Condition Prior to Acid Job 5.3 Acidizing Condition

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COMPLETION PRACTICES TUBING DESIGN

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TUBING DESIGN 1.0

SAUDI ARAMCO DESIGN FACTORS Tubing, like casing, must fulfill the design requirements dictated by the internal and external pressure loading conditions the tubing will be subjected to. In addition to satisfying the internal yield, collapse and tensile requirements the design must meet additional criteria. Saudi Aramco utilizes the same design factors for tubing as those used for casing which are: Burst: Collapse: Tension:

2.0

1.33 1.125 1.6

DESIGN CONSIDERATIONS 2.1

Tubing Size Selection Since the tubing usually contains the production stream, it must be sized accurately. Several factors are considered when selecting the correct tubing size for a well. Some of the main factors are:

2.2

Anticipated Production Rate The tubing must be of sufficient size to accommodate the expected production rate. Small tubing may cause high erosional velocities, a high pressure drop and low production rates. This is an important design consideration in high capacity reservoirs like those in Saudi Aramco.

2.3

Nature of Produced Fluids In practice, oil wells produce fluids in either two-phase (oil/water or oil/gas) or three phase (oil/water/gas) flow. Gas wells can also carry liquid in the flow stream. These multi-phase flow regimes complicate the modeling of fluid flow in tubing strings. When wells become water-cut for example, the water may break out and load up in the tubing string if the fluid velocity is too low. A smaller tubing string may be required to maintain a higher fluid velocity to carry the water to surface. Tubing size selection requires several reservoir and production parameters as input to the calculations. Saudi Aramco uses a computer program called "Pipe-Flow" to accurately model these complicated production streams. It is extensively used by Saudi Aramco Production Engineering Departments to determine tubing sizes required for new wells and workover wells. To

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COMPLETION PRACTICES TUBING DESIGN

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accurately calculate tubing size, it is recommended to review the "Pipe-Flow" program. 2.4

Accommodation of Through Tubing Tools Another consideration is the minimum acceptable through-bore for survey, servicing, production logging and coiled tubing unit (CTU) operations. Slim logging tools are typically 1-11/16" in diameter and can be accommodated with 2-3/8" production tubing. However wells with special logging requirements, such as the 3-5/8" Carbon-Oxygen log or Induction log, need tubing strings sized large enough to accommodate them. Some wells may require landing nipples with no-go profiles which may further restrict throughbore diameter. It is therefore important to communicate with the production engineer to determine the size of tools which will be run in the well after the completion operation.

2.5

Economic Considerations Larger tubing sizes typically cost more. An incentive toward smaller diameter tubing is the savings in tubular costs. Tubing sizes should be as small as practical, yet still fulfill the production requirements of the well.

2.6

Tubular Availability Once the accurate tubing size is determined (4" tubing for example), it may be found that the particular tubing size is not available. Saudi Aramco maintains a stock of tubulars of standard sizes and are listed in Appendix A. Some tubulars may have been discontinued (at the time of this printing) and new ones may appear which are not on the list. An up-to-date Aramco Material Supply (AMS) list should be reviewed when checking tubular availability. If the exact size tubing is not available, then either one size smaller or larger must be chosen. Since 4" tubing is not an Aramco stock item, then either 3-1/2" or 4-1/2" must be chosen. The 3-1/2" or 4-1/2" tubing may also be out of stock, further restricting the choice of tubulars available. It is therefore important to determine the size of tubulars required (and what tubulars are available) well in advance of any drilling or workover project. For new wells, once the tubing size is selected, the outer casing sizes may then be determined to accommodate the tubing. For older existing wells, the casing size frequently dictates the maximum tubing size which can be run in the well. Wells completed with 4-1/2" casings are very limited as to the size of tubing which can be run.

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COMPLETION PRACTICES TUBING DESIGN

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3.0

PICK-UP AND SLACK-OFF GUIDELINES 3.1

Tubing Movement and Force Analysis The typical Saudi Aramco oil producers have standard tubing landing procedures which accommodate anticipated tubing movement and forces. However, in extraordinary circumstances all possible conditions may need to be reviewed when designing tubing strings. For example, high internal pressure loading may be caused by several different well pressures such as producing, shut-in, stimulation treatments, testing, well killing operations (bull heading), artificial lift operations, etc. In addition to pressure forces, thermal forces may elongate or shrink the tubular beyond acceptable limits. This section will review the basics of tubing movement and force analysis. When the completion tubing is spaced-out and landed, the conditions affecting the tubing and packer are known. These conditions include tubing size and length, casing size, fluid inside and outside the tubing, temperatures, surface pressures and any mechanical forces applied. This point is used as a "reference point" to calculate the changes in forces and length for future conditions. In a tubing string, sealed off in a packer, there are four factors that cause length and force changes. These factors are dependent on well conditions, tubing/packer/casing configuration, and tubing restraint. Each factor acts independently and may either add to or cancel the effects of the other factors. Therefore it is important to keep the direction of the length changes and forces correct. Furthermore, mechanically applied tension or compression may be used to negate the combined effect of the pressure and temperature changes. 3.1.1

Basic Pressure and Temperature Effects The four pressure and temperature effects which should be investigated for future well operating conditions are:

3.1.2

Piston Effect Changes in pressure at the packer act on the inside and outside piston areas to produce length and force changes. These changes may be either up or down depending on the tubing/packer configuration.

3.1.3

Pressure Buckling Effect Changes in pressure that cause a higher pressure inside the tubing than outside, at the packer, cause pressure buckling. Pressure buckling is a shortening of the effective length of the tubing string because the tubing bends into a spiral (or helix) within the casing. It can only shorten the tubing and only exerts a negligible force.

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Although pressure buckling and mechanical buckling appear to have the same mechanics, they must be considered separately as they are produced by completely different factors

3.2

3.1.4

Ballooning Effect Changes in average pressure cause a radial swelling (ballooning) or contraction (reverse-ballooning) and a corresponding shortening or lengthening of the tubing string.

3.1.5

Temperature Effect Changes in the average temperature of the tubing string cause thermal expansion or contraction of the tubing. Thermal forces are prominent in tubing strings in deep hot wells such as the Khuff gas wells.

Tubing Movement Formulas The terms and simplified formulas for calculating tubing movement are given below. These formulas give the length and force changes for common wells of one tubing and one casing size. More than one tubing or casing size requires that the calculations be made on each section and combined for a final condition. Length changes are in feet and force changes are in pounds. The terms in each of the equations are defined in the following section "Length and Force Terms". Piston Effect

a)

Length change

The length change due to the piston effect ∆L 1 , is expressed with the following formula:

∆L1 =

−L

EA S

[ (A

p

− A i )∆Pi − ( A p − A o )∆Po

b)

]

_____________(1)

Force change

The force change due to the piston effect is expressed as follows:

F1 = ( A p − A i )∆Pi − ( A p − A o )∆Po

_______________________(2)

Pressure Buckling Effect

a)

Length change

(only if ∆Pi is greater than ∆Po ):

The length change due to the pressure buckling effect is expressed with the following formula

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COMPLETION PRACTICES

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TUBING DESIGN

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∆L 2 =

−1.5r 2 A 2p ( ∆Pi − ∆Po ) 2 EI( Ws + Wi − Wo )

_________________________(3)

b)

Force change

The force change is negligible since this effect mainly shortens the tubing.

Ballooning Effect

a)

Length change

The length change due to the ballooning effect is expressed as follows:

∆L 3 =

−2 Lγ ⎡ ∆Pia − R 2 ∆Poa ⎤ ⎢ ⎥ E ⎢⎣ R2 − 1 ⎥⎦

_________________________(4)

b)

Force change

The force change due to the ballooning effect is expressed as follows:

F3 = −0.6( ∆Pia A i − ∆Poa A o )

_______________________(5)

Temperature Effect

a)

Length change

The length change due to the temperature effect is expressed as follows:

∆L 4 = Lβ∆T

_______________________(6)

b)

Force change

The force change due to the temperature effect is expressed as follows:

F4 = 207A s ∆T

_______________________(7)

Since the stresses involved with tubing movement are three dimensional and require complex calculations, the formulas for stress are not included.

Length and Force Terms L

=

Depth, feet

E

=

Modulus of elasticity, psi (30 x 106 psi for steel)

As = Ap

Cross-sectional area of the tubing wall, sq. in.

Ai =

Area of tubing ID, sq. in.

Ao =

∆Pi

Area of tubing OD, sq. in.

∆Po

=

Change in tubing pressure at the packer, psi.

∆Pia

=

Change in annulus pressure at the packer, psi

=

Change in average tubing pressure, psi

=

Area of packer ID, sq. in.

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COMPLETION PRACTICES

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TUBING DESIGN

___________________________________________________________________________________________________________________________

∆Poa

∆T

=

Change in average annulus pressure, psi

=

Change in average tubing temperature, oF

r

=

Radial clearance between tubing OD and casing ID, inches

l

=

Moment of inertia of tubing about its diameter

=

where

π

64

(D o4 − D i4 )

D o is outside diameter and D i

is inside diameter

Ws

=

Weight of tubing, lb/ft

Wi

=

Weight of fluid in tubing, lb/ft

Wo =

Weight of displaced fluid, lb/ft

β γ

=

Ratio of tubing OD to ID

=

Coefficient of thermal expansion (6.9 x 10-6 in/in/oF for steel)

=

Poisson's ratio (0.3 for steel)

R

Sign Convention In tubing movement and force calculations it is important to be consistent with the sign conventions (positive or negative numbers) used in the formulas and calculation results. For example, if a negative length change occurred, does that mean the tubing moved upward or downward? If a positive force change occurred, does that mean the tubing is in tension or compression? The following sign conventions are used by the majority of the industry: A)

Length Changes Negative length changes refer to the upward tubing movement Positive length changes refer to the downward tubing movement

B)

Force Negative forces refer to tension Positive forces refer to compression

C)

Pressure Changes Negative pressure changes refer to pressure reduction Positive pressure changes refer to pressure increase P = Pfinal - Pinitial

D)

Temperature Changes Negative temperature changes refer to temperature reduction Positive temperature changes refer to temperature increase T = Tfinal - Tinitial

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June 2006

COMPLETION PRACTICES

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TUBING DESIGN

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4.0

SAUDI ARAMCO TUBING AND CASING TABLES

Table 4D-1 - RECOMMENDED MAKE-UP TORQUE FOR NON-PREMIUM CASING/TUBING SAUDI ARAMCO NON-PREMIUM CASING/TUBING CONDUCTOR CASING

Minimum (ft-lbs.)

Optimum (ft-lbs.)

Maximum (ft-lbs.)

-

WELD WELD

-

26,000

WELD WELD 29,000

32,000

24,000 24,000

WELD 26,000 26,000

28,000 28,000

18-5/8” 87.50# K-55, R-3, BTC 18-5/8” 115.00# K-55, R-3, BTC

Base of Triangle Base of Triangle

Base of Triangle Base of Triangle

Base of Triangle Base of Triangle

13-3/8” 13-3/8” 13-3/8” 13-3/8” 13-3/8”

61.00# 61.00# 68.00# 72.00# 72.00#

J-55, K-55, K-55, L-80, S-95,

R-3, R-3, R-3, R-3, R-3,

STC STC BTC STC BTC

4,460 4,750 Base of Triangle 7,720 Base of Triangle

5,950 6,330 Base of Triangle 10,290 Base of Triangle

7,440 7,910 Base of Triangle 12,860 Base of Triangle

9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8” 9-5/8”

36.00# 36.00# 40.00# 40.00# 40.00# 43.50# 47.00# 53.50#

J-55, K-55, J-55, K-55, L-80, L-80, L-80, S-95,

R-3, R-3, R-3, R-3, R-3, R-3, R-3, R-3,

LTC LTC LTC LTC LTC LTC LTC BTC

3,400 3,670 3,900 4,210 5,450 6,100 6,700 Base of Triangle

4,530 4,890 5,200 5,610 7,270 8,130 8,930 Base of Triangle

5,660 6,110 6,500 7,010 9,090 10,160 11,160 Base of Triangle

7” 7” 7” 7” ♦7”

23.00# 26.00# 26.00# 26.00# 26.00#

J-55, R-3, LTC J-55, R-3, LTC K-55, R-3, LTC K-55, R-3, NVAM K-55, R-3, OLD VAM

2,350 2,750 3,010 6,510 8,000

3,130 3,670 4,010 7,230 8,700

5”

15.00#

K-55/L-80, R-3, BTC

Base of Triangle

Base of Triangle

Base of Triangle

4-1/2” 4-1/2” 4-1/2” ♦4-1/2” ♦4-1/2” 4-1/2”

11.60# 11.60# 11.60# 12.60# 12.60# 12.60#

J-55, R-3, L-80, R-3, J-55, R-3, J-55, R-2, J-55, R-3, L-80-13CR,

1,160 1,670 4,300 3,190 4,300 -

1,540 2,230 4,700 3,540 4,700 4,120

1,930 2,790 5,100 3,890 5,100 -

48” 36”

0.500" wt. 253.65# GR-B, R-3, BE 0.625" wt. 236.15# GR-B, R-3, BE

30” 30” 30”

0.500" wt. 157.50# X-42, 55/60', SJ 0.750" wt. 234.30# X-42, 55/50', SJ 0.750" wt. 239.00# X-42, 55/60', JV-LW

24” 97.00# GR-B, R-3, SJ ♦24” 0.688” wt. 176.00# X-42, R-3, V-LS 24” 0.688” wt. 176.00# X-42, R-3, V-RL4S

CASING and TUBING

STC LTC OLD VAM NVAM OLD VAM R-3, FOX

3,910 4,590 5,010 7,950 10,100

3-1/2”

9.30# J-55,

R-2, EUE

1,710

2,280

2,850

2-7/8”

6.50# J-55,

R-2, EUE

1,240

1,650

2,060

2-3/8”

4.70# J-55,

R-2, EUE

970

1,290

1,610

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June 2006

COMPLETION PRACTICES TUBING DESIGN

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SAUDI ARAMCO PREMIUM CASING and TUBING

♦13-3/8” 72.00# C-95VT/ SM-95T, R-3, NVAM 13-3/8” 72.00# NKHC-95, R-3, NK-3SB 13-3/8” 72.00# NT-95HS, R-3, NS-CC ♦13-3/8” 86.00# C-95VT/ SM-95T, R-3, NVAM 13-3/8” 86.00# NKHC-95, R-3, NK-3SB 13-3/8” 86.00# NT-95HS, R-3, NS-CC

♦9-5/8” 53.50# C-95VTS/SM-95TS, R-3, NVAM 9-5/8” 53.50# NKAC-95T, R-3, NK-3SB 9-5/8” 53.50# NT-90HSS, R-3, NS-CC ♦9-5/8” 58.40# P-110VT/ SM-110T, R-3, NVAM 9-5/8” 58.40# NKHC-110, R-3, NK-3SB 9-5/8” 58.40# NT-105HS/-110HS, R-3, NS-CC

♦7” ♦7” 7” 7” ♦7” ♦7” ♦7” ♦7” ♦7”

26.00# 32.00# 32.00# 32.00# 35.00# 35.00# 35.00# 35.00# 35.00#

K-55, R-2, NVAM C-95VTS/ SM-95TS, R-3, NVAM NKAC-95T, R-3, NK-3SB NT-95HSS, R-3, NS-CC L-80, R-3, NS-CC L-80, R-3, NK-3SB L-80, R-3, NVAM MS L-80, R-3, HYDRIL SUPER-EU L-80, R-3, AB IJ-4S

♦5-1/2” 20.00# C-95VTS/SM-95TS, R-3, NVAM 5-1/2” 20.00# NKAC-95T, R-3, NK-3SB 5-1/2” 20.00# NT-95HSS, R-3, NS-CC ♦∇ 5-1/2” 23.00# L-80, R-3, NVAM

♦4-1/2” 12.60# J-55, R-2, NVAM ♦4-1/2” 13.50# L-80, R-3, NVAM ♦4-1/2” 13.50# C-95VTS/ SM-95TS, R-3, NVAM 4-1/2” 13.50# NKAC-95T, R-3, NK-3SB 4-1/2” 13.50# NT-95HSS, R-3, NSCT ♦ 4-1/2” 13.50# KO-105T, R-3, HTS ♦∇ 4-1/2”15.10# L-80, R-3, NVAM

Minimum (ft-lbs.)

Optimum (ft-lbs.)

Maximum (ft-lbs.)

14,400 16,000 13,100

15,900 20,000 14,800

17,400 24,000 16,600

14,400 16,000 13,100

15,900 20,000 14,800

17,400 24,000 16,600

14,400 13,200 9,500

15,900 16,500 10,800

17,400 19,800 12,300

14,400 13,600 10,200

15,900 17,000 11,700

17,400 20,400 13,300

6,510 9,850 8,800 6,600 6,900 9,600 9,500 8,500 -

7,230 10,850 11,000 7,600 8,000 12,000 10,500 9,560 10,000

7,950 11,850 13,200 8,600 9,000 14,400 11,500 10,625 -

6,120 5,760 5,100 7,170

6,800 7,200 5,900 7,960

7,480 8,640 6,800 8,750

3,190 4,430 5,080 3,520 2,900 4,200 5,210

3,540 4,920 5,640 4,400 3,600 4,725 5,790

3,890 5,410 6,200 5,280 4,300 5,250 6,370

3-1/2” 12.95# L-80, R-2,

HYDRIL PH-6

5,500

6,185

6,875

2-7/8” 6.40# J-55, R-2, 2-7/8” 8.70# L-80, R-2,

NSCT-SC HYDRIL PH-6

1,160 3,000

1,340 3,375

1,520 3,750

500 ♦2-3/8” 4.70# L-80, R-2, AB FL-4S 2-3/8” 4.70# L-80, R-2, HYDRIL CS 1,500 1,685 2-3/8” 5.80# L-80, R-2, NVAM 1,500 1,660 2-3/8” 5.90# L-80, R-2, HYDRIL PH-6 2,200 2,475 Note: ♦ Tubulars that are being phased out. ∇ Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly].

1,875 1,820 2,750

The use of a make-up monitoring system (Jam, Torque/Turn, etc.) should be used on all production tubing strings with specialty connections to ensure a more accurate make-up.

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COMPLETION PRACTICES TUBING DESIGN

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Table 4D-3 - SAUDI ARAMCO NON-PREMIUM TUBING & CASING DATA SIZE

WEIGHT

GRADE

CONNECTION

I.D.

DRIFT

CONN. O.D.

BURST

COLLAPSE

JT/ YLD STRENGTH

in.

ppf

in.

in.

in.

psi

psi

1,000's lbs.

24 24

97.00 176.00

B X-42

SJ VETCO-LS

23.25 22.624

22.250

25.500

2170

1080

2,116

18-5/8 18-5/8

87.50 87.50

J-55 K-55

BTC BTC

17.755 17.755

17.567 17.567

19.625 19.625

2250 2250

630 630

1,329 1,367

13-3/8 13-3/8 13-3/8 13-3/8 13-3/8 13-3/8 13-3/8 13-3/8

61.00 61.00 68.00 68.00 68.00 68.00 72.00 72.00

J-55 K-55 J-55 K-55 J-55 K-55 L-80 S-95

STC STC STC STC BTC BTC STC BTC

12.515 12.515 12.415 12.415 12.415 12.415 12.347 12.347

12.359 12.359 12.259 12.259 12.259 12.259 12.191 12.250

14.375 14.375 14.375 14.375 14.375 14.375 14.375 14.375

3090 3090 3450 3450 3450 3450 4550 4930 *

1540 1540 1950 1950 1950 1950 2670 3470

595 633 675 718 1,069 1,069 1,040 1,935

9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8 9-5/8

36.00 36.00 40.00 40.00 40.00 40.00 43.50 47.00 53.50

J-55 K-55 J-55 K-55 L-80 13CR L-80 L-80 L-80 S-95

LTC LTC LTC LTC LTC LTC LTC LTC BTC

8.921 8.921 8.835 8.835 8.835 8.835 8.755 8.681 8.535

8.765 8.765 8.679 8.679 8.679 8.679 8.599 8.525 8.500

10.625 10.625 10.625 10.625 10.625 10.625 10.625 10.625 10.625

3520 3520 3950 3950 5750 5750 6330 6870 9160 *

2020 2020 2570 2570 3090 3090 3810 4760 8850

453 489 520 561 727 727 813 893 1,477

7 7 7 7 7 7 7 7 7 7

23.00 26.00 26.00 26.00 26.00 26.00 26.00 26.00 35.00 35.00

J-55 J-55 K-55 J-55 K-55 J-55 K-55 13CR L-80 L-80 L-80

STC LTC LTC VAM VAM NVAM NVAM LTC LTC VAM

6.366 6.276 6.276 6.276 6.276 6.276 6.276 6.276 6.004 6.004

6.241 6.151 6.151 6.151 6.151 6.151 6.151 6.151 5.879 5.879

7.656 7.656 7.656 7.681 7.681 7.681 7.681 7.656 7.656 7.681

4360 4980 4980 4980 4980 4980 4980 7240 9240 9960

3270 4320 4320 4320 4320 4320 4320 5410 10180 10180

284 367 401 415 415 415 415 511 734 725

5 5

15.00 15.00

K-55 13CR L-80

Spec. Cl. BTC Spec. Cl. BTC

4.408 4.408

4.283 4.283

5.375 5.375

5130 7460

5560 7250

241 350

4-1/2 4-1/2 4-1/2 4-1/2 4-1/2

11.60 11.60 11.60 12.60 13.50

J-55 J-55 13CR L-80 J-55 L-80

STC LTC LTC VAM VAM

4.000 4.000 4.000 3.958 3.920

3.875 3.875 3.875 3.833 3.795

5.000 5.000 5.000 4.892 4.862

5350 5350 7780 5790 8540

4960 4960 6350 5720 9020

154 162 212 198 211

NOTE: [1] [2]

Internal yield values (*) listed above reflect the lower value for buttress couplings. Value provided is the minimum value, either pipe body strength or joint strength.

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D

SECTION

June 2006

TUBING DESIGN

___________________________________________________________________________________________________________________________

Table 4D-4 - SAUDI ARAMCO PREMIUM TUBING AND CASING DATA SIZE

WEIGHT

GRADE

CONN

LENGTH

wt.

I.D.

DRIFT

CONN. O.D.

BURST

COLLAPSE

JT/ YLD STRENGTH

in.

ppf

range

in.

in.

in.

in.

psi

psi

1,000's lbs.

48 36 30

253 236 234 176

B X-60 X-42 X-42

BE BE SJ LS

40’ 40' 55-60' R-3

0.500 0.625 0.750 0.688

47.000 34.750 28.500 22.624

22.250

48.000 36.000 25.500

1822 1890 2170

254 768 1080

2,116

24

176

X-42

RL-4S

R-3

0.688

22.25 (con)

22.125

25.250

2170

1080

2,116

18-5/8

115

K-55

BTC

R-3

0.594

17.437

17.249

20.000

3070

1511

1,850

13-3/8 13-3/8

72 72 72

S-95 NT-95HS C-95VT

BTC NS-CC N-VAM

R-3 R-3 R-3

0.514 " "

12.347 " "

12.250 " "

14.375 14.375 14.398

4930 * 6390 6390

3470 3680 3900

1,935 1,935 1,935

72

SM-95T

N-VAM

R-3

"

"

"

14.398

6390

3680

1,935

13-3/8

72

NKHC-95

NK-3SB

R-3

"

"

"

14.375

6390

3890

1,973

♦13-3/8 ♦13-3/8 13-3/8

86 86

NT-95HS C-95VT

NS-CC N-VAM

R-3 R-3

0.625 "

12.125 "

12.000 "

14.375 14.398

7770 7770

6260 6560

2,333 2,333

86

SM-95T

N-VAM

R-3

"

"

"

14.398

7770

6240

2,333

13-3/8

86

NKHC-95

NK-3SB

R-3

"

"

"

14.375

7760

6500

2,333

9-5/8 9-5/8

53.5 53.5 53.5

S-95 NT-90HSS C-95VTS

BTC NS-CC N-VAM

R-3 R-3 R-3

0.545 " "

8.535 " "

8.500 " "

10.625 10.625 10.650

9160 * 8920 9410

8850 9330 8960

1,477 1,386 1,477

53.5

SM-95TS

N-VAM

R-3

"

"

"

10.650

9410

9350

1,477

9-5/8

53.5

NKAC-95T

NK-3SB

R-3

"

"

"

10.625

9410

8940

1,477

9-5/8

58.4

NS-CC

R-3

0.595

8.435

8.375

10.625

11900

12050

1,739

♦9-5/8 ♦9-5/8 9-5/8

58.4 58.4

NT105HSS NT-110HS P-110VT

NS-CC N-VAM

R-3 R-3

" "

" "

" "

10.625 10.650

11960 11900

12870 11880

1,857 1,857

58.4

SM-110T

N-VAM

R-3

"

"

"

10.650

11900

12800

1,857

9-5/8

58.4

NKHC-110

NK-3SB

R-3

"

"

"

10.625

11900

12860

1,857

♦7 ♦7

32 32

NT-95HSS C-95VTS

NS-CC NVAM-MS

R-3 R-3

0.453 "

6.094 "

6.000 "

7.656 7.732

10760 10760

11380 11160

885 885

32

SM-95TS

NVAM-MS

R-3

"

"

"

7.732

10760

11190

885

32

NKAC-95T

NK-3SB

R-3

"

"

"

7.772

10760

11150

885

35

L-80

NS-CC

R-3

0.498

6.004

5.879

7.656

9960

10180

814

35

L-80

NVAM-MS

R-3

"

"

"

7.805

9960

10180

814

35

L-80

NK-3SB

R-3

"

"

"

7.772

9960

10180

814

5-1/2 5-1/2

23 20 20

L-80 NT-95HSS C-95VTS

N-VAM NS-CC N-VAM

Tbg. Hngr R-3 R-3

0.415 0.361 "

4.670 4.778 "

4.545 4.653 "

6.075 6.050 6.075

10560 10910 10910

11160 11580 11410

478 554 554

20

SM-95TS

N-VAM

R-3

"

"

"

6.075

10910

11450

554

5-1/2

20

NKAC-95T

NK-3SB

R-3

"

"

"

6.050

10910

11400

554

15.1

L-80

N-VAM

Tbg. Hngr

0.337

3.826

3.701

5.010

10480

11080

353

13.5 13.5

NT-95HSS C-95VTS

NS-CC N-VAM

R-3 R-3

0.290 "

3.920 "

3.795 "

5.000 4.961

10710 10710

11330 11090

364 364

♦24

♦13-3/8 ♦13-3/8

♦9-5/8 ♦9-5/8

7

7

∇

♦7 ♦7 ♦7

♦5-1/2 ♦5-1/2

∇

4-1/2 4-1/2

♦4-1/2 ♦4-1/2

13.5

SM-95TS

N-VAM

R-3

"

"

"

4.961

10710

11120

364

4-1/2 4-1/2 4-1/2

13.5 13.5 13.5 13.5

NKAC-95T L-80 D-95HC KO-105T

NK-3SB N-VAM HYDRIL TS HYDRIL TS

R-3 R-3 R-3 R-3

" 0.290 " "

" 3.920 " 3.840(con)

" 3.795 " "

5.000 4.961 4.719 "

10710 9020 10720 10710

11080 8540 12070 11280

364 307 300 295

3-1/2

12.95

L-80

HYDRIL PH-6

R-2

0.375

2.687(con)

2.625

4.313

15000

15310

295

♦4-1/2

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COMPLETION PRACTICES TUBING DESIGN

___________________________________________________________________________________________________________________________

NOTE: [1] [2] [3] [4] ♦ ∇

Internal yield values (*) listed above reflect the lower value for buttress couplings. Value provided is the minimum value, either pipe body strength or joint strength. The RL-4S connector ID is less than that of the LS connector (RL-4S = 22.250” ID, LS = 22.624” ID) . The Hydril PH-6 connector ID is less than that of the pipe body (Conn. = 2.687” ID, Body = 2.750” ID) Tubulars that are being phased out. Completion accessory items. [Flow Coupling, 'R' Landing Nipple, Seal Assembly]

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COMPLETION PRACTICES TUBING DESIGN

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5.0

EXAMPLE TUBING MOVEMENT / FORCE PROBLEM The following example takes a typical Saudi Aramco oil producer and calculates the tubing movements and forces which result when the well is acidized. It is provided here to show how the basic tubing movement and force equations are used. It does not cover the three dimensional (or triaxial) stresses since these equations are very complicated12. Acidization is one of the most stressful operations performed on a well. If not designed properly the well could be damaged to the point that an expensive workover is required to repair it. High surface pumping pressures balloon the tubing, causing it to contract, or shrink. Since the acid is normally pumped at ambient temperature, it is much cooler than the fluid (oil or gas) which was originally in the tubing. This causes the tubing to shrink due to thermal contraction. A combination of these movements, if large enough, may cause the tubing to disengage or "unsting" from the packer allowing the acid, the wellhead injection pressure and subsequent production fluid to be in contact with the tubing/casing annulus. In older wells, it may be possible that the seal assembly is stuck in the packer, not allowing the free movement of the seals in the seal bore extension. Since the tubing cannot move, tensile forces are imparted to the tubing string. These forces, if high enough, may part the tubing. The piston effect at the packer also plays a role in tubing movement and forces, depending on the tubing and packer configuration. Three basic well conditions are reviewed: 5.1

1

2

Landing Condition: This condition describes the well when the tubing string was initially installed or landed. For this example the following landing conditions, typical of Saudi Aramco onshore oil producers will be used (refer to Figure 11 for the well cross section): • Production casing is 7" 26# J-55 (6.276" ID from casing tables) • Production tubing is 4-1/2" 12.6# J-55 VAM (3.958" ID from tubing tables) • Packer depth is 7000' • Packer seal bore is 4.00" in diameter and is 12' long

Two classic papers have been presented on this subject: - D. J. Hammerlindl (Arco) "Movement, Forces and stress Associated with Combination Tubing Strings Sealed with Packers" published in JPT February, 1977. - Arthur Lubinski (Amoco) et al "Helical Buckling of Tubing Sealed in Packers" JPT June, 1962. Saudi Aramco maintains an in-house computer program called the "Tubing Distortion Program" which can be accessed on the mainframe by selecting ISPF option P.6.25. It calculates tubing movement, forces and triaxial stresses. It was developed by Allen Blanke during the Khuff drilling campaign in 1984 for the Khuff gas completions.

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COMPLETION PRACTICES TUBING DESIGN

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• • • • • • •

Seal assembly spaced out 3' Packer (tubing/casing annulus) fluid is inhibited diesel (51 pcf) Tubing fluid is diesel (51 pcf) Shut in tubing pressure (SITP) = 0 psi Shut in casing pressure (SICP) = 0 psi Wellhead temperature = 80 oF Bottom hole (stabilized) temperature = 220 oF

5.2

Well Condition Prior to Acid Job: This condition describes the well before the acid job. It is provided as background information and is not used in the calculations: • Inhibited diesel packer fluid (51 pcf) • Tubing fluid is oil and gas (~53 pcf) • Shut in tubing pressure (SITP) = 400 psi • Shut in casing pressure (SICP) = 0 psi • Wellhead temperature = 80 oF • Bottom hole temperature = 220 oF

5.3

Acidizing Condition: This condition describes the well during the acid job. Refer to Figure below. • Packer (tubing/casing annulus) fluid is inhibited diesel (51 pcf) • Tubing fluid is 15% HCl acid (67 pcf) • Tubing injection pressure (TIP) = 3000 psi • Shut in casing pressure (SICP) = 500 psi • Wellhead temperature = 80 oF • Bottom hole temperature = 100 oF

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 4

D

SECTION

June 2006

COMPLETION PRACTICES TUBING DESIGN

___________________________________________________________________________________________________________________________

WELLHEAD INJECTION PRESSURE 3000 PSI

FROM PUMPER TRUCKS

CASING PRESSURE 500 PSI

15% HCl ACID (67 PCF)

4-1/2" PRODUCTION TUBING (12.6# J-55 VAM)

INHIBITED DIESEL TUBING-CASING ANNULUS FLUID (51 PCF)

4-1/2" X 3-1/2" CROSSOVER ABOVE PACKER 7" PRODUCTION PACKER @ 7000' with 4.00" SEAL BORE EXTENTION

3-1/2" TAILPIPE 7" PRODUCTION CASING (26# J-55) 6-1/8" OPEN HOLE

TYPICAL SAUDI ARAMCO ONSHORE OIL PRODUCER (TUBING MOVEMENT FORCES EXAMPLE) FIGURE/4D-1

FIGURE 11

Assignment of Length and Force Terms: The length and force change terms (as defined in the previous section) can be defined as follows: L

=

Depth

=

7000'

E

=

30 x 106 psi (Modulus of elasticity for steel)

As

=

Cross-sectional area of the tubing wall

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Drilling & Workover Engineering Department CHAPTER 4

COMPLETION PRACTICES

D

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June 2006

TUBING DESIGN

___________________________________________________________________________________________________________________________

=

π 4

Ap

= = =

3.6 sq. in. Area of packer ID

π 4

Ai

× 4.00 2

=

12.56 sq. in.

=

Area of tubing ID

=

π 4

Ao

( 4.5 2 − 3.958 2 )

× 3.985 2

=

12.47 sq. in.

=

Area of tubing OD

=

π 4

∆Pi =

=

=

=

∆Po = =

× 4.5 2

15.90 sq. in. Change in tubing pressure at the packer change in hydrostatic pressure + change in wellhead pressure

⎡ (67 − 51) ⎤ × 7000 ⎥ + 3000 ⎢ ⎢⎣ 144 ⎥⎦ 3778 psi Change in annulus pressure at the packer

=

change in hydrostatic pressure + change in wellhead pressure

=

0 + 500

∆Pia =

500 psi

=

=

=

Change in average tubing pressure

[ BH press

] − [ BH press

avg. tubing press while acidizing - avg. initial tubing condition press ( acidizing )

+ surf press ( acidizing ) 2

( initial )

+ surf press ( initial ) 2

]

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TUBING DESIGN

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=

∆Poa =

=

=

= =

∆T =

=

=

=

⎡⎛ 67 ⎤ ⎞ × 7000 + 3000⎟ + 3000 ⎥ ⎢⎜ ⎠ ⎢⎣⎝ 144 ⎥⎦ − 2 3389 psi Change in average annulus pressure

avg. annulus press while acidizing - avg. initial annulus condition press

⎡⎛ 51 ⎤ ⎞ × 7000 + 500⎟ + 500 ⎥ ⎢⎜ ⎠ ⎢⎣⎝ 144 ⎥⎦ − 2

I

Change in average tubing temperature

[ BH temp

] − [ BH temp

avg. tubing temp while acidizing - avg. initial tubing condition temp ( acidizing )

+ surf temp ( acidizing )

[100 + 80] − [ 220 + 80] 2

-60 oF

=

Radial clearance between tubing OD and casing ID

=

(6.276" - 4.5")/2

=

0.888"

=

Moment of inertia of tubing about its diameter

=

π

=

64 π

( initial )

+ surf temp ( initial )

2

]

2

=

64 Ws

⎡⎛ 51 ⎤ ⎞ × 7000 + 0⎟ + 0⎥ ⎢⎜ ⎠ ⎢⎣⎝ 144 ⎥⎦ 2

500 psi

2

r

⎡⎛ 51 ⎤ ⎞ × 7000 + 0⎟ + 0 ⎥ ⎢⎜ ⎠ ⎢⎣⎝ 144 ⎥⎦ 2

(D o4 − D i4 ) where D o is outside diameter and D i is inside diameter

( 4.5 4 − 3.958 4 )

=

8.08 in.

=

Weight of tubing

=

12.6 lb/ft

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Drilling & Workover Engineering Department CHAPTER 4

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D

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TUBING DESIGN

___________________________________________________________________________________________________________________________

Wi

=

Weight of fluid in tubing

=

Acid Wt × A i

=

144 67 × 12.47 144

=

5.8 lb/ft

Wo =

Weight of displaced fluid

=

Diesel Wt × A o

=

144 51 × 15.9 144

R

β γ

=

5.6 lb/ft

=

Ratio of tubing OD to ID

=

4.5/3.958

=

1.14

=

Coefficient of thermal expansion for steel

=

6.9 x 10-6 in/in/oF

=

Poisson's ratio for steel

=

0.3

Substitution of Length and Force Terms into Equations 1. a)

Piston Effect

−L

Length change

∆L 1 =

EA S

[ (A

p

−7000

− A i )∆Pi − ( A p − A o )∆Po

]

[(12.56 − 12.47)3778 − (12.56 − 15.90)500]

=

30 × 10 6 × 3.6

=

-0.13' (upward since the answer is negative)

=

( A p − A i )∆Pi − ( A p − A o )∆Po

=

(12.56-12.47)3778-(12.56-15.90)500

b) Force change

F1

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 4 SECTION

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COMPLETION PRACTICES

D

TUBING DESIGN

___________________________________________________________________________________________________________________________

= =

2. a)

+340 psi (tubing side) +1670 psi (annular side) +2010 psi (compression since the answer is positive)

Pressure Buckling Effect Since ∆Pi (3778 psi) is greater than Length change

− r 2 A 2p ( ∆Pi − ∆Po ) 2

∆L 2 =

∆Po (500 psi) the length change due to buckling is

8EI( Ws + Wi − Wo ) −0.888 2 × 12.56 2 (3778 − 500) 2

=

8 × 30 × 10 6 × 8.08(12.6 + 5.8 − 5.6)

=

-0.053' (or 0.64" upward since the sign is negative)

b) Force change The force change is negligible since this effect mainly shortens the tubing.

3. a)

Ballooning Effect Length change

−2 Lγ ⎡ ∆Pia − R 2 ∆Poa ⎤ ⎢ ⎥ E ⎢⎣ R2 − 1 ⎥⎦ . 2 × 500 ⎤ −2 × 7000 × 0.3 ⎡ 3389 − 114 ⎢ ⎥ 30 × 10 6 114 . 2 −1 ⎢⎣ ⎥⎦

∆L 3 = = =

-1.28' (upward since the sign is negative) - 0.6( ∆Pia A i

− ∆Poa A o ) - 0.6(3389 × 12.47 − 500 × 15.90)

b) Force change

F3

= = =

4. a)

-20,586 lb (tension since the sign is negative)

Temperature Effect Length change

∆L 4 = = =

Lβ∆T

7000 × 6.9 × 10 −6 × ( −60) -2.90' (upward since the sign is negative)

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Drilling & Workover Engineering Department CHAPTER 4 SECTION

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COMPLETION PRACTICES

D

TUBING DESIGN

___________________________________________________________________________________________________________________________

207A s ∆T 207 × 3.6 × ( −60)

b) Force change

F4

= = =

-44,712 lb (tension since the sign is negative)

Summation of Movements and Forces The total movement of the tubing string is summarized by the following table. Since the summation of each effect results in a negative number, the movement is upward. Table 4D-5

Piston Effect Pressure Buckling Effect Ballooning Effect Temperature Effect TOTAL

Movement (ft) - 0.13 - 0.05 - 1.28 - 2.90 - 4.36

If the tubing seal assembly was not allowed to move or if the seals were anchored into the production packer, a tubing to packer force would be exerted. This force would be the sum of all the individual forces as shown by the following table. Since the answer is a negative number, the force is tensile. Table 4D-6

Piston Effect Pressure Buckling Effect (negligible) Ballooning Effect Temperature Effect TOTAL

Force (lbs) + 2010 - 20586 - 44712 - 63288

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 5 SECTION

A

June 2006

WIRELINE LOGGING AND EXPLOSIVES ELECTRIC LOGGING

___________________________________________________________________________________________________________________________

ELECTRIC LOGGING 1.0

INTRODUCTION

2.0

OPEN AND CASED HOLE LOGS 2.1 PDIL/MSFL/CAL OR DPIL/MLL/CAL 2.2 LDT/CNL/GR/CAL OR ZDL/CN/GR/CAL 2.3 FMI RO STAR 2.4 ATI/MSFL/SP/CAL/DSI-SONIC OR HDIL/MLL/SP/CA/MAC 2.5 CSI-Sidewall Core Gun 2.6 Induction/DLL 2.7 Cross-reference of Selected SCHLUMBERGER and WESTERN ATLAS Logs.

3.0

MISCELLANEOUS LOGGING SERVICES 3.1 Sidewall Core Guns 3.2 Borehole Profile and Cement Volume Log 3.3 Flowmeter/Gradio/FCAP/CAL/HRT 3.4 Others

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 5 SECTION

A

June 2006

WIRELINE LOGGING AND EXPLOSIVES ELECTRIC LOGGING

___________________________________________________________________________________________________________________________

ELECTRIC LOGGING 1.0

2.0

INTRODUCTION 1.1

Schlumberger and Western Atlas are on contract to Saudi Aramco to provide all electric logging services, with and without a rig on the well. Both companies have the basic and somewhat comparable logging tools. Each company also provides unique specialty logging services with the provision that some of the tools have to be brought into the Kingdom on short notice. The electric logging requirements for all rigs are split between the two Service Companies such that each is assigned or responsible for all the logging work on a particular rig. If the situation arises where the rig-assigned Service Company cannot meet its obligation to log a well for any reason, then the Foreman has the option to call on the other Service Company.

1.2

It is important for the rig Foreman to give ample advanced notice to the Service Companies when requesting logging service. Ten to twelve-hour notice is not uncommon since the tools have to be inspected and functionally tested prior to usage. For specialty tools and services, notification should be made weeks or even months in advance to insure availability when needed.

OPEN AND CASED HOLE LOGS Open and/or cased hole logs are run in wells during drilling operations to obtain information about the reservoir, tubulars, hole conditions, aquifers, or to assist in resolving a downhole problem. These logs are run individually or in combination, depending on the type of information desired. The logging program is included in every drilling program, as dictated by Reservoir Engineering and Geology Department. Open hole logging tools are commonly run in combination. These logs are usually run from total depth (TD) to between 50’ and 100’ above the 7” liner shoe. The following sections, 2.1 through 3.4, list the most common combination of logs run in Saudi Aramco during drilling operations. 2.1

PDIL/MSFL/CAL or DPIL/MLL/CAL 2.1.1

PDIL or PI (Schlumberger’s Phasor Induction) or DPIL (Western Atlas’s Dual Phase Induction Log). This log measures formation resistivity/conductivity with three depths of investigation. This means

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that the undisturbed formation can be measured even in the presence of deep invasion. Main applications of the tool include: A) B) C) D) E)

Correlation and reservoir modeling. Filtrate invasion Profiles. Formation evaluation, including hydrocarbon/water contact. Thin bed resolution. Interpretation of deeply invaded formations. Company

Tool OD Inches

Schlumberger Western Atlas

3.63 3.63

Maximum Temperature (oF) 350 400

Maximum Pressure (psi) 20,000 20,000

This tool is applicable in all wells drilled with low salinity or nonconductive drilling fluids. If the fluid salinity is rather high, then DLL (Dual Laterolog) might be run instead of the PI or DPIL. Reservoir Description Department will make this decision prior to logging. 2.1.2

DLL (Dual Laterolog): This tool measures deep and shallow formation resistivity in boreholes containing saline drilling fluids. With the measured information, the following reservoir parameters can be obtained: A) B) C) D)

2.1.3

Company

Tool OD Inches

Maximum Temperature (oF)

Schlumberger Western Atlas

5.25 3.36

350 400

Maximum Pressure (psi) 20,000 20,000

MSFL (Schlumberger’s Microspherically Focused Log) or MLL (Western Atlas’s Microlaterolog): A)

2 of 12

True formation resistivity in saline mud systems and high formation resistivities. Qualitative indication of permeability. Formation evaluation, including hydrocarbon/water contact. Correlation.

Schlumberger is the sole provider of the MSFL service and Western Atlas does not have a comparable tool. The MSFL

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 5 SECTION

A

June 2006

WIRELINE LOGGING AND EXPLOSIVES ELECTRIC LOGGING

___________________________________________________________________________________________________________________________

records resistivities of small volumes near the borehole in wells drilled with conductive muds. The data is used to 1. 2. 3.

B)

C)

Determine the resistivity of the flushed zone. Identify location of the porous and permeable zones. Identify movable Hydrocarbon

Company

Tool OD Inches

Maximum Temperature (oF)

Schlumberger

4 and 5.25

350

Maximum Pressure (psi) 20,000

Saudi Aramco uses Western Atlas’s MLL as a substitute for the MSFL even though it is not a true replacement. The MLL has a limited depth of lateral investigation and good vertical resolution. It responds primarily to the resistivity of the flushed zone adjacent to the wellbore. Although usually run in salt mud, the MLL can also be run in fresh mud where mudcake is thin. Company

Tool OD Inches

Maximum Temperature (oF)

Western Atlas

3.38

350

Maximum Pressure (psi) 20,000

CAL (Caliper Log, available from Schlumberger and Western Atlas). This log is a continuous profile of the borehole wall showing variations in diameter. Caliper logs can be recorded using 1, 2, 4 or 6 arm tools. The measurements and their average accurately describe the shape of the hole and size (I.D.), especially in deviated and elliptically shaped holes. When the hole is straight and round, all calipers read the same value. In an elliptical hole, the 2-arm caliper lines up with the long axis. The 4-arm caliper measures both the short and long axes of the hole and provides the most accurate description of true internal diameter. The primary uses of a Caliper Log include: 1. 2.

Determining borehole profile for cement volume calculations. Provide information on build-up of mudcake adjacent to permeable zones.

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3. 4. 5. 6.

2.2

Determine hole size for fluid flow calculations, particularly in irregular boreholes. Locate packer-seating areas in open hole. Locate breaks in parted tubing or casing. Locate gas lift mandrels, landing nipples, and other restrictions in tubular goods.

LDT/CNL/GR/CAL or ZDL/CN/GR/CAL After logging with the LDT/CNL/GR/CAL or ZDL/CNL/GR/CAL to above the 7” liner shoe, it is common Saudi Aramco practice to continue logging with only the CNL/CCL to 100’ above the 9-5/8” casing shoe. The logging speed should not exceed 60 fpm and the log should be recorded at 2” per 100-foot scale. This log is required by Geology in order to correlate the various formation tops above the Arab-D. 2.2.1

LDT (Schlumberger’s Litho-Density Tool) or ZDL (Western Atlas’s Compensated Z-Density). These tools use a gamma ray source to measure the bulk density and the photoelectric effect (Pe) of the formation. The Pe measurement is related to the formation composition and lithology, and the bulk density measurement can be related to the porosity. The two detectors compensate for mudcake effects and hole rugosity. Principal applications include: 1. Porosity analysis 2. Lithology determination. 3. Abnormal pressure identification Company Schlumberger Western Atlas

2.2.2

4 of 12

Tool OD Inches 4.5 3.63 4.88

Maximum Temperature (oF) 350 350

Maximum Pressure (psi) 20,000 20,000

CNL or CN (Schlumberger’s Compensated Neutron Log or Western Atlas’s Compensated Neutron): This tool contains a radioactive source that bombards the formation with fast neutrons. These neutrons are slowed and then captured, primarily by hydrogen atoms in the formation. The slowed neutrons deflected back to the tool are counted by the detectors.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 5 SECTION

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June 2006

WIRELINE LOGGING AND EXPLOSIVES ELECTRIC LOGGING

___________________________________________________________________________________________________________________________

Neutron logs are primarily used for identification of porous formations and for the estimation of their porosities. Other uses of the CNL tool include lithology identification, clay analysis and gas detection. The CNL is affected by very few borehole effects, which makes this instrument very desirable in rough or washed out boreholes. CNL tools are combinable and are usually run simultaneously with other services. Company Schlumberger Western Atlas

2.2.3

Tool OD Inches 2.75 3.375 2.75 3.625

Maximum Temperature (oF) 500 400 450 400

Maximum Pressure (psi) 25,000 20,000 25,000 20,000

GR (Gamma Ray). This instrument measures the natural radioactivity of the formation and can be run in any liquid or air filled hole, either cased on uncased. The main applications of the log are 1.

2. 3. 4.

Make depth correlation with other logs. Effective in any environment, it is the standard device for correlating cased hole logs with open hole logs. Determine stratigraphic profiles. Estimate shale content in reservoir rocks. Recognize radioactive minerals.

In cased hole, a Casing Collar Log is usually recorded simultaneously. The GR tool can be run in combination with other services. Company

Tool OD Inches

Schlumberger

1.688 3.375 1.688 – 3.625

Western Atlas

2.2.4

Maximum Temperature (oF) 350 350 300 – 450

Maximum Pressure (psi) 20,000 25,000 15,000 – 25,000

CAL: See section 2.1.1 above for details.

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A

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2.3

FMI or STAR (Schlumberger’s Formation Microscanner Imager or Western Atlas’s Simultaneous Acoustic & Resistivity Imager): 2.3.1

The FMI tool provides electrical images in conductive mud and offers quantitative information on fracture analysis; it hardly gets influenced by borehole effects. The tool is primarily used for 1. 2. 3. 4. 5.

Structural analysis. Characterization of sedimentary bodies. Complete fracture network evaluation. Depth matching, orientation and core studies. Reservoir characterization. Company Schlumberger

2.3.2

Western Atlas

Maximum Pressure (psi) 20,000

Tool OD Inches 5.0

Maximum Temperature (oF) 350

Maximum Pressure (psi) 20,000

AIT/MSFL/SP/CAL/DSI-SONIC OR HDIL/MLL/SP/CA/MAC 2.4.1

AIT (Schlumberger’s Array Induction Tool) or HDIL (Western Atlas’s High Definition Induction Log): This tool provides a resistivity image of the formation that reflects bedding, hydrocarbon content and invasion features. The tool can operate in any wellbore fluid, including oil-base mud. Company Schlumberger Western Atlas

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Maximum Temperature (oF) 350

The STAR log is similar to the FMI. It has the added advantage of acoustic imaging capabilities, which extends its application to wells containing non-conducting fluids Company

2.4

Tool OD Inches 5

Tool OD Inches 3.88 3.63

Maximum Temperature (oF) 350 400

Maximum Pressure (psi) 20,000 20,000

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2.4.2

MSFL: See section 2.1.1 above for details

2.4.3

SP (Spontaneous Potential): This is a curve that is recorded in conductive mud by resistivity logs to differentiate between potential reservoir rocks and shales, and to determine formation water resistivity.

2.4.4

CAL: See section 2.1.1 above for details

2.4.5

DSI-Sonic (Dipole Shear-Sonic Imager) or MAC (Western Atlas’s Multipole Array Acoustic): This tool measures shear, compression and Stoneley sound waves in all formations. The main applications of this tool are 1. 2. 3. 4. 5. 6. 7.

Seismic correlation. Wellbore stability. Sanding analysis. Prediction of rock strength for fracture stimulation and fracture height estimation. Mobility. Improved estimation of porosity and lithology in slow formations. Through-casing acquisition of shear-wave (S-Wave) and compressional-wave (P-wave) data. Company

Schlumberger Western Atlas 2.5

Tool OD Inches 3.63 3.63

Maximum Temperature (oF) 350 400

Maximum Pressure (psi) 20,000 20,000

CSI-Sidewall Core Guns 2.5.1

CSI (Schlumberger’s Combinable Seismic Imager): This tool measures compressional, vertical and horizontal shear seismic waves in open or cased hole. There are a number of applications for this tool, however, the main ones include: 1. 2. 3.

Vertical seismic profile and offset recording in open or cased hole. Horizontal well surveys in tough logging conditions. Deviated well vertical seismic profile

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ELECTRIC LOGGING

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2.5.2

2.6

Sidewall Core Guns: details.

See section 3.1.1 below for description and

Induction/DLL When the drilling program calls for running an Induction log, it is the same as running PI or DPIL (see section 2.1.1). The DLL (Dual Laterolog) is run in lieu of DPIL only if the drilling fluid salinity is high.

2.7

Standard Logs The following is a cross reference of the common logs run by Schlumberger and Western Atlas. It is important to note that the contracts with each Service Company calls for 1000 ft. minimum logging interval for all services. The exceptions include 300 ft. for the FMI log and 500’ for the STAR.

Schlumberger Log Name PI

Log Name Phasor Induction

DPIL

Dual Phase Induction Log

AIT

Array Induction Tool

HDIL

High Definition Induction Log

DLL

Dual Laterolog

DLL

Dual Laterolog

ARI

Azimuthal Resistivity Imager

-

MSFL

Microspherically Focused Log

MLL

Microlaterolog

CMR

Combinable Magnetic Resonance

MRIL

Magnetic Resonance Imager Log

NGS

Natural Gamma Ray Spectroscopy

SL

LDL

Litho Density Log

ZDL

Compensated Z-Densilog

CNL

Compensated Neutron Log

CN

Compensated Neutron

FMI

Formation Microscanner Imager

STAR

Simultaneous Acoustic & Resistivity Imager

UBI

Ultrasonic Borehole Imager

CBIL

Circumferential Borehole Imager Log

DSI

Dipole Shear-Sonic Imager

MAC

Multipole Array Acoustic

DSI-BCR Both Cross-dipole Receivers TDT-P RST

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Western Atlas

Thermal Decay Time Reservoir Saturation Tool

X-MAC

-

Spectralog

Cross Dipole MAC

PDK-100 Pulse Decay Tool RMS

Reservoir Monitoring Service

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ELECTRIC LOGGING

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3.0

MISCELLANEOUS LOGGING SERVICES Open and cased hole logs are run in a well during drilling operations to obtain information about the reservoir in order to better define the parameters. 3.1. Sidewall Core Guns Schlumberger’s CST (Chronological Sample Taker) or Western Atlas’s SWC (Sidewall Coregun) A core barrel, which is a hollow cylinder, is shot into the formation by a surface controlled powder charge ignited by an electric current. The core barrel, containing a formation sample, is retrieved by means of a steel cable(s) attached between the gun and the core barrel. Only one core barrel is fired at a time. A tandem gun can selectively core multiple (over 40) samples on a single run. Sidewall formation samples are used to A) B) C) D) E)

Determine porosity and permeability. Confirm hydrocarbon shows. Determine clay content. Determine grain density. Determine Lithology.

3.1.1

The CST tool can obtain up to 90 core samples in one trip. Recovered samples are generally large enough for a core analysis.

Core Bullet

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ELECTRIC LOGGING

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Company Schlumberger

3.1.2

Tool OD Inches 4 & 4.38 5.25

Maximum Temperature (oF) 450 450

Maximum Pressure (psi) 20,000 20,000

The SWC obtains cores ranging in size from 0.85 in. to 0.69 in. diameter and up to 2 in. in length. Up to 50 core samples can be obtained on a single run using the 4 in. Coregun.

Western Atlas’s SWC Coreguns Company Western Atlas

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Tool OD Inches 3 4

Maximum Temperature (oF) 400 400

Maximum Pressure (psi) 20,000 20,000

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3.2. Borehole Profile and Cement Volume Log When using the 4-arm caliper tool such as a dipmeter or Borehole Geometry Tool, the Borehole Profile-Cement Volume log can be generated. This Schlumberger log is computed using caliper and deviation data, which allows calculation of the amount of cement needed to set a particular size of casing. The log information is used for A) B) C) 3.3

Casing cementation Borehole and annular cement volume Drillstem testing

Flowmeter/Gradio/FCAP/CAL/HRT Both Schlumberger and Western Atlas are able to offer this Production Logging service. 3.3.1

Flowmeter: Continuous Spinner or Folding Impeller flowmeter surveys are used to meter fluid flowrates within cased hole or open hole wellbores. Velocity and direction of fluid movement in the borehole can be determined by the movement of the impeller. Units of measurement are revolutions per second, which can be converted to barrels per day and percentage of full flow.

3.3.2

Gradio and FCAP: A) Schlumberger uses a Gradio-manometer which works by measuring the pressure 2 foot apart and calculating the pressure differential to determine the density of the liquid. This measurement is valid for 20 to 80% water cut. The HUM (holdup meter) and DEFT tool is also used for water cuts less than 20% and greater than 80%. B)

3.3.3

Western Atlas uses the FDN (Fluid Density Log – Nuclear) which measures fluid density by injecting a gamma ray source in the flow stream. This tool is good for measuring densities up to 60% water cut. The FCAP (Fluid Capacitance), also referred to as WHI (Water Hold-Up Indicator), complements the FDN and can accurately measure water cuts greater than 60%

CAL: The Caliper log is needed to determine hole size for flow

calculations, particularly in irregular boreholes.

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3.3.4

HRT: A High Resolution Temperature log provides a continuous record of borehole fluid temperatures. In producers, the data is used to: A) B) C)

3.4

Detect gas entry in open and cased holes. Distinguish zones that are producing from those that are nonproducing. Determine the geothermal gradient.

OTHERS Other logging services are provided by both in-Kingdom Electric Logging Service Companies. Details of these logs are covered in other sections of this Drilling Manual as follows:

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3.4.1

Freepoint Indicator: See Chapter 5, Section D (Explosives).

3.4.2

String Shot: Back-off: See Chapter 5, Section D (Explosives).

3.4.3

Chemical Cutter: See Chapter 7, Section A (Fishing Tools).

3.4.4

Jet Cutter: See Chapter 7, Section A (Fishing Tools).

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 5 SECTION

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June 2006

WIRELINE LOGGING AND EXPLOSIVES LOGGING GUIDELINES

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LOGGING GUIDELINES 1.0

GENERAL

2.0

LOGGING TOOLS RUNNING SPEED

3.0

LOGER’S DEPTH VERSUS DRILLER’S DEPTH

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LOGGING GUIDELINES 1.0

GENERAL The following general guidelines will be observed during logging operations: 1.1

When drilling a new open-hole section, logging should be conducted as soon as possible to minimize the effects of filtrate invasion and minimize the thickness of the filter cake.

1.2

Collect two one-gallon mud samples of the drilling fluid from the effluent of the flowline, immediately after circulating and prior to pulling out of hole for logging. Give one sample to the logging engineer and send the other to the P.E. Laboratory for measurement of mud and filtrate resistivities. The results should be sent to Reservoir Description Department.

1.3

When logging with a combination logging tool and one of the sections in the tool malfunctions, the option whether to continue logging will depend on the usefulness of the data being recorded or obtained. Contact Reservoir Description Department for consultation and advice.

1.4

When running a suite of logs, always insure that the sonic or resistivity log is the first one and the radioactive tool is the second one. The reason is that the hole conditions across the interval to be logged are not known. If the logging tool becomes stuck in the hole, fishing operations can proceed on a non-radioactive tool. Once the stability of the hole is established, then it becomes less risky to run a tool with a radioactive source.

1.5

Per contract agreement with Schlumberger and Western Atlas, most logs have a minimum charge of 1000 feet regardless of the actual logged interval. Repeat sections of any log are a necessity to insure the reliability of the survey. The length of repeat section is dependent on many factors, such as (a) the type of log, (b) number of anomalies detected, (c) interval length, and other factors. Generally, 200’ repeat section is not uncommon. As an example, logging Arab-D vertical wells in Southern Area Producing involves a short +400 foot interval. The repeat log covers the total +400 interval since the minimum log footage charge is not exceeded.

1.6

When logging operations are competed, the Service Company provides the rig Foreman with a field-copy of all logs. Additional copies are provided to other Saudi Aramco organizations as stipulated.

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2.0

LOGGING TOOLS RUNNING SPEED

The following table lists the logging speeds that are recommended for the commonly used logging tools used during drilling operations: SURVEY

RUNNING SPEED

Generic Name

Service Company Log Name

Schlumberger Feet/Min

Western Atlas Feet/Min

Phased Induction Special Induction Azimuthal Resistivity Imager Dual Laterolog Compensated Density Compensated Neutron Dipmeter Gamma-Ray (Evaluation) Gamma-Ray (Correlation) Spectroscopic Gamma-Ray Microspherically Focused log Microlaterolog Formation Imager Acoustic Imager Combinable Seismic Imager Borehole Imager Borehole Compensated Sonic Platform Express

PI or DPIL AIT or HDIL ARI DLL LDL or ZDL CNL or CN HDT or HDIP GR GR NGS or SL MSFL MLL FMI or STAR DSI or MAC CSI UBI or CBIL BHC Sonic or BHC Acoustic AIT/TDD/CNL/GR/MCFL

60 60 60 60 30 30 30 30 60 15 30 30 30 30-60 Stations 30 60 60

60 60 60 60 25 30 60 30 30 30 60 60 30 30 Stations 15 60 -

Note: A) B)

C)

D)

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For a given combination of tools, the logging speed is dictated by the slowest component in order to preserve good log definition. The downhole acoustic environment determines Sonic or Acoustic logging speeds; the signal-to-noise ratio is the determining factor. If the ratio is low, then the logging speed is reduced, and vice versa. Special care should be taken when running a pad-type log since the rugged borehole conditions could damage the logging tool if run too fast. Logging speeds in the range of 1500 ft/hr are normal and should not be exceeded. Logging speeds for radioactive surveys should be based on wellbore rugosity and resolution requirements. Greater statistical errors and lower log resolutions are a result of higher logging speed.

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3.0

LOGGING VERSUS DRILLER DEPTH The following procedures should be followed when reporting Electric Logging and Perforating depths: 3.1

All casing, tubing and associated equipment, such as packers, SSSVs, etc., will be reported as Driller’s Depth (DD) and measured in feet from DF, Derrick Floor.

3.2

All depths associated with electric line operations, such as logging, perforating, setting packers, setting plugs, etc. during drilling of a well, should be reported as Logged Depth or Loggers Depth (LD) and referenced to the DF.

3.3

All measurements that have both a DD and LD should be properly labeled to differentiate between them. As an example, a packer is set on electric line at a particular depth and is tagged when landing the tubing at a different depth. It is therefore imperative for all reports, such as Daily Drilling reports, Well Completion Reports, etc., to contain the proper depth labeling to eliminate possible confusion.

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WIRELINE LOGGING AND EXPLOSIVES STUCK TOOL PROCEDURES

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STUCK TOOL PROCEDURES 1.0

GENERAL

2.0

FREEING STUCK TOOL 2.1 Tool Stuck During Logging 2.2 Tool Stuck on Bottom

3.0

STRIPPING OVER

4.0

BREAKING AT THE WEAK-POINT

5.0

FISHING FOR RADIOACTIVE TOOLS 5.1 Fishing Operations 5.2 Handling of a Radioactive Source 5.3 Abandonment of Source

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STUCK TOOL PROCEDURES 1.0

GENERAL Tool sticking usually occurs in open hole when the electric cable or tool itself becomes stuck due to differential sticking, getting hung up on junk, key-seating in a dogleg, and other reasons. The following are general electric cable logging field practices that should be observed: 1.1

Prior to rigging up the electric wireline unit for logging, ensure fishing tools are available on short notice.

1.2

Know the size/type of the cable, maximum allowable pull (50% of line breaking strength), and weak point rating.

1.3

For large cable where the breaking strength is 16,000 lbs., do not exceed 8000 lbs. pull. On smaller cable where the breaking strength is 4000 to 5100 lbs., do not exceed 2000 to 2500 lbs. pull.

1.4

The weak point setting (rope socket) is selected prior to running the logging tools. It is a function of the depth of the well, tool weight, and line breaking strength. The weak point setting + tool weight in mud + line weight at TD should be less than or equal to 50% of the breaking strength.

1.5

Permission shall be obtained from Saudi Aramco management prior to intentionally breaking the cable..

1.6

All standard logging tools use the same cable head, shown in Figure 5C-1. Note: The maximum pull on a standard logging head (3-3/8 inch thread) is 120,000 lbs.

1.7

The Schlumberger or Western Atlas engineer should consult the Drilling Foreman and their office before pulling beyond the weak point strength.

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Rope Socket

Figure 5C-1 Standard Schlumberger Logging Head

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2.0

FREEING STUCK TOOL 2.1

Tool Stuck During Logging Close tool, and attempt to go down if tool is free to descend; make several attempts if necessary. If tool is not free to descend, pull to maximum safe tension and hold at that level of tension until the tool becomes free. 2.1.1

If this action does not free the tool, stripping-over should be performed.

2.1.2

The RFT tools stick easily and consequently the following precautions should be taken: 1) 2) 3)

2.2

A dummy run prior to RFT logging is highly recommended. Adding friction reducer to the mud is desirable, if possible. If an excessive differential pressure situation exists across a formation, B-FREE pills or similar products should be spotted prior to taking RFT readings or samples.

Tool Stuck on Bottom If tool becomes stuck on bottom of the hole, close tool and pull to maximum safe tension and hold at that level of tension until the tool becomes free. If this action does not free the stuck tool, then stripping-over should be attempted.

3.0

STRIPPING OVER If the tool fails to unstick or come free, stripping over should normally be attempted. Remember to obtain approval prior to breaking the weak-point. If stripping-over is to be performed, proceed as follows: 3.1

Apply 2000 lbs. tension to the cable.

3.2

Land cable and cut above rotary table.

3.3

Connect spearhead to the hole end of the cable and a spearhead overshot to the unit end.

3.4

Strip over wire with Bowen overshot and drill pipe, stand by stand, maintaining 2000 lbs. tension in the cable.

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3.5

Prior to latching on the fish, install a circulating sub and special bushing at surface to catch the cable; the cable is landed in this bushing.

3.6

Install the Kelly and circulate to clean the overshot, prior to latching on the fish. After circulating, remove the Kelly, connect spearhead overshot to spearhead and apply 2000 lbs. tension.

3.7

Lower string and latch onto the fish. A tension decrease when lowering or tension increase when pulling the string indicates the fish to be connected. Note: While running in hole with the overshot, a decrease in cable tension may occur, indicating that the tool has become free. In such a case, the cable is connected and the tool pulled up until the overshot latches onto the fish head

3.8

4.0

After latching onto the fish, part the cable at the weak-point with the travelling block. Remove the spearhead-overshot combination, connect the cable together and wind in. Pull the string and recover the fish. Do not rotate the string while pulling out.

BREAKING WEAK-POINT 4.1

The following are precautionary measures when attempting to recover a stuck tool by breaking at the weak-point: A)

If the open hole is in reasonable condition or in casing, there is a good chance the tool can be fished out by breaking at the weak-point and fishing with an overshot (with an OD slightly smaller than the bit size).

B)

This technique should not be used for tools with radioactive source. If a radioactive logging tool is stuck in the hole, do not continue to work the tool since this may reduce the weak-point strength. Inform the concerned parties of the details of the situation.

C)

At no time should cable tension be suddenly released. This action can cause “bird-cages” and broken cables. Tension should be released slowly and should never drop below 50% of the normal logging tension.

D)

5.0

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The Schlumberger or Western Atlas engineer should always direct the operation when applying and releasing tension on the cable. FISHING FOR RADIOACTIVE TOOLS

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WIRELINE LOGGING AND EXPLOSIVES STUCK TOOL PROCEDURES

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5.1

Fishing Operations The following are precautionary measures when attempting to recover a stuck tool by breaking at the weak-point:

5.2

A)

Circulate once around prior to latching on to fish.

B)

Monitor the mud returns constantly with the Gamma-Ray tool placed in the return line.

C)

Do not locate engage-tool with more than 10,000 lbs. weight.

D)

Ensure the maximum allowable pull is not exceeded.

E)

No personnel other than Schlumberger or Western Atlas are to be near the mud pit or return lines.

F)

Check to ensure that with the tool engaged in the overshot, circulation remains impossible. Use a circulating sub in the fishing assembly one stand above the overshot.

Handling of a Retrieved Source The following safety precautions should be adhered to when handling a retrieved source:

5.3

A)

Limit personnel to the minimum required on the rig floor.

B)

Pull the source as far as possible in the derrick (minimum 50’).

C)

Cover the rotary table, close rams, etc., then all rig personnel shall leave the rig floor except the Driller.

D)

The Driller will assist Schlumberger or Western Atlas in laying down equipment.

Abandonment of Source The radioactive source will be abandoned in place (in hole) if all of the above actions fail to recover the source (see Chapter 2, Section G for details).

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EXPLOSIVES 1.0

PERFORATING 1.1 Types of Guns 1.2 Specifications 1.3 Log correlation 1.4 General Perforating Guidelines and Tips 1.5 Pressure Control Equipment & Testing 1.6 Procedures for Ordering Explosive Charges 1.7 Safety Concerns and Precautions

2.0

TUBULAR PUNCHERS 2.1 Types of Punchers 2.2 Suppliers and Specifications 2.3 Safety Concerns and Precautions

3.0 PIPE CUTTERS 3.1 Types of Cutters 3.2 Suppliers and Specifications 3.3 Safety Concerns and Precautions 4.0

PIPE BACK-OFF 4.1 Suppliers and Specifications 4.2 Procedures 4.3 Safety Concerns and Precautions

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1.0

PERFORATING Perforating is a critical part of the well completion process and provides the means of communication between the reservoir and the wellbore. Shaped charges are used to perforate casing and thus create a path for the fluids to flow from the reservoir into the wellbore. 1.1. Types of Guns 1.1.1

Retrievable Hollow Carrier Gun These guns are reusable, wireline or tubing conveyed, with normal 4 shots-per-foot perforating density at 90o or 120o phasing. Penetration of the charges into the formation is usually not as deep as an expendable type because of stand-off (distance between charge and casing). Advantages: 1. Essentially no debris left in the hole. 2. No deformation of casing when detonated. 3. Shot density can be varied. 4. High gun reliability. 5. High running speeds. 6. High temperature ratings up to 470 oF. Disadvantages: 1. Gun length is limited by weight 2. Rigid carrier is not good for passing through crooked hole sections. 3. Difficulties perforating under-balanced. 4. No way to verify if charges are fired. Note: Hollow carrier guns with High Shot Density (HSD, up to 12 shots-per-foot) are available. They are not reusable but are recovered from the well.

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1.1.2

Expendable Hollow Carrier and Strip Gun These type of guns are either classified as fully or semi-expendable. They are run on wireline or tubing conveyed, with normal 4 shots-perfoot at 0o or 45o phasing. It is common practice to magnetically orient the guns to one side of the casing in order to maximize formation penetration in one direction. A)

Fully expendable guns are designed to shatter when fired. The debris falls to bottom and is left in the well. The case, which houses the explosive charge and liner, is made of aluminum because it is light and can be cast into integral casings. Advantages: 1. High flexibility permits handling long lengths (200 feet). 2. Explosive charges penetrate deeper into the formation than equivalent slim hollow carrier guns. Disadvantages: 1. Debris left in well. 2. Under balanced perforating can result in gun blowing up the hole causing a fishing job. 3. Aluminum case is not resistant to HCl. 4. Lower pressure and temperature ratings as compared to Hollow Carrier guns. 5. Running speed limited to 10,000 ft/hr versus 30,000 ft/hr for other guns. The soft aluminum wears quicker than steel. 6. No way to verify if charges are fired. 7. Can cause casing deformation, especially in old wells. 8. Cannot push gun through bridge since it will ball up or break.

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B)

Semi-expendable guns are destroyed when fired. Actually, only the perforator casings are destroyed when the gun is fired. The carrier, either wire or strip-type, remains intact and is removable from the wellbore. The tougher strip carriers are preferred over the seldom-used wire type. A conventional strip gun can fire charges at 0 or 180 degree phasing, while an angled strip gun enables consecutive charges to be fired 90 degrees apart. This phasing places the perforations +45 degrees on either side of the magnetic positioning tool’s central axis. By providing some phasing, the angled strip gun is believed to limit a well’s tendency to produce sand by reducing the pressure drop across the perforations. Advantages: 1. The debris left in the hole is generally reduced as the strips and wiring are recovered. 2. In the case of glass and ceramic cases, the type of debris left is more like sand and less apt to cause problems. 3. Explosive charges penetrate deeper into the formation than equivalent slim hollow carrier gun due to magnetic positioning. 4. Flexibility of gun improves chances of passing through rigid tubing. 5. Lower cost than Hollow Carrier gun. 6. Head and accessories easily retrievable. 7. Lower shot density can be run on same strip. 8. Spacing out of the charges in the field is easy to accomplish. Disadvantages: 1. Debris left in the well. 2. No way to verify if all the charges are fired. 3. Limited to less than 40’ of gun length due to maximum lubricator length. 4. Has the potential of hanging up after perforating when pulling out of hole. 5. Coiled tubing conveyed not recommended. 6. In old or corroded wells, may damage or deform the casing.

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1.1.3

Tubing Conveyed Gun Tubing Conveyed Perforating or TCP is the placement of a hollow carrier gun on the end of a string of tubing or drill pipe. In Saudi Aramco, TCP guns have been run on drill pipe (without a packer) in horizontal wells, and on tubing in exploration/test wells (with a packer). Since TCP carriers are non-ported and can only be used once, they are classified as expendable guns. Advantages: 1. Can perforate under-balanced without the fear of being blown out of the hole 2. Pressure and temperature ratings are the same as the hollow carrier guns 3. Very long intervals can be perforated in a single trip 4. Can selectively perforate two separate zones in one run 5. Can perforate surge and gravel pack in a single trip. 6. No debris if gun is recovered

DRILL PIPE TO SURFACE RADIOACTIVE MARKER SUB ±500' OF DRILLPIPE RADIOACTIVE PIP TAG

RADIOACTIVE MARKER SUB

DRILLPIPE OR TUBING

±500' OF DRILLPIPE

PACKER W/ BYPASS

CIRCULATING SUB DIFFERENTIAL PRESSURE FIRING HEAD

DIFFERENTIAL PRESSURE AND/OR DROP BAR FIRING HEAD

SAFETY SPACER

SAFETY SPACER

4-1/2" O.D. HIGH SHOT DENSITY GUNS AT 5 SHOTS-PER-FOOT & SPACERS AS REQUIRED

4-1/2" O.D. HIGH SHOT DENSITY GUNS AT 5 SHOTS-PER-FOOT & SPACERS AS REQUIRED

BOTTOM NOSE

BOTTOM NOSE

(A) Typical Horizontal TCP String TUBING CONVEYED PERFORATING

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(B) Typical TCP String

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Disadvantages: 1. If the guns are left in the well, they may hinder future workover operations. 2. Verifying the firing of charges can only be done by tripping out of the hole with the guns 3. More expensive by as much as 40% over through-tubing methods. Th initial higher cost for TCP is offset by the associated rig time required to perforate longer than 50’ zones. 4. Well control has become an issue of concern when retrieving the perforated hollow carriers. A gas kick reaching surface while the +1000’ expended hollow carrier gun is being unscrewed, sectionby-section, cannot be controlled by simply closing the pipe rams. The only quick solutions are: (a) Quickly make up a joint or stand of drill pipe (with a check valve) on top of the hollow carrier, stab the drill pipe into the well, and close the pipe rams on the drill pipe (b) Drop the hollow carrier gun into the well and close the blind rams, in the hopes of retrieving the fish after the well is brought under control.

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1.2. Gun Specifications The following table lists the commonly used gun systems, associated explosive charges and performance supplied by the two In-Kingdom service companies: 1.2.1

Schlumberger

Gun System

Nominal Tool OD, inch.

Min. Restrict. inch. *

Shot Density & Phasing

Hole size inch.

Conveyance Method

Penetration Depth Inches **

Pivot FullyExpendable Laser Cut Carrier Enerjet Semi-Expendable Strip Gun Enerjet Semi-Expendable Strip Gun

1-11/16

1.78

4 spf o 180

Wireline

1-11/16

1.69

4 & 6 spf o 0

2-1/8

2.25

4 & 6 spf o 0

0.32 to 0.38 0.28 to 0.26 0.30 to 0.31

32.8 to 27.78 16.84 to 16.67 27.52 to 21.94

Phased Enerjet Semi-Expendable Strip Gun High Shot Density Expendable Hollow Carrier High Shot Density Expendable Hollow Carrier High Shot Density Expendable Hollow Carrier High Shot Density Retrievable Hollow Carrier

2-1/8

2.25

4 & 6 spf o 45

0.29

Wireline

22.9

2-1/2

2.80

1 to 6 spf o 60

0.29

Wireline TCP CTU

17.32

2-7/8

3.25

1 to 6 spf 60 or o 180

0.3 to 0.29

Wireline TCP CTU

21.97 to 20.57

Not used

2-7/8”

3.25

1 to 6 spf 60 or o 180

0.27 to o.69

TCP Drill Pipe CTU

8.4 to 20.00

Used @ 6spf to perforate horizontal wells

3-3/8

4.00

1 to 6 spf 60 or o 180

0.37 to 0.4

TCP Drill Pipe CTU

23.34 to 21.90

5-1/2” to 7” Liner

Wireline

Wireline

Most Common Use in Saudi Aramco New tool, not used to date For perforating 4-1/2 & 5” liners, through tubing For perforating 7” casing or 41/2” liners, through tubing For perforating 4-1/2 to 7” liners, through tubing Through-Tubing Perforating

* Minimum Restricted ID tool can be run in. Values vary with different gun systems. ** Penetration test is conducted in cement per API RP 43, fifth edition.

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1.2.2

Western Atlas

Gun System

Nominal Tool OD, inch.

Min. Restrict. inch.

Silver Jet Semi-Expendable Strip Gun Silver Jet Semi-Expendable Strip Gun Predator Semi-Expendable Strip Gun Phased Predator Semi-Expendable Strip Gun Alpha Jet Ported Hollow Carrier

1-11/16

1.78

2-1/8

2.25

4 & 6 spf 0o

2-1/8

2.25

4 & 6 spf 0o

2-1/8

2.25

4 & 6 spf 30o

3-1/8

3.8

Alpha Jet Ported Hollow Carrier

4

4.7

3-3/8

Alpha Jet Expendable Hollow Carrier Alpha Jet (Deep Penetrator) Expendable Hollow Carrier Alpha Jet (HSD charges) Expendable Hollow Carrier Jumbo Jet BH Expendable Hollow Carrier Alpha Jet (Deep Penetrator) Expendable Hollow Carrier JRC TP Expendable Hollow Carrier Super Hole Expendable Hollow Carrier

Shot Density & Phasing 4 & 6 spf 0o

Hole size, inch.

Conveyance Method

Penetration Inches *

0.37 to 0.36 0.42 to 0.72 0.29 to 0.32 0.28

Wireline

For perforating through tubing

Wireline

15.6 to 13.2 18.3 to 6.1 28.4 to 25.2 26.8

4 spf 120 & 90o 4 spf 120 & 90o

0.31

Wireline

18.9

0.48

Wireline & TCP

29.4

3.8

1 to 6 spf 60o

0.47

Wireline & TCP

22.8

4-1/2

5.0

5 spf 135/45o

0.45

Wireline & TCP

38.1

Used to perforate 4-1/2” casing or liner For perforating 5” & larger casing or liner (Prod. & GWI). Used to perforate 4-1/2” casing or liner Used in Central Area sandstone reservoirs

4-1/2

5.0

1 to 12 spf 135/45o

0.37

Wireline & TCP

20.2

4-1/2

5.0

1 12 spf 135/45o

0.74

Wireline & TCP

5.8

4

4 spf 90o

0.44

Wireline & TCP

25.08

4-1/2

4 spf 0o

0.29

Wireline & TCP

0.61

4-1/2

1 to 12 spf 135/45o

0.96

Wireline & TCP

5.9

Wireline

Wireline

Most Common Use in Saudi Aramco

For perforating through tubing For perforating through tubing For perforating through tubing

Used at 8 & 12 spf in Central Area sandstone reservoirs Used in Central Arabia for gravel packing Used in Central Area sandstone reservoirs

* Penetration test is conducted in cement per API RP 43, fifth edition.

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1.3

Log Correlation When selecting the interval to be perforated, it is common to utilize the original open hole formation logs (LDT/CNL/GR or ZDL/CN/GR). These logs have been run prior to cementing casing and therefore do not have casing markers such as collars, shoe, DV collars, liner tops etc. In order to insure perforating the appropriate interval in the right location, a Gamma Ray log (or Neutron) along with a casing collar locator log is run in conjunction, and the new log is correlated with the original log. 1.3.1

Conventional Perforating with Wireline i)

Obtain the original open hole log and mark the interval(s) to be perforated.

ii)

Run a new Gamma Ray or Neutron log and CCL log. If a previously run GR/CCL or NL/CCL log is available, a new log is not necessary. The selection of whether to run GR or NL depends on the how well defined the formation features are on the original logs.

iii)

Place the original Gamma Ray log alongside the new log along the same depths.

iv)

Slide the new log up or down to match the Gamma Ray or Neutron characteristics.

v)

Transfer the perforation interval(s) from the open hole log to the cased hole log.

vi)

Run the perforating gun containing a CCL on electric line and identify the collars in the vicinity of the perforation interval(s).

vii)

Adjust the electric line depth such that the collars on the cased hole log match with the collars of the perforating gun. Verify by running the electric line up and down across the collars in the vicinity of the perforating interval(s). Do not forget to compensate for the distance between the CCL and the top-most perforations.

viii) Using the cased hole log as the guide, run down to the bottom most interval and start perforating from the bottom up. Insure that the perforations have been shot and are on depth by examining the perforation log.

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1.3.2

Tubing Conveyed Perforating Saudi Aramco has two distinct applications of Tubing Conveyed Perforating (TCP), Horizontal wells and Exploration/Test wells. A)

Horizontal oil related wells are perforated using TCP guns on drill pipe without a packer. It is usually conducted with overbalanced fluid in the wellbore. In horizontal wells where the producing zone is long and homogeneous, it becomes unnecessary to run correlation logs. The TCP assembly is usually run to TD, raised a few feet and the guns fired. Close to 2400’ of horizontal liner has been perforated in one trip using this technique. If selective perforating of the horizontal section is desired without the use of a packer, then the procedures are as follows: i)

Displace the hole across the 4-1/2” liner to CaCl2 brine (containing 1% surfactant and 34% HCl acid to lower the pH to +5) and clean CaCl2 brine (viscosified with 2 ppb HEC) from top of the liner hanger to surface. Pull out of hole with bit.

ii)

Run in hole with TCP guns loaded at 4 SPF shot density alternating with spacer guns on tool string.

iii)

Run in hole on drill pipe and tag total depth. Pick up the drill pipe such that the bottom-most charge is at the deepest perforating depth.

iv)

Rig up circulating head and break circulation. annular BOP.

v)

Pressure up on drill pipe to 1500 psi and hold for 1 minute. Bleed off the pressure to 100 psi and observe well. Guns are expected to fire after approximately 10 minutes.

vi)

Record shut-in wellhead pressure. Open the annular BOP and observe the well. Circulate hole through circulation sub if required.

vii)

Pull out of hole if well is stable and insure all shots have been fired.

Close

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Note: If gas or oil has entered the wellbore creating an unstable well, then make a bit trip to PBTD to circulate and condition the well prior to running the completion. B)

Exploration/test Khuff/Pre-Khuff wells in Saudi Aramco are perforated using TCP guns, run on the bottom of packer assembles, and are subsequently production tested. The tubing strings are made up with a retrievable packer on 3-1/2”, 12.95 lbs/ft., L-80, PH-6 tubing, with the desired length of TCP guns hanging below the packer. This approach is favorable when under-balanced perforating is desirable. After being fired, if the completion does not have a permanent tail pipe, the well can be killed and the guns pulled out of hole. Otherwise, the guns can be left or dropped into the rathole by means of a special sub below the packer, which disconnects and drops the expended guns. The following procedures incorporate a packer-equipped TCP gun assembly: i)

Obtain the original open hole log and mark the interval(s) to be perforated.

ii)

Run in hole with retrievable packer/TCP gun assembly on tubing to the approximate depth the packer is to be set.

iii)

Note: The assembly should contain the necessary Radioactive marker-sub, circulating-subs, firing head and other necessary subs/equipment.

iv)

Run Gamma Ray & Casing Collar Locator tools in tandem through the tubing and obtain a log. Rig down logging truck.

v)

Place the original Gamma Ray/Neutron log alongside the new log, along the same depths.

vi)

Slide the new log up or down to match the Gamma Ray/Neutron characteristics.

vii)

Transfer the perforation interval(s) from the open hole log to the cased hole log.

viii) Correct for depth differences between the original open hole log and the new log by adding or subtracting footage to the electric line depth counter. Also, note and correct for

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the difference between the Radioactive Marker-sub depth on the TCP assembly with that of the collar depths of the new log. ix)

Space out the tubing such that the top shot (perforating charge) is at the desired depth in relation to the Radioactive Marker sub.

x)

Rig up control head, break circulation and condition mud. Set packer. Slack off weight and close 1-1/2 slip-joints to position the EZ Valve across pipe rams.

xi)

Close the pipe rams and pressure up on the TCA to +1000 psi while observing the tubing for leaks. Open pipe rams and pressure test tubing with mud while observing the annulus for leaks.

xii)

Reduce the hydrostatic pressure in the tubing by intruding lighter kill fluid. This can be accomplished by running coiled tubing inside the tubing or opening the packer bypass for displacing the test string to lighter fluid.

xiii) Close the by-pass and close the rams on the EZ valve. Pressure up on the tubing (primary firing method) or drop firing bar (secondary firing method) to activate the firing head. Perforate the well. xiv) Flow-test well per testing program. Following completion of well testing, kill well as directed in the program. Confirm that the well is dead. xv)

Unseat packer. Reverse out with mud, circulate, lay down Control Head and EZ valve. Pull out of hole with tubing and TCP/packer assembly.

xvi) Examine hollow carriers to insure all shots have been fired.

1.4

General Perforating Guidelines and Tips. 1.4.1

At any time during perforating, if unsure or the information is questionable, then do not continue with the perforating operations. Seek assistance and clarification. Once the casing is perforated, it is too late to reverse the process.

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1.4.2

Perforating under-balanced is desirable since the differential pressure across the perforation interval (between the reservoir and the wellbore) is beneficial in cleaning the debris left in the perforation tunnel. Under-balanced perforating is only practiced in cases where there is no danger of the downhole perforating gun from being blown out of the hole (e.g. TCP guns, with and without packer). In Saudi Aramco, horizontal wells are perforated using TCP guns on drill pipe without a packer; however, exploration wells are tested using TCP strings made up on the tailpipe of a retrievable packer.

1.4.3

When selecting gun phasing and intentional de-centralization, it is important to consider the objective of attaining deepest possible penetration into the formation. For example, in deviated wells, the cement thickness is typically at a minimum on the low side of the hole because of the casing’s tendency to eccenter. The proper gun selection could take into account the need for magnetic positioning and phasing.

1.4.4

The witnessing engineer will submit a detailed record of all perforating activities, with diagrams and correlation steps clearly explained. The purpose of this report is to retrace the perforating activities in case of doubt. The Service Company perforating log, as it stands, is incomplete and cannot be used to recreate the perforating sequence of events. The engineer will prepare a Completion Report, documenting well activities, within a maximum of two weeks after the job.

1.4.5

Whenever expended guns are pulled out of the hole, the Saudi Aramco representative should visually inspect all charges to ensure all the explosives have been fired.

1.5. Pressure Control Equipment and Testing A lubricator and BOPs are essential equipment to be used during perforating operations for pressure control. The lubricator must accommodate the entire length of the perforating gun and accessories. After nippling up the electric line BOPs and lubricator, the equipment should be pressure tested (to 1.2 times the expected wellhead pressure) prior to use by inserting a 7/32” or 3/16” test rod between the rams. Testing the BOPs with the logging cable is not acceptable due to possible leaks through the cable armor. Also, the lubricator should never be pressure tested with an armed perforating gun inside because a pressure leak in the gun or detonator could result in gun detonation.

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1.6. Procedures for Ordering Explosive Charges. When a rig foreman notifies the service company (Schlumberger or Western Atlas) to provide a services which requires explosive charges, the following procedures apply depending on the area of operations: 1.6.1

Eastern Province: A) The service company submits a written request to the Explosives Police office in Dammam indicating the explosive charges required to perform the job. B) Upon approval, a 1-day valid permit is issued to the Service Company. C) This permit is presented to the Police Department in Abqaiq at which point a policeman is assigned to accompany the Service Company to the Gun Shop. D) At the Gun Shop, the service company retrieves the explosive charges required and transports them to the rig (while a policeman is present at all times) to perform the job. E) Prior to start of the job, the explosives are counted and run in hole. F) After detonating the explosive charges, the downhole equipment is retrieved and the explosive charges are inspected to insure they have been fired. All unexploded charges are returned to the gun shop for reuse on a future job.

1.6.2

Remote Areas outside the Eastern Province Jurisdiction: A) Four to five months prior to moving in a drilling rig to drill an exploratory well in an area outside the Eastern Province, the Manager of Drilling & Workover Services sends a letter to Government Affairs requesting assistance in obtaining blanket approval to transport explosive charges. The letter should contain 1. The location of the proposed well 2. All the necessary explosive charges which might be needed (such as perforations, tubing punch, casing cutter, packer setting charges and pipe back-off)

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3. The approximate start of operations 4. The statement “the explosives to be transported to the rig site belong to Schlumberger or Western Atlas on consignment to Saudi Aramco”. B) Government Affairs then contacts the Explosives Police department in Dammam who in turn communicates with Riyadh. C) Upon approval, the explosives Police department contacts the respective police departments in each province and notifies them of the fact. D) A written blanket approval to transport explosive charges is then issued to the Service Company. E) When the rig foreman or drilling engineer contacts the service company for notification of upcoming explosive charge service, mobilization starts 3 to 4 days in advance to reach location on time. In both cases where explosive charges are required for well operations with a rig on the well, it is essential to notify the Service Company well in advance to overcome unavoidable delays and prevent rig standby time. 1.7

Safety Concerns and Precautions 1.7.1

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Radio Silence A)

Onshore: All radio transmitters, stationary or mobile (cars & facilities), within the vicinity of the rig will be turned off prior to arming of the detonator, running the explosive charges in the hole, pulling out of hole, retrieving the tool at surface and inspecting for unfired charges. The operation of radio transmitters could cause inadvertent detonation and firing of the explosive charges.

B)

Offshore: All radio transmitters, stationary or mobile (platforms, boats & other nearby facilities), within the vicinity of the rig will be turned off prior to and during arming of the detonator, running the explosive charges in hole, pulling out of hole, retrieving the tool at surface and inspecting for unfired charges. The operation of radio transmitters could cause inadvertent detonation and firing of the explosive charges.

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1.7.2

C)

Helicopter Service: Flights should be rescheduled to avoid flying into the vicinity of the well while perforating activities are in progress. The operation of radio transmitters in the helicopter could cause inadvertent detonation and firing of the explosive charges.

D)

In situations such as perforating a well in proximity to a gas plant, where complete radio silence is impractical or impossible, the Service Companies can provide, for an additional charge, safety equipment which prevent inadvertent detonation of explosive charges due to radio transmission, RF-induced stray voltages, and voltages induced by cathodic protection and welding. Schlumberger’s Slapper-Actuated Firing Equipment (S.A.F.E.) and Western Atlas’s Guardian are currently available for In-Kingdom use. Caution should be used when selecting these tools due to their pressure and temperature limitations.

Voltage Around the Rig After grounding the casing, rig structure, pipe rack and logging unit, the Service Company representative will measure the voltage difference between the casing and the rig structure. For Schlumberger, the reading should not exceed 0.25 volts, and for Western Atlas, 0.20 volts. If the readings are higher, a search should be made to identify the source and turn it off immediately. The reason for these voltage limits is to avoid inadvertent detonation of the charges.

1.7.3

Safety Meeting Prior to every job where explosive charges are to be used, the Saudi Aramco foreman will hold a safety meeting with all site personnel in attendance. The following safety items will be discussed: A)

Barriers: The erected barriers will be identified and off-limits areas indicated to unauthorized personnel. The objective is to minimize risk to personnel not required for this activity.

B)

Signs: The foreman will insure that Arabic & English signs indicating the silence of radio transmission are posted around the location and at the entrance to the rig road. He will insure that all radios and other equipment, which could generate RF-

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induced stray voltage at the rig site, have been turned off and everyone on location understands the impact. C)

Smoking: Designated smoking areas will be clearly identified.

D)

Weather conditions: The foreman should alert all present of his intention to suspend the explosive charge detonation if weather conditions (sand storms, electrical storms, etc.) change for the worse. The foreman can suspend operations at any time if in his judgement adverse weather conditions create a hazard to personnel or equipment.

E)

1.7.4

Emergency exit: In case of a mishap, alternate escape routes should be pointed out to the attendees.

Perforating after Dark If an oil or gas well is expected to have high wellhead pressure after perforating, then perforating should only be conducted during daylight hours. It is unacceptable to perforate high pressure wells in the dark unless a waiver is obtained from the General Manager of Drilling & Workover or the Vice President of Petroleum Engineering and Development. This policy has been in effect since it is difficult to detect a wellhead leak should it occur at night.

1.7.5

Arming the Detonator Prior to arming the detonator, the Service Company representative will inform the Saudi Aramco rig foreman or engineer in charge of his intention to insure it is safe to do so. Also, at the conclusion of the job when all explosive charges are either detonated or safely locked away, the Service Company representative will inform the rig foreman of job termination in order to turn on the radios and resume communication.

2.0 TUBULAR PUNCHERS 2.1

Types of Punchers Punchers are used to create a hole or orifice in tubulars to establish communication between the inside and outside. Punchers are often used to punch holes in tubing or drill pipe to establish circulation, in casing to

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squeeze cement behind pipe, and other uses. Mechanical, and explosive tubing punchers are currently available in Saudi Arabia. 2.1.1

Explosive Type: A one-foot section of tubular is usually perforated with 4 or 6 shots per foot of explosive charges as desired. The important criteria for explosive punching is creating holes large enough and with the desired penetration objective (i.e. between one and four casing strings) to .be able to pump fluid or cement through them with ease.

2.1.2

Mechanical Type A mechanical puncher or perforator which can be used with wireline, under pressure, to perforate both standard and heavyweight tubing. Saudi Aramco wireline provides this service to the rigs when called upon.

2.2

Suppliers & Specifications Schlumberger and Western Atlas are the two In-Kingdom suppliers of explosive tubular punchers. When requesting Tubing Puncher service, the same requirements apply as perforating service. See Chapter 5, Section 1.4. 2.2.1

Western Atlas

Puncher Tool OD inches

Max. Tubular Wall Thickness to be penetrated inches

Average Exit Hole Size in Inner Pipe inches

Maximum Penetration in outer pipe, inches

1-9/16”

0.61

0.29

Not Available

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2.2.2

Schlumberger: Puncher

1-3/8” HNS 16DS Minimum Maximum 16CL Minimum Maximum 1-11/16” HNS 20ES Minimum Maximum 20DM Minimum Maximum 20DL Minimum Maximum

2.3

Tubing/Casing Wall Thickness inches

Average Exit Hole Size in Inner Pipe inches

Maximum Penetration in outer pipe, inches

0.19 0.375

0.30 0.23

0.10 0.05

0.375 0.50

0.22 0.13

0.10 0.05

0.19 0.375

0.32 0.24

0.10 0.05

0.375 0.50

0.30 0.23

0.10 0.05

0.5 0.58

0.25 0.17

0.10 0.05

General Comments There is a concern that a second outer pipe (usually casing) can get penetrated or deformed if excessive explosive charges are used and the pipes are in contact with each other at the perforating location.

2.4

Safety Concerns and Precautions Since explosive charges are used to punch holes in tubulars, the same safety concerns are applicable as perforating. See Chapter 5, section 1.7.

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3.

PIPE CUTTERS 3.1

Types of Cutters Cutters are primarily used to cut or sever tubulars for retrieving out of hole. Common uses include cutting tubing or drill pipe after becoming stuck in the hole, cutting and salvaging casing when economical and feasible, etc. Explosive, mechanical and chemical cutters are currently available in the industry, however, only mechanical and explosive cutters are used in Saudi Aramco’s operations.

3.2

Suppliers and specifications Schlumberger and Western Atlas are the two In-Kingdom suppliers of explosive tubular cutters. When requesting explosive tubing cutters, the same requirements apply as perforating service. See Chapter 5, Section 1.7. Additional ordering lead-time is needed since the cutters usually have to be shipped in from out-of-Kingdom. 3.2.1

Explosive or jet Type: Explosive Jet Cutter A cut is made by an explosive, shaped with a concave face and formed in a circle. It is run and fired on electric line. When the cut is made the end of the pipe is flared and requires mill over to dress off for fishing operations. The jet cutter is often used when retrieving stuck tubing or drill pipe, abandoning a well during salvage operations or when low fluid level, heavy mud, or cost would prevent the use of the chemical Sha pe d Cha r ge Ex plos iv e cutter. There is a possibility of damage to an adjacent string or to a casing if the pipe to be cut is touching at the point where the cut is made.

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3.2.2

Mechanical Type A mechanical cutter is designed to cut pipe with a set of knives installed in a tool and run on a small diameter work string. Internal Mechanical pipe cuts are most common when removing sections of casing and wellhead equipment during final well abandonment operations. See Chapter 7, Section A for tool operating details.

3.2.4

Chemical Type The use of a propellant and a chemical (halogen fluoride) is used to burn a series of holes in the pipe, thus weakening and making it easy to pull the pipe apart with slight pull. See Chapter 7, Section A. Specifications A)

Schlumberger Pipe Recovery Systems cutters are available in-Kingdom for cutting 2-3/8”, 2-7/8” 3-1/2” and 4-1/2’ tubing. In addition, a cutter is available for 3-1/2” drill pipe, ranging from 12.95 to 15.50 lbs/ft. If CT cutters are required, they will have to be brought in from out-of-Kingdom.

B)

Western Atlas GOEX and JRC cutters and severing tools are available in different sizes to cut various tubing, casing and drill pipe from 2-3/8” to 10” OD. To find out the exact cutter sizes on hand, Western Atlas should be contacted when the need arises.

3.3

General Comments When cutting pipe, a concern is raised regarding the damaging or cutting of the outside casing, particularly if the two are in contact with each other at that point.

3.2

Safety Concerns and Precautions Since Explosive charges are used to cut or sever tubulars, the same safety concerns are applicable as perforating. See Chapter 5, section 1.7.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 5

WIRELINE LOGGING AND EXPLOSIVES

D

SECTION

June 2006

EXPLOSIVES

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4.

DRILL PIPE BACK-OFF When drill pipe becomes stuck in the wellbore, the depth at which drill pipe is stuck is determined by either calculations or more accurately through Free-Point instruments run on electric line inside the stuck drill pipe. Upon determining the drill pipe stuck depth, it is desirable to part the drill pipe above the stuck point so that fishing tools can be run to retrieve the remainder of the pipe. Pipe back-off is the unscrewing of the drill pipe at a selective threaded joint above the stuck point by using prima cord explosive which is run on electric line. Reverse torque applied to the drill pipe from surface along with the explosive shock generated by the prima cord across a collar most often results in unscrewing of threads. 4.1

Suppliers and Specifications Both Schlumberger and Western Atlas provide pipe back-off service. When requesting Back-Off service, the same requirements apply as perforating service. See Chapter 5, Section 1.4. 4.1.1

Specifications

Pipe O.D. (inches)

Tubing

Drill Pipe

Drill Collars

Casing

2-3/8 2-7/8 4 to 4-1/2 2-3/8 to 2-7/8 3-1/2 to 4 4-1/2 to 6–9/16 6-5/8 3-1/2 to 4 4-1/8 to 5-1/2 5-3/4 to 7 4-1/2 to 5-1/2 6 to 7 7-5/8 8-5/8 9-5/8 13-3/8

0 to 3000 1 1 2 1 2 2 3 2 to 4 2 to 4 3 to 6 3 3 4 5 5

Depth From Surface (Feet) 3000 6000 9000 to to to 6000 9000 12,000 1 1 2 2 3 3 to 4 4 to 5 2 to 5 3 to 6 4 to 8 3 3 4 5 5

1 2 2 2 to 3 3 to 4 4 to 6 5 to 7 3 to 7 4 to 8 5 to 10 3 3 4 5 5

2 2 3 3 to 4 4 to 6 5 to 9 6 to 10 3 to 8 4 to 10 6 to 12 3 4 4 5 6

Over 12,000 2 3 3 4 to 6 5 to 6 6 to 12 7 – 14 4 to 9 5 – 12 7 to 15 3 4 5 5 6

Note: The table above shows the quantity of 80 gms/ft RDX prima cord strands to be used according to the depth and pipe size, and assumes a well full of 0.52 psi/ft. mud. Where two values are given, the higher value indicates the

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Drilling & Workover Engineering Department CHAPTER 5 SECTION

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WIRELINE LOGGING AND EXPLOSIVES

D

EXPLOSIVES

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maximum explosive load that normally will not damage pipe in heavy mud. Such high loads may, however, be detrimental to the electric wireline toolstring, e.g. CCL, cable head, etc.

4.2

Procedures 4.2.1

General Comments A)

The weight of the drill string at the point of back-off should be correctly calculated. Normally, the buoyancy effect of the mud is ignored, and the weight of the drill string in air is used. The ideal weight condition at the point of back-off is a neutral condition. Determining this condition requires careful calculation, however, where there is any uncertainty, the calculation must be made so as to leave the break in tension The following information is necessary for an accurate calculation: ♦

♦

♦

The weight of the string when it became stuck (Weight up and down should be recorded). Does the string weight include the kelly, and or the traveling block assembly? What was the pump pressure prior to sticking?

The applied pull is equivalent to the indicated string weight before sticking, minus the buoyant weight of the fish to be left in the hole. B)

Sufficient back-off torque. The amount of reverse torque to be applied depends on the pipe used, hole depth and deviation and so no hard and fast rule can be laid down. As a general guide, the following figures are recommended: Drill Pipe Length Under 4000 ft. 4000 to 9000 ft. Over 9000 ft.

Turns/1000 ft. 1/4 to 1/2 1/2 to 3/4 3/4 to 1

It is important to take into account the age and condition of the pipe prior to torquing.

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D

June 2006

WIRELINE LOGGING AND EXPLOSIVES EXPLOSIVES

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4.2.2

C)

Successful back-offs between drill collars is statistically low. The best string joints for back-off therefore is at the crossover from the drill collars to the HWDP (if unstuck). This enables fishing assemblies to be jarred directly on the drill collar string.

D)

Tong and slip dies must be sharp, clean and the correct size to bite and hold the pipe, kelly or whatever other part of the string protrudes above the rotary table.

E)

When applying torque with the pipe in the hand slips (prior to installing tongs), the slip handles must be tied with soft line to prevent them from slipping or jumping during this operation.

F)

When applying torque, the elevators should be latched around the pipe and free below the tool joint so that the pipe can rotate freely through the elevators. The hook should be unlocked when the pipe is being rotated in the slips.

G)

If the pipe is to be lifted out of the slips without the tongs engaged and biting, ensure that there is no residual torque present to rotate the pipe and create a hazard.

H)

The bull plug at the top of the swivel must be well maintained so that if a string shot has to be run through the kelly, it is not necessary to remove the gooseneck.

I)

If operational conditions do not allow application of back-off torque, it may be necessary to “jump a box” using explosive charges run on wireline.

Applying Torque & Working it down to the Stuck Point It is often necessary to work the back-off torque down the string to the desired back-off depth, especially in crooked or deviated holes. To accomplish this task, the following procedures should be followed: A)

Prior to applying the back-off torque, torque the string to the recommended level. Check the torque amount on the ammeter. When later applying back-off torque, the reading on the ammeter should not exceed the maximum observed while applying initial torque.

B)

Set the string at the calculated back-off weight.

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C)

Mark the pipe at the top of the slips and refer to this datum mark at all times. Thereafter, do not use the weight indicator because wall friction may cause an inaccurate reading.

D)

Apply 50% of the back-off torque required for the back-off and lock the rotary.

E)

Use a jerk-line and the rotary tongs to pull off the rotary lock and hold.

F)

Pick up the string off the slips and work the pipe vertically a few times. Do not go lower than the “weight mark” since the pipe may break at random.

G)

Set the pipe back on the slips at the “weight mark” and pull on the tongs to relock the rotary.

H)

If it is believed that the pipe will accept the remaining torque, then apply it. If not, apply 50% of the remaining torque and keep repeating steps (C) through (F) until the full amount of the reverse torque is in the pipe.

Note: Using the rotary on the pipe to apply the full back-off torque can damage the pipe and cause the sting to break prematurely. Therefore, use the rotary to apply 50% of the back-off torque and complete the operation using the rotary tongs. 4.2.3

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Detonating the Prima Cord A)

Rig up the service company lubricator and pressure test.

B)

Arm the string shot and run in hole to target depth with the help of the CCL, as dictated by the Saudi Aramco rig foreman. Note: The tables in section 4.2 above should be used to determine the correct quantity of prima cord strands needed to obtain a successful back-off.

C)

Detonate the prima cord while observing the rotary tongs and torque gauge on the control.

D)

Pull out of hole with the electric line.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 5 SECTION

D

June 2006

WIRELINE LOGGING AND EXPLOSIVES EXPLOSIVES

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4.2.4

Completing the Back-off A)

Check for back-off. Usually the pipe has spun free with the box and pin completely unscrewed. In some cases, however, the pipe may only partially back-off and when picking up, no indication of back-off will be observed.

B)

Complete the back-off by applying approximately 50% of the calculated back-off torque to the string and work the pipe up and down while ensuring that the neutral point passes beyond/below the point where the back-off was shot.

C)

If any torque is lost, repeat step (a) until the back-off is completed.

D)

If no torque is lost, then increase the torque an increment and observe.

E)

Reassess the string weight and back-off point, and prepare to attempt another back-off. Note: i) Based on experience, if the pipe fails to back-off the first time after detonating the prima cord, no additional torquing effort will unscrew the selected joint. The next attempt should be at least 1 or preferably 2 joints higher. If the hole is filling rapidly, the string should be backed out of the hole and washover commenced a quickly as possible so that the hole can be brought under control and washover time minimized. ii)

On completion of a successful back-off, pull out of the hole while checking all connections for the correct make-up torque.

iii)

When out of the hole, do not rotate the pipe and do not circulate unless necessary.

iv)

When pulling the electric line tool out of the hole, observe for breaks on the CCL. Also, observe the tension meter in case the tool hangs up.

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4.3

Safety Concerns and Precautions Since explosive prima cord strand(s) are used to back-off pipe, the same safety concerns are applicable as perforating. See Chapter 5, section 1.7.

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Drilling & Workover Engineering Department CHAPTER

6

June 2006

WELL TESTING

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WELL TESTING 1.0

INTRODUCTION

2.0

RESPONSIBILITIES 2.1 Drilling Foreman 2.2 Drilling Engineer 2.3 Well Test Engineer

3.0

OPERATIONAL REQUIREMENTS 3.1 Planning the Well Test 3.1.1 Buttoned-up Test 3.1.2 Non-Buttoned-up Test 3.1.3 Open Hole Test 3.1.4 Barefoot Test 3.1.5 Cased Hole Test 3.1.6 Limited Entry Test 3.1.7 Minimum Barriers 3.1.8 Packer Fluid 3.1.9 Test String 3.1.10 Retrievable Test Packers 3.2 Prior to Well Testing 3.3 During Well Testing 3.4 Livening the Well 3.4.1 Coiled Tubing 3.4.2 Nitrogen 3.4.3 Limitations 3.5 Killing the Well 3.5.1 Bullheading 3.5.2 Coiled Tubing 3.5.3 Reverse Circulating

4.0

TOOL CONFIGURATIONS 4.1 7” Barefoot Test 4.2 9-5/8” Barefoot Test 4.3 Micro Frac Test 4.4 Open Hole Test 4.5 Cased Hole Test 4.5.1 TCP 4.5.2 Enerjet

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 6

_

June 2006

WELL TESTING

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WELL TESTING 1.0

INTRODUCTION Well testing is an important source of information with respect to the reservoir potential of a geologic formation. The objectives of a well test are to determine the reservoir characteristics and to obtain a representative sample of the reservoir fluid for analysis. These objectives are achieved by the following: A)

Running in the hole with a test string and tool assembly to either perforate the production casing or flow test an open-hole section.

B)

Flowing the reservoir fluids to obtain samples, flow rates and surface pressures (or limited entry data in the case of an extreme high pressure and H2S content well).

C)

Collecting data on bottom-hole pressure recorders during flowing and downhole shut-in periods.

The purpose of this chapter is to present testing responsibilities, operational requirements, and test tool configurations involved in the well testing operation. The testing procedures described in this chapter will vary slightly with the type of test tools utilized, but the principals and policies remain the same. Individual test tools/equipment descriptions are not meant to be addressed in this chapter. Safety is the major concern in well testing and must be considered throughout each stage of the testing operation.

2.0

RESPONSIBILITIES The operational success and safety of a well test, especially a high pressure Khuff (sour gas) well, largely depends on good co-ordination and communication between Drilling & WO Operations, Drilling & WO Engineering, and Reservoir Description/Well Testing. The responsibilities of each department representative on the rig are specified below. These responsibilities are not intended to be a comprehensive list nor are they meant to be the sole concern of only the indicated representative. Each representative should contribute to all phases of the test. Prior to testing, a meeting should be held on the rig between the respective department representatives to achieve a clear understanding of the work to be performed and to identify each individual’s specific role.

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2.1

Drilling Foreman Two Drilling Foremen should be assigned to supervise the well testing operation. The Drilling Foreman on duty has the overall responsibility for the rig and safety of the personnel. He has the option at any time to change procedures or stop operations, if he considers that a situation will become dangerous. In such situations, he can override the authority of the Contract Toolpusher (on contract rigs) and refer the situation to the Drilling Manager. The Drilling Engineer and RDD-Well Testing Engineer shall consult with the Drilling Foreman prior to any instructions/requests given to rig or testing personnel. The Drilling Foreman is specifically responsible for the following: 2.1.1

Ensuring that the fire fighting systems and breathing apparatus are inspected and in good working order.

2.1.2

Conducting H2S drills and safety meetings with each crew prior to testing.

2.1.3

Conducting special safety meetings prior to initiating the test. This will require at least two meetings to include both crews. Special emphasis should be placed on emergency shut down procedure, personal safety equipment, evacuation to the “safe briefing area”, rescue operations and first-aid procedures.

2.1.4

Ensuring proper well preparation (casing pressure testing, scraping, circulating or displacing).

2.1.5

Witnessing pressure testing of the BOP stack prior to running the test tools.

2.1.6

Supervising the running/drifting of the test string and setting of packer.

2.1.7

Witnessing all pressure testing of test tools, test string, test tree (or test head), and surface test equipment. Verifying all test equipment is suitable for H2S service. All items from the test tree (or test head) to the choke manifold should be furnished by the surface test equipment company, if possible. Any items furnished by the drilling contractor or Saudi Aramco (such as chicksans, co-flex hose, valves, etc.) should be on an emergency basis only and must be checked for manufacturer, pressure rating, and H2S rating.

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2.1.8

Installation and pressure testing of the kill line from the cement pump unit to the kill line valve on test tree (or test head). Installation of rig pumps to Tubing Casing Annulus (TCA).

2.1.9

Alerting Security of upcoming well testing and flaring.

2.1.10 Ensuring the number of personnel on the rig is at a minimum during testing and all personnel are H2S certified. Other related departments should notify Drilling Operations of essential personnel required for upcoming well test. 2.1.11 Ensuring an adequate volume of kill mud with appropriate properties is available in the mud tanks (1.5 times the hole volume) and a sufficient stock of mud chemicals (including H2S scavenger) available on the rig. 2.1.12 Verifying that any required welding is done at a safe distance and appropriate time. 2.1.13 Implementing radio and telephone silence as required. 2.1.14 Ensuring flaring operations are conducted safely and initiated in daylight hours. All produced gases must be burned through a flare system equipped with a continuous pilot and an automatic igniter. At least one back-up ignition device must be provided. Stored produced fluids must be vented to the flare pit. The main flare pit to the south will be rigged up with flow lines for testing. 2.1.15 Ensuring the flow testing operation is performed safely. The test should be conducted with the minimum number of personnel on the rig floor and in the vicinity of test lines/equipment. Other personnel should be assigned duties in an upwind area away from the cellar, rig floor, and test lines/equipment. During the test, the presence of H2S should be monitored with portable equipment or individual detection devices. 2.1.16 Installation and pressure testing of the acidizing lines. Ensuring the well stimulation operation is performed safely. 2.1.17 Witnessing the rig-up and pressure testing of wireline lubricator and coiled tubing unit.

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2.1.18 Supervising the lifting operation with coiled tubing and nitrogen, if minimal flow to surface during the test. 2.1.19 Supervising the well kill operation following the test. 2.1.20 Ensuring the minimum requirement of barriers/shut-offs #1853.001) are observed in all phases of the testing program.

(G.I.

2.1.21 Ensuring any additional requirements, based on the H2S Contingency Plan, are met when testing a sour well. 2.2

Drilling Engineer The Drilling Engineer assigned to the rig will be on location during the well testing operation. The Drilling Engineer will coordinate with GF&PD/Special Projects Unit for stimulation recommendations and will prepare the testing program as per ‘requirement letter’ from RDD-Well Testing. The Drilling Engineer will assist the Drilling Foreman and ensure the well testing program is strictly adhered to. The Drilling Engineer is specifically responsible for the following: 2.2.1

Consulting with the Drilling Foreman regarding the responsibilities associated with the well testing program. Consulting with the Drilling Foreman prior to giving instructions/requests to the rig or testing personnel.

2.2.2

Supervising the ‘Cased Hole Logging’ company personnel while correlating and perforating. Ensuring the proper equipment and procedures are utilized. Ensuring personnel perform in a professional and safe manner.

2.2.3

Witnessing the mixing/filtering of the completion or packer fluid, if required. Ensuring the brine density is the required kill weight at down-hole conditions.

2.2.4

Re-verifying the final brine packer fluid and water cushion density. Recalculating the shear pin setting and hydraulic firing pressure, if TCP is required.

2.2.5

Checking the measurement and tally of test string and tools run in the hole. Verifying the setting depth of the packer and position of TCP guns, if required.

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2.2.6

Supervising the ‘Downhole Test Tool’ company personnel regarding the well testing procedure. Ensuring the proper test tools and procedures are utilized. Verifying the pressure settings of all annular operated tools with the actual packer fluid density. Ensuring the minimum pressure settings are not exceeded with applied TCA pressure while testing the packer seat. Ensuring personnel perform in a professional and safe manner.

2.2.7

Witnessing pressure testing of the test tools, test string, test tree (or test head), and surface test equipment.

2.2.8

Checking TCA pressure throughout the test and pressure bleed-offs made while flow testing, to prevent functioning down-hole tools.

2.2.9

Witnessing the pressure testing of acidizing lines. Ensuring the stimulation program is strictly followed and safely performed.

2.2.10 Assisting in the lifting operations with coiled tubing and nitrogen. Checking the tubing collapse pressure and packer differential pressure based on full evacuation and hydrostatic pressure of the packer fluid. 2.2.11 Assisting in the well kill operation. 2.3

Well Testing Engineer An assigned RDD-Well Testing Engineer will be on location during the well test operation. The Well Testing Engineer will supervise the flow testing, shutin periods, and sampling requirements during the well test. The Well Testing Engineer will ensure the well testing requirements are strictly adhered to. The Well Testing Engineer is specifically responsible for the following: 2.3.1

Consulting with the Drilling Foreman regarding the responsibilities associated with the well testing program. Consulting with the Drilling Foreman prior to giving instructions/requests to the rig or testing personnel.

2.3.2

Verifying that the down-hole gauges are properly programmed with the ‘Down-hole Test Tool’ company personnel.

2.3.3

Coordinating with the Saudi Aramco Lab to have sample catchers and required containers on the rigsite during the flow test.

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2.3.4

Verifying calibration of the liquid meters on the separator by pumping fresh water to the gauge tank.

2.3.5

Supervising the surface test equipment personnel while flow testing and sampling well. Ensuring the proper equipment and procedures are utilized. Ensuring personnel perform in a professional and safe manner.

2.3.6

Recording all information specified while flow testing. Providing an accurate daily summary to RDD-Well Testing and the Drilling Foreman.

2.3.7

Coordinating with the Drilling Foreman and Drilling Engineer regarding any change in the well testing requirements or procedure.

2.3.8

Supervising the ‘Cased Hole Logging’ company personnel while running PLT. Ensuring the proper logging tools and procedures are utilized. Ensuring personnel perform in a professional and safe manner.

2.3.9

Alerting the Drilling Foreman on duty immediately of the presence and concentration of H2S, if at any time it is detected in the flow stream.

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3.0

OPERATIONAL REQUIREMENTS 3.1

Planning the Well Test The table below summarizes the operational considerations in planning the well test with respect to expected formation pressure, H2S content, and produced fluid. The organization requesting the well test shall provide Drilling and Workover Engineering the required reservoir parameters and testing requirements in sufficient time to properly prepare the well testing program and coordinate with the testing company.

WELL TESTING

ABOVE JILH FORMATION

BELOW JILH FORMATION

Formation Pressure < 0.55 psi/ft

Formation Pressure > 0.55 psi/ft

Low Pressure Well

High Pressure Well

Expected

Expected

Expected

Oil or Water

Gas

Oil, Water or Gas

H2S ≤ 5%

H2S ≤ 10%

H2S ≤ 10%

1.

Non-Buttoned up

1.

Non-Buttoned up

1.

Non-Buttoned up

2.

Use drill pipe

2.

Use L-80 tubing

2.

Use L-80 tubing

3.

Open hole or cased hole testing

3.

Open hole or cased hole testing

3.

Cased hole testing only

H2S > 5 and ≤ 10%

H2S > 10%

H2S > 10%

1.

Non-Buttoned up

1.

Non-Buttoned up

1.

Buttoned up to flow to surface

2.

Use L-80 tubing

2.

Use L-80 tubing

2.

Use L-80 tubing

3.

Open hole or cased hole testing

3.

Cased hole testing only

3.

Cased hole testing only

4.

Use 10,000 psi tree

H2S > 10% 1.

Buttoned up

2.

Use L-80 tubing

3.

Cased hole testing only

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3.1.1

Buttoned-up Test A ‘buttoned-up’ test requires nippling down the BOP stack and installing a test tree prior to testing the well. After killing the well, the test tree is nippled down and BOP stack re-installed to pull the test string. This test method is required on all high pressure gas wells, low pressure gas wells, and low pressure oil wells with > 10% H2S. A subsurface safety valve should be installed in the test string (approx. 300’) on a buttoned-up test of a high pressure gas well in a critical location (near populated area or a surface facility). This will involve a modified tubing bonnet (bored to exit the control line).

3.1.2

Non-Buttoned-up Test A ‘non-buttoned-up’ test utilizes a test head (supplied by the DownHole Tool company). This test method will reduce the associated rig time/cost of the test by eliminating the need to ND the BOP stack, install the test tree, remove test tree after test, and NU the BOP stack. The non-buttoned-up test is recommended on all high pressure gas wells, low pressure gas wells, and low pressure oil wells with < 10% H2S. A non-buttoned-up test may be run on high pressure exploration gas wells where H2S is not expected (as in the Pre-Khuff). A surface safety valve should be installed in the test string (across the BOP stack) on a non-buttoned-up test of a high pressure gas well.

3.1.3

Open Hole Test An open hole test requires isolating the zone of interest with two open hole packers above the zone and perforated tail pipe on bottom. This type of well test is recommended only on low pressure and shallow less risk wells, as problems associated with losing the packer seat and stuck test tools are common. Open hole testing is limited to low pressure gas wells and low pressure oil wells with < 10% H2S.

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3.1.4

Barefoot Test A bare foot test is an open hole test with the packer set inside the previous casing shoe. This type of test improves the packer-seat capability but is limited to only one exposed reservoir (upper-most) in the open hole interval. A barefoot test should be considered in the following situations: A)

Where open hole depth or hole diameter near the zone of interest may hinder achieving a good packer seat.

B)

Where open hole deviation or borehole instability may result in problems freeing the packer at the conclusion of the well test.

Open hole testing of high pressure gas wells shall be limited to bare foot tests only (with the packer set inside the previous casing shoe). 3.1.5

Cased Hole Test A cased hole test consists of perforating and testing a zone of interest behind pipe. The advantages of a cased hole test include the ability to isolate (a) small test intervals and (b) reservoir pressure while running test tools. The test duration of a cased hole test will be longer and more data extensive. The perforation technique will vary from Tubing Conveyed Perforating (TCP) to ‘Through Tubing Wireline Perforating’ (Enerjet). Perforating should be done underbalanced, if at all possible, with the largest size gun that can be run. RDD-Well Testing (in conjunction with Exploration, if an exploration well test) will determine the perforation requirements.

3.1.6

Limited Entry Test A limited entry test consists of a non-buttoned-up test with full water cushion to gauge entry. No flow should be allowed at surface. Limited entry should be used on high pressure wells that are highly questionable producers with unknown concentrations of H2S. If the well shows good flow characteristics on limited entry, the well should be killed and buttoned-up before further testing.

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Limited entry can also be used on a buttoned-up test of an expected good producer with unknown bottomhole pressure. If the surface pressure and calculated bottomhole pressure are acceptable with regard to the surface equipment pressure rating, then the well test may continue. Otherwise, the test shall be terminated and well killed immediately. 3.1.7

Minimum Barriers (Shut-offs) The minimum requirement of barriers (G.I. #1853.001) shall be observed in all phases of the testing program. These policies are shown below: Oil Wells (GOR less than 850 scf/bbl) 2 shut-offs (1 mechanical) Oil Wells (GOR more than 850 scf/bbl) 3 shut-offs (2 mechanical) Gas Wells 3 shut-offs (2 mechanical)

3.1.8

Packer Fluid The packer fluid density used in the TCA shall never be less than kill mud weight. If annular operated tools are required, a brine of kill weight density (CaCl2/CaBr2 for Khuff/Pre-Khuff wells) is recommended to avoid mud solids settling, which can result in operational problems with the annular operated tools and freeing the packer. Mud should be used as a packer fluid in open hole tests, and cased hole tests where brine cannot be mixed to kill-fluid density.

3.1.9

Test String The test string on all gas wells (both low and high pressure) shall consist of 3-1/2” 12.95# L-80 tubing with a premium connection (as PH-6). Drill pipe may be used as a test string on low pressure oil wells with < 6% H2S.

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3.1.10 Retrievable Test Packers A retrievable packer (Champ or Flex-Pac ) should be utilized as the test packer. Running retrievable test tools eliminates the additional time associated with milling a permanent packer. If the zone of interest is extremely high pressure gas, with H2S, and in a critical area, a permanent packer should be utilized. 3.2

Prior to Well Test Prior to well testing activities, the following operational requirements should be carried out: 3.2.1

‘Pre-testing’ safety meeting(s) shall be held with each crew and all concerned personnel on location. The emphasis should be on safety awareness while conducting the following operations: Pressure Testing (with nitrogen) Chemical Handling and Hazards (CaCl2/CaBr2 brine) Wireline Operations Perforating Acidizing Emergency Shut Down Special emphasis should be placed on H2S safety, when applicable, as shown: Personal Safety Equipment Evacuation to the “Safe Briefing Area” Rescue Operations First-Aid Procedures

3.2.2

A H2S drill with each crew shall be conducted prior to any testing.

3.2.3

All breathing apparatus shall be inspected and ready for emergency use. All concerned personnel on location during testing shall have H2S and Scott Airpak Donning training or certification.

3.2.4

All appropriate fire fighting equipment should be checked and ready for emergency use.

3.2.5

All vent lines from stored produced fluid vessels must be vented to the flare pit. These lines shall be checked and verified open.

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3.2.6

The main flare pit to the south shall be rigged up with the required number and length of flare lines for testing. •

•

Khuff/Pre-Khuff gas wells require 1000’ of flare line (2 to 3) 4-1/2” VAM flow lines for gas (weighted down) (1) 3-1/2” EUE liquid line (tied or weighted down) Oil wells require 300’ of flare line utilize existing flare lines during drilling (tied or weighted)

A secondary pit is required on all Khuff/Pre-Khuff gas wells. This pit will be used for emergency well control operations only and will not be utilized during the well testing activities. The only *line to this pit will remain connected to the drilling choke manifold. •

(1) 4-1/2” VAM flare line

3.2.7

Prior to running the test tools, the test plug shall be installed. The tubing hanger bowl and BOP stack shall be tested to 90% of working pressure with water. An accurate measurement from rotary table to tubing hanger bowl should be made with the test plug assembly (if buttoned-up test).

3.2.8

The test string configuration and tools will vary depending of type of well test and down-hole tools. All rubber elements and O-rings shall have a 95 Duro-meter rating for Khuff/Pre-Khuff gas wells.

3.2.9

If TCP is used, the primary firing system should be hydraulic with a 1-1/4” drop bar system as a back up. If TCP guns are to be dropped to accommodate production logging across perforations or stimulation with ball sealers, adequate rat hole will be required. If TCP guns are not dropped, wireline or coiled tubing can only be run to the flow sub.

3.2.10 Down-hole electronic and temperature recorders will be specified in well testing requirements. A mechanical gauge should be run as a back up. A sample chamber will be requested by RDD on wells with minimal expected inflow. 3.2.11 If TCP guns are utilized, the annular or pipe rams should not be closed while pressure testing the tubing (against the tubing tester valve). This will allow identifying the leak from the TCA and prevent prematurely firing the guns, if tester valve leaks.

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3.2.12 The test string shall be drifted as per the minimum ID requirement stated in the well testing program. 3.2.13 The use of slip joints will be required on Khuff/Pre-Khuff gas wells and will be specified in the well testing program. Typically three slip joints are run (upper slip joint: open, middle slip joint: 1/2 open, and lower slip joint: closed). This will allow 7.5’ of travel down (for expansion) and 7.5’ of travel up (for contraction). 3.2.14 If a button-up test is required and the well location is critical (near a populated area or surface facility), a subsurface safety valve should be installed in the test string (approx. 300’). This will require the use of a modified tubing bonnet (bored to exit the control line). 3.2.15 If a non-button-up test (test head) is required, a surface safety valve should be installed in the test string (across the BOP stack). 3.2.16 If a sub-surface safety valve (or surface safety valve) is in the test string on a Khuff/Pre-Khuff well, pressure test the valve as follows: A) B) C) D) E)

Pressure tubing to 8,500 psi against Tubing Tester Valve. Close surface safety valve (or sub-surface safety valve). Bleed-off pressure above valve to 500 psi. Check for leaks. Equalize pressure across valve. Reopen safety valve and bleed off pressure.

3.2.17 The water cushion will be spotted after setting the packer by pumping down the test string and circulating through the packer by-pass. Returns should be measured in the trip tank. On buttoned-up tests with existing perforations, coiled tubing will be required to spot the water cushion. On open hole tests, the water or diesel cushion is spotted by filling the drill pipe as required while running in the hole with test tools. 3.2.18 The packer seat and by-pass closure should be pressure tested to approximately 1000 psi (ensuring this applied TCA pressure is less than the setting of any annular operated tools) while observing the test string for leaks. This pressure will also lock open the Tubing Tester Valve. 3.2.19 The minimum requirement of barriers/shut-offs (G.I. #1853.001) shall be observed in all phases of the testing program. These policies are described below: ______________________________________________________________________________________ 13 of 28

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Oil Wells (GOR less than 850 scf/bbl) 2 shut-offs (1 mechanical) Oil Wells (GOR more than 850 scf/bbl) 3 shut-offs (2 mechanical) Gas Wells 3 shut-offs (2 mechanical) 3.2.20 The test tree (or test head) shall have a hydraulic or pneumatic ESD (Emergency Shut Down) safety valve installed as the flowline valve. This ESD valve should be remotely operated from the rig floor, choke manifold, and test equipment trailer. The remote ESD stations should be visually identified. All personnel should be made aware of this emergency shutdown procedure in the safety meeting. The ESD safety valve should be function tested daily, when possible. 3.2.21 The cement pump unit should be rigged up to the kill line valve and rig pumps connected to the TCA, independently, for immediate pump in capability, if required. A Lo-Torc valve or check valve should be installed immediately outside the kill line valve on the test tree (or test head). An adequate volume of kill mud with appropriate properties should be available in the mud tanks (1.5 times the hole volume) and sufficient stock of mud chemicals (including H2S scavenger) available on the rig. 3.2.22 Only lines with metal-to-metal seals (API Flanged or Graylock) or Coflex hose (if Coflon lined) of the proper pressure rating and H2S sour service are acceptable as indicated below, Upstream of Choke Manifold (10,000-15,000 psi WP) A) Only metal-to-metal seals (API Flanged or Graylock) (No Weco connections) B) Use of Coflex hose is conditional o Only Coflon lined o API Flanged or Gray-Lock (No Weco connections) o Only if CO2 + H2S < 30% Downstream of Choke Manifold (2,000-2,500 psi WP) A) Weco 602 connections acceptable B) Gray-lock connections acceptable 3.2.23 All components of the test manifold shall be the proper pressure rating and suitable for H2S sour service. 3.2.24 Pressure testing surface equipment should consist of the following,

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A) B) C) D) E) F)

Pressure test string to 8,500 psi Negative test surface safety valve and lower master valve Pressure test down-stream of choke to 1,200 psi with water Pressure test up-stream of choke to 10,000 psi with water Pressure test down-stream of choke to 1,200 psi with nitrogen Pressure test up-stream of choke to 8,000 psi (80% of water pressure test) with nitrogen Note: Pressure testing with nitrogen is not required on oil wells.

3.2.25 The Driller shall be rigged up to monitor and bleed-off TCA pressure from the rig floor. A pressure chart recorder will be installed to record TCA pressure and will be located/monitored near the choke manifold area. 3.2.26 A 10M H2S sand filter should be installed on all Pre-Khuff well tests in sandstone reservoirs. Formations as the Jauf and Unayzah can produce sand at high flow rates and erode surface test equipment in a short period of time. 3.2.27 A 10M H2S ball catcher should be installed on Khuff/Pre-Khuff gas wells if the stimulation program requires ball sealers for diversion. 3.2.28 A surface data acquisition system will be required on Khuff/Pre-Khuff gas wells. This system will provide an accurate real time readout/plot of flow line temperature, pressure, and flow rate. 3.3

During the Well Test During the well test, the following guidelines should be observed: 3.5.1

The initial opening of the well to unload the tubing contents shall be performed during daylight hours. Flaring operations may continue through the night but must be initiated at least 2 hours before darkness.

3.5.2

All produced gases must be burned through a flare system equipped with a continuous pilot and an automatic igniter. At least one back-up ignition device must be provided. The test should be shut-in at the choke manifold if the problems with flare ignition or unfavorable wind conditions develop.

3.3.3

Two surface test equipment operators (buddy system) should be on duty in the choke manifold/separator area throughout the well test.

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3.3.4

The Driller and two Floorhands shall be on duty on the rig floor throughout the test. The Driller should be familiar with the ESD (Emergency Shut Down) procedure. If a test head (non-buttoned-up test) is utilized, the Test Tool operator will also be on duty on the rig floor.

3.3.5

Crane operations should be restricted (not used or positioned near flowlines, choke manifold, separator, or any part of testing system under pressure) when possible.

3.3.6

The rig floor and area surrounding the surface test equipment shall be kept clear at all times.

3.3.7

After perforating, the well should be flowed to the flare pit for cleanup. The choke size should be changed slowly. Monitor and record FWHP, FWHT, %BS&W, H2S, CO2, pH, and Chloride content of any produced water. When clean, divert the well through the separator and establish a stable flow rate on a maximum size positive choke. Measure and record gas and liquid production rates and gravities. Take readings every 15 minutes until flow stabilizes and 30 minutes thereafter. Calibrate liquid flow rates using the gauge tank. Collect 2 sets of separator gas and liquid samples for recombination analysis during stabilized separator conditions. Collect samples of any produced water including glass bottles for isotope analysis. Note: Actual measurement and sampling requirements will vary depending on the type of well (oil or gas) and surface equipment required.

3.3.8

The Driller should monitor TCA pressure from the floor and bleed off increasing pressure during the flow testing to prevent functioning the down-hole tools. If annulus pressure can not be bled off, the well test shall be terminated and well killed immediately.

3.3.9

The first hydrocarbons to surface shall be checked immediately for the presence of H2S. If H2S is detected at any time during the well test in the flow-stream, the Drilling Foreman on duty shall be informed immediately. All personnel not immediately required should be instructed to keep clear of areas downwind of the test equipment.

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A constant check for H2S around the rig should be made. If H2S is detected in the atmosphere of any quantity at all, the Drilling Foreman on duty shall be informed immediately. The well test shall be shut-in at the wellhead if the leak is visible at surface; otherwise, a down-hole shut-in with surface safety valve or annular operated valve is required. If H2S persists and is detected in the atmosphere after repairing leaks, management should review the situation before proceeding. If at any time the situation appears life threatening or out of control, the well shall be killed immediately. 3.4

Livening Well Occasionally during a well test, the well will not flow to surface. The combined hydrostatic effect of the water cushion, produced water or rathole mud may be enough to prevent the well from flowing. In this situation, a coiled tubing unit is required to lift the well and reduce the hydrostatic pressure on the reservoir. The following guidelines should be observed during this operation: 3.4.1

Coiled Tubing Unit If the well does not flow after perforating, rig up a coiled tubing unit of adequate coil length, outside diameter clearance, required pressure rating, and BOP stack configuration (as per Saudi Aramco Well Control Manual). Pressure test coiled tubing (CT) to same pressure used to test the surface equipment or 120% of the maximum possible WHP for planned CT operation (whichever is less). Pressure test with water only. Test pressure must be stable for at least 15 minutes.

3.4.2

Nitrogen Nitrogen should be used to unload the test string, as pumping diesel is not recommended from an open top tank (pump truck). Stage in hole with the coiled tubing and displace the test string contents with nitrogen. The well should be monitored for flow, as the coiled tubing is staged-in and test string unloaded. Caution is required while running through test string components of minimum ID (slip joints, drill collars, and down-hole valves). Once the well is kicked off, the coiled tubing should be immediately pulled out of the hole and the flow test continued.

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3.4.3

Limitations Several limitations may exist while lifting with nitrogen at deeper depths. These include the following: 1)

Collapse of the Coiled Tubing If the well starts to flow, the wellhead pressure (outside the coiled tubing) will increase. The differential pressure across the coiled tubing (outside to inside) can exceed the collapse rating of the coil. The coiled tubing operator should provide the differential pressure limitation. Continued lifting at greater depths will not be possible if this differential pressure is approached. Opening the choke and pumping nitrogen at a faster rate should be enough to control the differential pressure while pulling out of hole with coiled tubing.

2)

Collapse of Test String If the test string continues to be unloaded with no inflow, the tubing collapse rating may be exceeded by the hydrostatic pressure of the packer fluid. The maximum depth for tubing collapse should be calculated (with a design factor of 1.125 ) for full evacuation. This depth shall not be exceeded with coiled tubing while nitrogen lifting.

3)

Differential Pressure of Packer If the test string continues to be unloaded with no inflow, the hydrostatic pressure of the packer fluid may exceed the rated differential pressure of the packer. The maximum depth for packer failure should also be calculated (assuming reservoir pressure of zero) with a full column of packer fluid. This depth shall not be exceeded with coiled tubing while nitrogen lifting.

4)

Coiled Tubing in Open Hole The use of coiled tubing and nitrogen should be limited to only lifting inside the test string. In barefoot tests, borehole stability below the casing shoe may be affected by the evacuation of the test string (no hydrostatic support on open hole section). Running in open hole with the coil is risking a costly fishing job and possibly the loss of the well. After evacuating of the entire test string, very little is to be gained by lifting in the open hole section.

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3.5

Killing Well The three basic methods of killing a well after a well test are shown below: A) B) C)

Bullheading the influx back into the formation. Utilizing coil tubing to circulate out the influx. Reverse-circulating out the influx.

The recommended kill method on high pressure gas wells is a combination of bullheading (when possible) and reverse circulating, as described below: 3.5.1

Bullheading At the conclusion of the test, the well should be opened to the flare pit to reduce wellhead pressure. After wellhead pressure is sufficiently reduced, kill fluid will be bullheaded down the test string and the influx will be squeezed back into the formation. If the well was shut-in down-hole during the last shut-in period, the tubing should be bleed-off and filled with kill fluid. The down-hole valve should be opened with annular pressure and influx squeezed into the formation.

3.5.2

Coiled Tubing If bullheading cannot be accomplished due to low permeability of the reservoir, coiled tubing will be required to circulate out the influx from below the packer with kill density packer fluid.

3.5.3

Reverse Circulating After the test string is dead, the reversing valve should be ruptured with annular pressure and reverse-circulated with kill density packer fluid. The well should be circulated and conditioned as required until the packer fluid density is uniform (in/out) and gas circulated out. In the case of a non-buttoned-up test, the packer by-pass could be opened and reverse circulated through the by-pass. The recommended kill method on low pressure wells (open hole tests) is reverse circulating though the impact sub, internal pump-out sub, or reversing valve. Bullheading is not an option as the inside diameters of the open hole test tools are small.

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4.0

TOOL CONFIGURATIONS

The test tool configurations commonly utilized by Saudi Aramco in well testing operations are summarized in the following illustrations. Individual test tool descriptions are not meant to be addressed in this chapter. This information is readily available from the Service Company providing the specific tools.

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4.1

7” Barefoot Test The barefoot test is generally performed on exploration wells with the casing set at the top of the zone of interest. In this case, the packer is set inside the 7” casing shoe and the entire open hole section is tested. 7” BAREFOOT DESCRIPTION

OD(in)

ID(in)

LENGTH(M)

HANDLING SUB SURFACE TEST TREE

2.560

PRESSURE BALANCED SWIVEL

2.680

STIFF JOINT

5.000

3.000

9.88

X-OVER 5 3/4-6STUB X 3 1/2"PH-6 P

5.000

3.000

1.07

3 1/2"PH-6 PUP JOINT

3.500

2.750

X-OVER 3 1/2"PH-6 B X 4 1/2-4STUB

4.400

2.250

1.07

SUPER SAFETY VALVE

8.000

3.000

6.64 0.87

X-OVER 4 1/2-4STUB X 3 1/2"PH-6 P

4.400

2.750

TUBING

3.500

2.750

X-OVER 3 1/2"PH-6 B X 3 7/8"CAS P

5.000

2.750

1.00

SLIP JOINT

(OPEN)

5.000

2.250

20.00

SLIP JOINT

(HALF OPEN)

5.000

2.250

17.50

SLIP JOINT

3 1/2"PH-6

(CLOSED)

5.000

2.250

15.00

X-OVER 3 7/8"CAS B X 3 1/2"IF P DRILL COLLAR 3 1/2" IF X-OVER 3 1/2"IF B X 3 7/8"CAS P

5.000 4.250 5.000

2.500 2.250 2.250

0.67 1.18

RD SAFETY CIRCULATING VALVE Operating Pressure 3500 psi +/-

5.000

2.250

2.250

X-OVER 3 7/8"CAS B X 3 1/2"IF P DRILL COLLAR 3 1/2" IF (3 JOINTS) X-OVER 3 1/2"IF B X 3 7/8"CAS P DRAIN VALVE

5.000 4.250 5.000 5.000

2.500 2.250 2.250 2.250

0.67 1.18 3.44

SELECT TESTER VALVE Operating Pressure 2500 psi +/-

5.000

2.250

23.88

DRAIN VALVE

5.000

2.250

3.44

T.S.T. VALVE

5.000

2.250

4.00

EXTERNAL GAUGE CARRIER

5.030

2.250

16.86

EXTERNAL GAUGE CARRIER X-OVER 3 7/8"CAS B X 3 1/2"IF P

5.030 5.000

2.250 2.250

16.86 1.18

BIG JOHN JARS

5.000

2.250

5.19

SAFETY JOINT

5.000

2.440

3.73

7" CHAMP PACKER

5.750

2.370

9.200

X-OVER 3 1/2"IF B X 3 1/2"PH-6 P TUBING 3 1/2"PH-6

4.810 3.500

2.750 2.750

0.75 30.32

MULE SHOE

3.500

2.750

2.50

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4.2

9-5/8” Barefoot Test The barefoot test is generally performed on exploration wells with the casing set at the top of the zone of interest. In this case, the packer is set inside the 9-5/8” casing shoe and the entire open hole section is tested.

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4.3

Micro Frac Test The micro frac test is similar to the barefoot test, as the casing is set at the top of the zone of interest, and the packer is set inside the casing shoe. The objective of the micro frac is to obtain rock strength data on the zone of interest, rather than reservoir productivity information

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4.4

Open Hole Test The open hole test is performed on a zone of interest after drilling or coring into the zone. The packer is set in the open hole and tail pipe on bottom. Open hole tests are limited by depth and hole stability.

OPEN HOLE

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4.5

Cased Hole Test The cased hole test is performed on a zone(s) of interest behind casing. The zone(s) is perforated using TCP or wireline guns and tested accordingly. 4.5.1 TCP (Halliburton)

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4.5.1

TCP Guns Detailed (Halliburton)

HALLIBURTON TOOL STRING SCHEMATIC TCP TOOLS APF

ACTUATOR

ANNULUS

ASSEMBLY

PRESSURE

FIRING

HEAD

MECHANICAL

FIRING

HEAD

TIME

DELAY

FIRING

HEAD

MECHANICAL

TUBING

RELEASE

PORTED

B.I.T.

DETONATION TCP

SUB

INITIATOR

SUB

GUN

PERFORATED

PUP

PERFORATED

TAIL

BAR

DROP

BAR

CATCHER

BLANK

JOINT PIPE

DEVICE SUB

SPACER

CROSSOVER TUBING PORTED

BULL

PLUG

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4.5.1

TCP (Schlumberger)

7” CASING TCP Schlumberger T o o l S trin g

D e s c rip tio n

O .D .(" )

I.D .(" )

B ox.

P in .

L e n g th .

1 0 .0 0

C h ris tm a s T re e C o n tro l H ead

****

3 .0 8

****

4 1 /2 IF

T u b in g H a n g e r

6 .2 5

2 .2 5

****

3 1 /2 P H 6

1 .9 7

3 1 /2 " P H 6 T u b in g J o in t

4 .3 1

2 .7 5

3 1 /2 P H 6

3 1 /2 P H 6

3 0 0 .0 0

S u b S u rfa c e S a fe ty V a lv e

8 .0 0

2 .5 0

3 1 /2 P H 6

3 1 /2 P H 6

1 1 .2 8

3 1 /2 " P H 6 T u b in g S trin g .

4 .3 1

2 .7 5

3 1 /2 P H 6

3 1 /2 P H 6

1 4 3 7 2 .0 0

X - O v e r.

5 .0 0

2 .2 5

3 1 /2 P H 6

3 1 /2 IF

1 .0 0

S lip - J o in t ( O p e n )

5 .0 0

2 .2 5

3 1 /2 IF

3 1 /2 IF

2 8 .2 5

S lip - J o in t ( 1 /2 O p e n )

5 .0 0

2 .2 5

3 1 /2 IF

3 1 /2 IF

2 5 .7 5

S lip - J o in t ( C lo s e d )

5 .0 0

2 .2 5

3 1 /2 IF

3 1 /2 IF

2 3 .2 5

1 8 J o in t 4 3 /4 " D rill C o lla rs .

4 .7 5

2 .2 5

3 1 /2 IF

3 1 /2 IF

5 4 0 .0 0

X - O v e r.

5 .0 0

2 .2 5

3 1 /2 IF

3 1 /2 P H 6

1 .0 0

R A M a rk e r S u b

4 .7 5

2 .2 5

3 1 /2 P H 6

3 1 /2 P H 6

1 .0 0

5 .0 0

2 .2 5

3 1 /2 P H 6

3 1 /2 P H 6

3 .0 0

S V P V

in g le a lv e um p a lv e

S h o t R e v e rs in g (S H R V ) T h ro u g h S a fe ty (P F S V )

5 .0 0

2 .2 5

3 1 /2 P H 6

3 1 /2 P H 6

5 .0 0

P re s s u re C o n tro l T e s te r V a lv e (P C T )

5 .0 0

2 .2 5

3 1 /2 P H 6

4 1 /2 " S A

1 6 .0 0

R e f e re n c e T o o l.( P O R T )

5 .0 0

2 .2 5

4 1 /2 " S A

3 1 /2 P H 6

4 .9 7

T u b in g F ill T e s te r V a lv e (T F T V )

5 .0 0

2 .2 5

3 1 /2 P H 6

3 1 /2 P H 6

5 .0 0

G a u g e C a rrie r. (R C A R )

5 .1 5

2 .2 5

3 1 /2 P H 6

3 1 /2 P H 6

1 5 .5 0

H y d ra u lic J a r -F

5 .0 0

2 .2 5

3 1 /2 P H 6

3 1 /2 P H 6

6 .0 0

S a f e ty J o in t.

5 .0 0

2 .2 5

3 1 /2 P H 6

3 1 /2 P H 6

2 .0 0

F le x P a c H o ld D o w n .

5 .7 5

2 .2 5

3 1 /2 P H 6

3 1 /2 P H 6

4 .5 0

5 .7 5

2 .2 5

3 1/ 2" PH 6

****

4 .5 0 4 .0 0

7" (A 7" (B

F le x bove F le x e lo w

Pac M id Pac M id

P acker E le m e n t) P acker E le m e n t)

3 .6 8

2 .2 5

****

2 7 /8 " E U E

X - O v e r.

4 .3 1

2 .7 5

2 7 /8 " E U E

3 1 /2 P H 6

1 .0 0

2 j o in t s 3 . 5 P H 6 Tu b in g

4 .3 1

2 .7 5

3 1 /2 P H 6

3 1 /2 P H 6

6 0 .0 0

X - O v e r.

4 .3 1

2 .7 5

3 1 /2 P H 6

2 7 /8 " E U E

1 .0 0

D e b r is S u b

3 .6 8

2 .4 4

2 7 /8 " E U E

2 7 /8 " E U E

1 .0 0

3 .6 8

2 .4 4

2 7 /8 " E U E

2 7 /8 " E U E

3 .0 0

SXAR

3 .6 8

2 .7 5

2 7 /8 " E U E

2 1/ 2" A PI

2 .0 0

Sa f e t y Sp a c e r 8 G u n s

2 .8 8

****

2 1/ 2" A PI

2 1/ 2" A PI

1 7 3 .1 2

2 .8 8

****

2 1/ 2" A PI

2 1/ 2" A PI

3 8 .0 0

2 .8 8

****

2 1/ 2" A PI

****

0 .5 0

2 .8 8

****

S .A .

****

0 .3 1

F ill S u b c / w

HD F

G u n s To p S h o t

G u n s Bo tto m Sh o t B u ln o s e

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4.5.2 Enerjet

(Wireline Perforating)

7” CASING DESCRIPTION

OD(in)

ID(in)

LENGTH(M)

HANDLING SUB

SURFACE TEST TREE

2.560

PRESSURE BALANCED SWIVEL

2.680

STIFF JOINT

5.000

3.000

9.88

X-OVER 5 3/4-6STUB X 3 1/2"PH-6 P

5.000

3.000

1.07

3 1/2"PH-6 PUP JOINT

3.500

2.750

X-OVER 3 1/2"PH-6 B X 4 1/2-4STUB

4.400

2.250

1.07

SUPER SAFETY VALVE

8.000

3.000

6.64 0.87

X-OVER 4 1/2-4STUB X 3 1/2"PH-6 P

4.400

2.750

TUBING

3.500

2.750

3 1/2"PH-6

X-OVER 3 1/2"PH-6 B X 3 7/8"CAS P

5.000

2.750

1.00

SLIP JOINT

(OPEN)

5.000

2.250

20.00

SLIP JOINT

(HALF OPEN)

5.000

2.250

17.50

SLIP JOINT

(CLOSED)

5.000

2.250

15.00

X-OVER 3 7/8"CAS B X 3 1/2"IF P DRILL COLLAR 3 1/2" IF X-OVER 3 1/2"IF B X 3 7/8"CAS P

5.000 4.250 5.000

2.500 2.250 2.250

0.67 1.18

RD SAFETY CIRCULATING VALVE Operating Pressure 3500 psi +/-

5.000

2.250

2.250

X-OVER 3 7/8"CAS B X 3 1/2"IF P DRILL COLLAR 3 1/2" IF (3 JOINTS) X-OVER 3 1/2"IF B X 3 7/8"CAS P DRAIN VALVE

5.000 4.250 5.000 5.000

2.500 2.250 2.250 2.250

0.67 1.18 3.44

SELECT TESTER VALVE Operating Pressure 2500 psi +/-

5.000

2.250

23.88

DRAIN VALVE

5.000

2.250

3.44

T.S.T. VALVE

5.000

2.250

4.00

EXTERNAL GAUGE CARRIER

5.030

2.250

16.86

EXTERNAL GAUGE CARRIER

5.030

2.250

16.86

X-OVER 3 7/8"CAS B X 3 1/2"IF P

5.000

2.250

1.18

BIG JOHN JARS

5.000

2.250

5.19

SAFETY JOINT

5.000

2.440

3.73

7" CHAMP PACKER

5.750

2.370

9.200

X-OVER 3 1/2"IF B X 3 1/2"PH-6 P TUBING 3 1/2"PH-6

4.810 3.500

2.750 2.750

0.75 30.32

MULE SHOE

3.500

2.750

2.50

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FISHING TOOLS 1.0

INTRODUCTION TO DOWNHOLE FISHING

2.0

TYPES OF FISHING TOOLS 2.1 Overshot 2.1.1 Releasing Overshot 2.2 Spears 2.2.1 Releasing Spear 2.2.2 Wireline Spears 2.3 Safety Joints 2.3.1 Drill Pipe Safety Joint 2.3.2 Washover Safety Joint 2.4 Fishing Bumper Sub 2.5 Fishing Jars 2.6 Jar Intensifier 2.7 Surface Jars 2.8 Impression Blocks 2.9 Die Collars 2.10 Taper Tap 2.11 Junk Baskets 2.11.1 Core-Type Junk Basket 2.11.2 Reverse Circulation Junk Basket 2.12 Fishing Magnets 2.13 Cutters 2.13.1 Jet Cut 2.12.2 Chemical Cut 2.13.3 Mechanical Cut A) K-Mill B) Internal Casing Cutter C) External Pipe Cutter 2.14 Junk Subs 2.15 Keyseat Wiper or Reamer 2.16 Washover Pipe & Accessories 2.17 Free Point Instrument and Pipe Back-Off 2.18 Casing Scrapers 2.19 Swages and Casing Rollers

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FISHING TOOLS 1.0

INTRODUCTION TO DOWNHOLE FISHING The word fish describes any undesired object in the well bore that must be removed. The equipment required to clean out the hole or to remove an unwanted object is called a fishing tool. When a fishing job develops, all drilling progress ceases and tools and procedures must be utilized to remove the fish. Failure to recover the fish can require redrilling or even abandoning the well. The costs and inherent risks when fishing make it imperative that the operations and engineering personnel involved communicate freely. Predicted additional cost and risk in certain types of fishing operations may make it necessary to change the whole job plan and objective. A) B) C) D) E)

Factors that should be considered when planning a fishing job are: The mechanical condition of the wellbore tubulars and the fluids or solids that they contain. Knowledge of the size, amount, and type of fish (all dimensions are important). Location of the fish. Predicted cost, probability of success, and risks of failure.

One of the most common types of fishing jobs is created when the drilling string parts or is twisted in two. By carefully measuring the pipe that has been removed from the hole, the operator knows the depth at which he must engage the fish. By carefully examining the end piece brought from the hole, the operator can determine if the fish is a drill collar, a tool joint, an external upset section or plain pipe. Although the outside diameters are generally known, it is good practice to caliper the drill collar, the nearest tool joint to the fish, and the drill pipe at the lowermost end to ascertain whether or not the pipe, tool joints or drill collars have been worn to a smaller size than their original outside diameter. The size of the hole being drilled at the time of failure will provide information regarding the amount of room that is available to accommodate the required fishing tool or tools. The first requirement will be to select a suitable tool to engage the fish. If there is sufficient operating clearance, the fishing tool selected should be one that will engage the fish externally. If there is not sufficient clearance to externally catch the tool an internal catching tool should be used.

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For relatively simple, straightforward fishing jobs such as the recovery of pipe inadvertently dropped or left in the hole, an overshot can be used for fast, inexpensive recovery. For a more complicated job-such as recovery of stuck, cemented, or plasticized pipe, or recovery of several wireline tools with the wireline on top of them-special fishing tools and skills will be required. When cases such as these arise, an experienced fishing-tool operator should be considered.

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2.0

TYPES OF FISHING TOOLS 2.1

Overshots 2.1.1

Releasing Overshot

The Releasing Overshot is used to externally engage and retrieve all sizes of tubing, drill pipe, and casing. The overshot is designed to assure positive external engagement over a large area of the fish and is ruggedly built to withstand severe jarring and pulling strains without damage or distortion to either tool or fish. Most overshots consist of a bowl, top sub, guide and the grapple or slip, a control, and packoff. The overshot bowl is turned with a taper on a helical spiral internally and then the grapple, which is turned with an identical spiral and taper, is fitted to it. Overshots are very versatile and may be fitted for a variety of problems. Mill controls may be used to dress the area that the grapple will catch in order to remove burrs and splinters on the pipe. When the pipe has been "shot off" or parted in such a way to heavily damage it, it may be necessary to fit a mill extension, or mill guide, to the overshot bowl so that extensive milling can be accomplished for the catch to be made on the same trip in the hole. These extensions, or guides, are "dressed" inside with tungsten carbide and can mill off a substantial amount of material so that the "fish" is trimmed down to the grapple size.

Top Sub

Packer

Bowl Spiral Grapple Grapple Control

Guide

Controls may also be designed with a pack-off, or packer, that seals off around the fish and allows the circulating fluid to be pumped through the fish to aid in freeing the stuck fish.

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To properly engage an overshot on a fish, slowly rotate the overshot as it is lowered onto the fish. The pump may be engaged to help clean the fish and also to indicate when the overshot goes over the object. Once this has been indicated by an increase in pump pressure, stop the pump, as there may be a tendency to kick the overshot off the fish. Set the grapple with gradually increasing light upward blows. An excessively hard upward impact may strip the grapple off the fish and cause the wickers to be dulled, resulting in a misrun and trip to replace the grapple. To release overshots, it is first necessary to free the two tapered surfaces, bowl, and grapple, from each other. This freeing of the grapple or "shucking" can be accomplished by jarring down with the fishing string. Usually a bumper sub is run just above the overshot and is used for this purpose. After bumping down on the overshot the grapple is usually free and the overshot can be rotated to the right and released from the fish. If a large amount of the fish has been swallowed, it may be necessary to free or " shuck" the grapple more than once. 2.1.2

Bowen Series 150 Circulating and Releasing Overshots The following is a complete list of the Saudi Aramco Releasing Overshot inventory: OD 2-5/8” 3-3/8” 3-5/8” 3-3/4” 5-5/8” 5-5/8” 5-3/4” 5-7/8” 7-5/8” 7-5/8” 7-3/4” 8-1/8” 8-1/8” 8-3/8” 11-1/4 11-3/4 12-3/4 13-3/4

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TYPE S.H. S.H. X.S.H. S.H. S.H. F.S. F.S. S.H. S.H. S.F.S. S.F.S. F.S. S.H. S.H. F.S. F.S F.S. F.S.

GRAPPLE No. B-10204 B-5091 9272 37591 B-2201 1135 6112 B-4369 9863 1644 5503 B-2374 9222 C-5354 B-12827 5334 15803 33009

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2.1.2

Bowen Series 70 Short Catch Overshots The following is a complete list of the Saudi Aramco Short Catch Overshot inventory: OD 3-3/4” 4-1/8” 5-5/8” 5-7/8” 7-5/8” 7-7/8” 9-3/4” 11-1/4”

2.2

TYPE S.H. S.H. F.S. S.H. F.S. F.S. F.S. F.S.

GRAPPLE No. 13538 10437 11300 10563 11633 16978 20063 33881

Spears 2.2.1

Releasing Spear

The Releasing Spear is used to internally engage and to retrieve all sizes of tubing, drill pipe, and casing as opposed to overshots which catch on the outside. It is designed to assure positive internal engagement with the fish and is ruggedly built to withstand severe jarring and pulling strains without distorting the fish. Mandr el

Usually a spear is not the first choice, as the spear will have a smaller internal bore than an overshot which limits running of some tools and instruments through it for cutting, free-pointing, and in some cases, backing-off. Spears, however, are popular for use in pulling liners, picking up parted or stuck casing, or fishing any pipe that has become enlarged when parted due to explosive shots, fatigue, or splintering. The most popular spears in use today are built on the same principles as overshots with a tapered helix on the mandrel and a matching surface on the inside of the grapple. The slip or gripping surface is on the outside surface of the spear so that it will catch and grip the inside of the pipe that is being fished. Due to the design with the small bore in the mandrel, spears are usually very strong.

Gr apple

Release Ring

Nut

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The spear is run inside the fish and positioned. The slips are released by action of the J-slot by using left-hand torque, moving the drill string down a short distance, and then picking it back up slowly. This action releases the slips so they can slide up over a taper on the body of the spear, as the spear is moved uphole. The slips move outward engaging the inner wall of the fish. In order to release a spear, it is rotated to the right. If the grapple is frozen to the mandrel, it may be necessary to bump down to free or 'shuck' the grapple. Usually a bumper sub is run just above the spear and this can be used to effectively jar down and free the grapple. The spear is a very versatile tool, in that it can be run in the string above an internal cutting tool if desired or in combination with other tools. Milling tools may be run below the spear to open up the pipe so that the spear can enter and catch the fish.

The following is a complete list of the Saudi Aramco Releasing Spear inventory: A)

Bowen ITC) Releasing Spear 1.660” Shoulder Mandrel Spear Assy. No. 11195 2-7/8” Shoulder Mandrel Spear Assy. No. 17231 3-1/2” Shoulder Mandrel Spear Assy. No. 9410 4-1/2” Flush Mandrel Spear Assy. No. 17475 5” Flush Mandrel Spear Assy. No. 9680 7” Flush Mandrel Spear Assy. No. 9266 8-5/8” Shoulder Mandrel Spear Assy. No. 9380 9-5/8” Shoulder Mandrel Spear Assy. No. 17246

B)

Tri-State Releasing Spear 4-1/2” Casing Pack-Off Tools 7” Casing Pack-Off Tools 9-5/8” Casing Pack-Off Tools

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2.2.2

Wireline Spears

One of the most challenging of fishing operations may be the recovery of wireline and the tools or instruments run with it. Often times wireline has been parted. When this occurs, wireline slumps down the hole in a coil. The wireline center spear or the twopronged wire grab, shown at left, is used frequently to remove parted wireline from the wellbore. TWO-PRONGED WIRELINE GRAB

When the tools are used in casing, a guide should be run above the tool to prevent the wire from getting above the spear.

WIRELINE CENTER SPEAR

Crankshaft Wireline Spear

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2.3

Safety Joints 2.3.1

Drill Pipe Safety Joint

The Safety Joint is a two-piece special connection that can be located at any desired point in a string of pipe. It will withstand all of the normal operation of the string, transmit full torque in either direction or, at the will of the operator, it can be easily released to salvage all of that portions of the string above it. Made up at any desired point in a drilling, fishing, testing, wash-over or tubing string, the Safety Joint operates as a unit unaffected by vibration, inertia of the bit or drill collars, or while rotating out of the well. No movement can occur between the two sections of the Safety Joint nor can it be released without a specific mechanical procedure. When the need arises, it is simple to release and to reengage. A Safety joint is used in a drilling, fishing, testing, wash-over or tubing string whenever and wherever a releasing safety connection is considered to be desirable In Drilling Strings, the Safety Joint is usually located far enough above the drill collars to prevent compression loading and to avoid sticky or heaving formation. Drill pipe Safety Joints have drill pipe box and pin connections with the O.D. and I.D. corresponding to the drill pipe tool joints. The Safety Joint consists of an upper Pin Section, a lower Box Section and two Packers. The upper Pin Section has a box connection up for connecting to the tool joint and abroad helical male thread down for connection to the Box Section. The Box Section has a broad helical female thread matching

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the male thread of the Pin Section and has a tool joint pin connection down for connecting to the pipe. The broad helical matching threads of the Pin and Box Sections allow speed and ease of engagement since they are relatively free of contact as the two sections are made up. However when the Safety Joint is bade up tightly, the reversely pitched surfaces of the joining shoulders grip each other securely, pulling the mating helical surfaces into complete contact and therefore form the Safety Joint into a rigid unit. The Pin Section is grooved at the top and bottom to accommodate the “O” ring type Top and Bottom Packers which seal the Safety Joint from both internal and external fluid pressures. Both Packers are rated for highpressure operation, capable of withstanding in excess of 10,000 psi in continuous service. 2.3.2

Washover Safety Joint

The washover safety joint is used in connecting drill pipe to your washover string. It provides a dependable means of releasing the drill pipe from the washover pipe if the washover string becomes stuck. The lower half of the washover safety joint remains with the washpipe when parted and is full bore to match the washpipe, making subsequent re-entry of other tools possible. A coarse pitch safety thread, in combination with the friction ring, assures proper release when required. Washover safety joints are made from heat -treated alloy steel and are stronger than the pipe that they are designed to run on. The safety joint should be made up properly in the string. This is done by making up the lower half into the washpipe. Make up the top half into the lower half with the same torque as applied to the washpipe connections. To release the safety joint, bump down sharply on the safety joint with drill string while holding a safe, left hand torque. Raise the string slowly while maintaining

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torque. The upper half will unscrew from the lower half, and the friction ring will remain with the retrieved upper half. To re-engage the joint, carefully feel for contact with the lower half, then apply a small amount of weight. Make one revolution to the left, then turn slowly to the right, while maintaining the small amount of weight. An increase in torque will signify that the joint has made up. 2.4

Fishing Bumper Sub To make up a proper fishing string, it is very important that a Bumper Sub be included as one of the components. There are numerous other applications where a Bumper Sub is a required item, such as when drilling in sticking or heaving formations. In these cases the ability to deliver downward blows is necessary to keep the string from sticking. The Fishing Bumper Sub is an inexpensive device designed primarily for use in a fishing string. Under normal conditions, its use is not prolonged over a considerable period of time. Fishing Bumper Subs are installed on fishing strings immediately above the fishing tool or safety joint. Its presence in the string assures the operator of the ability to release the fishing tool in the event it becomes impossible to pull the fish. This device will deliver the sharp downward blow and transmit the torque that is required to break the fishing tool’s engagement and releases it from the fish.

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2.5

Fishing Jars Jars are impact tools used to strike heavy blows either up or down upon a fish that is stuck. Jars fall into two categories as to use: drilling jars and fishing jars. Jars can further be classified as to the basic principle of operation; either hydraulic or mechanical. Most jarring strings used in conjunction with fishing operations consist of hydraulic "Oil" jars. Oil Jars are very effective in freeing stuck fish as the energy stored in the stretched drill pipe or tubing is converted to an impact force, which can be varied according to the pull exerted on the string. The oil jar is designed to strike a blow upward only, while an additional tool; the bumper sub is designed to strike a blow downward on the fish. The oil jar consists of a mandrel and piston operating within a hydraulic cylinder. When the oil jar is in the closed position, the piston is in the down position in the cylinder where it provides a very tight fit and restricts the movement of the piston within the cylinder. The piston is fitted with a set of packing which slows the passage of oil from the upper chamber to the lower chamber of the cylinder when the mandrel is pulled by picking up on the work string at surface. About half way through the stroke, the piston reaches an enlarged section of the cylinder and is no longer restricted so the piston moves up very quickly and strikes the mandrel body. The intensity of this impact can be varied by the amount of strain taken on the work string. This variable impact is the main advantage of the oil jar over the mechanical jar for fishing.

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2.6

Jar Intensifier The Jar Intensifier is perhaps one of the most outstanding devices designed to aid in the successful completion of difficult fishing jobs. The tool is designed to become a component part of a fishing string and to work in conjunction with a Hydraulic Jar to positively insure that the jarring blows are concentrated at the stuck point. The restraining mechanism in a Hydraulic Jar (an expansion joint with a limited longitudinal stroke) permits the buildup of extreme energy in the drill pipe and the ability to suddenly release the energy to drive a mass of weight upwardly to strike a heavy jarring blow. The mass of weight is composed of those drill collars which are installed above the Jar. The energy which has been built up in the stretched drill pipe is often partially dissipated by hole friction, crooked holes, etc. If the tremendous energy stored in the drill pipe can be concentrated at a point close to where the fish is stuck and released in a forceful manner at that point, the net result of the jarring effort is greatly increased. Therefore, the Jar Intensifier is installed immediately above the drill collars. The design of an effective tool of this type is possible because of the development of a good compressible fluid and the unique and extremely effective Seal Ring Assembly similar to that used in the Hydraulic Rotary Jar. The Intensifier is essential in shallow holes when there is insufficient pipe to achieve the necessary stretch to strike a blow.

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2.7

Surface Jars Jars are tools designed to deliver frequent and hammer-like blows to drive a fish toward the surface. The Surface Jar is designed to deliver a heavy downward blow against a stuck fish. The tool performs outstanding service in areas where keyseating is a problem. It is virtually impossible to pull large diameter drill collars up through keyseats; therefore, the solution lies in being able to drive them back down into the open hole. The tool is unusual in that to strike downward blows, the operator actually pulls upward against the tool. The Surface Jars, in fact, reverses the direction of force that is obtained from a Rotary Jar used in a downhole jarring operation. A point of difference between the Surface Jar and a conventional rotary jar lies in the fact that the Surface Jar has a long 48” stroke. In a jarring operation, when the tool trips, the energy that has been built up and stored in the drill pipe creates a force that travels away from the point of release. Since a Surface Jar is installed at the surface, the drill pipe below is stretched and when the Jar trips, the stretched drill pipe will move rapidly to regain its original length. Because the stretched drill pipe is below the Jar, the force will travel in a downward direction, resulting in the weight of the drill pipe being hammered downward against the stuck fish. In this reverse action, it is not necessary that two striking surfaces meet and ordinarily this would never occur unless there was a very great length of pipe between the surface and the stuck point. The purpose of the 48” stroke in a Surface Jar is to permit the drill string to fall heavily against the stuck point. The short stroke in a conventional rotary jar makes it ineffective in a Surface Jar application. The tripping tonnage of the Surface Jar is adjustable, but it should be set so that the pull necessary to trip it does not exceed the weight of the drill pipe between the surface and the stuck point. This is necessary to avoid pulling a stuck drill collar further into a keyseat. Repeating the jarring operations several times normally knocks the drill collars out of the keyseat. Also, a single blow usually is ample to cause the release of a fishing tool when the Surface Jar is used to provide the downward blow required to cause effective disengagement from a fish.

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2.8

Impression Blocks Impression Blocks, which consist of a soft lead insert in the lower end of a steel housing, are used in fishing operations. They are designed to enable the operator to determine the configuration of the top of the fish and to locate its position in the well bore. Its use enables the operator to more precisely assess the fishing conditions and to more accurately select the proper tool or tools needed to successfully complete the fishing operations. The Impression Block is lowered into the well on the lower end of a fishing string of pipe. After the Block contacts the upper end of the fish, the weight of the string is further lowered straight down (never rotate) against the fish which indents into the soft lead lower end of the Block. When the fishing string is withdrawn from the well, the impression in the lead will reveal the condition of the fish.

Impression Block with Transporting Cap

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2.9

Die Collars Rotary Die Collars are the most economical external catch tools for freeing stuck fish. The shallowtapered, hardened teeth provide excellent engagement. Die Collars are available with plain or lipped bottom or threaded bottom for attaching a lipped guide. The principal advantage of a Die Collar is that it is inexpensive and that it requires virtually no maintenance. The disadvantage of a Die Collar lies in the fact that it cannot be disengaged from the fish in the event that it proves impossible to pull the fish. Furthermore, it is difficult to gauge the amount of torque required for its operation. Insufficient torque results in an insecure hold; too much torque can result in distortion of the fish and damage the tool to such an extent that engagement is lost. Operating Procedure - Tag fish and pick up approximately 2 feet. Rotate slowly while lowering the pipe. (Rotate to the LEFT for left-hand taper tap or die collar; rotate to the RIGHT for right-hand taper tap or die collar). When rotary torque indicates that fish has been engaged, release the torque slowly. Do not allow the pipe to spin freely or fishing tool may back off and disengage from fish. Proceed with recovery operations. Die Collar

Lip Guide

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2.10 Taper Tap The Taper Tap is used to engage a tubular fish internally. This tool screws into the fish and cuts threads as it goes. Cutting new threads is a more positive engagement than attempting simply to screw on or into existing threads on a fish that may be damaged, misaligned, or incomplete. New threads can also be cut on blank pipe. Frequently, the Taper Tap is used to retrieve a production packer after the slip segments and packer elements have been milled with conventional mills.

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2.11 Junk Baskets 2.11.1 Core-Type Junk Basket The Core-Type Junk Basket, as shown, was the old stand-by for years for fishing bit cones and similar junk from the open hole. It consists of the top sub, a barrel, a shoe, and usually two sets of fingertype catchers. This tool is still used quite often, and it is made to circulate out the fill and to cut a core in the formation. The two sets of fingers help to break the core off and retrieve it. Any junk that is in the bottom of the hole is retrieved on top of the core.

2.11.2 Reverse Circulation Junk Basket The reversing action is extremely helpful in lifting junk into the barrel and catcher that might otherwise be held away from the catcher by fluid flow. The reverse circulation junk basket design incorporates an inner barrel with the fluid flow between the outer and inner barrels when a ball is dropped and closes off the center flow through the seat. With this design, when the ball is circulated down, the flow is diverted between the two barrels and reverse circulation flow is created back up the inside of the junk catcher with the fluid exiting into the annulus through the upper ports near the top of the barrel.

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2.12 Fishing Magnets Fishing magnets are either permanent magnets fitted into a body with circulating ports or electromagnets which are run on a conductor line. Permanent magnets, as shown, have circulating ports around the outer edge so that fill and cuttings can be washed away and contact made with the fish. Ordinarily the magnetic core is fitted with a brass sleeve between it and the outer body so that all of the magnetic field is contained and there is no drag on the pipe or casing. Permanent magnets have the advantage of the circulation washing away any fill so that the junk is exposed. Ordinarily, by rotation, one can detect when contact is made with the fish. The operator should then thoroughly circulate the hole, shut the pump off, and retrieve the fish without rotation

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2.13 Cutters 2.13.1 Jet Cut A cut made by an explosive shaped with a concave face and formed in a circle. It is also run and fired on an electric line. For details, see Chapter 5, section D. 2.13.2 Chemical Cut An electric wireline tool and procedure that uses a propellant and a chemical, halogen fluoride, to burn a series of holes in the pipe thereby weakening it so that it easily pulls apart with a slight pull. This method of cutting pipe is the most recent innovation. It was patented and for years was an exclusive process of one wireline company. Today it is available through most electric wireline service companies for practically all sizes of tubing and drill pipe and most popular sizes of casing. All wireline cuts are generally economical because rig time is reduced to a minimum. The big advantage of the chemical cut is that there is no flare, burr, or swelling of the pipe that is cut. Therefore, no dressing of the cut is necessary in order to catch it on the outside with an overshot or on the inside with a spear. The chemical cutting tool consists of a body having a series of chemical flow jets spaced around the lower part of the tool. The tool contains a propellant which forces the chemical reactant through the jets under high pressure and at high temperature to react with the metal of the pipe. Electric current ignites the propellant which forces the chemical, halogen fluoride or bromide trifluoride, through the reaction section which heats the chemical and forces it out the jets. The tool also contains pressure-actuated slips to prevent a vertical movement of the tool up the hole and insure a successful cut. The chemical cutting tool may also be explained as producing a series of perforations around the periphery of the pipe. The reaction of the chemical produces harmless salts which do not damage adjacent casing. The products of the chemical reaction are harmless and are rapidly dissipated in the well fluid. The chemical cutter will not operate successfully in dry pipe and requires at least one hundred feet of fluid above the tool when a cut is made. Since it is not necessary to apply torque to the pipe when chemically cutting as compared with the string shot back-off, it is a safer process for rig personnel. 19 of 29

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Chemi cal Cut t er

Pipe cut wi th a Chemical Cutter .

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2.13.3 Mechanical Cut A)

K-Mill

The K-Mill is a hydraulically actuated tool used to mill a section in casing or tubing. The K-Mill is a simple design, easy to operate, and has an outstanding reputation for milling performance. The Milling knives are dressed with tungsten carbide. The Mill is effective for milling casing, which is poorly cemented, split or corroded. Upon circulation through the tool, a pressure drop is created across the piston. This forces the cam down and expands the cutter knives into contact with the casing. Cut-out knives part the casing then all the knives participate in milling. When circulation is stopped, the piston spring will lift the piston, making the cam withdraw from between the knives. The knives are now free to collapse back into the body and the tool can be retrieved. The tool’s cutting action is very effective with 100’ sections possible with one set of knives.

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B)

Internal Casing Cutter

Stuck casing can be cut internally with a casing cutter for sizes 1-1/2” up to 20-3/4”. They may be run on macaroni strings, tubing or drill pipe. The Internal Consists of Wiper Block or Drag Spring assembly to accomplish setting the tool in the pipe that is to be cut A) B) C)

D)

Slips and Cone assembly to anchor the tool Main spring to assist in maintaining uniform feed to the Knives Wedge-like Knife Blocks to drive the Knives upward and outward into contact with the pipe Hardened and ground Knives for easy and efficient cutting

An outstanding feature of the Internal Cutter is the automatic bottom. This feature permits the operator to set the Cutter at any desired depth, without coming out of the hole. When the cutter reaches a point were a cut is to be made, lowering and rotation to the right unscrews the Mandrel from the Grip Jaw while friction is maintained by the Wiper Blocks against the inside of the pipe. With a wedging action, the cone expands the Slips to engage the Knife Blocks then force the Knives outward, continuing until the cut has been completed. When the string is raised, the Slips are disengaged, the Knives retract, and the cutter returns automatically to its run-in position.

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C)

External Pipe Cutter

The Hydraulic External Cutters are hydraulically actuated mechanical tubing and drill pipe cutters. The cutters are fast, smooth cutting, efficient, and are capable of cutting and recovering stings of tubing or drill pipe. The Cutter Knives are fed entirely by pump pressure, thus giving the operator sensitive control. To operate, assemble the cutter using the proper size and type of Piston Assembly. Run the cutter into the hole to cutting depth. When cutting depth is reached, open the fill-up and standpipe valves just enough to shear the shear pins. Begin slow rotation, 15 to 25 RPM. Slowly close the bypass valve again to pump fluid down the working string. This will begin feeding the knives to start the cut. The amount of pressure and gallons per minute required depends on the size cutter and piston assembly being used. Use extreme caution to avoid surging or pump pressure when starting a cut. Pressure surging causes the string length to contract and expand, moving the cutter up and down. This motion prevents the knives from remaining in one position when starting a cut. A rough chattering action followed by the smoothing of the rotary will signal the completion of the cut.

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2.14 Junk Subs Junk Subs, which are normally run just above the drill bit, have a cup for catching objects too heavy to be completely circulated out of the hole. This is particularly advantageous in junk milling operations, By running a Junk Sub above the scraper, operators can get quicker, cleaner scraping jobs. Junk Subs are constructed from high quality steel, completely stress-relieved after cup and rib guides have been welded to the main body. Rib guides prevent the Cup from becoming crushed and help guide the tool through tight places upon withdrawal from the hole. There are three main types of Junk Subs, as follows: •

•

•

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Boot Type normally run just above the drill bit, utilizing a cup for catching objects too heavy to be completely circulated out of the hole such as cuttings from milling operations. The boot basket is available in a complete range of sizes from 2 1/4" to 18" and larger, with API Reg. connections. Finger Type utilizes free-spinning finger type catchers to retrieve all types of small objects in the wellbore. Used with a variety of mill shoes to mill over and retrieve objects. Available in sizes from 3 3/4" to 20" OD. Reverse Circulating Type the principle of reverse circulation ensures complete recovery of junk in the wellbore. Available in a "full flow" design which permits circulation through the center of the tool while running in the hole. The tool is available in sizes from 3 3/4" to 20" OD.

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2.15 Keyseat Wiper or Reamer One of the major causes of fishing is keyseating. A keyseat is a section of hole where a smaller hole is cut into the wall of the well bore by the movement of the downhole drilling assembly. It usually occurs where the hole changes direction. A section of the downhole drilling assembly can get wedged into the keyseat. Keyseats almost always can be detected in time to take preventive action before the pipe sticks. Proper prevention means observing the signs that a keyseat is developing and immediately eliminate it. The Keyseat Wiper or Reamer, which consists of a mandrel and sleeve with spiraling Tungsten Carbide strips, is located in the string immediately above the drill collars. The Sleeve is slightly larger in diameter than the drill collars. After locating the keyseat, the Wiper or Reamer is raised to engage it. The tool is then rotated causing the Tungsten Carbide strips to cut clearance for the drill collars. During drilling operations, the sleeve remains engaged with the Positive Clutch and rotates with the drill pipe. Should the sleeve become stuck and impossible to rotate, an Overriding Clutch at the upper end will produce a downward blow to assist in dislodging the Sleeve

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2.16 Washover Pipe & Accessories Very often it is not enough merely to catch hold of the fish and pull. In those cases, washpipe and a rotary shoe can be used to rotate over the fish to remove annular material that may be causing it to stick and free up a section of stuck pipe so that it may be retrieved. The outside diameter of the washpipe must be small enough to run inside the casing, and its inside diameter must be large enough to fit over the fish. Washpipe is therefore thin walled and the length of it run in the well must normally be limited to a few hundred feet. The rotary shoe is placed on the end of the washpipe to drill-up and circulate out any material around the fish.

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Washover Pipe

Casing

Tubing Fish

Rotary Shoe

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2.17 Free Point Instrument and Pipe Back-off The most common method of parting a downhole assembly is backing it off. The procedure includes the following steps: A) B)

C) D)

Running a free-point indicator to determine the free point. Placing left hand torque in the drill pipe downhole assembly and working it down to the point to be baked off Running a string shot across the depth to be backed off and detonating Rotating the pipe until it is backed off and pulled out of hole.

For detailed step-by-step procedures of Pipe Back-off, see Chapter 5, Section D of this manual.

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2.18 Casing Scrapers Casing Scrapers are used for all types of scraping operations. They wil remove cement, mud cakes and asphaltines, as well as perforation burrs and similar obstructions. The Scraper is simple and rugged. It employs hardened steel blades, set in a pattern, which provides 360 degrees of coverage three times, in its working length. No springs, screws or other small parts are used in these tools which could get damage or lost during operations. The tool may be either rotated during operation or spudded up or down with equal effectiveness. Full circulation may be maintained at all times through the tool, although circulation is not required for its operation. The tool allows it to easily enter liners down-hole or re-enter the bottom of the liner, should it pass through the bottom.

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2.19 Swages and Casing Rollers Casing swages are heavily tapered cones which can be driven through the collapse and jarred back out. It is usually necessary to run several sizes in sequence, as the pipe must be swaged out in small increments, sometimes as little as ¼ inch. Most collapsed casing can be swaged out to approximately 1/8 of an inch below the drift diameter. Casing rollers were first made as adaptations of the swage mandrel by merely adding a series of rollers. It is a simple tool for restoring buckled, collapsed or dented casing to its normal diameter and roundness. The tool is rotated slowly and lowered gradually through the casing until the damaged area is located. Upon contact with the collapsed casing, the rotary speed is increased to between 50 and 75 rpm, circulation is established and the roller lowered slowly. The operation of swaging or rolling is rather sever. One should always run the jars and drill collars in either procedure since they can become wedged in the collapsed pipe and must be jarred loose. Once the casing is opened sufficiently, it is usually squeeze cemented or an inner liner run to support the weak casing.

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MILLING 1.0

DOWNHOLE MILLING SUMMARY

2.0

GENERAL DESCRIPTION OF HARDFACING 2.1 Uses of Hardfacing 2.2 Hardfaced Milling Shoes and Rotary Shoes

3.0

OPERATION OF MILLING SHOES AND ROTARY SHOES

4.0

MILLING TOOLS 4.1 Use of Milling Tools 4.2 Recommended Weights and Speeds 4.3 Cuttings 4.4 Mill Stability and Rough Operation

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MILLING 1.0

DOWNHOLE MILLING SUMMARY “Milling” means to cut, grind, pulverize, or break down metal into smaller particles. These particles are then circulated up the annulus. Mills are used to cut objects that either fall into the hole or get stuck and require removal from the hole or can mill away entire casing sections. Mills are normally built with high quality tungsten carbide called hardfacing.

2.0

GENERAL DESCRIPTION OF HARDFACING Hardfacing material is composed of crushed sintered tungsten carbide particles compounded with a matrix of nickel-silver alloy. Hardfacing is applied with oxygen acetylene welding equipment. During milling operations, when a hardfaced tool is lowered and rotated against an object, a fish, formation or cement, small tungsten carbide particles imbed themselves into the object. Each tungsten carbide particle creates a small chip along the edge as it is moved along the object, cutting the object. As a particle’s cutting edge becomes dulled, pressures and strains increase causing the particle to fracture and fall off. Such fractures then create a new cutting structure. Once the particle falls off, a new particle in the matrix takes its place as the cutting edge. This process continues until all the hardfacing is exhausted. The hardness of tungsten carbide is almost that of diamonds. It retains its hardness at high temperatures and is not affected by the heat generated by cutting operations. The resilient nickel-silver alloy matrix securely holds the tungsten carbide particles together and in place and cushions the particles against impact forces. Hardfacing is made in two types, cutting type and wear type. 2.1

Uses of Hardfacing Cutting type tungsten carbide hardfacing is used as the cutting surface in mill shoes, rotary shoes, junk mills, and milling stabilizer construction. Tools dressed with hardfacing are used to mill away all kinds of junk including drill pipe, drill collars, bit cones, casing, liners, and liner hangers. Wear type is used for wear resistance on stabilizers, roller reamer bodies and hole opener saddles and bodies.

2.2

Hardfaced Milling Shoes and Rotary Shoes Milling shoes and rotary shoes can be designed in various sizes and styles to meet various conditions encountered in well fishing and washover operations. 1 of 21

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Following are examples of mill shoes, and Type A through K rotary shoes, with a brief explanation of their intended applications. Note: When ordering out mill shoes and rotary shoes specify the type from Saudi Aramco Drilling Manual, or Bowen, or Servco, etc. Different manuals describe Types A, B, C, etc. differently so be sure and specify which model is required and which reference the source originated.

Overshot Milling Shoe

Overshot milling shoes are used to mill away jagged metal from the top of fish so that the fish will pass easily into an overshot bowl.

Packer Retrieving Milling Shoe

Packer retrieving milling shoes are used to mill away the slips of a production packer without damage to the casing so that the remainder of the packer can be retrieved. When planning packer milling, specific information must be known concerning packer size, packer type, casing size and weight.

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Junk Basket Milling Shoes

Junk basket milling shoes are used to capture and trap junk too heavy to circulate and mill away jagged edges from small junk or bit cones so that the junk will pass into the basket and be retrieved, or for formation cutting to cut small cores.

Type A Rotary Shoe

Type A rotary shoes are used to cut metal on the fish without cutting casing. It cuts only on the inside diameter (I.D.) and the bottom, does not cut on the outside diameter (O.D.). It can be used with washpipe when washing over drillpipe and tubing.

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Type B Rotary Shoe

Type B rotary shoes are used for washing over a fish and metal and formation in the open hole. It cuts only on the outside diameter (O.D.) and the bottom, and does not cut on the inside diameter (I.D.).

Type C Rotary Shoe

Type C rotary shoes are used for washing over and cutting metal, formation or cement. It cuts freely only on the inside diameter (I.D.) the outside diameter and the bottom. 4 of 21

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Type D Rotary Shoe

Type D rotary shoes are used to cut metal on the fish without cutting the casing where clearances are limited. It cuts only on the inside diameter (I.D.) and the bottom, and does not cut on the outside diameter (O.D.).

Type E Rotary Shoe

Type E rotary shoes are used for washing over a fish and cutting metal, formation or cement in the open hole casing where clearances are limited. It cuts only on the outside diameter (O.D.) and the bottom, and does not cut on the inside diameter (I.D.).

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Type F Rotary Shoe

Type F rotary shoes are used to size and dress the top of a fish inside the casing. It makes a tapered cut on the inside diameter (I.D.) and cuts on the bottom, and does not cut on the outside diameter (O.D.).

Type G Rotary Shoe

Type G rotary shoes are used for washing over and cutting metal, formation or cement in the open hole casing with limited inside clearances. It cuts on the outside diameter (O.D.), the bottom, and on the inside diameter (I.D.).

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Type H Rotary Shoe

Type H rotary shoes are used for washing over and cutting metal in the open hole casing where clearances are limited. It cuts on the outside diameter (O.D.), the inside diameter (I.D.), and on the bottom.

Type I Rotary Shoe

Type I rotary shoes are used for washing over and cutting formation only. Saw toothed design permits maximum circulation. It cuts on the bottom only. Does not cut on the outside diameter (O.D.) or the inside diameter (I.D.).

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Type J Rotary Shoe

Type J rotary shoes are used for washing over and cutting formation only. Saw toothed design permits maximum circulation. It cuts on the bottom and on the outside diameter (O.D.). Does not cut the inside diameter (I.D.).

Type K Rotary Shoe

Type K rotary shoes are used for washing over and cutting on the bottom face only. Does not cut on the outside diameter (O.D.) or the inside diameter (I.D.).

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3.0

OPERATION OF MILLING SHOES AND ROTARY SHOES Milling shoes are used to mill over and free stuck packers, spears, stabilizers, string reamers, rock bits or any metal objects which cannot be removed from the well by conventional fishing methods. Milling shoes and rotary shoes are used primarily to dress a fish so that grappling or a retrieving tool may engage the fish. Rotary shoes are excellent for washing over stuck pipe to cut away shales, clay, sand salt or limestone, cement, anhydrite, red beds and other formations. Prior to milling always inspect the ID of subs to insure they are full-bore. While milling, the penetration rate is affected by the hole condition, the rotary speed, the weight of the drill string upon the milling shoe, the weight and viscosity of the drilling fluid, the dimensional size of the milling shoe, and finally the size and hardness of the material to be milled. Based on all of these variables, the optimum weight and RPM cannot be stated to obtain the most efficient penetration rate. Therefore the most efficient weight and RPM must be determined by actual operating conditions. Revolutions may vary from 75 to 150 RPM. Washover or milling operations should begin at a moderate speed and low weight, increasing both until the desired or optimum penetration rate is attained. Lower the washover string into the well until the mill shoe is a few feet above the top of the fish. Begin the pumps and circulate the hole until the top of the fish is clean. Either conventional or reverse circulation can be used. Reverse circulation is often desired because the velocity of the returns is greater and less settling of cuttings will take place. Normal pump pressures are recommended with the mud weight and viscosity being sufficient to circulate the cuttings out of the hole. If many metal cuttings are anticipated, a ditch magnet or other method of surface cutting removal should be considered to prevent damage to surface equipment like pumps. The volume and characteristics of the returned cuttings should be checked frequently since they will provide valuable information on what is being cut and the washover procedure. In the event that penetration rate declines, it is advisable to change the weight or the rotary speed and in some cases spudding on the fish might become necessary to reestablish the desired rate of progress.

4.0

MILLING TOOLS

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Milling tools are designed to mill away a stuck fish that cannot be retrieved by conventional fishing methods. Since milling is usually a follow-up operation (after several fishing attempts), the fish to be milled should be familiar to the operator and therefore the selection of the milling tool should be relatively easy to determine, since the dimensional restrictions of the well should be known. The milling tool selected should provide maximum exposure of the milling edge to the material to be milled, maximum replacement of the milling edge as wear occurs and maximum circulation to remove the cuttings. 4.1

Use of Milling Tools Most milling tools are simple to operate. Relatively fast rotary speeds should be available as well as drill pipe and drill collars. Rotary speeds may vary from 60 to 175 RPM. Higher rotary speeds are used with smaller diameter mills and slower RPM with larger mills. Rotary speeds are best determined in the field during operations, being dependent on the size and the type of mill, hole conditions and depth, and the material to be milled. For maximum results, the mill should be run beneath a string of drill collars weighing anywhere between 10,000 and 15,000 lbs., depending on the size of the mill. Weight applied to the mill during operations like RPM, will vary due to the size and type of mill, hole condition and depth, and material to be milled. The volume and characteristics of the cutting should be checked frequently since they will provide a great deal of information about the milling progress. Best results are achieved with high volume pumps since high circulation rates will both flush and cool the milling surfaces and circulate the metal cuttings more efficiently to the surface. Annular velocity should be maintained at 80 to 120 ft. per minute. The mud weight and viscosity should be adequate to lift the metal cuttings to the surface. Oil base mud should be avoided whenever possible. Ordinarily, no difficulty is encountered in circulating drilled cuttings under normal drilling practices. Milled cuttings are much heavier than normal drilled formation cuttings, therefore a ratio of plastic viscosity to yield point (PV/YP) as close to 1.0 is ideal for steel cutting removal. If the ratio is higher than 1.5, a common remedy is to add LCM to the mud. This will help to sweep the hole and aid in carrying the cuttings up the annulus and out of the well. Polymer muds are best for milling operations with clay based muds being a second choice and oil base mud being third. A ditch magnet or other method of surface metal cutting removal should be considered to prevent damage to surface equipment when the metal cuttings become excessive. If the cutting cannot be brought to the surface with the circulating system being used, then boot or junk baskets should be run just above the mill or drill collars to catch the cuttings.

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Milling operations begin by lowering the drill string down to within a few feet of the object to be milled. Start the pumps and circulate to remove any debris that might have fallen on top of the fish. Rotate at a moderate speed and slowly lower the drill string until the mill makes contact with the object to be milled. The first 30 minutes should determine how fast the penetration rate will be. The first 4 to 5 ft. of a milling job are extremely critical, especially during section milling. Cuttings tend to accumulate at the cutting knife. This can cause bird nesting. Slowly increase the RPM and gradually increase the weight until an optimum penetration rate is achieved. Too much weight will merely grind down the carbide and matrix and prematurely dull the mill. Never mill faster than it is possible to remove cuttings. If bird nesting occurs, pull up and circulate until proper cutting return is achieved. The following are some examples of milling tools,

Junk Mill

A)

Junk mills are used to mill away metal objects in the hole that cannot be retrieved with grappling tools or junk baskets. These mills are the toughest mills and referred to as workhorses of downhole milling operations. The blade forms of all junk baskets are designed so that they hold the junk in place to be milled under the milling face. Therefore the mill continuously cuts rather than sweeping the junk ahead of the blades. The junk mills selected should be 1/8 to ¼ in. less than the minimum inside diameter of the casing or open hole through which it is 11 of 21

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to be run. Run a junk sub directly above the mill. Have a minimum of 10,000 lbs. of drill collar weight available. Frequent spudding may be required to break up loose junk, this action will pound the junk down into the bottom, positioning it better for effective milling. Never allow a piece of junk to lodge next to the mill. Force it down by spudding the mill. A noticeable increase in torque will indicate that junk is alongside. B)

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Special Design Junk Mill Aramco and Weatherford have designed an 8 bladed junk mill with a 3-deg. lay back on the cutters and a ½ in. offset nose from the center (in the 12-in. size). This mill has proven very reliable when milling up drillpipe. It can be used with a skirt on the outside to protect the casing when milling drillpipe inside casing. See pictures below.

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Round Nose Mill

Round nose mills are used primarily to mill out the bottom of liners or casing which have been set with a bull plug during original completion. Round nose mills cut on the leading edge or nose, along the taper but not full circumference of the mill.

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Taper Mill

Taper mills are used primarily to mill collapsed pipe, to restore elliptical pipe to full bore, and to remove restrictions from the inside diameter such as landing seats, bushings, and other metal objects that might restrict the well bore. Taper mills have cutting structures along the taper.

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Flat Bottom Mill

Flat bottom mills are used to mill bits cones and other pieces of junk if they cannot be recovered by other means of recovery. Flat bottom mills normally have a concave face on the bottom to keep the junk centered under the mill.

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Watermelon Mills or String Mills

Watermelon mills or string mills are used to open up tight spots in pipe, to enlarge and clean up a window cut in casing, or in some circumstances, to run in collapsed casing that has been partially opened up. With a guide below the mill, it will not go outside as is possible with a tapered mill.

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Piranha Mills

Piranha mills are used solely for the removal of downhole casing strings. The effecting milling weight has been found to be 5,000-10,000 lbs. with Piranha mills. Stabilization is necessary with this mill. A sleeve type stabilizer is included in the tool’s design. The OD and stabilizer diameter is sized to prevent damage to the outer casing strings. Refer to the mill handbook for further details.

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Pilot Mills

Pilot mills are used primarily to mill up wash pipe, safety joints, crossover swages, drill pipe, casing, liners and washover shoes in the hole. The stinger can be equipped with a retrieving tool on the bottom. In selecting a pilot mill, the blade OD should be about 1/4 in. larger than the OD of the tool joint or coupling to be milled. The pilot OD should be about the same as the drift diameter of the tubular.

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Section or K-Mills

Section or K-mills are hydraulically actuated tools that are used to mill a section of casing or tubing. Circulation through the tool creates a pressure drop across the piston. This forces a cam down, expanding the knives into contact with the casing. Cut out knives part the casing then all knives are used to mill. When circulation is stopped, the piston spring will lift the piston, 19 of 21

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withdrawing the cam from between the knives. The knives are now free to collapse back into the body and the tool can be retrieved. It is important to insure that the mill completely cuts through the casing (cutting out) so the blades can be firmly seated on casing while milling. If you experience a sudden drop off of penetration rate of the mill, this may be attributed to a loose ring of steel from the casing coupling. This ring will rotate with the section mill. Lightly spudding the section mill should break up the ring. Pump rates for the K-Mill are pre-determined and depend on the tool size, refer to a Servco handbook for the required flow rates for different K-Mill sizes. The correct GPM must be selected to produce the desired pressure drop through the K-Mill providing efficient tool operation. The most common cause of difficulty in cutting out is insufficient pressure at the tool. Approximately 300 psi is required to keep the cutting knives open and part the casing. 4.2

Recommended Weights and Speeds Usually the most efficient rotary speeds are obtained by running the rotary at 80 to 100 RPM. Milling with washover shoes is an exception, they are usually more efficient when run at 60 to 80 RPM. High speed can burn or damage the tungsten carbide, which is critical to milling steel. Tungsten carbide cuts steel best at 3000 to 4000 surface inches per minute. The following formula determines the recommended rule of thumb minimum and maximum milling RPM’s, MIN/MAX RPM = Surface Speed/(Tool OD x 3.14)

For example, for a 12 in. mill, Min RPM = 3,000/(12 x 3.14) = 80 RPM Max RPM = 4,000/(12 x 3.14) = 106 RPM

For optimum penetration rates, it will be necessary to try different rotary speeds, weights, and pump pressures. When the penetration rate slows down varying one or more of the above variables might be required to attain the desired penetration rate. Occasionally spudding on the fish might help. If the penetration rate cannot be increased to what it should be by varying

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some of the above mentioned variables or by light spudding, the mill might need to be pulled out of the hole because the hardfacing might be worn off. 4.3

Cuttings Ideally cuttings should be 1/32 to 1/16 in. thick ands 1” to 2” long. If cuttings are long thin stringers, increase the milling weight. If fish scale type cuttings are being returned when pilot or section milling, the penetration rates will improve by decreasing weight and increasing RPM.

4.4

Mill Stability and Rough Operation A mill that moves eccentrically does a poor job. Stabilize above the mill at 60 ft. or 90 ft. intervals. The stabilizer OD should not exceed the dressed OD of the mill. Section and pilot mills should also be stabilized to the drift diameter of the casing. When rough running and bouncing occurs, decrease weight, then slowly increase speed and weight until an acceptable ROP is obtained. If rough running reoccurs, once again decrease and then gradually increase to a maximum ROP.

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June 2006

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TRAINING REQUIREMENTS

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TRAINING REQUIREMENTS 1.0

HYDROGEN SULFIDE

2.0

WELL CONTROL

3.0

CRANES AND HEAVY EQUIPMENT

4.0

OFFSHORE SURVIVAL

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Drilling & Workover Engineering Department CHAPTER 8 SECTION

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June 2006

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TRAINING REQUIREMENTS

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TRAINING REQUIREMENTS 1.0

HYDROGEN SULFIDE 1.1

Upon reporting to any rig, all persons must receive basic H2S training from the H2S safety service contractor assigned to that rig OR provide proof (i.e. a valid & current training card) that they have already received this orientation.

1.2

The H2S safety service contractor will conduct basic H2S training as required to ensure that the training standards listed below are met.

1.3

All basic H2S training will include the actual donning and breathing from each different type of breathing apparatus in use on that particular rig. Each person must be able to don and breathe from the breathing apparatus within 45 seconds.

1.4

A training card will be issued to each person completing the basic H2S training. This card will remain valid for 2 years, following which the person must retake the basic H2S training.

1.5

All personnel on all rigs must be capable of the following:

1.6

1.5.1

Don & breath from breathing apparatus within 45 seconds.

1.5.2

Identify the H2S alarm.

1.5.3

Identify wind direction.

1.5.4

Evacuate to the upwind safe briefing area immediately upon hearing the H2S alarm (on land rigs).

1.5.5

Muster to the Safe Briefing Area (onshore) or their boat station (offshore), and enter/fasten seat belts in their assigned boat while wearing both their PFD and breathing apparatus.

In addition to the basic skills listed above, anyone whose duties include working on the rig package must be fully competent perform the tasks assigned to them by to the rig’s H2S emergency plan.

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2.0

1.7

All drilling contractor rig crew must be able to perform mouth-to-mouth resuscitation. (Mouth-to-mouth resuscitation is the basic lifesaving technique to revive someone who has succumbed to H2S poisoning. Therefore, it is critically important that each rig have an adequate number of people trained in this technique.)

1.8

The Drilling Foreman is responsible to verify that H2S training requirements are met. This will be done by observing H2S drills, and by random testing to verify competence in breathing apparatus use.

WELL CONTROL 2.1

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Anyone assigned to the following positions must have a current well control certificate meeting IWCF requirements: 2.1.1

Assistant Driller

2.1.2

Driller

2.1.3

Toolpusher (or Rig Manager, or any other senior contractor supervisor)

2.1.4

Drilling Foreman

2.1.5

Drilling Engineer

2.2

The drilling contractor is responsible to ensure that all drilling crew are fully competent in the tasks assigned to them by the rig’s well control plans (e.g. BOP drill duties).

2.3

The Drilling Foreman is responsible to verify that well control training requirements are met. This will be done by the following: 2.3.1

Maintaining copies of current well control training certificates in the rig’s training file.

2.3.2

Observing BOP drills.

2.3.3

Randomly questioning the drillcrew to verify their understanding of their role in BOP drill and well killing procedure.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 8 SECTION

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June 2006

HEALTH, SAFETY & ENVIRONMENTAL ISSUES

TRAINING REQUIREMENTS

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3.0

4.0

CRANES & HEAVY EQUIPMENT 3.1

All crane and heavy equipment operators shall have a valid Saudi Aramco operator certificate as per G.I. 7.025 requirements.

3.2

The drilling contractor is responsible to ensure that all crane and heavy equipment operators have valid certificates, by arranging for testing with the Saudi Aramco Vehicle & Heavy Equipment Training & Testing Unit (Tel. 8741857).

3.3

The Drilling Foreman is responsible to verify that crane and heavy equipment operators have valid Saudi Aramco operator certificates by maintaining copies of current certificates in the rig’s training file.

3.4

The Drilling Foreman is responsible to ensure that no one operates cranes or heavy equipment without a valid Saudi Aramco operator certificate.

OFFSHORE SURVIVAL CRAFT & HELICOPTER SAFETY All Saudi Aramco employees working offshore on a regular basis shall complete the Saudi Aramco Survival Craft and Helicopter Safety training programs offered by N.A. Job Skills Satellite Training Unit.

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June 2006

HEALTH, SAFETY &ENVIRONMENTAL ISSUES

RIG SAFETY INSPECTIONS & MEETINGS

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RIG SAFETY INSPECTIONS & MEETINGS 1.0

PHYSICAL CONDITIONS INSPECTIONS

2.0

SPECIALIZED INSPECTIONS 2.1 Rig Accommodations, Camp, and Kitchen 2.2 Crane & Hoisting Equipment Inspections 2.3 Marine Inspections

3.0

SERVICE COMPANY INSPECTIONS

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 8 SECTION

B

June 2006

HEALTH, SAFETY & ENVIRONMENTAL ISSUES

RIG SAFETY INSPECTIONS & MEETINGS

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RIG SAFETY INSPECTIONS & MEETINGS 1.0

2.0

PHYSICAL CONDITIONS INSPECTIONS 1.1

The Drilling Foreman is responsible to verify that the rig complies with Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations.

1.2

Drilling Superintendents will verify compliance by conducting Quarterly Safety Inspections (QSI) on each rig in their Division. Loss prevention shall also be invited to participate in each QSI.

1.3

Drilling Foremen are encouraged to submit their comments to Drilling management with respect to improving Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations, by identifying omissions, recommending new policy, etc.

SPECIALIZED INSPECTIONS 2.1

Rig Accommodations, Camp, and Kitchen 2.1.1

The appropriate Environmental Health Unit (EHU) of the Preventive Medicine Services Division will conduct an inspection of every rig camp once per quarter.

2.1.2

The Drilling Foreman is responsible to contact the appropriate Environmental Health Unit to arrange the camp inspection: Northern Area EHU.................. Tel: 678-4868, 678-4914 ................ Fax: 678-4910 Central Area EHU .................... Tel: 877-8426, 877-8371 ................... Fax: 877-8444 Southern Area EHU ................. Tel: 572-2076, 574-6796 ................ Fax: 572-2220

2.1.3

Following the EHU inspection and report, the Drilling Foreman will follow up with the Toolpusher or Camp Boss to ensure corrective actions are taken to comply with EHU requirements.

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RIG SAFETY INSPECTIONS & MEETINGS

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2.1.4 2.1.5

2.2

2.3

3.0

Copies of EHU camp inspection reports will be kept on file at the rig for 2 years. Drilling Superintendents will verify compliance by reviewing EHU inspection documentation during rig Quarterly Safety Inspections.

Crane & Hoisting Equipment Inspections 2.2.1

The Crane Inspection Unit shall inspect all hoisting equipment on each rig as per G.I. 7.027 requirements.

2.2.2

The Drilling Foreman is responsible to contact the appropriate Crane Inspection Unit office to arrange for crane inspection.

2.2.3

No hoisting equipment shall be operated on a drilling rig without a valid crane inspection certificate.

2.2.4

Drilling Superintendents will verify compliance by reviewing crane inspection documentation during rig Quarterly Safety Inspections.

Marine Inspections 2.3.1

The specialized marine equipment (e.g. life boats) shall be inspected by a representative of the Saudi Aramco Marine department once per quarter.

2.3.2

The Drilling Foreman is responsible to contact the Marine Department to arrange for the inspection.

2.3.3

Drilling Superintendents will verify compliance by reviewing Marine inspection documentation during rig Quarterly Safety Inspections.

SERVICE COMPANY INSPECTION The Drilling Foreman is responsible to ensure all service company equipment meets Saudi Aramco standards before work begins. Specific requirements for the various services will be found in the sections of this manual dealing with each activity, e.g. coring, testing, etc.

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H2S CONTINGENCY PLAN

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H2S CONTINGENCY PLAN 1.0

INTRODUCTION AND PURPOSE OF PLAN

2.0

PREPLANNING, PRIOR TO SPUD 2.1

3.0

AFTER SPUDDING THE WELL, PRIOR TO COMPLIANCE DEPTH 3.1 3.2 3.3

4.0

Coring Well Testing Well Control Lost Circulation Stuck Pipe Highly Deviated and Horizontal Wells

ATTACHMENTS (FOR A SITE SPECIFIC PLAN) 6.1

6.2 6.3

7.0

Level 0: [H2S] = 0, Normal Operations in Potential H2S Zones Level 1: 0 < [H2S] < 10 ppm, Acceptable amount of H2S is present Level 2: 10 < [H2S] < 100 ppm, Anywhere but on the drill floor Level 3: 10< [H2S] < 100 ppm, On the drill floor H2S Emergency, [H2S] > 100 ppm H2S Orientation Requirements

SPECIAL OPERATIONS 5.1 5.2 5.3 5.4 5.5 5.6

6.0

Training Safety Equipment BOPE, Surface Equipment & Downhole Tools

OPERATIONAL CONDITIONS (ALERT LEVELS) AFTER COMPLIANCE DEPTH 4.1 4.2 4.3 4.4 4.5 4.6

5.0

Responsibilities

Well Coordinates, Expected H2S Zones and Potential Contact Points List 6.1.1 Exploration wells 6.1.2 Development wells Map Showing Potential Contact Points, Highways and Roads Rig Layout Showing Access Roads, Flare Pits, etc. Note: For an offshore rig, this would be drawings for each deck.

APPENDIX 7.1 7.2 7.3 7.4 7.5 7.6 7.7 7.8

Saudi Aramco Standard Safety Equipment for H2S Operations on all Onshore Drilling and Workover Rigs Safe Briefing Area Equipment List Typical H2S Drill Attachment for Offshore Wells Saudi Aramco Standard Safety Equipment for H2S Operations on all Offshore Drilling and Workover Rigs G. I. 1850.001, Onshore Contingency Plan (for emergencies and disasters) G. I. 1851, Offshore Contingency Plan (for emergencies and disasters) Physical Properties of H2S and Toxicity Table

SAUDI ARAMCO

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June 2006

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H2S CONTINGENCY PLAN

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H2S CONTINGENCY PLAN 1.0

INTRODUCTION AND PURPOSE OF PLAN This plan specifies precautionary measures, safety equipment, emergency procedures, responsibilities and duties pertaining to drilling where Hydrogen Sulfide (H2S) is known or suspected to be present. This includes preparations prior to drilling the well as well as preparations after spud, prior to drilling into the known or suspected H2S interval. These preparations either reduce the risk of an H2S incident or lessen the response time should an incident occur. It specifies what should be done during normal drilling and completion operations to reduce the risk of controlled or uncontrolled H2S release. It also defines the three types of releases as commonly accepted by the industry (Condition I, II and III), slightly modified to fit existing Saudi Aramco policy and how to respond to each. This plan was developed because of the potential hazards involved when drilling and completing in formations that contain Hydrogen Sulfide (H2S). Saudi Aramco’s priorities are the preservation and protection of human life first and foremost, with the rig and well having second priority. Every effort will be made to provide adequate safeguards against harm to persons both on location and in the vicinity from the effects of H2S. To be effective, this plan requires the cooperation and effort of each individual involved in drilling and completing the well. Each individual should know his responsibilities and duties in regard to normal operating procedures and emergency operating procedures. He should thoroughly understand and be able to use each type of breathing apparatus in use on the rig and any other safety equipment that he might be required to operate, monitor or service and know where each piece of equipment is stored. The ideas and suggestions of each individual involved in the drilling and completion of the well are highly welcomed and necessary for providing absolutely the safest working conditions possible.

2.0

PREPLANNING, PRIOR TO SPUD Special consideration should be given to the “Drilling Program” of a well that will drill through horizons that may contain H2S. It is beyond the scope of this contingency plan to go into detailed well planning. However, the Drilling Engineer should plan the well on the concept that any release of H2S is hazardous to human life, that the risk of such a release should be minimized and that an uncontrolled release is intolerable and should be avoided at all costs. Selection of the mud system and design of the casing (including selection of casing points) have the most obvious impact on this risk. 2.1 Responsibilities

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2.1.1

It shall be the responsibility of Exploration to advise Drilling and W/O Engineering of any anticipated H2S in the requirements letter for each exploration well. H2S zones are commonly known on a development well, but Reservoir Geology should make Drilling aware of anything that is out of the ordinary on a particular well.

2.1.2

Drilling and Workover Management will decide if a site-specific H2S plan is warranted. Proximity to the general public and to other Aramco facilities should be considered. Moving the location and drilling a directional well is an option at this point. All Exploration wells with anticipated H2S in an untested horizon with unknown pore pressure should have a site-specific plan. Development wells with manned facilities, residences etc., within a 5km radius and anticipated H2S should have a site-specific plan. H2S wells falling outside the above categories would be a judgement call. Under the generally accepted definition of an H2S well (capable of producing atmospheric concentrations of 20ppm or greater), even an Arab-D oil well would be considered an H2S well.

2.1.3

Once it is decided that a site-specific plan is warranted, it shall be the responsibility of the Drilling Engineer, with assistance from Facilities and Projects, to obtain the surveyed well location and prepare a list and map showing that location, distances and directions to all manned facilities and points of possible contact within a 5 km radius. This map should show all roads and highways.

2.1.4

A phone list will be compiled by the Drilling Engineer giving the contact phone numbers (a 24 hour contact for any facility that is not manned 24 hours per day) of any facilities near the location and the phone number of the nearest Saudi Aramco Industrial Security main gate. The phone list, location map, and H2S Contingency Plan should be attached to the Drilling Program and sent to each facility listed. The map and phone list should also be sent to Industrial Security, Loss Prevention and Government Affairs to assist them in carrying out their duties under GI’s 1850 and 1851, should an emergency be declared. The cover letter to each of the above with the map and phone list should give Drilling and Workover contact names and phone numbers and it should reference the above G. I. See G. I. 1850 and 1851 in Appendix.

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H2S CONTINGENCY PLAN

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3.0

2.1.5

It shall be the responsibility of Government Affairs to give advanced notice to the general public and prepare any evacuation plans if deemed necessary. They shall also be responsible for notifying any interested Saudi Arabian Government Authorities.

2.1.6

Drilling & W/O Operations (Supt. or Foreman) shall be responsible for surveying the rig to assure that tubulars, BOP’s, choke manifolds, degassers, flares lines etc. meet the requirements for H2S service set forth in the Aramco Well Control Manual. This will be especially critical if it is the first H2S well for the rig in question. Operations will also be responsible for assuring that the location is built to specifications for H2S wells and that the rig camp is the required 3km from the wellsite.

2.1.7

The “H2S Safety Representative” (whether a drilling contractor safety man, drilling contractor Toolpusher, Loss Prevention safety man, a second Saudi Aramco Drilling Foreman in charge of H2S safety, or a third party consulting H2S specialist) shall be responsible for inventorying all H2S Safety Equipment, repair or replacement as needed. As covered in the next section (“Prior to Compliance Depth”), he shall be a certified trainer and shall be responsible for conducting H2S training in safety, the use of breathing equipment, and competency drills. Regardless of who is the designated “H2S Safety Representative”, the Drilling Foreman is ultimately responsible for confirming that the training and drills have been properly carried out. See “Saudi Aramco Standard Safety Equipment for H2S Operations”, Appendix 1 (onshore) and 5 (offshore) and “Training Requirements” in Chapter IX, Section A, of this Drilling Manual.

AFTER SPUDDING THE WELL, PRIOR TO COMPLIANCE DEPTH Generally, with the exception of workovers, there will be some time prior to having to be in compliance under the H2S Contingency Plan in which to check all H2S safety equipment and prepare personnel. Compliance depth will usually be the last casing set prior to the anticipated H2S zone. On workovers (must be in compliance prior to nipple down of the tree) there will be less preparation time but generally this will be a much more controlled situation with only one zone open. Regardless, the same safety precautions should still be observed.

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3.1

3.2

Training 3.1.1

The “H2S Safety Representative” (as defined in Section I) will immediately begin training crews, ensuring that everyone on the rig site has received an H2S orientation and that it has been recorded in the training file.

3.1.2

Everyone on the rig site shall be trained in the proper response to H2S alarms. Drills should be held as often as deemed necessary by the Aramco Foreman and the “H2S Safety Representative” until satisfactory performance is obtained, then once per week per crew thereafter. These weekly drills will be documented in the IADC morning report book. See Appendix , “Typical H2S Drill”.

3.1.3

The Drilling Foreman will designate two safe-briefing areas such that at least one will always be upwind of the wellbore under prevailing wind conditions. The primary area will be near the Saudi Aramco/ Contractors offices (generally upwind). This upwind location will be a gathering point for the above drills.

3.1.4

Everyone who might work on or come in contact with the rig package shall be trained in breathing apparatus use and user inspection with a record kept in the training file. See “Training Requirements” in Chapter IX, Section A, of the Drilling Manual.

3.1.5

The Drilling Foreman will ensure that a sign is posted, notifying all visitors to report to the Aramco office to verify that they receive or already have H2S orientation. This must be documented as per item 1, above. The Foreman may delegate these duties, but he remains responsible.

3.1.6

Following H2S orientation, all visitors will be able to recognize the H2S alarm and will proceed to the upwind safe briefing area upon hearing the alarm. If a visitor is required to work on the rig package, he must also be able to properly don and use the breathing apparatus.

Safety Equipment 3.2.1

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The primary “Safe Briefing Area” will be near the Saudi Aramco and Drilling Contractors offices and should include the equipment listed in “Equipment Requirements” Appendix 2, “Safe Briefing Area Equipment List”. When not in use, this equipment may be stored in the adjacent offices, the Aramco Storehouse etc., as long as it is readily available.

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H2S CONTINGENCY PLAN

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3.3

3.2.2

During this time prior to compliance depth, the H2S Safety Representative should ensure that all safety equipment for H2S operations is in place as required by “Saudi Aramco Standard Safety Equipment for H2S Operations”, Appendix 1. Note that there is a separate list for Offshore Rigs in Appendix 4.

3.2.3

The Saudi Aramco Drilling Foreman with assistance from the H2S Safety Representative will ensure that sensors and warning devices listed in Appendix 1and 4, and referenced above, are rigged up and properly working prior to compliance depth. Occasionally, more stringent monitoring may be required, in which case the actual requirements should be included under Appendix 1, under a subheading of “Additional Monitoring Equipment and Warning Devices”.

BOP, Surface Equipment , Downhole Tools 3.3.1

The Saudi Aramco Drilling Foreman with assistance from the Toolpusher or senior contractor representative will inspect and insure that BOP and surface equipment meets the standards set forth in the “Saudi Aramco Well Control Manual” for H2S service (NACE Standard MR-01-75-96). This should be done well in advance of nipple-up so that changes can be made if necessary. This will be a second check since most equipment should have been checked out prior to spud.

3.3.2

The Drilling Foreman should verify that drill pipe and all downhole tools to be used below compliance depth are of metallurgy suitable for H2S service and order replacement equipment as needed. This will also be a second check. Attention should be given to any equipment that was not available during the pre-spud check.

3.3.3

The Drilling Foreman and wellsite mud engineer should confirm that an H2S Scavenger (zinc oxide or an equivalent scavenger) is available and sufficient quantity is on location to treat the entire mud system with 2 lb/bbl., or as required.

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H2S CONTINGENCY PLAN

____________________________________________________________________________________________________________

4.0

OPERATING CONDITIONS (ALERT LEVELS) AFTER COMPLIANCE DEPTH Since it is common to drill through zones containing H2S, it is normal and not necessarily hazardous to have small amounts of H2S (as drilled gas) released to the atmosphere as the mud returns come over the shale shaker. It is Drilling Operations policy to keep atmospheric H2S within a safe level by such methods as: • • •

Adding H2S scavenger Reducing ROP, or temporarily discontinuing drilling Reducing hole size (drilling a pilot hole)

However, the Drilling Foreman is responsible to take every practical precaution to maintain a safe working environment while these remedial actions are being taken to reduce the amount of H2S circulated to surface. This section outlines drilling operations when drilling through zones known or suspected to contain H2S. While drilling these zones, the rig will conduct operations based on the following classifications of H2S risk. Note: [H2S], using square brackets, refers to H2S concentration, usually measured in ppm (parts per million). Alert Level

H2S Concentration [H2S]

Comments

Level 0:

[H2S] = 0 ppm

Normal operations

Level 1:

0 ppm < [H2S] < 10 ppm

Normal operations, but increased alertness, preparing for next level. Restricted access to affected areas.

Level 2:

10 ppm < [H2S] < 100 ppm

Restricted access & breathing apparatus required in affected areas [H2S] > 10 ppm. Non-essential personal removed from rig package. Immediate action taken to reduce mud H2S levels.

(but not on drill floor)

First alarm at 10 ppm, high alarm at 20 ppm. Level 3:

H2S Emergency

4.1 6 of 41

10 ppm < [H2S] < 100 ppm (on the drill floor)

Approaching an emergency situation.

[H2S] > 100 ppm

Actions taken to reduce H2S concentrations have failed and an emergency situation has been reached. This is not necessarily an uncontrolled release but would include uncontrolled releases.

First alarm at 10 ppm, high alarm at 20 ppm.

Level 0: [H2S] = 0, Normal Operations in Potential H2S Zones

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H2S CONTINGENCY PLAN

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This is the base level, in effect immediately after drilling out casing above the suspected H2S formations. The following items shall be done even when no H2S has been detected: 4.1.1

All H2S detection equipment will be function tested daily and documented in the IADC book.

4.1.2

H2S detection equipment will be calibrated weekly and documented in the rig PM file.

4.1.3

All breathing apparatus will be ready for immediate use and in place as per contract specifications and Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations.

4.1.4

All breathing apparatus on the rig (SCBA & SABA) will be inspected weekly, documented in rig PM file. A quick release (e.g. string) tag is used to seal each container, and the inspection date and inspector initials are written on the tag.

4.1.5

Each stored breathing apparatus (i.e. not on the rig package) will be inspected and containers sealed with a quick release (e.g. string) tag. The inspection date and inspector initials are to be written on the tag. The tag/seal on stored breathing apparatus will be inspected monthly to ensure the container has not been opened. If tags are missing or disturbed, the stored apparatus will be re-inspected and re-tagged.

4.1.6

Supplied air (cascade) manifold gauges are checked for proper pressure and air lines checked for proper operation every tour (i.e. at every crew change). This is documented in the IADC book.

4.1.7

Windsocks are in place such that the wind direction can be readily identified from anywhere on the location.

4.1.8

All other safety equipment (e.g. bug blowers, etc.) is in place as specified by Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations, Appendix XX.

4.1.9

Two safe briefing areas have been marked out and identified and the entrance sign has been posted as specified in Section III.

4.1.10 The drills specified in Section III will continue a minimum of once per week per crew and will be documented in the IADC book. Orientation and training on breathing apparatus will continue so that new arrivals and visitors are covered. Following their H2S orientation, all visitors will be able to recognize the H2S alarm and will proceed to the upwind safe briefing area upon hearing the alarm. Note: If visitors are required to work on the rig package they must also be able to properly don and use breathing apparatus.

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4.2

Level 1: 0 < [H2S] < 10 ppm, Acceptable amount of H2S is present Level 1 begins whenever H2S is detected anywhere on the rig. Typically, this will be at the shale shaker, when safe concentrations (i.e. less than 10 ppm) of H2S are being released to the atmosphere. Although this is a safe H2S concentration, everyone must be alert to the fact that the H2S concentration could increase at any time. Upon reaching Level 1 conditions, the Drilling Foreman shall take the following actions.

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4.2.1

All of the previous H2S level precautions are already in place.

4.2.2

The area around the shale shaker and the rig cellar will be declared “restricted areas”. No one may approach these areas without the following: A)

Ready access to breathing apparatus,

B)

Continuous awareness of current H2S concentration (e.g. personal H2S monitor giving continuous readouts.

C)

Continuously observed by a stand-by man who also has immediate access to breathing apparatus (e.g. “buddy system”).

4.2.3

Appropriately rated (i.e. “explosion-proof”) bug blowers will be positioned to provide adequate ventilation to H2S contaminated areas and the rig floor.

4.2.4

The Toolpusher or designated “H2S Representative” (as defined in Section II) shall conduct an initial H2S safety meeting with each crew. H2S safety will be discussed at a brief tool-box safety meeting at every shift change.

4.2.5

The H2S concentration in the mud is checked a minimum of every 24 hours, more often at the Saudi Aramco Foreman’s discretion. The Garret Gas Train Kit will be used for this determination.

4.2.6

The Drilling Foreman shall identify possible courses of action to take should the H2S concentration increase to higher levels (e.g. reduce ROP, treat mud with H2S scavenger).

4.2.7

The Drilling Foreman shall take appropriate actions to maintain H2S levels below 10 ppm. The objective is to minimize the number of times the H2S alarms sound. (If the 10 ppm H2S alarm becomes excessive, it will contribute to complacency and lose its effect as a warning sign.)

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4.3

Level 2: 10 < [H2S] < 100 ppm anywhere but on the drill floor. Saudi Aramco policy requires breathing apparatus to be worn when working in an atmospheric H2S concentration higher than 10 ppm. Therefore, every practical precaution shall be taken to either reduce atmospheric H2S levels to less than 10 ppm, or to declare “off-limits” those areas with an atmospheric H2S concentration higher than 10 ppm. When drilling through H2S bearing zones, it is not uncommon to have H2S breaking out at the shale shaker as drilled gas. This can be addressed by treating the mud with scavenger, weighting up to increase overbalance and restricting access to the shaker area. The rate of penetration can be controlled or even halted until corrective measures have been taken. Upon reaching Level 2 conditions, the Drilling Foreman shall take the following actions. 4.3.1

Ensure that all of the previous H2S level precautions are already in place.

4.3.2

The rig crew shall respond to the low level (H2S >10 ppm) alarm with their H2S drill (as previously trained).

4.3.3

The Drilling Foreman, assisted by the Senior drilling contractor representative, shall identify the source of the H2S, and respond accordingly (As stated above, if the H2S release is confined to the shale shaker area only, this is not as critical a situation as [H2S] > 10 on the drill floor).

4.3.4

Hand-held H2S monitors shall be used to continuously measure atmospheric H2S concentrations.

4.3.5

The Drilling Foreman shall implement appropriate procedures to reduce atmospheric H2S levels in the affected areas (e.g. treat mud with H2S scavenger, increase overbalance, control ROP, increase ventilation to area, etc.).

4.3.6

The H2S concentration in the mud shall be checked every 4 hours or as directed by the Drilling Foremen. The Garret Gas Train Kit will be used for this determination.

4.3.7

Breathing apparatus must be worn when entering an area with atmospheric H2S concentration higher than 10 ppm. No one shall remain in an area with [H2S] >10 ppm unless their presence is absolutely necessary to regain a safe working environment

4.3.8

A strict “buddy system” shall be enforced throughout the rig package, and immediately downwind of the rig.

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4.3.9

The rig substructure, shale shaker area, and any other areas with H2S > 10 ppm shall be roped off and identified as a restricted area. No one shall enter these areas without specific Drilling Foreman approval.

4.3.10 If the Level 2 condition occurs only at the shale shaker, and only as a result of drilled gas, then after access to the shaker area has been restricted, the Drilling Foreman may, at his discretion, disable the low level (H2S >10 ppm) alarm in the shaker area only. Note: This may be done only to prevent repeated alarms during the time it takes to reduce the H2S concentration in the mud; and only if the H2S concentrations in the shaker area are continuously monitored by a competent person. 4.4. Level 3: 10< [H2S] < 100 ppm on the drill floor Since the drill floor is a critical work area and cannot be easily evacuated, H2S concentrations higher than 10 ppm are far more critical on the drill floor than in more remote areas of the rig. Upon reaching Level 3 conditions, the Drilling Foreman shall take the following actions.

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4.4.1

All of the previous H2S level precautions are already in place.

4.4.2

Upon initial low alarm (H2S > 10 ppm), everyone on the drill floor shall either evacuate or mask up as per established H2S drill.

4.4.3

No one shall remain on the drill floor unless their presence is absolutely necessary to regain a safe working environment.

4.4.4

An H2S monitor shall be placed on the drill floor to provide continuous atmospheric H2S concentrations.

4.4.5

Drilling shall stop and unless well conditions dictate against it, the well shall be immediately circulated bottoms-up. The Foreman shall use his discretion whether to circulate through the choke or through the shakers (taking into consideration the risk of stuck pipe).

4.4.6

The Drilling Foreman shall immediately implement appropriate procedures to reduce H2S concentration in the mud (e.g. treat mud with H2S scavenger, increase overbalance, increase ventilation, etc.).

4.4.7

Two men shall be placed at each entrance to the location to turn back non-essential personnel and to direct essential personnel to the appropriate safe briefing area. These teams shall be equipped with breathing apparatus and H2S monitors.

4.4.8

The Drilling Foreman shall discuss longer-term procedures to reduce H2S levels with his Superintendent and Drilling Engineering.

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4.4.9

4.5

Drilling shall not recommence until drill floor H2S levels have been reduced to less than 10 ppm, and adequate action has been taken to maintain safe H2S levels during subsequent drilling.

H2S Emergency, [H2S] > 100 ppm It is difficult to define an H2S emergency on the basis of the atmospheric concentration. For example, when drilling a large hole through a highly porous deep zone containing a relatively high concentration of H2S, the drilled gas breaking out at the shale shaker could easily exceed 100 ppm, although this does not necessarily constitute an emergency. An H2S emergency is defined as having lost the capability to control the amount of H2S being released at the wellsite. Under this condition, the Drilling Foreman must identify the problem and take immediate corrective action. The specific response will depend upon the specific problem. However, at the same time, the Drilling Foreman must implement the following precautions and work procedures to provide an adequate level of safety for the men working on the rig. 4.5.1

Immediately implement a strict “buddy system”. No one is to ever do anything alone. Everything is done in pairs.

4.5.2

As per the GI’s, the Drilling Foreman will notify the Drilling Superintendent of an emergency, and the Drilling Superintendent will decide whether or not to activate the (Disaster) Contingency Plan. Should the Drilling Superintendent decide to activate the Plan, he will notify the facilities identified in Attachment 1 & 2 of this plan and provide them with pertinent data. The Drilling Superintendent will also call the appropriate Saudi Aramco Industrial Security main gate and request security patrols be dispatched. See GI 1850.001 (2.4.1.2). See G.I.1851 for notification requirements on offshore wells.

4.5.3

Communicate to the Superintendent what outside resources the rig needs, or may need in the immediate future (e.g. gas monitors, gas monitoring teams, increased breathing apparatus re-fill capacity, mobile radios, walkie-talkie etc.). The Superintendent will contact the outside resources needed to assist the rig.

4.5.4

Establish a Command Post (CP), typically in the Drilling Foreman’s office, equipped with the following: • Telephone & radio. • Continuous contact with the Drilling Superintendent. • Flare gun and one box of flare gun shells.

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•

•

•

Fluorescent orange vest to identify the Command Post Commander. Walkie-talkies to communicate with the Safe Briefing Area and work parties throughout the rig. Continuously manned by either a Drilling Foreman, or a highly reliable, experienced and competent individual, plus at least 2 pairs of runners

4.5.5

Man the primary safe briefing area (SBA), typically near the Drilling Foreman’s office, equipped as specified in “Safe Briefing Area Equipment List”, Appendix 2.

4.5.6

Establish and mark off a “hot” zone, where H2S concentration is greater than 10 ppm. This is done by assigning pairs of individuals, masked up and equipped with a continuous H2S monitor, to measure H2S concentrations throughout the location.

4.5.7

Maintain at least one 2-man team to continuously check that the “hot” zone is adequately identified. (Winds can vary and change conditions rapidly).

4.5.8

Assign an individual to gather all vehicles and park them in a safe upwind location, parked facing their escape route, with the motor off and with the keys left in the ignition.

4.5.9

Alert the rig camp of the emergency, and to stand by for further instructions.

4.5.10 Organize small work teams of at least 2, but usually not more than 5 men. Assign one man as leader of every work team. (Under emergency conditions, it may be difficult for one man to directly supervise more than 4 people, hence the 5 person maximum.) •

•

• •

•

•

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All work is assigned to individual teams at the Safe Briefing Area. The Safe Briefing Area commander keeps a written log of all assigned tasks. Each work team is assigned one task and one task only. An “estimated time of completion” is identified for each assigned task. Each work team reports back to the Safe Briefing Area immediately upon completion of their assigned task. (This allows the Commander to be fully up-to-date on the progress being made.) If a work team has not completed their task by their “estimated time of completion”, they shall report back to the Safe Briefing Area (or send a pair of runners to report in).

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•

4.6

Each work team will have an individual to be assigned to check the air supply of all team members and to monitor H2S levels using a continuous monitor. This should be his primary responsibility: he should not be assigned other duties that could interfere with this vital safety function.

H2S Orientation Requirements The level of orientation or training required will vary, depending upon the role each individual is expected to take in the event of an H2S release.

Personnel Offshore: All personnel

Minimum H2S Training Requirement 1. Able to don & use breathing apparatus. 2. Able to identify H2S alarm. 3. Able to identify wind direction. 1. Able to muster to the Safe Briefing Area or their boat station, and enter and buckle-up in their assigned boat while wearing breathing apparatus.

Onshore: Occasional visitors: never (or very rarely) on the rig package

1. Able to identify H2S alarm.

Onshore: Visitors who may work on the rig package

1. Able to don & use breathing apparatus.

2. Able to identify wind direction. 3. Know to evacuate to the upwind safe briefing area immediately upon hearing the alarm.

2. Able to identify H2S alarm. 3. Able to identify wind direction. 4. Know to evacuate to the upwind safe briefing area immediately upon hearing the alarm.

Onshore: Rig crew

1. Able to don & use breathing apparatus. 2. Able to identify H2S alarm. 3. Able to identify wind direction. 4. Know how to perform the tasks assigned to them, according to the rig’s H2S Drill.

Also refer to “Training Requirements, H2S” in Chapter X, Section A of the drilling manual.

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5.0

SPECIAL OPERATIONS 5.1

Coring During drilling operations below compliance depth, it may be decided to core. This operation takes on critical complexities when attempted in an H2S bearing formation. The following practices should be followed during coring operations. 5.1.1

After start of coring operation, monitor first bottoms up for H2S. If coring rate indicates porosity has been cut, clear floor and shaker areas of unnecessary personnel and mask up remaining personnel at least 15 minutes prior to bottoms up.

5.1.2

After core has been cut, circulate bottoms up and monitor mud for H2S prior to pulling out of hole. If H2S levels do not return to normal (less than 10 ppm) consider additional circulating and increase of mud weight (if hole conditions allow).

5.1.3

When pulling out of hole, clear floor and shaker area of unnecessary personnel and have remaining personnel mask up 10 stands before core barrel reaches the surface or sooner if H2S level exceeds 10 ppm. Breathing equipment should be worn while the core barrel is broken out and the core is extracted and until portable H2S detectors indicate a safe atmosphere.

The following practices must be followed for every core barrel pulled.

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5.1.4

Due to the difficulty in communicating with breathing equipment on, it is required that a chalkboard or erasable communication board be available during the above mask up periods.

5.1.5

The importance of leaving the breathing equipment on must be stressed to all personnel involved in the coring operation. The most critical time is when the core is extracted.

5.1.6

All personnel not wearing breathing equipment should stay a safe distance upwind from the core barrel.

5.1.7

The containers holding cores containing H2S should be labeled as such and anyone transporting them should be made aware of the contents.

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5.2

Well Testing It may be required to test the well below compliance depth. The following will apply any time a test is done with a potential H2S zone open, regardless of whether the zone actually being tested contains H2S. Refer also to Chapter VI, (Well Testing) of this Manual, under H2S Precautions. 5.2.1

Prior to initiation of the test, special safety meetings must be conducted by the “H2S Safety Representative” for all personnel who will participate. This will require at least two meetings to include both crews. Special emphasis should be placed on use of personal safety equipment, evacuation to the “safe briefing area”, rescue operations and first-aid procedures.

5.2.2

The test should be conducted with the minimum number of personnel on the rig floor and in the vicinity of the lines and test equipment to safely conduct the test. Other personnel should be assigned duties in an upwind area away from the cellar, rig floor, lines and test equipment.

5.2.3

Downhole test tools and surface equipment should be suitable for H2S service and supplied by a reputable testing contractor. All items from the test head (or tree) to the choke manifold should be furnished by this tester if possible. Any items furnished by the drilling contractor or Aramco (such as chicksans, co-flex hose, valves, etc.) should be on an emergency basis only and the item must be checked for manufacturer, pressure rating, H2S rating, last date of service and last date of pressure test can be confirmed.

5.2.4

During the test, the use of H2S portable detection equipment will be intensified. All produced gases must be burned through a flare system equipped with a continuous pilot and an automatic igniter. At least one back-up ignition device must be provided. Produced fluids which are stored must also be vented to the flare pit. If well is within 5 km of a contact point, portable H2S monitoring must be done down wind of the flare pit in case the flare cannot be kept burning continuously. Two people, both masked up, should conduct this monitoring.

5.2.5

The main flare pit to the south will be rigged up with flow lines for testing. The test can be postponed or shut-in if unfavorable wind conditions develop. The second pit is for emergency well control operations only, when gas buster cannot handle pressure and/or volume or for diverting an uncontrolled flow.

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5.2.6

The testing of all wells should be initiated only during daylight hours.

5.2.7

Refer to the Table below for well testing details regarding expected H2S concentrations.

WELL TESTING

ABOVE JILH FORMATION

BELOW JILH FORMATION

Formation Pressure < 0.55 psi/ft

Formation Pressure > 0.55 psi/ft

Low Pressure Well

High Pressure

Expected

Expected

Expected

Oil or Water

Gas

Oil, Water or Gas

H2S ≤ 5%

H2S ≤ 10%

H2S ≤ 10%

1.

Non-Buttoned up

1.

Non-Buttoned up

1.

Non-Buttoned up

2.

Use drill pipe

2.

Use L-80 tubing

2.

Use L-80 tubing

3.

Open hole or cased hole testing

3.

Open hole or cased hole testing

3.

Cased hole testing only

H2S > 5 and ≤ 10%

H2S > 10%

H2S > 10%

1.

Non-Buttoned up

1.

Non-Buttoned up

1.

Buttoned up to flow to surface

2.

Use L-80 tubing

2.

Use L-80 tubing

2.

Use L-80 tubing

3.

Open hole or cased hole testing

3.

Cased hole testing only

3.

Cased hole testing only

4.

Use 10,000 psi tree

H2S > 10% 1.

Buttoned up

2.

Use L-80 tubing

3.

Cased hole testing only

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5.3

Well Control The following well control practices should be initiated below compliance depth. See also the Aramco Well Control Manual. Well control procedures are basically the same in the presence of H2S, but the added risk has a definite impact on the decision making process in handling a given well control situation. Extra consideration should be given to items such as remote kill lines, remote adjustable choke control panels and remote BOP controls. A second flare pit has recently been added to all Khuff and Exploration wells. This pit will be to the east or west and will be used when wind conditions make the pit to the south unsafe to use. This would be primarily for uncontrolled flows or when the gas buster cannot handle the flow. 5.3.1

Any influx into the wellbore (kick) should be assumed to contain H2S. The size of the influx, amount of under balance, amount of open hole, depth and EMW test of last casing shoe, formation character, weather conditions and proximity to contact points (in other words, all factors) should enter into the decision to circulate out or pump away the influx.

5.3.2

If the decision is made to circulate out the kick, clear the rig floor and shaker/choke/gas buster area of all unnecessary personnel and take the following precautions.

5.3.3

A)

The rig substructure, BOP, choke line, choke manifold, and mud return areas shall be roped off and identified as a restricted area. No one shall enter these areas without breathing apparatus, H2S monitor, and specific Drilling Foreman approval.

B)

The H2S concentration in the mud returns shall be monitored continuously.

C)

The Drilling Foreman shall alert affected downwind facilities as identified in the well program.

D)

The Drilling Foreman shall implement any other precautions he deems prudent.

E)

All personnel involved in the well control operation will mask-up at least 30 minutes prior to bottoms up. The flow from the choke should be diverted through the gas buster and the gas should be flared. The mud stream will return to the active system where any remaining gas can be removed by the degasser and the use of H2S scavenger.

If the decision is made to pump away the influx, a procedure should be furnished by the engineer based on actual conditions at the time. This will usually involve pumping down the drill pipe at a slow rate while bullheading on the annulus with the same mud weight as in the 17 of 41

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hole or with kill weight mud if weight up can be accomplished with little delay. When drill pipe and casing pressure are equal it can be assumed that the influx is pumped away (an additional volume of mud should be pumped for safety). Kill weight mud can then be circulated in the well holding the appropriate back pressure on the choke. If the drill pipe and casing pressure fail to equalize while bullheading it is likely that the casing seat or a formation above the point of influx has broken down.

5.4

5.3.4

Stripping operations in the presence of H2S are particularly hazardous due to increased stress cracking at low temperatures and high stress levels. If an influx occurs while out of the hole or off bottom, pumping away the influx should be considered prior to initiating stripping operations.

5.3.5

Heavy trip or drill gas concentrations should be diverted through the gas buster and flared, if possible.

Lost Circulation Lost circulation becomes a much more serious problem when it occurs with a formation containing H2S open, especially if that formation has a minimal overbalance. As with well control, the presence of H2S does not change the way you combat losses, rather it impacts the decision making process on which options to take. A more conservative approach is warranted with more attention given to preventative maintenance

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5.4.1

If the hole will not stand full, it is very important to keep the hole filled with mud, water or diesel and record the exact volume pumped so that an accurate hydrostatic head can be calculated if the well becomes static.

5.4.2

The most serious situation would be losses up hole while drilling into or weighting up to kill a higher pressure H2S zone. In this situation, a barite plug can be pumped through the bit to shut off the high pressure zone and allow lost circulation up hole to be remedied. See “Barite Plug” in Chapter II, Section F, of this Drilling Manual. If the losses cannot be controlled serious consideration should be given to setting a casing string across the loss zone before drilling out the barite plug and into the H2S zone.

5.4.3

A more common situation encountered by Saudi Aramco is loss on bottom with a higher pressure H2S zone open up hole with minimal overbalance. An example would be losses in the Khuff-C (partially depleted by production) with the Khuff-B (or L. Jilh) open with original

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pressure. If conventional LCM pills are not successful and the hole will not stand full, there are LC plugs that can be pumped through the bit under various trade names. These type plugs are usually polymer based and acid soluble. If the hole is static and only dynamic losses are being experienced, the pipe can be tripped and run open ended in order to spot higher concentrations of LCM, marble chips or other plugs. See “Types of Plugs” in Chapter II, Section F, of this Drilling Manual. Again, serious consideration should be given to setting a casing string across the higher pressure zone so that the mud weight can be reduced to a minimal overbalance. This reduces the chance of losses, differentially stuck pipe and well control incidents. 5.4.4

5.5

As with well control, all well parameters should be considered in making the decision on how to proceed after encountering loss circulation. The Drilling Engineer should be consulted and should furnish the rig with a general procedure and specific recipes for any plugs required. Serious consideration should be given to setting casing prior to encountering the situations outlined in “2” and “3” above.

Stuck Pipe Stuck pipe in an H2S zone or with an H2S zone open becomes a much more serious problem because the presence of H2S limits your options in freeing the pipe. Diesel based fluids and acids used to free differentially stuck pipe may bring H2S to the surface in solution. Reducing the hydrostatic head below formation pressure will also bring H2S to the surface and is presently against Saudi Aramco policy. As before, the presence of H2S has more impact on the decision making process in reducing the risk of stuck pipe and on how to proceed after pipe is stuck than it does on the actual methods of freeing stuck pipe. These methods remain basically the same. 5.5.1

The Drilling Foreman should make the Mud Engineer aware that more extreme measures should be taken to prevent stuck pipe than would normally be done on a non-H2S well. Reduction of water loss, filter cake thickness, carrying a minimum overbalance, addition of lubricants, etc., can all reduce the possibility of differentially stuck pipe. The Mud Engineer will not normally be aware of an overbalance situation and potential for stuck pipe unless informed by the foreman.

5.5.2

When planning BHA’s, consideration should be given to minimizing the risk of mechanically stuck pipe.

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5.6

5.5.3

Consideration should be given to running a mechanical jar in the string well above the hydraulic jars. This jar would be used to free the hydraulic jars if they became stuck. It should have the capability to be locked out if the hydraulic jars are free.

5.5.4

Consideration should be given to keeping a weighted grease pill ready for pumping should stuck pipe occur.

5.5.5

Where differential sticking appears to be a problem, a minimum overbalance, as recommended by the drilling engineer, may be carried. If differentially stuck pipe does occur, the mud weight may be further reduced to a near balanced condition with approval from the superintendent. An under-balanced situation should not be induced as this procedure is against Saudi Aramco policy.

Highly Deviated and Horizontal Wells Mention has to be made of highly deviated and horizontal wells as they become more common in H2S zones. Everyone involved in the operation should be aware that a highly deviated or horizontal well in an H2S bearing formation increases all risks relative to a straight hole in the same formation. All the risks mentioned above, associated with coring, well testing, well control, lost circulation and stuck pipe are compounded when a highly deviated hole situation is added to the presence of H2S. All preventative measures recommended in the five sections above should be taken as well as some mentioned below.

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5.6.1

Twenty four (24) hour supervision must be provided in this portion of the hole. This would require two Drilling Foremen, two Directional Drillers and two Mud Engineers while drilling the horizontal or highly deviated section in an H2S zone or with an H2S zone open. Change out of these personnel should not be made with both on the same day (for instance, both Directional Drillers should not be relieved together). Many problems on critical wells develop right after a change of senior personnel.

5.6.2

Pumping out of the hole should become a routine operation in the horizontal section. This allows back-reaming with the bit and motor, keeps cuttings moving up the hole to prevent packing off and prevents swabbing in formation fluid. Note: A 1000’ column of gas (or oil) swabbed into a horizontal section would give no pressure differential between drill pipe and annulus and no flow. The only indication would be improper fill volume.

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5.6.3

Slide drilling with no pipe rotation and the pipe laying on the low side of the hole is obviously very conducive to differential sticking. All preventative measures mentioned under stuck drill pipe should be considered. Maintain maximum mud lubricity with synthetic or oil based lubricants. Consider the use of lubricating beads (under various trade names) while sliding. Plan the well so that sliding is minimized in the later stages of the horizontal section.

5.6.4

To prevent packing off and mechanical sticking, mud properties should be maintained for maximum hole cleaning benefit. Alternating low/high viscosity sweeps have been found to aid in hole cleaning as well as high viscosity sweeps weighted slightly above the mud weight in use (sweep tends to stay on low side of the hole and specific gravity difference between mud and cuttings is reduced).

5.6.5

More frequent wiper trips also help keep the hole clean and may give hints of hole problems that are developing. It should be kept in mind that reducing the incidence of hole problems in general reduces the chances of an H2S incident.

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6.0

ATTACHMENTS 6.1

Well Coordinates, Expected H2S and Potential Contact Points 6.1.1

Exploration Wells

This plan is specifically for ___________ Well No. _____ with actual surface location of North _______________, East _____________, UTM Zone ____. Compliance depth is ____________. This well is an Exploration well with known H2S at: HORIZON

DEPTH MD

DEPTH TVD

DEPTH SS

DEPTH TVD

DEPTH SS

And anticipated or possible H2S at: HORIZON

DEPTH MD

The nearest points of contact are: DESCRIPTION

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Direction Deg. (N=0o)

Distance Km.

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List all contact points including but not limited to: Public Highways, manned GOSP or plant, rig camp (if no alarms and permanent communication with rig), residences, gas stations, stores or other businesses, towns or villages.

The attached map (Attachment B) shows the location of the well and each contact point. This map has been furnished to Industrial Security, Loss Prevention and Government Affairs, should they be required to carry out duties under G.I. 1850 and 1851. See applicable G.I.’s in Appendix 1 and 4. (Note: On the map, list only those contact points 5 Km. or less from the surface location. If multiple contact point exist in a particular direction such as a village or group of businesses, they may be combined and shown as one contact point as long as it is so noted on the map key and list. This map should be updated if any additional contact points are noted during drilling and completion operations (such as seismic camp or temporary residence or business).

Attachments B and C, Map of potential contact points and Rig Layout, should follow.

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6.1.2

Development Wells

This plan is specifically for ___________ Well No. _____ with actual surface location of North _______________, East _____________, UTM Zone ____ Compliance depth is ____________. This well is a Development well in a known area with a total depth (TVD) that will penetrate a horizon no deeper than other wells in the immediate area (or structure), with known H2S occurring at: HORIZON

DEPTH MD

DEPTH TVD

DEPTH SS

The nearest points of contact are: DESCRIPTION

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Direction Deg. (N=0o)

Distance Km.

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List all contact points including but not limited to: Public Highways, manned GOSP or plant, rig camp (if no alarms and permanent communication with rig), residences, gas stations, stores or other businesses, towns or villages.

The attached map (Attachment B) shows the location of the well and each contact point. This map has been furnished to Industrial Security, Loss Prevention and Government Affairs, should they be required to carry out duties under G.I. 1850 and 1851. See applicable G.I.’s in Appendix 1 and 4. (Note: On the map, list only those contact points 5 Km. or less from the surface location. If multiple contact point exist in a particular direction such as a village or group of businesses, they may be combined and shown as one contact point as long as it is so noted on the map key and list. This map should be updated if any additional contact points are noted during drilling and completion operations (such as seismic camp or temporary residence or business).

Attachments B and C, Map of potential contact points and Rig Layout, should follow.

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7.0

APPENDIX 7.1

Saudi Aramco Standard Safety Equipment for H2S Operations on All Onshore Drilling and Workover Rigs 7.1.1

H2S and Combustible Gas Monitors. A)

H2S Monitor and Alarm System A four channel H2S monitoring system with two visual-audio alarm system shall be installed and fully operational on all land drilling rigs operating on known or suspect H2S locations. Each sensor and alarm system shall have a portable reel with 200 feet of neoprene covered electrical cable with cannon connectors at each end for hookup of cable to monitor, cable to sensor and cable to alarm (a total of six cables on reels). 1.

The sensors shall be located as near as practical to: • • •

•

B)

The top of the bell nipple. The flowline opening to the shale shaker. The Driller's position and about three feet above the floor. The cellar or underneath the choke manifold, above the choke manifold skid floor. This sensor should be easily moveable so that it can be used around the BOP stack or at the well testing equipment when necessary.

2.

The alarm system (amber strobe lights and horn) shall be set for first alarm at 10 ppm and high alarm at 20 ppm H2S. The alarm system shall be located in clearly visible locations so that personnel in any work area can see and/or hear at least one set.

3.

The monitor shall be located in the doghouse.

4.

There shall be minimum of one spare sensor.

Combustible Gas Monitor and Alarm System A continuous combustible gas monitor and single sensor with a portable reel holding 200 feet of neoprene covered electrical cable with two pairs of cannon connectors (monitor to cable and cable to sensor) shall be provided. An alarm system with similar reel, cable and connectors is required

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1.

7.1.2

The sensor shall be located at either:

•

The top of the bell nipple, or The flowline opening to the shale shaker when a rotating head is in use.

2.

The alarm system (red strobe light and horn) shall be set at 20% of the Lower Explosive Limit (LEL) for the low alarm and 50% of the LEL for the high level alarm. The alarm system shall be clearly visible from work areas on location. The alarm system (light and horn) shall be located on the rig floor above the doghouse. Note: This setting criterion applies to cold work situations only.

3.

The monitor shall be located in the doghouse.

4.

There shall be a minimum of one spare sensor.

C)

Two personal portable H2S monitors, alarm to be set at 10 ppm.

D)

Two portable H2S detectors (hand pump suction type) with high level and low-level H2S and SO2 tubes.

E)

Two portable combustible gas or vapor monitors.

F)

Drager Test Kit for checking mud returns for H2S.

Required Breathing Apparatus A)

•

Hose-line work units, with emergency escape cylinders, shall be provided as follows:

• Rig floor - six • On handrail near shale shaker - two • On rack near mud mixing area - two Near choke manifold - one In derrick for Derrickman (at monkey board) - one

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B) Self contained breathing apparatus (SCBA's) shall be provided as follows: • • • • •

C)

7.1.3

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Toolpusher's office/quarters – two Company Foreman's office/quarters – two Logging Unit (when used) - two SCR room - one Rig Floor - three

At least one fully-charged spare cylinder shall be provided for each unit of all type listed.

Emergency First Aid and Other Safety Equipment A)

Two "Bug Blowers" explosion proof, high volume (40,000 cfm) and moveable.

B)

Three wind socks, two in service, plus streamers to be located so all personnel will know wind direction. One windsock is to be held as a spare.

C)

Flare line ignition system (Alex-500 or equivalent) with backup flare guns or pencil flares.

D)

Two portable oxygen resuscitator units, each with a spare oxygen cylinder.

E)

Two 25 man First Aid Kits, one at rig site and one at campsite.

F)

Four eye wash stations located in the following areas:

• • • •

On the rig floor or in the rig floor doghouse. In the mud mixing area. In the rig medic's office or the rig supervisor's office. In the rig camp mess hall.

G)

Two safety harnesses with two 250 foot retrieval ropes.

H)

Two basket-type stretchers (Stokes or Navy type litter) with blankets and securing straps.

I)

Two Quick-Air splint kits.

J)

One portable bull horn with extra battery pack.

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Drilling & Workover Engineering Department CHAPTER 8 SECTION

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K)

Six small chalk boards with clamps for mounting with an adequate supply of chalk and erasers. Boards can be utilized as visual means of coordinating activities when working under a SCBA. [Note: Dry eraser boards may be substituted for chalk boards].

L)

Flashlights - explosion proof with an extra set of batteries and extra bulb for each (number to be at least one for each two persons in the operation but not less than five). Note:

Sanitation and care of Respiratory Protection Equipment is covered in Section B-5 of Saudi Aramco Safety Requirements for Drilling and Workover Rig Operations.

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7.2

Safe Briefing Area Equipment List The purpose of a safe briefing area is to provide the following: • •

•

A safe area from which the Aramco drilling foreman can direct operations. A safe area where personnel can gather to receive briefings on the present situation and further orders. A safe area where personnel can receive first aid, change out air bottles and repair or replenish other equipment.

The safe briefing area is usually near the Aramco office unless wind conditions require that the secondary site be used. The following equipment must be kept at or near the safe briefing area. It is understood that most equipment will be kept inside and brought out only for drills or actual H2S incidents. A) B) C) D) E) F) G) H) I) J) K) L) M) N) O) P) Q) R) S) T)

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Saudi Aramco radio (radio in Foreman’s truck or a portable unit). Walkie-Talkie (if available) or rig PA unit. Fluorescent orange vest to identify the Safe Briefing Area Commander. All extra SCBA’s not in use elsewhere on the rig. One breathing air compressor/recharge station complete, as near as practical to Safe Briefing Area. A minimum of one charged, spare cylinder for each SCBA on the rig. A minimum of two personal portable H2S monitors (alarm set at 10 ppm) and equipment and power for recharging it. A minimum of two portable H2S/SO2 detectors (hand pump suction type) with high and low level tubes for both gases. A minimum of two portable combustible vapor monitors. One Drager Test Kit. A minimum of two portable oxygen resuscitator units and two spare oxygen cylinders. A minimum of one 25 man First Aid Kit (a second at the camp/quarters) and additional first aid supplies in the rig medics office. Two basket type stretches with blankets and securing straps. Two safety harnesses with two 250 foot retrieval ropes. Two Quick-Air splint kits. A minimum of two portable bull horns with extra battery packs. One flare gun with minimum of 25 flare shots (kept in foreman’s office). A minimum of six dry eraser boards or chalk boards A minimum of six explosion proof flashlights or at least one for each two men on the rig site at any given time. Continuously manned by either a Drilling Foreman, Toolpusher or other experienced and competent individual, plus two pair of runners.

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7.3 Typical H2S Drill Low level alarm sounds for 10 ppm or more (amber light and horn). At this time two Safe Briefing Areas have been designated with the Primary area near the Aramco Drilling Foreman’s office and the secondary area near the entrance to the rig site. It is understood that all the equipment listed in the “Safe Briefing Area Equipment List” cannot be kept out in the weather, but these items should be readily available from the offices and storeroom nearby. A) Driller and one floorman (or assistant driller, if there is one) don 5 minute SCBA’s and plug into cascade system. All other personnel proceed directly to the Safe Briefing Area. B) Driller proceeds to flow-check and shut-in the well if flowing as per the Aramco Well Control Manual (BOP Drill). If no flow, circulate until receiving orders from Drilling Foreman. C) Drilling Foreman and Toolpusher don 30 minute SCBA’s and proceed to the rig floor with at least one portable H2S monitor. They are to first confirm the well is properly secured if flow was detected, then locate the source of the alarm (shaker area, bell nipple, cellar, etc.). If no flow was detected, it will usually be prudent not to shut-in the well and risk stuck DP (shutting in the well can actually concentrate H2S just below the annular or ram). The area of the alarm should then be checked with the portable monitor to confirm that it was not a false alarm. If the alarm is confirmed, the Drilling Foreman and Toolpusher should come up with a plan of action. Superintendent should be informed at this point and drilling engineer consulted if there is any doubt about how to proceed. •

•

If the well was flowing and had to be shut in, this would become a well kill operation and handled according to the Saudi Aramco Well Control Manual. However, Section V., Special Operations/Well Control of the H2S Contingency Plan should be consulted. The option of pumping the kick away down the annulus should be considered. If the decision is made to kill the well conventionally, the listed precautions in this plan should be taken. If the well did not flow, there are several options open to reduce H2S concentrations in the atmosphere that are a result of gas breaking out of the drilling mud. These include reducing drilling rate or pulling off bottom to circulate the use of H2S scavengers in the mud, increasing overbalance (increasing mud weight) and additional ventilation in the area of the alarm. Stopping circulation completely is only a temporary

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measure and the resulting reduction in ECD can actually worsen the situation. D) The person acting as the “H2S Safety Representative” will collect any equipment not already at the “Safe Briefing Area” and see that it is in place. He will then proceed to take a head count with the assistance of the medic. He will assume command of the “Safe Briefing Area” reporting directly to the Drilling Foreman. Note: If the Toolpusher is the designated “H2S Safety Representative”, the medic will assume this command until relieved by the Toolpusher. E) Chief Roustabout dons a 30 minute SCBA and checks all rooms and offices for anyone who did not hear the alarm. He then proceeds to Safe Briefing Area for the head count. F) Medic proceeds to Safe Briefing Area with portable resuscitators, first aid kit and any other required medical equipment not already at the “Safe Briefing Area”. He then will assist the person acting as the “H2S Safety Representative” in the head count. G) If anyone is missing, the “Safe Briefing Area” commander will select a two man team to mask up on SCBA’s, report the missing personnel to the Toolpusher and continue with the search unless directed otherwise by the Toolpusher. H) The above condition shall continue until an H2S level of less than 10 ppm is confirmed and alarms cease or until the Drilling Foreman announces that all unsafe areas with H2S levels in excess of 10 ppm have been roped off (shaker shake and choke area only) and continuous monitoring with portable monitors is being done.

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7.4

Attachment for Offshore Wells More stringent requirements are necessary when H2S is anticipated offshore. This is due to the nature of offshore operations, being on a small confined rig or platform with the only means of evacuation being by boat, helicopter or escape capsule. The crew quarters being in direct proximity to the rig package also presents problems that are not encountered on onshore wells. The operational levels (alarm levels) remain the same as onshore and all precautions taken for onshore wells should be observed on offshore wells. In addition, the following precautions and additional equipment requirements should be observed. Note: Additional equipment requirements are detailed below under “Saudi Aramco Standard Safety Equipment for H2S Operations on all Offshore Drilling and Workover Rigs”. A) There shall be two Safe Briefing Areas, the same as for onshore. If possible, they should be located on the port and starboard sides of the rig near the escape boats or capsules. Wind direction and proximity to the Aramco foreman’s office should determine which one is the primary area. A Public Address system audible from any point on (or within) the vessel or platform is required in order to give assembly and evacuation instructions B) Due to the close proximity to the quarters and the rig package, H2S orientation, instruction with breathing equipment and evacuation drills will be required of all persons on board, including visitors. Every person on board will be issued a SCBA. See below, “Standard Safety Equipment for H2S Operations on All Offshore Drilling and Workover Rigs”. C) Since mud pumps, mud pits, shakers, cement pumps and other equipment are usually in enclosed or partially enclosed areas, ventilation is critical on an offshore operation where H2S might be present. Even though extra sensors are required in most of these areas, loss of below deck ventilation fans is a critical situation and these areas should be evacuated until ventilation is restored. If repairs in the non-ventilated deck are required, a portable H2S detectors and 30 minute SCBA’s (for each worker) will be available for immediate use. D) Mask-up and evacuation of non-essential personnel from the rig package shall be at level 2, the same as for onshore. Evacuation of non-essential personnel from the vessel should be at the Saudi Aramco Foreman’s discretion. It should be considered after a sustained level 3 alert, when efforts to reduce the H2S levels on the drill floor have been unsuccessful. Weather conditions and the time required to evacuate by boat or helicopter should be considered in making this decision.

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E) All work boats and crew boats should approach the rig from up wind maintaining radio contact. When red lights are flashing, the rig should not be approached except on request for evacuation. When on standby, anchorage should be in the general upwind direction. SCBA’s should be issued to the crews of all work boats and crew boats servicing the rig. F) Helicopters should make radio contact with the rig prior to approach and landing to confirm operations are normal. During a level two or higher alert, when visual alarms are active, landings will generally not be made. Any exception to this should be for evacuation only. The pilot should be appraised of the situation in as much detail as possible and the final decision on whether to land will be his. G) Two flare lines (offshore type burner booms), situated so that at least one is always down wind, will be operational by compliance depth. This should be the case even when no testing is planned. The choke manifold outlet and the gas buster outlet should remain connected to both flare lines with the ability to quickly switch from either outlet or either fare line. H) When declaring an emergency or disaster, refer to GI 1851, “Offshore Contingency Plan” attached as Appendix 6. The reporting procedure is very similar to an onshore incident with the main difference being response and responding support groups.

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7.5

Saudi Aramco Standard Safety Equipment for H2S Operations on All Offshore Drilling and Workover Rigs 7.5.1. A continuous monitoring system with eight sensors and six red beacon light/siren alarm systems, each with conductor cable, shall be provided. A)

All sensors must have protective housings capable of protecting the sensor from accidental spray from rig wash down hoses and accidental mud and/or oil splashes.

B)

Sensors shall be located as near as practical to: 1. 2. 3. 4. 5. 6. 7.

The top of the bell nipple. The flowline opening to the shale shaker. The Drillers position and about three feet above the rig floor. The mud pit in the pump area. The motorman's work area in the motor room. The living quarters area nearest the most likely source of hydrogen sulfide. The breathing apparatus compressor package, near the rig floor.

Note: The eight sensor with 200 feet of cable on portable reel shall be extra and will be used to monitor any other potential source of hydrogen sulfide or kept on standby in designated safety equipment storage area. C)

There shall be at least four spare sensors in addition to the eight in the monitoring system.

D)

The H2S alarm system (red beacon and siren) shall be set at 10 ppm H2S for the first alarm and 20 ppm H2S for the second alarm. The combustible gas alarm system shall be set at 20% of the Lower Explosive Limit (LEL) for the low alarm and 50% of the LEL for the high level alarm. [Note: This setting criteria applies to cold work situations only.]

E)

The alarm system shall be located in a clearly visible area so that personnel in any work area can see and/or hear at least one set. They shall be located:

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F) 7.5.2

On the rig floor and at least eight feet above the floor.

2.

On the port side at the corner of and above the quarters.

3.

On the starboard side at the corner of and above the quarters.

4.

Below deck in the pump-motor room area.

5.

In crew quarters.

6.

In the galley area.

The monitor shall be located in the Supervisor's office, Control Room or Radio Room.

A minimum of one hundred 30 minute SCBA's will be located on any offshore rig operating in known or suspected H2S areas. There shall always be at least 25% more SCBA onboard than the number of personnel. A)

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1.

The 30 minute SCBA's shall be stored ready for use as follows: 1.

There shall be one SCBA assigned to each person on board, regardless of his affiliation, contractor, service contractor, Aramco, or any visitor. These will be stored under the head-end of the assigned bunk when the person is in the bunk and during any period considered safe by the Supervisor. (If there is no bunk assignment, the person will be assigned a SCBA and a designated area for storage during his time on board.) Before assignment of a SCBA to any person, he will demonstrate that he is capable of donning it, adjusting the face piece, and turning on the pressure demand air. This requirement shall be waived for any personnel with documentation from his employer that he has received training within the past 12 months in H2S safety, including practice in donning respiratory protection equipment.

2.

Ten SCBA's shall be stored in the dining area.

3.

Four SCBA's shall be stored in the motor room or pump area.

4.

Four SCBA's, each with clip on communication device. Two shall be in Aramco Foreman's office and two in the Rig Supervisor’s office.

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5.

B)

7.5.3

All remaining SCBA's and extra cylinders will be stored in an air conditioned designated safety equipment storage area near the Supervisor's office.

The hose-line work units with escape cylinders shall be stored as follows: 1.

Six work units (three with clip on communication devices) on the rig floor in a convenient location.

2.

Two work units each with a clip on communication device in the Supervisor's office.

3.

Two work units each with a clip on communication device in the Aramco Foreman's office.

4.

One work mask shall be located in the derrick at the Derrickman's position, finger board or stabbing board.

5.

Five work units and 16 spare cylinders shall be stored in an air-conditioned designated safety equipment storage area near the Rig Supervisor's office.

6.

Nine spare clip communication devices units with supply of spare batteries will be stored with the five work units as above in #4.

Three cascade systems with 12 - 300 cubic foot cylinders each or equivalent capacity; three air compressors each with purification system and capacity of 26 scfm at 2400 psi; one 3 outlet manifold and three 12 outlet manifolds; two 200 foot hoses; two - 150 foot hoses; twelve - 50 foot hoses; two 5000 psi working pressure hoses (250 foot and 300 foot respectively). A)

One cascade system with air compressor powered by an explosion proof electric motor will be located near the rig floor 1. 2. 3. 4. 5. 6.

There shall be two six outlet manifold on the derrick floor. There shall be a three outlet manifold at the Derrickman's position. There shall be a three outlet manifold in the mud room. There shall be a three outlet manifold in the motor room. There shall be a one six outlet manifold for recharging portable cylinders, one at each cascade system. There shall be a double tee with check valves for tying in either or both of the other two systems.

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B)

C)

There shall be two cascade systems with diesel powered air compressors, located as remotely from the rig floor as practical, one on the upper starboard deck, the other on the upper port deck 1.

There shall be one six outlet manifold for recharging portable cylinders at each cascade system, as well as regulators and low pressure manifolds for hose line units.

2.

There shall be a double tee with check valves for tying in either or both of the other two systems.

There shall be one 250 foot of 5000 psi w.p. hose; one 300 foot of 5000 psi w.p. hose; two 150 foot and twelve 50 foot hoses stored and ready for immediate use in an air conditioned designated storage area.

7.5.4

Five personal portable H2S monitors, as well as stock of lead acetate sampling devices.

7.5.5

One hydrogen sulfide calibrator with two permeation tubes, portable and AC/DC.

7.5.6

Continuous H2S mud monitor (Mud Duck). Garret Gas Train with supply of accessory equipment for testing mud, plus Drager Test Kits for checking mud return.

7.5.7

Four portable oxygen resuscitators with eight spare oxygen cylinders.

7.5.8

Four portable H2S - SO2 detectors, suction type with H2S and SO2 tubes.

7.5.9

Four portable combustible gas detectors - hand pump suction type.

7.5.10 Six bug blowers, explosion proof, high volume (25,000 cfm or larger) and movable. 7.5.11 Wind socks (4 minimum), streamers, and flags to be located on various places on rig so all personnel will know the wind direction. 7.5.12 Remote flare line ignition system (Alex-500 or equivalent). 7.5.13 Two emergency ignitors, preferably a flare type with a supply of flares (25 minimum). Emergency ignitors to be stored ready for use in lower right hand drawer of Aramco Foreman's desk.

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7.5.14 Four safety harnesses and four 250 feet retrieval ropes. 7.5.15 Four stretchers (Stokes litter - Navy type basket or equivalent) with blankets and securing straps. 7.5.16 Four first aid kits (each 25 man size). 7.5.17 Four Quick-Air splint kits or equivalent. 7.5.18 Six portable electronic bull horn speakers with six extra battery packs. 7.5.19 Six small chalk boards with clamps for mounting with an adequate supply of chalk and erasers. Boards can be utilized as visual means of coordinating activities when working under a SCBA. [Note: Dry eraser boards may be substituted for chalk boards.] 7.5.20 Flashlights - explosion proof with extra set of batteries and extra bulb for each (minimum number shall be 10 flashlights). Note: All safety equipment with rubber, plastic or other parts like to deteriorate shall be stored in an air conditioned, dark and designated area, near the Supervisor's office. Adequate supplies of sanitizing material shall be available for sanitizing face masks and other body contact equipment.

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7.6

GI 1850.001 – Onshoreore Contingency Plan (for Emergencies and Disasters) Refer to Appendix of this manual for a copy of the GI

7.7

GI 1851.001 – Offshore Contingency Plan (for Emergencies and Disasters) Refer to Appendix of this manual for a copy of the GI

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7.8

Physical Properties of H2S and Toxicity Table Hydrogen Sulfide (H2S) a colorless, transparent gas that is slightly heavier than air. It will tend to accumulate in low places if the air is still. It is flammable from 4.3% to 47% vapor by volume in air. It is soluble in both water and oil with solubility decreasing as temperature increases. Low concentrations have an unpleasant “rotten egg” odor but it rapidly kills the sense of smell above 0.01%, therefore odor should not be relied upon for detection. It is extremely toxic as can be seen in the table below.

1 ppm

(0.0001%)

Easily noticeable smell.

10 ppm

(0.001%)

Threshold limit value (TLV) for a time-weighted average (TWA) 8-hour day. Essentially, the maximum allowable concentration in which one can safely work, 8 hours a day, day in and day out. Breathing apparatus required when working in concentrations greater than 10 ppm.

20 ppm

(0.002%)

Ceiling concentration (no worker may ever be exposed to 20 ppm for any period of time. Causes irritation or burning sensation in eyes, and irritation to upper respiratory tract if exposed for one hour or more.

50 ppm

(0.005%)

Loss of sense of smell after about 15 minutes. Increased eye irritation or burning sensation. Exposure more than one hour may cause headache, dizziness, and/or staggering.

100 ppm

(0.01%)

Coughing, eye irritation, loss of sense of smell after 3 to 5 minutes. Altered respiration, pain in eyes, and drowsiness after 15 to 20 minutes, followed by throat irritation after one hour.

200 ppm

(0.02%)

Burns eyes and throat, rapid loss of sense of smell.

250 ppm

(0.025%)

Between 250 ppm and 500 ppm, pulmonary edema, which can be life threatening, almost always occurs.

500 ppm

(0.05%)

Loss of consciousness within 15 minutes, breathing stops if nor treated quickly – resuscitation required. Dizziness, loss of sense of reasoning and balance.

700 ppm

(0.07%)

Immediate unconsciousness, seizures, loss of bowel and bladder control, breathing will cease. Death will result if immediate resuscitation is not administered.

1000 ppm

(0.1%)

Immediate unconsciousness, death or permanent brain damage may result.

10,000 ppm

(1%)

Instant death.

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SAFETY EQUIPMENT

__________________________________________________________________________________________________________________________

SAFETY EQUIPMENT 1.0

FIRE PROTECTION EQUIPMENT

2.0

BREATHING APPARATUS

3.0

GAS DETECTION EQUIPMENT

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June 2006

CHAPTER 8 - HEALTH, SAFETY & ENVIRONMENTAL ISSUES SECTION

D - SAFETY EQUIPMENT

__________________________________________________________________________________________________________________________

SAFETY EQUIPMENT

1.0

2.0

FIRE PROTECTION EQUIPMENT 1.1

All fire protection equipment (e.g. fire extinguishers) on Saudi Aramco operated rigs shall be maintained in accordance to G.I. 1781.001 (Inspection, Testing and Maintenance of Fire Protection Equipment). G.I. 1781.001 clearly details these requirements.

1.2

All fire protection equipment (e.g. fire extinguishers) on contractor rigs shall be maintained to the same standards as stipulated in G.I. 1781.001 (Inspection, Testing and Maintenance of Fire Protection Equipment). G.I. 1781.001 clearly details these requirements. Note however, that the drilling contractor is responsible to maintain his own equipment, not the Saudi Aramco Fire Protection Department, as listed in the G.I.

1.3

The Drilling Foreman is responsible to ensure that G.I. 1781.001 requirements are met. Should any questions arise, concerning Saudi or contractor fire protection equipment, the Drilling Foreman should contact the Saudi Aramco Fire Protection Department.

BREATHING APPARATUS 2.1

All breathing apparatus on Saudi Aramco operated rigs shall be maintained in accordance to G.I. 1780.001 (Atmosphere Supplying Respirators). G.I. 1780.001 clearly details these requirements.

2.2

All breathing apparatus on contractor rigs shall be maintained to the same standards as stipulated in G.I. 1780.001 (Atmosphere Supplying Respirators). G.I. 1780.001 clearly details these requirements. Note however, that the drilling contractor is responsible to maintain his own equipment, not the Saudi Aramco Fire Protection Department, as listed in the G.I.

2.3

On those rigs where the breathing apparatus is supplied by a third-party contractor contracted to directly to Saudi Aramco, this third-party contractor is responsible for all aspects of breathing apparatus maintenance.

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2.4

3.0

The Drilling Foreman is responsible to ensure that G.I. 1780.001 requirements are met. Should any questions arise, concerning Saudi Aramco or contractor breathing apparatus, the Drilling Foreman should contact the Saudi Aramco Fire Protection Department.

GAS DETECTION EQUIPMENT This section is incomplete, pending further research in Saudi Aramco Engineering Standards (SAES) for combustible gas and H2S detection equipment. The relevant SAES were written for plant applications and their requirements must be studied and possibly adapted for mobile drilling rig use.

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SAFE HANDLING PROCEDURES 1.0

CAUSTIC SODA 1.1 Hazards 1.2 Required Protective Equipment 1.3 Safe Work Procedures 1.4 First Aid Instructions 1.5 Spill or Leak Procedures

2.0

ACID 2.1 2.2 2.3 2.4 2.5 2.6 2.7

Hazards Required Protective Equipment Safe Work Procedures Pre-Job Safety Meeting Equipment Inspection First Aid Instructions Spill or Leak Procedures

3.0

EXPLOSIVES 3.1 Uses 3.2 Hazards 3.3 Safe Work Procedures 3.4 Pre-Job Safety Meeting 3.5 Lease & Traffic Control

4.0

RADIOACTIVE MATERIALS 4.1 Hazards 4.2 Safe Work Procedures 4.3 Applicable Documents 4.4 Saudi Aramco Abandonment of A Radioactive Source

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SAFE HANDLING PROCEDURES 1.0

CAUSTIC SODA 1.1 Major Hazards

1.2

1.1.1

Caustic soda is extremely corrosive to skin and eyes, and all contact with skin and eyes must be avoided.

1.1.2

Severe eye splashes can cause blindness.

1.1.3

Solid caustic soda absorbs moisture from the atmosphere, and dissolves in it, creating liquid caustic. A small piece can lodge in the clothing and later cause burns as it dissolves.

1.1.4

Dust from caustic flakes is not usually a problem when flakes are big. However, a dust mask must be worn if flakes are small, or if flakes are being broken up by sweeping or other actions.

Required Protective Equipment 1.2.1

Chemical face shield.

1.2.2

Elbow length gloves, either PVC or neoprene, in good condition.

1.2.3

PVC apron.

1.2.4

Eye wash station in immediate vicinity.

1.2.5

Wet weather (waterproof plastic) trousers worn with cuffs over boots.

1.2.6

Optional: dispensable dusk mask (3M type 8710 or equivalent). Note: Dust masks are mandatory for cleaning up caustic spills.

1.3

Safe Work Procedures 1.3.1

Caustic must be stored where it can remain dry.

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1.4

1.5

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1.3.2

Caustic flakes or pellets must be added to water. It is absolutely forbidden to add water to caustic. (Adding water to caustic will cause an extremely concentrated and dangerously hot caustic solution to splash about.)

1.3.3

Sleeves and trousers must hang over gloves and boots, not tucked in. (If sleeves and trousers are tucked in, caustic can get into the glove or boot and cause burns.).

1.3.4

There must be no obstructions around either the mixing tank or the safety shower/eyewash.

1.3.5

Split, torn or leaking caustic containers must not be used.

1.3.6

A suitable waste container (dedicated for emptied caustic containers) must be readily accessible and used.

1.3.7

Partially used bags of caustic must be placed inside a fresh clear plastic bag, tied off, and returned to store.

1.3.8

Gloves and apron must be washed well with water after use.

First Aid Instructions 1.4.1

Respond immediately to any skin or eye contact with caustic by flushing with copious quantities of water.

1.4.2

In the case of eye contact with caustic, use eyewash immediately, and wash eyes with running water for at least 15 minutes.

1.4.3

Notify rig medic to examine and treat as appropriate.

Spill or Leak Procedures 1.5.1

The Drilling Foreman must be notified of a major spill or leak.

1.5.2

Spills must be roped off or otherwise marked.

1.5.3

Full PPE must be used to clean up spills, including a dust mask if solid caustic is spilled. Liquid caustic spills require the use of a wet weather jacket.

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2.0

1.5.4

Gather up spilled solid caustic using dust pan and hand broom, placing spilled caustic in the dedicated caustic waste container. Clear away whatever cannot be swept by be washing with plenty of water. This will create heat and splashing, so extreme caution must be used.

1.5.5

Liquid spills must be cleaned by gentle application of large amounts of water. This will create heat and splashing, so extreme caution must be used. When washing down, ensure no one is in the vicinity where the water will run off. Guards may have to be posted to prevent entry while clean-up is underway.

ACID 2.1

2.2

Hazards 2.1.1

Hydrochloric acid is a very corrosive liquid, skin contact will cause serious burns. Eye splashes could cause serious eye damage, even blindness. Even diluted acid can cause burns.

2.1.2

Burns may take some time to be felt. By this time, the burn could be serious.

2.1.3

Hydrochloric Acid fumes can also cause skin and lung burn injuries.

2.1.4

Strong (concentrated) acid contact with metal releases hydrogen, a very explosive gas.

2.1.5

Acidizing uses high pressure lines, therefore also presenting all the risks associated with pressurized piping.

Required Protective Equipment 2.2.1

Rubber gloves.

2.2.2

Plastic apron.

2.2.3

Full face mask.

2.2.4

Rubber boots (steel toed).

2.2.5

Fire retardant acid suits (wet gear) must be available for emergency use. An emergency shower must be readily accessible.

2.2.6

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2.3

2.4

Safe Work Procedures 2.3.1

All acid accidents or near misses must be reported to the Drilling Foreman.

2.3.2

Only the acid contractor crew will handle acid tank and pump equipment.

2.3.3

Correct PPE to be worn at all times.

2.3.4

Hot work is prohibited in acid storage or handling areas.

2.3.5

Rig crew must stay outside security-taped area or clear of acid tank and pump at all times.

2.3.6

No unauthorized personnel are allowed adjacent to, or in the vicinity of pressurized lines. No personnel may cross over pressurized lines at any time.

2.3.7

Keep personnel well clear when acid is being pumped FROM the well, gas may cause the acid to spray or spurt.

2.3.8

Flush pumping lines with water after acid pumped.

2.3.9

Treat displaced acid with caustic or soda ash before disposal.

Pre-Job Safety Meeting Before acidizing operations or pressure testing of any lines is started, a safety meeting with all personnel must be held. At minimum, such a meeting will cover:

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2.4.1

Scope of work, including an explanation of the treatment and procedures to be followed.

2.4.2

Specific identification/designation of personnel in charge of the operation.

2.4.3

Specific hazards associated with each stage of work (pressure ruptures, corrosive contacts, toxicity, flammability, etc).

contractor

and

operator

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2.4.4

Specific safety procedures for the control of these hazards (fresh water sources, flushing procedures for corrosive contact, line approach restrictions, etc).

2.4.5

Dangers associated with pressures and energized lines. Any approach to pressurized lines is prohibited.

2.4.6

Safety equipment (PPE, eyewash stations, fire equipment, etc.).

2.4.7

Restrictions and restricted areas (essential personnel only, no ignition sources, no smoking, etc.).

2.4.8

Emergency arrangements (action plan in the event of fire or serious leak, review of strategic equipment, placement, fresh water sources, emergency actions).

2.4.9

Evacuation procedures (escape paths, follow up actions, re-entry conditions, etc.).

2.4.10 It must be stressed that actual handling of acid, including repair of acid leaks in injection lines must be left to the acid company's employees. 2.5

Equipment Inspection The following equipment should be available and inspected for leaks: 2.5.1

Chicksans

2.5.2

Swivels

2.5.3

Valves

2.5.4

By pass line

2.5.5

Choke manifold

2.5.6

Vent line

2.5.7

Wash down hoses

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2.6

2.7

2.8

First Aid Instructions 2.6.1

Respond immediately to any skin or eye contact by flushing with copious quantities of water. Use the emergency shower for for large body splashes.

2.6.2

In the case of eye contact, use eyewash immediately, and wash eyes with running water for at least 15 minutes.

2.6.3

Notify rig medic to examine and treat as appropriate.

Spill or Leak Procedures 2.7.1

The Drilling Foreman must be notified of a major spill or leak.

2.7.2

Spills must be roped off or otherwise marked.

2.7.3

Large acids spills require a well-trained responder. Therefore, only the acid contractor crews will clean up large acid spills.

2.7.4

Full PPE must be used to clean up spills, including acid suits.

Access 2.8.1

2.9

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The immediate area required for surface equipment should be cleared to permit adequate spacing of surface equipment, with regard to personnel, safety and regulations.

Minimum Recommended Breathing Air Equipment Placement 2.9.1

1/4" airlines with 3 SABA should be provided to cover personnel requirements at the wellhead.

2.9.2

1 - 1/4" airline with 1 SABA is required to cover the operator's cab.

2.9.3

1 - 1/4" airline with 1 SABA is required to cover the acid pumper.

2.9.4

1 - 1/4" airline with 1 SABA is required for the N2 operator.

2.9.5

SCBA are required, one each for the operator's representative and the contractor safety representative.

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2.10 Safety Representative 2.10.1 The acidizing contractor shall provide a safety representative. During the acidizing operation, the safety representative will be equipped, at minimum, with: 2.10.1.1 One gas detector. 2.10.1.2 Fire retardant slicker suit. 2.10.1.3 Full rubber gloves. 2.10.1.4 Steel toed rubber boots. 2.10.1.5 Self contained breathing apparatus. 2.10.2 The safety representative duties include: 2.10.2.1 Pedestrian traffic control. 2.10.2.2 Monitoring of all work stations and personnel movements. 2.10.2.3 Verification of safe work practices. 2.10.2.4 Verification of PPE use. 2.10.2.5 Monitoring and control of SABA use during rig in, installation of/removal of injector or endless tubing related equipment. 2.10.2.6 Checking wellhead for leaks prior to/after rig in and throughout operation. 2.10.2.7 Monitoring under mask of any H2S returns. 2.10.2.8 Shut down of operations upon detection of imminent danger, substandard practices and/or conditions.

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3.0

EXPLOSIVES 3.1

Uses The most common use of explosives in drilling is casing perforation. Other uses include making a hole in the drillstring, backing off from stuck pipe, sidewall coring, and small charges associated with setting plugs and packers.

3.2

3.3

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Hazards 3.2.1

Failure to observe, radio silence and explosives safety measures.

3.2.2

Incorrect storage or transportation of explosives.

3.2.3

Mishandling of mechanical firing system for explosives.

3.2.4

Loss of explosives at the rig site.

Safety Procedures 3.3.1

Only the explosives contractor engineer and crew are permitted to handle explosives at the rig site.

3.3.2

All other crew must keep well away, 50m or more is recommended during all explosives operations.

3.3.3

Preparation of explosive devices must be done in an area marked with red and white tape and with “Explosives-No Smoking- Keep Out” signs set out.

3.3.4

To stop stray electric currents, all non-essential equipment must be turned off during gun connection for example the mobile telephone.

3.3.5

All welding must be stopped before explosive connection.

3.3.6

The Explosives Engineer must check the rig grounding. (Must be less than 25v difference).

3.3.7

All mobile and fixed radios shall be switched off and not used.

3.3.8

Radio silence warning signs must be posted on access roads 200m from the rig.

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3.4

Pre-Job Safety Meeting Before rigging up, a safety meeting must be conducted jointly by the Drilling Foreman and perforating contractor representatives for all personnel on location. This meeting must address:

3.5

3.6

3.4.1

Scope of work.

3.4.2

Assignment of tasks.

3.4.3

Work permit and relevant requirements.

3.4.4

Hazards and means of reducing the hazards.

Lease and Traffic Control 3.5.1

Clear the lease of all non-essential personnel.

3.5.2

Post a worker at least 70 metres from the wellhead to monitor traffic and stop unnecessary personnel wishing to enter the job site.

3.5.3

Shut off all mobile radios and telephones before rigging up begins until perforating is completed, as the units may otherwise set off charges. If it is necessary to use a radio or telephone, drive off the lease a minimum of 1 km.

3.5.4

Place signs saying "Perforating, Shut Off Radio Transmitting Equipment" at the lease entrance and on the lease roadway at least 70 metres from the perforating gun.

3.5.5

Personnel assigned to stop vehicles must be adequately protected from vehicle traffic under existing conditions. Reflective traffic vests should be used.

Procedures for Retrieving and Disarming a Misfired Perforating Gun 3.6.1

Do not permit a gun to be retrieved during a lightning storm.

3.6.2

No one but members of a trained perforating crew are allowed to handle misfired guns.

3.6.3

The Drilling Foreman shall review with the perforating crew their procedure for handling misfired guns.

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3.6.4

Hold a safety meeting to determine a strategy and discuss procedures.

3.6.5

Establish who the essential personnel will be during the retrieving of the live gun. When the gun is at the surface, all other personnel are to be off the lease until the gun is disarmed.

3.6.6

Shut off the wireline generator and rig generators.

3.6.7

Turn off the main circuit breakers.

3.6.8

Disconnect all panels used in the gun firing procedure.

3.6.9

Ensure the casing-to-rig voltage monitor is reading less than 0.25 V.

3.6.10 Pull the gun up to 30 metres from the surface. Check all two-way radios and mobile phones and ensure they are turned off. Post a guard at the lease entry to prevent any vehicles or personnel from entering. All non-essential personnel must move to a pre-established distance off location. 3.6.11 Have the gun pulled up into the lubricator and have the valve closed. Have the lubricator broken out and carefully lowered. 3.6.12 With the exception of a trained perforating crew, all personnel will be required to remain in a safe location until the gun has been effectively disarmed and an all clear signal has been issued.

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4.0

RADIOACTIVE MATERIALS Radioactive equipment uses a radioactive source to make a measurement. Examples of such equipment are the Schlumberger logging tools to measure rock density and rock porosity. Halliburton has a radioactive source in a tool on their truck to measure the density of the cement. Inspection crews sometimes use a radioactive source in a tool to measures steel thickness on the standpipe. 4.1

4.2

Hazards 4.1.1

Radioactive sources are extremely dangerous. They emit tiny particles and rays that can pass through rock and steel. When these particles pass through the human body, they kill or change cells that make up the body. A person exposed to radioactive source radiation could become very sick, get cancer, or die. Very strict precautions against radiation exposure must be applied.

4.1.2

Loss of a radioactive source at the rig site.

4.1.3

Radioactive source lost or stuck in the hole.

Safety Procedures: 4.2.1

At all times, radioactive sources or tools are in use, keep all crew far away.

4.2.2

Drilling crew should keep clear of the fluid end of the cement unit if radioactive sources or tools are in unit.

4.2.3

Only the radioactive tool operators are allowed to be present in the rig floor during radioactive source handling.

4.2.4

Radioactive sources must be stored in sealed containers and in a radiation shielded box.

4.2.5

The Schlumberger (Contractor) source box must only be removed from the truck when the sources are required.

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EMERGENCY RESPONSE PLANNING & DRILLS 1.0

INTRODUCTION 1.1 Definitions 1.2 Objectives of Emergency Response Plans 1.3 Objectives of Drills

2.0

GENERAL REQUIREMENTS

3.0

TYPES OF DRILLS / EMERGENCY PLANS 3.1 Well Control (BOP) Drills 3.2 H2S Release Drills 3.3 H2S Rescue Drills 3.4 Fire Attack Plans 3.5 Fire Drills 3.6 Man Down (Injury) Drills 3.7 (Offshore) Lifeboat Drills 3.8 (Offshore) Man-Overboard Drills

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EMERGENCY RESPONSE PLANNING & DRILLS 1.0

INTRODUCTION "Emergency planning" means considerably more than providing a first aid kit, stretcher, or fire blanket. Instead, there must be written action plans detailing (to the extent possible) those actions to be taken when an emergency occurs. This will ensure more effective responses when it becomes necessary to face extraordinary circumstances. The effectiveness of the plan will usually be proportionate to the thoroughness and soundness of the planning effort. Emergency response plans cannot anticipate every event. However, plans can anticipate the types of emergencies that may occur, and plans can outline a communications network and a decision-making process that provides support to those who must handle the emergency. Those on the site will have to make many decisions on the spot, based on the situation at hand. One purpose of the plan is to take care of as many (administrative) issues as possible, to allow the site commander to focus on the matters of prime importance. The time devoted to the preparation of an adequate plan will enhance speedy decisions and actions at the time of an emergency. It can result in lives saved and limits to the extent of damage. The plan will provide the means for supervisors to concentrate on solving major problems rather than spending an undue amount of time trying to bring some organization out of chaos. A properly developed plan includes procedures which enable people to make balanced and considered decisions during an emergency. This opportunity to weigh and consider beforehand reduces the need for spur-of-the-moment decisions. The plan also makes it easier for supervisors to delegate in advance, to establish who does what, and to save the precious time that otherwise would be wasted in deciding and redeciding actions to be taken during an emergency. 1.1

Definitions Emergency: A dangerous situation, arising with little or no warning, and causing or threatening death, injury, or serious disruption to people, property or process. A condition needing immediate treatment to mitigate hazards and minimize loss.

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Emergency Response Plan: An organized response, planned in advance to counter a specific potential emergency, that identifies the command structure, lines of communication, and specific actions to prevent damage and control the situation. Drills: An on-site rehearsal of the emergency response plan that tests the ability of responders to meet their responsibilities, and tests the plan itself for effectiveness.

These definitions make it clear that the emergency response plans are the critical feature. Drills are conducted to provide practice, and to ensure the emergency response plans are effective to meet the possible emergency. 1.2

1.3

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Objectives of Emergency Response Plans 1.2.1

Ensure the safety of workers, responders, and the public.

1.2.2

Reduce the potential for the destruction of property or for further losses of products.

1.2.3

Assist response personnel to determine and perform proper remedial actions quickly.

1.2.4

Reduce recovery times and costs.

1.2.5

Inspire confidence in response personnel, industry, and the public.

Objectives of Drills 1.3.1

Drills allow the Drilling Foreman to evaluate the preparedness of each individual participating in the drill. For large scale drills this includes outside agencies and support services.

1.3.2

Drills provide practice for participants to perform their assigned tasks and responsibilities, and to improve their proficiency and response time.

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2.0

1.3.3

Drills test the communications between the command center and the local emergency scene.

1.3.4

Drills identify and correct shortcomings in the Emergency Response Plans.

GENERAL REQUIREMENTS 2.1

All rigs shall develop emergency response plans against those emergencies that can be reasonably foreseen, including fire, injured personnel (man down), H2S release, H2S poisoning, and kicks.

2.2

Each rig will designate a primary and back-up command center, continually manned during the emergency by the Drilling Foreman or senior Toolpusher. The command center must be readily identifiable to both outside responders and the drill crew.

2.3

Each rig shall conduct regular drills to ensure that all personnel are fully able to carry out their assigned duties.

2.4

Each drill will have a maximum acceptable response time. The rig crew must complete their assigned tasks within this time limit. If crews are not able to respond within the time limit, drills must be conducted more frequently until the crew is able to meet the time limit.

2.5

During drills, the Drilling Foreman shall observe and verify that:

2.6

2.5.1

The emergency response plan is adequate to address the emergency.

2.5.2

There are adequate numbers of knowledgeable people in appropriate areas to ensure the Drilling Foreman will get the information he needs to make informed decisions on how to counter the emergency.

2.5.3

Each responder in the drill carries out his assigned duties competently, quickly, with confidence, and reports in to the command center as appropriate.

Following each drill, the Drilling Foreman shall conduct a debriefing with the rig crew, outlining both what was well done and what needs improvement. If necessary, the Drilling Foreman and the Toolpusher shall develop and implement action plans to ensure an adequate response.

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3.0

TYPES OF DRILLS / PLANS 3.1

Well Control (BOP) Drills 3.1.1

Each crew shall conduct a BOP drill at least once per week. The Drilling Foreman will decide if more frequent BOP drills are required to ensure adequate response.

3.1.2

BOP drills will be varied to cover all possible kick scenarios, including on bottom, hoisting, running in the hole, out of the hole, trip drills with different size pipe (or collars) in the hole, wireline logging, cementing, etc.

3.1.3

The Drilling Foreman will time crew response during BOP drills and verify they meet minimum requirements.

3.1.4

BOP drill procedures should ensure that adequately trained individuals are posted to check on and report on the status of the following key areas: • • • • • • • • • • • •

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Kill line HCR position Choke manifold set-up Choke position(s) Stack configuration Stack closing pressure Pit gain SIDPP & SICP, (all gauges) Mud weight in and out Shaker box Pump strokes Mixing hopper & mud supply

3.1.5

Each BOP drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the type of BOP drill (e.g. pit, trip, etc.) and the response time to secure the well.

3.1.6

Further details regarding BOP drills will be found in the Saudi Aramco Well Control Manual.

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3.2

H2S Release Emergency Planning & Drills 3.2.1

Every person boarding an offshore rig must be able to don breathing apparatus and breath bottled air within 45 seconds.

3.2.2

Every person who may be required to work on a land rig must be able to don breathing apparatus and breath bottled air within 45 seconds. All other persons working near a land rig must be able to recognize the H2S alarm and know to proceed to the safe briefing area.

3.2.3

Each crew of each rig operating in a known or suspected H2S area will conduct an H2S drill at least once per week. The Drilling Foreman will decide if more frequent H2S drills are required to ensure adequate response.

3.2.4

The H2S drill will be announced by the standard siren & strobe light alarm. There must be no prior warning of the drill. Note:

3.2.5

3.2.6

The rig PA system shall immediately and repeatedly announce “This is a drill! This is a drill!”

H2S drill procedure will include the following: 3.2.5.1

Masking up and breathing bottled air for those crew members whose assigned tasks require breathing apparatus.

3.2.5.2

Requiring all non-essential personnel (i.e. no specific assigned tasks in the drill) muster at upwind safe briefing area.

3.2.5.3

Conducting a head count or other means to account for all personnel.

3.2.5.4

Rescuing procedures for rescuing potentially injured persons from the H2S contaminated site or vicinity (see “H2S Rescue Drills” below).

Following the drill, the contractor Toolpusher and the Drilling Foreman shall randomly select (non-essential) crew members mustered at the safe briefing area and verify that they know how to don and breath from breathing apparatus.

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 8

HEALTH, SAFETY & ENVIRONMENTAL ISSUES

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EMERGENCY RESPONSE PLANNING & DRILLS

SECTION

June 2006

___________________________________________________________________________________________________________________________

3.2.7

3.3

3.4

H2S Rescue Drills 3.3.1

Each crew of each rig operating in a known or suspected H2S area will conduct an H2S rescue drill at least once per month (as part of their weekly H2S drill). The Drilling Foreman will decide if more frequent H2S rescue drills are required to ensure adequate response.

3.3.2

There must be no prior warning of the drill, nor any warning whatsoever that someone is missing. It is critically important to verify that the standard H2S drill procedure is adequate to identify who is missing and locate and rescue him.

3.3.3

H2S Rescue Drills will proceed as per normal H2S drills, with the following additions: 3.3.3.1

Rig management will assign one crew member to act as an “H2S victim” and place this individual at an appropriate location.

3.3.3.2

No other crew member will be given advance notice of either the drill or that someone may be missing.

3.3.3.3

Following their normal H2S drill procedure, the rig crew must be able to identify that someone is missing, locate the missing person, rescue him by bringing him to the safe briefing area and administering appropriate first aid within 7 minutes after the alarm first sounded.

Fire Attack Plans 3.4.1

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Each H2S drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the response time (to complete the drill).

On each rig (land and offshore), the drilling contractor will develop written site–specific Fire Attack Plans for each of the following areas: 3.4.1.1

Engine rooms or skids.

3.4.1.2

SCR rooms.

3.4.1.3

Fuel tank storage areas.

3.4.1.4

Rig and camp accommodations.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 8

HEALTH, SAFETY & ENVIRONMENTAL ISSUES

F

EMERGENCY RESPONSE PLANNING & DRILLS

SECTION

June 2006

___________________________________________________________________________________________________________________________

3.4.1.5

3.4.2

Any other site on the rig where a fire may be reasonably thought possible.

In addition to the above, each offshore rig will develop Fire Attack Plans for the following areas: 3.4.2.1

Pit room.

3.4.2.2

Accumulator deck.

3.4.2.3

Helideck.

3.4.3

The Drilling Superintendent is responsible to ensure that adequate Fire Attack Plans are in place for each rig under his supervision.

3.4.4

As a minimum, Fire Attack Plans will include the following:

3.4.5

3.4.4.1

Identify the primary and secondary Fire Attack Team that will fight and contain the fire (the secondary Fire Attack Team is held in reserve in case the primary team needs relief or assistance).

3.4.4.2

Identify the Fire Attack Team composition (consisting, as a minimum, of a commander, 2 fire fighters, and one messenger).

3.4.4.3

Identify specific fire fighting equipment and procedures to fight the fire in that specific area.

3.4.4.4

Identify the maximum acceptable response time for the Fire Attack Team to assemble and begin to fight the fire.

3.4.4.5

Include procedures for conducting a head count or other means to account for all personnel.

3.4.4.6

Include rescue procedures for rescuing potentially injured persons from the fire site or vicinity.

The drilling contractor shall provide adequate training to ensure his personnel are competent to perform their assigned tasks.

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Drilling & Workover Engineering Department CHAPTER 8

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EMERGENCY RESPONSE PLANNING & DRILLS

SECTION

June 2006

___________________________________________________________________________________________________________________________

3.5

3.6

Fire Drills 3.5.1

Each rig will conduct a fire drill at least once per quarter. The Drilling Foreman will decide if more frequent fire drills are required to ensure adequate response.

3.5.2

Fire drill locations will be varied to provide practice in all Fire Attack Plans.

3.5.3

The Drilling Foreman will observe and time crew response during fire drills and verify that the Fire Attack Plan and Fire Attack Teams are adequate to address the fire risk.

3.5.4

Each fire drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the location and type of fire drill and the response time to assemble and begin to fight the fire.

Man Down (Injury) Drills 3.6.1

Each rig will develop a Medical Evacuation (MEDEVAC) Plan that complies and coordinates with Saudi Aramco GI 1321.015 (Request for Air Medical Evacuation). Even if air medevacs are unlikely, GI 1321.015 contains other critically important procedures to ensure a rapid and effective response to a medical emergency.

3.6.2

Each rig will have the telephone number of the following posted in the rig clinic, the rig office, and the radio room (if applicable, e.g. offshore rigs):

3.6.3

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3.6.2.1

Nearest medical facility.

3.6.2.2

Nearest Saudi Aramco medical clinic.

3.6.2.3

Saudi Aramco Aviation.

Each rig will develop Man Down (Injury) Drill procedures to address and treat an immobilizing injury occurring anywhere on the rig location, including an immobilized injured man on the monkey board.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 8

HEALTH, SAFETY & ENVIRONMENTAL ISSUES

F

EMERGENCY RESPONSE PLANNING & DRILLS

SECTION

June 2006

___________________________________________________________________________________________________________________________

3.6.4

As a minimum, Man Down (Injury) Drill procedure will address the following: 3.6.4.1

Prompt notification of the Medic.

3.6.4.2

First aid at the injury site.

3.6.4.3

Placing and securing the injured person in a basket stretcher.

3.6.4.4

Transferring the injured person to the rig clinic.

3.6.5

Each rig will conduct a Man Down (Injury) Drill at least once per quarter. The Drilling Foreman will decide if more frequent Man Down (Injury) drills are required to ensure adequate response.

3.6.6

Each rig will conduct a vertical rescue drill, for example getting an immobilized injured man safely down from the monkey board, once per year. Note:

3.7

A suitably weighted dummy must be used to simulate the injured person.

3.6.7

The Drilling Foreman will observe and time crew response during Man Down (Injury) drills and verify that the procedures are adequate to provide prompt and effective treatment.

3.6.8

Each Man Down (Injury) drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the location and type of drill and the response time to bring the injured person to the clinic.

(Offshore) Lifeboat Drills 3.7.1

Each offshore rig will conduct a lifeboat drill within 24 hours of a crew change, and at least once per month. The Drilling Foreman will decide if more frequent lifeboat drills are required to ensure adequate response.

3.7.2

Lifeboat drills must include everyone aboard the rig, with the possible exception of only those crew members absolutely essential to maintain a safe watch over the ongoing operation.

3.7.3

Lifeboat drills may be combined with fire and/or H2S drills.

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SECTION

June 2006

___________________________________________________________________________________________________________________________

3.7.4

The maximum acceptable response time for lifeboat drills must take into account the possibility that evacuation may have to proceed in a hazardous H2S environment. Therefore, everyone aboard the rig must be able to muster to their boat stations and enter their boats with enough time left to lower the boats and sail to a safe upwind area before their SCBA’s run out of air. With a standard 30-minute SCBA, everyone must be aboard their assigned boat within 12 minutes of the alarm first sounding.

3.7.5

Fully occupied lifeboats shall not be lowered into the water as part of the boat drill. (Testing and operating the boats shall be done as routine maintenance items.)

3.7.6

Lifeboat drill procedure must include the following:

3.7.7

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3.7.6.1

Command center manned by senior rig management.

3.7.6.2

Immediate and repeated PA announcement “This is a drill! This is a drill!”

3.7.6.3

Two trained and competent lifeboat men assigned to each lifeboat.

3.7.6.4

Headcount procedure to verify/report to the command center that all persons are accounted for.

3.7.6.5

Search and rescue procedure to locate all missing persons.

3.7.6.6

Maximum acceptable response time for all persons to report to their boat stations.

3.7.6.7

Verification that everyone aboard the rig is capable of entering the lifeboat and securely fastening his seat belt while wearing both a PFD and SCBA.

Each lifeboat drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the response time for all aboard to muster to their assigned boat stations.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 8

HEALTH, SAFETY & ENVIRONMENTAL ISSUES

F

EMERGENCY RESPONSE PLANNING & DRILLS

SECTION

June 2006

___________________________________________________________________________________________________________________________

3.8

(Offshore) Man-Overboard Drills 3.8.1

Each offshore rig will develop Man-Overboard rescue procedures and train a sufficient number of crewmen to effect a safe and prompt rescue.

3.8.2

Each offshore rig will conduct a man-overboard drill at least once per quarter. The Drilling Foreman will decide if more frequent manoverboard drills are required to ensure adequate response.

3.8.3

A suitably weighted dummy will be used to simulate a man overboard.

3.8.4

Man overboard drills will involve either (or both) the standby boat or the rig’s own rescue boat, depending upon equipment available on that specific rig.

3.8.5

If no standby boat is readily available, the rig must launch a rescue boat to retrieve the dummy.

3.8.6

Each man-overboard drill will be documented on both the IADC sheet and the Saudi Aramco morning report. Documentation will include the response time to rescue the man overboard.

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Drilling & Workover Engineering Department CHAPTER 9

June 2006

APPENDIX TABLE OF CONTENTS

__________________________________________________________________________________________________________________________

TABLE OF CONTENTS 1.0

GIs, LETTERS, AND REFERENCES 1.1 Onshore Contingency Plan 1.2 Offshore Contingency Plan 1.3 Rig Site Flare Gun and Communication Equipment 1.4 Isolation Barriers for Wells During Drilling and Workover 1.5 Onshore Wellsite Safety 1.6 Installation of Slip-on/Weld-on Casing Heads

2.0

SAUDI ARAMCO FORMS 2.1 Daily Drilling Report 2.2 Casing/Liner Landing Details 2.3 Wellhead and Tree Details 2.4 Transportation Department Waybill 2.5 Drilling & Workover Services Department Waybill 2.6 Material Request 2.7 Motor Vehicle Accident Report Form 2.8 Petroleum Products Requisition 2.9 Staged Material Transfer

3.0

WELL ACCOUNT CHARGE NUMBERS 3.1 Accounting Location Code 3.2 Item Number Description

4.0

SAFETY REQUIREMENTS FOR DRILLING AND WORKOVER RIGS

5.0

RIG INSPECTION CHECKLIST FOR ONSHORE RIGS

6.0

RIG INSPECTION CHECKLIST FOR OFFSHORE RIGS

Saudi Aramco 7180 (5/89) G.I. NUMBER

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

1850.001 ISSUE DATE

03/16/1999 APPROVAL

MYR

Approved

REPLACES

08-01-1996 PAGE NUMBER

1

OF

14

CONTENT: This General Instruction contains the Contingency Plan for a disaster occurring at any onshore wellsite during drilling or workover operations, or when Producing has turned over responsibility for well control to the Drilling and Workover organization. The text includes: 1. 2. 3. 4. 5. 6. 7. 8. 9.

**

OBJECTIVE IMPLEMENTATION ORGANIZATION WELL CONTROL RESTORATION OR ABANDONMENT OPERATIONS COST ACCOUNTING SUPPORT SERVICES DOCUMENTING AND CRITIQUE DISASTER DRILLS

APPENDIX APPENDIX APPENDIX APPENDIX

1.0

I II III IV

-

DUTIES AND RESPONSIBILITIES DUTIES AND RESPONSIBILITIES, SUPPORT ORGANIZATIONS ORGANIZATION CHART, WELLS WITHOUT RIG ON LOCATION ORGANIZATION CHART, WELLS WITH RIG ON LOCATION

OBJECTIVE The objective of this Contingency Plan is to handle well control operations when an onshore well disaster or major blowout occurs during drilling or workover operations or when Producing has turned over responsibility for well control to Drilling and Workover. This plan will complement the existing Producing Disaster Contingency Plans and will become effective only when a well blowout causes or threatens to cause a major emergency.

*

2.0

IMPLEMENTATION 2.1

*

* CHANGE

Well Emergency During Production Operations If a well emergency or disaster occurs while the well is the responsibility of one of the Producing Departments, notification that a well emergency exists or that a disaster has occurred will be made through the normal chain of command. The Area Producing Vice President or Manager (if the Vice President cannot be reached) may request Drilling and Workover to take over well control operations by contacting (by priority): •

Vice President, Petroleum Engineering and Development or

•

General Manager, Drilling and Workover or

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

1850.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

ISSUE DATE

03/16/1999 APPROVAL

MYR

• 2.2 *

Approved

REPLACES

08-01-1996 PAGE NUMBER

2

OF

14

Manager, Drilling & Workover Services.

Well Emergency During Drilling or Workover Operations If an emergency or disaster occurs during drilling or workover operations on a well, the situation will be reported by dialing 110 and contacting the Manager, Drilling and Workover Operations or the General Manager, Drilling and Workover. The responsibility of the well control will be with Drilling and Workover.

2.3 *

Reporting of Emergency During Drilling or Workover Operations 2.3.1

The drilling/workover Foreman or Senior drilling representative will report the emergency by dialing 110.

2.3.2

The proper method for reporting an emergency is that the person reporting speaks slowly, calmly, distinctly in a clear voice and gives information in the following sequence: a.

, on Well at _______area.” State: “There is an emergency at Rig When reporting a disaster, include the statement: “This is a disaster.”

b.

Identify yourself by name and badge number.

c.

Give your location.

d.

Describe the emergency briefly, i.e. blowout, fire, leak, etc.

e.

State if there is any injured person.

f.

Repeat the above information.

g. 2.3.3

* 2.4

Order of Priorities 2.4.1

*

* CHANGE

Ask the person receiving the call to repeat the information to make sure it is complete and correct. The drilling/workover Foreman will also contact the Superintendent, Manager or General Manager of Drilling and Workover to report the emergency.

Rescue and Protection of Personnel 2.4.1.1

** ADDITION

The first objective of this plan is the preservation and protection of human life. In the event that there are any injured or dead, the drilling or workover foreman on the rig will be responsible for obtaining emergency treatment and for ambulance or helicopter transportation. This will be done by notifying medical services when calling the emergency number 110. He should state the number of injuries and/or deaths. NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

1850.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

ISSUE DATE

03/16/1999 APPROVAL

MYR

* **

2.5 *

Approved

REPLACES

08-01-1996 PAGE NUMBER

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2.4.1.2

Security patrols will be dispatched to restrict access to the area to Saudi Aramco authorized personnel only.

2.4.1.3

The drilling/workover Foreman or senior drilling representative will designate a team to immediately begin monitoring the area for flammable gas and hydrogen sulfide (H2S) or other potential hazards.

2.4.1.4

Persons in any endangered area near the emergency site will be alerted and/or evacuated.

2.4.1.5

Fire Protection Division will respond to the emergency by dispatching the necessary personnel and equipment. Level of assistance will depend on remoteness of the site.

Safeguarding of Company Property Fire fighting and special well control equipment from the Drilling Equipment & Water Well Maintenance in Abqaiq will be dispatched as quickly as possible. Water or foam will reduce the danger of ignition if the well is not on fire, or it will cool and help protect the wellhead if the blowout should catch fire. Specialized fire fighting equipment will be utilized as necessary 2.5.1 Well Control

*

2.5.2

The Site Leader of the Well Control Team (with rig on well) or Special Well Action Team (without rig on well) will supervise the on-site well control operations. No other leader or site commander, designated by a different organization, will have the authority to interfere or take charge. Ignition Should uncontrolled flow from a well occur without being accidentally ignited, the decision to ignite will be based on the following criteria:

*

*

* CHANGE

A)

If flow from a gas well contains H2S in excess of 20 ppm ignite the flow immediately.

B)

If the flow presents immediate and serious danger to the inhabited areas or facilities, ignite the flow immediately.

C)

Any flow condition other than that described in item (A) & (B) will be evaluated on a case-by-case basis. The decision to ignite will be made by the General Manager, Drilling and Workover, after evaluating all the facts. If there is no communication with higher levels of Mangement or the time factor becomes

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

1850.001 ISSUE DATE

03/16/1999 APPROVAL

MYR

Approved

REPLACES

08-01-1996 PAGE NUMBER

4

OF

14

critical, then the decision to intentionally ignite can be made by a Drilling or Workover foreman, Superintendent or Manager.

3.0

ORGANIZATION The organization for the Well Control Contingency Plan is described in appendix III & IV. Personnel assigned to the organization will be relieved of current responsibilities by other personnel who will carry on regular Company business. 3.1

In the event that the well has a drilling or workover rig on it, the Manager of Drilling and Workover Operations will be responsible for well control operations. He will appoint the Site Leader of the Well Control Team. The Well Control Team will consist of necessary drilling and workover foreman and the rig crew of the rig on location. Support services such as the Special Well Action Team, will be provided as needed.

*

3.2

In the event that Producing turns over a well to Drilling and Workover, the Manager of Drilling and Workover Services will be responsible for well control operations. The Superintendent of Drilling Equipment & Water Well Maintenance Division will assume the job of Site Leader of the Special Well Action Team. The team will be made up of the Special Well Services Unit plus Drilling /Workover foreman as required to provide the necessary expertise. A representative from the Producing Organization will be part of the team and will provide advice and assistance as needed. Labor crews will be provided by Water Well Rig Operations Unit.

**

3.3

Prior to any rig move to drill or workover a well, the Drilling Superintendent or designated representative will contact the respective Producing counterpart and others that may have interest in the area in order to: -

4.0 *

* CHANGE

Ensure that the concerned Organizations are familiar with the responsibilities described in the Drilling & Workover Contingency Plan in case of a disaster, Establish a contact point in case the Contingency Disaster Plan has to be activated. This communication channel will serve as the information pipeline to keep Producing Operations abreast of the latest developments, and to request assistance if required.

WELL CONTROL The Site Leader of the Well Control Team (with rig on well) or the Special Well Action Team (without rig on well) will work closely with the respective Manager and the General manager, Drilling and Workover. He will participate in the immediate evaluation of the emergency to determine the plan for control of the well.

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

1850.001 ISSUE DATE

03/16/1999 APPROVAL

MYR

5.0

Approved

REPLACES

08-01-1996 PAGE NUMBER

5

OF

14

RESTORATION OR ABANDONMENT OPERATIONS As a well is brought under control, safety equipment will be installed. Debris must be removed and construction plans will be implemented to repair the site and return the well to its previous operating status. If necessary, the well will be abandoned.

6.0 *

COST ACCOUNTING Drilling and Workover, Planning & Accounting Services Unit, will obtain a special project number from the Finance and Insurance Claims Administrator, Treasurers Department, Dhahran, to accumulate costs related to the disaster. The Treasurers Department will determine the proper disposition of the costs accumulated in the SP. The Planning and Accounting Services Unit of the Drilling and Workover Department will review the charges and make corrections or adjustments as necessary and issue a final financial cost report if required.

*

7.0

SUPPORT SERVICES Support services provided by various departments as well as those performed by services companies will be coordinated by the Site Leader, Well Control Team and the Manager, Drilling and Workover Services. Each department providing a support service will be responsible for adequate preparation to provide prompt and efficient service during the emergency.

8.0

Complete daily logs will be maintained from the time of the initial report and the activation of the emergency control organization. The responsible persons in the central emergency group Manager’s control room (Room 200, Bldg. 3193) will act as liaison with all of the various groups to maintain continuous documentation of the emergency. A complete factual report of each day’s activities will be maintained as permanent record. The final report shall be prepared by the Drilling and Workover Engineering Department and shall contain a complete record of facilities and wells involved, planning, decisions, photographs, etc. Upon completion of the final report, a critique will be held to evaluate all the causes, actions and reactions of the various phases up to the final restoration or disposition.

*

**

DOCUMENTING AND CRITIQUE

9.0

DISASTER DRILLS 9.1

* CHANGE

Drilling and Workover will conduct an annual “Primary” rig emergency drill to better prepare for unexpected well disasters when they occur. This drill will be coordinated with the disaster plan drills of Southern or Northern Area Producing and other operating organizations so that all parties will become familiar with the respective responsibilities and response plans. By ** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

1850.001 ISSUE DATE

03/16/1999 APPROVAL

MYR

Approved

REPLACES

08-01-1996 PAGE NUMBER

6

OF

14

conducting joint drills, the response time to activate the disaster plans for a blowout will decrease, resulting in rapid control of the well. This Primary drill will require full mobilization of equipment and personnel. Other organizations such as Loss Prevention, Medical, Fire Department, Transportation, etc will also participate in the drill. 9.2

Drilling and Workover will also conduct annual “Secondary” rig emergency drills with each division of a Producing area. The “Secondary” drills will evaluate readiness to respond to a disaster and will require minimal mobilization of equipment and personnel.

Recommended By: ______________________________

F. A. Al-Moosa General Manager, Drilling. & Workover Concurred By: ______________________________ H. J. Kassem Manager, Loss Prevention Department ______________________________ A.A. Ghabbani Manager, Fire Protection Department ______________________________

S. S. Raslan General Manager, Industrial Security Operations ______________________________

A. M. Al-Sabti Vice President, Southern Area Producing ______________________________

Y. A. Al-Aiderous Vice President, Northern Area Producing Approved By: ______________________________

M. Y. Rafie Vice President, Petroleum Engineering and Development

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

1850.001 ISSUE DATE

REPLACES

03/16/1999 APPROVAL

Approved

08-01-1996 PAGE NUMBER

MYR

7

OF

14

APPENDIX I

APPENDIX I DUTIES AND RESPONSIBILITIES Many of the duties and responsibilities of the members of the Contingency Plan Organization are listed in order to clarify the various functions. This list is not intended to describe all the actions necessary for any particular emergency. Vice President, Petroleum Engineering and Development *

*

*

*

**

1.

Assume executive authority over the well control emergency and report conditions and operating progress to the Executive Vice President or President.

2.

Advise Vice President, Government Affairs of Statements for news release.

3.

Appoint investigating committee.

General Manager, Drilling and Workover 1.

Decide on activation of the Contingency Plan and formulate a plan for controlling the well.

2.

Make decision on ignition of well effluent, if required.

3.

Provide Vice President with details of well and field.

4.

Notify Vice President of Exploration.

Manager, Drilling and Workover Operations 1.

Assume responsibilities for well control operations on wells involving drilling or workover rigs.

2.

Advise staff that Contingency Plan has been activated.

3.

Provide support and direction to the Site Leader of the Well Control Team and advise if the decision on ignition must be made.

Superintendent Drilling or Workover Operation 1.

Notify Dept. Manager of the emergency.

2.

May act as Site Leader of the Well Control Team.

3

Insure that the drilling/workover Foreman or senior drilling representative has designated a team to monitor the area for flammable gas and hydrogen sulfide (H2S) or other potential hazards.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

1850.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

ISSUE DATE

REPLACES

03/16/1999 APPROVAL

Approved

08-01-1996 PAGE NUMBER

MYR

8

OF

14

APPENDIX I *

*

*

Manager, Drilling and Workover Services 1.

Notify Government Affairs Representative.

2.

If necessary call

Boots & Coots

(281) 931-8884

Fax No. (281) 931-8302

or

Neal Adams

(713) 937-8320

Fax No. (713) 937-6503

3.

Notify Department Managers of support services departments.

4.

Assume responsibilities for well control operations on wells turned over to Drilling and Workover by Producing Operations.

5.

Advise staff that Contingency Plan has been activated.

6.

Provide support and direction to the Site Leader of the Special Well Action Team.

7.

Arrange for on-site inspection for Vice President and General Manger, Drilling and Workover.

8.

Coordinate services provided by other department.

9.

Maintain the emergency equipment in a ready manner and arrange movement to location.

Superintendent, Drilling Equipment & Water Well Maintenance Division

1.

Send Emergency Well Control Equipment to the well location.

2.

Provide personnel to work in the DE&WWM yard to help assemble, operate and repair equipment.

3.

Act as head of Special Well Action Team.

4.

Hook up nearby water wells for use during onshore well control operations.

5.

Provide skilled and semi-skilled personnel to work at the disaster location.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

1850.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

ISSUE DATE

03/16/1999 APPROVAL

MYR

Approved

REPLACES

08-01-1996 PAGE NUMBER

9

OF

14

APPENDIX I Site Leader, Well Control Team (w/ rig on well) or Site Leader, Special Well Action Team (w/o rig on well) 1.

Advise Foreman of immediate action to be taken.

2.

Assist with evacuation and rescue operation if needed.

3.

Advise staff that Contingency Plan has been activated.

4.

Proceed to location and take the position of Site Leader.

5.

Maintain on-scene control and keep Manager advised of any change in condition.

6.

Contact Area Loss Prevention Superintendent and arrange for safety equipment surveys and servicing needs.

7.

Set up security as required.

Accounting Services 1.

Maintain a record of costs incurred and appropriate documentation as directed.

2.

Maintain inventory of all Equipment and Materials delivered to disaster site.

Superintendent, Drilling Rig Support Division 1.

Obtains all materials and equipment needed for use at the disaster site.

2.

Coordinates with Transportation to ensure prompt delivery of materials and equipment.

Superintendent, Wellsites Division 1.

Provides a location for emergency equipment and camp to be set up.

2.

Provides a roadway for movement of material and equipment to reach the location.

3.

Provides stand-by equipment for use during well control operations to construct pits or dikes.

Government Affairs Representative 1.

* CHANGE

Notify Government officials of situation. All communications will be cleared through Vice President, Petroleum Engineering & Development.

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

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1850.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

ISSUE DATE

MYR

*

REPLACES

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Approved

08-01-1996 PAGE NUMBER

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APPENDIX I Manager, Drilling and Workover Engineering 1.

Inform Manager, Reservoir Engineering Department of situation and conditions. Obtain relevant well data including: (a)

Bottom-hole pressure, productivity index, water cut and oil-water contact.

(b)

Preferred relief well drilling location(s) subject to wind and terrain considerations.

(c)

Preferred intercept interval.

(d)

Contour dip and strike.

2.

Request flow rate and pressure profile calculations to be run (computer) for given conditions.

3.

Transmit copies of well configuration sketch, wellhead drawing, Morning Reports, and other pertinent documentation to the General Manager, Petroleum Engineering, General Manager, Drilling and Workover and to the Vice President, Petroleum Engineering and Development.

4.

Assemble well data and distribute copies as required. Include drilling program, well cross-sectional sketch, reports, known information - formation tops, final elevation etc.

5.

Have large-scale sketch (flip chart size) of well configuration prepared for use in review meetings. Denote casing sizes/depths, drill string configuration, formation tops, hole problems encountered and other relevant information which may be of use.

6.

Designate qualified and experienced engineer (s) to go to the wellsite to: (a)

Keep accurate log of on-site operations and well/environmental/weather conditions.

(b)

Assist technically as required.

7.

Prepare kill program including fluid type, density and pumping rates.

8.

Review available rig(s) to drill relief well(s). Recommend rig(s) from optimum technical viewpoint.

9.

Once survey location(s) for relief well(s) are received, prepare directional drilling program.

10.

Monitor drilling progress on relief well(s) and provide technical liaison among engineering services group(s) and operations. Prepare relief well kill program(s). Prepare management reviews of progress as required.

11. 12.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

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1850.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

ISSUE DATE

REPLACES

03/16/1999 APPROVAL

Approved

08-01-1996 PAGE NUMBER

MYR

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APPENDIX II

APPENDIX II DUTIES AND RESPONSIBILITIES OF SUPPORT SERVICES DEPARTMENT *

Communications 1. 2. 3.

Implement communications system at Disaster Control Center. Provide for maintenance of system on the scene and at control center. Monitor system to see that it is functioning properly.

Aviation 1.

Provide emergency transportation for evacuation.

2.

Aerial surveillance for security and well conditions.

3.

Provide for movement of authorized personnel and materials.

Land Transportation 1. *

Loss Prevention 1

**

Provide for movement of materials and equipment.

Provide Personnel at the well site and Disaster Control Center to advise the site leader or commander on safety related issues.

Fire Protection 1.

Provide onsite personnel and equipment to support emergency operations as requested. Level of assistance will depend on remoteness of the emergency site.

Medical *

1.

Provide emergency medical services as required (on-the-scene and at clinic).

Community Services 1.

Provide accommodations and food services as needed.

Security 1.

* CHANGE

Provide on-site personnel for security control.

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

Saudi Aramco 7180 (5/89) G.I. NUMBER

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

1850.001 ISSUE DATE

REPLACES

03/16/1999 APPROVAL

Approved

08-01-1996 PAGE NUMBER

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APPENDIX II Producing *

1.

Handle all liaison with oil and gas dispatcher, plants, pipelines and other groups concerned with oil movement and gas production.

*

2.

Coordinate with the Site Leader of the Well Control Team on all activities within the field.

3.

Supervise all shut-in and start-up activities of nearby wells when the need arises.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

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1850.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

ISSUE DATE

Approved

REPLACES

03/16/1999 APPROVAL

08-01-1996 PAGE NUMBER

MYR

13

OF

APPENDIX III

APPENDIX III WELLS WITHOUT RIG ON LOCATION PET. ENGR. & DEVELOPMENT VICE PRESIDENT GOVT. AFFAIRS DRILLING & WORKOVER GENERAL MANAGER

DRILLING & WORKOVER DRILLING & WORKOVER ENGR. DEPT. SVCS. DEPT. MANAGER MANAGER

DRLG. EQUIP & WATER WELL MAINT. DIV. SUPERINTENDENT/

DRLG. & WORKOVER ENGINEERS

PETROLEUM ENGINEERING GENERAL MANAGER

RESERVOIR MGMT DEPT. MANAGER

PRODUCING ENGR. DEPT. MANAGER NAPE OR SAPE

DRLG. & WORKOVER ENGR. DIV GEN. SUPERVISOR

SPECIAL WELL ACTION TEAM LEADER

SUPPORT SVCS.

SPECIAL WELL ACTION TEAM

DRLG. RIG SUP. DIV. SUPERINTENDENT WELLSITES SVCS. DIV. SUPERINTENDENT

PLANNING & ACCT. SERVICES SUPERVISOR

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

14

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1850.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

DRILLING & WORKOVER SERVICES

SUBJECT:

ONSHORE CONTINGENCY PLAN

ISSUE DATE

REPLACES

03/16/1999 APPROVAL

MYR

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08-01-1996 PAGE NUMBER

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APPENDIX IV

APPENDIX IV WELLS WITH RIG ON LOCATION PET. ENGR. & DEVELOPMENT VICE PRESIDENT GOVT. AFFAIRS

DRILLING & WORKOVER GENERAL MANAGER

PETROLEUM ENGINEERING GENERAL MANAGER PRODUCTION ENGR. DEPT. MANAGER NAPE OR SAPE

DRILLING & WORKOVER SVCS. DEPT. MANAGER

DRLG. EQUIP & WATER WELL MAINT. DIV. SUPERINTENDENT DRLG. RIG SUP. DIV. SUPERINTENDENT

WELLSITES SVCS. DIV. SUPERINTENDENT

DEV. DRILL. & OFFSHORE W/O DEPT. OR DEEP DRILL.& ONSHORE W/O DEPT MANAGER

DRLG & WORKOVER ENGR DEPARTMENT MANAGER

DRLG. & WORKOVER ENGINEERING DIV(S). GEN. SUPERVISOR(S)

WELL CONTROL TEAM SITE LEADER

SUPPORT SVCS.

RESERVOIR MGMT. DEPT. MANAGER

WELL CONTROL TEAM

DRLG. & WORKOVER ENGINEERS

SPECIAL WELL ACTION TEAM

PLANNING & ACCT. SERVICES SUPERVISOR

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

14

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SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

DRILLING & WORKOVER OPERATIONS DEPARTMENT DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

1851.001 ISSUE DATE

REPLACES

03/16/1999 APPROVAL

MYR

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CONTENT: This General Instruction contains the Contingency Plan for a disaster occurring at an offshore wellsite during drilling or workover operations, or when Producing has turned over responsibility for well control to the Drilling and Workover organization. The text includes:

**

1. 2. 3. 4. 5. 6. 7. 8. 9.

OBJECTIVE IMPLEMENTATION ORGANIZATION WELL CONTROL RESTORATION OR ABANDONMENT OPERATIONS COST ACCOUNTING SUPPORT SERVICES DOCUMENTING AND CRITIQUE DISASTER DRILL

APPENDIX I APPENDIX II APPENDIX III

1.0

DUTIES AND RESPONSIBILITIES DUTIES AND RESPONSIBILITIES, SUPPORT ORGANIZATIONS ORGANIZATION CHART

OBJECTIVE: The objective of this Contingency Plan is to handle well control operation when an offshore well disaster or major blowout occurs during drilling or workover operations, or when Producing has turned over well control responsibilities to Drilling and Workover. This plan will complement the existing Marine and Producing Departments’ Disaster Contingency Plans and the Saudi Aramco Oil Spill Contingency Plan. It will become effective only when a well blowout causes or threatens to cause a major emergency.

2.0

IMPLEMENTATION: 2.1

Well Emergency During Production Operations If a well emergency or disaster occurs while the well is the responsibility of one of the Producing Departments, notification that a well emergency exists or that a disaster has occurred will be made through the normal chain of command. The Area Producing Vice President or Manager (if the Vice President cannot be reached) may request Drilling and Workover to take over well control operations by contacting the Vice President, Petroleum Engineering and Development or the General Manager, Drilling and Workover (if the Vice President is not immediately available).

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

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SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

*

ISSUE DATE

DRILLING & WORKOVER OPERATIONS DEPARTMENT

2.2

REPLACES

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APPROVAL

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Well Emergency During Drilling, or Workover Operations If an emergency or disaster occurs during drilling or workover operations on a well, the situation will be reported by dialing 110 and contacting the Manager, Drilling and Workover Operations or the General Manager, Drilling and Workover. The responsibility for well control will be with Drilling and Workover.

*

2.3

Reporting of Emergency During Drilling or Workover Operations 2.3.1

The drilling/workover Foreman or senior drilling representative will report the emergency by dialing 110. The drilling/workover Foreman will be the onsite commander unless and until relieved by the Well Control Team Site Leader (WCTSL) designated in the ORGANIZATION section (paragraph 3) of this document. If the drilling/workover Foreman is incapacitated prior to the onsite arrival of the WCTSL, then the next senior Saudi Aramco individual on-board will assume responsibility as onsite commander until properly relieved. If no viable Saudi Aramco personnel are onboard, then the Senior Contractor individual on-board will assume responsibility as onsite commander until properly relieved.

2.3.2

The proper method for reporting an emergency is that the person reporting speaks slowly, calmly, distinctly in a clear voice and gives information in the following sequence: a.

State: "There is an emergency at Rig ___________., on Well/Platform _______/ ______." When reporting a disaster, include the statement: "This is a disaster".

b. c. d. e. f. g.

* 2.3.3 2.4

Identify yourself by name and badge number. Give your location. Describe the emergency briefly, i.e. blowout, fire, leak, etc. State if there is any injured person. Repeat the above information. Ask the person receiving the call to repeat the information to make sure it is complete and correct. The drilling/workover Foreman will also contact the Superintendent, Manager or General Manager of Drilling and Workover to report the emergency.

Order of Priorities 2.4.1

Rescue and Protection of Personnel 2.4.1.1

* CHANGE

** ADDITION

The first objective of this plan is the preservation and protection of human life. In the event that there are any injured or dead, the drilling or workover foreman on the rig, or the Production Superintendent of the area, if no rig is involved,

NEW INSTRUCTION

COMPLETE REVISION

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SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

DRILLING & WORKOVER OPERATIONS DEPARTMENT DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

1851.001 ISSUE DATE

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will be responsible for obtaining emergency treatment and helicopter/marine 00transportation. This will be done by notifying medical services when calling the emergency number 110. He should state the number of injuries and/or deaths. Search and rescue efforts will be coordinated between the Rig Foreman, the Marine Rig Move Coordinator, Offshore Security and Aviation. In addition, the Rig Foreman should contact the Marine Rig Move Coordinator for any advice and assistance not covered by this instruction.

*

*

* *

* CHANGE

2.5

The rig standby vessel(s) will receive instructions directly from the rig. If a major problem on the rig is obvious, the vessel master(s) shall prepare to render immediate assistance by maintaining an appropriate position upwind of the rig with all available engines running, unless specifically ordered otherwise by the rig.

2.4.1.3

Helicopters and boats will be dispatched for assistance and deployment in search and rescue efforts as required.

2.4.1.4

Concurrent with the dispatch of helicopters/boats, the Medical Chief for Emergency Services will be alerted to dispatch Medical Evacuation Team(s) to assist in transporting and to prepare for handling the injured.

2.4.1.5

Next of kin of the dead, missing or injured will be notified by the Personnel Department, with the assistance, if required, of the Manager, Drilling and Workover Operations if the dead, missing or injured person is a Drilling and Workover Operations employee.

2.4.1.6

The Rig Foreman shall contact the Tanajib Toolhouse to begin coordination of supply vessels and materials.

2.4.2

A "Notice to Mariners" should be broadcast immediately by the Marine Shift Coordinator.

2.4.3

The drilling/workover Foreman or senior drilling representative will designate a team to immediately begin monitoring the area for flammable gas and hydrogen sulfide (H2S) or other potential hazards.

2.4.4

Persons in any endangered area near the emergency site will be alerted and/or evacuated. The drilling/workover Foreman is responsible for personnel on the rig while the rig is working on a well. The Producing Superintendent, working closely with the Marine Department, will be responsible for alerting and evacuating personnel from the platform.

*

*

2.4.1.2

Safeguarding of Company Property 2.5.1

Northern Area Marine Offshore Operation Division will dispatch pollution control boats as quickly as possible.

2.5.2

Northern Area Marine Offshore Operation Division will dispatch fire fighting vessels when called upon. Large volumes of seawater will be spread to reduce the ignition potentials (if the platform /well in not on fire) or to cool the platform and protect wellheads of other wells if the blowout should ignite. Dispersant will be added to the water streams if necessary.

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

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SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

DRILLING & WORKOVER OPERATIONS DEPARTMENT DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

1851.001 ISSUE DATE

REPLACES

03/16/1999 APPROVAL

MYR

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**

2.5.3

Aviation Department may be requested to provide an Air Tractor to assist in containing the oil spill if the need arises.

*

2.5.4

Forecasts of tide, wind and other weather conditions that will affect the direction in spread of hazardous discharges can be obtained from the Saudi Aramco Intranet on a 24hour basis. The Disaster Control Center will provide up-to-date weather forecast information to the site leader or commander.

2.6

Well Control The Site Leader of the Well Control Team (with rig on well) or Special Well Action Team (without rig on well) will supervise the on-site well control operations. No other leader or site commander, designated by a different organization, will have the authority to interfere or take charge.

*

2.7

Ignition Should uncontrolled flow from a well occur without being accidentally ignited, the decision to ignite will be made on a case-by-case basis after evaluating all the facts. Since the impact of intentional ignition on an offshore platform can be significant, it is imperative that the decision to ignite be made by Management of Drilling and Producing organizations.

3.0

ORGANIZATION

*

The organization for the Well Control Contingency Plan is described in Appendix III. Personnel assigned to the organization will be relieved of current responsibilities by other personnel who will carry on regular Company business.

*

3.1

In the event that the well has a drilling or workover rig on it, the Manager of Drilling and Workover Operations will be responsible for well control operations. He will appoint the Site Leader of the Well Control Team. The Well Control Team will consist of necessary drilling, and workover foreman and the rig crew of the rig on location. Support sevices such as the Special Well Action Team, will be provided as needed.

**

3.2

In the event that a well is turned over to Drilling and Workover by Producing, the Manager of Drilling and Workover Operations will again be responsible for well control operations. He will appoint the Site Leader of the Well Control Team. The Well Control Team will consist of the neccessary drilling and workover foreman and the rig crew of a nearby rig. Support services such as the Special Well Action Team, will be provided as needed.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

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SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

DRILLING & WORKOVER OPERATIONS DEPARTMENT DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

3.3

ISSUE DATE

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Prior to any rig move to drill or workover a well, the Drilling and Workover Manager, Superintendent or Foreman will contact the respective Producing counterpart and others that may have interest in the area in order to: -

4.0

1851.001

Ensure that the concerned Organizations are familiar with the responsibilities described in the Drilling & Workover Contingency Plan in case of a disaster, Establish a contact point in case the Contingency Disaster Plan has to be activated. This communication channel will serve as the information pipeline to keep Producing Operations abreast of the latest developments, and to request for assistance if required.

WELL CONTROL: The Site Leader of the Well Control Team will work closely with the respective Manager and the General Manager, Drilling and Workover. He will participate in the immediate evaluation of the emergency to determine the plan for control of the well.

5.0

RESTORATION OR ABANDONMENT OPERATIONS: As a well is brought under control, safety equipment will be installed. Debris must be removed and construction plans will be implemented to repair the site and return the well to its previous operating status. If necessary, the well will be abandoned

6.0 *

COST ACCOUNTING: Drilling and Workover, Planning & Accounting Services Unit, will obtain a special project number from the Finance and Insurance Claims Administrator, Treasurers Department, Dhahran, to accumulate costs related to the disaster. The Treasurers Department will determine the proper disposition of the costs accumulated in the SP.

*

The Planning and Accounting Services Unit of the Drilling and Workover Department will review the charges and make corrections or adjustments as necessary and issue a final financial cost report if required.

7.0

SUPPORT SERVICES: Support services provided by various departments as well as those performed by service companies will be coordinated by the Site Leader, Well Control Team and the Manager, Drilling and Workover Services. Each department providing a support service will be responsible for adequate preparation to provide prompt and efficient service during the emergency.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

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SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

8.0

DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

ISSUE DATE

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DOCUMENTING AND CRITIQUE Complete daily logs will be maintained from the time of the initial report and the activation of the emergency control organization. The responsible persons in the central emergency group Manager's control room (Room-200, Bldg. 3193) will act as liaison with all of the various groups to maintain continuous documentation of the emergency. A complete factual report of each day's activities will be maintained as permanent record. The final report shall be prepared by the Drilling and Workover Engineering Department and shall contain a complete record of facilities and wells involved, planning, decisions, photographs, etc. Upon completion of the final report, a critique will be held to evaluate all the causes, actions and reactions of the various phases up to the final restoration or disposition.

*

**

DRILLING & WORKOVER OPERATIONS DEPARTMENT

1851.001

9.0

* CHANGE

DISASTER DRILLS 9.1

Drilling and Workover will conduct an annual “Primary” rig emergency drill to better prepare for unexpected well disasters when they occur. This drill will be coordinated with the disaster plan drills of Northern Area Producing, Marine Department and other operating organizations so that all parties will become familiar with the respective responsibilities and response plans. By conducting joint drills, the response time to activate the disaster plans for a blowout will decrease, resulting in rapid control of the well. This Primary drill will require full mobilization of equipment and personnel.

9.2

Drilling and Workover will also conduct annual “ Secondary” rig emergency drills with each division of a Producing area. The “Secondary” drills will evaluate readiness to respond to a disaster and will require minimal mobilization of equipment and personnel.

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

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1851.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

ISSUE DATE

DRILLING & WORKOVER OPERATIONS DEPARTMENT

REPLACES

03/16/1999

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APPROVAL

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Recommended By: ________________________________

F. A. Al-Moosa General Manager, Drilling & Workover.

Concurred By:

__________________________

__________________________

A. A. Mohyiddin

H. J. Kassem

Manager, Marine Department

Manager, Loss Prevention Department

___________________________ Y. A. Al-Aiderous V. P. Northern Area Producing

__________________________

S. S. Raslan General Manager, Industrial Security

_______________________ Approved By: M. Y. Rafie V. P. Petroleum Engineering and Development

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

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SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

DRILLING & WORKOVER OPERATIONS DEPARTMENT DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

1851.001 ISSUE DATE

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APPENDIX I

APPENDIX I DUTIES AND RESPONSIBILITIES Many of the duties and responsibilities of the members of the Contingency Plan organization are listed in order to clarify the various functions. This list is not intended to describe all the actions necessary for any particular emergency. Vice President, Petroleum Engineering and Development * 1.

Assume executive authority over the well control emergency and report conditions and operating progress to the Executive Vice President or President.

2.

Advise Vice President, Government Affairs of statements for news release.

3.

Appoint investigating committee.

General Manager. Drilling and Workover 1.

Decide on activation of the Contingency Plan and formulate a plan for controlling the well.

2.

Make decision on ignition of well effluent, if required.

3.

Provide Vice President with details of well and field.

* 4.

Notify Vice President of Exploration.

Manager, Drilling and Workover operations 1.

Assume responsibilities for well control operations on wells involving drilling or workover rigs and wells turned over to Drilling and Workover by Producing.

2.

Advise staff that Contingency Plan has been activated.

3.

Provide support and direction to the Site Leader of the Well Control Team and advise if the decision on ignition must be made.

4.

Arrange for on-site inspection by Vice President and General Manager, Drilling and Workover.

Superintendent Drilling or Workover operations 1.

Notify Department Manager of the emergency.

2.

May act as Site Leader of the Well Control Team.

3.

Insure that the drilling/workover Foreman or senior drilling representative has designated a team to monitor the area for flammable gas and hydrogen sulfide (H2S) or other potential hazards.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

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SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

*

ISSUE DATE

DRILLING & WORKOVER OPERATIONS DEPARTMENT

REPLACES

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APPENDIX I Manager, Drilling and Workover Services 1.

Notify Government Affairs Representative.

2.

If necessary call

Boots & Coots

3.

(281) 931-8884 Fax No. (281) 931-8302 Telex No. 790-161 A/B BOOTSCOUTS HOU. or Neal Adams (713) 937-8320 Fax No. (713) 937-6503 Telex No. 701-106 Notify Department Managers of support services departments.

4.

Advise staff that Contingency Plan has been activated.

5.

Provide support to the Site Leader of the Well control Team.

6.

Arrange for on-site inspection by Vice President.

7.

Coordinate services provided by other department.

8.

Maintain the emergency equipment in a ready manner and arrange movement to Offshore Tanajib as required.

Superintendent, Drilling Equipment and Water Well Maintenance Division 1.

Send emergency well control equipment to Offshore Tanajib as required.

2.

Provide personnel to work in various locations as required.

Site Leader, Well Control Team I.

Participate in formulation of immediate plans to control the well.

2.

Advise Foreman (if a rig on the well) of immediate action to be taken.

3.

Assist with evacuation and rescue operation if needed.

4.

Advise staff that Contingency Plan has been activated.

5.

Proceed to location and take the position of Site Leader.

6.

Maintain on-scene control and keep Manager advised of any change in condition.

7.

Contact Superintendent, Dhahran Area Loss Prevention or Supervisor, L. P. Exploration & Development Unit and arrange for site coverage, as required.

8.

Set up security as required.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

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ISSUE DATE

DRILLING & WORKOVER OPERATIONS DEPARTMENT

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APPENDIX I Accounting Services I

Maintain a record of costs incurred and appropriate documentation as directed.

2.

Maintain inventory of all Equipment and Materials delivered to disaster site.

Superintendent, Drilling Rig support Division 1.

Obtains all materials and equipment needed for use at the disaster site.

2.

Coordinate with Transportation to ensure prompt delivery of materials and equipment.

* Government Affairs Representative Notify Government officials of situation. All communications will be cleared through Vice President, Petroleum Engineering Development. Manager, Drilling and Workover Engineering Department 1.

Inform Manager, Reservoir Engineering Department of situation and conditions. Obtain relevant well data including: (a)

Bottom-hole pressure, productivity index, water cut and oil-water contact.

(b)

Preferred relief well drilling locations subject to wind and terrain considerations.

(c)

Preferred intercept interval.

(d).

Contour dip and strike.

2.

Request computer flow rate and pressure profile-calculations to be run for given conditions.

3.

Transmit copies of well configuration sketch, wellhead drawing, Morning Reports, and other pertinent documentation to the General Manager, Petroleum Engineering, General Manager, Drilling and Workover and to the Vice President, Petroleum Engineering and Development.

4.

Assemble well data and distribute copies as required. Include drilling program, well cross-sectional sketch, bottom-hole pressure and directional survey data, reports, known information - formation tops, final elevation etc.

5.

Have large-scale sketch (flip chart size) of well configuration prepared for use in review meetings. Denote casing sizes/depths, drill string configuration, formation tops, hole problems encountered and other relevant information which may be of use.

6.

Designate qualified and experienced engineer(s) to go to the wellsite to:

* CHANGE

(a)

Keep accurate log of on-site operations and well/environmental/weather conditions.

(b)

Assist technically as required. ** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

Saudi Aramco 7180 (5/89) G.I. NUMBER

1851.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

ISSUE DATE

DRILLING & WORKOVER OPERATIONS DEPARTMENT

REPLACES

03/16/1999

DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

APPROVAL

MYR

Approved

12 /96 PAGE NUMBER

11

OF

13

7.

APPENDIX I Prepare kill program including fluid type, density and pumping rates.

8.

Review available rig(s) to drill relief well(s). Recommend rig(s) from optimum technical viewpoint.

9.

Once survey location(s) for relief well(s) are received, prepare directional drilling program.

10.

Monitor drilling progress on relief well(s) and provide technical liaison among engineering services group(s) and operations.

11.

Prepare relief well kill program(s).

12.

Prepare management reviews of progresses required.

* CHANGE

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

Saudi Aramco 7180 (5/89) G.I. NUMBER

1851.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG.

ISSUE DATE

DRILLING & WORKOVER OPERATIONS DEPARTMENT

REPLACES

03/16/1999

DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

SUBJECT:

APPROVAL

MYR

Approved

12 /96 PAGE NUMBER

12

OF

13

APPENDIX II

APPENDIX II DUTIES AND RESPONSIBILITIES OF SUPPORT SERVICES DEPARTMENTS Marine *

1.

Provide marine transportation, communication, offshore fire fighting to combat oil pollution, and support as necessary.

Communications 1.

Implement communications system at Disaster Control Center.

2.

Provide for maintenance of system on the scene and at control center.

3.

Monitor system to see that it is functioning properly.

Aviation 1.

Provide emergency transportation for evacuation.

2.

Aerial surveillance for security and well conditions.

3.

Provide for movement of authorized personnel and materials.

Land Transportation 1. *

Provide for movement of materials and equipment.

Loss Prevention 1.

Provide Personnel at the well site and Disaster Control Center to advise the site leader or commander on safety related issues.

Security

**

1. 2. 3. 4. Medical 1.

Assist in the marine evacuation of personnel using Security Patrol Boats as directed by the Disaster Control Center. Assist in the marine search and rescue operations as directed by the Disaster Control Center. Keep the disaster area clear of any Saudi Aramco, Contractor or local fishing boats. Coordinate with Northern Area Government Affairs and other Government Agencies. Provide emergency medical services as required on-scene and at clinic(s).

Community Services 1. *

Provide accommodation and food services as needed.

Producing 1. 2. 3.

* CHANGE

Handle all liaison with oil dispatcher, plants pipelines and other groups concernedl with oil movements. Coordinate with the Site Leader of the Well Control Team on all activities within the field. Supervise all shut-in and start-up activities of nearby wells when the need arises.

** ADDITION

NEW INSTRUCTION

COMPLETE REVISION

13

Saudi Aramco 7180 (5/89) G.I. NUMBER

1851.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL ISSUING ORG. SUBJECT:

ISSUE DATE

DRILLING & WORKOVER OPERATIONS DEPARTMENT DRILLING AND WORKOVER OPERATIONS OFFSHORE CONTINGENCY PLAN

Approved

REPLACES

03/16/1999

12 /96

APPROVAL

PAGE NUMBER

MYR

13

OF

13

APPENDIX III

APPENDIX III APPENDIX III ORGANIZATION CHART

PETROLEUM ENGINEERING & DEVELOPMENT VICE PRESIDENT GOV’T AFFAIRS

PETROLEUM ENGINEERING GENERAL MANAGER

DRILLING & WORKOVER GENERAL MANAGER * DRLG & WKVR SVCS DEPT MANAGER

DRLG & WKVR ENGR DEPT MANAGER

DRLG EQPT & WTR WELL MTCE DIV SUPERINTENDENT

DRLG RIG SUPP DIV SUPERINTENDENT

ACCT SERVICES SUPERVISER

* CHANGE

** ADDITION

DEV. DRILL & OFFSHORE WORKOVER DEPT. MANAGER

PROD ENGR DEPARTMENT MANAGER,NAPE

RESVR MGMT DEPARTMENT MANGER

WELL CONT TEAM SITE LEADER

SPECIAL WELL ACTION TEAM

WELL CONTROL TEAM

SUPPORT SERVICES

NEW INSTRUCTION

COMPLETE REVISION

13

Saudi Aramco 7180 (5/89) G.I. NUMBER

1852.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT:

RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT

REPLACES

03/10/1999 APPROVAL

FAM

Approved

NEW PAGE NUMBER

1

OF

2

CONTENT: This General Instruction contains policy for equipping a rig with a Flare Gun and standard Communication Equipment. 1. OBJECTIVE 2. BACKGROUND 3. FLARE GUN 4. COMMUNICATION EQUIPMENT

1.0

OBJECTIVE The purpose of this policy is to ensure that every rig is fully equipped with a Flare Gun and Communication Equipment in case of an uncontrolled surface well flow (blowout) or other emergency.

2.0

3.0

BACKGROUND 2.1

During Drilling and Workover operations, with a rig on the well, an uncontrolled surface flow (blowout) may occur, requiring immediate ignition of the well effluent to protect human life and company assets. In such a case, a Flare Gun is fired to ignite the effluent before spreading.

2.2

During the blowout emergency, it becomes imperative to have reliable means of communication at the rig site and with headquarters, especially when all power is turned off at the well site to avoid uncontrolled ignition. The use of mobile car radios and portable communication devices (such as Walkie-Talkies) become essential in effective transmittal of instructions and expedient control of the well.

FLARE GUN Drilling & Workover will have a Flare Gun on each rig site, as well as a box of at least 24 cartridges with long shelf life. The Flare Gun and cartridges will be locked up in a clearly marked wooden box in the Foreman's office, and the location of the key will be known only to the Foreman and the rig Contract Supervisor. The Foreman and Contract Supervisor should be proficient in operation of the Flare Gun.

* CHANGE

** ADDITION

NEW INSTRUCTION X

COMPLETE REVISION

2

Saudi Aramco 7180 (5/89) G.I. NUMBER

1852.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT:

RIG SITE FLARE GUN AND COMMUNICATION EQUIPMENT

FAM

4.0

REPLACES

03/10/1999 APPROVAL

Approved

NEW PAGE NUMBER

2

OF

2

COMMUNICATION EQUIPMENT 4.1

Mobile Radio Drilling & Workover and Computer & Communications Services Department will work together to forecast, acquire and install a single side-band mobile radio in every rig Foreman's vehicle to provide the capability to communicate with the Superintendent in case of an emergency. The radio will only be used when at a safe distance from the well site in case of unignited hydrocarbon accumulation since the vehicle and radio are both sources of ignition.

4.2

Walkie-Talkie Drilling & Workover and Computer & Communications Services Department will work together to forecast and acquire at least two portable communication devices, such as WalkieTalkies. The devices are needed on every rig site during an emergency or critical operation. The portable communication devices will be locked up in a clearly marked wooden box in the Foreman’s office, and the location of the key will be known only to the Foreman and the Rig Contract Supervisor. The Foreman is responsible for the proper operation and charging of the devices. The Walkie-Talkies must be rated for use in Class I, Div. I electrically classified areas (i.e. explosion proof).

Approved by:

F. A. Al-Moosa General Manager, Drilling and Workover.

N. H. Al-Rabeh Manager, Computer and Communications Services Department.

* CHANGE

** ADDITION

NEW INSTRUCTION X

COMPLETE REVISION

2

Saudi Aramco 7180 (5/89) G.I. NUMBER

1853.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT:

ISOLATION BARRIERS FOR WELLS DURING DRILLING & WORKOVER OPERATIONS (WITH AND WITHOUT RIG)

REPLACES

02/14/1999 APPROVAL

MYR

Approved

NEW PAGE NUMBER

1

OF

5

CONTENT: This document contains instructions for providing adequate isolation barriers (or shut-offs) when removing surface control equipment while drilling or working over wells. These instructions are also applicable for well repair work, performed by the Drilling & Workover organization without a rig on location. 1. OBJECTIVE 2. BACKGROUND 3. MINIMUM REQUIREMENT 4. TYPES OF ISOLATION BARRIERS 5. RELIABILITY OF ISOLATION BARRIER 6. WAIVER

1.0

OBJECTIVE: The purpose of this GI is to ensure safe operations during drilling and well repair work by strict compliance to the guidelines. Short cuts to compromise these guidelines will not be permitted unless a waiver is obtained from the Vice President of Petroleum Engineering & Development or designated representatives.

2.0

BACKGROUND: When drilling or working over wells, with or without a rig, situations arise where surface equipment such as Blow Out Preventers (BOPs), wellheads, master valves and trees have to be removed for various reasons. In these situations, surface well control is temporarily removed and is substituted with downhole isolation barriers so that the reservoir pressure is isolated and work can continue around the wellhead safely. More than one isolation barrier or shut-off is normally required in certain wells in case of unexpected failure of the primary barrier. Adequate back-up barriers reduce the chances of uncontrolled surface flow (blowout) and costly repair work.

3.0

MINIMUM REQUIREMENT: The following guidelines will apply at all times unless a waiver has been obtained from Management (as described in paragraph 6.2). The mandatory number of barriers or shut-offs in each case is the minimum; any additional barriers are optional, dictated by the well condition and downhole completion equipment. 3.1

Oil Wells (GOR less than 850 scf/bbl) 2 shut-offs, one of which is mechanical.

* CHANGE

** ADDITION

NEW INSTRUCTION X

COMPLETE REVISION

5

Saudi Aramco 7180 (5/89) G.I. NUMBER

1853.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT:

ISOLATION BARRIERS FOR WELLS DURING DRILLING & WORKOVER OPERATIONS (WITH AND WITHOUT RIG)

3.2

REPLACES

02/14/1999 APPROVAL

MYR

Approved

NEW PAGE NUMBER

2

OF

5

Oil Wells (GOR more than 850 scf/bbl) 3 shut-offs, two of which are mechanical. Note:

3.3

For tubing and packer completed wells, the 3 shut-off guideline is applicable to the tubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus (tubing hanger and packer seals). If one of the two shut-offs is deemed to be ineffective or questionable, then the annulus will have to be filled with overbalanced kill fluid to act as a reliable shut-off.

Water Injection Wells - If positive WH pressure, 2 shut-offs are required, one of which is mechanical. - If no WH pressure, 1 shut-off is required. Note:

3.4

It is acceptable to nipple up or nipple down the BOPs on top of the injection tree by only closing the 10" ball valve. No additional shut-offs are required as long as the tree was never removed or the tree has been pressure tested after nippling up.

Gas Wells 3 shut-offs, two of which are mechanical. Note:

3.5

For tubing and packer completed wells, the 3 shut-off guideline is applicable to the tubing only. A minimum of 2 shut-offs is required for the tubing-casing annulus (tubing hanger and packer seals). If one of the two shut-offs is deemed to be ineffective or questionable, then the annulus will have to be filled with overbalanced kill fluid to act as a reliable shut-off.

Water Supply Wells (with or without submersible pump) - If well flows to surface, 1 shut-off is required. - If well does not flow to surface, no shut-off is required.

4.0

TYPES OF ISOLATION BARRIERS: 4.1

* CHANGE

A number of acceptable isolation barriers or shut-off alternatives are available and can be used under different operating conditions. These barriers can be separated into two main groups: Mechanical and Non-Mechanical.

** ADDITION

NEW INSTRUCTION X

COMPLETE REVISION

5

Saudi Aramco 7180 (5/89) G.I. NUMBER

1853.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT:

ISOLATION BARRIERS FOR WELLS DURING DRILLING & WORKOVER OPERATIONS (WITH AND WITHOUT RIG)

4.2

REPLACES

02/14/1999 APPROVAL

MYR

Approved

NEW PAGE NUMBER

3

OF

5

The following are examples of Mechanical and Non-Mechanical isolation barriers. The type of barrier to utilize will depend on the well condition and downhole completion equipment. These barriers include, but are not limited to: Mechanical: - Drillable or Retrievable Bridge Plug - Retrievable Tubing Plug - Back Pressure Valve - Valve Back-Seat - Surface Valve - Subsurface Safety Valve (SSSV) - Unperforated Casing Non-Mechanical: - Kill Fluid - Cement

5.0

RELIABILITY OF ISOLATION BARRIERS: 5.1

5.2

Equipment Testing 5.1.1

Vendor Testing: Prior to delivery of a new mechanical pressure isolation device, the vendor must conduct the required and appropriate hydrostatic pressure tests per Saudi Aramco Materials System Specification (SAMSS) to insure that the device meets design specifications.

5.1.2

Field-Testing: Whenever a mechanical isolation barrier is installed in a well, every effort should be made to field test and insure the barrier is holding. Since plugs are designed to hold pressure from above, below or from both directions, the field test should be designed according to the plug functionality.

Kill Fluid 5.2.1

* CHANGE

A kill fluid can be used as one of the isolation barriers as mentioned in section 4.2 above. In order for the kill fluid to be effective as an isolation barrier, two conditions must be met: a)

The hydrostatic pressure of the kill fluid column must exceed the reservoir pressure.

b)

The wellbore kill fluid must remain static at surface for a period of time ( as per item 5.2.2 below) to insure the presence of a competent barrier.

** ADDITION

NEW INSTRUCTION X

COMPLETE REVISION

5

Saudi Aramco 7180 (5/89) G.I. NUMBER

1853.001

SAUDI ARABIAN OIL COMPANY (Saudi Aramco) GENERAL INSTRUCTION MANUAL

ISSUE DATE

ISSUING ORG.

DRILLING & WORKOVER

SUBJECT:

ISOLATION BARRIERS FOR WELLS DURING DRILLING & WORKOVER OPERATIONS (WITH AND WITHOUT RIG)

5.2.2

MYR

NEW PAGE NUMBER

4

OF

1 hour 2 hour 3 hours 1 hour 30 minutes

WAIVER: 6.1

The above instructions will be mandatory when drilling or working over a well (with or without a rig) by the Drilling & Workover organizations, unless prior management approval has been secured. A written waiver to divert from the established guidelines must be obtained when an unusual well situation dictates the need for fewer barriers than stipulated. Obtaining a waiver to reduce the number of isolation barriers or shut-offs is highly discouraged and should only be considered when there are no other alternatives.

6.2

The waiver will be requested by submitting Waiver Request Form Waiver - 01 (see Appendix I) documenting the well situation, explaining why a waiver is necessary and explaining the impact of the waiver. Waiver signature approval level will be Vice President of Petroleum Engineering & Development or designated representaive.

Recommende by:

F. A. Al-Moosa General Manager, Drilling and Workover

Approved by:

M. Y. Rafie Vice President, Petroleum Engineering & Development

* CHANGE

5

The following are the minimum mandatory observation times for a kill fluid to be declared static: Oil Well (GOR less than 850 scf/bbl): Oil Well (GOR more than 850 scf/bbl): Gas Well Water Injector Water Supply Well

6.0

REPLACES

02/14/1999 APPROVAL

Approved

** ADDITION

NEW INSTRUCTION X

COMPLETE REVISION

5

Appendix I

GI 1853.001 Page 5 of 5

WAIVER REQUEST FOR ISOLATION BARRIER Date Requested

Waiver Request #

Saudi Aramco Form: Waiver 01(10/98) Well Name & Number

Plant #

Facility Connected to

Include number, paragraph, and issue date of this affected GI

Waiver requested

Y

N

After-the-Fact Justification (Include discussion of impact assessment)

Impact Assessment

W A I V E R

O R G I N A T O R

Y

N

Financial Impact

Safety Impact

Discuss under Justification Alternatives to waiving requirements

Originating Organization

(Originator's Name)

(Signature)

Date

Phone: Originator's Supervisor

(Signature)

Date

Phone

A P P R O V A L

REMARKS

Vice President or Designated Representative

Name

Signature

Date

Saudi Aramco Forms

Saudi Aramco Forms

Saudi Aramco Forms

Saudi Aramco Forms

Saudi Aramco Forms

Saudi Aramco Forms

Saudi Aramco Forms

Saudi Aramco Forms

Saudi Aramco Forms

WELL ACCOUNT CHARGE NUMBER 13 DIGITS 66-50125-065-299

66

-

WELL TYPE

50 FIELD CODE (Table 1)

125

-

0

WELL NUMBER W Supply 800-999 Others 1-799

65 TYPE OF WORK (Table 2)

NOT USED BY DRLG Always 0

58 59 61 62 63 64 65 66 75

Drilling done for other organization Offshore Workover of a non-producer well Onshore Workover of a producer well Water Supply well for water injection Water Supply well for drilling support Offshore Workover of a producer well Onshore Workover of a non-producer well Devclopmcnt Wells (other than water wells) Exploration Wells (other than water wells)

299

DESCRIPTION OF COST 100-199 S.Aramco Labor 200-299 Materials 400-699 Support Services 800-998 Rc-Allocation Cost

WELL ACCOUNT CHARGE NUMBER

Table 1 Development Accounting Location Code ACCT. CODE 01 02 04 05 06 07 08 09 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 30 31 32 33 34 36 38 39 40 41 42 44 47 48

FIELD CODE FRHH FRDH SMIN LGFH MGRB HAMR SAHB WIBN DHRN DMMM QTIF SFNY ABHD KRSN MNIF SFNY FDHL ABSF LAYL HABA ABMK HSBH BRRI BRRI MNIF LWHH DBDB RSTR SUBN SHRR SDWI JDLI HBRI QTIF HRUR HRQS UMJF WRIH RGHB DHYN DHIB

FIELD NAME Farhan Faridah Samin Lughfah Magrhib Hamur (Offs) Sahba Watban Dhahran Dammam Qatif Safaniya (Offs) Abu-Hadriya Khursaniyah Manifa (Offs) Safaniyah (Ons) Fadhili Abu Safah (Offs) Layla El Haba Abu-Markah Hasbah (Offs) Berri (Off) Berri (Ons) Manifah (Offs) Lawhah(Offs) Dibdibah Ras Tanura Suban Sharar Sadawi Jaladi Habari Qtif (Offs) Haruri Harqus (Offs) Umm Jurf Wari’ah Raghib Duhaynah Dhib

ACCT CODE 49 50 51 52 53 54 55 56 57 58 59 60 62 65 66 67 68 69 70 71 72 73 76 77 78 79 81 82 83 85 86 87 88 90 91 92 93 95 96 97 98

FIELD CODE JAWB ABQQ KHRS SUHL HWYH SDGM FZRN ANDR UIMN HRDH DILAM ABU-Rakiz ZULF (Offs) HWTH KIDN KARN NYYM JAUF UYRS JRBT SHYB MRJN HZMY RMLH UTMN ZUML HLWH GHNH MDYN HRML MZIJ AB]F NSLH AMAD Q1RD MAQL MHRH RMTN TINT BAKR KRYN

FIELD NAME Jawb Abqaiq Khurais Suhul Hawiyah~Ghwr Shedgum-Ghwr Fazran-Ghwr Aindar-Ghwr Uthmaniyah-Ghwr Hardh-Ghwr Dilam Abu-Rakiz Zuluf t•fli') Hawtah Kidan Karan Nuayyim Jauf Uhayrish Juraibi’at Shaybah Marjan (Offs) Hazmiyah Ramlah Uthmaniyah (1000+) Zumul Hilwah Ghinah Midyan Harmaliyah Mazalij Abu Jifan Nislah Amad Oirdi Ma'aqla Meharah (Offs) Rimthan Tinat Bakr Kurayn (Offs)

WELL ACCOUNT CHARGE NUMBER Table 2 Item Number Description

ITEM NUMBER 10 I1 12 13 14 15 16 17 19 40 41 42 43 44 46 47 49 SO 51 52 S3 S4 SS 63 64 65 66 67 68 73 74 78 79 84 89 90

DESCRIPTION Contractor Rig Move Contractor Camp Move Contractor Rig Operation - Modified Day Rate Contractor Rig Operation - Footage Bonus Contractor Rig Operation – Daywork Rate Contractor Rig Operation - Downtime Rate Contractor Camp – Saudi-Aramco Accommodation Other Contractor Cost (On wells drilled by Contractors) Other Contractor Cost (On wells drilled to Saudi-Aramco) Location Work Roads Aramco Rig Move (Aramco Charges) Special Rig Up/Rig Down Water Supply Equipment Hauling And Handling Transportation Drilling and Coring Bits Cement Handling and Pumping Cement and Additives Drilling Fluids Welihead Equipment Well pipe and Downhole Equipment Intangible Costs Contractor Invoices Costs Testing Acidizing Logging and Perforating Nitrogen and associated pumping charges Coil Tubing and antler associated charges Technical Services Rig Operations and Drilling Overhead Demobilization Mobilization Camp Operations - Drilling Drilling Equipment Depreciation Development Seismic Activity

SAFETY REQUIREMENTS FOR DRILLING & WORKOVER RIGS

Revised, updated, and re-issued by the Drilling and Workover Operations Departments, Saudi Aramco

REVISED June 2006

Safety Requirements for Drilling & Workover 2 of 82 Rev: June 2006

SAFETY REQUIREMENTS FOR DRILLING & WORKOVER RIGS

© COPYRIGHT 2006 SAUDI ARABIAN OIL COMPANY (SAUDI ARAMCO)

All rights reserved. No part of this book may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, recording, or any information storage and retrieval system, without permission in writing from the Saudi Arabian Oil Company (Saudi Aramco).

Safety Requirements for Drilling & Workover 3 of 82 Rev: June 2006

TABLE OF CONTENTS Page # DRILLING & WORKOVER MANAGEMENT LOSS PREVENTION POLICY STATEMENT …………………………….. 08

SECTION A-INTRODUCTION A-1

Objectives of this Safety Manual ……………………………………… 09

A-2

Definitions ……………………………………………………………….. 09

A-3

Reference Material ………………………………………………………

A-4

Glossary of Abbreviations ……………………………………………… 13

A-5

Rig Operator’s Responsibilities for Loss Prevention ………….……… 13

A-6

Inspection and Preventive Maintenance ………………………………. 15

SECTION B-GENERAL B-1

Medical …………………………………………………………………… 16

B-2

Communications ………………………………………………………… 17

B-3

Personal Protective Equipment ………………………………………… 17

B-4

Clothing ………………………………………………………………….. 19

B-5

Respiratory Protection ………………………………………………….. 19

B-6

Hydrogen Sulfide Safety ……………………………………………….. 24

B-7

Housekeeping ……………………………………………………………. 34

B-8

Rig Camps: Kitchens and Accommodations …………………………. 35

B-9

Fire Extinguishing Equipment …………………………………………. 35

B-10

Truck Loading and Unloading …………………………………………. 38

B-11

Fuel Tanks ………………………………………………………………. 38

B-12

Bulk Storage Tanks ..……………………………………………………. 38

B-13

Control of Static Electricity ……………………………………………. 39

B-14

Handling and Storage of Compressed Gas Cylinders ………………… 39 Safety Requirements for Drilling & Workover 4 of 82

Rev: June 2006

B-15

Electric Wiring and Equipment ……………………………………….. 39

B-16

Illumination .. …………………………………………………………… 41

B-17

Tools -- Hand and Power …………………………………………..…… 41

B-18

Abrasive Wheel Machinery …………………………………………….. 42

B-19

Welding and Cutting ……………………………………………………. 43

B-20

Air Compressors ………………………………………………………… 46

B-21

Hot Work ………………………………………………………………… 47

B-22

Lockouts and Tagging …………………………………………………... 47

B-23

Confined Spaces …………………………………………………….…… 47

B-24

Use of Potentially Hazardous Chemicals ……………………………… 49

SECTION C-RIG EQUIPMENT AND PROCEDURES C-1

Spudding In ………………………………………………………….…... 50

C-2

Derricks and Masts ……………………………………………………... 50

C-3

Anchoring – Alterations ………………………………………………… 51

C-4

Crown Blocks …………………………………………………………… 51

C-5

Traveling Blocks . ………………………………………………………. 51

C-6

Auxiliary Escape ………………………………………………………… 52

C-7

Guards …………………………………………………………………… 52

C-8

Derrick Exits, Ladders, Stairways, Floors, and Platforms …………………………………………………………… 53

C-9

Pipe Racks ………………………………………………………………. 55

C-10 Pipe Handling …………………………………………………………… 55 C-11 Drawworks Controls . …………………………………………………... 56 C-12 Brake …………………………………………………………………….. 57 C-13 Rotary Table ….…………………………………………………………. 57 C-14 Cathead Lines and Spinning Chains ………………………………….. 57 C-15 Spinning, Hoisting and Rotary Operations …………………………… 58 C-16 Slips ……………………………………………………………………… 58 C-17 Hoisting Lines …………………………………………………………… 59 Safety Requirements for Drilling & Workover 5 of 82 Rev: June 2006

C-18 Riding Hoisting Equipment ……………………………………………. 60 C-19 Elevators ………………………………………………………………… 61 C-20 Manual Tongs …………………………………………………………… 61 C-21 Tong Counterweights …………………………………………………… 62 C-22 Making Up and Breaking Joints ……………………………………….. 62 C-23 Mud Bucket or Saver …………………………………………………… 63 C-24 Power Tongs …………………………………………………………….. 63 C-25 Racking Pipe in Derricks ……………………………………………….. 63 C-26 Finger Boards . ………………………………………………………….. 63 C-27 Stabbing Platforms and Boards ………………………………………... 64 C-28 Safety Belts and Harnesses ……………………………………………... 65 C-29 Blowout Preventors ……………………………………………………… 65 C-30

Safety Valves ……………………………………………………………. 67

C-31 Weight Indicators ………………………………………………………. 67 C-32 Test Plugs ………………………………………………………………… 67 C-33 Rig Tanks or Pit Enclosures …………………………………………… 67 C-34 Pressure Relief Devices, Rig Mud Pumps, Piping, and Hoses ……………………………………………………….. 68 C-35 Cellars …………………………………………………………………… 69

SECTION D-SPECIAL OPERATIONS D-1

Crane Operations ……………………………………………………….. 70

D-2

Rigging, Material Handling and Slings ……………………………….. 72

D-3

Drill Stem Testing ………………………………………………………. 73

D-4

Swabbing ………………………………………………………………… 73

D-5

Cementing ……………………………………………………………….. 74

D-6

Well Servicing and Well Stimulation ………………………………….. 74

D-7

Stripping and Snubbing ……………………………………………….. 75

D-8

Flare Pits and Flare Lines ……………………………………..………

75

Safety Requirements for Drilling & Workover 6 of 82 Rev: June 2006

SECTION E-OFFSHORE E-1

Overwater Operations ………………………………………………… 76

E-2

Life Saving Equipment -- Offshore Rigs …………………………….. 77

E-3

Heliports and Helicopter Operations ………………………………… 80

E-4

Personnel Transfer: Boat and Rig ………………………………….… 82

Safety Requirements for Drilling & Workover 7 of 82 Rev: June 2006

SAUDI ARABIAN OIL COMPANY (SAUDI ARAMCO) DRILLING AND WORKOVER OPERATIONS DEPARTMENT LOSS PREVENTION POLICY STATEMENT The Drilling and Workover Organization is committed to the protection of Saudi Aramco resources against human distress and financial loss resulting from accidental occurrences. Reduced drilling/workover efficiency and property losses resulting from accidental occurrences can be controlled through good management. Loss prevention is one aspect of this process and is the direct responsibility of line management. To fulfill this commitment, we will provide and maintain a safe and healthy work environment as well as protect the public against foreseeable hazards resulting from our operations. All Saudi Aramco drilling and workover activities and functions, including onshore and offshore activities, will comply with Saudi Arab Government and Saudi Aramco loss prevention requirements as applied to the design, operation and maintenance of our facilities and equipment. If the application of any of these requirements is not practical a waiver will be sought. Reviews for compliance with this policy will be performed on a selective basis at regular intervals. Dedication and cooperation of all Saudi Aramco and Contractor personnel associated with drilling and workover is required and expected to fulfill this Loss Prevention commintment.

N.A. AL-AJMI, Manager (A)

J.D. LAYTON, Manager (A)

Development Drilling and Offshore W/O Department

Deep Drilling and Onshore W/O Dep.

___________________________________________

_________________________________

Z.A. AL-HUSSAIN, General Manager (AA) Drilling & Workover _______________________________________

Safety Requirements for Drilling & Workover 8 of 82 Rev: June 2006

SECTION A: INTRODUCTION A-1

OBJECTIVES OF THIS SAFETY MANUAL The objectives of this manual are to:

1.

Establish Saudi Aramco safety rules directly applicable to drilling and workover activities, and

2.

Establish a uniform and comprehensive set of safety requirements that are equally applicable to Contractor and Company-owned drilling and workover rigs.

A-2

DEFINITIONS

RIG OPERATOR: In this document, the term "RIG OPERATOR" means the agency or company responsible for operating any drilling or workover rig, and/or providing any drilling or workover rig services on behalf of the Saudi Arabian Oil Company (Saudi Aramco). COMPANY: The term, "COMPANY", as used throughout this document, shall be understood to mean the Saudi Arabian Oil Company (Saudi Aramco). It shall include the management of the Drilling and Workover Operations Departments of Article but can also include all other of management of Saudi Aramco. LOSS PREVENTION: The definition of the term, "LOSS PREVENTION," as used in these “Safety Requirements” is stated in the Saudi Aramco Corporate Loss Prevention Manual”: “Loss in productivity and property resulting from accidental occurrences that can be controlled through good management. Loss prevention is one aspect of this process and is the direct responsibility of line management.” The Dhahran Area Loss Prevention Division, Exploration, Development & Manufacturing Unit (ED&MU) has the responsibility for Loss prevention Department (LPD) technical assistance to the COMPANY, Drilling and Workover, Exploration and Petroleum Engineering organizations throughout the Kingdom of Saudi Arabia.

Safety Requirements for Drilling & Workover 9 of 82 Rev: June 2006

A-3

REFERENCE MATERIAL

In addition to this publication, the RIG OPERATOR shall have available for reference to drilling or workover personnel the most recent publications as follows:IADC

Drilling Manual

IADC

Accident Prevention

API SPEC 4A

Steel Derricks

API SPEC 4E

Drilling and Well Servicing Structures

API BULL 5C2

Performance Properties of Casing, Tubing, and Drill Pipe

API BULL 5C4

Round Thread Casing Joint Strength With Combined Internal Pressure and Bending

API SPEC 6A

Wellhead Equipment

API SPEC 7

Rotary Drilling Equipment

API SPEC 7 B-11C

Internal Combustion Reciprocating Engines For Oil Field Service

API RP 7G

Drill Stem Design And Operating Limits

API RP 7H

Drilling Machinery

API SPEC 8

Drilling and Production Hoisting Equipment

API RP 8B

Hoisting Tool Inspection and Maintenance Procedures

API SPEC 9A

Wire Rope

API RP 9B

Application, Care and Use of Wire Rope For Oil Fields

API SPEC 13A

Oil Well Drilling Fluid Materials

API BULL 13C

Drilling Fluid Processing Equipment

API RP 49

Recommended Practice for Safe Drilling of Wells Containing Hydrogen Sulfide

API RP 52

Recommended Land Drilling Operating Practices for Protection of the Environment

API RP 54

Recommended Practices for Occupational Safety and Health for Oil and Gas Drilling and Servicing Operation

API RP 500

Recommended Practice for Classification of Location for Electrical Installation at Petroleum Facilities.

API RP 2020

Safe Practices in Drilling Operations

ANSI Z88.2

American National Standard Practices for Respiratory Protection

Safety Requirements for Drilling & Workover 10 of 82 Rev: June 2006

ANSI Z89.1

Protective Headware for Industrial Workers - Requirements

ANSI Z41.83

Protective Footwear

G.I. 2.100

Work Permit System

G.I. 2.104

Leak and Spill Reporting - Arabian Gulf

G.I. 2.400

Offshore Oil Spill Contingency Plan

G.I. 2.401

Inland Oil Spill Contingency Plan

G.I. 6.012

Isolation, Lockout and Use of Hold Tags

G.I. 6.020

Personal Flotation Devices for Work Over, On or Near Water

G.I. 6.025

Control of Remote Area Travel and Search/Rescue Procedures

G.I. 8.003

Air Supplied Breathing Apparatus

G.I. 7.025

Mobile Heavy Equipment Operator Testing and Certification

G.I. 7.026

Cranes and Heavy Equipment Accident Reporting Procedures

G.I. 7.027

Personnel Work Platform Operations

G.I. 7.028

Heavy Crane Lift, Multiple/Tandem Crane Lift, etc.

G.I. 7.029

Inspection, Testing and Maintenance of Wire Rope Slings

G.I. 7.030

Inspection & Testing Requirements of Elevating/Lifting Equipment

G.I. 151.006

Implementing the Saudi Aramco Sanitary Code

G.I. 355.020

Control of Compressed Gas Cylinders.

G.I. 520.001

Confined Space Entry Procedures

G.I. 1780.001

Atmosphere-Supplying Respirators

G.I. 1781.001

Inspection and Maintenance of Fire Protection Equipment

G.I. 1850.001

Onshore Contingency Plan

G.I. 1851.001

Offshore Contingency Plan

G.I. 1852.001

Rig site Flare Gun and Communication Equipment

G.I. 1853.001

Isolation Barriers for Wells During Drilling & Workover Operations

Safety Requirements for Drilling & Workover 11 of 82 Rev: June 2006

Rig & Equipment Manufacturers

Operations and Maintenance Manuals for the Drilling Rig and Other Major Equipment Items

Saudi Aramco

Crane Safety Handbook

Saudi Aramco

Construction Safety Manual

Saudi Aramco

Safe Drilling and Workover Operations in Known or Suspected Hydrogen Sulfide Areas

Schedule ‘D”

Contractor’s Safety & Loss Prevention Requirements

SAES-A-103

Discharges to the Marine Environment

SAES-A-105

Noise Control

SAES-B-019

Portable, Mobile and Special Fixed Firefighting Equipment

SAES-B-062

Onshore Wellsite Safety

SAES-B-063

Aviation Obstruction Marketing and Lighting

SAES-B-067

Safety Identification and Color Coding

SAES-B-068

Electrtical Area Classification

SAES-B-069

Emergency Eyewashes and Showers

SAES-J-505

Combustile Gas and Hydrogen Sulfide in Air Detection Systems

SAES-L-070 Valves and Chokes

Technically Acceptable Manufacturers of API 6A 10000 PSI Gate

NOTE: ASSISTANCE IN OBTAINING COPIES OF THESE DOCUMENTS IS PROVIDED BY THE DHAHRAN AREA LOSS PREVENTION DIVISION - Westpark 3, Room 244A, Telephone 874-8419, Dhahran.

Safety Requirements for Drilling & Workover 12 of 82 Rev: June 2006

A-4

GLOSSARY OF ABBREVIATIONS

SAES

Saudi Aramco Engineering Standards

ANSI

American National Standards Institute

API

American Petroleum Institute

BOP

Blowout Preventer

G.I.

(Saudi Aramco) General Instruction

IADC

International Association of Drilling Contractors

MODU

Mobile Offshore Drilling Unit

NEC

(American) National Electrical Code

NFPA

(American) National Fire Protection Association

SCECO

Saudi Consolidated Electric Company

SCR

Silicon Controlled Rectifier

SWL

Safe Working Load (Limit)

UKDOT

United Kingdom Department of Trade

USCG

United States Coast Guard

A-5

RIG OPERATORS' RESPONSIBILITIES FOR LOSS PREVENTION

Throughout all phases of any drilling or workover operation the RIG OPERATOR will be held accountable for the prevention of accidental losses, the protection of COMPANY interests and resources, and the avoidance of any contamination of the environment. The following minimum guidelines are provided to aid the RIG OPERATOR in meeting this responsibility. Assistance in complying with the requirements set forth in these guidelines is available from Drilling and Workover Management or from the Loss Prevention Department of the COMPANY. 1. The RIG OPERATOR shall establish a written loss prevention program that fulfills all the requirements stated in this Manual. 2. Any loss prevention program of the RIG OPERATOR shall provide for frequent and regular inspections of the rig equipment, materials, and accommodations by competent persons designated by the RIG OPERATOR. This inspection shall be completed on a monthly basis and submitted to the COMPANY Drilling Superintendent with responsibility for the oversight of each rig.

Safety Requirements for Drilling & Workover 13 of 82 Rev: June 2006

3.

The RIG OPERATOR shall provide at each drilling and workover rig a copy of the reference materials (listed earlier on page 10) necessary for the safe operation of the rig.

4.

The RIG OPERATOR shall be thoroughly familiar with the drilling or workover program. He shall inform the rig crew of any potential adverse conditions (i.e., lost circulation zones, high reservoir pressure, high H2S concentrations, etc.) that require special safety precautions, training, equipment, or additional personnel.

5.

The RIG OPERATOR shall clearly indicate the "SMOKING PERMITTED" areas around each rig location. All other areas on the location will be considered as "NO SMOKING" areas and shall be marked accordingly. Smoking shall be closely controlled throughout the rig location.

6.

The RIG OPERATOR shall take all reasonable safety precautions to prevent oil spills or pollution both onshore and offshore. If an accidental spill or discharge does occur, every effort shall be made to (a) protect human life, including both employees and the public, and (b) minimize the impact on the environment. Should an accidental spill occur, it shall be reported immediately to the COMPANY representative so that he can take the necessary steps to contain the spill and implement the applicable reporting requirements of G.I. 2.104, G.I. 2.400, or G.I. 2.401.

7.

The RIG OPERATOR shall adequately train each of his employees in the recognition and avoidance of unsafe conditions and in all COMPANY loss prevention standards applicable to his work environment. He shall also adequately train his employees in methods to control or eliminate any hazards or other exposures resulting in injury or illness.

8.

The RIG OPERATOR's employees, who are required to handle or use poisons, caustics, acids and other harmful substances, shall be adequately trained regarding their safe handling and use. The RIG OPERATOR's supervisors shall discuss the potential hazards, personal hygiene, and necessary personal protective equipment prior to their employees handling any harmful materials. The RIG OPERATOR will maintain water stations for washing chemicals spills and Material Safety Data Sheets for all potentially hazardous chemicals the RIG OPERATOR orders onto the rig. Note: Saudi Aramco will supply MSDS for materials Saudi Aramco orders.

9.

The RIG OPERATOR shall allow only those personnel qualified by training and/or experience to operate equipment and machinery. The RIG OPERATOR shall also ensure that any personnel requiring operator's certificates have them, or copies thereof, in their possession and have completed any training which may be required by the laws of the Kingdom of Saudi Arabia or by the COMPANY.

10. RIG OPERATORS providing offshore rigs shall ensure that their rigs are kept in compliance with all applicable maritime/MODU standards of the country in which the rig is registered as well as any applicable laws and regulations of the Kingdom of Saudi Arabia or the COMPANY. 11. A RIG OPERATOR providing offshore rigs shall ensure that all required certifications are current and that re-certification inspections are completed by an approved certification authority prior to the expiration of the existing certificate. 12. On all offshore rigs, a copy of the Barge Marine Operations Manual shall be kept readily available in the control room for consultation and use. The manual shall Safety Requirements for Drilling & Workover 14 of 82 Rev: June 2006

include a complete set of operating instructions, control systems diagrams, and stability characteristics. 13. Any special or unusual towing characteristics of an offshore rig shall be included in the operating instructions and communicated to the towing vessel operators before towing operations begin. 14. A RIG OPERATOR providing offshore rigs shall ensure that all navigation and transit lights are operable and used as required by International Rules and Regulations for Aids to Navigation. 15. Should a conflict arise between a RIG OPERATOR's safety requirement and a COMPANY requirement, the most restrictive requirement shall apply. A-6

INSPECTION AND PREVENTIVE MAINTENANCE

The RIG OPERATOR is responsible for providing drilling or workover rig(s), including all auxiliary equipment, that is structurally and mechanically capable of performing according to the agreement between the RIG OPERATOR and the COMPANY. In order to assure the COMPANY that all equipment is in good working condition, the RIG OPERATOR shall conduct a physical inspection of its rig and all auxiliary equipment on a regular basis – no less than once per month. The RIG OPERATOR will implement a comprehensive preventive maintenance program to keep equipment in good working condition.

Safety Requirements for Drilling & Workover 15 of 82 Rev: June 2006

SECTION B: GENERAL B-1

MEDICAL

1.

Each RIG OPERATOR shall comply with the Saudi Arabian Ministry of Labor and Social Affairs Decision Number 404, dated 7 July 1974, entitled "First Aid Facilities at Work Sites". A copy of this document or an English language translation is available from the Drilling and Workover Operations Manager or from Dhahran Area Loss Prevention Exploration, Development & Manufacturing (ED&M) Unit.

2.

The RIG OPERATOR, with the assistance of the COMPANY as required, prior to the start of drilling or workover operations, shall identify the nearest trauma clinic or physician or hospital and shall make provisions for the PROMPT transportation of a victim of injury or sudden illness to the physician, hospital or clinic or to summon emergency medical personnel to the location. Also, prior to the start of operations, the COMPANY shall provide an effective communication system for contacting necessary medical and emergency agencies with written posted procedures for medical evacuation [Medivac].

3.

The RIG OPERATOR, with the assistance of the COMPANY as required, shall furnish to any person injured in his employment who is in need of medical attention immediate transportation to a hospital, physician, or clinic for the purpose of treatment.

4.

Telephone numbers of the physician, hospital, ambulance, and helicopter services shall be conspicuously posted in the COMPANY Representative’s office, Rig Manager's office, the rig medic station, and the radio room. These numbers shall be posted as soon as possible after moving to a new location.

5.

The vehicle or conveyance used for transport of the injured shall: (a)

Be of sufficient size and suitabe to accommodate a stretcher and accompanying person entirely within the body of the vehicle or conveyance.

(b)

Be clean and well maintained.

(c)

Protect the injured worker and the accompanying person.

(d)

Be designed and equipped such that verbal communication between the operator of the vehicle or conveyance and the injured worker or accompanying person is possible.

6.

When immediate transport of the injured is necessary and circumstances do not allow compliance with Item #5 (above), the senior supervisor at the site shall use any available means of suitable transportation.

7.

A reliable means of communication shall be provided by the company from the rig site to base of operations and other outside locations.

8.

The RIG OPERATOR shall provide at each rig, qualified medic on the rig, adequate first aid equipment and emergency treatment facilities.

9.

Each rig shall be equipped with two stretchers (Stokes, Navy, Scoop) with blankets and securing straps that are capable of being carried on the helicopter or transportation serving the rig. Safety Requirements for Drilling & Workover 16 of 82

Rev: June 2006

10.

While being transported, all victims shall be accompanied by the rig medic in addition to the driver or pilot. If a rig medic is not available, the accompanying person shall have valid up-to-date first aid certification.

11.

The RIG OPERATOR shall complete Saudi Arabian Government Form 11 for each of his injured employees requiring medical treatment and submit the completed form(s) within three days to the nearest Social Insurance Office. The RIG OPERATOR shall also comply with any other reports or investigations required by the laws of the Kingdom of Saudi Arabia. He shall advise the responsible Aramco Government Affairs Office of all pertinent information on a timely basis.

12.

All RIG OPERATOR employee injuries shall be reported promptly to the COMPANY Representative. A RIG OPERATOR accident/injury form will be completed at the rig site, reviewed by the COMPANY Representative and sent to the appropriate COMPANY Superintendent within 24 hours.

13.

Conduct Disaster Drills as specified in the procedures published by the company.

B-2

COMMUNICATIONS

1.

Reliable communications, radio and/or telephone, shall be maintained at all times between the rig and operations base. Offshore rigs must also be able to communicate with other rigs, helicopters, and vessels in the vicinity.

2.

On all offshore rigs, on-site communication shall be done using an intercom type system and necessary in an emergency must be provided by the RIG OPERATOR.

3.

Every rig shall be equipped with a general alarm system capable of providing an alarm audible throughout the entire installation. In areas of high noise levels, visual warning signals such as flashing lights shall be provided in addition to the audible alarms. The RIG OPERATOR shall ensure that visual warning signals are not screened or hidden by equipment, machinery, or structure.

4.

Each rig shall be equipped with a public address system capable of clearly transmitting emergency instructions.

5.

Both the general alarm system and the public address system shall be operable from the main control room and from other control positions on the installation.

6.

The general alarm and public address system shall be supplied with power from both the normal and emergency power supply.

B-3

PERSONAL PROTECTIVE EQUIPMENT

Personal protective equipment can never prevent an accident. It does, however, serve to minimize the effects of an accident if an accident does occur. The RIG OPERATOR is responsible to require the wearing of approved personal protective equipment at all times where its use could protect personnel. 1.

The RIG OPERATOR shall post warning signs in areas where the use of personal protective equipment is required. Safety Requirements for Drilling & Workover 17 of 82

Rev: June 2006

2.

Protective headgear and gloves shall be worn by all personnel working at a drilling or workover well site.

3.

Protective headgear shall meet or exceed the requirements of ANSI Z89.1. Metal hard hats are forbidden per Saudi Aramco Construction Safety Manual.

4.

Properly fitting goggles, face-shields, or other eye protection equipment appropriate to the work being done, shall be worn by all personnel who are handling or exposed to any material capable of causing injury or irritation to the eyes, or engaged in any work in which there is an eye hazard from flying objects, injurious light, heat rays, or radiation.

5.

Safety steel-toe boots or shoes shall be worn by all personnel when working on or about a drilling or workover rig as per ANSI Z41.83.

6.

The RIG OPERATOR shall provide, and all personnel will wear, suitable protective clothing and equipment including appropriate respiratory protection, when handling acids, caustics, or other harmful substances which are potentially injurious to the skin. Any rig employee handling dry mud material must wear adequate personal protective clothing, including proper eye and face protection. This requirement includes those personnel handling "super-sacks".

7.

The RIG OPERATOR shall ensure that, when the clothing or skin of any personnel becomes contaminated with any flammable or harmful substance, those exposed shall get in the shower and then remove their clothing and wash the affected part of the body. The clothing shall be decontaminated before re-use.

8.

The RIG OPERATOR shall provide hearing protection in areas where the noise levels are above 90 DBA. RIG OPERATOR shall post warning signs informing all personnel that hearing protection is required while working in that area.

9.

Hearing protection equipment, including head phone type hearing protection or soft ear plugs, shall be readily available to personnel working in high noise level areas.

10.

All personal protective equipment shall be kept in a sanitary condition and maintained to perform satisfactorily the function for which it was designed.

11.

The RIG OPERATOR shall provide emergency eye wash stations where necessary to provide immediate relief to any personnel who may be contaminated with a harmful substance. These eye wash stations shall be capable of providing a minimum of 15 minutes of fresh, clean water to irrigate eyes that have been contaminated by some hazardous material. The RIG OPERATOR shall maintain these eye wash stations in good condition continually ready for use per SAES-B-69, “Eye Wash Station and Showers”.

12.

The RIG OPERATOR shall post identification signs to mark the location of all emergency equipment such as emergency eye wash stations.

WORK SMART Your Personal Protective Equipment (PPE) is your final protection against accidents and injuries. Your special skills and safety attitude is your primary protection against accidents and injuries. Safety Requirements for Drilling & Workover 18 of 82 Rev: June 2006

B-4

CLOTHING

1.

The RIG OPERATOR shall ensure that all his personnel wear clothing suitable for the existing conditions and the work being performed. The RIG OPERATOR shall specifically prohibit his personnel from working without shirts or in short trousers.

2.

RIG OPERATOR personnel shall not unnecessarily expose any part of the body to substances which may be injurious to the skin.

3.

Where there is danger of contact with moving parts of machinery or in any work process where a similar hazard exists: (a) Close fitted clothing shall be worn, (b) Head and facial hair shall be completely confined or cut short, and (c) Dangling neckwear, jewelry, or other similar items shall not be worn.

B-5

RESPIRATORY PROTECTION

1.

The RIG OPERATOR shall ensure that all respiratory protection equipment, needed by or reasonably anticipated to be needed by his employees, is provided. Those employees required to use this equipment must be trained in its effective use. This training MUST include practice in the maintenance and use of this equipment. This equipment may be provided by the Contractor or by the COMPANY, depending upon the terms and conditions of the contract.

2.

The RIG OPERATOR shall ensure that the required respiratory protection equipment is maintained and used as intended, and that it provides all personnel with adequate protection against all anticipated hazardous atmospheres.

3.

Such respiratory protection equipment shall be readily available, maintained in good working order, in a sanitary condition, and inspected every 30 days per GI1780.001.

4.

Unless protected by respiratory protection equipment, no personnel shall be allowed to enter any area:

5.

6.

(a)

Where the oxygen content of the atmosphere is less than 20 per cent by volume, or

(b)

Where the atmosphere is contaminated or in danger of being contaminated by any airborne substance that may be considered to be harmful.

All respiratory protection equipment shall be supplied air apparatus in the form of: (a)

Self-Contained Breathing Apparatus (SCBA), or

(b)

Hose-line work masks, including an emergency escape cylinder.

On all drilling and workover rigs operating in known hydrogen sulfide areas or on any rig drilling a wildcat well, there shall be on each rig at least the minimum amount of respiratory protection equipment required in the drilling/workover contract. Safety Requirements for Drilling & Workover 19 of 82

Rev: June 2006

7.

Where respiratory protection equipment is or may be required to be worn in areas which are or may be contaminated with substances immediately dangerous to life or health, RIG OPERATOR shall ensure that excessive facial hair which prevents effective sealing of the face shall be removed.

8.

Refer to Section B-5, Appendix I for further information regarding Respiratory Protective Equipment.

Section B-5 Appendix I: REQUIREMENTS FOR MINIMAL ACCEPTABLE RESPIRATORY PROTECTION PROGRAM EACH RIG OPERATOR SHALL DEVELOPE AND PUT INTO PRACTICE A RESPIRATORY PROTECTION PROGRAM THAT MEETS OR EXCEEDS THE FOLLOWING CRITERIA AS PER G.I. 1780.001. 1.

Written standard operating procedures governing the selection and use of respiratory protective equipment shall be established.

2.

Respiratory protective equipment shall be selected on the basis of the hazards to which the worker is exposed. The airborne hazards most likely to be encountered in drilling and workover operations are: (a)

Immediately dangerous to life or health (IDLH) atmospheres that require the use of supplied-air respiratory protection equipment. This equipment includes the hose-line work masks, including an escape cylinder, and selfcontained breathing apparatus (SCBA). The most likely IDLH atmospheres that may be encountered at drilling and workover locations are: (1)

Toxic vapors and gases, such as H2S.

(2) Atmospheres containing less than 20 per cent oxygen, by volume. (b) 3.

4.

Corrosive or irritating particulate matter for which full-face filter mask protection is required. It is very important the proper filters be used.

The user shall be instructed and trained in the proper use of respiratory protective equipment and their limitations. This training must include: (a)

Instructions on the selection of the proper respiratory protection equipment for each potential hazard an employee may encounter.

(b)

Instructions in the wearing and use of this equipment. This training MUST include drills in which the equipment is used and worn under simulated emergency conditions. (BOP drills while wearing work masks, for instance.)

(c)

Proper cleaning and sanitizing of the equipment after it is worn and used. It is very important each user of this equipment understands how important it is to properly clean and sanitize this equipment after each wearing, even for equipment that may be permanently assigned to him.

Where possible, respiratory protective equipment should be assigned to individual workers for their exclusive use. Safety Requirements for Drilling & Workover 20 of 82

Rev: June 2006

5.

Respiratory protective equipment shall be regularly cleaned and disinfected. Those issued for the exclusive use of one worker should be cleaned after each day's use, or more often if necessary. Those used by more than one worker shall be thoroughly cleaned and disinfected after each use. Cleaning this equipment must be included in the training and use of the equipment. Aside from understanding how to use the equipment for maximum possible protection, cleaning is of paramount importantance.

6.

A log shall be maintained that documents the cleaning and maintenance of respiratory protective equipment.

7.

Respiratory protective equipment shall be stored in a convenient, clean and sanitary location. One practical method for keeping this equipment clean and ready for use is to cover the storage cases with a tear-away plastic trash bags. This equipment must always be ready for immediate emergency use. This is possible only if it is stored properly.

8.

Respiratory protective equipment shall be inspected during cleaning. Worn or deteriorated parts shall be replaced. Respiratory protective equipment for emergency use, such as self-contained devices, shall be thoroughly inspected at least once a month and after each use. Every rig inspection must include a careful inspection of all respiratory protection equipment.

9.

Appropriate surveillance of work area conditions and the degree of employee exposure or stress shall be maintained. The RIG OPERATOR is responsible for knowing what respiratory exposures may be present and must alert all personnel when protective equipment is required. The level of exposure to a given substance is determined by continuous area monitoring, personal monitoring and warning devices, or from studying the Material Safety Data Sheets (MSDS) for each substance used on the location, The RIG OPERATOR is responsible for requiring the use of the proper equipment at all times when exposure limits exceed acceptable limits.

10.

There shall be regular inspection and evaluation to determine the continued effectiveness of the program. The RIG OPERATOR is responsible for his respiratory protection program. In meeting that responsibility a RIG OPERATOR must know that all equipment is in good condition and is ready for use when needed. A part of every LOSS PREVENTION inspection will be to evaluate the state of the entire respiratory protection program of each location visited.

11.

Persons should not be assigned to tasks requiring the use of respiratory protective equipment unless it has been determined that they are physically able to work while wearing the equipment. Any employee who may, in the course of his employment, be required to wear respiratory protection equipment must pass an annual examination by a competent medical staff. This examination must include a pulmonary function test.

12.

Compressed air used for breathing purposes shall comply with the standards recommended in G.I. 1780.001.

Safety Requirements for Drilling & Workover 21 of 82 Rev: June 2006

COMPRESSORS THE COMPRESSOR FOR SUPPLYING BREATHING AIR SHOULD MEET THE REQUIREMENTS OF G.I. 1780.001. 1.

Breathing air compressors should be equipped with necessary safety and standby devices.

2.

Breathing air compressors should be situated so as to avoid entry of contaminated air.

3.

They should be equipped with purifying sorbent beds and filters to further assure greater air quality.

4.

They must be equipped with alarms to indicate compressor failure and/or overheating.

5.

Oil lubricated compressors must have a high-temperature or carbon monoxide alarm or both. If only a high-temperature alarm is used, the air must be frequently tested for carbon monoxide to insure that the air meets the specifications as described in G.I. 1780.001. AIR PURITY STANDARDS

Limits have been established for breathing air quality. Air suitable for human respiration must meet minimum standards as established by various governing bodies, including the Compressed Gas Association. The following chart provides the maximum allowable contaminant allowed under the C.G.A. standard. COMPONENT

C.G.A. STANDARD

Oxygen % by volume

19 - 23%

Carbon Dioxide, by volume

0.10% max. (1000 ppm)

Carbon Monoxide

10 ppm

Oil Vapor

(< 1 mg/liter @ STP)

Water

Saturated

Odor

None

Particulates and Solids

None

The standards cited above are usually referred to as "Grade D", in reference to the Compressed Gas Association Table No.1 These standards apply to compressed air for use in filling open circuit breathing systems.

Safety Requirements for Drilling & Workover 22 of 82 Rev: June 2006

HOW MUCH BREATHING AIR? In reality, each man should be trained and drilled to determine his own duration by using the Self-contained Breathing Apparatus (SCBA) under extremely strenuous working conditions. Many factors come into play that may greatly reduce the rated duration; therefore, one should not expect to obtain the exact time rating, without taking into consideration the size of the person, physical condition, breathing habits, adequate mask seal, etc. DECIMAL SYSTEM (CUBIC FEET) 1 Cubic Foot of Air

METRIC SYSTEM (LITERS) 28.3 Liters

One - 30 Minute Air Cylinder is Equivalent to 45 Cubic Feet

1,273.5 Liters by Volume

300 Cubic Feet of Air

8,490.0 Liters by Volume

1 Cascade of 6-300 Cubic Foot of Air Cylinders is equivalent to 1,800 Cubic Feet

50,940.0 Liters by Volume

An Air Compressor with a 9.2 Cubic Foot Delivery per Minute

260.3 Liters by Volume

It takes an air compressor, delivering 9.2 cubic feet of air per minute, 32 minutes to fill one 300 cubic foot air cylinder, or 3 hours and 12 minutes to fill six 300 cubic foot air cylinders without considering line fill time if compressor is more than 10 feet from cylinders. ONE MAN One man using one 300 cu. ft. cylinder at medium heavy work would last approx. 3 hrs. 50 min.

One 300 cu. ft. cylinder contains 8,490 liters of air.

One man using one 300 cu. ft. cylinder at maximum work would last approx. 1 hour.

Six 300 cu. ft. cylinders contain 50,940 liters of air

21 hrs. & 20 minutes

6 hrs. & 30 minutes

SIX MEN One 300 cu. ft. cylinder contains 8,490 liters of air.

Six men using one 300 cu. ft. cylinder at medium heavy work would last approx. 35 minutes.

Six men using one 300 cu. ft. cylinder at maximum work would last approx. 10 minutes.

Six 300 cu. ft. cylinders contain 50,940 liters of air.

3 hrs. & 50 minutes

One hour

Safety Requirements for Drilling & Workover 23 of 82 Rev: June 2006

B-6

HYDROGEN SULFIDE SAFETY

1.

All drilling and workover operations in known or suspect hydrogen sulfide areas shall be conducted according to API RP 49, "Recommended Practices for Safe Drilling of Wells Containing Hydrogen Sulfide" and with any COMPANY rules. Also, these RIG OPERATORS shall comply with the requirements of the following Appendices to this Section:

(Appendix I)

SAUDI ARAMCO H2S CONTINGENCY PLAN (For More Details, see chapter 8, section-C of the Drilling Manual.)

(Appendix II)

SAUDI ARAMCO STANDARD SAFETY EQUIPMENT FOR H2S OPERATIONS ON ALL ONSHORE DRILLING AND WORKOVER RIGS

(Appendix III)

SAUDI ARAMCO STANDARD SAFETY EQUIPMENT FOR H2S OPERATIONS ON ALL OFFSHORE DRILLING AND WORKOVER RIGS

2.

On all drilling and workover operations in known or suspect hydrogen sulfide areas, there shall also be some method for the passive monitoring of returns, both gaseous and liquid, to anticipate the likely need for wearing protective equipment. In all instances where there is no provision for adequately monitoring the returns to anticipate the likely need for wearing protective equipment, the ambient atmosphere shall be monitored: (a)

on the rig floor at the Driller's position and about 3 feet above the floor.

(b)

at the top of the bell nipple.

(c)

at the flowline opening to the shale shaker.

(d)

the cellar or underneath the choke manifold, above the choke manifold skid floor.

3.

Wind indicating devices, such as wind socks, shall be provided and maintained in good condition. They shall be conspicuously located so they are visible from anywhere on the location.

4.

The RIG OPERATOR shall adequately train all his personnel in the basic fundamentals of hydrogen sulfide safety. This training must include: (a)

Characteristics of hydrogen sulfide and its toxicity.

(b)

Detection and warning systems peculiar to the location.

(c)

Emergency procedures consisting of, ***

Designation of safe briefing areas. Safety Requirements for Drilling & Workover 24 of 82

Rev: June 2006

5.

***

Wearing and use of emergency breathing equipment.

***

Evacuation procedures.

***

Rescue procedures.

***

First aid for victims.

(d)

Instructions in the inspection, maintenance, and use of assigned respiratory protection equipment.

(e)

This training MUST include drills in all these procedures so all personnel on the location can quickly and effectively follow each of these instructions when there is an actual, life-threatening emergency.

Refer to Section B-6, Appendices I, II and III for specific details regarding H2S Safety Equipment and procedures.

Safety Requirements for Drilling & Workover 25 of 82 Rev: June 2006

Section B-6 Appendix I: SAUDI ARAMCO H2S CONTINGENCY PLAN I.

The scope of the Aramco H2S Contingency Plan is to cover operations while drilling, testing, and completing oil and gas wells that have a potential H2S hazard. A.

B.

The Drilling and Workover Operations Departments shall have the responsibility for executing the plan. 1.

The on-site Drilling Foreman shall be responsible for carrying out the plan.

2.

Drilling Engineering will develop and coordinate the procedures.

3.

Loss Prevention can be consulted for training and H2S surveillance.

Other Organizations will be appraised of the operations. 1. Camp Management will be notified prior to starting operations. 2.

C.

Government Relations will be given a map covering the surrounding area that might be affected in the event of an emergency. a.

Government Relations may notify any possibly interested SAG Authorities.

b.

Drilling Engineering will coordinate this notification.

3.

The Medical Department will be notified by the Drilling Operations Department.

4.

The Fire Department will be notified by the Drilling Operations Department.

5.

All installations within the area of Operations shall be noted and the Management of possibly affected installations notified.

6.

A detailed evacuation plan will be developed for any residential area that might be remotely endangered if an emergency condition develops.

Flaring of sour gas wells at night must be done with extreme caution because: 1.

Wind normally diminishes at sundown.

2.

With little or no wind, it is impossible to disperse any escaped H2S or SO2 from flares.

Safety Requirements for Drilling & Workover 26 of 82 Rev: June 2006

II.

III.

The BOP equipment, the wellhead equipment, the test equipment and the safety equipment shall all conform to presently developed standards. A.

The Class A 10,000 psi and 5,000 BOP equipment shall meet NACE Standard MR-01-75 (1980 Revision) for sour service.

B.

The tree, wellhead and all fittings exposed to H2S shall meet NACE Standard MR-01-75 (1980 Revision) for sour service.

C.

The wellhead, chokes, manifolds and flowlines shall meet the standards for sour service.

D.

The heater, test unit and all connections shall meet sour service standards.

E.

All flare lines and emergency blowdown lines will be staked or otherwise secured against movement in the event of a mechanical failure.

F.

The heater, if required, will be a minimum of 150 feet from the wellhead and the test separator.

G.

Wellhead gas will not be used for controller gas, bottled nitrogen is preferred over supply air for controls.

H.

During gas well production tests, two flare pits will be constructed down wind from the location in the direction of prevailing wind and at least 180º apart and 600 feet from the wellhead manifolds or any test equipment. Minimum flare line size shall be two 3-1/2" J-55 lines to each pit.

I.

Explosion-proof bug blowers shall be positioned to move air around well and equipment.

Emergency Safety and First Aid Equipment shall be on location and conveniently located. A.

Self-contained breathing apparatus will be located for emergency work and escape.

B.

Cascade systems for work and recharge will be set up on location.

C.

Resuscitators, safety harnesses, safety ropes, first aid kits, splints and litters will be on location.

D.

An H2S monitor with alarm systems and sensors at various locations will be installed.

E.

Personal electronic H2S monitors, explosimeters, spot checks, hand pump type H2S - SO2 detectors will be used.

F.

Wind socks, warning signs and flags as well as streamers in localized areas will be in use.

Safety Requirements for Drilling & Workover 27 of 82 Rev: June 2006

Section B-6 Appendix II: SAUDI ARAMCO STANDARD SAFETY EQUIPMENT FOR H2S OPERATIONS ON ALL ONSHORE DRILLING AND WORKOVER RIGS I.

H2S and Combustible Gas Monitors. (See also SAES-J-505 Combustible Gas and Hydrogen Sulfide in Air Detection Systems). A.

H2S Monitor and Alarm System A four channel H2S monitoring system with two visual-audio alarm system shall be installed and fully operational on all land drilling rigs operating on known or suspect H2S locations. Each sensor and alarm system shall have a portable reel with 200 feet of neoprene covered electrical cable with cannon connectors at each end for hookup of cable to monitor, cable to sensor and cable to alarm (a total of six cables on reels). 1.

The sensors shall be located as near as practical to: a. b. c. d.

B.

The top of the bell nipple. The flowline opening to the shale shaker. The Driller's position and about three feet above the floor. The cellar or underneath the choke manifold above the choke manifold skid floor. This sensor should be easily moveable so that it can be used around the BOP stack or at the well testing equipment when necessary.

2.

The alarm system (amber strobe lights and horn) shall be set for first alarm at 10 ppm and high alarm at 20 ppm H2S. The alarm system shall be located in clearly visible locations so that personnel in any work area can see and/or hear at least one set.

3.

The monitor shall be located in the doghouse.

4.

There shall be minimum of one spare sensor.

Combustible Gas Monitor and Alarm System A continuous combustible gas monitor and single sensor with a portable reel holding 200 feet of neoprene covered electrical cable with two pairs of cannon connectors (monitor to cable and cable to sensor) shall be provided. An alarm system with similar reel, cable and connectors is required 1.

The sensor shall be located at either: a.

The top of the bell nipple, or

b.

The flowline opening to the shale shaker when a rotating head is in use. Safety Requirements for Drilling & Workover 28 of 82

Rev: June 2006

II.

2.

The alarm system (red strobe light and horn) shall be set at 20% of the Lower Explosive Limit (LEL) for the low alarm and 50% of the LEL for the high level alarm. The alarm system shall be clearly visible from work areas on location. The alarm system (light and horn) shall be located on the rig floor above the doghouse. Note: This setting criteria applies to cold work situations only.

3.

The monitor shall be located in the doghouse.

4.

There shall be a minimum of one spare sensor.

C.

Two personal portable H2S monitors, alarm to be set at 10 ppm.

D.

Two portable H2S detectors (hand pump suction type) with high level and low level H2S and SO2 tubes.

E.

Two portable combustible gas or vapor monitors.

F.

Drager Test Kit for checking mud return for H2S.

Required Breathing Apparatus A.

B.

C.

Hose-line work units, with emergency escape cylinders, shall be provided as follows: 1.

Rig floor - six

2.

On handrail near shale shaker - two

3.

On rack near mud mixing area - two

4.

Near choke manifold - one

5.

In derrick for Derrickman (at monkey board) - one

Self contained breathing apparatus (SCBA's) shall be provided as follows: 1.

Toolpusher's office/quarters - two

2.

Company Foreman's office/quarters - two

3.

Logging Unit (when used) - two

4.

SCR room - one

5.

Rig Floor - three

At least one fully-charged spare cylinder shall be provided for each unit of all type listed.

Safety Requirements for Drilling & Workover 29 of 82 Rev: June 2006

III.

Emergency First Aid Safety Equipment A.

Two "Bug Blowers" explosion proof, high volume (40,000 cfm) and moveable.

B.

Three wind socks, two in service, plus streamers to be located so all personnel will know wind direction. One wind sock is to be held as a spare.

C.

Flare line ignition system (Alex-500 or equivalent) with backup flare gun and supply of 24 long self life cartridge.

D.

Two portable oxygen resuscitator units, each with a spare oxygen cylinder.

E.

Two 25 man First Aid Kits, one at rig site and one at camp site.

F.

Four eye wash stations located in the following areas: 1.

On the rig floor or in the rig floor doghouse.

2.

In the mud mixing area.

3.

In the rig medic's office or the rig supervisor's office.

4.

In the rig camp mess hall.

G.

Two safety harnesses with two 250 foot retrieval ropes.

H.

Two basket-type stretchers (Stokes or Navy type litter) with blankets and securing straps.

I.

Two Quick-Air splint kits.

J.

One portable bull horn with extra battery pack.

K.

Six small chalk boards with clamps for mounting with an adequate supply of chalk and erasers. Boards can be utilized as visual means of coordinating activities when working under a SCBA. [Note: Dry eraser boards may be substituted for chalk boards].

L.

Flashlights - explosion proof with an extra set of batteries and extra bulb for each (number to be at least one for each two persons in the operation but not less than five). NOTE:

All safety equipment with rubber, plastic or other parts likely to deteriorate shall be stored in a dark air conditioned room near the supervisor's office. Adequate supplies of sanitizing materials shall be available for sanitizing face masks and other body contact equipment.

Safety Requirements for Drilling & Workover 30 of 82 Rev: June 2006

Section B-6 Appendix III: SAUDI ARAMCO STANDARD SAFETY EQUIPMENT FOR H2S OPERATIONS ON ALL OFFSHORE DRILLING AND WORKOVER RIGS I.

A continuous monitoring system with eight sensors and six red beacon light/siren alarm systems, each with conductor cable, shall be provided. A.

All sensors must have protective housings capable of protecting the sensor from accidental spray from rig wash down hoses and accidental mud and/or oil splashes.

B.

Sensors shall be located as near as practical to: 1. 2. 3. 4. 5. 6. 7.

The top of the bell nipple. The flowline opening to the shale shaker. The Drillers position and about three feet above the rig floor. The mud pit in the pump area. The motorman's work area in the motor room. The living quarters area nearest the most likely source of hydrogen sulfide. The breathing apparatus compressor package, near the rig floor.

Note: The eight sensor with 200 feet of cable on portable reel shall be extra and will be used to monitor any other potential source of hydrogen sulfide or kept on standby in designated safety equipment storage area. C.

There shall be at least four spare sensors in addition to the eight in the monitoring system.

D.

The H2S alarm system (red beacon and siren) shall be set at 10 ppm H2S for the first alarm and 20 ppm H2S for the second alarm. The combustible gas alarm system shall be set at 20% of the Lower Explosive Limit (LEL) for the low alarm and 50% of the LEL for the high level alarm. [Note: This setting criteria applies to cold work situations only.]

E.

The alarm system shall be located in a clearly visible area so that personnel in any work area can see and/or hear at least one set. They shall be located: 1.

On the rig floor and at least eight feet above the floor.

2.

On the port side at the corner of and above the quarters.

3.

On the starboard side at the corner of and above the quarters.

4.

Below deck in the pump-motor room area.

5.

In crew quarters. Safety Requirements for Drilling & Workover 31 of 82

Rev: June 2006

6. F.

II.

In the galley area.

The monitor shall be located in the Supervisor's office, Control Room or Radio Room.

A minimum of one hundred 30 minute SCBA's will be located on any offshore rig operating in known or suspected H2S areas. There shall always be at least 25% more SCBA onboard than the number of personnel. A.

B.

The 30 minute SCBA's shall be stored ready for use as follows: 1.

There shall be one SCBA assigned to each person on board, regardless of his affiliation, contractor, service contractor, Aramco, or any visitor. These will be stored under the head-end of the assigned bunk when the person is in the bunk and during any period considered safe by the Supervisor. (If there is no bunk assignment, the person will be assigned a SCBA and a designated area for storage during his time on board.) Before assignment of a SCBA to any person, he will demonstrate that he is capable of donning it, adjusting the face piece, and turning on the pressure demand air. This requirement shall be waived for any personnel with documentation from his employer that he has received training within the past 12 months in H2S safety, including practice in donning respiratory protection equipment.

2.

Ten SCBA's shall be stored in the dining area.

3.

Four SCBA's shall be stored in the motor room or pump area.

4.

Four SCBA's, each with clip-on communication device. Two shall be in the Saudi Aramco Foreman's office and two in the Rig Supervisor’s office.

5.

All remaining SCBA's and extra cylinders will be stored in an air conditioned designated safety equipment storage area near the Supervisor's office.

The hose-line work units with escape cylinders shall be stored as follows: 1.

Six work units (three with clip-on communication devices) on the rig floor in a convenient location.

2.

Two work units each with a clip-on communication device in the Supervisor's office.

3.

Two work units each with a clip-on communication device in the Saudi Aramco Foreman's office.

4.

One work mask shall be located in the derrick at the Derrickman's position, finger board or stabbing board.

5.

Five work units and 16 spare cylinders shall be stored in an airconditioned designated safety equipment storage area near the Rig Supervisor's office. Safety Requirements for Drilling & Workover 32 of 82

Rev: June 2006

6. III.

Nine spare-clip communication device units with supply of spare batteries will be stored with the five work units as above in #4.

Three cascade systems with 12 - 300 cubic foot cylinders each or equivalent capacity; three air compressors each with purification system and capacity of 26 scfm at 2400 psi; one 3 outlet manifold and three 12 outlet manifolds; two 200 foot hoses; two - 150 foot hoses; twelve - 50 foot hoses; two 5000 psi working pressure hoses (250 foot and 300 foot respectively). A.

One cascade system with air compressor powered by an explosion proof electric motor will be located near the rig floor 1. 2. 3. 4. 5. 6.

B.

C.

There shall be two six outlet manifold on the derrick floor. There shall be a three outlet manifold at the Derrickman's position. There shall be a three outlet manifold in the mud room. There shall be a three outlet manifold in the motor room. There shall be a one six outlet manifold for recharging portable cylinders, one at each cascade system. There shall be a double tee with check valves for tying in either or both of the other two systems.

There shall be two cascade systems with diesel powered air compressors, located as remotely from the rig floor as practical, one on the upper starboard deck, the other on the upper port deck 1.

There shall be one, six outlet manifold for recharging portable cylinders at each cascade system, as well as regulators and low pressure manifolds for hose line units.

2.

There shall be a double tee with check valves for tying in either or both of the other two systems.

There shall be one 250 foot of 5000 psi w.p. hose; one 300 foot of 5000 psi w.p. hose; two 150 foot and twelve 50 foot hoses stored and ready for immediate use in an air conditioned designated storage area.

IV.

Five personal portable H2S monitors, as well as stock of lead acetate sampling devices.

V.

One hydrogen sulfide calibrator with two permeation tubes, portable and AC/DC.

VI.

Continuous H2S mud monitor (Mud Duck). Garret Gas Train with supply of accessory equipment for testing mud, plus Drager Test Kits for checking mud return.

VII.

Four portable oxygen resuscitators with eight spare oxygen cylinders.

VIII.

Four portable H2S - SO2 detectors, (suction type) with H2S and SO2 tubes.

IX.

Four portable combustible gas detectors - hand pump suction type.

X.

Six bug blowers, explosion proof, high volume (25,000 cfm or larger) and movable.

XI.

Wind socks (4 minimum), streamers, and flags to be located on various places on rig so all personnel will know the wind direction. Safety Requirements for Drilling & Workover 33 of 82

Rev: June 2006

XII.

Remote flare line ignition system (Alex-500 or equivalent).

XIII.

One emergency flare gun with a supply of 24 cartridge will long shelf life will be stored in a locked-up wooden box in in the Company Foreman’s office.

XIV. Four safety harnesses and four 250 feet retrieval ropes. XV.

Four stretchers (Stokes litter - Navy type basket or equivalent) with blankets and securing straps.

XVI. Four first aid kits (each 25 man size). XVII. Four Quick-Air splint kits or equivalent. XVIII Six portable electronic bull horn speakers with six extra battery packs. XIX. Six small chalk boards with clamps for mounting with an adequate supply of chalk and erasers. Boards can be utilized as visual means of coordinating activities when working under a SCBA. [Note: Dry eraser boards may be substituted for chalk boards.] XX.

Flashlights - explosion proof with extra set of batteries and extra bulb for each (minimum number shall be 10 flashlights).

Note: All safety equipment with rubber, plastic or other parts like to deteriorate shall be stored in an air conditioned, dark and designated area, near the Supervisor's office. Adequate supplies of sanitizing material shall be available for sanitizing face masks and other body contact equipment. B-7

HOUSEKEEPING

1.

Work areas, stairs and walkways shall not be obstructed by debris or stored materials.

2.

All walking and working surfaces shall be kept in good repair and free from oil, mud, and other potentially slippery material.

3.

The area around the base of the derrick ladder shall be kept clear to provide unhampered access to the ladder.

4.

The area around the rotary table shall be kept clear of obstacles; clean, and free of tools, materials and any accumulation of oil, water, or circulating fluids.

5.

Storage of material shall not create a hazard. Bags, containers, bundles, etc., stored in tiers shall be stacked, blocked, and limited in height so they are stable and secure against sliding or collapse.

6.

Storage areas shall be kept free from accumulation of materials that constitute hazards from tripping, fire, or explosion.

7.

Combustible materials, such as oily rags and waste, shall be stored in approved covered metal containers.

Safety Requirements for Drilling & Workover 34 of 82 Rev: June 2006

B-8

RIG CAMPS: KITCHENS AND ACCOMMODATIONS (See Also G.I. 151.006 Implementing the Saudi Aramco Sanitary Code)

1.

In addition to complying with applicable requirements for housekeeping and fire extinguishing equipment, the RIG OPERATOR shall ensure that: (a)

Exhaust fans, hoods, filters, grease trays, and ductwork are cleaned regularly to prevent a buildup of cooking grease and other flammable material.

(b)

Blades of exhaust and ventilation fans, if within 2.1 meters (7 feet) of the floor, are equipped with proper guards to prevent employee exposure.

(c)

Each walk-in freezer is equipped with a working audible alarm to alert other personnel should the door become stuck.

(d)

Sanitation requirements published by the Saudi Aramco Preventive Medicine Department are fully complied with.

2.

Each cooking, sleeping, washing and toilet facility shall be kept clean and sanitary.

3.

The plumbing and mechanical appliances shall be kept in good working order.

B-9

FIRE EXTINGUISHING EQUIPMENT

1.

On every drilling or workover rig, the RIG OPERATOR shall have readily accessible not less than the fire extinguishing equipment specified in the Drilling/Workover Contract.

2.

The RIG OPERATOR shall inspect fire extinguishers monthly, or more frequently if necessary to ensure they are fully charged, kept in their designated locations, and free from any obstructions. Inspection shall be documented in an inspection log.

3.

Fire fighting equipment shall not be tampered with and shall not be removed for other than for fire fighting or for servicing. Extinguishers removed from the premises to be recharged shall be replaced by spare extinguishers during the period they are missing.

4.

Carbon tetrachloride and other toxic vaporizing liquid fire extinguishers are prohibited.

5.

For each offshore rig, the RIG OPERATOR shall prepare a fire control plan and the plan shall be permanently exhibited on the rig.

6.

Fixed fire extinguishing systems for each offshore rigs (including water, carbon dioxide, dry powder, Halon, or foam) shall be kept in good working order and available for immediate use at all times while engaged in drilling operations or in transit.

7.

Manual fire alarm stations shall be conspicuously located on each deck level of offshore rigs.

8.

A fire hose shall not be used for any purpose other than fire fighting, fire drills, and testing.

Safety Requirements for Drilling & Workover 35 of 82 Rev: June 2006

9.

Each fire hose shall be completely unrolled and inspected by the RIG OPERATOR once each month and defective parts should be replaced. Fire hoses shall be pressure-tested annually. (Refer to G.I. 1781.001-1 and SAES-B-19).

10.

The access to any fire hydrant shall not be blocked.

11.

Each fire hydrant shall be equipped with a spanner wrench.

12.

Each fire hose shall be properly stored on a rack or reel when not in use.

13.

Each fire nozzle shall either be attached to the hose or stored next to the fire hydrant to which the fire hose is attached.

14.

Each hose water nozzle provided shall be of an approved dual purpose type (i.e. spray jet type) incorporating a shutoff.

15.

Each hose on a helicopter deck that discharges foam shall have a nozzle that has a foam stream, foam spray, and off position.

16.

Each fire station on an offshore rig shall be properly identified by marking: "FIRE STATION NO.____" next to the station in letters at least 5 centimeters (2 inches) high.

17.

On each offshore rig, there shall be,at all times at least two RIG OPERATOR personnel who are trained in the use of a Fire Fighter Aircraft Crash Rescue Equipment.

18.

A crash rescue box should be permanently located in an area readily accessible to the heliport. This box should be highly visible and designated exclusively for crash equipment. The required contents shall comply with current Saudi Aramco Aviation policy.

19.

Additional information on requirements is available in specific Rig Contracts (See Schedule ‘G’ Attachment 1) and the following Section B-9 Appendix I.

Safety Requirements for Drilling & Workover 36 of 82 Rev: June 2006

Section B-9 (Appendix I) FIRE PROTECTION AND CONTROL EQUIPMENT A.

Nine 30-lb dry chemical ‘UL’ listed per (GI 1981 & SAES-B-19) BC extinguishers provided for extinguishing of localized fires located and mounted as follows: •

•

•

•

•

•

•

B.

Two on rig floor at control station. One in shaker area. One on mud pump skid. Two in drawworks area. One on generator trailer. One inside tool room. One in the area of the gasoline fuel tank.

Two 10-lb carbon dioxide extinguishers located and mounted as follows: 1.

Two on the generator trailer.

C.

One 150-lb wide wheel type ‘UL’ Listed BC type "Purple K" dry chemical fire extinguisher located at a minimum of 75 feet from the wellhead and/or mud, diesel tanks.

D.

One fixed 1-1/4" live hose reel with 125 feet of 1-1/4" hose for delivery of water to the rig floor, cellar and mud tank area. The unit should be centrally mounted to adequately cover the rig and associated equipment.

E.

One Type 2A 10 BC extingusiher located in Foreman’s trailer.

B-10 TRUCK LOADING AND UNLOADING 1.

Before pumping hydrocarbons between two units, the units shall first be electrically bonded together and grounded.

2.

The bonding connector and the grounding conductor from the unit to earth shall remain effectively attached until all pumping connections have been removed.

3.

While tank trucks containing flammable, vaporizing liquids are being connected or disconnected, no vehicle shall start up or have its motor running in the loading area.

4.

When liquid in a tank contains or is likely to contain hydrogen sulfide, personnel required to gauge the liquid shall be provided with and shall wear proper respiratory protective equipment.

Safety Requirements for Drilling & Workover 37 of 82 Rev: June 2006

B-11

FUEL TANKS

1.

Except for diesel fuel and the fuel in the tanks of operating equipment, no gasoline or other liquid fuel shall be stored within 22.9 meters (75 feet) of a rig or its auxiliary equipment that could be a potential ignition source.

2.

The RIG OPERATOR shall ensure that all fuel tanks are conspicuously marked as to contents.

3.

The RIG OPERATOR shall ensure that neither smoking nor open flame is allowed within 7.6 meters (25 feet) of the handling of flammable liquids. A notice shall be conspicuously posted.

4.

Dispensing nozzles and valves shall be of the self-closing type. Drip pans shall be provided and used when needed.

5.

Fuel tanks shall be located where they are not subject to physical damage from vehicles. Where this is not possible, barrier protection shall be provided.

6.

Drainage from any fuel storage shall be in a direction away from the rig. Rig "day tanks" may be located on the level well site but they must be so located that, should they rupture, the resulting fuel spillage will not drain toward the well.

7.

A fire extinguisher, approved for extinguishing petroleum fires, shall be readily accessible at a permanently designated and highly visible location at each fuel storage tank.

8.

Label Emergency fuel shut off.

9.

Recommend all valves on fuel tank be (1/4 turn) Ball Type.

10.

Fuel tanks should be supplied with appropriate vents without any bends.

B-12

BULK STORAGE TANKS

1.

All bulk storage tanks shall be equipped with safety relief valves and/or rupture discs so as to prevent excess pressure. Rupture discs can only be used for bulk storage tanks in open areas where drainage would be to a safe area.

2.

Bulk storage tanks in enclosed areas shall be equipped with testable safety relief valves which can be vented out of the area. Such enclosed areas shall be ventilated so that a pressure build-up will not occur if a break or a leak in the air supply system occurs.

3.

All safety relief valves shall be function tested at least every three months.

4.

A proper means of access shall be provided to each bulk storage tank.

5.

Each bulk storage tank shall be clearly marked as to contents.

Safety Requirements for Drilling & Workover 38 of 82 Rev: June 2006

B-13 CONTROL OF STATIC ELECTRICITY 1.

When transferring flammable liquids or finely divided flammable or explosive materials from one container to another the containers shall be in firm contact with each other or be continuously electrically bonded throughout the transfer so as to prevent the accumulation of a static charge.

2.

When tanks, mixers, or processing vessels are used for flammable liquids or flammable or explosive compounds, they shall be electrically bonded and grounded while being filled or emptied.

B-14 HANDLING AND STORAGE OF COMPRESSED GAS CYLINDERS 1.

Reference G.I. 355.020 and attachment must comply with it.

2.

Gas cylinders shall be secured in an upright position and shall be separated in storage as to full and empty cylinders. All oxidizers shall be separated from fuel gases by at least 6.1 meters (20 feet).

3.

Valve protection caps shall be installed on all cylinders at any time a regulator is not attached.

4.

When gas cylinders are hoisted, they shall be secured on a cradle, sling board, or pallet. They shall not be hoisted or transported by means of magnets or choker slings applied directly to the cylinders.

5.

When gas cylinders are transported by powered vehicles they shall be secured and protected in such a manner to prevent physical damage. Cylinders that contain acetylene must be transported, used, and stored vertically to prevent the liquid acetone collecting in the neck of the cylinder.

6.

Valve protection caps shall not be used for lifting gas cylinders.

7.

Damaged or defective gas cylinders must not be used. Since these cylinders can be especially hazardous, it is important to exercise great care when removing them from the rig area.

8.

Freon cylinders shall be stored in an area protected from the direct rays of the sun.

B-15 ELECTRICAL WIRING AND EQUIPMENT 1.

The installation, use, and maintenance of any fixed or portable electric wiring or equipment shall comply with the provisions of NFPA 70, "National Electrical Code", and of API RP 500, "Classification of Areas for Electrical Installations at Drilling Rigs and Production Facilities on Land and on Marine Fixed and Mobile Platforms" and SAES-B-68.

2.

All diesel engines used to generate electrical or mechanical power on a rig shall be equipped with spark arresting devices or water sprays. The exhaust stacks shall be directed so that hot exhaust gases and noise will not endanger nearby personnel.

3.

Warning signs that prohibit unauthorized access shall be conspicuously displayed on the housing or other enclosure around high voltage electrical equipment.

Safety Requirements for Drilling & Workover 39 of 82 Rev: June 2006

4.

Lead-in cables from the generators to the derrick shall be placed in trays, suitcased, or adequately protected from physical damage by other means. In those instances where these methods are impossible or impractical, all wiring must be bundled and secured to fixed structural members.

5.

A non-conductive floor mat shall be provided in front of each switch panel in the generator or SCR room.

6.

Each SCR room shall be equipped with emergency lighting for at least two of the exits from the room.

7.

All switch box, junction box, and connector box covers shall be in place and properly labeled.

8.

Each onshore generator skid shall be grounded together to the well cellar.

9.

Each onshore generator skid shall be equipped with a secure system for pinning the doors open. It shall also have warning signs posted to alert workers of the high voltage.

10.

Auxiliary/emergency standby generators for offshore rigs shall be installed so they will start automatically when "auto start" circuits are activated. The RIG OPERATOR shall test "auto start" circuits on at least on a weekly basis. A sign that says “DANGER – AUTOSTART.”, Must be posted.

11.

The power available from the emergency generator shall be sufficient to supply, simultaneously, all those services that are essential for safety in an emergency.

12.

Auxiliary and emergency standby generators shall be run at full load for a minimum of two hours every week and logged.

13.

All skids shall be securely electrically bonded together to the rig cellar. Refer to National Electrical Code ANSI/NFPA 70 (latest edition) Article 250-26, “Grounding Separately Derived Alternating-Current Systems” and SAES-P-111, “Grounding”. “A separately derived system is a premises wiring system where power is derived from a generator, a transformer, or converter windings, and there is no direct electrical connection, including a solidly grounded circuit conductor, to supply conductors originating in another system.”

Safety Requirements for Drilling & Workover 40 of 82 Rev: June 2006

B-16

ILLUMINATION

1.

Rig lighting shall at all times provide a minimum illumination of: (a)

53.8 lux (5 foot-candle) power on the entire derrick floor,

(b)

53.8 lux (5 foot-candle) power at the monkey board, mud pumps, catwalk, and

(c)

21.5 lux (2 foot-candle) power at the shale shaker, stairways and other working areas.

2.

The installation of the rig lights shall be according to NFPA requirements for electrical installations in classified areas (see API RP-500).

3.

Each lighting fixture in a derrick shall be independently attached to the derrick by a safety cable to prevent it from falling to the rig floor should it be torn loose.

4.

Lighting fixtures shall be kept sufficiently clean, adjusted, and repaired so as to provide the illumination required for the safety of RIG OPERATOR personnel.

5.

Light beams shall be directed toward the objects to be illuminated and away from the eyes of rig personnel.

6.

Except in an emergency, vehicle lights shall not be used for the lighting of onshore rig operations.

7.

Emergency lighting shall be kept in good repair and ready for immediate emergency use. It shall be tested on a regular basis to be certain it will function properly in an emergency.

B-17

TOOLS -- HAND AND POWER

1.

All tools, hand and power, and similar equipment, whether furnished by Saudi Aramco or by a contractor, shall be kept in good operating condition.

2.

All hand-held power tools shall be equipped with a constant pressure ("dead-man") switch that will shut off the power when the pressure on it is released. Switches or triggers which can be locked in the "ON" position are expressly forbidden. Note: Such locks are very common on power tools and must be disabled before use on a Saudi Aramco Company or Contract Rig.

3.

Impact tools, such as drift pins, wedges, and chisels, shall be kept free of mushroomed heads.

4.

Sledge hammers having a square face shall not be used.

5.

Wooden handles of tools shall be kept free from splinters or cracks and shall be kept tight in the tool.

6.

Electric power operated tools shall be either of the approved types: Doubleinsulated or grounded. 120V AC Max Voltage with GFCI (See construction Safety Manual 10.6.1.1,2).

Safety Requirements for Drilling & Workover 41 of 82 Rev: June 2006

7.

Pneumatic power tools shall be secured to the hose or whip to prevent the tool being accidentally disconnected.

8.

Safety clips or retainers shall be securely installed and maintained on pneumatic impact (percussion) tools to prevent attachments from being accidentally expelled.

9.

The manufacturer's safe operating pressure for hoses, pipes, valves, filters, and other fittings shall not be exceeded.

10.

The use of hoses or electrical cords for hoisting or lowering tools is prohibited.

11.

All hoses exceeding 12.7 millimeters (1/2 inch) inside diameter with a pressure greater than 1034 kilopascals (150 pounds per square inch) shall have a safety device at the source of supply or branch line to reduce pressure if a hose fails.

12.

The fluid used in hydraulic powered tools shall be fire resistant and shall retain its operating characteristics at the most extreme temperature to which it will be exposed.

B-18 ABRASIVE WHEEL MACHINERY 1.

Abrasive wheels used on bench or pedestal mounted grinding machines shall have spindle-end, tongue, and work rest guards.

2.

Work rests shall be kept adjusted closely to the wheel face with a maximum opening of 3.2 millimeters (1/8 inch) to prevent the work from being jammed between the wheel and the rest, causing possible wheel damage.

3.

Tongue guards shall be kept adjusted so the distance between the wheel periphery and the adjustable tongue guard never exceeds 6.4 millimeters (1/4 inch).

4.

All contact surfaces of grinding wheels shall be kept properly dressed and free of foreign material.

5.

Before installing a new grinding wheel, the maximum approved speed stamped on the wheel blotter shall be checked against the arbor speed of the machine to ensure that the safe peripheral speed is not exceeded. A grinding wheel shall not be operated at peripheral speeds that exceed the manufacturer's recommendations.

6.

Mounting blotters supplied by the grinding wheel manufacturer shall always be used when mounting a new wheel.

7.

Bench grinders shall be securely mounted to a bench in order to prevent vibration and movement.

8.

All abrasive wheel machinery that is electrically powered shall be adequately grounded or of the approved double-insulated type.

9.

Safety guards used on machines known as right angle head or vertical portable grinders shall have a maximum exposure angle of 180 degrees, and the guard shall be located so as to be between the operator and the wheel during use.

10.

Eye and face protection must be worn while using grinders.

Safety Requirements for Drilling & Workover 42 of 82 Rev: June 2006

B-19 WELDING AND CUTTING 1. No welding or cutting shall be done: (a)

On any pipe or vessel containing pressurized fluid or gas.

(b)

On any tank or container which contains or has previously contained flammable fluids or gases until such containers or vessels have been filled with water or are otherwise suitably purged. Used 55 gallon drums are specifically included in this instruction.

(c)

In a confined space and until a properly trained person has first tested the atmosphere with proper instrumentation to ensure it is free from combustible gases (i.e. 0% LEL) and contains at least 20% oxygen, all requirements for confined tank entry shall be strictly followed. (refer to section B-32)

(d)

On any automobile or truck wheel rim upon which a tire is mounted.

2.

Welding, cutting, or brazing shall not be done on any certified pressure vessel except by code qualified personnel following code procedures and techniques.

3.

No field welding shall be performed on any load handling tools or equipment. Tools requiring this type of repair shall be sent to a shop for properly controlled repair conditions.

4.

Welders and cutters must be trained in all the safe operating procedures that are applicable to their work.

5.

Welding, cutting, or brazing shall not be done in the presence of explosive gas or fumes, or combustible materials.

6.

Suitable eye protection shall be worn by welders and helpers when welding or cutting operations are being performed or scale is being cleaned from welds. Ref CSM Figure 1.4A.

7.

Acetylene cylinder valves shall not be opened more than one and one-half turns. The wrench must be left on the stem. The maximum optional gauge pressure for acetylene cylinders must not exceed 103 kilopascals (15 pounds per square inch).

8.

All gauges and regulators shall be maintained in good condition. Regulator gauges shall not be used if the glass cover is broken or cracked.

9.

A friction lighter, not matches or hot work, shall be used to light a torch.

10.

Hoses showing leaks, burns, worn places, or other defects rendering them unfit for service shall be repaired or replaced.

11.

When gas welding equipment is not in use, the cylinder valves shall be closed and the pressure in the hoses released.

12.

Arc welding cables with damaged insulation or exposed bare conductors shall be replaced.

13.

Cables with splices within 3 meters (10 feet) of the electrode holder shall not be used. Safety Requirements for Drilling & Workover 43 of 82

Rev: June 2006

14.

When in use, electrode holders shall be placed so that they cannot make electrical contact with persons, conducting objects, fuel tanks, or compressed gas tanks.

15.

Portable arc welding machines shall have the frames properly grounded.

16.

Welders shall place welding cable and other equipment so that it presents no obstruction of passageways, ladders, and stairways. The ground lead should be placed as close to the work as practical.

17.

Welding helmets shall be worn by all welders during arc welding operations. Personnel shall not be permitted to observe arc welding operations unless they are wearing proper eye protection.

18.

When arc welding under wet conditions, special insulating protection shall be supplied. in order to prevent an electrical shock.

19.

After welding operations are completed, the welder shall mark the hot metal or provide some other means to warn people of the hazard.

Safety Requirements for Drilling & Workover 44 of 82 Rev: June 2006

SECTION B-19 APPENDIX I PROTECTIVE GOGGLES, SPECTACLES, FACE SHIELDS AND HELMETS

TYPICAL EYE PROTECTION APPLICATIONS Operation

Hazards

Protection

Acetylene-welding cutting burning

Sparks, molten metal, harmful rays, flying particles Sparks, molten metal, intense rays, flying particles Splash, acid burns, fumes Flying particles Glare, heat, molten metal Flying particles Flying particles Chemical splash, glass breakage Flying particles Heat, glare, sparks, splash Flying particles, sparks

D, E, F

Electric arc welding Chemical handling Chipping Furnace operations Grinding (light) Grinding (heavy) Laboratory Machining Molten metals Spot welding

I G, H (Severe +C) A, B, C, E, F, G D, E, F A, B, C, G C, D, E, G G, H (A or B +C) A, B, C, G D, E (A or B tinted +C) A, B, C, G

Safety Requirements for Drilling & Workover 45 of 82 Rev: June 2006

Protection against Radiant Energy Protection against radiant energy requires the selection and use of the proper shades of welding filter lens or plate. The table below shall be used as a guide for the selection of the proper shade numbers of filter lenses or plates used in welding. Shades more dense than those listed may be used to suit the individual’s needs. Welding Operation Shielded metal-arc welding 1/16-, 3/32, 1/8-, 5/32- inch diameter electrodes. Gas-tungsten are welding and gas-metal arc welding (nonferrous) 1/16-, 3/32-, 1/8-, 5/32- inch diameter electrodes. Gas-tungsten arc welding and gas-metal arc welding (ferrous) 1/16-, 3/32-, 1/8-, 5/32-inch diameter electrodes Shielded metal-arc welding 3/16-, 7/32-, ¼- inch diameter electrodes Shielded metal-arc welding 5/16-, 3/8-inch diameter electrodes Atomic hydrogen welding Carbon-arc welding Soldering Torch brazing Light oxy fuel gas cutting, up to 1 inch Medium oxy fuel gas cutting, 1 inch to 6 inches Heavy oxy fuel cutting, over 6 inches Gas welding (light), up to 1/8- inch Gas welding (medium), 1/8-inch to ½ inch Gas welding (heavy), over ½- inch Air-carbon arc cutting

Comfort Shade Number 10 11

12

12 14 10-14 14 2 3 or 4 3 or 4 4 or 5 5 or 6 4 or 5 5 or 6 6 or 8 12

B-20 AIR COMPRESSORS 1.

All air compressors shall have at least one air pressure regulator to control proper air flow.

2.

The safety relief valve on the main air tank shall be checked at least every three months and kept in proper working order.

3.

No valves shall be allowed upstream or downstream from any safety relief valve.

4.

The piping connected to the pressure side and discharge side of a safety relief valve shall not be smaller than normal pipe size openings of the device.

5.

The piping from the discharge side of the safety relief device shall be securely anchored to prevent any movement of the pipe when venting air.

6.

All valves and pressure control devices shall be kept in proper working order and inspected as required.

Safety Requirements for Drilling & Workover 46 of 82 Rev: June 2006

B-21

HOT WORK

1.

No hot work, welding or cutting, open flames, smoking or other potential source of ignition will be allowed within any electrically classified areas, as defined in API RP 500, until the measured lower explosive limit (LEL) of the ambient atmosphere is zero.

2.

Before the hot work begins and as it continues, all potential sources of ignitable material - liquids or gases - shall be prevented by some positive means from entering into the work area. When possible all such sources shall be locked and tagged to prevent their being opened.

3.

Monitoring of the LEL shall be continuous until the hot work is completed.

4.

All electrically classified areas shall be marked, with signs in Arabic and English: "NO SMOKING". "NO WELDING, CUTTING, OR OTHER SOURCE OF IGNITION EXCEPT UNDER THE DIRECT SUPERVISION OF THE RIG SUPERINTENDENT".

B-22 LOCKOUTS, TAGGING AND WORK PERMITS 1.

Where there is danger of machinery being started or electrical circuits being energized while repairs or maintenance work is being done the RIG OPERATOR shall ensure that the electrical circuits are locked open and tagged. Where there is danger of machinery being started or of compressed gases creating a hazard to RIG OPERATOR personnel while repairs or maintenance work is being done, the RIG OPERATOR shall: (a)

Disconnect the lines, or

(b)

Lock and tag the main valve closed, or

(c)

Blank the lines on all hydraulic or air driven machinery, pressurized lines, or any lines connected to such equipment if they could create a hazard to personnel.

(d)

The craftsman doing the actual work should have the lock out key in his possession.

B-23 CONFINED SPACES 1.

DEFINITION OF A CONFINED SPACE: A confined space is any space that can be entered by personnel that: (a)

has limited openings for entry or exit,

(b)

inadequate ventilation or the presence of a harmful atmosphere is likely, and

(c)

the space is not designed for personnel occupancy.

Note: "confined space" includes, but is not limited to, tanks, vessels, cellars, compartments, piping geometry, or building and facility ‘dead ends’ that limit access or escape.

Safety Requirements for Drilling & Workover 47 of 82 Rev: June 2006

2.

Whenever possible, work shall be planned so as to circumvent entry into a confined space.

3.

The RIG OPERATOR must never allow any person to enter a confined space until ALL the following criteria have been met: (a)

The atmosphere in the confined space must be sampled by a supervisor for the presence of harmful or toxic materials, for the likelihood of a flammable atmosphere during the time the space is entered, and for a minimum 20% oxygen concentration.

(b)

In confined spaces where toxic materials such as hydrogen sulfide are present, those entering the space shall be required to wear the proper respiratory protective equipment as prescribed in Section B-6, "Hydrogen Sulfide Safety", of this Manual.

(c)

If a potentially flammable atmosphere (a reading of anything above "zero percent" of the lower explosive limit) is encountered, the flammable material shall be removed from the area or all work shall be done with non-sparking hand tools and pneumatic power tools. If pneumatic tools are not available the electromotive force to the tools shall not exceed 32 volts.

(d)

If the oxygen level inside the confined space is less than 20% the area shall be adequately ventilated or the persons entering the area shall wear respiratory protective equipment (as required in Section B-5, "Respiratory Protection", of this Manual).

(e)

No personnel shall be allowed to enter a confined space until positive means are established to prevent all energy sources from entering the confined space area or causing associated equipment to operate while work continues.

4.

Each person entering the confined space shall wear a safety harness with an attached life-line.

5.

A stand-by man shall be assigned the duty of watching the persons working inside the confined space during the time they are inside. This duties of the stand-by man are:

6.

(a)

He shall have no responsibilities other than to continually watch those inside the confined space and observe their condition and, also, be alert to any need for rescue or other assistance by those inside.

(b)

He shall be in such a position as to physically observe the condition of every person inside the confined space.

(c)

He shall have the means (winching equipment or adequate nearby personnel) to rescue any personnel from inside the space.

(d)

He shall have adequate personal protective equipment available so if it should become necessary to aid those inside the confined space, he can enter the area safely.

These are minimum requirements which must always be met any time personnel are required to enter a confined space (see Item #1) for ANY length of time. Safety Requirements for Drilling & Workover 48 of 82

Rev: June 2006

B-24 USE OF POTENTIALLY HAZARDOUS CHEMICALS 1.

Rig personnel must be informed regarding the potential harmful effects of all chemicals used in drilling and workover operations. The COMPANY will ensure that the least hazardous chemicals are used in Company operations.

2.

Before requesting any chemicals that are potentially hazardous (low flash point, strong oxidizers, corrosives, toxic, highly flammable, etc.) the COMPANY will research the available chemicals to determine if it is possible to use chemicals that may be safer. The COMPANY should utilize the safest possible chemicals available that will adequately perform according to the operations requirements.

3.

The COMPANY shall make every effort to ensure that current material safety data sheets (MSDS) are available at the rig site for all chemicals that are used.

4.

For unusually hazardous chemicals, those for which extraordinary safety measures are necessary, the MSDS must be in the hands of the rig operator at the location where it will be used at least 24 hours prior to delivery of that chemical. This is important in instances of chemical use where protective gear, special handling and storage requirements, or other preparations must be made before the chemicals arrive at the location.

5.

The RIG OPERATOR will be responsible to insure that the proper protective equipment and first aid measures are available, when necessary, at the location. Also, the RIG OPERATOR will ensure the proper protective equipment is used properly and consistently in order to properly protect rig personnel.

6.

All Hazardous Materials shall be segregated from normal stores and clearly identified. Hazardous Materials Labels shall not be removed from containers.

Safety Requirements for Drilling & Workover 49 of 82 Rev: June 2006

SECTION C: RIG EQUIPMENT AND PROCEDURES C-1

SPUDDING IN

1.

Spudding in shall not begin until: (a)

all machinery guards are in place,

(b)

appropriate platforms, stairways, handrails, and guardrails are installed and securely fastened in position,

(c)

the derrick or mast is secured and all assembly pins and keepers are in place, and

(d)

the escape line and safety buggy are properly installed.

C-2

DERRICKS AND MASTS

1.

Derricks and masts shall have a permanent nameplate either attached to the structure, or available at the site indicating the following: (a)

Name of manufacturer.

(b)

Model number and serial number.

(c)

Load rating including hook load capacity with number of lines and wind load rating both with and without pipe standing in the derrick.

(d)

Whether external guying is required and, if so, the recommended guying pattern.

2.

The derrick or mast shall not be loaded beyond its design capacity.

3.

All girts, legs, and braces shall be maintained in good condition, properly secured, and free from damage, bowing, or deflection.

4.

Chain hoists and snatch blocks shall not be fastened to girts and braces. Any bending of the girts and braces weakens the derrick or mast.

5.

Any girt, brace, or derrick member having enlarged or distorted bolt holes shall be replaced.

6.

Girts, braces, and other members of the derrick or mast shall never be removed while the derrick or mast is under a load.

7.

To withstand operating vibration, the mud standpipe shall be attached to the derrick leg rather than the girts and braces, unless the derrick is specifically designed otherwise by the manufacturer.

8.

All substructure members shall be free from damage and all securing bolts, nuts, pins, and safety pins shall be in place.

Safety Requirements for Drilling & Workover 50 of 82 Rev: June 2006

9.

Before subjecting the derrick or mast to unusually heavy loads, connecting pins and keepers, bolts, and nuts shall be checked to ensure that they have not been loosened or worn excessively by vibration.

10.

The weep holes in the "A" legs of the derrick or mast shall be kept clear of dirt, debris, gloves, rags, etc., that could block the drain holes and permit water to accumulate resulting in corrosion of the legs.

11.

An aircraft warning light on the crown shall be provided and shall be maintained in satisfactory operating condition.

C-3

ANCHORING -- ALTERATIONS

1.

Derrick or mast guy lines, when required, shall be installed according to the manufacturer's specifications and shall be properly fastened to adequate ground anchors.

2.

No structural change or addition to a derrick or mast shall be made unless approved in writing beforehand by the manufacturer of the equipment or the manufacturer's representative.

3.

No holes shall be drilled, punched, or burned in a load carrying member of a derrick, mast, or substructure.

C-4

CROWN BLOCKS

1.

There shall be no opening between the beams of main support members or frame work of the crown large enough to permit a worker to fall through.

2.

Where wood bumper blocks are attached to the underside of crown block beams, a wire rope safety line or wire mesh shall be fastened along the beam and attached to the derrick at both ends, thereby safely retaining the wood bumper blocks should a crown-out occur.

3.

When the crown block is to be lubricated, the drawworks shall be shut down, and the brake chained down.

C-5

TRAVELING BLOCKS

1.

Traveling blocks shall be equipped with securely attached sheave guards. Any traveling block hook to which equipment is directly or indirectly attached shall be equipped with a safety latch or a wire rope safety line.

2.

Safety latches on hooks shall be maintained rigid so that a jar from the elevator links will not drive the latch aside and unhook the line.

3.

All traveling blocks, hooks, elevators, elevator links, and traveling equipment shall be free of projecting bolts, nuts, pins, or parts.

4.

An upward travel limiting device (crown protector, such as a Crown-O-Matic) shall be installed, properly adjusted, and used on all drilling and workover rigs. Safety Requirements for Drilling & Workover 51 of 82

Rev: June 2006

5.

The upward travel limiting device shall disengage all power to the hoisting drum and apply the brakes to prevent the traveling blocks from contacting the crown structure.

C-6

AUXILIARY ESCAPE

1.

On every drilling and workover derrick or mast an auxiliary means of escape shall be provided by the installation of a specially rigged and securely anchored escape line attached to the derrick. (Offshore rigs are exempt from this requirement until an escape device becomes available that meets the criteria contained in Requirement Number 2, below.)

2.

The emergency means of escape shall be located in such a manner that the escape line itself does not create a hazard to helicopter rotors, crane booms, or other moving equipment. The rate of descent of any safety buggy must be controllable by the rider.

3.

An escape line shall consist of a wire rope not less than 12.7 millimeters (1/2 inch) in diameter and shall be free from kinks, splices, and broken wires.

4.

On land-based rigs, all escape lines shall be securely anchored with either an iron stake or deadman that will withstand a 1361 kilogram (3000 pound) static cable pull. The ground end of the escape line shall be staked out so that the escape route and landing area are unobstructed. If space limitations are such that the escape line is, or may be, exposed to motorized traffic, it shall be conspicuously marked at eye level with a visible flag or streamer.

5.

Tension on an escape line and configuration of the landing area shall be such that a worker sitting in a safety buggy will touch the ground, deck, or water approximately 6.1 meters (20 feet) from the anchor.

6.

The length of an escape line for onshore rigs shall be at least double the vertical distance between the ground and the point at which it is attached to the derrick (normally the first girt above the monkey board).

7.

An approved safety buggy shall be properly installed on the escape line and kept at the derrickman's principal working platform for instant emergency use. It shall be inspected by a qualified person at least once each week.

8.

The escape buggy shall be secured to the monkey board in a manner to ensure easy release in an emergency.

C-7

GUARDS

1.

Sturdy machinery guards shall be installed on all drawworks and rotary table drives to prevent personnel being injured by rotating machinery or by disintegrated or broken parts.

2.

A metal guard not less than 3.2 millimeters (1/8 inch) thick shall enclose the tops and outer sides of all hoisting drum brake flanges.

3.

Every rotary table shall have a substantially constructed metal guard with a non-skid surface that adequately covers the outer edge of the table and extends downward to Safety Requirements for Drilling & Workover 52 of 82

Rev: June 2006

completely cover all of the exposed rotating sides of the table, including the pinion gear. 4.

Guards shall be installed on all hoisting drums to prevent personnel coming in contact with the rotating drum.

5.

Rig machinery shall not be operated unless all guards are properly maintained and in position, except during maintenance, repair, or rig-up work, or when limited testing is being performed by an authorized and qualified person.

6.

If it is necessary to remove guards to reach lubrication fittings for oiling and greasing, machinery shall be fully stopped. All guards shall be replaced prior to resuming operations.

7.

Air hoists shall be equipped with a guard and a line guide.

8.

All V-belt drives shall be guarded.

9.

All engine fan blades shall be equipped with shrouds to protect against personnel injury.

10.

All hot surfaces of equipment shall be suitably guarded or insulated to prevent possible injury to personnel.

C-8

DERRICK EXITS, LADDERS, STAIRWAYS, FLOORS, AND PLATFORMS

1.

Safe exits shall be provided directly to the outside on at least two sides of the derrick floor. An exit that leads directly to the mud pits prior to reaching ground level shall not be counted as one of the required exits.

2.

Exit doors from the doghouse shall open outward and shall not be held closed with a lock or outside latch when RIG OPERATOR personnel are working on the derrick floor.

3.

Floors, stairways, and platforms shall be free from dangerous projections and obstructions and shall be maintained in good repair, clean, and free from oil, grease, water, or other materials of similar nature. Where any type of operation necessitates working on slippery floor areas, such surfaces shall be protected against slipping by use of mats, grates, cleats, or other means to provide reasonable protection.

4.

Every flight of stairs having four or more risers shall be equipped with standard stair railings on open sides.

5.

Standard guardrails shall be installed on the outer perimeter of all working platforms and walkways that are over 1.2 meters (4 feet) above ground level. A standard guard rail consists of a top rail 1.1 meters (42 inches) in height, a mid-rail, located an even distance between the top rail and the floor, and a 10.2 centimeter (4 inch), toe board mounted flush with the floor. The guardrails shall be mounted on centers and designed to withstand the weight of a 90.7 kilogram (200 pound) person.

6.

When it is not possible, during a temporary condition to provide adequate railing all personnel working within 3.1 meters (10 feet) of the edge must be tied off with a safety harness. Safety Requirements for Drilling & Workover 53 of 82

Rev: June 2006

7.

On drilling and workover rigs, a stairway shall be installed beside the pipe ramp which shall extend from the ground to the derrick floor at the V-door.

8.

A sturdy guard rail shall be provided at the V-door. It shall be in place at all times except when the pipe ramp is being used. The use of chains on wide spans, such as V-doors, is discouraged.

9.

Every opening in a derrick floor shall be covered or guarded when not being used.

10.

Unless the rathole or mousehole extends at least 30.5 centimeters (12 inches) above the rig floor, the opening in the floor above the pipe shall be covered when a kelly or joint of pipe is not in the hole.

11.

Catwalks shall be provided with a stairway at the outer end.

12.

Guardrails shall be installed on both sides of walkways located over open mud tanks.

13.

When a chain or wire rope is used as a temporary substitute for a guardrail on mud tank walkways, the chain or wire rope shall be adequately secured and kept taut.

14.

Cages having hoop type back supports shall be provided on all fixed ladders of more than 3.1 meters (10 feet) unless a climbing device is used. When a cage is used, the maximum unbroken length between resting points shall be 6.1 meters (20 feet).

15.

The area around the base of the derrick ladder shall be kept clear to provide unhampered access to the ladder.

16.

Ladder safety devices may be used on ladders over 3.1 meters (10 feet) in unbroken length in lieu of cage protection. All ladder safety devices, such as those that incorporate climbing belts, sheaves, and sliding counterweight attachments shall be properly installed to meet the design requirements of the ladders which they serve. Where possible, the sliding counterweight shall be installed on the off-ladder side of the derrick.

17.

Climbing devices, when used in lieu of caged ladders, shall be properly rigged with a minimum of three cable clips. The counterweights should approximate the weight of the derrickman.

18.

Derrickmen shall always use the climbing device. They must climb or descend the ladder rung by rung and not "ride" the climbing device.

19.

No personnel shall slide down any pipe, kelly hose, cable, or rope line except in an extreme emergency.

20.

Platforms shall be located at the monkey board, tubing board, and crown of all drilling and workover rigs. The requirement for a platform at the crown may be deleted for masts which are frequently lowered as a normal part of operations (i.e., carrier-mounted workover rigs).

21.

All landing platforms shall be equipped with standard railings and toe boards, so arranged as to give safe access to the ladder. The step-across distance from the nearest edge of the ladder to the nearest edge of equipment or structure shall not be more than 30.5 centimeters (12 inches).

Safety Requirements for Drilling & Workover 54 of 82 Rev: June 2006

22.

The side rails of a ladder shall extend at least 91.5 centimeters (3 feet) above a landing platform.

23.

All ladders, fixed or portable, shall be maintained in good condition with no bent, broken, or damaged siderails or steps.

24.

Defective ladders shall be immediately removed from service and repaired or replaced.

25.

When portable ladders are used, they shall be secured against slippage by the use of safety feet and tied-off.

26.

Portable aluminum ladders shall not be used by electricians or by any other personnel where they may come into contact with electrical circuits.

27

Tools or other materials shall not be carried up or down a ladder unless properly secured to the body.

C-9

PIPE RACKS

1.

Pipe racks shall be level and firmly butted and fixed together with no gaps or elevation differences between each rack or the catwalk.

2.

Outer ends of each pipe rack shall have sturdy stop pins in place to prevent pipe from rolling off the rack. Pins should be permanently attached to the rack to prevent loss.

3.

The catwalk shall be level and free from tripping hazards with a stairway to the ground at each end.

4.

Every pipe rack shall be flush at top and bottom to prevent pipe hang-up.

5.

When pipe is to be stored in layers on the rack, spacers shall be used between the layers and each layer shall be choked.

6.

Provision shall be made for the storage of thread protectors.

7.

Thread protectors shall be lowered from the rig floor in a container or lashed together. They shall not be dropped or rolled down the pipe ramp.

C-10 PIPE HANDLING 1.

Tag line must be used when transferring tubulars.

2.

When pipe is being transferred between pipe racks, catwalks, or trucks, the temporary supports or skids shall be so constructed, placed, and anchored that they will support the load placed upon them.

3.

All driveways alongside pipe racks shall be level so that the truckbed is parallel and even with the racks.

Safety Requirements for Drilling & Workover 55 of 82 Rev: June 2006

4.

During loading, unloading, and transferring of pipe or other similar tubular goods, no workers shall be required or permitted to be on top of the load, or between the load and the pipe racks.

5.

Manual pipe loading, unloading, and transferring operations shall be done only from the pipe ends, and pipe shall be loaded or unloaded from trucks one layer at a time.

6.

When transferring drill collars, tubular goods, or other similar materials which are not provided with shoulders, pickup subs shall be used during the transfer of those materials into the derrick. Subs shall be secured completely into the drill collars before the collars are lifted.

7.

Thread protectors shall be left on tubular goods and downhole equipment when it is being pulled up the pipe ramp. A lifting bail, sub or nubbin screwed into the box end is acceptable in lieu of a thread protector.

8.

A multi-purpose safety clamp (dog collar) shall always be available for use on the rig floor.

9.

When a nubbin or lift sub is used as a lift point in handling drill collars or other tubular goods, the nubbin shall be made up with positive torque using chain tongs. Nubbins installed "hand tight" are not sufficient. All such nubbins or lift subs must be bored full "ID" and have a box connection to accept a stabbing valve.

10.

Trailers used for transporting pipe or as a pipe rack during drilling, workover, or pipe salvaging operations shall be equipped with a guard the full length of both sides of the trailer.

11.

Trailers used for transporting pipe shall be equipped with side stakes adequate to prevent the pipe from rolling off. Also, the entire load of pipe shall be secured with chains or straps that are sufficient to hold the pipe in place on the trailer if there is a complete failure of the stakes. All pipe trailers shall use stakes and adequate binding.

12.

Guards on trailer sides shall be so designed and constructed to ensure that when pipe is being hoisted into the derrick the lower end of the pipe will not roll off the trailer.

13.

Provision shall always be made to prevent pipe, tubular goods, or similar round material from accidentally rolling off a pipe rack.

C-11 DRAWWORKS CONTROLS 1.

Each automatic cathead on the drawworks shall have a separate control. Dual controls may be used only where a locking device is installed to prevent one automatic cathead from being accidentally engaged while the other is in operation.

2.

All drilling controls on the console shall be clearly identified.

3.

Except during drilling with automatic driller engaged, drawworks controls shall not be left unattended while the hoisting drum is in motion. When drilling with an automatic driller, it is permissible for the driller to step out of arms reach of the controls; however, he must always be in a position to simultaneously see the drilling controls, associated gauges, and drill floor.

Safety Requirements for Drilling & Workover 56 of 82 Rev: June 2006

4.

Before putting the drawworks in motion, the worker in charge of the drawworks shall ensure that all other workers are clear of the machinery and lines.

5.

When there is a danger of the controls being engaged by accidental contact with catlines or other equipment, the controls shall be protected by a guard.

6.

There shall be an emergency kill switch at the driller's console for the emergency shutdown of the rig motors and mud pumps. This switch shall be checked periodically by the rig electrician to ensure that it is ready for immediate use.

7.

All instrumentation at the driller's console, including pit level indicator, mud rate return flow, and pump stroke counter, shall be installed, used and maintained according to its manufacturer's specifications. All warning alarms shall be kept turned on.

C-12 BRAKES 1.

The RIG OPERATOR shall ensure that the brakes on the drawworks of every drilling rig are tested by each driller when he comes on tour to determine whether they are in good working order. Both the mechanical brake and the auxiliary brake shall also be examined by the toolpusher at weekly intervals to determine the condition of the brake blocks, linkage, seals, and other operating parts.

2.

Unless the drawworks is equipped with an automatic driller, the brake shall not be left unattended without first being tied down. [Note: Meaning of "unattended" in context of automatic usage]

3.

Where a hold down chain is used in securing the drawworks brake handle, the slot for holding the chain shall be provided with a seat or, where a side lug is provided, it shall be curved upwards to prevent accidental disengagement of the hold down chain.

C-13 ROTARY TABLE 1.

Water hoses, lines, or chains shall not be handled or used near a rotary table while it is in motion.

2.

When visibility on a rig floor is obscured, personnel shall not be required or permitted to work on the rig floor while the rotary table is in motion.

3.

The rotary table shall not be engaged until all personnel and materials are clear of it.

4.

During tripping operations, personnel setting the slips shall be cautioned to keep their feet well clear of the rotary table and the rotating slip handles.

5.

When the kelly bushing drive, pipe, or other tubular equipment are not in it the opening in the rotary table shall be covered with a metal plate.

C-14 CATHEAD LINES AND SPINNING CHAINS 1.

Cathead Lines and Spinning Chains are NOT to be utilized in Saudi Aramco drilling and workover operations. Safety Requirements for Drilling & Workover 57 of 82

Rev: June 2006

C-15 HOISTING AND ROTARY OPERATIONS 1.

A driller going off duty shall inform his relief of any special hazards or ongoing work that may affect the safety of the crew. Oncoming tour personnel shall be alerted by the driller to ongoing work that could affect their safety.

2.

The driller shall never engage the rotary clutch unless he is watching the rotary table. The rotary clutch shall not be engaged until the turntable is clear of personnel and material.

3.

Drill pipe or casing shall not be picked up suddenly so that the bottom end whips about, endangering employees working on the floor.

4.

The driller shall never begin hoisting drill pipe until he has ascertained that the pipe is latched in the elevator or the derrickman has signaled that he may safely hoist the drill pipe.

5.

The derrickman shall ensure that the elevators are properly clamped onto all pipe joints and locked prior to signaling the driller to engage the load.

6.

During instances of unusual loading of the derrick or mast, such as when making an unusually hard pull, only the driller and other essential supervisory personnel shall be allowed on the rig floor; and as well, no one shall be allowed in the derrick or mast. Such precautions shall always be undertaken when loading exceeds ninety percent (90%) of the manufacturer's rated load for the derrick or mast or any component of the hoisting gear, or attached drilling or casing string.

7.

Personnel shall never be permitted to stand in front of hoisting drums or line spoolers; slack line may form and entangle the personnel standing there.

8.

Personnel shall never stand near the well bore when any wireline device is being run.

9.

Hoisting control stations shall be kept clean and the controls labeled as to their function.

C-16 SLIPS 1.

All slip handles shall be in place, in good condition, and not project beyond the rotating top of the turntable.

2.

Slips shall be inspected by RIG OPERATOR personnel before each trip to check for worn dies, keeper pins, presence of retaining ring, worn hinge pins, rib cracks, and segment deformation.

3.

The tapered side of the slips shall always be lubricated to facilitate slip removal.

4.

No one shall be allowed to kick the slips into place when tripping.

5.

Slips shall not be allowed to ride the pipe while tripping out.

Safety Requirements for Drilling & Workover 58 of 82 Rev: June 2006

6.

The RIG OPERATOR must not, for any reason, allow other than the proper size slips to be used.

7.

No field welding shall be permitted on slips which have been heat treated.

C-17 HOISTING LINES 1.

The working load on hoisting lines, chains, slings, and fittings shall not exceed the safe working load recommended by the manufacturers.

2.

Ton-mile records shall be maintained by the toolpusher for all drilling lines. Drilling lines shall be slipped and cut according to established RIG OPERATOR policy unless the line develops unusual wear, damage, or wickering before it is due to be slipped and cut. When the wire rope is slipped and cut, it shall be recorded on the tour report as to date and length of wire rope removed.

3.

In no event shall the hoisting line or sand line be allowed to remain in service if it shows evidence of kinking, crushing, cutting, wearing, bird caging, or unstranding.

4.

Hoisting lines shall be securely fastened to every winding drum and at least five full wraps of wire rope shall remain on a drum when the traveling block is in its lowest position.

5.

Knots or cable clips shall not be used as stoppers on rope ends which pass through an opening in a winding drum.

6.

Before the hoisting line is removed from a drum, the traveling block shall be laid on the derrick floor or held suspended by means of a separate wire rope adequate to support the load.

7.

A hoisting line under load shall never be allowed to come in direct contact with any derrick member, stationary equipment, or material in the derrick unless specifically designed or intended for line contact.

8.

A dead-line anchor for a drilling line shall be so constructed, installed, and maintained that its strength shall at least equal the working strength of the hoisting line.

9.

All safety pins shall be kept in place at the outer periphery of the drilling line anchor to prevent the line from jumping off the anchor during slack loading.

10.

Excess drilling line shall always be kept properly protected and spooled.

11.

A cable cutter shall be available on the rig for cutting the drilling line. The use of a cutting torch for cutting the drilling line is prohibited.

12.

Making loops or eyes in wire rope should be avoided, use manufactured slings. If used, clips shall be installed with U-bolts on the dead or short end of the rope.

13.

The number of cable clips shall be according to the following table. The minimum spacing between clips shall be six times the diameter of the wire rope.

Safety Requirements for Drilling & Workover 59 of 82 Rev: June 2006

CABLE CLIPS ROPE DIAMETER (Millimeters)

ROPE DIAMETER (Inches)

NUMBER OF CLIPS

11 to 15.9

7/16 to 5/8

3

19 to 25.4

3/4 to 1

4

28.6 to 31.7

1 1/8 to 1 1/4

6

34.9 to 44.4

1 3/8 to 1 3/4

7

2 to 2 1/4

8

2 1/2

9

50.8 to 57.2

63.5

14.

All clip bolts shall be retorqued after new clips have been in use one hour.

15.

The use of "Flemish eye", "farmer's eye", or "rig operator's standby", or any other knot shall not be permitted in any wire rope. Knots in wire rope often lead to premature failure.

C-18 RIDING HOISTING EQUIPMENT 1.

Derrickman and other personnel required to work in the derrick or mast shall ascend and descend the derrick or mast by means of the ladder provided. Riding the pipe hoisting gear is forbidden.

2.

No personnel shall slide down any pipe, kelly hose, cable, or rope line other than the escape line in an emergency.

3.

In an emergency, personnel may be lowered from the derrick by means of the traveling blocks or catline. In this case the rotary table shall be stopped and an experienced person, designated by the RIG OPERATOR, shall operate the controls.

4.

The use of a boatswain’s chairs is prohibited. The use of riding type safety belts is permissible for duties, such as inspection or lubrication, that require a person to work in an elevated position. This is allowed if, in the judgment of the senior RIG OPERATOR supervisor, a higher risk of personnel injury would be incurred by workers erecting and working on scaffolding than by hoisting or lowering a man in a riding belt. When a person is to be hoisted or lowered in a riding belt, the following conditions must all be met: (a)

Any personnel to be hoisted must be familiar with the task to be performed and be willing to perform the task. No person can be compelled to ride or Safety Requirements for Drilling & Workover 60 of 82

Rev: June 2006

work from a belt. (b)

The riding belt used must be of such design that no effort is required by the person being hoisted to remain inside the belt and in an upright position.

(c)

The hoisting mechanism must have controls which allow the speed of ascent or descent to be controlled by the hoist operator, have a positive brake or lock that will automatically stop and suspend a load at any instant the hoist controls are released, and the hoist operator must be experienced in the operation of the hoist. Use of a cathead to hoist personnel is specifically prohibited.

(d)

A meeting shall be held immediately prior to the hoisting operation to review the task to be accomplished. A means of communication must be established between the person being suspended in the riding belt and the hoist control operator. All lifting and lowering shall be at the direction of the person suspended in the riding belt, NOT the hoist control operator.

(e)

All hand tools carried by the person suspended in the riding belt shall be attached to the riding belt by safety lines to prevent them from falling should they be dropped.

(f)

All other operations on the rig, such as the rotation of the kelly, should be suspended while personnel are working from a hoisting line.

C-19 ELEVATORS 1.

Elevators shall be equipped with a positive latch or safety latch combination designed to prevent drill pipe or other tubular goods from prematurely disengaging.

2.

Drill pipe, casing, and tubing elevators shall be provided with a complimentary (to the elevator latch) collar or protrusion designed to prevent elevator links or latches from becoming accidentally disengaged.

3.

With the exception of the latch handles, elevators shall be free of projections that could catch on the derrick structure or rigging equipment.

4.

Elevators shall be inspected by RIG OPERATOR personnel before each trip to ensure that they are in good operating condition. If defects are found, elevators shall be removed from service until repaired or replaced.

5.

When the kelly is in the rathole, the swivel bail shall be positioned so that it does not interfere with or damage the elevators during tripping operations.

C-20 MANUAL TONGS 1.

Each rotary tong shall be attached to the derrick or a backup post by means of a wire rope snub line. The breaking strength of the snub line shall be above the capacity of the pull that is exerted on the tongs by means of the automatic cathead. Both ends of the snub line shall be secured by the required number of wire rope clips, properly installed, or other equivalent fittings. (Refer to Section C-17 on "HOISTING LINES")

Safety Requirements for Drilling & Workover 61 of 82 Rev: June 2006

2.

Tong backup posts, kelly pull-back posts, tong backup lines, and safety lines shall not be secured to derrick or mast girts or to derrick or mast legs unless the legs are so constructed and the lines so attached that the stresses imposed will not result in structural damage to the legs.

3.

The wire rope and connections on tongs shall be frequently inspected for wear, broken wires, and wire rope rot, and shall be replaced when necessary.

4.

Tong dies shall be inspected regularly by RIG OPERATOR personnel and replaced as they become damaged or worn.

5.

Die keepers shall always be kept in place to prevent dies from becoming displaced from the retainer grooves.

6.

All threaded hinge pins shall be equipped with a nut and cotter pin.

7.

Tongs shall be inspected and greased by RIG OPERATOR personnel before each trip.

8.

Tongs that fail to latch properly because of worn jaws, hinge pins, or other defects shall be removed from service until either repaired, rebuilt, or replaced.

9.

No field welding shall be done on tongs which have been heat treated.

10.

RIG OPERATOR personnel shall handle the tongs only by the appropriate handles.

11.

When not in use, tongs shall be hooked back on the rig floor in such a manner as to present no obstruction to personnel passing between the tongs and the rotary table.

C-21 TONG COUNTERWEIGHTS 1.

A tong counterweight above a derrick floor, when not fully encased or running in permanent guides, shall be held to the frame of the derrick with a wire rope safety line, not less than 15.9 millimeters (5/8 inch) in diameter, which will prevent the counterweight from coming within 2.4 meters (8 feet) of the floor.

2.

The wire rope connecting a tong to a counterweight shall have a minimum diameter of 12.7 millimeters (1/2 inch).

C-22 MAKING UP AND BREAKING JOINTS 1.

Spinning chains shall not be used.

2.

The rotary table shall not be used for the final making up or initial breaking out of a pipe connection. The potential forces that can be delivered by the rotary table far exceed the breaking strength of the safety or snub lines used to restrain the tong handles. When the snub or safety line breaks, the contained energies are suddenly released and the tong handles whip around the drill pipe.

3.

The snapping up of a tool joint by using an automatic cathead or pipe joint breaker of the jaw-clutch type, which automatically disengages its clutch at the completion of the fixed stroke, shall not be permitted. Safety Requirements for Drilling & Workover 62 of 82

Rev: June 2006

C-23 MUD BUCKET OR SAVER 1.

Whenever a wet joint or stand of pipe or tubing is being broken and disconnected above a derrick floor, a mud bucket or mud saver shall be used to carry all liquids away from the rig floor to the mud tanks or sump.

2.

The mud bucket or mud saver shall be checked regularly to ensure that the rubber seals are in good condition, latches are working properly, and that it is safely suspended in the derrick in such a manner that it can be easily moved to and from the drill pipe.

C-24 POWER TONGS 1.

The control device on power tongs shall be either designed or guarded to prevent accidental activation.

2.

The discharge end of hoses used on power tongs shall be disconnected before any repair, replacement, or other similar work is done on tongs, chains, dies, or other component parts.

3.

High pressure lines (hydraulic or air) shall have a safety pressure relief valve that shall never be set higher than the manufacturer's specifications for the working pressure of the lines or valve.

C-25 RACKING PIPE IN DERRICKS 1.

Whenever drill pipe, drill collars, or tubing are racked in a derrick, provision shall be made for the complete drainage of any fluids or gases in the stands.

2.

Drill pipe, collars, or tubing shall be racked to safely distribute the load in the finger boards.

3.

Stands of drill pipe, drill collars, tubing, casing, and rods shall be secured at the top ends by means of a tie-back rope or an equivalent device to prevent them from falling out of or across the derrick.

4.

A pipe hook or tag line shall be available for use by the derrickman to assist in maneuvering, stacking, and securing pipe in the derrick.

5.

If pipe hooks are used above the derrick floor, the pipe hook shall be secured to the derrick in a manner that will prevent the hook from falling.

C-26 FINGER BOARDS 1.

Fingers, finger boards, and finger braces shall be installed in the derrick or mast in a workmanlike manner to safely withstand the stresses imposed on them by pipe or other tubular equipment racked in the derrick or mast. Fingers shall be kept in good repair, free from bending, cracks, or other defects.

Safety Requirements for Drilling & Workover 63 of 82 Rev: June 2006

2.

The unsupported ends of the monkey board fingers shall be connected to the monkey board frame with a wire rope or chain of sufficient strength to hold the weight of the fingers in case of failure.

C-27 STABBING PLATFORMS AND BOARDS 1.

The RIG OPERATOR shall ensure that each drilling rig is equipped with a safe stabbing platform for the stabber to use when running casing, tubing, or during well servicing operations.

2.

The stabbing platform shall not be located opposite the V-door if there is a likelihood that either the stabber or the platform could be struck by a joint of casing as it is being pulled into the derrick.

3.

Before casing is to be run, the stabbing platform shall be inspected by the rig mechanic to ensure that the platform is in good operating condition, free from damage, lubricated, and all safety devices working.

4.

Each fold down extension platform shall be either counterbalanced so that a minimum amount of force is required to lift the platform, or the platform must be powered.

5.

Every pneumatic or electric powered stabbing platform shall be equipped with:

6.

(a)

An automatic fail-safe brake.

(b)

Shock absorbers at the bottom of the track that will withstand maximum speed descent into the stop without damage.

(c)

The safe working load (SWL) marked on the platform.

(d)

Upper and lower travel limit switches.

(e)

Standard guard rail, intermediate rail, and toeboard protection on each side and back of the platform.

(f)

A non-skid floor surface.

(g)

A rail assembly that is securely fastened to the rig structure.

(h)

A platform control lever that automatically returns to the neutral position when released.

(i)

A secondary safety system to support the carriage if the winch or winch cable fails.

(j)

A belly-belt for the stabber on the platform.

(k)

A fixed ladder for access to and exit from the platform.

Any electrically operated stabbing platform shall meet the requirements of the electrical classification for the area in which it is located.

Safety Requirements for Drilling & Workover 64 of 82 Rev: June 2006

7.

Each stabbing platform on a rig shall be installed, used, and maintained according to the manufacturer's instructions.

8.

In those areas where hydrogen sulfide is a possible hazard, breathing air shall be available for personnel on the stabbing platform.

9.

On onshore workover rigs where only a stabbing board can be used, the board shall consist of at least one 7.6 centimeters (3 inches) by 30.5 centimeter (12 inch) construction grade lumber or metal plank of the same width or and strength.

10.

When lumber is used for a stabbing board, expanded metal or a wire rope shall be fastened to the underside of the plank across its full width.

11.

Each end of a stabbing board shall be fastened to the derrick or mast with a wire rope at least 12.7 millimeters (1/2 inch) in diameter.

12.

On single stand rigs where there is insufficient room for 30.5 centimeter (12 inch) wide stabbing boards, a special stabbing board shall be designed and used.

13.

Personnel shall not be allowed to stand on the girts to stab casing.

C-28 SAFETY BELTS AND HARNESSES 1.

When working 3.1 meters (10 feet) or more above the derrick floor, personnel shall use a safety harness attached to a lifeline adequately secured to the structure, unless they are protected by another approved method.

2.

Personnel engaged in racking pipe at the monkey board, rod board, or other platform shall be provided with and shall wear a safety harness fitted with shoulder straps, and the shoulder straps shall be in place at all times.

3.

The lifeline attached to the safety harness shall be at least 15.9 millimeters (5/8 inch) manila rope, in good condition with no splices. It shall be securely fastened to the derrick.

4.

The safety harness lifeline at the stabbing board shall be securely attached to the derrick structure.

5.

Synthetic rope shall not be used as a substitute for manila rope.

6.

Safety harnesses and lifelines shall be maintained in good condition. Damaged harnesses or lines shall be replaced immediately.

7.

A spare safety harness in good condition shall be available for use on every rig.

C-29 BLOWOUT PREVENTERS 1.

Blowout preventors and ancillary equipment shall be installed, used, maintained, and tested as prescribed in the "ARAMCO BLOWOUT PREVENTION STANDARDS" unless specified differently in the approved drilling or workover program for the work in progress.

Safety Requirements for Drilling & Workover 65 of 82 Rev: June 2006

2.

During the installation of the blowout preventor assembly, no personnel shall be permitted or required to be in an area where they may be injured due to the swinging or dropping of the blowout preventor assembly. Tag lines shall be used for initial alignment and control until the BOP and wellhead flange are within 2.5 centimeters (1 inch) of mating. In those cases where the structural arrangement of the rig and wellhead are such that the exact position of the BOP stack relative to the wellhead can only be determined by an observer, it is permissible for a single observer to approach the wellhead for the purpose of directing the movement of the BOP. All other personnel are to remain clear of the BOP stack until directed by the person in charge to rest the stack on the wellhead.

3.

When removing blowout preventors from the wellhead, either tag lines, tugger lines, or other equipment shall be utilized to control BOP stack movement. Until the stack is securely at rest, all personnel shall remain a safe distance from it in case it should suddenly rotate or fall.

4.

Wire rope, not chains, shall be used to lift preventors, diverters, and stack assemblies.

5.

To avoid sudden overturning of the equipment when being moved lifting lines shall be attached well above the center of gravity of the BOP.

6.

When BOP stacks are installed on a wellhead, they shall be braced to prevent lateral or vertical movement that could impair the integrity of the wellhead structure, four turnbuckles attached to the rig substructure are normally required.

7.

The accumulator unit shall be regularly inspected by RIG OPERATOR personnel to ensure that the required pressure is being maintained, the gauges are in good working order, and the unit is free from leaks and spills.

8.

Areas around the blowout preventor controls shall always be kept clear, unobstructed, and well-lighted.

9.

The accumulator shall be located at least 100 feet from the well bore for exploratory and Khuff gas wells and 60 feet from the wellbore for development oil wells. Also, it should be shielded using corrugated metal, or equivalent, to provide protection for the accumulator and its operator, not only from the wellhead and other operations around the rig but from raining liquids as well.

10.

There shall be at least two sets of controls for operating the accumulator. The master controls shall be at the accumulator, and the remote controls shall be located on the rig floor where they are accessible to, and visible by, the driller.

11.

All operating controls shall be clearly marked according to their function and ram sizes. Accumulator controls shall be in either the open or closed position, not in the neutral position.

12.

Welding is not permitted on BOP's.

13.

Hydraulic lines from the accumulator to the BOP's shall be either steel pipe or approved equivalent armored hose.

14.

The RIG OPERATOR shall train all crew personnel in the proper operation of BOP equipment in emergencies. Such training shall be according to the "ARAMCO BLOWOUT PREVENTION STANDARDS", plus any additional training the RIG Safety Requirements for Drilling & Workover 66 of 82

Rev: June 2006

OPERATOR may direct. The RIG OPERATOR shall also ensure that all its floor personnel are capable of timely response to situations requiring the use of BOP equipment, and that emergency procedures for drills and actual emergencies are conspicuously posted in the doghouse. 15.

The RIG OPERATOR will conduct BOP drills on each rig often enough for each member of each crew to experience one drill per month. These drills shall be entered into the driller's log.

C-30 SAFETY VALVES 1.

All required safety valves (ball type) and inside BOP's (check valve type) with tool joint O.D. and the largest available bore plus any necessary subs to fit drill collars, drill pipe, or tubing in use, shall be kept on the rig floor at all times.

2.

All safety valves, inside BOP, and subs, as well as closing wrenches and setting tools, shall be stored (valves open) in a highly visible and convenient permanent location.

3.

An additional small size safety valve and inside BOP shall be required with a tapered drill string. THE SAFETY VALVE SHALL ALWAYS BE INSTALLED FIRST, PROPERLY MADE UP AND CLOSED, BEFORE INSTALLING THE INSIDE BOP.

C-31 WEIGHT INDICATORS 1.

Every drilling rig shall be equipped with a reliable weight indicator that is readily visible to the driller.

2.

When the weight indicator is hung above the rig floor, it shall be secured by means of a wire rope safety line.

C-32 TEST PLUGS 1.

Every test plug used above a derrick floor shall be attached to the links by a wire rope safety line.

C-33 RIG TANKS OR PIT ENCLOSURES 1.

Rig tanks or pits used for the circulation of drilling fluids containing flammable material shall be protected from sources of ignition.

2.

When rig mud tanks or pits are enclosed, adequate mechanical ventilation shall be provided.

3.

Any rig tank including void tanks, ballast tanks, bilge tanks, etc., are enclosed spaces and no personnel shall be required or permitted to enter without following established procedures for confined tank entry. (Refer to Section B-32, "CONFINED SPACES")

Safety Requirements for Drilling & Workover 67 of 82 Rev: June 2006

C-34 PRESSURE RELIEF DEVICES, RIG MUD PUMPS, PIPING, AND HOSES 1.

A pressure relief device shall be installed on all power driven rig mud pumps that directly service the drilling or maintenance of the well. There shall be no valve between the rig mud pump and the pressure relief device.

2.

The pressure relief device shall be set to discharge at a pressure not in excess of the manufacturer's recommended maximum working pressure of the rig mud pumps and all connecting pipes and fittings.

3.

Shear pins used in pressure relief devices shall be those specified by the manufacturer. Tools, welding rod tips, etc., shall not be used for shear pins.

4.

All pressure relief devices of the shear pin type shall be provided with guard or barrier placed around the shear pin and spindle of the device.

5.

All fluids or materials discharged through a pressure relief device shall be piped in a direction that will not endanger workers.

6.

There shall be no valve in the discharge opening of a pressure relief device or in the discharge pipe connected to it.

7.

The piping connected to the pressure side and discharge side of a pressure relief device shall not be smaller than the normal pipe size openings of the device.

8.

The piping on the discharge side of the pressure relief device shall be adequately secured to prevent movement during discharge.

9.

The pressure relief devices lines shall be flushed at the beginning of each well or on a monthly basis.

10.

The piping from the discharge side of the pressure relief device shall be continuously sloped downward to the suction pit in order to drain liquids.

11.

All mud guns used for jetting shall be securely anchored.

12.

Quick-closing valves shall not be used on the discharge line from a positive displacement type mud pump.

13.

Clamps and wire rope safety lines or chains shall be used to fasten a kelly hose at the stand-pipe end to the derrick and at the swivel end to the swivel housing. The safety chains shall never be attached to the goosenecks as they are subject to washing out and may be the point of failure.

14.

Mud line system hoses, which may be subject to whipping in case of failure, shall be equipped with clamps and wire rope safety lines or chains of sufficient strength and secured to an adequate support.

C-35 CELLARS 1.

Cellars for onshore rigs that are 1 meter (39.4 inches) or more in depth shall be provided with a safe means of access and exit, (i.e. ladder, stairs, ramp, etc.). Barrier protection shall be provided around open cellars. Safety Requirements for Drilling & Workover 68 of 82

Rev: June 2006

2.

Every cellar and means of entry and exit shall be soundly constructed and shall be kept in a safe condition.

3.

Because of the hazards of hydrogen sulfide, flammable gases, and oxygen deficiency, the atmosphere of the cellar for onshore rigs shall be tested by a competent person designated by the RIG OPERATOR before any personnel are permitted to enter.

4.

When personnel are required to work in a cellar, the cellar and the exits from it shall be kept reasonably free from water, oil, drilling fluid, and other substances that may endanger the personnel.

Safety Requirements for Drilling & Workover 69 of 82 Rev: June 2006

SECTION D: SPECIAL OPERATIONS D-1

CRANE OPERATIONS

1.

The RIG OPERATOR is responsible for crane operations at Saudi Aramco drilling and workover locations. This responsibility includes, but is not limited to, ensuring the following: (a)

Each operator of a crane or other hoisting device must be thoroughly trained and properly licensed to operate that equipment. The required licenses are (1) a valid Saudi Arabian Government crane operator's license for the type equipment being operated, and (2) a Saudi Aramco crane operator's license.

(b)

Each crane, mechanical hoisting device, or other associated equipment, must have a current Saudi Aramco inspection sticker. Using a crane that has received a "REJECTED" sticker from a Saudi Aramco crane inspector shall be considered as placing any personnel on that location into an IMMINENT DANGER situation.

(c)

All crane operations shall be directly supervised by the RIG OPERATOR supervisor in charge at the location. The direction of sitting the crane on a stable bed, rigging of the load, movement of the load, and landing of the load shall be the responsibility of the RIG OPERATOR supervisor in charge. The RIG OPERATOR supervisor in charge can delegate this responsibility but he shall be accountable for any mishap that may occur due to error such as improper rigging, faulty direction, or operator miscalculation.

2.

The RIG OPERATOR supervisor in charge shall read and be completely familiar with the requirements of all Saudi Aramco written safe crane operations procedures and general instructions. This material consists of G.I. 7.025, G.I. 7.026, G.I. 7.027, G.I. 7.028, G.I. 7.029, and G.I. 7.030, plus the Saudi Aramco Crane Safety Handbook and the Saudi Aramco Construction Safety Manual Section III. Copies of this material is available through Saudi Aramco Drilling and Workover Operations or Dhahran Area Loss Prevention Division.

3.

Rated load capacities, recommended operating speeds, special hazard warnings, and any instructions such as those describing use of outriggers, shall be in a language readily understood by the crane operator and conspicuously posted on all equipment. Instructions or warnings shall be visible to the operator while he is at this control station.

4.

All crane controls shall be properly marked to show their function.

5.

Crane operators shall follow lifting directions ONLY from assigned signalers. However, an "emergency stop" signal from anyone on the location must be obeyed immediately.

6.

The crane directors shall use the international standard hand signals.

7.

A durable chart showing these hand signals shall be conspicuously posted in the cab of each crane.

8.

Crane windows shall be kept clean and free from defects that could affect visibility.

Safety Requirements for Drilling & Workover 70 of 82 Rev: June 2006

9.

All safety devices provided on cranes such as boom stops, boom angle indicators, and anti-two-blocking switches shall be kept in proper working order.

10.

All lighting installed on a crane by the manufacturer, including boom lights, travel lights, instrument panel lights, and warning lights shall be properly maintained and used.

11.

Before attempting any lift with a crane, RIG OPERATOR shall first determine the weight of the load. No lift shall be attempted if load is beyond crane’s rated lifting capacity as listed on chart for current boom angle, radius, configuration, and position of outriggers.

12.

Onshore mobile cranes shall not be permitted on any drill site if the fully extended crane boom or load line can contact an electric power line FROM ANY POINT ON THE DRILL SITE.

13.

Until SCECO authorities indicate that a line is not an energized line, and it has been visibly grounded, any overhead wire shall be considered to be energized.

14.

Cranes shall not be used for dragging loads sideways.

15.

Each crane hook shall be provided with a safety latch.

16.

All cranes shall be equipped with a horn. Offshore cranes shall also be equipped with a two-way means of communication.

17.

Personnel shall never be permitted to ride the hook or ball of a crane.

18.

Tag lines shall be used to guide and steady equipment being loaded or unloaded.

19.

Floating cranes and floating derricks shall meet the applicable requirements for design, construction, installation, testing, maintenance, and operation as prescribed by the manufacturer.

20.

An approved life vest shall be worn by the operator of any crane operating over water.

21.

Deck cranes shall be shut down and cradled when wind speeds exceed 32 knots (20 mph). Use of a crane in wind speeds shall be restricted to emergency operations only and the proposed use shall be thoroughly reviewed and approved by the senior on-site RIG OPERATOR’s supervisor.

22.

Winds speeds shall be monitored at all times by the control room operator on offshore rigs.

23.

All crane operations shall be suspended during any helicopter movement on or around an offshore rig.

Safety Requirements for Drilling & Workover 71 of 82 Rev: June 2006

D-2

RIGGING, MATERIAL HANDLING AND SLINGS SEE ALSO: CONSTRUCTION SAFETY MANUAL, SECTION III, PART 2.0 ‘SLINGS AND LIFTING GEAR’

1.

The operator of any vehicle, such as cranes, loaders, bulldozers, forklifts, or tractors, shall not move the vehicle or otherwise manipulate its equipment until signaled to do so by the designated signalman.

2.

The signalman shall ensure that no personnel are in the path of the vehicle or load.

3.

For any equipment that may slide or roll off a loaded truck or trailor, the lifting slings and hoist line must be attached and the slack taken out before the tie down securing devices are removed.

4.

Personnel shall not ride on any load or part of a load being raised or lowered.

5.

A tag line shall be used to control the movement of a load being raised or lowered.

6.

A tag line shall be long enough for the worker controlling it to avoid being struck by any movement of the load.

7.

Personnel shall not be required or permitted to work, stand, or pass under a suspended load.

8.

Personnel shall not be permitted to work, stand, or pass between the winch mechanism and a load being winched, nor in an area where the worker may be injured due to winch line or winch line mechanism failure.

9.

Personnel shall not be required or permitted to work, stand, or pass within the length of a cable under tension.

10.

The working load on winch mechanisms, gin poles, hoists, lines, slings, grommets, hooks, and fittings shall not exceed the safe working load (SWL) recommended by the manufacturer. SWL shall be displayed on each device.

11.

Winch mechanisms, lines, slings, grommets, hooks, and fittings shall be thoroughly inspected by the operator of the equipment before use for evidence of overloading, excessive wear, or damage. Any rigging equipment found to be defective shall be immediately removed from service and either repaired or destroyed.

12.

The safe working load (SWL) of a sling shall be marked on the sling. If the SWL is exceeded the sling shall be taken out of service and destroyed per G.I. 7.02, ‘Wire Rope Slings.’

13.

When using slings, softeners shall be provided between the sling and sharp unyielding surfaces of the load to be lifted.

14.

A sling shall not be pulled from under a load when the load is resting on the sling. Cribbing consisting of cut drill line, lumber, etc., shall be used to support the load and provide a space for sling removal.

15.

In order to eliminate shock loading, all slack in the sling shall be taken up carefully by the crane operator before beginning the lift.

Safety Requirements for Drilling & Workover 72 of 82 Rev: June 2006

16.

When using other than single leg slings for straight vertical lifts, the rigger shall be aware of the loading changes that occur when different hitches are used (i.e., basket, choker, etc.) or when the angle of loading is changed in multiple leg bridle slings.

17.

When using a choker hitch, the sling shall be equipped with either a protective thimble, protector arc or sliding choker hook in order to reduce wear and abrasion at the point where the loop contacts the sling body.

18.

When not in use, slings shall be stored in such a manner that will protect the slings from damage by moisture, extreme heat, corrosion, or physical abuse.

D-3

DRILL STEM TESTING

1.

Initial flowing of formation fluids to surface during a drill stem test shall be restricted to daylight hours only.

2.

During drill stem testing or the removal of pipe after a drill stem test, the Rig Supervisor or some other equally qualified person shall remain on the rig and shall exercise continuous supervision over all operations.

3.

When oil or gas or both have been encountered during a drill stem test, the drill stem contents should be replaced with drilling fluid. Fluid recovered from the mud saver shall flow back to the tanks or to a reserve pit.

4.

During drill stem testing, motors and engines not required in the operation shall be shut off. All engine exhausts shall be equipped with water sprays or spark arrestors for spark suppression. The RIG OPERATOR shall ensure that water on engine exhausts is shut off when engines are not operating.

5.

During drill stem testing, no motor vehicle shall be permitted within 22.9 meters (75 feet) of the well bore.

D-4

SWABBING

1.

Swabbing operations shall not be carried out during the hours of darkness.

2.

Auxiliary swabbing units shall be anchored securely during swabbing operations.

3.

Where swabbing tanks are not provided with an external means of gauging, any personnel physically gauging the tanks shall be provided with, and shall wear, approved respiratory protective equipment. In addition, they shall be continuously monitored during this procedure by another person.

4.

Oil savers shall be equipped with controls which can be readily operated from the rig floor.

5.

During swabbing operations, the fluids shall be piped directly to a battery, flare pit, skid tank, or mobile trailer tank located 45.7 meters (150 feet) or more from the well bore.

6.

The air intake and exhaust of the pump engine shall be located 7.6 meters (25 feet) or more from the rig tank when a well is being circulated with hydrocarbon or hydrocarbon based fluid. Safety Requirements for Drilling & Workover 73 of 82

Rev: June 2006

7.

During loading or unloading, the tank truck exhaust shall be located at a distance of not less than 7.6 meters (25 feet) from the rig fuel tank and a minimum of 22.9 meters (75 feet) away from the well bore.

8.

Fluids used in or as a result of swabbing operations shall not be piped to a tank truck under any circumstances.

D-5

CEMENTING

1.

During cementing all piping systems which will be exposed to either pump or well pressure shall be securely staked down or secured in such a manner as to prevent any undue whipping or flailing of the pipe if a failure occurs.

2.

The cementing head shall be secured to the elevator links (bales) with a wire rope safety line.

3.

The leadoff chicksan from the cementing head shall be secured to either the head or elevators with a wire rope safety line.

4.

After completion of cementing work, all cementing lines shall be flushed with fresh water.

D-6

WELL SERVICING AND WELL STIMULATION

1.

During drill stem testing and well stimulation, all piping systems, which will be exposed to either pump or well pressure, shall be securely staked down or secured in such a manner as to prevent any undue whipping or flailing of the pipe should a failure occur.

2.

Swivel joints provided with lugs for hammer tightening shall not be used in a well servicing operation unless they are manufactured from steel.

3.

Hammering or tightening of unions or connections while under pressure shall not be permitted.

4.

Any tool or equipment other than normal drilling equipment, which is connected to the top of the drill string, casing, or tubing while it is in the hole, shall be secured against falling by means of a wire rope safety line or safety chain.

5.

All piping, pumps, valves, and fittings used in servicing operations shall be hydraulically pressure-tested prior to the commencement of each well cementing or servicing operation. Subsequent pumping pressure shall not exceed the test pressure.

6.

On any well service job involving pressure only the minimum number of people necessary to perform the task shall be exposed to the equipment under pressure.

7.

Before transferring hydrocarbons, all pumps, tanks, and trucks shall be bonded together and electrically grounded.

8.

No vehicle shall be allowed to cross surface flowlines on a location.

Safety Requirements for Drilling & Workover 74 of 82 Rev: June 2006

D-7

STRIPPING AND SNUBBING

1.

An emergency escape system shall be provided for personnel working atop hydraulic snubbing equipment.

2.

Prior to starting snubbing operations, the snubbing tower shall be guyed according to the manufacturer's specifications to prevent it from collapse or turnover.

3.

Flow lines or bleed-off lines shall be located away from areas frequented by personnel and adequately secured to prevent whipping or flailing if these lines should burst.

4.

Gasoline engines shall not be used on snubbing operations.

5.

Diesel engines used for snubbing operations shall be equipped with spark arrestors and located a sufficient distance away from the wellhead to ensure that any inadvertently released well fluids do not come in contact with the engines.

6.

Two-way communications shall be provided between the snubbing operator and the pump operator. This may be accomplished by hand signals, voice communication, or other effective means.

7.

A safe means of access shall be provided to the tower platforms.

8.

Well surface pressure shall be monitored at all times during stripping and snubbing operations.

9.

All personnel involved in a stripping operation shall be informed of the maximum working pressure that is safe for the work. The RIG OPERATOR shall provide blowdown lines with remote control valves as needed to relieve pressure from the wellhead equipment if the working pressure exceeds the established limit.

D-8

FLARE PITS AND FLARE LINES

1.

A reliable and safe means of remote ignition shall be provided when hydrocarbon gases are released to the atmosphere through a flare system.

2.

No personnel shall enter a flare pit to light the flare or any waste material therein.

3.

When lighting a flare pit, the lighting shall be done from the upwind side.

4.

When there is no wind or when the wind direction is uncertain, no attempt shall be made to light the pit unless the man can locate himself in a position known to be free of flammable concentrations of gases or vapors.

5

All sources of ignition in the flare pit and surrounding areas shall be extinguished while any vessel is being completely drained to the flare pit, unless the system is designed and constructed to prevent flashback.

6.

All lines connecting any vessel to a flare pit shall be blanked off before any work is performed within the vessel.

Safety Requirements for Drilling & Workover 75 of 82 Rev: June 2006

SECTION E: OFFSHORE E-1

OVERWATER OPERATIONS

1.

When work is performed over water, the RIG OPERATOR shall instruct all personnel in the proper water entry and survival procedures to be used.

2.

While working over water an emergency means of escape from platforms shall be provided.

3.

U.S.C.G. or U.K.D.I.T. approved life preservers and buoyant work vests (personal flotation devices (PFD's)) shall be readily available on an offshore rig or platform.

4.

Oil-soaked or otherwise damaged personal flotation devices (PFD's) shall be removed from service and destroyed.

5.

Approved PFD's shall be worn: (a)

When being transported by personnel basket between an offshore drilling rig or platform and a crew boat.

(b)

When performing work from a work basket that is suspended over water.

(c)

When moving either a blowout preventor or a diverter stack on or off the wellhead where the suspended work platform on which personnel are working is over open water.

(d)

When being lowered to the water in a davit-launched life raft, life boat, survival craft, rescue craft, or inspection boat.

(e)

When being transported by helicopter over water.

6.

Employees wearing PFD's shall keep them snugly fitted and securely fastened.

7.

Decks of all rig platforms shall be kept clean of oil, grease, debris, and free of all excess equipment that poses a tripping or fire hazard.

8.

Wireline units, power packs, tool boxes, and other equipment to be transported to or from offshore water locations shall be securely tied down once the cargo has been loaded on a vessel.

9.

It shall be the responsibility of the person skippering a vessel to determine when it is safe or unsafe to tie up or jack up on a well site.

10.

Fire drills, abandon rig drills, hydrogen sulfide drills, and man overboard drills shall be held by the RIG OPERATOR at least twice each month and recorded on the log or tour report. The RIG OPERATOR shall brief all newly arriving personnel on all emergency procedures.

Safety Requirements for Drilling & Workover 76 of 82 Rev: June 2006

E-2

LIFE SAVING EQUIPMENT -- OFFSHORE RIGS

1.

There shall always be enough personal flotation devices (PFD's) aboard to provide 125% coverage of persons on board at any time.

2.

The PFD's shall be maintained in good condition, U.S.C.G. or U.K.D.I.T. approved, and labeled with the name of the rig.

3.

Spare PFD's shall be stored in marked containers throughout the rig.

4.

Each cabin shall be equipped with the proper number of PFD's stored on top of the lockers.

5.

PFD's shall be equipped with salt water activated lights, whistles and reflector tape.

6.

Each offshore rig shall be equipped with at least eight ring life buoys maintained in satisfactory condition, and mounted so that they are easily removable from their brackets.

7.

At least one ring life buoy on each side of the offshore rig shall have attached to the ring a buoyant life line that is at least 1-1/2 times the distance from the deck of stowage to the waterline at low tide and maximum air gap of 27.4 meters (90 feet), whichever is greater. The end of the line must not be secured to the rig.

8.

At least four of the ring buoys on an offshore rig shall have a water light attached to the ring, and two of those rings must also be equipped with a smoke signal.

9.

All ring life buoys shall be in their proper location, and each shall be marked with the rig name and port of registry.

10.

Escape ladders shall be provided and maintained.

11.

Inflatable life rafts and their containers shall be intact and not damaged, rubber seals shall be free of breakage or damage, and the container bands intact.

12.

Operating instructions shall be posted at each life raft.

13.

Annual certification by an authorized third party and servicing inspections shall be required for all life rafts and containers.

14.

All life raft containers shall be kept clean and free of oil and gas, and shall be clearly marked with "inflatable life raft", date of next servicing, and capacity.

15.

Access to each raft shall be free of obstructions that would interfere with launching.

16.

The cradle for each raft shall be of proper size and the release mechanism kept free of rust and corrosion.

17.

Inflatable life raft containers shall be stored with the top straight up so the drain holes on the bottom are properly positioned for drainage of any moisture.

18.

Temporary lashing bands used in transporting the inflatable life raft containers shall be removed before stowage on the rig.

Safety Requirements for Drilling & Workover 77 of 82 Rev: June 2006

19.

The RIG OPERATOR shall ensure that the length of the painter line for each manually launched inflatable life raft is greater than the distance from the deck of stowage to the waterline at low tide and maximum air gap.

20.

The exit point for the painter line shall be pointed aft of the rig when possible to protect it from the on-coming water during towing.

21.

The painter line for each inflatable life raft which is not davit-launched shall have its external end secured to a strong point on the platform.

22.

Each life raft station shall be clearly marked to conform to the Station Bill.

23.

Station Bills shall be kept current and posted in conspicuous locations.

24.

The launching equipment for davit-launched inflatable life rafts must include: (a)

A means to hold it securely while personnel enter the life raft.

(b)

A means to rapidly retrieve the falls if the station has more than one life raft.

(c)

The capability of being operated from either the life raft or from the rig.

(d)

Winch controls located where the operator can observe the life raft launching.

(e)

A system whereby a loaded life raft does not have to be lifted before it is lowered.

25.

Not more than two davit-launched life rafts may be launched from the same launching equipment.

26.

Survival craft and life rafts shall be manufactured to a recognized international standard.

27.

The access route and launching platform from which survival craft are to be launched shall be kept clear of any obstruction that interferes with the immediate launching of the craft.

28.

Emergency lighting shall be provided at the launching area and it shall be maintained in good working order.

29.

Each survival craft shall be marked with the number of the craft, name of the rig, port of registry, and the number of persons allowed in the craft. This marking shall be with letters at least 7.6 centimeters (3 inches) high and in a color that contrasts to the background color of the craft (international orange).

30.

The watertight doors of all survival craft shall seal properly in order to maintain watertight integrity.

31.

Spare life preservers shall be stored in a storage box outside both lifeboats.

32.

A compass shall be mounted in the craft where it will be readily visible to the operator. It shall be maintained in good working order.

Safety Requirements for Drilling & Workover 78 of 82 Rev: June 2006

33.

The gear shift and throttle control shall always be kept in the neutral position until made ready for starting the engines.

34.

The salt water inlet valve and fuel shut-off valve shall always be in the open position.

35.

The fuel tank shall be kept full. The fuel shall be changed out annually.

36.

All survival craft shall be checked weekly and recorded in a log book by a qualified mechanic to ensure that: (a)

Compressed air tanks are full.

(b)

Drain plug is in place.

(c)

Battery and battery connections are in good condition.

(d)

Belts and hoses are in good condition.

(e)

Transmission fluid, hydraulic fluid, and oil levels are in the full range of the dipstick.

37.

Emergency lifeboat drills, including launching all motorized survival craft and starting their engines, shall be conducted monthly.

38.

All survival craft engines shall be started weekly and run for no longer than five minutes (or until the engine becomes warm) if the craft is not placed in the water.

39.

All emergency supplies required in the survival craft shall be visually inspected weekly to ensure that they are still safely stored in the craft.

40.

Emergency food rations and drinking water in each survival craft shall be replaced prior to their expiration date. They shall be replaced sooner if the vacuum seal of the container is lost. Signal flares shall be replaced prior to their expiration date.

41.

The complete launching system for all survival craft shall be visually inspected weekly by a qualified mechanic to ensure that the hand stop, wire rope, U-clamps, motor and motor starter, supports, sheaves and blocks, falls, release pins, and limit switches are in good order.

42.

When any survival craft is launched in the water during boat drills, the sprinkler system shall be checked to ensure that it works properly.

43.

A survival craft operator and alternate operator shall be assigned to each craft. Both shall be trained in the operation of the survival craft.

44.

Two Transponders (McMurdo Marine Model RT9-3 or equivalent) shall be available at each lifeboat.

45.

Each offshore rig will be inspected by representatives of Saudi Aramco organizations as required.

Safety Requirements for Drilling & Workover 79 of 82 Rev: June 2006

E-3

HELIPORTS AND HELICOPTER OPERATIONS

1.

The RIG OPERATOR shall ensure that a fully equipped fire equipment storage box is available at the heliport for fire fighting and rescue. The contents of this box are listed in Requirement Number B-9-18.

2.

Fire-fighting equipment, adequate to control and extinguish the largest foreseeable fire, shall be available at the heliport. In addition, a 30lb 120B:C UL Listed dry chemical or equivalent, portable type extinguisher shall be located at each exit. This equipment shall be properly maintained for emergency use.

3.

Unless the heliport is a continuous extension of a rig deck with unrestricted entry and exit to it, there shall be at least two exit routes from the heliport. One exit may be designated for emergency use only.

4.

Each access to the heliport area shall be marked with warning signs in Arabic and English saying "Beware of the Tail Rotor".

5.

The primary access should have a passenger waiting area at least seven feet below helideck level. This area should have a passenger briefing sign, a clear deck policy sign, and a scale for weighing passengers.

6.

Each shift must have a designated helicopter attendant to meet landing aircraft. The helideck attendant will wear an orange vest to identify himself. His duties include the following: a.

Inform the crane operator to cease operations.

b.

Inform the fire and crash rescue team on helicopter operations.

c.

Check the helideck for loose objects.

d.

Obtain the exact weight of passengers, baggage, and cargo and log this information on the passenger manifest for the pilot.

e.

Do not load any cargo until directed by the pilot.

f.

Assist passengers in loading and unloading baggage and entering and exiting the aircraft. Assure life vests and seat belts are correctly worn.

7.

There shall be a minimum of eight perimeter lights, alternating blue and yellow. These lights should be not be frangible, and the upper portion of the light guard should be no greater than six inches above the helideck. Exits should be marked with red lights.

8.

If the highest points on the rig exceeds the elevation of the helideck by more than fifty feet, an Omni-directional red light should be fitted at that point, with additional such lights fitted at thirty five foot intervals down to the interval of the flight deck.

9.

An emergency power supply should provide power to the perimeter and obstruction lighting and lighting along heliport access and egress routes.

Safety Requirements for Drilling & Workover 80 of 82 Rev: June 2006

10.

A rotating or flashing beacon should be installed on the cab of any crane boom that can reach the helideck. The beacon should be illuminated whenever the crane engine is operating. Crane operators must be knowledgeable about proper procedures to use around helicopters.

11.

The helideck safety fence should be at least five feet wide. It should be attached six inches below the helideck and incline to the outer edge at one to ten. The outer edge must not protrude above the level of the flight deck.

12.

Each heliport shall have a minimum of four recessed tie-down points arranged to secure one helicopter in the middle of the deck.

13.

Each heliport shall be constructed so that rain or spilled fluids will drain from the deck.

14.

Each heliport should have a windsock that is easily visible to the pilot. It must be illuminated for night operations and not constitute an obstacle to helicopter operations.

15.

The heliport markings shall be in accordance with the Saudi Aramco Offshore Helideck Standard Drawing # AA-036248 (latest revision). a.

A sixteen inch wide stripe to mark the boundary of the load bearing portion of the helideck surface.

b.

A three foot wide rectangular red border to mark the primary stairway opening designating a tail rotor hazard.

c.

Aiming circle, twenty feet in diameter and using a sixteen inch wide stripe containing the "H" designation to mark the center of the helideck.

d.

A thirty six inch wide walkway should be marked from the aiming circle to the primary access route.

e.

The secondary access route will be used and marked in Arabic and English as an "Emergency Exit'.

f.

Limitation markings shall show the maximum allowable weight to the nearest thousand pounds. The helideck dimension is shown to the nearest foot.

g.

The rig identification shall be marked on the heliport.

h.

Obstruction markings are as follows: 1.

Any obstruction four feet or higher is a main rotor obstruction and must have a solid red arc one third the rotor diameter of the largest helicopter expected to land there.

2.

Any obstruction six inches or higher is a tail rotor obstruction and must be marked with a three foot solid red rectangular border.

3.

Any obstruction on the deck less than six inches high is a skid hazard and must be marked with an eight inch red circular band. Safety Requirements for Drilling & Workover 81 of 82

Rev: June 2006

16.

Painting requirements are as follows: a.

Flight deck - Non skid light gray

b.

Flight deck border - Yellow

c.

Aiming circle - Yellow

d.

Walkways - Alternating yellow and light gray

e.

"H" designation - Yellow

f.

Limitations - Yellow numbers with black borders

g.

Identification - Yellow letters with black borders

h.

Stairway - Red border

i.

Obstruction - Red arc, rectangle or circle

17.

The rig must be equipped with a VHF radio capable of reaching 138.25 and 138.20 to allow for direct communications with the helicopter.

E-4

PERSONNEL TRANSFER: BOAT AND RIG

1.

An offshore crane operator shall not be required or permitted to transfer personnel by personnel basket if the wind force is above 30 knots or the wave height above 1.8 meters (6 feet).

2.

Personnel shall be transferred by basket to or from a rig only when visibility is good.

3.

The lifting and lowering of personnel in a personnel basket shall be over open water whenever possible.

4.

A safety line shall be used on each personnel basket. The crane hook shall be equipped with a safety latch.

5.

Each personnel basket used for transferring personnel by crane between an offshore rig and crew boat shall be in good condition, provided with an adequate number of approved life preservers or buoyant work vests. It should be stored out of the way when not being used.

6.

The offshore crane operator shall not be required or permitted to transfer more than four persons by personnel basket each crane trip.

7.

When employees are transported by personnel basket, they shall wear approved life preservers or buoyant work vests. They shall stand on the outer rim of the basket facing inward.

8.

Only light hand luggage shall be permitted inside the personnel basket when the basket is occupied by personnel.

9.

Rig supplies shall not be transported by personnel basket at any time. Safety Requirements for Drilling & Workover 82 of 82

Rev: June 2006

LOSS PREVENTION STATISTICS BY ORGANIZATIONS AND DEPARTMENTS Definitions of Statistical Terms Industrial Disabling Injury (IDI): An on-job injury resulting in or more full days away from work, plus on-job fatalities. IDI Frequency: The number of IDI’s for every 200,000 on-job man-hours, including overtime. IDI Frequency =

Number of IDI’s x 200,000

On-job Man-hours Restricted Duty Injury (RDI): An on-job injury resulting in one or more full days of restricted duty. RDI Frequency: The number of RDIs for every 200,000 on-job man-hours, including overtime. RDI Frequency =

Number of RDI’s x 200,000

On-job Man-hours Off-job Disabling Injury (ODI): An off-job injury resulting in one or more full days away from work. ODI Frequency: The number of ODI’s for every 200,000 off-job man-hours, which DO NOT include nonexposure hours (8 hours per day for sleeping). ODI Frequency =

Number of ODI’s x 200,000

On-job Man-hours Motor Vehicle Accident (MVA): Any recordable accident involving a Saudi Aramco fleet vehicle, whether preventable or non-preventable. MVA Frequency: The number of fleet MVA’s for every 1,000,000 kilometers driven. MVA Frequency =

Number of MVA’s x 1,000,000

Kilometers driven Note: U-Drive MVA’s are included only in the overall company frequency calculation, not in any organizational frequency calculations. Upper Control Limit (UCL): The UCL is calculated for each category of injury or MVA for a given year and is the average of the experience of the previous three years, minus a 5% improvement factor. All UCL calculations are made during October-November of the previous year (for example, UCLs for 1997 were determined in October-November of 1996). The detailed formulas are available from the Loss Prevention Department’s Technical Services Unit. Safety Performance Index (SPI): The SPI is a combined indicator of performance which relates the current year’s frequency to the UCL (essentially past performance) in each category. SPI = 0.35

(IDI Freq.) (IDI UCL)

+ 0.15

(RDI Freq.) (RDI UCL)

+ 0.15

(ODI Freq.) (ODI UCL)

+ 0.35

(MVA Freq.) (MVA UCL)

Safety Requirements for Drilling & Workover 83 of 82 Rev: June 2006

General Comments 1. 2. 3. 4.

Statistics such as UCL’s and SPI’s are means to identify safety-related problems, not an end in themselves. Do not use UCL’s and SPI’s to compare one organization’s performance with that of another. These statistics indicate the organization’s performance now with respect to the organization’s performance in the past three years. To compare current performance of one organization with that of another organization, use the frequencies in each category. (a) A Saudi Aramco IDI is equivalent to the US Occupational Safety & Health Administration (OSHA) definition of lost workday cases involving days away from work. (b) A Saudi Aramco RDI is equivalent to the US OSHA definition of lost workday cases involving days of restricted work activity.

Safety Requirements for Drilling & Workover 84 of 82 Rev: June 2006

DHAHRAN AREA LOSS PREVENTION (DHALPD)

RIG INSPECTION CHECKLIST FOR LAND RIGS DATE:

RIG:

FOREMAN:

WELL NAME:

OPERATION:

PERSONNEL CERTIFICATIONS: Enter "T" if date entered indicates date training was taken. Enter "E" if date entered indicates date training expires. POSITION Foreman

NAME

BADGE #

BOP

FIRST AID

H2S

OTHER

NAME

BADGE #

SAG

ARAMCO Cert #

ARAMCO Cert Expiry

OTHER

Foreman Toolpusher Toolpusher Driller Driller

POSITION Crane Op Crane Op Forklift Op Forklift Op Dozer Op Dozer Op

1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Rig Site Accommodations ......................... 2 Genset & Engines ...................................... 2 SCR Room................................................. 2 Accumulator .............................................. 3 Mud Pumps................................................ 3 Mud Tanks................................................. 4 Substructure ............................................... 4 Rig Floor.................................................... 5 Dog House ................................................. 6 Derrick ....................................................... 7

11. 12. 13. 14. 15. 16. 17. 18. 19. 20.

Catwalk & Pipe Racks ...............................8 Manifold, Flare Lines, & Flare Pit.............9 Fuel Tanks..................................................10 Fire Fighting Equipment ............................10 Compressed Gas Cylinders ........................10 Hand & Power Tools .................................10 Welding & Cutting.....................................11 Cranes & Slings .........................................11 General.......................................................11 H2S Protection (Land Rigs).......................12

Note: Where applicable, inspection items are referenced to published Aramco policy. "SASR" refers to Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

Page 1

1. RIG SITE ACCOMMODATION

… … … Site accommodation trailers located at least 25 YES

1-1

NO N/A

metres (75 ft) from well bore

1-2

… … … Power cables to trailers from light plant

suspended or otherwise protected from vehicular traffic

1-3

… … … Electrical junction boxes on trailers weather proofed, and closed [SASR B-15 (7) p.39]

1-4

… … … Electrical cords and fittings free of defects

1-6 1-7 1-8 1-9

… … … Protective covers on all lights

… … … ABC fire extinguisher in each trailer

… … … Escape window or door in sleeping room … … … Smoke alarm present and functioning … … … For an H2S locations, rig medic or

2-9 2-10 2-11 2-12

2-1

2-13

… … … For H2S locations, 10-pound CO2 fire

extinguisher in place [SASR Onshore H2S Std. (IV B-1) p.27]

2-14 2-15

… … … Noise hazard sign in place [SASR B-3 (8) p.17] … … … Hearing protection provided and used by workers [SASR B-3 (9) p.17]

2-16 2-17

… … … Exits free of obstruction [SASR B-7 (1) p.34] … … … Floors and equipment free of oil or grease [SASR B-7 (2) p.34]

2-18

… … … Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

2-19

2. GENSET & ENGINES

… … … Grounded to casing or cellar [SASR B-15 (8)

2-20

… … … Ground cable securely fastened with bolted

2-21

… … … "High Voltage" sign posted [SASR B-15 (9) p.39]

… … … All engine exhausts equipped with water sprays or spark arrestors for spark suppression [SASR B-15 (2) p.38]

NO N/A

p.39 & updated D&WOOD policy].

2-2

… … … Switches capable of being locked out … … … Lockout procedures in place [SASR B-31 p.43] … … … Lights have protective coverings … … … Suitable emergency lighting available on location and working [SASR B-16 (7) p.39]

Toolpusher’s office has an eyewash station [SASR B-6 III F3 p.26]

YES

NO N/A

condition [SASR B-15 (1) p.38]

[SASR B-15 (1) p.38]

1-5

… … … Electrical cords, plugs, receptacles etc. in good YES

2-8

… … … Auxiliary and emergency standby generators run at full load for 2 hours every week [SASR B-15 (12) p.39]

clamps [SASR B-15 (1) p.38]

2-3 2-4 2-5

… … … Buildings bonded together to common ground

… … … Fans and belts guarded [SASR C-1 (1a) p.45] … … … Electrical junction boxes identified and kept in closed position [SASR B-15 (7) p.39]

2-6

… … … Electrical outlets labeled, voltage identified [SASR B-15 (7) p.39]

2-7

… … … All knockouts in panels (no open knockouts)

3. SCR ROOM

… … … Emergency lighting installed and working at YES

3-1

NO N/A

TWO exits [SASR B-15 (6) p.38]

3-2

… … … Non-conductive mats placed on floor [SASR B15 (5) p.38]

3-3

… … … Halon fire extinguisher available (only Halon is

permitted in the SCR room) [SASR B-9 (4) p.35]

[SASR B-15 (1) p.38]

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

COMMENTS:

Page 2

… … … NO valves installed between pop valve and its YES

4-2

[SASR C- 30 (9) p.63]

5-7

… … … Located at least 18.3 m. (60 ft) from wellbore

YES

4-1

4. ACCUMULATOR

5-6

[SASR C- 30 (7) p.63]

4-3 4-4

discharge [SASR C-35 (6) p.64]

NO N/A

… … … Accumulator bottles precharged to 1200 psi … … … No leaks in system [SASR C- 30 (7) p.63]

… … … Gauges in good condition and readable [SASR … … … Controls free of any obstruction [SASR C- 30 (8)

5-8

… … … Controls in OPEN or CLOSED position, not neutral [SASR C- 30 (11) p.63]

4-7

… … … Accumulator function tests conducted

5-9

5-10

4-9

5-11

5-13

5-14 5-15

… … … Fans and belts guarded [SASR C-1 (1a) p.45]

5-2

NO N/A

… … … Lubricator pump belt and pulleys guarded [SASR C-1 (1a) p.45]

5-3

… … … Shock hoses safety chained [SASR C-35 (13) p.65]

5-4

… … … Pop (relief) valve capped, proper size pins

… … … Sign posted identifying remote startup of

… … … Noise hazard sign posted [SASR B-3 (8) p.17]

… … … Hearing protection provided and used [SASR B3 (9) p.17]

5. MUD PUMPS

5-1

… … … For H2S locations, 30 pound dry chemical fire

equipment (if applicable)

(2) p.34]

YES

… … … Electrical lights have protective covers

extinguisher serviced and in place [SASR B-6 (IV A-3) p.26]

Date of

… … … Compressor free of dirt, grease or oil [SASR B-7

… … … Used electrical receptacles capped [SASR B-15 (7) p.39]

5-12

… … … Fire extinguisher in place and serviceable

… … … Electrical connections in good condition [SASR B-15 (1) p.38]

last test:__________________

4-8

… … … Discharge line properly secured [SASR C-35 (8) p.65]

p.63]

4-6

… … … Discharge line sloped downward [SASR C-35 (9) p.65]

C- 30 (7) p.63]

4-5

NO N/A

5-16

… … … Floor and equipment free of grease, oil and debris [SASR B-7 (2) p.34]

5-17

… … … No oily rags or tools laying about [SASR B-7 (7) p.34]

5-18

… … … Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

inserted (set @ _____psi) [SASR C-35 (2, 3, 4) p.64]

5-5

… … … NO valves installed between pump and pop valve [SASR C-35 (1) p.64]

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

COMMENTS:

Page 3

6. MUD TANKS (Class 1, Div. 1 & 2)

… … … All pulleys, belts, couplings on motors properly YES

6-1

NO N/A

… … … Eyewash facilities at mixing area serviced and

6-17

… … … Goggles provided at mixing area, and worn

6-18

… … … Respirators provided for employees working

6-19

[SASR A-5 (8) p.13; SASR B-3 (4) p.17]

6-4

6-6

… … … Degasser installed and vented to flare pit

7. SUB-STRUCTURE (Cl.1, Div. 1&2)

… … … Hazardous products (i.e. caustic) used in barrel

7-1

… … … Mud products Material Safety Data Sheets

7-2

… … … MSDS stored at _____________

7-3

6-9 6-10

… … … Pumps, motors in good condition

… … … Explosion-proof motors and fittings if applicable [SASR B-15 (1) p.45]

6-11

… … … Electrical connections, plugs, receptacles, and

6-15

7-4 7-5 7-6

… … … Kill and choke lines connected, pressure tested … … … Fire resistant kill and flare lines

… … … Steel or approved equivalent armored hose accumulator lines [SASR C-30 (13) p.63]

… … … Lights have protective covers [SASR B-15 (1)

7-7

… … … Grommets & electrical cables with proper fit

7-88

… … … Guard rails in place [SASR C-1 (1b) p.45]

7-9

… … … For H2S locations, 30 pound dry chemical fire

… … … BOP scaffolding or working platforms in good condition

… … … All electrical junction boxes and conduit sealed [SASR B-15 (7) p.39]

… … … Electrical equipment and cables in good condition [SASR B-15 (1) p.38]

[SASR B-15 (1) p.38]

6-14

… … … BOP properly turnbuckled (4 lines) [turnbuckles recommended by SASR C-30 (6) p.63]

p.38]

6-13

NO N/A

[SASR C-36 (1) p.65]

lights in good condition and properly sealed [SASR B-15 (1) p.38]

6-12

… … … Cellar protected from workers falling into it YES

(MSDS) available [SASR B-33 (3, 4, 5,) p.45]

6-8

… … … Bottom of stairs within 9" of ground level, and unobstructed

mixer or mud tank adequately identified

6-7

… … … No tools or tripping hazards on walking/working surfaces [SASR C-8 (3) p. 48]

with oil-based mud system

6-5

… … … Walkways, stairs and platforms in good

condition [SASR C-1 (1b) p.45; SASR C-8 (3) p. 48]

operable [SASR B-3 (11) p.17; B-6 III F2 p.26]

6-3

NO N/A

falling [SASR C-1 (1b) p.45]

guarded [SASR C-1 (1a) p.45]

6-2

… … … Floor coverings in place to prevent tripping or

YES

6-16

… … … Unused electrical receptacles covered [SASR B15 (7) p.39]

7-10

extinguisher serviced and in place at shaker [SASR B-6 (IV A-2) p.26]

… … … Lights sealed with protective covers [SASR B-15 (1) p.38]

7-11

… … … Guards on pulleys and belts [SASR C-1 (1a) p.45]

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

COMMENTS:

Page 4

… … … All pins and safety pins in place [SASR C-2 (9) YES

7-12

NO N/A

… … … Snub line on each tong [SASR C-21 (1) p.58]

YES

8-14

p.46]

8-15

NO N/A

… … … Tong snub lines in good condition [SASR C-21 (4) p.58]

8. RIG FLOOR (Class 1, Division 1 & 2 Area)

… … … A loudspeaker system is installed that can be YES

8-1

NO N/A

heard throughout the working area [SAMIR requirement]

8-2

… … … Two unobstructed exits from rig floor, not

counting the exit leading directly to mud pits [SASR C-8 (2) p.48]

8-3

… … … Doors open outward from floor and dog house

8-16

factory-made eyes) [SASR C-21 (1) p.58]

8-17

… … … V-door closed or chained when not in [SASR C-

8-18

8-6

… … … Handrails in place [SASR C-8 (5) p.49]

… … … Floor openings covered when not in use [SASR

8-19 8-20

… … … Walkways and work areas unobstructed and

8-21

… … … Drawworks and rotary drive guarded [SASR C-7

8-22

… … … Stabbing valves (or crossovers) on floor (or

8-23

… … … Handles for kelly cocks and stabbing valve in

8-24

8-12

… … … Rough tread plate installed around rotary table … … … Tong dies sharp and die keepers installed [SASR C-21 (6) p.58]

8-13

… … … Tong body and tong jaws in good condition

… … … Lockouts on rotary and cathead clutches … … … Ends of Driller’s headache post contained [SASR C-13 (12) p.53]

8-25

… … … Brake handle slotted c/w tiedown [SASR C-12 (3) p.52]

8-26

easily accessible place

8-11

… … … Driller's controls adequately guarded [SASR C-

[DHALPD ED&M recommendation]

doghouse) for each thread type used in string

8-10

… … … Driller's controls adequately labeled [SASR C-11

11 (5) p.52]

(4, 5) p.48]

8-9

… … … Mud can and line installed and in good condition

(2) p.51]

clean [SASR C-8 (3) p.48]

8-8

… … … NO spinning chain installed [D&WOOD SOC] [SASR C-24 (2) p.59]

C-8 (9) p.49]

8-7

… … … Tong chain in good condition, no evidence of excess wear, gouging, or grooving

8 (8) p.49]

8-5

… … … Tong snub lines minimum 5/8 " (15.9 mm) diameter

[SASR C-8 (2) p.48]

8-4

… … … Tong snub lines properly triple clamped (or have

8-27

… … … Brakes in good condition [SASR C-12 (1) p.52]

… … … Hydromatic, Dynamatic, or El Magco functioning properly and checked weekly [SASR C-12 (1) p.52]

8-28

… … … Weight indicator safety tied [SASR C-32 (21) p.64]

[SASR C-21 (5) p.58]

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

COMMENTS:

Page 5

… … … Engine shut-offs working [SASR C-11 (6) p.52]

8-44

… … … Slip and cut program in place, documented

8-45

YES

8-29 8-30 8-31

NO N/A

… … … Date of last engine kill switch test:___________

8-33 8-34

8-35

… … … Crown stop properly set [SASR C-5 (4) p.47]

8-46

anchored [SASR C-18 (4) p.55]

8-47

… … … Tugger line in good condition, not kinked,

crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

8-36

… … … Tugger line with safety hook or shackle on end … … … Swivel used on tugger line (recommended by

… … … Proper fit between electrical cables and grommets [SASR B-15 (1) p.38]

… … … Lights with proper sealed coverings free of

cracks or breaks, properly sealed [SASR B-15 (1) p.38]

8-48

… … … For an H2S locations, eyewash facilities on rig floor (or doghouse) serviced and operable [SASR B-3 (11) p.17; B-6 III F1 p.26]

(recommended by DHALPD)

8-37

… … … Electrical connections, cords, plugs and

receptacles in good condition (no electrician's tape used to splice or repair) [SASR B-15 (1) p.38]

… … … Line spooler on fast line adequately secured … … … Drill line properly spooled on drum and

NO N/A

cords comply with Classification for the area [SASR B-15 (1) p.38]

[SASR C-18 (2) p.55]

8-32

… … … All electrical connections, plugs, receptacles and

YES

8-49

… … … For H2S locations, two 30 pound dry chemical fire extinguishers serviced and in place at drawworks [SASR B-6 (IV A-4) p.26]

DHALPD)

8-38

… … … All wire rope fittings properly clamped, clamps properly spaced [SASR C-18 (13) p.55]

8-39

9. DOGHOUSE

… … … No wire ropes are knotted, or have "Flemish eye

9-1

… … … All other wire ropes and slings free from wickers,

9-2

splice", "farmer's eye splice" or "rig operator's standby" [SASR C-18 (15) p.55]

8-40

8-42

… … … Signal man used with tugger line

… … … NO rope installed on cat head (cat head not

9-3

… … … Blowout prevention procedures posted [SASR C-30 (14) p.63]

9-4

… … … BOP function tests done every trip [Saudi

Aramco Well Control Handbook: K 1.0 (5), p. K3]; and documented in IADC book

… … … Maximum allowable casing pressure posted at remote choke control panel

… … … Doghouse doors free of locking devices [SASR C-8 (2) p.48]

used) [D&WOOD SOC]

8-43

NO N/A

signs posted at foot of stairs leading to doghouse [SASR A-5 (5) p.13]

not kinked, crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

8-41

… … … "No Smoking", hard hat, and safety footwear YES

9-5

… … … BOP pressure tested at least every 2 weeks

[Saudi Aramco Well Control Handbook: K 2.1 (5), p. K-4]; and documented in IADC book

9-6

… … … Drills held and documented in IADC book (BOP, H2S, fire, evacuation) [SASR C-30 (15) p.63]

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

COMMENTS:

Page 6

… … … Safety meeting topics and attendance YES

9-7

NO N/A

documented

9-8 9-9

… … … Trip records (measured hole-fill volumes) kept

10. DERRICK

10-1

… … … For H2S locations, two 25-man first aid kit in

… … … Two stretchers readily available [SASR B-1 (III

10-2

… … … Employees know location of stretcher and

10-3

… … … Bulletin board used to post current safety

10-4

… … … Date of last safety item posted on the bulletin

10-5

9-15

9-16 9-17

… … … Spare derrick belt [SASR C-29 (7) p.47],

goggles, face shields and other personal protective equipment kept in doghouse

10-6

junction boxes comply with electrical code for such atmospheres [SASR B-15 (1) p.38]

10-7

… … … For H2S locations, three SCBA available and

10-8

… … … Remote BOP controls free of obstruction and

10-9

… … … Housekeeping acceptable, no accumulations

… … … Derrick girts in good condition [SASR C-2 (4)

… … … All derricks pins in place c/w safety pins [SASR C-2 (4, 10) p.46]

10-10

… … … Tong counterweight weight ropes minimum 1/2" (12.7 mm) diameter [SASR C-22 (2) p.59]

accidental operation [SASR C-30 (8) p.63]

9-19

… … … Climbing belt always used [SASR C-8 (18) p.49] p.46]

in good condition in doghouse (or rig floor) [SASR B6 (II B5) p.25]

9-18

… … … Platforms provided at regular intervals on

ladder, or climbing device provided [SASR C-8 (14) p.49]

… … … Electrical plugs, receptacles, cords, conduit … … … Light covers sealed [SASR B-15 (1) p.38]

… … … Derrick ladder extends at least 3 feet (91 cm) above each landing platform (including the crown)[SASR C-8 (23) p.50]

board:________________

9-14

… … … Base of ladder clear of obstructions [SASR C-8 (15) p.49]

material

9-13

… … … Derrick ladder extends down to rig floor (no need to climb up standpipe, etc.)

blankets

9-12

… … … Operating within prescribed limits [SASR C-2 (2) p.46]

B) p.26] [location:_______________]

9-11

NO N/A

(or available in-site) stating: manufacturer, model number, serial number, hook load capacity, wind load capacity (both with and without pipe in the derrick), and (if applicable) the recommended guying pattern. [SASR C-2 (1) p.45]

good condition present: one at the rig site, and one at the camp [SASR B6 (III E) p.26]

9-10

… … … Derrick has a permanent nameplate attached

YES

10-11

… … … Unguided tong counterweights safety tied with minimum 5/8" (15.9 mm) diameter wire rope [SASR C-22 (1) p.59]

that present a hazard [SASR B-7 (6) p.34]

10-12

… … … Safety line prevents counter weight from

dropping within 8 ft. (2.4 m) of floor [SASR C-22 (1) p.59]

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

COMMENTS:

Page 7

… … … All sheaves, lights, and other fixtures safety-tied

10-29

… … … Standpipe adequately anchored

10-30

YES

10-13

NO N/A

[SASR B-16 (3) p.39 (for lights only)]

10-14 10-15

… … … Kelly hose safety chained at both ends, (chained to the swivel, not chained to the gooseneck) [SASR C-35 (12) p.65]

10-16

… … … Traveling blocks have sheave guards [SASR C5 (1) p.47]

10-17

… … … Traveling blocks free of projections [SASR C-5 (3) p.47]

10-18 10-19

… … … Kelly hook safety latched [SASR C-5 (1) p.47]

… … … Safety belt c/w shoulder harness in derrick

10-22 10-23

10-31

lubricated

10-32

10-26 10-27

10-33

… … … All electrical connections, plugs, receptacles,

cords etc. are in good condition [SASR B-15 (1) p.38]

10-34

… … … Electrician's tape not used in splices or at grommets [SASR B-15 (1) p.38]

… … … Monkey board secured and in good condition … … … Adequate tie back and pull back ropes

… … … Fingers and pads properly pinned and safety

… … … Geronimo or other escape mechanism installed

11. CATWALK & PIPE RACKS

… … … • Easily accessible [SASR C-6 (9) p.48]

… … … • Inspected weekly [SASR C-6 (8) p.48]

… … … Catwalk level, in good condition [SASR C-9 (3) YES

11-1

NO N/A

p. 50]

11-2

… … … Catwalk free of tripping hazards [SASR C-9 (3) p. 50]

11-3 11-4

… … … Stairs at end of catwalk [SASR C-9 (3) p. 50] … … … Pipe racks/tubs level and in good condition [SASR C-9 (1) p. 50]

11-5

… … … Pipe racks butted against catwalk, and secured to catwalk [SASR C-9 (1) p. 50]

… … … • Quick release knots on geronimo tie back

11-6

… … … Geronimo (escape) line is minimum 1/2" (12.7

11-7

… … … Pipe racks chained or pinned together [SASR C9 (1) p. 50]

[SASR C-6 (9) p.48]

10-28

… … … Derrick lights have adequately sealed protective covers [SASR B-15 (1) p.38]

[SASR C-6 (1) p.47]

10-25

… … … Crown sheaves in good condition and well

… … … Safety belt lanyard minimum 5/8" (15.9 mm)

chained [SASR C-27 (2) p.60]

10-24

… … … Crown bumper blocks (wooden planks) safety

tied, or covered with expanded metal, or suitable screen or mesh [SASR C-4 (2) p.46]

manila rope (not synthetic) with no splices [SASR C-29 (3) p.47]

10-21

NO N/A

worker to fall through [SASR C-4 (1) p.46]

[SASR C-29 (2) p.47]

10-20

… … … Crown has no openings large enough for a

YES

… … … Adequate spacing between layers of pipe [SASR C-9 (5) p. 50]

mm) diameter [SASR C-6 (3) p.47]

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

COMMENTS:

Page 8

… … … Workers stand out of the way when rolling, YES

11-8

NO N/A

12. MANIFOLD, FLARE LINES, & FLARE PIT

loading, or unloading pipe [SASR C-10 (3) p. 51]

11-9

… … … Pipe key, crowbar, or other safe method used … … … Blocks, pins, or chocks used to prevent pipe

12-2

from rolling off rack [SASR C-9 (1) p. 50]

11-11

… … … Tag line used when loading or unloading pipe [SASR D-2 (5) p. 67]

11-12

… … … From the derrick, the Geronimo (escape) line is minimum 1/2" (12.7 mm) diameter [SASR C-6 (3) p.47]

12-3 12-4

12-5 12-6

… … … • Twice vertical length from attachment on

… … … • When used, the worker will touch ground 20 feet (6.1 m) from the escape line anchor point [SASR C-6 (6) p.47]

11-15

… … … • Regular check of escape line anchor to

ensure load bearing ability (3000 lb. static cable pull) [SASR C-6 (4) p.47]

11-16 11-17

… … … • Anchor staked in opposite direction of pull … … … • Escape line touchdown area free of

obstruction or vehicular traffic [SASR C-6 (4) p.47] (DHALPD recommends 50 feet (16 m) clearance)

11-18

… … … • Escape line does not impede access to

… … … Valves wheels turn easily

… … … Valve handles kept 1/4 turn from the open or … … … Casing and drillpipe pressure gauges installed … … … Casing and drillpipe pressure gauges easily

visible from manual choke operator's position

12-7

… … … Maximum allowable casing pressure posted at manual choke

derrick to the ground [SASR C-6 (7) p.47]

11-14

… … … Manifold and valves free of obstruction

closed position

Geronimo (escape) line (from the derrick):

11-13

NO N/A

I, Div. II and lights are properly sealed with a protective cover [SASR B-15 (1) p.38]

when rolling pipe

11-10

… … … Electrical connections, plugs, receptacles Class YES

12-1

12-8 12-9

… … … Flare lines properly and adequately staked

… … … Safety chains used for pressure hoses, lines with hammer unions, or chiksans

12-10 12-11

… … … Flare line sloped toward flare pit

… … … Flare pit minimum 60 metres from well bore, on an arc from 60º to 225º [SAES B-62 (7.2)]

12-12 12-13 12-14

… … … Flare pit adequate size, with proper backwall … … … Flare pit not used as garbage disposal

… … … Reliable and safe means of remote ignition of gases at flare pit [SASR D-8 (1) p. 71]

crown stand or pipe racks

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

COMMENTS:

Page 9

13. FUEL TANKS

… … … Flammable liquid containers are bonded or in YES

13-1

NO N/A

firm contact with each other before transfers occur [SASR B-13 (1) p.37]

13-2

… … … Fuel dispensing nozzles and valves are selfclosing [SASR B-11 (4) p.37]

13-3

… … … Fuel tanks have a fire extinguisher nearby [SASR B-11 (4) p.37]

13-4

… … … Fuel tanks conspicuously marked as to contents

… … … Empty and full gas cylinders stored separately

YES

15-3

NO N/A

[SASR B-14 (1) p.38]

15-4

… … … Oxidizers stored at least 20 ft. (6.1 m) from fuel gases [SASR B-14 (1) p.38]

15-5

… … … Valve protection caps on all cylinders (without a regulator) [SASR B-14 (2) p.38]

15-6

… … … Gas cylinders hoisted only in a cradle, pallet, or slingboard [SASR B-14 (3) p.38]

[SASR B-11 (2) p.37]

16. HAND & POWER TOOLS

… … … Hand held power tools have "dead-man" auto-

YES

14. FIRE FIGHTING EQUIPMENT

… … … 30 lb. ABC fire extinguishers provided

YES

14-1

16-1

shutoff devices (tools that can be locked "ON" are expressly forbidden) [SASR B-17 (2) p.40]

NO N/A

… … … • Readily accessible … … … • Locations identified … … … • Inspected weekly [SASR B-9 (2) p.35] throughout the rig at strategic areas

14-2 14-3 14-4 14-5 14-6

… … … Fire drills held regularly and logged

… … … Fire hoses kept on rack or reel when not in use

16-2

16-3

16-4

… … … Fire hoses not used for any other purpose than

Bench grinders:

… … … Fire hoses completely unrolled and inspected

16-5

… … … Cylinders stored upright [SASR B-14 (1) p.38] NO N/A

… … … Acetylene bottles (empty or full) always stored upright [SASR B-14 (4) p.38]

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

… … … • Grinding wheel is rated for the machine rpm (grinder rpm stamped on nameplate; wheel rpm rating identified on the wheel blotter) [SASR B-18 (5) p.41]

15. GAS CYLINDERS

YES

… … … • Tool rests no more than 1/8" (3.2 mm) from abrasive wheel [SASR B-18 (2) p.40]

16-6

15-2

… … … Pneumatic power tools are secured to the air

line to prevent accidental disconnection [SASR B-17 (7) p.40]

monthly [SASR B-9 (10) p.35]

15-1

… … … Impact tools (such as drift pins, chisels, hammer wrenches) do not have mushroomed striking surfaces [SASR B-17 (3) p.40]

fighting fires, drills, or testing [SASR B-9 (9) p.35]

14-8

… … … Hand held power tools are double insulated or grounded [SASR B-17 (2) p.40]

[SASR B-9 (13) p.35]

14-7

NO N/A

16-7 16-8

… … … • Eye hazard sign

… … … • Goggles or face mask available and used

COMMENTS:

Page 10

18. CRANE OPERATIONS AND SLINGS

17. WELDING & CUTTING YES

No welding or cutting performed on: [SASR B19 (1) p.41]:

17-1

Note:

… … … • any container which contains or did contain

NO N/A

information on the title page of this inspection checklist must be completed in full.

… … … • any pipe/vessel containing pressurized fluid or gas

17-2

… … … The heavy equipment operator certification YES

NO N/A

18-1

… … … Cranes have valid Aramco Crane Inspection Certificate [SASR D-1 (1b) p.65]

flammable liquids or gases, until the container is filled with water or otherwise suitably purged. Used 55-gallon drums are specifically included.

17-3

Crane #: ________________ Certificate Expiry: ________________

… … … • or in a confined space until the atmosphere has been tested "safe for fire" (DHALPD recommends 0% LEL)

17-4

Crane 1

18-2

… … … No welding or cutting on load handling tools or

18-3

… … … Suitable eye/face protection used when welding,

18-4

… … … Maximum acetylene gauge pressure less than 15 psi (103 kPa) [SASR B-19 (7) p.42]

17-7

18-5

… … … Acetylene cylinder valves not opened more than … … … All gas bottle regulator gauges are in good

… … … Tag lines used [SASR D-2 (5, 6) p.67]

… … … All slings identified with Manufacturer name or … … … All slings have a detailed visual inspection every … … … Spreader bars identified with Manufacturer

name, serial number, date of load test certification, and (in English and Arabic) safe working limit (SWL) [S.A. G.I. 7.029 (6.2)]

1 1/2 turns [SASR B-19 (7) p.42]

17-8

18-6

… … … Spreader bars have a semi-annual documented inspection [S.A. G.I. 7.029 (6.2)]

condition (no cracked glass covers) [SASR B-19 (8) p.42]

17-9

… … … All welding hoses are free from cracks, leaks, burns, worn spots [SASR B-19 (10) p.41]

17-10

17-11

… … … No arc-welding cable with damaged insulation or … … … No splices in arc-welding cables within 10 ft. (3

19-2

… … … Portable arc-welding machines are suitably

19-3

m) of the electrode holder [SASR B-19 (13) p.42]

17-12

19. GENERAL

… … … All stairs with more than 4 risers have handrails

YES

19-1

exposed conductors [SASR B-19 (12) p.42]

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

NO N/A

[SASR C-8 (4) p.49]

… … … All working surfaces higher than 4 feet (1.2 m)

have standard handrails (42" handrail, 21" knee rail, 4" toe board) [SASR C-8 (5) p.49]

… … … Safety harnesses used when working higher

than 10 feet (3.1 m) above grade [SASR C-8 (6) p.49]

grounded [SASR B-19 (15) p.42]

COMMENTS:

________________

6 months, recorded in a sling inspection log [S.A. G.I. 7.029 (7.2)]

cutting, or grinding [SASR B-19 (6) p.42]

17-6

________________

logo, a unique identifier number, and safe working limit (SWL) [S.A. G.I. 7.029 (4.1)]

equipment (slips, tongs, elevators, bales, etc.) [SASR B-19 (3) p.41]

17-5

Crane 2

COMMENTS:

Page 11

… … … All ladders (fixed and portable) in good shape YES

19-4

NO N/A

… … … Noise protection signs posted where required

H2S PROTECTION: LAND RIGS All drilling or workover rigs will have the following equipment on location when operating in known or suspected H2S areas. The reference term "H2S Std (Land)" refers to the Saudi Aramco Standard Safety Equipment for H2S Operations on All Onshore Drilling and Workover Rigs, a document included in the Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations. The page numbers refer to the Safety Requirements Manual.

… … … At least one qualified First Aid person on each

20-1

with no bent, broken, or damaged side rails and steps [SASR C-8 (24) p.50]

19-5

… … … Portable ladders are safety tied [SASR C-8 (26) p.50]

19-6

[SASR B-3 (8) p.17]

19-7

YES

shift [GI 150.002]

19-8

… … … Crews trained in the following [SASR B6 (4) NO N/A

p.23] • H2S characteristics and toxicity • Detection and warning systems on location • Safe briefing area locations • Evacuation procedures • Rescue procedures • First aid for victims • Inspection, maintenance, and use of emergency breathing equipment • Drill procedure

… … … Telephone numbers of physician, hospital, &

ambulance posted in the office & clinic [SASR B1 (4) p.15]

19-9

… … … Overall housekeeping acceptable, no

accumulations that present a hazard [SASR B-7 (6) p.34]

19-10 19-11

… … … Rig signs posted at strategic road intersections … … … Warning signs, information signs, and signs posted requiring visitors to report to drilling supervisor posted at location entrance

19-12

… … … Safety orientation given to all personnel entering

20-2

… … … One 4-channel H2S monitoring system [H2S STD. (LAND) (I-A) p.24]

20-3

… … … H2S first alarm set for 30 ppm; high alarm set

for 50 ppm [H2S STD. (LAND) (I-A-2) p.24] Note: All ED&M reports will always recommend Drilling change their policy to 10 & 20 ppm, in line with Saudi Aramco policy and general industry practice.

location

19-13

… … … Workers wear appropriate protective equipment at all times

19-14

… … … Pre-job safety meetings conducted &

20.4

……… ……… ……… ………

documented (e.g. casing, testing, laydown)

19-15 19-16

… … … No rings, necklaces, long hair, or loose clothing

… … … Self contained breathing apparatus available … … … • Pressure demand … … … • Extra air cylinders … … … • Readily accessible … … … • Adequately maintained

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

20-5

Monitor sensor heads placed at [SASR B6 (2) p.23]:

• driller's position (about 3 feet off the rig floor) • top of bell nipple • flowline opening to shale shaker • cellar, or underneath the choke manifold above the choke manifold skid floor

… … … One spare H2S sensor [H2S STD. (LAND) (I-A4) p.24]

COMMENTS:

Page 12

… … … Four personal H2S monitors [H2S STD. (LAND)

20-15

… … … Two hand-held pump-type H2S detectors, with

20-16

YES

20-6

NO N/A

high and low level H2S and S02 tubes [H2S STD. (LAND) (I-D) p.25]

20-8

… … … One Hach Test Kit for checking H2S in the mud … … … One continuous combustible gas monitor

installed, with the sensor at either the top of the bell nipple (or the flowline opening to the shale shaker if a rotating head is in use) [H2S STD. (LAND) (I-B) p.24]

20-10

… … … Combustible gas first alarm set for 20% LEL;

20-17

… … … One spare combustible gas sensor [H2S STD.

20-18

… … … Two portable combustible gas monitors [H2S

20-19

20-20

20-21

20.14

……… ……… ……… ……… ………

SCBA located as follows [H2S STD. (LAND) (IIB) p.25]:

… … … Two safety harnesses with two 250-foot retrieval ropes [H2S STD. (LAND) (III-G) p.26]

20-22

… … … One basket stretcher [Stokes litter or Navy type) [H2S STD. (LAND) (III-H) p.26]

SABA installed (manifold outlets and SABA) [H2S STD. (LAND) (II-A) p.25]:

• 6 on rig floor • 2 at shale shaker • 2 at mud mixing area • 1 at choke manifold • 1 in monkey board

… … … Two portable oxygen resuscitator units, each

with a spare oxygen cylinder [H2S STD. (LAND) (III-D) p.26]

20-23

……… ……… ……… ……… ………

… … … Flare ignition system (and a backup) [H2S STD. (LAND) (III-C) p.25]

STD. (LAND) (I-E) p.25]

20-13

… … … Two safe briefing areas marked out [SASR B6 (4c) p.23]

(LAND) (I-B-4) p.25]

20-12

… … … Windsock or streamer visible from anywhere on the location [SASR B6 (3) p.23]

high alarm set for 40% LEL [H2S STD. (LAND) (I-B-2) p.24]

20-11

… … … Three windsocks (2 mounted, 1 spare) [H2S STD. (LAND) (III-B) p.25]

returns [H2S STD. (LAND) (I-F) p.25]

20-9

… … … Two quick air splints [H2S STD. (LAND) (III-I) p.26]

20-24

… … … Two portable bullhorns with three extra battery packs [H2S STD. (LAND) (III-J) p.26]

20-25

… … … Three chalk boards with clamps for mounting, and a supply of chalk and erasers [H2S STD. (LAND) (III-K) p.26]

20-26

… … … Explosion-proof flashlights with an extra set of

batteries and extra bulb for each (one flashlight for every two persons on location, with a minimum of 25 flashlights) [H2S STD. (LAND) (III-L) p.26]

• 2 in toolpusher's office • 2 in Aramco representative's office • 2 in mud logging unit • 1 in SCR room • 3 on rig floor

COMMENTS:

DHALPD ED&M LAND RIG INSPECTION CHECKLIST 6/13/06 [CHEKLAND.DOC]

NO N/A

STD. (LAND) (III-A) p.25]

(I-C) p.25]

20 -7

… … … Two 40,000 cfm bug blowers on drillfloor [H2S

YES

COMMENTS:

Page 13

DHALPD E&D RIG INSPECTION CHECKLIST FOR OFFSHORE RIGS DATE:

RIG:

FOREMAN:

WELL NAME:

OPERATION:

PERSONNEL CERTIFICATIONS: POSITION Foreman

NAME

Enter "T" if date entered indicates date training was taken. Enter "E" if date entered indicates date training expires. OTHER BADGE # BOP FIRST AID H2S

Foreman Toolpusher Toolpusher Driller Driller

POSITION Crane Op

NAME

BADGE #

SAG

ARAMCO Cert #

ARAMCO Cert Expiry

OTHER

Crane Op

1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Accommodations...........................1 Deck ..............................................2 SCR & Emergency Generator.......3 Accumulator ..................................4 Mud Pumps & Pump Room...........4 Pit Room........................................5 Substructure & Spider Deck..........6 Rig Floor........................................6 Dog House ....................................8 Derrick ...........................................9

11. 12. 13. 14. 15. 16. 17. 18. 19. 20.

Catwalk & Pipe Racks .................10 Manifold & Flare Lines,................10 Helideck .......................................10 Fire Fighting Equipment ..............11 Compressed Gas Cylinders ........11 Hand & Power Tools....................11 Welding & Cutting........................12 Cranes & Slings...........................12 General ........................................13 Engine Room...............................13

Note: Where applicable, inspection items are referenced to published Aramco policy. "SASR" refers to Saudi Aramco Safety Requirements for Drilling & Workover Rig Operations

1. ACCOMMODATIONS & GALLEY YES NO N/A

YES NO N/A

1 -1 6

All remaining SCBA and extra cylinders stored in an air-conditioned designated safety equipment storage area near the supervisor's office [H2S Std. (Offsh) (II-A5) p.31]

1 -1 7

Two Hose line SABA (with escape bottles and clip-on communication devices) stored in the supervisor's office. [H2S Std. (Offsh) (II-B) p.31]

1 -1 8

Two Hose line SABA (with escape bottles and clip-on communication devices) stored in the Aramco Foreman's office. [H2S Std. (Offsh) (II-B) p.31]

1 -1 9

Five SABA and 16 spare cylinders stored in an air-conditioned designated safety equipment storage area near the supervisor's office [H2S Std. (Offsh) (II-B 5) p.31]

1 -2 0

Nine spare clip-on communication devices are stored with the 5 spare SABA in an air-conditioned designated safety equipment storage area near the supervisor's office [H2S Std. (Offsh) (II-B 6) p.31]

1 -2 1

Ten personal H2S monitors present [H2S Std. (Offsh) (IV) p.32]

1 -2 2

One H2S calibrator with 2 permeation tubes, portable and AC/DC [H2S Std. (Offsh) (V) p.32]

1 -2 3

Ten 30-minute SCBA in the dining area [H2S Std. (Offsh) (II-A-2) p.31]

Four portable oxygen resuscitator units, with 8 spare oxygen cylinders [H2S Std. (Offsh) (VII) p.36]

1 -2 4

Two 30-minute SCBA, each with a clipon communication device, in the Aramco Foreman's office [H2S Std. (Offsh) (II-A4) p.31]

Four hand-held pump-type H2S detectors, with high and low level H2S and S02 tubes [H2S Std. (Offsh) (VIII) p.32]

1 -2 5

Four portable hand-pump suction-type combustible gas detectors [H2S Std. (Offsh) (IX) p.32]

1 -2 6

Flare ignition system (and a backup) [H2S Std. (Offsh) (XII) p.32]

1 -1

Electrical junction boxes weather proofed and closed [SASR B-15 (7) p.39]

1 -2

Electrical cords and fittings free of defects [SASR B-15 (1) p.38]

1 -3

Protective covers on all lights

1 -4

ABC fire extinguishers adequately placed

1 -5

Smoke alarms present and functioning

1 -6

Qualifications of workers posted or available on site (first aid, CPR, BOP, crane, rigger)

1 -7

Escape routes posted, marked and kept clear

1 -8

Station bills posted

1 -9

Drills conducted on a regular basis:

Date of last fire drill:________________________ Date of last abandon drill:___________________ Date of last BOP drill:______________________ Date of last man overboard drill:______________ 1 -1 0

Life jacket for each bunk in every stateroom

1 -1 1

One 30-minute SCBA assigned to each person on the rig, stored under the head end of his assigned bunk. [H2S Std. (Offsh) (II-A-1) p.31]

1 -1 2

1 -1 3

1 -1 4

1 -1 5

If no assigned bunk, that person's assigned SCBA is stored in a designated area [H2S Std. (Offsh) (II-A-1) p.31]

Two 30-minute SCBA, each with a clipon communication device, in the Toolpusher's office [H2S Std. (Offsh) (IIA-4) p.31]

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

COMMENTS:

Page 1

1 -2 7

Two emergency igniters (preferably flares) with a minimum 25 spare flares, stored in the Aramco foreman's lower right hand desk drawer [H2S Std. (Offsh) (XIII) p.33]

1 -2 8

Four safety harnesses and four 250-foot retrieval ropes [H2S Std. (Offsh) (XIV) p.33]

1 -2 9

Four basket stretcher [Stokes litter, Navy type, or equivalent) [H2S Std. (Offsh) (XV) p.33]

1 -3 5

The H2S alarm system is located where personnel can see/hear it, e.g. crew quarters, galley area, etc. [H2S Std. (Offsh) (I-E) p.30]

1 -3 6

The H2S monitor is located in the Supervisor's office. [H2S Std. (Offsh) (I-F) p.30]

1 -3 7

Cooking range exhaust fans, filters and ducts clean and operable

1 -3 8

Electrical appliances grounded and intact

1 -3 0

Four 25-man first aid kits [H2S Std. (Offsh) (XVI) p.33]

1 -3 9

Thermostats operable and regularly checked

1 -3 1

Four Quick-Air splints (or equivalent) [H2S Std. (Offsh) (XVII) p.33]

1 -4 0

Freezer doors operable from inside

1 -4 1

First aid kit and fire blanket available

1 -3 2

Six portable bullhorns with six extra battery packs [H2S Std. (Offsh) (XVIII) p.33]

1 -4 2

Fire extinguishing system in place and charged

1 -4 3

1 -3 3

Six chalk boards with clamps for mounting, and a supply of chalk and erasers [H2S Std. (Offsh) (XIX) p.33]

Personal sanitation rules posted and followed

1 -4 4

Adequate sanitation and housekeeping

1 -4 5

Galley inspected by Industrial Hygiene / Environmental Health; Date of last inspection:_________________

Minimum 7 explosion-proof flashlights with an extra set of batteries and extra bulb for each [H2S Std. (Offsh) (XX) p.33]

1 -3 4

2. MAIN DECK YES NO N/A

2 -2

YES NO N/A

Main decks in good condition, clean, and not slippery

2 -1

2 -9

Sprinkler, deluge, Halon, etc. Systems inspected regularly [G.I. 1781.001, 1782.001]

2 -1 0

Lifeboats, emergency stores, and equipment maintained and inspected

Oil spills and slick spots cleaned immediately

2 -3

Hand rails, kick plates in place

2 -4

Hatch openings guarded

2 -5

Deck loads properly secured

2 -6

Routes to life boats, rafts marked

2 -7

Safety signs posted and legible

2 -8

Fire fighting equipment, hose stations, etc. properly maintained, marked, accessible

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

Date of last Inspection:_____________ Expiry date on stores:______________ 2 -1 1

Boats checked and started regularly, recorded in logbook.

Frequency:______________________ Date of last Inspection:_____________

COMMENTS:

Page 2

2 -1 2

Windsocks or streamers visible from anywhere on the rig [H2S Std. (Offsh) (XI) p.32]

2 -2 0

Three air compressors each with purification system and 26 scfm capacity at 2400 psi [H2S Std. (Offsh) (III) p.32]

2 -1 3

H2S monitor sensor heads placed as near as practical to living quarters area nearest the most likely source of H2S [H2S Std. (Offsh) (I-B) p.30]

2 -2 1

One 3-outlet cascade manifold [H2S Std. (Offsh) (III) p.32]

2 -2 2

Three 12-outlet cascade manifolds [H2S Std. (Offsh) (III) p.32]

2 -1 4

2 -1 5

A spare H2S sensor with 200 feet of cable on a portable reel kept on standby in a designated safety equipment storage area. (There are supposed to be eight sensors rigged up: 7 already in position and this eighth ready to go). [H2S Std. (Offsh) (I-B) p.30]

2 -2 3

Two 150-ft. cascade hoses [H2S Std. (Offsh) (III) p.32]

2 -2 4

Twelve 50-ft. cascade hoses [H2S Std. (Offsh) (III) p.32]

2 -2 5

Two 5000 psi cascade hoses (250-ft. and 300-ft.) [H2S Std. (Offsh) (III) p.32]

Four spare H2S sensors available [H2S Std. (Offsh) (I-C) p.30]

2 -2 6

Two cascade systems with dieselpowered air compressors are located as remotely from the rig floor as practical, one on the upper port deck, the other on the upper starboard deck [H2S Std. (Offsh) (III-B) p.32]

2 -1 6

H2S low alarm (red beacon and siren) set for 10 ppm; and high alarm set for 20 ppm [H2S Std. (Offsh) (I-D) p.30]

2 -1 7

The alarm system is located where personnel in any work area can see/hear at least one set. Specifically [H2S Std. (Offsh) (I-B) p.30]:

These remote cascades have: 2 -2 6 a )

one 6-outlet cascade manifold for recharging portable cylinders at each cascade system, as well as regulators and low pressure manifolds for hoseline units [H2S Std. (Offsh) (III-B1) p.32]

2 -2 6 b )

double Tee with check valves for tying in either or both of the other 2 cascade systems [H2S Std. (Offsh) (III-B-2) p.32]

• port side at the corner of and above the quarters • starboard side at the corner of and above the quarters

2 -1 8

One hundred 30-minute SCBA located on the rig [H2S Std. (Offsh) (II-A-1) p.31]

2 -1 9

Three cascade systems with twelve 300 cu. ft. cylinders each (or equivalent) [H2S Std. (Offsh) (III) p.32]

3. SCR & EMERGENCY GENERATOR YES NO N/A

YES NO N/A

3 -1

Emergency lighting installed and working at TWO exits [SASR B-15 (6) p.38]

3 -2

Non-conductive mats placed on floor [SASR B-15 (5) p.38]

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

3 -3

Halon fire extinguisher available (only Halon is permitted in the SCR room) [SASR B-9 (4) p.35]

3 -4

Fans and belts guarded [SASR C-1 (1a) p.45]

COMMENTS:

Page 3

3 -5

Auxiliary and emergency standby generators run at full load for 30 minutes every week [SASR B-15 (12) p.39]

3 -1 2

Lights have protective coverings

3 -1 3

Noise hazard sign in place [SASR B-3 (8) p.17]

3 -1 4

Hearing protection provided and used by workers [SASR B-3 (9) p.17]

3 -6

Electrical junction boxes identified and kept in closed position [SASR B-15 (7) p.39]

3 -7

Electrical outlets labeled, voltage identified [SASR B-15 (7) p.39]

3 -1 5

Exits free of obstruction [SASR B-7 (1) p.30]

3 -8

All knockouts in panels (no open knockouts) [SASR B-15 (1) p.38]

3 -1 6

Floors and equipment free of oil or grease [SASR B-7 (2) p.34]

3 -9

Electrical cords, plugs, receptacles etc. in good condition [SASR B-15 (1) p.38]

3 -1 7

Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

3 -1 0

Switches capable of being locked out

3 -1 8

3 -1 1

Lockout procedures in place [SASR B-31 p.43]

"High Voltage - Use No Water" sign posted [SASR B-3 (2) p.16]

4. ACCUMULATOR YES NO N/A

YES NO N/A

4 -1

Accumulator area clean and tidy

4 -7

4 -2

Accumulator bottles precharged to 1200 psi [SASR C- 30 (7) p.63]

Controls in OPEN or CLOSED position, not neutral [SASR C- 30 (11) p.63]

4 -8

Spare nitrogen bottles available & pressurized

Accumulator function tests conducted Date of last test:_________

4 -9

No leaks in system [SASR C- 30 (7) p.63]

Emergency lighting installed and working [SASR B-16 (7) p.39]

4 -1 0

Gauges in good condition and readable [SASR C- 30 (7) p.63]

Fire extinguisher in place and serviceable

4 -1 1

Compressor free of dirt, grease or oil [SASR B-7 (2) p.34]

4 -3

4 -4

4 -5

4 -6

Controls free of any obstruction [SASR C- 30 (8) p.63]

5. MUD PUMPS & PUMP ROOM YES NO N/A

YES NO N/A

5 -4

Lubricator pump belt and pulleys guarded [SASR C-1 (1a) p.45]

Pop (relief) valve capped, proper size pins inserted (set @ _____psi) [SASR C-35 (2, 3, 4) p.64]

5 -5

Shock hoses safety chained [SASR C-35 (13) p.65]

No valves installed between pump and pop valve [SASR C-35 (1) p.64]

5 -6

No valves installed between pop valve and its discharge [SASR C-35 (6) p.64]

5 -1

Fans and belts guarded [SASR C-1 (1a) p.45]

5 -2

5 -3

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

COMMENTS:

Page 4

5 -7

Pop valve discharge line is horizontal or sloped downward [SASR C-35 (9) p.65]

5 -1 4

Sign posted identifying remote startup of equipment (if applicable)

5 -8

Discharge line properly secured [SASR C-35 (8) p.65]

5 -1 5

Noise hazard sign posted [SASR B-3 (8) p.17]

5 -9

Electrical connections in good condition [SASR B-15 (1) p.38]

5 -1 6

Hearing protection provided and used [SASR B-3 (9) p.17]

5 -1 0

Used electrical receptacles capped [SASR B-15 (7) p.39]

5 -1 7

Floor and equipment free of grease, oil and debris [SASR B-7 (2) p.34]

5 -1 1

Electrical lights have protective covers

5 -1 8

5 -1 2

Emergency lighting installed and operable [SASR B-16 (7) p.39]

No oily rags or tools laying about [SASR B-7 (7) p.34]

5 -1 9

30 pound dry chemical fire extinguisher serviced and in place [SASR B-6 (IV A-3) p.26]

Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

5 -2 0

Gas detection equipment present, functioning, can be seen and heard

5 -1 3

6. PIT ROOM (CLASS 1, DIV. 1 & 2) YES NO N/A

YES NO N/A

6 -1

All pulleys, belts, couplings on motors properly guarded [SASR C-1 (1a) p.45]

6 -2

Eyewash facilities at mixing area serviced and operable [SASR B-3 (11) p.17; B-6 III F2 p.26]

6 -3

Goggles provided at mixing area, and worn [SASR A-5 (8) p.13; SASR B-3 (4) p.17]

6 -9

Electrical connections, plugs, receptacles, and lights in good condition and properly sealed [SASR B-15 (1) p.38]

6 -1 0

Lights have protective covers [SASR B15 (1) p.38]

6 -1 1

Grommets & electrical cables with proper fit [SASR B-15 (1) p.38]

6 -4

Mud tanks and shale shakers ventilated if enclosed [SASR C-34 (2) p.64]

6 -1 2

Guard rails in place [SASR C-1 (1b) p.45]

6 -5

Hazardous products (i.e. caustic) used in barrel mixer or mud tank adequately identified

6 -1 3

30 pound dry chemical fire extinguisher serviced and in place at shaker [SASR B-6 (IV A-2) p.26]

6 -6

Mud products Material Safety Data Sheets (MSDS) available [SASR B-33 (3, 4, 5,) p.45]

6 -1 4

Floor coverings in place to prevent tripping or falling [SASR C-1 (1b) p.45]

6 -1 5

6 -7

MSDS stored at _____________

6 -8

Explosion-proof motors and fittings if applicable [SASR B-15 (1) p.45]

Walkways, stairs and platforms in good condition [SASR C-1 (1b) p.45; SASR C-8 (3) p. 48]

6 -1 6

No tools or tripping hazards on walking/working surfaces [SASR C-8 (3) p. 48]

6 -1 7

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

Bottom of stairs within 9" of ground level, and unobstructed

COMMENTS:

Page 5

6 -1 8

6 -1 8 a )

H2S monitor sensor head placed as near as practical to: [H2S Std. (Offsh) (I-B) p.30]: flowline opening to shale shaker

6 -1 8 b )

mud pit

6 -1 9

Rig floor cascade system connected to one 3-outlet cascade manifold in the mud room [H2S Std. (Offsh) (III-A-3) p.32]

7. SUB-STRUCTURE/ SPIDER DECK (CLASS 1, DIV. 1&2) YES NO N/A

YES NO N/A

7 -1

All pins and safety pins in place [SASR C-2 (9) p.46]

7 -7

Unused electrical receptacles covered [SASR B-15 (7) p.39]

7 -2

BOP properly turnbuckled (4 lines) [turnbuckles recommended by SASR C30 (6) p.63]

7 -8

Hand rails in place

7 -9

Work vests available & used

7 -1 0

Tugger lines in good condition, not kinked, crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

7 -1 1

H2S monitor sensor heads placed as near as practical to top of bell nipple [H2S Std. (Offsh) (I-B) p.30]

7 -1 2

Lights sealed with protective covers [SASR B-15 (1) p.38]

7 -3

BOP scaffolding or working platforms in good condition

7 -4

Steel or approved equivalent armored hose accumulator lines [SASR C-30 (13) p.63]

7 -5

All electrical junction boxes and conduit sealed [SASR B-15 (7) p.39]

7 -6

Electrical equipment and cables in good condition [SASR B-15 (1) p.38]

8. RIG FLOOR (CLASS 1, DIVISION 1 & 2 AREA) YES NO N/A

YES NO N/A

8 -1

A loudspeaker system is installed that can be heard throughout the working area [SAMIR requirement]

8 -2

Two unobstructed exits from rig floor, not counting the exit leading directly to mud pits [SASR C-8 (2) p.48]

8 -3

Doors open outward from floor and dog house [SASR C-8 (2) p.48]

8 -4

V-door closed or chained when not in use [SASR C-8 (8) p.49]

8 -5

Handrails in place [SASR C-8 (5) p.49]

8 -6

Floor openings covered when not in use [SASR C-8 (9) p.49]

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

8 -7

Walkways and work areas unobstructed, and clean [SASR C-8 (3) p.48]

8 -8

Drawworks and rotary drive guarded [SASR C-7 (4, 5) p.48]

8 -9

Stabbing valves (or crossovers) on floor (or doghouse) for each thread type used in string

8 -1 0

Handles for kelly cocks and stabbing valve in easily accessible place

8 -1 1

Rough tread plate installed around rotary table

8 -1 2

Tong dies sharp and die keepers installed [SASR C-21 (6) p.58]

COMMENTS:

Page 6

8 -1 3

Tong body and tong jaws in good condition [SASR C-21 (5) p.58]

8 -3 1

Crown stop properly set [SASR C-5 (4) p.47]

8 -1 4

Snub line on each tong [SASR C-21 (1) p.58]

8 -3 2

Drill line properly spooled on drum and anchored [SASR C-18 (4) p.55]

8 -1 5

Tong snub lines in good condition [SASR C-21 (4) p.58]

8 -3 3

8 -1 6

Tong snub lines properly triple clamped (or have factory-made eyes) [SASR C-21 (1) p.58]

Tugger line in good condition, not kinked, crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

8 -3 4

Tong snub lines minimum 5/8 " (15.9 mm) diameter

Tugger line with safety hook or shackle on end (recommended by DHALPD E&D)

8 -3 5

Make-up tong chain not unduly worn, gouged, or grooved

Swivel used on tugger line (recommended by DHALPD E&D)

8 -3 6

All wire rope fittings properly clamped, clamps properly spaced [SASR C-18 (13) p.55]

8 -3 7

No wire ropes are knotted, or have "Flemish eye splice", "farmer's eye splice" or "rig operator's standby" [SASR C-18 (15) p.55]

8 -3 8

All other wire ropes and slings free from wickers, not kinked, crushed, cut, worn, bird-caged, or unstranded [SASR C-18 (3) p.55]

8 -1 7

8 -1 8

8 -1 9

No spinning chain on drill floor [Revised D&WOOD policy 10-01-96]

8 -2 0

Mud can and line installed and in good condition [SASR C-24 (2) p.59]

8 -2 1

Driller's controls adequately labeled [SASR C-11 (2) p.51]

8 -2 2

Driller's controls adequately guarded [SASR C-11 (5) p.52]

8 -2 3

Lockouts on rotary and cathead clutches (recommended by DHALPD E&D)

8 -3 9

Ends of Driller’s headache post contained [SASR C-13 (12) p.53]

Signal man used with tugger, when required

8 -4 0

Brake handle slotted c/w tiedown [SASR C-12 (3) p.52]

Maximum allowable casing pressure posted at remote choke control panel

8 -4 1

All electrical connections, plugs, receptacles and cords comply with Classification for the area [SASR B-15 (1) p.38]

8 -4 2

Electrical connections, cords, plugs and receptacles in good condition (no electrician's tape used to splice or repair) [SASR B-15 (1) p.38]

8 -4 3

Proper fit between electrical cables and grommets [SASR B-15 (1) p.38]

8 -4 4

Lights with proper sealed coverings free of cracks or breaks, properly sealed [SASR B-15 (1) p.38]

8 -2 4

8 -2 5

8 -2 6

Brakes in good condition [SASR C-12 (1) p.52]

8 -2 7

Hydromatic, Dynamatic, or El Magco functioning properly and checked weekly [SASR C-12 (1) p.52]

8 -2 8

Weight indicator or transducer safety tied on deadline [SASR C-32 (21) p.64]

8 -2 9

Slip and cut program in place, documented [SASR C-18 (2) p.55]

8 -3 0

Line spooler on fast line adequately secured

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

COMMENTS:

Page 7

8 -4 5

Eyewash facilities on rig floor (or doghouse) serviced and operable [SASR B-3 (11) p.17; B-6 III F1 p.26]

8 -4 6

Two 30 pound dry chemical fire extinguishers serviced and in place at drawworks [SASR B-6 (IV A-4) p.26]

8 -4 7

Six movable, explosion-proof, 25,000 cfm bug blowers are available [H2S Std. (Offsh) (X) p.32]

8 -4 8

A continuous monitoring system with 8 sensors and 6 red beacon light-siren alarms is installed [H2S Std. (Offsh) (I) p.30] H2S monitor sensor heads placed as near as practical to [H2S Std. (Offsh) (IB) p.30]:

8 -4 9

8-49a)

Driller’s position (about 3 ft off the rig floor)

8-53b)

one 3-outlet cascade manifold at the Derrickman's position [H2S Std. (Offsh) (III-A-2) p.32]

8-53c)

one 3-outlet cascade manifold in the mud room [H2S Std. (Offsh) (III-A-3) p.32]

8-53d)

8-49b)

breathing apparatus compressor package, near the rig floor

8 -5 0

H2S low alarm (red beacon and siren) set for 10 ppm; and high alarm set for 20 ppm [H2S Std. (Offsh) (I-D) p.30]

8 -5 1

The alarm system is at least 8 feet high and can be seen/heard on the floor [H2S Std. (Offsh) (I-B) p.30]

8 -5 2

Six SABA on rig floor, 3 of which have clip-on communication devices [H2S Std. (Offsh) (II-B) p.31]

8 -5 3

One cascade system is located near the rig floor with air compressor powered by an explosion-proof motor [H2S Std. (Offsh) (III-A) p.32]

This rig floor cascade is connected to: 8-53a)

two 6-outlet cascade manifolds on the derrick floor [H2S Std. (Offsh) (III-A-A) p.32]

8-53e)

one 6-outlet cascade manifold for recharging portable cylinders, one at each cascade system [H2S Std. (Offsh) (III-A-5) p.32]

8-53f)

a double Tee with check valves for tying in either or both of the other 2 cascade systems [H2S Std. (Offsh) (III-A-6) p.32]

one 3-outlet cascade manifold in the motor room [H2S Std. (Offsh) (III-A4) p.32]

9. DOGHOUSE YES NO N/A

9 -1

YES NO N/A

"No Smoking", hard hat, and safety footwear signs posted at foot of stairs leading to doghouse [SASR A-5 (5) p.13]

[location:_______________] 9 -5

Employees know location of stretcher and blankets

9 -2

Doghouse doors free of locking devices [SASR C-8 (2) p.48]

9 -6

Bulletin board used to post current safety material

9 -3

Blowout prevention procedures posted [SASR C-30 (14) p.63]

9 -7

Date of last safety item posted on the bulletin board:________________

9 -4

Two stretchers readily available [SASR B-1 (III B) p.26]

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

COMMENTS:

Page 8

9 -8

Three SCBA available and in good condition in doghouse (or rig floor) [SASR B6 (II B5) p.25]

9 -9

Spare derrick belt [SASR C-29 (7) p.47]

9 -1 0

Goggles, face shields and other personal protective equipment kept in doghouse

9 -1 1

BOP function tests done regularly and documented in IADC book

9 -1 2

Drills held and documented in IADC book (BOP, H2S, fire, evacuation) [SASR C-30 (15) p.63]

9 -1 3

Safety meeting topics and attendance documented

9 -1 4

Trip records kept

9 -1 5

Electrical plugs, receptacles, cords, conduit junction boxes comply with API RP-500 C [SASR B-15 (1) p.38]

9 -1 6

Light covers sealed [SASR B-15 (1) p.38]

9 -1 7

Remote BOP controls free of obstruction and accidental operation [SASR C-30 (8) p.63]

9 -1 8

Housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

10. DERRICK YES NO N/A

1 0 -1

YES NO N/A

Derrick has a permanent nameplate attached (or available in-site) stating: manufacturer, model number, serial number, hook load capacity, wind load capacity (both with and without pipe in the derrick), and (if applicable) the recommended guying pattern. [SASR C2 (1) p.45]

1 0 -2

Operating within prescribed limits [SASR C-2 (2) p.46]

1 0 -3

Derrick ladder extends down to rig floor (no need to climb up standpipe, etc.)

1 0 -4

Base of ladder clear of obstructions [SASR C-8 (15) p.49]

1 0 -5

Derrick ladder extends at least 3 feet (91 cm) above each landing platform (including the crown) [SASR C-8 (23) p.50]

1 0 -8

Derrick girts in good condition [SASR C2 (4) p.46]

1 0 -9

All derricks pins in place c/w safety pins [SASR C-2 (4, 10) p.46]

1 0 -1 0

Tong counterweight weight ropes minimum 1/2" (12.7 mm) diameter [SASR C-22 (2) p.59]

1 0 -1 1

Unguided tong counterweights safety tied with minimum 5/8" (15.9 mm) diameter wire rope [SASR C-22 (1) p.59]

1 0 -1 2

Safety line prevents counter weight from dropping within 8 ft. (2.4 m) of floor [SASR C-22 (1) p.59]

1 0 -1 3

All sheaves, lights, and other fixtures safety-tied [SASR B-16 (3) p.39 (for lights only)]

1 0 -1 4

Standpipe adequately anchored

1 0 -6

Platforms provided at regular intervals on ladder , or climbing device provided [SASR C-8 (14) p.49]

1 0 -1 5

Kelly hose safety chained at both ends, (chained to the swivel, not chained to the gooseneck) [SASR C-35 (12) p.65]

1 0 -7

Climbing belt always used [SASR C-8 (18) p.49]

1 0 -1 6

Traveling blocks have sheave guards [SASR C-5 (1) p.47]

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

COMMENTS:

Page 9

1 0 -1 7

Traveling blocks free of projections [SASR C-5 (3) p.47]

1 0 -1 8

Kelly hook safety latched [SASR C-5 (1) p.47]

1 0 -1 9

Safety belt c/w shoulder harness in derrick [SASR C-29 (2) p.47]

1 0 -2 0

Safety belt lanyard minimum 5/8" (15.9 mm) manila rope (not synthetic) with no splices [SASR C-29 (3) p.47]

1 0 -2 1

Monkey board secured and in good condition

1 0 -2 2

Adequate tie back and pull back ropes

1 0 -2 3

Fingers and pads properly pinned and safety chained [SASR C-27 (2) p.60]

1 0 -2 4

Crown has no openings large enough for a worker to fall through [SASR C-4 (1) p.46]

1 0 -2 5

Crown bumper blocks (wooden planks) safety tied, or covered with expanded metal, or suitable screen or mesh [SASR C-4 (2) p.46]

1 0 -2 6

Derrick lights have adequately sealed protective covers [SASR B-15 (1) p.38]

1 0 -2 7

All electrical connections, plugs, receptacles, cords etc. are in good condition [SASR B-15 (1) p.38]

1 0 -2 8

Electrician's tape not used in splices or at grommets [SASR B-15 (1) p.38]

1 0 -2 9

SABA in the derrick (monkey board) [H2S Std. (Offsh) (II-B) p.31]

1 0 -3 0

The rig floor cascade system is connected to one 3-outlet cascade manifold on the monkeyboard [H2S Std. (Offsh) (III-A-2) p.32]

11. CATWALK & PIPE RACKS YES NO N/A

YES NO N/A

1 1 -6

Catwalk free of tripping hazards [SASR C-9 (3) p. 50]

Workers stand out of the way when rolling, loading, or unloading pipe [SASR C-10 (3) p. 51]

1 1 -7

Stairs at end of catwalk [SASR C-9 (3) p. 50]

Pipe key, crowbar, or other safe method used when rolling pipe

1 1 -8

Blocks, pins, or chocks used to prevent pipe from rolling off rack [SASR C-9 (1) p. 50]

1 1 -9

Tag line used when loading or unloading pipe [SASR D-2 (5) p. 67]

1 1 -1

Catwalk level, in good condition [SASR C-9 (3) p. 50]

1 1 -2

1 1 -3

1 1 -4

Pipe racks/tubs level and in good condition [SASR C-9 (1) p. 50]

1 1 -5

Adequate spacers between layers of pipe [SASR C-9 (5) p. 50]

12. MANIFOLD & FLARE LINES YES NO N/A

YES NO N/A

1 2 -1

Manifold and valves free of obstruction

1 2 -2

Valves wheels turn easily

1 2 -3

Valve handles kept 1/4 turn from the open or closed position

1 2 -4

Casing and drillpipe pressure gauges installed

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

1 2 -5

Casing and drillpipe pressure gauges easily visible from manual choke operator's position

1 2 -6

Maximum allowable casing pressure posted at manual choke

COMMENTS:

Page 10

1 2 -7

Safety chains used for pressure hoses, lines with hammer unions, or chiksans

1 2 -8

Electrical connections, plugs, receptacles Class I, Div. II and lights are properly sealed with a protective cover [SASR B15 (1) p.38]

13. HELIDECK YES NO N/A

1 3 -1

YES NO N/A

Regularly inspected by Aviation

1 3 -5

Date of last inspection:_____________ 1 3 -2

Non-skid material on helideck

1 3 -3

Outside perimeter lattice in place and in good condition

1 3 -4

Crash box properly equipped box [SASR B-9 (9) p.35] (Note: ONLY Aviation will inspect crash box)

Fire fighting equipment inspected and operable

Date of last inspection:_____________ 1 3 -6

Safe arrival/boarding procedures used

1 3 -7

Fire team in position for landing/take-off

1 3 -8

Cranes secured (not working) during landing/take-off

14. FIRE FIGHTING EQUIPMENT YES NO N/A

YES NO N/A

1 4 -1

30 lb. ABC fire extinguishers provided throughout the rig at strategic areas

1 4 -2

Extinguishers readily accessible

1 4 -3

Extinguisher locations identified

1 4 -4

Extinguishers inspected weekly [SASR B-9 (2) p.35]

1 4 -5

Fire drills held regularly and logged

1 4 -6

Fire hoses kept on rack or reel when not in use [SASR B-9 (13) p.35]

1 4 -7

Fire hoses not used for any other purpose than fighting fires, drills, or testing [SASR B-9 (9) p.35]

1 4 -8

Fire hoses completely unrolled and inspected monthly [SASR B-9 (10) p.35]

1 4 -9

Offshore rigs have a Fire Control Plan permanently exhibited [SASR B9 (6) p.35]

15. COMPRESSED GAS CYLINDERS YES NO N/A

YES NO N/A

1 5 -1

Gas cylinders stored upright [SASR B-14 (1) p.38]

1 5 -4

Oxidizers stored at least 20 ft. (6.1 m) from fuel gases [SASR B-14 (1) p.38]

1 5 -2

Acetylene bottles (empty or full) always stored upright [SASR B-14 (4) p.38]

1 5 -5

1 5 -3

Empty and full gas cylinders stored separately [SASR B-14 (1) p.38]

Valve protection caps on all cylinders (without a regulator) [SASR B-14 (2) p.38]

COMMENTS:

D H A L P D E & D O F F S H O R E R IG IN S P E C T IO N C H E C K L IS T 6 /1 3 /0 6 [ CHEKOFSH.DOC]

COMMENTS:

Page 11

1 5 -6

Gas cylinders hoisted only in a cradle, pallet, or slingboard [SASR B-14 (3)

p.38]

16. HAND & POWER TOOLS YES NO N/A

1 6 -1

1 6 -2

1 6 -3

1 6 -4

YES NO N/A

Hand held power tools have "dead-man" auto-shutoff devices (tools that can be locked "ON" are expressly forbidden) [SASR B-17 (2) p.40] Hand held power tools are double insulated or grounded [SASR B-17 (2) p.40] Impact tools (such as drift pins, chisels, hammer wrenches) do not have mushroomed striking surfaces [SASR B17 (3) p.40]

Bench grinders: 1 6 -5

Tool rests no more than 1/8" (3.2 mm) from abrasive wheel [SASR B-18 (2) p.40]

1 6 -6

Grinding wheel is rated for the machine rpm (grinder rpm stamped on nameplate; wheel rpm rating identified on the wheel blotter) [SASR B-18 (5) p.41]

1 6 -7

Eye hazard sign

1 6 -8

Goggles or face mask available and used

Pneumatic power tools are secured to the air line to prevent accidental disconnection [SASR B-17 (7) p.40]

COMMENTS:

D H A L P D E & D O F F S H O R E R IG IN S P E C T IO N C H E C K L IS T 6 /1 3 /0 6 [ CHEKOFSH.DOC]

COMMENTS:

Page 12

17. WELDING & CUTTING YES NO N/A

YES NO N/A

No welding or cutting performed on: [SASR B-19 (1) p.41] 1 7 -1

1 7 -2

…any pipe/vessel containing pressurized fluid or gas …any container which contains or did contain flammable liquids or gases, until the container is filled with water or otherwise suitably purged. Used 55gallon drums are specifically included.

1 7 -6

Maximum acetylene gauge pressure less than 15 psi (103 kPa) [SASR B-19 (7) p.42]

1 7 -7

Acetylene cylinder valves not opened more than 1 1/2 turns [SASR B-19 (7) p.42]

1 7 -8

All gas bottle regulator gauges are in good condition (no cracked glass covers) [SASR B-19 (8) p.42]

1 7 -3

… in a confined space until the atmosphere has been tested "safe for fire" (0% LEL)

1 7 -9

All welding hoses are free from cracks, leaks, burns, worn spots [SASR B-19 (10) p.41]

1 7 -4

No welding or cutting on load handling tools or equipment (slips, tongs, elevators, bales, etc.) [SASR B-19 (3) p.41]

1 7 -1 0

No arc-welding cable with damaged insulation or exposed conductors [SASR B-19 (12) p.42]

1 7 -1 1

1 7 -5

Suitable eye/face protection used when welding, cutting, or grinding [SASR B-19 (6) p.42]

No splices in arc-welding cables within 10 ft. (3 m) of the electrode holder [SASR B-19 (13) p.42]

1 7 -1 2

Portable arc-welding machines are suitably grounded [SASR B-19 (15) p.42]

18. CRANE OPERATIONS AND SLINGS YES NO N/A

YES NO N/A

Note: The crane operator certification

1 8 -3

All slings identified with Manufacturer name or logo, a unique identifier number, and safe working limit (SWL) [S.A. G.I. 7.029 (4.1)]

1 8 -4

All slings have a detailed visual inspection every 6 months, recorded in a sling inspection log [S.A. G.I. 7.029 (7.2)]

1 8 -5

Spreader bars identified with Manufacturer name, serial number, date of load test certification, and (in English and Arabic) safe working limit (SWL) [S.A. G.I. 7.029 (6.2)]

1 8 -6

Spreader bars have a semi-annual documented inspection [S.A. G.I. 7.029 (6.2)]

information on the title page of this inspection checklist must be completed in full. 1 8 -1

Crane has valid Aramco Crane Inspection Certificate [SASR D-1 (1b) p.65]

Crane #:____________________ Cert. Expiry:_________________ Crane #:____________________ Cert. Expiry:_________________ 1 8 -2

Tag lines used [SASR D-2 (5, 6) p.67]

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

COMMENTS:

Page 13

19. GENERAL YES NO N/A

YES NO N/A

1 9 -1

All stairs with more than 4 risers have handrails [SASR C-8 (4) p.49]

1 9 -2

All working surfaces higher than 4 feet (1.2 m) have standard handrails (42" handrail, 21" knee rail, 4" toe board) [SASR C-8 (5) p.49]

1 9 -3

Safety harnesses used when working higher than 10 feet (3.1 m) above grade [SASR C-8 (6) p.49]

1 9 -4

All ladders (fixed and portable) in good shape with no bent, broken, or damaged side rails and steps [SASR C-8 (24) p.50]

1 9 -5

Portable ladders are safety tied [SASR C-8 (26) p.50]

1 9 -6

PFD's worn when working over water [SASR E-1 (5) p.50]

1 9 -7

Noise protection signs posted where required [SASR B-3 (8) p.17]

1 9 -8

Sign posted requiring visitors to report to radio room immediately upon arrival

1 9 -9

1 9 -1 0

Safety and abandonment procedures orientation given to all arriving newcomers, visitors, etc.; and documented in a log book Workers wear appropriate protective equipment at all times

1 9 -1 1

Pre-job safety meetings conducted & documented (e.g. casing, testing, laydown)

1 9 -1 2

No rings, necklaces, long hair, or loose clothing

1 9 -1 3

Overall housekeeping acceptable, no accumulations that present a hazard [SASR B-7 (6) p.34]

1 9 -1 4

At least one qualified First Aid person on each shift [GI 150.002]

1 9 -1 5

Telephone numbers of physician, hospital, ambulance, and helicopter service posted in the Toolpusher’s office, the nurse's station, and the radio room [SASR B1 (4) p.15]

1 9 -1 6

Crews trained in the following [SASR B6 (4) p.23] H2S characteristics and toxicity Detection and warning systems on location Safe briefing area locations Evacuation procedures Rescue procedures First aid for victims Inspection, maintenance, and use of emergency breathing equipment Drill procedure

1 9 -1 6 a ) 1 9 -1 6 b )

1 9 -1 6 c ) 1 9 -1 6 d ) 1 9 -1 6 e ) 1 9 -1 6 f) 1 9 -1 6 g )

1 9 -1 6 h ) 1 9 -1 7

Two safe briefing areas marked out [SASR B6 (4c) p.23]

20. ENGINE ROOM YES NO N/A

YES NO N/A

2 0 -1

H2S monitor sensor heads placed as near as practical to motor man's work area in the motor room [H2S Std. (Offsh) (I-B) p.30]

2 0 -3

The rig floor cascade system is connected to one 3-outlet cascade manifold in the motor room [H2S Std. (Offsh) (III-A-4) p.32]

2 0 -2

The H2S/gas alarm can be seen or heard [H2S Std. (Offsh) (I-E) p.30]

2 0 -4

One SABA in the motor man's work area in the motor room [H2S Std. (Offsh) (II-B) p.31]

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

COMMENTS:

Page 14

2 0 -5

Emergency shut off for fuel lines located in an area where they can be safely operated in the event of an engine room fire

COMMENTS:

DHALPD E&D OFFSHORE RIG INSPECTION CHECKLIST 6/13/06 [CHEKOFSH.DOC]

2 0 -6

Fire protection equipment tested, date of last inspection:___________________

COMMENTS:

Page 15

Engineering Standard SAES-B-062

30 June, 1997

Onshore Wellsite Safety Loss Prevention Standards Committee Members Lamp, W.P., Chairman Baghabrah, M.A. Buck, R.A. Fadley, G.L. Mullen, M.A. Mustafa, S.G. Terris, T.M.

Saudi Aramco DeskTop Standards Table of Contents 1 2 3 4 5 6 7

Scope............................................................ Conflicts And Deviations............................... References.................................. ................. Determination Of Rupture Exposure Radius. Wellsite In Populated Area........................... Population Analysis Procedure..................... Wellsites.......................................................

Previous Issue: 1 December, 1996 Next Planned Update: 1 February, 1998 Revised paragraphs are indicated in the right margin.

2 2 2 3 3 4 4

Page 1 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998

SAES-B-062 Onshore Wellsite Safety

8 Well Safety Valves And Wellsite Hardware.. 6 9 Abandoned Wells......................................... 8 10 Drilling Rig Access Routes........................... 8

1

2

3

Scope 1.1

This Standard covers requirements for site layout, wellhead protection, access, and flow isolation related to oil/gas production wells, hydrocarbon injection wells, delineation/monitoring wells, abandoned/suspended wells, and wellsite facilities located onshore. Water injection and supply wells which are open to or pass through a geological zone which could produce hydrocarbons are also included.

1.2

This standard shall apply in the following circumstances: 1.2.1

All new wellsites.

1.2.2

All new wells drilled at existing wellsites.

1.2.3

Existing wells located in areas which have become populated per this standard shall be upgraded as necessary during workovers.

Conflicts And Deviations 2.1

Any conflicts between this Standard and other applicable Saudi Aramco Engineering Standards (SAESs), Saudi Aramco Materials System Specifications (SAMSSs), Saudi Aramco Standard Drawings (SASDs), or industry standards, codes, and forms shall be resolved in writing by the Company or Buyer Representative through the Manager, Loss Prevention Department of Saudi Aramco, Dhahran.

2.2

Direct all requests to deviate from the Standard in writing to the Company or Buyer Representative, who shall follow internal company procedure SAEP-302 and forward such requests to the Manager, Loss Prevention Department of Saudi Aramco, Dhahran.

References All referenced specifications, standards, codes, forms, drawings, and similar material shall be of the latest issue (including all revisions, addenda, and supplements) unless stated otherwise. 3.1

Saudi Aramco References Page 2 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998

SAES-B-062 Onshore Wellsite Safety

Saudi Aramco Engineering Procedure SAEP-302

Instructions for Obtaining a Waiver of a Mandatory Saudi Aramco Engineering Requirement

Saudi Aramco Engineering Standards SAES-B-055

Plant Layout

SAES-M-006

Fencing

Saudi Aramco Materials System Specification 45-SAMSS-005

Wellhead Equipment

Saudi Aramco Standard Drawings

3.2

AD-036010

Wellhead Guard Posts

AB-036685

Wellhead Guard Barrier

AA-036247

Windsock Pole

AA-036454

Remote Controls for Onshore Wells

Industry Codes and Standards American Petroleum Institute

4

API RP 14B

Design, Installation, Repair and Operation of Subsurface Safety Valve Systems.

API SPEC 6A

Specification for Wellhead and Tree Equipment

Determination Of Rupture Exposure Radius (RER) The appropriate rupture exposure radius (100 ppmv hydrogen sulfide (H2S) or lower flammable limit (LFL) basis) shall be plotted from the wellhead at the distance indicated in Table 1. For fields, reservoirs, or service not listed, the rupture exposure radius shall be obtained from the Saudi Aramco Loss Prevention Department's Technical Services Unit.

5

Wellsite In Populated Area 5.1

A well is in a populated area if the population density index within the rupture exposure radius exceeds 20, or if a school, hospital, hotel, penal institution, or retail complex, existing or planned, is included within the rupture exposure radius of that well.

Page 3 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998

SAES-B-062 Onshore Wellsite Safety

Table 1 - RER For Oil/Gas Wells In Populated Areas Field Ain Dar Abqaiq Berri Central Arabia Dammam Manifa Qatif Shedgum Uthmaniyah Shedgum Shedgum Uthmaniyah

5.2

6

Reservoir Arab-D Arab-D Arab-C Unayzah Arab-D Lower Ratawi Arab-C Arab-D Arab-D Khuff Gas-B Khuff Gas-C Khuff Gas-C

RER (m) 1630 980 1650 200 1500 2400 2400 375 1350 1200 1500 1620

For purposes of this Standard, roads are not deemed to generate populated areas. Where wells are located near areas of potential concern, such as roads, parking areas, or camp sites, the Proponent Operating/Engineering Department shall determine whether additional precautionary measures, such as subsurface safety valves, fencing, etc., are required.

Population Analysis Procedure 6.1

The boundaries of Saudi Aramco and non-Saudi Aramco development areas, present and planned, within the rupture exposure radius of a well location shall be obtained from the Land and Lease Division of Government Affairs Services Department.

6.2

The population density index at a well location is defined as the sum of the existing density index and the virtual density index values for the site.

6.3

Buildings having more than 4 stories shall be included in the population density index as a number of equivalent buildings. The number of equivalent buildings shall be calculated by dividing the number of stories in the building by 3 and rounding up to a whole number.

6.4

To determine the existing density index for a well location, count the number of buildings lying within the rupture exposure radius of the well. The resulting whole number is the existing density index value.

6.5

For areas within the rupture exposure radius of a well which are planned for development, the virtual density index shall be calculated as follows:

Page 4 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998

6.6

7

SAES-B-062 Onshore Wellsite Safety

6.5.1

Calculate the land area in square meters (m²) of each development which is included within the rupture exposure radius of the well.

6.5.2

Multiply the included area by 0.00075 (exact) and round up. The resulting whole number is the virtual density index for this well location.

Not to be included in these calculations are temporary facilities which will be in place for less than 6 consecutive months.

Wellsites 7.1

A wellsite is defined as the well(s), prepared drilling pad, well flare/burnpit area, and buffer zone. The entire wellsite constitutes an exclusive land use. No other uses are permitted in this area. See Figure 1, page 10.

7.2

For oil/gas wells, the following layout and spacing requirements apply to individual low-pressure wells, which for purposes of this Standard are defined as wells for which the shut-in wellhead pressure is not expected to exceed 25000 kPa (3600 psig). For oil/gas wells that are expected to have shut-in wellhead pressures in excess of 25000 kPa, and for all gas injection wells, layout and spacing requirements are to be determined case by case, with concurrence by the Chief Fire Prevention Engineer. For multiple low-pressure oil/gas wells to be drilled in one location, layout and spacing requirements are to be determined case by case, with concurrence by the Chief Fire Prevention Engineer. 7.2.1

The minimum distance from a well to the outer edge of the wellsite shall be 105 m.

7.2.2

Well burnpit shall be located on a bearing between 60 degrees through 225 degrees true and at a minimum distance of 60 m from the well. Commentary Note: A 60 m buffer zone shall be maintained around the burnpit. For additional burnpit spacing requirements, see paragraph 7.7.

7.3

Vehicular Crash Protection and Fencing 7.3.1

In populated areas, where the wellsite is already enclosed by a fence, or where the well is located more than 150 m from an existing or planned public road, the wellhead shall be protected with guard posts per Saudi Aramco Drawing AD-036010. All other wellheads shall be protected with a guard barrier per Saudi Aramco Standard Drawing AB-036685. Guard barriers (AB-036685) may be used in place of the guard posts at the request of the Proponent. Page 5 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998 7.3.2

SAES-B-062 Onshore Wellsite Safety

Wellsites in populated areas shall be enclosed by a fence meeting the specifications of SAES-M-006 (Type III). The fence shall have four lockable vehicle gates, one in each quadrant. Two gates shall be 18 m wide rig-access gates. The locations of these rig-access gates shall permit access to all wells on the wellsite from either gate.

7.4

The drilling pad shall be level.

7.5

A wind sock pole per Saudi Aramco Standard Drawing AA-036247 and a wind sock per SAMS Catalog Number 47-947-030-00 are to be permanently installed at each active production or injection wellsite in a populated area.

7.6

Following are minimum spacing requirements from low-pressure oil/gas wells.

7.7

-

450 m minimum spacing between oil/gas wells and any of the following: process areas; major shipping pump, blending/booster pump, or fire pump areas; tetraethyl lead (TEL) facilities; LPG loading racks; atmospheric or pressure storage vessels; boilers and power generation facilities; major electric distribution centers; buildings, property lines, and residential areas; elevated flare stacks, unrelated ground flares, and unrelated burn pits.

-

200 m minimum spacing between oil/gas wells and main overhead power lines.

-

105 m minimum spacing between oil/gas wells and cathodic protection (CP) and other noncritical power lines.

-

105 m minimum spacing between oil/gas wells and right-of-way or camel fence, whichever is greater, of Saudi Aramco or Government highways, paved roads, or railroads.

-

105 m minimum spacing between oil/gas wells and pipelines.

Flares and burnpits for low-pressure oil/gas wells are viewed as infrequentlyused facilities that are under constant attendance and supervision of drilling personnel during the drilling of the well. Hence, spacing requirements are less than normal minimums specified for burnpits in SAES-B-055. Minimum requirements for well burnpits are as follows: -

Well burnpits shall be no closer than 150 m to main overhead power lines or residential areas.

-

Well burnpits shall be no closer than 105 m to CP and other noncritical power lines.

Page 6 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998

7.8

8

SAES-B-062 Onshore Wellsite Safety

-

Well burnpits shall be no closer than 105 m to highway right-of-way/camel fence, paved road, or railroad.

-

Well burnpits shall be no closer than 60 m to aboveground pipelines or 15 m to buried lines.

Water gravity injector, power injector, or supply wells have a basic 105 m spacing requirement from all other facilities. For gas injection wells, see paragraph 7.2.

Well Safety Valves And Wellsite Hardware 8.1

Hydrocarbon Producing and/or Hydrocarbon Injection Wells - General Requirements 8.1.1

All well installations shall be in accordance with the specifications prepared by Saudi Aramco Drilling and Workover Engineering. Naturally flowing wells shall be completed in a manner which permits flow only through a tubing string. They shall be equipped with a downhole packer or polished bore receptacle.

8.1.2

The specification break point from the high pressure rated wellhead piping to the lower pressure rated flowline piping shall be within the wellsite, upstream of any scraper launcher.

8.1.3

A manual isolation block valve to API SPEC 6A and Saudi Aramco wellhead equipment specifications shall be installed at the downstream end of the wellhead piping of each well. This valve shall be pressure rated equal to the wellhead piping. (Refer to 45-SAMSS-005). Where required by the Proponent Operating Department, a second block valve shall be installed on the wellsite, downstream of the valve in 8.1.3, for flowline isolation. Pressure rating of the valve shall either match the API SPEC 6A valve or the downstream flowline pipe specification, as required by the Proponent Operating Department.

8.1.4

All wells shall have a manual lower master valve. At the discretion of the Proponent Operating Department, oil wells may be equipped with manual remote operators attached to the master valve and/or wing valve. If manual remote operators are installed on oil wells, they shall be in accordance with AA-036454.

8.1.5

Any lockout device used to hold a surface safety valve in the open position by restricting movement of the valve stem shall be constructed Page 7 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998

SAES-B-062 Onshore Wellsite Safety

of fusible materials with a melting point 30 Celsius degrees above the higher of the flowing wellhead or maximum design ambient temperature.

8.2

8.3

8.1.6

All gas production wells shall have three spring-assisted failsafe surface safety valves (SSV), triggered when an abnormally high or low pressure is sensed in the high pressure piping downstream of the choke. Fusible devices with a set point 30 Celsius degrees above the higher of the flowing wellhead or maximum design ambient temperature, shall be installed on the wellhead to trigger the SSVs.

8.1.7

Hydrocarbon injection well flowlines shall each be provided with a check valve in the wellhead piping.

Producing Wells in Populated Areas 8.2.1

Supplemental to the general requirements, wells in populated areas shall comply with the following:

8.2.2

On oil wells the upper wellhead master valve shall be a spring-assisted fail-safe surface safety valve (SSV), triggered when an abnormally low pressure is sensed. Triggering by abnormally high pressure is required only when necessary to protect the downstream flowline. A fusible device with a melting point 30 Celsius degrees above the higher of the flowing wellhead temperature or maximum design ambient temperature, shall be installed on the wellhead to trigger the SSV.

8.2.3

A Subsurface Safety Valve (SSSV) per API RP 14B specification shall be installed more than 60 m below ground level in oil wells. The SSSV shall be controlled by the low pressure pilot. Closure triggered by an abnormal condition in the high pressure piping downstream of the choke shall be provided when required by the Proponent Operating Department. A fusible device with a melting point 30 Celsius degrees above the higher of the flowing wellhead or maximum design ambient temperature, shall be installed on the wellhead to separately trigger the SSSV.

Power Water Injection Wells Power water injection well flowlines shall each be provided with a check valve in the wellhead piping.

8.4

Observation Wells Wells shall be equipped with the relevant safety devices equivalent in function to those that would be required for a producing well at the same location. Page 8 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998 8.5

SAES-B-062 Onshore Wellsite Safety

Suspended Wells Wells shall be suspended in accordance with Producing Operations requirements. Suspension procedures for wells shall be documented by Producing Operations and shall be available for review.

9

Abandoned Wells The following requirements apply to a wellsite only if all its wells have been permanently plugged and if it is located in a populated area.

10

9.1

The perimeter of the drilling pad shall be provided with a fence (SAES-M-006, Type III) if there is no fence at the perimeter of the buffer zone.

9.2

The fence shall have one lockable vehicle gate 10 m wide.

9.3

One access route 10 m wide shall be maintained to the wellsite gate.

Drilling Rig Access Routes Two access routes shall be available to each wellsite. These shall meet the following requirements: 10.1

Each access route shall be 18 m wide, terminating at a rig access gate.

10.2

Vertical clearance over the access routes shall be 14 m minimum.

10.3

An access route shall not include grades or transverse slopes of more than 5 percent.

10.4

No obstruction is allowed on an access route.

10.5

The minimum radius of curvature of access routes shall be 70 m. The center point of all access route curves shall be outside the wellsite served.

10.6

One of the access routes required by paragraph 10.1 above shall have within it a prepared roadway consisting of a compacted marl running surface 0.3 m thick and 7.0 m wide with 3.5 m wide shoulders, giving a total clear road width of 14 m.

1 December, 1996 30 June, 1997

Revision Summary Editorial revision to convert document to new format. Editorial revision in paragraph 7.1.

Page 9 of 10

Document Responsibility: Loss Prevention Issue Date: 30 June, 1997 Next Planned Update: 1 February, 1998

SAES-B-062 Onshore Wellsite Safety

Figure 1 - Wellsite Location Spacing

Page 10 of 10

PREPARED BY:

SAUDI ARAMCO

NUMBER

WRS-602 REVISION

S.W. SMITH

DRILLING MAINTENANCE DIVISION

REVIEWED BY:

S. AL-DOSSARY

0 TYPE

WELDING PROCEDURE DATE

7 MAY, 1996

APPROVED BY:

SUPERSEDES SPEC. DATED

PROCEDURE NONE

G.K. SHAMMARY TITLE:

INSTALLATION OF SLIP ON/WELD ON CASING HEADS

1.0

SCOPE

This procedure applies to the installation of all slip on casing heads both in the field and in the shop.

2.0

INDEX 1.0 2.0 3.0 4.0

3.0

SCOPE INDEX REQUIRED MATERIALS PROCEDURE 4.1 PREPARATION 4.2 CASING CUT OFF 4.3 LEVELING HEAD AND TACK WELDING 4.5 WELDING TECHNIQUE 4.6 POSTHEATING AND COOLING 4.7 TESTING

REQUIRED MATERIALS

Welds shall be performed using Shielded Metal Arc. Low hydrogen electrodes shall be used. These are classes EXX15, EXX16, EXX18, or EXX28 of AWS 5.1 latest edition. SAMS catalog numbers for acceptable electrodes, temperature sticks and fire blankets are given below. Item 1 2 3 4 5

Description Electrode, E-6010 AWS A5.1, 1/8” Dia. Electrode, E-7018 AWS A5.1, 5/32” Dia. Electrode, E-7018 AWS A5.1, 3/16” Dia. Temperature Stick, 400 oF Blanket, Silica Cloth (rated to 3,000 oF)

4.0

PROCEDURE

4.1

PREPARATION Page 1 of 4

SAMS Number 20-484-024 20-483-074 20-483-078 20-477-135 20-532-460

Title:

Revision:

INSTALLATION OF SLIP/WELD ON CASING HEADS

0

Page: 2 of 4

Date:

7 MAY, 1996 4.1.1 4.1.2 4.1.3 4.1.4

Avoid anyone working above the welder on the drill floor. The wellhead should be protected from dripping mud, water or oil and from adverse weather conditions such as wind or rain. The head and casing in the weld area shall be dry and free from paint, grease, scale, rust or dirt. Fire extinguishers shall be placed in convenient reach of a stand-by/fire watch man.

4.2

CASING CUT OFF 4.2.1 Cut two holes in the top 1 foot of the last casing joint. 4.2.2 Install cable and shackles into the holes to hold casing when rough cut is made. 4.2.3 Determine from Rig Foreman the height required for the final cut. 4.2.4 Cut window in casing 6 to 8 inches above final cut height. Let mud and fluids drain. 4.2.5 Complete rough cut. 4.2.6 Bail or siphon fluids 6 to 8 inches below final cut height. 4.2.7 Mark and make final cut. 4.2.8 Grind off the top 3/32” of casing to remove the HAZ (Heat Affected Zone). DO NOT BEVEL THE CASING.

4.3

LEVELING HEAD AND TACK WELDING 4.3.1 Bail or siphon fluids/mud from casing to 1 foot below the weld area. Check fluid level continuously throughout procedure to ensure that fluid level stays ± 1 foot below weld area, bailing or siphoning as necessary. 4.3.2 Remove the test plug and ensure that the test port is open. 4.3.3 Pick up Casing Head and slip on to casing stub. 4.3.4 Welding cable should be firmly clamped to the wellhead. 4.3.5 Level head and tack-weld in place.

4.4

PREHEATING 4.4.1 The Casing Head and casing shall be preheated to a temperature of 400 oF for at least 3 inches above and below the weld. 4.4.2 Preheating temperature shall be verified by using 400 0F Temperature stick. 4.4.3 The rosebud heating torch shall be continuously used during welding to keep the head at approximately 400 0F.

Title:

Revision:

INSTALLATION OF SLIP/WELD ON CASING HEADS

0

Page: 3 of 4

Date:

7 MAY, 1996 4.5

WELDING TECHNIQUE 4.5.1

Use 1/8” E-6010 Electrode and step weld first bead (root pass). That is weld 2” to 4” (WELD 1), then move 1800 weld another 2” to 4” (WELD 2). Then move 1/2 way between the first two welds and weld 2” to 4” (WELD 3) then move 1800 and weld 2” to 4” (WELD 4) and continue (WELDS 5, 6, 7, 8 etc.), as shown in Figure 4.5-1A. Continue welding 2” to 4” 1/2 way between two welds then 2” to 4” 1800 opposite until the first pass is completed (as shown in Figure 4.1-5B). 1 7

5

4

3

8

6 2

Figure 4.5-1A: Begin Step Weld

4.6

Figure 4.5-1B: Finish Weld

4.5.2

The second pass shall be made with a 5/32” E-7018 electrode and may be continuous. The balance of the welding groove shall be filled using 3/16” E-7018 electrodes.

4.5.3

All beads shall be stringer beads with good penetration and should be thoroughly peened before applying the next bead. There should be no undercutting and welds shall be workmanlike in appearance.

4.5.4

Complete inside welds by repeating steps 4.5.1 through 4.5.3.

4.5.5

Grind inside welds as necessary to leave the required drift diameter (as per Rig Foreman).

POSTHEATING AND COOLING 4.6.1

Verify that temperature of the weld area is 400 0F using temperature stick. If temperature is below 400 0F reheat.

4.6.2

Wrap casing head with Silica cloth blanket to protect from wind and allow the head to slowly cool.

Title:

Revision:

INSTALLATION OF SLIP/WELD ON CASING HEADS

0

Page: 4 of 4

Date:

7 MAY, 1996 4.7

TESTING 4.7.1

4.7.2 4.8

After the casing head has cooled to ± 150 0F (cool enough to be able to lay your hand on the head. Test the weld using oil to the pressure required by the Drilling Program. DO NOT EXCEED 80% OF CASING COLLAPSE PRESSURE. Re-install the test plug.

REPAIR OF DEFECTS 4.8.1

If any leaks are detected one of three methods shall be used to repair the leak. The method used will be determined by the type of leak. 4.8.1.1

4.8.1.2

Blow Hole/Pin Hole Leak: e.g.: Single leak through small hole 4.8.1.1.1

Grind out hole to good metal at least 1” to each side.

4.8.1.1.2

Preheat area to 400 0F at least 3” to each side of ground area and re-weld. Wrap casing head with silica blanket and let cool. Test as in section 4.7.

Multiple Blow Hole/Pin Hole Leak: 4.8.1.2.1 4.8.1.2.2

4.8.1.3

Grind out holes to good metal ± 2” to each side of each hole to ensure no communication between holes. Preheat area to 400 0F at least 3” to each side of ground area and re-weld. Wrap casing head with silica blanket and let cool. Test as in section 4.7.

Crack: 4.8.1.3.1

If a crack is detected grind out to good metal 3600 around. Preheat entire head, either inside or outside as required, as in section 4.4. Re-weld number of beads as necessary to completely fill ground area. Post heat and cool as per section 4.6. Test as in section 4.7.