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

A

DRILLING MANUAL June 2006

GENERAL INFORMATION INTRODUCTION

___________________________________________________________________________________________________________________________

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

___________________________________________________________________________________________________________________________

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

___________________________________________________________________________________________________________________________

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

___________________________________________________________________________________________________________________________

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

___________________________________________________________________________________________________________________________

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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SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

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GENERAL INFORMATION ORGANIZATION AND RESPONSIBILITES

___________________________________________________________________________________________________________________________

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

___________________________________________________________________________________________________________________________

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.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

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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

C

June 2006

GENERAL INFORMATION ORGANIZATION AND RESPONSIBILITIES

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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 MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

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June 2006

GENERAL INFORMATION ORGANIZATION AND RESPONSIBILITIES

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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

___________________________________________________________________________________________________________________________

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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Drilling & Workover Engineering Department CHAPTER 1 SECTION

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June 2006

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.

SAUDI ARAMCO

DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

E

June 2006

GENERAL INFORMATION COMMUNICATION SYSTEMS

___________________________________________________________________________________________________________________________

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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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

E

June 2006

GENERAL INFORMATION COMMUNICATION SYSTEMS

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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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GENERAL INFORMATION COMMUNICAION SYSTEMS

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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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GENERAL INFORMATION

F

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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GENERAL INFORMATION RIG SPECIFICATIONS

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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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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 1 SECTION

F

June 2006

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 3.2.2 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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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

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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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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

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DRILLING MANUAL

Drilling & Workover Engineering Department CHAPTER 2 SECTION

June 2006

DRILLING PRACTICES

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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 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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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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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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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

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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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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 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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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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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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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

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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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DRILLING PRACTICES WELLHEADS

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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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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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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 MANUAL June 2006

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

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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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DRILLING PRACTICES WELLHEADS

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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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June 2006

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.

SAUDI ARAMCO Drilling & Workover Engineering Department CHAPTER 2 SECTION

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DRILLING PRACTICES LOST CIRCULATION

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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



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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