Types of Drilling Rigs (RT) – Stand-alone Chapter of the IADC Drilling Manual [2, 12 ed.] 9780990904953

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

IADC Drilling Manual 12th Edition IADC Drilling Manual • Copyright © 2015

THE IADC LEXICON

D E F I N I N G T H E D R I L L I N G S PAC E ! IADC Lexicon puts critical definitions at your fingertips. Imagine thousands of the most pertinent definitions and terms relevant to drilling, all in a single convenient repository – the IADC Lexicon. The IADC Lexicon draws from the most critical legislation, regulations, standards and guidelines worldwide. The European Union requested that IADC, as the authority in the drilling space, create the Lexicon to aid in regulation and understanding our industry. Use the IADC Lexicon as a dictionary or to quickly and easily identify a relevant standard, guideline or regulation. Or, use it as a template to develop instructions for your own company.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

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The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. Contributors Dan Postler, Sierra Hamilton Mark Childers, Consultant Mark Dreith, Dreith Working Interests LLC Vamsee Achanta, 2H Offshore Bob Blank, Noble Drilling Services Inc. Taylor Bowles, National Oilwell Varco Chistopher Brachey, 2H Offshore Dale Doherty, ConocoPhillips

Orlan Lyle, Noble Drilling Services Inc. Calvin Norton, Friede & Goldman. Ltd. John Shelton, Delmar Systems, Inc. Ron Swan, Noble Drilling Services Inc. Rohit Vaidya, 2H Offshore Meridith Wilson, SK Energy Justin Barrow, Delmar Systems, Inc. Jason Pasternak, Delmar Systems, Inc.

Reviewers Barry Braniff, Transocean Dave Foster, Transocean Harvey Rich, Atwood Oceanics Inc.

Kevin Lake, Atwood Oceanics Inc. Sam Pannunzio, Atwood Oceanics Inc.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9909049-3-9

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CHAPTER FD

FLOATING DRILLING EQUIPMENT AND OPERATIONS Introduction................................................................................. FD-1 Environment and safety.......................................................... FD-2 Environmental impact assessment................................. FD-3 Shallow hazard assessment.............................................. FD-3 Job safety analysis............................................................... FD-3 Simultaneous operations plans........................................ FD-3 Safety training and drills..................................................... FD-3 Conclusion..............................................................................FD-4 MODU floating equipment....................................................FD-4 Types of floating MODUs..................................................FD-4 Semisubmersibles............................................................. FD-4 Drillships...............................................................................FD-5 Ultra-Deepwater Drillships.............................................FD-5 Deck cranes and lifting systems......................................FD-6 Power generation and electrical systems...................... FD-7 Safety considerations........................................................FD-7 Power generation...............................................................FD-7 Configuration.......................................................................FD-7 Management system....................................................... FD-8 Redundancy and emergency power.......................FD-8 Fire, Safety, and Monitoring..............................................FD-9 Mooring systems and equipment...................................FD-12 Types of offshore-mooring systems......................... FD-12 Catenary moorings (conventional, steel, poly-insert)........................................................FD-12 Semi-taut moorings (steel, steel-polyester, steel-HMPE) ....................................................FD-12 Taut moorings (steel, steel-polyester, steel-HMPE).....................................................FD-12 Offshore mooring line components.......................... FD-12 Stud Link Chain.....................................................FD-14 Steel wire rope......................................................FD-14 Polyester rope.......................................................FD-14 Anchors.............................................................................. FD-14 Drag embedment anchors.................................FD-14 Driven anchors......................................................FD-15

Contents Gravity-installed anchors...................................FD-16 MODU deck mooring line-handling equipment........ FD-16 Drum winches.................................................................. FD-16 Traction winches............................................................. FD-16 Windlasses........................................................................ FD-17 Fairleaders......................................................................... FD-17 Auxiliary mooring equipment and hardware...............FD-17 Connecting hardware..................................................... FD-17 Dynamic positioning......................................................... FD-18 Well control and subsea equipment ........................... FD-20 Subsea BOP stacks......................................................... FD-20 Annular BOPs........................................................FD-20 Ram BOPs...............................................................FD-21 Kill and choke valves...........................................FD-22 Arrangement of a subsea BOP stack.............FD-22 Hydraulic wellbore connectors........................FD-23 Flex joint..................................................................FD-24 BOP control pods.................................................FD-24 BOP stack frame...................................................FD-25 Auxiliary and miscellaneous items.................FD-25 Subsea BOP control system......................................... FD-26 Surface control equipment................................FD-27 Subsea control pods............................................FD-28 Diverter control system......................................FD-28 Auxiliary and miscellaneous Items.................FD-29 Diverter systems..................................................FD-29 Marine risers...................................................................... FD-30 Physical operating principles....................................... FD-31 Buoyancy modules.......................................................... FD-32 Marine riser handling........................................................FD-32 Horizontal riser handling.............................................. FD-33 Vertical riser handling....................................................FD-34 Telescopic joints in marine riser systems............... FD-35 Emergency disconnect sequence.............................. FD-36 Subsea wellheads...............................................................FD-37

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Traveling load compensation..........................................FD-38 Drill string compensator............................................... FD-38 Crown-mounted compensator .................................. FD-39 Major CMC components...................................FD-39 Drawworks traveling block motion compensation..............................................................FD-40 Marine riser tensioners................................................... FD-42 Wireline marine riser tensioners................................FD-42 Inline marine riser tensioners......................................FD-43 Guideline Tensioners......................................................FD-44 Riser recoil.........................................................................FD-44 Auxiliary systems.............................................................. FD-46 Cementing.........................................................................FD-46 Remotely operated vehicles .......................................FD-46 Location..............................................................................FD-46 Deck structure..................................................................FD-47 Power, electrical and safety.........................................FD-47 MODU marine operations.................................................. FD-47 Vessel stationkeeping......................................................FD-48 Approaching location.....................................................FD-48 Spread-moored systems...............................................FD-49 Dynamic positioning systems.....................................FD-53 Cargo, special well and marine operations.................FD-57 Work boats ......................................................................FD-57 Deck and overhead cranes...........................................FD-57 Bulk and liquid transfer.................................................FD-58 Completion and well fluids........................................... FD-59 Moving MODU with the BOP stack suspended..................................................................... FD-59 Weather forecasting and integration with operations...........................................................FD-60

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MODU well drilling operations..........................................FD-60 Spud meeting and preparation......................................FD-60 Setting the foundation pipe............................................. FD-61 Drill the hole, run pipe and cement..........................FD-62 Jet pipe into the ground................................................FD-63 Turbodrill the pipe into the ground...........................FD-63 Drilling riserless................................................................. FD-63 Setting the conductor pipe.............................................FD-64 Preparing the BOP stack for running...........................FD-64 Marine riser space out and operation......................... FD-66 Running the marine riser and BOP stack.................... FD-68 Leak-off test and maximum anticipated surface pressure (MASP)............................................FD-70 Drilling below conductor casing.....................................FD-71 Well abandonment.............................................................FD-71 Other procedures...............................................................FD-72 Online, offline and simultaneous tubing/ casing handling........................................................... FD-72 Simultaneous operations ............................................. FD-72 Circulating marine riser of drilled cuts..................... FD-72 Diverting well fluids�������������������������������������������������������� FD-73 Circulating out trapped gas in the BOP stack......................................................... FD-73 Well testing....................................................................... FD-73 Completions and workovers.........................................FD-74 Coring...................................................................................FD-74 Setting cement plugs..................................................... FD-75 Unconventional floating drilling.....................................FD-75 Managed pressure drilling............................................ FD-75 Dual gradient drilling...................................................... FD-76 Surface BOP drilling........................................................ FD-76

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Introduction

This chapter will discuss floating mobile offshore drilling units (MODUs), their equipment and how to operate them. At this writing (Q1 2015) there are more than 900 MODUs of all types in the world, more than 300 of which are floaters (nearly 200 semisubmersibles [“semis”] and more than 100 drillships). This chapter will not cover bottom-supported units (jackups and submersibles), stationary platform rigs, or tender assist drilling (TAD) units. The first offshore well was drilled in Louisiana in 1947, followed in 1955 with the first well drilled from a floating vessel using a blowout preventer (BOP), a landmark that occurred on the California ocean floor. Since these milestones, equipment and processes for drilling from floating vessels have grown enormously and now constitute some of the most sophisticated technologies in the world. Two key characteristics of a floating drilling rig distinguish it from an onshore or bottom-supported rig. The rig: • Is fixed over the well by a spread-mooring system or a dynamic positioning (DP) system (“stationkeeping”); •• Drills through a pipe (marine riser) connected to a BOP stack that is latched onto a wellhead at the sea floor. (Surface BOP drilling, which is discussed later in this chapter, is an exception.) Today’s floating MODUs are generally categorized by water-depth capability as follows: • Shallow-water units (less than 2,000 ft water depth) are almost all spread-moored semisubmersibles, with a few drillships built prior to the early 1990s; •• Intermediate, or midwater, units (2,000 ft to approximately 7,500 ft) are a mix of upgraded and new spread-moored and DP semisubmersibles and a few DP drillships; •• Ultra-deepwater units (more than 7,500 ft), of which a majority are DP drillships built since the late 1990s. At present no MODU is rated beyond 12,000 ft water depth. Drilling rigs being built for ultra-deepwater are DP drillships or semis. Today’s MODUs are built to a standard and certified by Classification Societies, regulated by industry organizations and “registered” in a country just like a commercial vessel. In the United States for example, the US Department of the Interior regulates the wellbore and the US Coast Guard regulates the MODU. The classification agencies and governments work together and have a powerful influence on MODUs and their operation. Higher cost and risks also differentiate floating from bottom-supported drilling rigs. As of the mid-2010s, construction costs for an ultra-deepwater MODU average $700-$750 million, with some units as high as $850 mil-

IADC Drilling Manual

Figure FD-1: Unlike land or bottom-supported offshore drilling, floating drilling rigs are fixed over the well by a mooring or dynamic positioning system and drill through a pipe connected to the BOP on the wellhead on the sea floor. Courtesy Diamond Offshore Drilling Inc.

lion. Dayrates for these MODUs can reach $850,000/day, with total operating rate, including all support services and expendable items exceeding $1,500,000/day. As a result, $100-million deepwater wells are common. Some have exceeded $250 million in cost. Assuming an economic hydrocarbon discovery is found in deepwater, the development cost can be tens of billions of dollars, with a 5-10-year horizon for first production. This extremely high capital cost leaves most floating drilling and development to major oil companies, though some independents do conduct floating offshore operations. It has taken the industry more than 50 years to develop the technology to drill economically in deepwater. Compared to the first floating drilling units, today’s deepwater rigs are significantly larger, with water displacements reaching 90,000 deadweight tonnage (dwt) and beyond. (Deadweight tonnage represents how much weight a vessel can safely carry, totaling weights of cargo, fuel, freshwater, ballast water, provisions, passengers and crew.) Today’s floating rigs can also drill much deeper, with wells reaching 40,000 ft in depth. (This is the depth of the well, not the water depth, which is a separate measure.) Hoisting systems must handle loads in excess of 2 million lb to run and pull the marine riser and BOP stack. Subsea BOP stacks are generally rated for 15,000 psi, can weigh more than 600,000 lb, and are well over 40 ft tall. Marine riser tension systems to structurally support the riser with proper drilling angles might require pulls beyond 4 million lb. Another complicating factor for offshore operations is the variable met-ocean environment (winds, waves and currents), which impact the motions of the MODU. Met-ocean conditions can add significant loads to the stationkeeping

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system, whether moored or DP, and complicate supplying the rig with expendables. Weather can also be problematic. Arctic conditions can cause ice loading, and icebergs can force rig moves. Spreadmoored MODUs are often temporarily abandoned for safety while a hurricane or cyclone passes. DP vessels, however, can often move away from storms. The North Sea, Gulf of Mexico, eastern Canada and the west coast of Australia can suffer some of the most severe met-ocean conditions for MODU operations. Even in good weather, supplying the floater, usually far offshore, can be a challenge because of lengthy boat and helicopter transit times. Foul weather further complicates water and air transportation, especially for loading or offloading supply boats in rough seas. Because of the impacts of distance and met-ocean conditions, offshore wells typically take longer to drill and in some cases to complete than onshore wells of similar types. Another complication in floating drilling is reduced fracture gradient, the level at which drilling fluids crack the rock and flow into the formation. This is because the confining pressure of the rock, acting as a barrier to fluid inflow, represents a combination of not only the rock, but the weight of seawater acting on the sea floor. For example, a 10,000-ft well in 5,000-ft water depth has a confining pressure composed of the weight of 5,000 ft of rock and 5,000 ft of water. Conversely, a 10,000-ft onshore well has a confining pressure composed of the weight of 10,000 ft of rock only; thus the well in 5,000 ft water depth has a lower fracture gradient. The deeper the water and the higher the mud weight needed to control formation pressures in the well, the greater the likelihood of fracturing the formation, resulting in a wellbore stability and/or a well control issue. In conventional (i.e., non-managed pressure drilling or non-MPD) drilling operations, the only solution to low fracture gradients is to run more casing in the well to cover weaker zones. Because of reduced fracture gradients, it is not uncommon in deepwater wells to need 7-9 different casing strings to drill the same depth for which an onshore well might require only 3- 4 casing strings. “Subsalt” drilling is a further complication in deepwater. Such wells are drilled through thick salt lenses, often into unknown pressure gradients below the salt. Abnormal pressures are common in deepwater drilling, especially in the Gulf of Mexico, and the combination of high pressure and high temperatures (HPHT) in the wells increase the difficulty in drilling safely and successfully. These severe environments, abnormal pressures, ultra-deepwater penetration wells, and potentially long supply lines in remote areas require enormous equipment, from the supply boats to the MODU to helicopters. This amplifies

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the need for very capable stationkeeping systems on large vessels that must hoist and rotate extremely large loads. The potential to lose location, which is more a concern for DP than moored MODUs, requires emergency planning and rehearsals/drills to be prepared to prevent well control or vessel problems. Another big difference between onshore and MODU operations is the number of people on the drilling unit. Depending on the operation, a MODU may have over 200 crew and personnel aboard. Besides the drilling crew, this includes marine crew and a host of specialists responsible for rig maintenance and operation. In addition, third-party service personnel stay aboard the vessel for long periods, because of the cost and difficulty of moving personnel to and from the rig. As a result, newer MODUs will have a very large accommodation facility, with over 250 bunks in predominantly 2-person rooms. Most of the equipment on a MODU is very specialized and expensive, and crews must be trained to use it safely and efficiently. Operations are 24 hours a day, and planning ahead is one of the keys to a successfully drilled well. Teamwork and good communications are essential for the drilling crews, specialists, and marine personnel to have a smooth, safe, and efficient operation. The remainder of this chapter will discuss the unique features of floating drilling equipment and floating drilling operations, with emphasis on special operations and emergency procedures. Obviously, many drilling operations are common to floating, bottom-founded and land drilling. This chapter and future updates will focus on special aspects of such operations for floaters. The IADC Drilling Manual, 12th edition, covers nearly all drilling operations, many of which are interesting and relevant to those specializing in floating operations. The print version of the IADC Drilling Manual includes all chapters. Please refer to www.IADC.org/ebookstore to peruse all IADC ebooks.

Environment and safety

While the mechanics of drilling a well are very similar for floating, bottom-founded and onshore operations, the potential safety and environmental consequences of an incident offshore, especially in deepwater, make a critical difference. Several environmental and safety risk considerations unique to floating operations are discussed in this section. While the risk-mitigation efforts identified in this section are also recommended for onshore drilling operations, the larger consequences of an incident over water has resulted in increased scrutiny and regulation of all floating drilling operations by industry, regulatory authorities, communities and other stakeholders. In general, the consequences of an incident during floating

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FLOATING DRILLING EQUIPMENT AND OPERATIONS drilling operations include environmental damage from a spill that reaches the water or, in the event of any injury, delays in medical response and/or evacuation back to shore. The offshore response to environmental and safety incidents poses logistical challenges and requires supplemental resources not typically relevant to land drilling operations. These challenges translate into increased consequence and risk. (It’s important to note that MODUs include an onboard medical clinic to conduct triage for major injuries and to treat minor injuries. Most offshore locations have a qualified emergency medical technician [EMT] on board at all times.)

Environmental impact assessment

Several proactive steps are typically taken to mitigate the increased risks of offshore operations. One of these proactive measures is an environmental impact assessment (EIA), a process for evaluating the likelihood that the environment may be impacted as a result of exposure to one or more environmental stressors, such as chemicals, oil, noise, or just the physical presence of a MODU in the water. One key environmental concern that every EIA will address is the possibility of a spill. The EIA will include spill trajectory modeling to simulate how and where a spill might spread in the water. Depending on the likelihood and severity of a consequence, the EIA might result in modifications to offshore operating procedures, such as avoiding operations during certain periods of time or increased environmental mitigation measures. When warranted, the EIA documentation will include an environmental mitigation plan. All analyses in the EIA are compiled and submitted to regulatory authorities and shared with communities and other stakeholders to obtain permission for the floating operation to take place. Once approval to drill is granted, the mitigation measures identified in the EIA are implemented. These measures could include increased monitoring, operational delays, or detailed response planning. For example, if floating drilling operations are proposed in an area with endangered aquatic species or within the migration path of such species, certain restrictions to the drilling operation could be imposed, such as transport of drill cuttings to shore, rather than disposal at sea, or increased frequency of inspections for leaks or spills. The EIA will identify spill response resources that are required onboard the MODU should a spill occur; it may also require the staging of additional spill response resources close to shorelines to reduce spill-response time.

Shallow hazard assessment

Another proactive step typically taken to mitigate the increased risks of offshore operations is a shallow hazard assessment, which will examine the risks that might be imposed on the operation by sea floor conditions, as well

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as the geological formations in the shallow portions of the well. Sea floor risks include obstructions, such as marine organisms (e.g., tube worms) and subsea infrastructure (e.g., pipelines), and geographic issues, such as sea floor mountains and boulders. The geologic portion of the shallow hazard assessment will analyze the likelihood that the proposed wellbore will encounter shallow flows of water or gas.

Job safety analysis

Hazard assessments are also conducted for offshore safety concerns. Safety cases identify the hazards and risks of various operations, and then document how the risk is controlled and the safety management system in place to ensure the controls are effectively and consistently applied. Job safety analyses (JSA) are completed for all job tasks. A JSA is a risk-assessment process that helps integrate accepted safety and health principles and practices into all tasks necessary for an operation. The JSA is conducted before starting an operation, and identifies potential hazards for each step of the task, while recommending the safest way to do the job. A JSA is drafted or reviewed by those involved in completing the task. The goal is to ensure that actions designed to reduce risks as low as reasonably practicable (ALARP) are clearly understood and followed by the workforce to avoid an incident. Specialized or non-routine operations might employ further effort, such as a review of any potential dropped objects during an operation.

Simultaneous operations plans

Simultaneous operations plans (SIMOPs) are developed to consider additional risks that occur when two work activities are being done at the same time within close proximity to one another. Communication of SIMOPs risks and hazards during floating drilling operations is required. Well-defined communication protocols are followed to ensure everyone onboard the MODU is aware and alert.

Safety training and drills

Workers in an offshore environment require specialized training, not only for the technical aspects of the job, but also for the increased risks that exist there. This specialized training is closely monitored and tracked to ensure the physical capabilities of the workforce as well as their awareness of the additional environmental and safety risks in the offshore environment. Because medical treatment can be more difficult, given the remote nature of floating drilling operations, training and health education are also closely scrutinized to avoid incidents. As mentioned earlier, medical clinics with a certified EMT are standard aboard MODUs. Safety plans and drills are conducted frequently offshore to ensure the workforce understands how to respond to emergencies and how and when to evacuate a MODU. Life-

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FLOATING DRILLING EQUIPMENT AND OPERATIONS react differently to a given environment and must compensate for the resulting vessel motions of heave, pitch, and roll. This requires unique equipment and procedures to carry out drilling operations safely and economically. For example, the vessel must account for the constant change in vertical distance between the rig and the ocean floor caused by tides and heave. Various types of vertical motion compensation equipment are used to maintain a constant weight on the drill bit and to maintain the riser pipe connection between the rig and the BOP stack on the sea floor. As another example, vessel pitch and roll require special handling and securing of equipment to ensure that loads remain in control.

Figure FD-2: Semisubmersibles are characterized by an upper-hull structure supported on vertical columns connected to submerged lower hulls providing buoyancy for the rig. Courtesy Ensco plc. boats are maintained to ensure personnel are able to escape should a significant incident occur. Transportation logistics for floating drilling operations introduces other safety challenges. A variety of marine operations such as materials supply, rig towing, and rig mooring may be required, all of which have their own inherent risks. In addition, the workforce must be transported by boat or helicopter, both of which have safety requirements and regulations that must be followed, increasing the training required of an offshore workforce.

Conclusion

Despite the emphasis on safety and the environment, several catastrophic incidents have occurred in floating drilling operations. Analyses of incident lessons learned from these catastrophes have resulted in industry improvements in avoidance of incidents through detailed hazard analysis, increased understanding of risk potential, improved engineering and technology advancements as well as a more stringent requirements to operate. All of these efforts towards improved safety in floating drilling operations have significantly reduced the frequency of incident occurrences despite increased levels of such operations.

MODU floating equipment Types of floating MODUs

Floating MODUs come in a variety of configurations, from simple drill barges to the most complex ultra-deepwater drillships. The common denominator for floating rigs is that they are all acted upon by the environmental forces of wind, wave, and offshore currents. Consequently, floaters require different equipment from that used in drilling a well from a stationary or bottom-founded unit. Each MODU type will

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Floating MODU designs have evolved to minimize vessel motions, and the unique motion compensation equipment used on these vessels have evolved as well.

Semisubmersibles

Another type of offshore drilling vessel is the semisubmersible, characterized by an upper hull structure supported on vertical columns connected to submerged lower hulls providing buoyancy for the rig (Figure FD-2). The upper hull structure supports the rig’s drilling equipment. While the most common semisubmersible configuration is a rectangular upper deck supported by two elongated pontoons, there are a number of other configurations currently in operation, such as triangular shapes with three submerged buoyancy pontoons and pentagonal vessels with five pontoons. Pontoon shapes also vary across the industry. For example, some rigs have torpedo-shaped pontoons, while others have rectangular cross-sections. The size, number and configuration of semisubmersible support columns also vary as much as the configuration of the lower pontoons. Until recently, stationkeeping for most semisubmersibles was based on an 8-point fixed-mooring system. Some moored semis equipped with self-propulsion use their thrusters for fixed-mooring assist (to relieve high loading on the leading mooring lines). Today, many of the newer semis have fully dynamically positioned stationkeeping systems. Semisubmersibles generally have better weather operating envelopes than other types of floating MODUs. Semisubmersible rigs have superior motions characteristics, compared to ship-shaped or barge-shaped rigs, because their smaller water plane areas (the area of the columns supporting the upper deck structure) result in proportionally smaller vessel heave. Semisubmersibles with a fixed mooring configuration also experience less pitch and roll when the prevailing weather shifts than a ship or barge-shaped hull. While semisubmersibles have superior motion character-

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Ultra-deepwater drillships

As floating drilling moved into deeper waters, the size of the MODUs increased. Ultra-deep water depths (7,500 ft and beyond) and deeper overall well depths led to higher derrick and riser loads and the need for more storage and deck-load capacity. As a result, ultra-deep water MODUs now need a derrick capacity approaching 3 million lb, riser tensioning capacity of 4 million lb, and variable deck-load capacity in excess of 20,000 short tons. In nearly all cases, this combination of equipment and storage capacity dictates the use of a drillship-type configuration to carry these large loads. And, because of the impracticality of mooring in ultra-deepwater, these drillships are exclusively dynamically positioned to maintain station over the wellsite. Besides larger vessels and equipment load capacities, other innovations that have further enabled ultra-deepwater drilling include a secondary load path to increase efficiency of running tubulars and equipment to the ocean floor, and multiple moonpools or false moonpools to decrease the vessel’s water-plane area and reduce heave response. Figure FD-3: Drillships are self-propelled ship-shaped drilling vessels, with an opening in the middle (called a “moonpool”) through which the drilling operation takes place. Courtesy Atwood Oceanics Inc. istics, they generally have less deck-loading capability than other floating MODUs.

Drillships

Drillships are self-propelled ship-shaped drilling vessels, with an opening in the middle (called a “moonpool”) through which the drilling operation takes place (Figure FD-3). Stationkeeping for early drillship configurations used traditional 8-point fixed mooring systems, which yield good longitudinal stability when the bow of the vessel is pointed into the prevailing weather, but poor stability when the weather shifts to the beam of the vessel. Moored drillships thus had high operational downtime due to vessel motions when the weather shifted away from the “optimal” direction. To overcome this operational limitation, all drillships built during the past 20-plus years utilize dynamic-positioning stationkeeping systems, which rotate the ship’s bow into the changing weather and improve the rig’s weather-related motions. Regardless of their stationkeeping system, drillships still have greater heave and roll motions for a given environment than a semisubmersible, because of their larger water plane area. One significant advantage of drillships over semisubmersibles is their superior deck-loading capabilities. This higher deck-loading capacity, combined with self-propulsion, make drillships the vessel of choice for drilling remote offshore locations, where resupply of equipment and materials is difficult.

IADC Drilling Manual

Figure FD-4: Lattice boom cranes are a major deck crane aboard floating MODUs. Courtesy Noble Corp.

Figure FD-5: Pedestal-mounted knuckle boom cranes are important equipment aboard floating MODUs. Courtesy Noble Corp.

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Figure FD-6: The king post crane features a bearing assembly on its top and bottom to keep the crane aligned. Courtesy Noble Corp.

Deck cranes and lifting systems

Many types of deck cranes and lifting systems are used on semisubmersibles and drillships and they are essential to the operation of the MODU. They are used for transferring cargo, equipment, and material to and from work boats alongside and from place to place on the MODU. Some cranes are also used for transferring subsea equipment to and from the sea floor. Some can also be used to transfer personnel to and from the MODU. The two major types of deck cranes in use are pedestal-mounted lattice boom cranes and the pedestal-mounted knuckle boom crane (Figure FD-4 and FD-5). These cranes make use of a slew bearing to connect the stationary pedestal to the rotating (slewing) structure of the crane. They can be all-electric, electro-hydraulic, or diesel-hydraulic driven, with capacities ranging from a few tons to 200 tons or more. The hoists of the electric-drive crane are driven by electric motors supplied from larger electric motors or variable frequency drives (VFDs) powered from the rig’s main switchboards. The hoists of the electro-hydraulic crane are driven by hydraulic motors powered by hydraulic pumps that in turn are driven by electric motors powered from the rig’s main generators. The lifting function of the knuckle boom crane uses hydraulic cylinders to raise and lower the knuckle and main boom. The hoists of the diesel-electric crane are driven by hydraulic motors powered by hydraulic pumps that are driven by a diesel engine. Lattice boom and knuckle boom cranes can be configured with such features as active heave compensation capability, constant tension capability, automatic and manual overload protection systems, and emergency load lowering capability, and can be certified for personnel handling. Knuckle boom cranes can also be equipped with hydraulically operated pipe handling and riser handling yokes. Another type of deck crane in use is the king post lattice

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Figure FD-7: Gantry cranes are used for lifting and moving riser joints and other tubulars and various subsea equipment. Courtesy Noble Corp. boom crane (Figure FD-6). King post cranes provide similar functions as the slew-bearing cranes. However, rather than the upper portion of the crane being supported on a slew bearing, the crane is suspended and supported from a king post. The king post features a bearing assembly on its top and bottom to keep the crane aligned. These cranes are usually all-electric or diesel-hydraulic driven, with capacities ranging from a few tons to 200 tons or more. These cranes can include such features as automatic and manual overload protection systems, and emergency load lowering capability and can be certified for personnel handling. The safe working load (SWL), sometimes referred to as the working load limit (WLL), of a pedestal or king post crane is determined by the designed strength of the crane and its load-bearing parts, boom angle (or angles for a knuckle boom crane), distance of the load from the centerline of the crane, and sea conditions. Crane operations are also limited by wind speed. The SWL or WLL is provided on a load chart maintained at the operating station for the crane. Load charts are calculated for onboard and off-board lifts, taking into consideration static load, which is the weight of a load unaffected by external forces, and the dynamic load, a load subject to dynamic forces, such as going through the splash zone when in water, wind, vessel motions, etc. Several special-purpose cranes are employed on MODUs. Gantry cranes (Figure FD-7) are used for lifting and moving riser joints and other tubulars and various subsea equipment including the LMRPs and Christmas trees. They are usually electro-hydraulically controlled and operate through a rack and pinion drive forward to aft or port to starboard on the vessel on a track system. They include a gantry section with trolleys and independently controlled hoists that can be positioned to move various loads. Depending on the operation, the hoists can also be synchronized to operate together. The hoists can be equipped with hooks or can support a lifting

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FLOATING DRILLING EQUIPMENT AND OPERATIONS yoke. Operation of the crane may be from an operator’s cab, a pendant or a radio control console. Overhead bridge cranes are frequently used to move equipment inside spaces within the MODU. These are usually electrically powered and travel on an overhead track system through a rack and pinion drive. They will have one or more hoists with a hook for attaching the load or may use an electro magnet system for attaching the load. A pendant or radio control console is usually provided for operation. Some smaller knuckle boom cranes are used for handling small loads or positioning work baskets. These are usually electro-hydraulically operated from either a control station near the crane or by controls inside the basket. Maintenance jibs, chain hoists, wire rope hoists and comealongs are positioned in various locations throughout the MODU for use during maintenance activities and are usually manually operated with some hoists being electrically or pneumatically operated.

Power generation and electrical systems Safety considerations

When working with high-voltage (HV) equipment, all personnel must be trained, proper PPE must be worn, and every precaution taken. At a minimum, special “flash” suits must be worn and a grounding rod used when opening an HV compartment. No work should ever proceed without another two people present. Depending on the system, there are interlocks in place to prevent a compartment from opening without the system being de-energized; however, stored energy or induced voltage can still be present. Conduct a Job Safety Analysis (JSA) before conducting any maintenance or other work on HV equipment.

Power generation

With the modernization of equipment controls used in drilling comes automated systems controlled with smart devices. About 10 years ago, if an engine was powered manually and successfully started with automatic controls, it was considered an advanced system. At present, most MODUs are designed for minimal human-machine interaction. More companies have elected to generate a higher voltage main buss as a standard. In the past it was normally a 600volt AC (vac) main buss. Today there are different voltages generated. Currently, the most common voltages generated are 11 kv. 6.6 kv and 13.8 kv. Technically these rank as medium voltage. Our industry, however, refers to these as high voltage, and they should be treated as such. This concept facilitates running smaller cable from generator to the main buss, which can be distributed around the rig more easily with smaller ampere-rated breakers and cables.

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FD-7

However, eventually the voltage must be transformed back down to a more common usable lower voltage, which is 480 vac and 690 vac. This requires a very large transformer, so any loss in the cable is gained back in the transformer. These lower voltages are more useful at 480 vac, which is used on the auxiliary equipment. Most motor control centers (MCCs) use 480 vac as the primary voltage to eventually run the pumps/motors for various equipment. 690 vac will be used primarily for powering an AC drive, the industry having generally moved away from DC drives. Of course, the lighting distribution has not changed much in voltage, although some installations appear to be adding LED lighting. There are numerous great features with LEDs, and this trend will likely continue to grow in the drilling industry.

Configuration

Currently, most dynamically positioned vessels are built to either DP2 or DP3 class. (DP2 requires a vessel not lose location following a single failure of an active component or system. DP3 incorporates DP2 requirements, as well as static components and all components and systems in any one watertight compartment that could fail from fire or flooding of any single compartment. See separate section in this chapter discussing dynamic positioning.) The requirements for these classifications rely mainly on the amount of redundancy critical equipment must have. For example, the main buss for a DP2-class vessel must comprise two sections, with each located in a separate compartment. The buss can be split, comprising four sections total. A DP3 class requires the same configuration; however, the two main sections must have a separate means of combining. This is sometimes called a “ring buss” configuration. All critical equipment control systems with virtual memory or PLCs attached, will also have a secondary controls system and a battery storage/UPS system powering the system. For example, for the DP system, there will be a main control system powered by UPS with a battery bank located on the bridge and a secondary control system normally located in the engine control room (ECR). The secondary control system will be powered by a UPS system as well. Theoretically, if an issue occurs with the main control system on the bridge, control of the vessel can be sent to the ECR until the issue is resolved. In practice, however, this would be very difficult to achieve. It is most likely not rehearsed enough to be effective. On most vessels, all visibility to the outside environment is lost at this point, so this procedure would require special instructions and communications with the captain and the crew. The vessel will also have a minimum of two separate engine rooms and a single ECR. The redundancy for the ECR is usually the bridge. Although not ideal, it is more realistic to move the ECR to the bridge than it is to move the bridge to the ECR during an emergency.

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FD-8

FLOATING DRILLING EQUIPMENT AND OPERATIONS

Management systems

Most vessels today have a VMS (vessel management system, PMS (power management system), and/or AMS (alarm management system). The PMS tends to be the brains for power generation and can control drilling operations as well. The system can decide whether to intervene in drilling operations. When all settings are properly established and in normal circumstances, an engine can start automatically, allowing time for engine warm up. Once the engine is ready, it will run up to operating speed, and close the breaker to put the generator on line. The VMS accomplishes this by sending commands and awaiting feedback from other systems on the same network. When a series of engines meet a certain load demand for a set period, the VMS will launch this sequence using PMS information until load demand is within an acceptable range. If the load demand has reached a certain level, and no more engines remain to come on line, the PMS will send a command to the drilling bays to slow down or “phase back” their operation until power demand is brought down to an acceptable range. This is common on vessels with thrusters when current or wind is considered abnormally high. Eddy currents exist in some locations, complicating stationkeeping. In this situation, the PMS will work to ensure that the thrusters have enough power to maintain location, even if drilling operations must shut down. If the vessel lacks a PMS, power-demand monitoring runs locally in the generator controls. The AMS can monitor engines as well. If an engine encounters an alarm condition, the AMS will report this to the VMS and in turn start another engine. Once the additional engine is on line, the alarmed engine will power down. Precisely when the engine powers down depends on the alarm condition. In some cases, the engine might be powered down or e-stop prior to another engine coming on-line.

Redundancy and emergency power

Power is distributed to enable equipment power up in multiple areas around the vessel, including thrusters, MCCs, lighting, battery power, and any other devices or equipment requiring power. Depending on the vessel classification, there might be redundancy in powering the equipment. Distribution systems that power critical equipment might require a secondary feeder for powering that same equipment. For example, MCCs on a DP2- or DP3-rated vessel with feed thrusters will have two means for power up, a normal and an alternate source. These feeders eventually come from different sections of the two main switchboards, should one section be lost. Critical equipment, such as the MCC referenced above, will have devices installed to determine whether normal power is lost, then automatically switching the system over to alternate power.

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Vessels such as these are designed to not lose all power or “black out”. If a section is lost, the system will identify this immediately and provide an alternative means to power the section. The alternative means can depend on what the original problem was. The main buss is designed to automatically isolate any issues; however, in some cases it can lose a section or the entire main buss. If a section is lost, this is referred to as a partial black out. If both main switchboards are lost (black-out condition), the emergency generator will come on quickly, supplying enough power to keep emergency systems running and to power the UPS systems. While the emergency generator is going on line, a main engine will also start and prepare to go on line, if there was an engine in standby mode before power was lost. The main engines will continue to come up until the vessel has reached its last normal condition, i.e., powering the equipment running prior to the blackout minus some auxiliary equipment. If the issue that caused the black out occurred on the main buss or the engine that was running at the time, that equipment will not attempt to start . However, the Golden Rule is that all batteries and UPS systems must be maintained and operating to have a successful blackout recovery or successful abandon vessel shutdown (AVS/ ESD-0) recovery. Black-out recoveries differ from AVS/ESD-0 recoveries. During a black-out recovery, the emergency generator (e-gen) can come on line, but when an AVS situation occurs, the emergency generator is in a locked-out state until the AVS pushbutton is back to normal. At this point, the system will recover as if a black-out situation occurred. However, during an AVS, if the UPS system for the AVS control processor is not working properly, the rig will stay blacked out with no equipment running until the maintenance team determines which AVS circuit to jumper out to get the e-gen to start. This could take five minutes or six hours, depending on the maintenance crew’s familiarity with the system. During this time, if the batteries totally discharge to other systems, problems will keep compounding. This is not a good scenario, especially during certain rig operations or if close to another structure. The UPS system is now more important than ever and must stay maintained, including batteries. Tests of the UPS system should be conducted at least annually and preferably as often as practical to ensure crew familiarity with the system. Activating the ESD system will ensure the safest possible condition of the rig and its equipment to minimize the consequences of an emergency situation related to uncontrolled releases of hydrocarbons or an outbreak of fire. The ESD system is used to provide a safe and rapid shutdown of systems and equipment.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

FD-9

Audible ECR Matrix panel

Visual ECR Matrix panel

Audible DCC Matrix panel (2)

Visual DCC Matrix panel (2)

Audible alarm accommodation

Visual alarm accommodation

X

X

X

X

X

X

X

X

Manual – Other Areas

X

X

X

X

X

X

X

X

X

X

Smoke/Thermal - Quarters

X

X

X

X

X

X

X

X

X

X

Smoke/Thermal/Flame– Other Areas

X

X

X

X

X

X

X

X

X

X

Explanations:

C

X

X

X

X

C C

C

C

C

Visual alarm all areas (1)

Visual Nav Bridge Matrix panel

X

Audible alarm all areas (1)

Audible Nav Bridge Matrix panel

X

Visual alarm control spaces

Visual alarm DCC Operator Consoles (2)

X

Audible alarm control spaces

Audible alarm DCC Operator Consoles (2)

X

ê Cause

Visual alarm machinery

Visual alarm VMS

Manual - Quarters

Effect è

Audible alarm machinery

Audible alarm VMS

Table FD-1: Fire alarm cause and effect

X

X

X

X

X = single actions. (single detector or manual station) C = confirmed. (more than one detector)

Note 1: Alarm in all areas if alarm not acknowledged within 2 minutes (ABS SVR 4-7-3/11.1.4). Note 2: May be made inactive by Chief or Captain by a password protected VDU function.

Fire, safety, and monitoring

Most MODUs will have an AMS (alarm management system) that monitors every aspect of the vessel via fire-detection systems, gas-detection systems, and other safety systems. These systems report back to the AMS and, depending on what the alarms are, the VMS can send commands to isolate the issue. For example, infrared detectors or smoke detectors are installed in every machinery space, along with a pull station. The size of the room determines the number of detectors, but at least two sensors will be placed in most, if not all machinery spaces. Most cause and effect (C&E) matrix set-ups will ensure that if a sensor indicates a fire on board a vessel, an alarm will sound locally in the Control Room (Table FD-1). In most cases, if a local alarm is not acknowledged within a certain period of time, the system will sound a vessel-wide alarm. After a set amount of time, if equipped, the VMS system can set off the fire-suppression system in that compartment. However, if two sensors are indicating a problem in the same compartment, in most cases, the system provides little acknowledgment time before activating the fire-suppression system.

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See Tables FD-2 and FD-3 for cause and effect for gas alarms and a general emergency action plan, respectively. As one can see, the AMS in combination with the VMS is a very powerful tool. Vessels might have several anti-fire systems — sprinklers, deluge, water mist, and/or foam — that can be operated manually or in some cases automatically. Ventilation will be shut down in most areas, fire dampeners will close, water-tight doors will close (thruster areas), and the helicopter wave-off light will come on. This particular matrix example calls for power to be shut down if certain conditions are met. However, management should take precautions against electrical power tripped automatically until it’s certain that vital firefighting equipment will not be down while it’s expected to operate during the emergency.

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FD-10

FLOATING DRILLING EQUIPMENT AND OPERATIONS

Audible alarm DCC Operator Consoles

Visual alarm DCC Operator Consoles

Audible Nav Bridge Matrix panel

Visual Nav Bridge Matrix panel

Audible ECR Matrix panel

Visual ECR Matrix panel

Audible DCC Matrix panel

Visual DCC Matrix panel

Audible alarm all areas

Visual alarm all areas

Audible alarm all areas except quarters

Visual alarm all areas except quarters

Audible alarm all areas except quarters

Visual alarm all areas except quarters

X

X

X

X

X

X

X

X

X

X

X

X

Comb. High 40%LELQuarter Intakes

X

X

X

X

X

X

X

X

X

X

Comb. Low 20%LEL-non. haz.areas

X

X

X

X

X

X

X

X

X

X

X

X

Comb. Low 20%LEL-haz. areas

X

X

X

X

X

X

X

X

X

X

X

X

Comb. High 40%LEL-non. haz.areas

X

X

X

X

X

X

X

X

X

X

X

X

Comb. High 40%LEL-haz. areas

X

X

X

X

X

X

X

X

X

X

X

X

Toxic Low 10ppm-Quarters Intakes

X

X

X

X

X

X

X

X

X

X

Toxic High 20ppm-Quarters Intakes

X

X

X

X

X

X

X

X

X

X

Toxic Low 10ppm-Other Areas

X

X

X

X

X

X

X

X

X

X

Toxic High 20ppm-Other Areas

X

X

X

X

X

X

X

X

X

X

X

X

ê Cause

Explanations:

X = single actions. (single detector or manual station) C = confirmed. (more than one detector)

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X

Visual alarm all areas

Visual alarm VMS Consoles

Comb. Low 20%LELQuarter Intakes

Effect è

Audible alarm all areas

Audible alarm VMS Consoles

Table FD-2: Gas alarm cause and effect

X

X

X X

X X

X

FLOATING DRILLING EQUIPMENT AND OPERATIONS

X

X

X

X

Manual alarm call point – Quarters

X

X

X

C

Manual alarm call point – Other Areas

X

X

X

C

C X

Smoke/Thermal - Quarters Smoke in quarters inlet

X

X

Fire – Other Areas

C

C

Manual fire damper closure – Quarters

X

X

Combustible Low – Quarters Intakes

X

Combustible High – Quarters Intakes

X

Combustible Low – Other Areas

X

Combustible High – Other Areas

X

Toxic Low – Quarters Intakes Toxic High – Quarters Intakes

Explanations:

X

C C

X

C

C

X X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X = single actions. (single detector or manual station) C = confirmed. (more than one detector)

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X

Trip electrical equipment

Stop ventilation fans

Fire fighting released

ê Cause

Activate helideck warning

Close fire dampers

Activate fire fighting

Stop air handlers

Effect è

Close Watertight sliding doors

Table FD-3: Action plan for emergency situations

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FD-11

FD-12

FLOATING DRILLING EQUIPMENT AND OPERATIONS

Mooring systems and equipment Types of offshore mooring systems

Offshore mooring systems for Mobile Floating Units (MFUs), such as MODUs, TADs and flotels, comprise individual mooring line(s) for vessel stationkeeping. Eight is the most common number of lines, followed by twelve. Offshore mooring systems can be classified by the arrangement of the mooring lines when examined from an overhead (plan) view, as “spread” (equal angle between all lines) for omni-directional environmental loading or “cluster” (unequal angles) to favor a predominate environmental force direction or avoid infrastructure. Spread moorings are preferred, but require locations with less subsea infrastructure, e.g., wellheads, pipelines, manifolds, etc. There are three types of MFU mooring systems, when classified by the type of their line components:

Catenary moorings (conventional, steel, poly-insert)

The catenary type is the most prevalent offshore mooring system, primarily because most MODUs have self-contained moorings of wire and/or chain (Figure FD-8). This mooring system has grounded components at both survival and operating tensions. A catenary mooring system typically employs either all chain for shallower water depths (below 2,000-ft water depth), a combination of wire rope and chain for deeper water (less than 5,000 ft, with some exceptions), or a combination of polyester or high-modulus polyethylene (HMPE) rope with wire rope and/or chain, which works beyond 7,500-ft water depth. The water-depth limitation of catenary-mooring systems is controlled by the weight of the system, which reduces the horizontal restoring component, and deployment and operational requirements. Deployment and operational requirements increase costs relative to taut or semi-taut mooring systems as water depth increases. Care must be taken with this type of mooring system around subsea infrastructure, because of the significant amount of grounded mooring components. The use of polyester or HMPE can help mitigate the risk of potential damage to subsea assets. Catenary moorings can be installed by the preset method (to be discussed later), similar to the taut and semi-taut systems, or by the conventional installation method. These systems generally use high holding capacity (HHC) drag embedment anchors that require a near-horizontal mooring line pull at the seabed.

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Semi-taut moorings (steel, steel-polyester, steelHMPE)

Semi-taut mooring line(s) have grounded components at survival tensions, but none at the anchor location for maximum design tensions (operating, hurricane, cyclone, etc.). The semi-taut system typically consists of the MODU wire rope and/or chain at the fairlead and significant preset components (not self-contained MODU components), such as insert wire rope or polyester, subsea buoyancy, etc., all used with anchors that are capable of high-uplift loading (e.g., pile or vertical-loaded anchor [VLA]). This system is typically limited to use in moderately deepwater of approximately 3,000 ft to 6,000 ft (approximately 900 m to 1,800 m), because of operational and survival limitations imposed by the mooring system. This mooring system poses less danger to subsea infrastructure, thanks to the reduced amount of grounded mooring components over a conventional system.

Taut moorings (steel, steel-polyester, steel-HMPE)

Taut-mooring systems have no mooring line grounded component at survival or operating tensions. The system typically consists of rig wire or chain at the fairlead and significant preset components (not self-contained MODU components), such as insert wire rope, subsea buoyancy, polyester rope, HMPE and an anchor capable of high-uplift loading (e.g., pile or VLA). Taut moorings are used in a much wider range of depths, and are typically used in shallower water (approximately 500 ft) to avoid subsea assets and deeper waters (beyond 10,000 ft) to reduce the operational and survival limitations imposed by an all-steel mooring system. This mooring system poses the least danger to subsea infrastructure because the anchor is the only contact point with the sea floor during use.

Offshore mooring line components

Offshore mooring lines primarily contain only a few major component types. In general, the key factors that determine which mooring components are used and their placement are cost, required stationkeeping specifications, desired type of mooring system (taut, catenary, semi-taut), desired mooring line strength or minimum break load (MBL), component resistance to chafing, and MODU variable-deck loading. This section discusses the most widely used mooring components, in order of prevalence.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

8a

FD-13

Conventional catenary mooring (500 ft WD) 1: 3000 ft rig chain 2: High holding capacity drag anchor

1

2

8b Conventional catenary mooring (3,000 ft WD) 1: 5,000 ft rig wire 2: 2,500 ft rig chain 3: High holding capacity drag anchor

1 3

2

8c

Polyester insert catenary mooring (3,000 ft WD)

1

1: 750 ft rig chain 2: 4,000 ft 6.3 in. insert polyester 3: 2,500 ft rig chain 4: High holding capacity drag anchor

2

Figure FD-8a, 8b and 8c: Typical catenary mooring line configurations for MODUs. Courtesy Delmar Systems Inc.

3

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4

FD-14

FLOATING DRILLING EQUIPMENT AND OPERATIONS

Stud Link Chain

•• Comprises individual steel links that are flash welded and heat treated in series to produce continuous lengths; • Chain strength is defined by the Classification Societies ranging from R3, the lowest, up to the highest, R5. The most common is R4 strength;

••

• Anchor chain has superior fatigue characteristics and chafing resistance, when compared to wire rope, because of its weight, a damping effect on shallow water mooring systems and MODU offsets;

••

• Because of its weight, an all-chain mooring line is usually restricted to less than 2,000 ft, depending on the environment. In severe environments it might be reduced to less than 1,000 ft.

Steel wire rope

••

•• ••

•• Consists of smaller steel cables woven together to produce strands that are then woven into larger diameter cable. Most wire ropes comprise 6 strands although some use 8. For mooring lines, the wire rope is usually coated with drawn galvanized coating. • Commonly stored on land on spools/winch drums or wet stored in near-straight lines. Length can be over 15,000 ft and diameters for MODUs up to 3 ¾ in. Inserts (not part of the self-contained MODU system) can be larger in diameter. Shipping, handling and installation can be a major effort, as reels can weigh over 200 metric tons, requiring special care, dock strength and ships. • Wire rope weight is about 75% less per unit length than mooring chain. Its service life depends on handling damage, amount of tension seen during service and the corrosive environment. Average life without severe damage is usually 5-7 years, with some lasting as long as 10 years. Most MODU users change the rope out after a specific time span, such as 5 years.

••

ww If one jacket covers the entire rope core, the rope is said to have closed-braid construction; ww If each sub-rope is individually jacketed or visible in the finished rope, then the rope is said to have open-braid construction. One of the lightest mooring components used in mooring systems, it reduces weight by approximately 95% over studded link chain and some 80% over 6-strand wire rope; Polyester rope diameters are typically about twice that of wire rope for the same breaking strength, requiring significantly larger storage reels than an equivalent minimum-breaking load (MB)L wire rope; When compared to steel components, the high elasticity and low weight of polyester rope allows it to provide superior stationkeeping and storm survival results over other components, when used in an optimized mooring system; Commonly stored on land on spools/winch drums or wet stored in near-straight lines; Polyester rope has excellent fatigue characteristics and can improve the fatigue life of steel components that are connected in-line by reducing the effect of dynamic loads applied to the mooring system; Polyester rope is never part of the MODUs selfcontained system. It is used primarily in deepwater and ultra-deepwater mooring systems in preset operations.

Anchors

There are numerous types of anchors used in offshore moorings, with a large variation in sizes, shapes, installation methods and holding capacities (Figure FD-9). The three main types of anchors are, from most common to least common on MODUs, drag embedment anchors (DEA), driven anchors, and gravity-installed anchors. Each of these three categories, which are based upon the anchor installation method, can further be subdivided into the suitability of the anchor for the design loading conditions, such as “low uplift” catenary mooring systems and “high uplift” taut and semitaut mooring systems, and sea floor conditions (sand, clay, rock, etc.).

Drag embedment anchors

Polyester rope

•• Made of small yarns (or fibers) woven together to produce sub-rope strands, which are woven together to create sub-ropes, which are again woven together to produce a continuous, larger diameter rope (core); •• The bundle of sub-ropes or each individual sub-rope is threaded through a barrier (particle filter) to protect the rope from particle ingress from soil or marine growth, which can cause microscopic tears on the yarn and lead to mooring line failure; •• The rope core and barrier (or sub-ropes and barriers) are then sheathed in a protective cover(s) or jacket(s) that helps prevent tearing of the load-bearing subropes;

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Drag embedment anchors (DEAs) are the most prevalent type of modern anchor used on MODUs and for offshore temporary moorings. All seagoing commercial vessels, including drillships and semisubmersibles, are equipped with a DEA because of their long-documented history (from use on ships and naval vessels to current offshore MODUs), versatility and ease of installation in widely varying soil conditions. All MODUs carry DEAs as part of their mooring equipment. Within the DEA category, there are three main groupings of anchors: •• Conventional DEAs, which are predominantly used on ships and vessels that only use anchors for emergency

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

FD-15

Figure FD-9: Examples of high-holding capacity drag-embedment anchors. Courtesy Delmar Systems Inc. or short duration situations. “Stockless” anchors are a specific type of DEA, so called because they lack long stabilizer bars; •• VLA (vertically loaded anchor) DEAs, which are capable of resisting mooring loads at high uplift angles without significant reductions in capacity and are common on some MODUs; •• HHC (high-holding capacity) DEAs, predominantly used for modern-day MODU and permanent facility offshore mooring systems with low uplift at the anchor (Figure FD-9). All common MODU-sized DEAs are capable of being installed with typical anchor-handling tow-supply (AHTS) vessels without the support of remotely operated vehicles (ROV) or divers. Of the anchor types listed in this section, DEAs generally have the lowest level of anchor-placement accuracy and precision, due to the methods of installation. Their typical weight for MODU use is 9-15 metric tons, averaging 12 metric tons. HHC DEAs are of fabricated construction. The fluke angle can usually be adjusted for hard sandy bottoms at 20°-30° (lowest angle of penetration) up to 50° for soft muddy bottoms. The drag distance to set these anchors is around 100150 ft if successfully embedded. Unfortunately their construction of fabricated steel plate makes them susceptible to damage.

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Driven anchors

Driven anchors, which cannot be dragged into place, are less prevalent than DEAs for MODU moorings due to the increased logistical constraints, typically higher-specification requirements and cost of anchors and installation. Most of these anchors are fabricated with very few cast or forged parts. These anchors are typically high capacity, as they are optimized for specific soil conditions, and allow for a wider range of uplift angles for anchor loading (catenary, semi-taut, and taut mooring systems). They are used on preset mooring installations and are not part of the MODU’s self-contained mooring systems. These anchors can be sorted into the following categories: •• Suction piles (suction caissons), which use a submersible pump to drive the pile into the sea floor by creating a pressure differential between the inside and outside of the pile (Figure FD-10); •• Driven piles, which use a subsea hammer, subsea vibrator, and/or significant deadweight (i.e., follower) that pushes the anchor into the sea floor; •• Driven plate anchors, which use a suction pile or driven pile (i.e., follower) to push the plate anchor into the soil; •• Drilled and grouted piles, which use a subsea drill to create the hole for installing the pile and a submersible pump for applying the cement.

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FD-16

FLOATING DRILLING EQUIPMENT AND OPERATIONS

Figure FD-11: Drum winch. Courtesy Delmar Systems Inc.

Figure FD-10a and 10b: Example of suction piles, a type of driven anchor. Courtesy Delmar Systems Inc.

Gravity-installed anchors

Figure FD-12: Traction winch. Courtesy Delmar Systems Inc.

Gravity-installed anchors are rapidly becoming more popular with both MODU and permanent facility offshore mooring systems, predominantly because of their speed of installation and high-holding capacities. Most of these anchors are fabricated with very few cast or forged parts. These anchors are typically lowered to a predetermined distance above the sea floor, released from the lowering cable, and allowed to free-fall into the soil.

moored condition, but unless the wire rope was on the bottom, 2-3 layers of the drum proper tension at higher layers could not be obtained. During the 1980s-1990s, the traction winch was developed to perform as the tension device. In combination with the drum winch or storage reel, this is now the standard wire-rope MODU mooring system. Besides having band brakes, these winches also incorporate a lock bar that is usually dogged into the winches’ drum flange.

Once again, these anchors are not part of the self-contained MODU mooring systems and are used on preset locations. There are two types of gravity-installed anchors, the torpedo-shaped and the OMNI-Max AnchorTM. Torpedo anchors are typically expendable, because they are non-retrievable .

Traction winches

MODU deck mooring line-handling equipment

MODUs have equipment necessary to deploy and retrieve mooring lines, rack anchors, store chain and wire rope, and sheaves and fairleaders to guide the mooring lines in the proper direction.

Drum winches

Drum winches (Figure FD-11) are primarily used as storage drums on modern MODU mooring systems. In the early days they were also used to tension the wire rope in the

IADC Drilling Manual

Traction winches (Figure FD-12) operate on a principle similar to a block and tackle pulley system. These winches use two parallel drums to gain a mechanical advantage. Wire rope loops around the parallel drums multiple times (usually six), using friction to provide grip. The drum storage winch supplies a minimal amount of tension that is magnified through the traction winch drums, thus tensioning the wire rope while leaving the winch outboard. While more versatile than drum winches, traction winches are typically heavier, require a larger footprint, and cost more. Traction winches can pull at a constant torque, regardless of the amount of wire rope left on the storage take-up reel. Therefore, they are ideal for applications in which short lengths of wire rope must be paid out while maintaining high line tensions and re-

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winching operations.

Auxiliary mooring equipment and hardware

There are numerous types of shackles, connecting links, etc., used to connect the major components of a mooring system, as well as support hardware. Some of the key components are discussed in this section.

Connecting hardware

Figure FD-13: Fairleaders function as a sheave, guiding the wire rope and/or chain from the windlass and/ or traction winch outward and down the mooring line toward the anchor. Courtesy National Oilwell Varco. taining the capability to pay out longer lengths with tension from the storage or drum winch.

Windlasses

Windlasses are used to haul in and/or pay out anchor chain. Figure FD-12 shows a chain windlass attached to the side of the traction winch. The slotted wildcat wheel with whelp located on the windlass assembly must be sized properly for the specific chain type and size to allow for the chain to mesh properly, preventing jumping or skipping. Due to the high tension required, MODU windlasses usually have 7 whelps. The windlass feeds the chain through a hawser pipe assembly before being lowered into a chain locker for storage. Excess chain not used in the mooring system is typically stored on the MODU in a chain locker. Some windlasses are powered by DC traction motors with the capability to pay out chain under high load at low speeds. AC-motor windlasses can do the same thing, provided they have a big enough energy dissipation system. For rapid pay out under control speeds, water brakes that can dissipate significant amounts of horsepower are used. Along with the band brakes, windlasses usually have a remotely activated chain stopper or lock that can be released under full load.

Fairleaders

Fairleaders (Figure FD-13), also called “fairleads”, function as a sheave, guiding the wire rope and/or chain from the windlass and/or traction winch outward and down the mooring line toward the anchor. Fairleaders used for chain must be pocketed and sized appropriately for the type and size of the chain and also the wire rope used. MODU fairleaders typically swivel along the vertical axis, allowing the angle between mooring lines to be modified horizontally, as necessary, to a limited degree. Care must be taken to avoid jumping the mooring component off of the fairlead during

IADC Drilling Manual

This encompasses all equipment used in-line between two mooring components (e.g., a wire rope and a section of chain). These items are usually taken apart and assembled on the deck of the installation vessel (e.g., anchor-handling/ tow/supply vessel [AHTS]). Some of these items, such as connecting links, are used only to connect mooring components into a contiguous line, while others, such as a bearing or friction swivel, are used to free torque from a mooring line. Almost all connecting hardware are deemed as “chain accessories” by class societies, requiring their material grades to be comparable to those of chain.

»» Common chain connecting links

There are two types of common chain connecting links – C-Type and Kenter, with the latter the most common. These links are built to go through the wildcat of the windlass in the horizontal and vertical position without jamming or causing damage to any of the equipment. They are manufactured to be disassembled such that when reassembled they connect two equally sized chain lengths. In general, these links do not have the fatigue durability of a common link, so they are used as sparingly as possible.

»» Pear links

These connectors are used to connect two different sizes of chain and thus have the appearance of a pear. They are often used at or near the anchor. Since there are two different sizes of chain, they are not designed to pass through any of the MODU’s deck equipment.

»» Assorted shackles

Numerous types, shapes, weights and strengths of shackles exist, with names that generally describe their appearance. They are used to connect chain, wire rope, anchors, workwire lines, chain chasers, permanent pendantless systems and so on. Most common are the “U” shackle, “D” shackle, elongated “U” shackle, and “bow” shackles, similar to what is used on the drill floor, deck cranes around the MODU and air hoists. The difference is these shackles are generally of higher quality, strength and certification. None of this hardware is designed to pass through the windless wildcats, fairleaders, traction winches or store reels.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

»» Swivels

Swivels used in modern mooring systems are generally placed between the mooring chain and mooring wire-rope connection. They are used to relieve torque in the wire rope at very low tensions. At high tension they are designed to lock to prevent the wire rope from un-torquing and creating a “bird nest”. These type of swivels are intricately machined designs with self-lubricating bearings and close tolerances. Other less-sophisticated swivels are used in the pendantless system, work wires and other handling hookups.

»» Quick-release devices

Pelican hooks are the most common quick-release devices used to release two components under moderate to high tensions. They are generally not used on MODUs, but on the AHTS to release anchors and mooring lines. They generally have a lever with a mechanical advantage. Thus, a relatively small pull can release an arm bearing a much larger load. These devices are necessary in the anchor-handling business, but can be dangerous if not handled properly.

»» Catenary modifying equipment

With an all-chain, wire-rope or combination mooring system, the catenary of the mooring line is controlled by the in-water weight of the mooring line and tension at both ends. There is on occasion a need to modify the catenary shape. This can be accomplished by adding buoyancy or weight along the length of the catenary. • Buoyancy Buoyancy can be added to the mooring line, typically in the form of submersible buoys, at most points along its length to modify the catenary shape as required to avoid hazards or infrastructure. Buoys can be in-line with the mooring line, or shackled to the mooring line by a pennant line. Fabricated steel or syntactic foam buoys must be very large to have any effect on the catenary shape, but also strong enough to resist collapse when pulled beneath the sea. Syntactic foam is often used for deeper water, but it is fragile and must be protected when handled. Buoyancy can add a more robust horizontal stationkeeping component to the mooring design and/or to clear an underwater object. However, significant operational consideration must be taken for installation and recovery of the mooring system. The use of buoyancy is common practice near subsea infrastructure or hazards. • Weight Often referred to as a “clump weight” and typically placed near the anchor or at the chain/wire rope connection of combination systems, this shortens the necessary catenary and creates a “stiffer” mooring system. The design should prevent the clump weight from rising and falling off the ocean bottom, because shock waves will result up and down the mooring line. Clump weights are not often used in modern MODU mooring systems, unless it is a highly unusual situation.

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Dynamic positioning

Dynamic positioning (DP) for the offshore drilling industry means the use of thrusters and/or propulsion, location and heading reference instrumentation, environmental sensing equipment, power plant(s), and a control and monitoring system to reliably maintain a vessel above a designated location. The DP concept was first used in the drilling industry in the early 1960s and over the years has developed into the primary stationkeeping method for deepwater and ultra-deepwater MODUs. Its use has expanded to many other types of vessels in and out of the offshore oil and gas business. Position-keeping reliability is the key to successful DP operations. DP systems are ranked into three classes – DP1, DP2, and DP3 – by the International Maritime Organization: the higher the number, the more reliable the system. The ranking system is based on the degree of reliability via backup and standby capability in the event of a fault in one of the system components. Almost all DP MODUs today are DP2 or DP3. By definition and design, a DP2 vessel must not lose location in the event of a single fault in an “active” component or system. Non-active (“static”) components, such as wiring, cables, pipes, manual valves, etc., are assumed to not fail and are not included in the reliability analysis. Active components and systems include nearly everything else, including engines, generators, switchboard, sensors, DP control system, thrusters, computer networks, remote control devices, etc. For DP3 class, the vessel must not lose location in the event of a single failure for all DP2 definitions, plus static components and all components in any one watertight compartment that could fail from fire or flood. In other words, DP3 systems must have complete physical separation of backup components and systems. The classification societies (Lloyds, ABS, DNV, etc.) certify a vessel for one of the DP classes by examining the vessel design and system redundancy. The vessel’s DP system must also successfully pass a failure-mode effects analysis (FMEA), which conducts a single-point failure analysis of the entire DP system to determine whether the vessel would lose location. The FMEA considers the redundancy concept, the worst-case failure design intent, and the worst-case failure. Vessel DP certification also requires successful passing of FMEA sea trials. The design of a MODU DP system starts with the owner’s desire to stay on location during specified wind, wave and current combinations. The design of the vessel must accommodate environmental loads on the vessel, power demands for thrusters, drilling and hotel (ventilation, heating and A/C, lighting, safety systems, etc.) loads and the worstcase failure design intent. Power plant requirements and the

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BRIDGE FORWARD

Figure FD-14: Schematic of one version of a complete DP system.

number and type of thrusters are determined by combining DP, hotel and drilling equipment power demands, maintenance downtime and the FMEA requirement. A key element in the successful design of a MODU DP system is integration of the power plant, thrusters/propulsion, drilling equipment and DP controls with an effective FMEA to deliver a reliable and effective vessel. Because these components are usually manufactured by different companies, it is critical to integrate all systems to work reliably together. The majority of DP MODUs are ship units, and the rest are semisubmersibles. Most thrusters on both types of MODUs are 360° AC-azimuthing thrusters with 5,000 hp, driven by adjustable-speed AC drives. Most modern MODUs permit the removal or installation of thruster units outside of a shipyard by keelhauling or other methods. This is a great improvement over earlier designs, which required shipyard assistance. Power plants usually have 6-8 engine/generator skids with more than 45,000 installed horsepower. The main power plant electrical bus on modern DP MODUs is usually 11,000 AC volts.

IADC Drilling Manual

Every DP MODU has redundant environmental sensors, including sensors for wind speed and direction, motion, and sometimes current speed and direction. The DP control system uses one or more acoustic position systems, usually long ultra-short base line (LUSBL) technology with four or five transponder arrays. Sometimes the acoustic position data are compared with an inertia reference system. Riser angle measurements might be available when the BOP stack is installed on the sea floor, and can be used to manage the riser angle just above the BOP stack at less than ½-¾°. The combination of multiple differential global positioning systems (DGPS), which has an accuracy of 10 cm vs. 15 m for standard GPS, and multiple acoustic position reference systems allows for error checking and blending of the reference signals in the DP control system. Figure FD-14 shows a first level diagram of one version of an entire DP system. Other reference position systems are available and used on other types of DP vessels, but the system shown in Figure FD-14 is used for DP MODUs.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

Flex Joint

Annular BOP L.M.R.P. Connector

Figure FD-15: Schematic (left) and photo (right) of a typical subsea BOP stack. Photo courtesy GE Oil & Gas. IADC drawing at left.

Blind or Shear Ram Preventer Pipe Ram Preventers

Wellhead Connector

Figure FD-16: Schematic of annular BOP. IADC drawing.

Well control and subsea equipment

This section is intended to complement the Well Control Equipment & Procedures chapter of the IADC Drilling Manual, 12th edition, with an emphasis on floating drilling and subsea equipment. Differences from onshore and surface equipment will be highlighted. Onshore and offshore equipment are designed and manufactured from a shared basic philosophy and purpose. While the equipment is much the same, subsea equipment is generally larger, with higher pressure ratings, more complicated and with considerably more redundancy.

Subsea BOP stacks

Modern subsea BOP stacks are massive, with heights exceeding 40 ft and sometimes beyond 50 ft. Weights exceed 600,000 lb and sometimes 700,000 lb. These sizes and capabilities have evolved over decades of floating drilling development, driven by increased attention to safety, environmental protection and well security. Figure FD-15 shows a drawing and photo of a typical modern subsea BOP stack.

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A subsea BOP stack consists of two major assemblies, the lower BOP stack and the lower marine riser package (LMRP). In the photo shown in Figure FD-15b, the lower assembly consists of ram-type BOPs, while the LMRP consists of two annular BOPs and two BOP control pods. The typical floating BOP stack has an 18 ¾-in. bore and is rated for 15,000 psi working pressure, with a factory test pressure of 22,500 psi. The specifications of the equipment for a BOP stack are spelled out in API Specifications and Recommended Practices. These specs and RPs are often used by government regulators as references and guidelines for their laws and regulations.

Annular BOPs

Figure FD-16 is a drawing of a typical 10,000-psi working pressure subsea annular. The annular is designed to close and seal around most items of any size OD. This includes drill pipe, some parts of tool joints, Hevi-Wate, drill collars, some stabilizers and sizes from almost full bore (18 ¾ in. for

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Figure FD-17: Schematic of ram BOP without ram locks. IADC drawing.

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Figure FD-19: Schematic of upper and lower shearing blind rams. Courtesy GE Oil & Gas. IADC drawing. do a CSO. Variable bore rams (VBR) are exceptions (Figure FD-18). VBRs shut around a narrow range of ODs, such as 3 ½-6 ⅝ in. or 4-7 in. The variation may increase to include casing sizes.

Figure FD-18: Variable bore rams. IADC drawing. subsea) to complete shut off (CSO) of the wellbore. Though annulars have working pressures, for durability and life of the element, they should not be closed and seal on anything above 70% of rated WP; 50% of rating for CSO. The life of the packer element is controlled by the OD of the items it closes upon and the pressure placed on it. The operating pressure used to close the unit is usually 1,500 psi above ambient pressure, i.e., at the water depth of the annular. However, this can vary, depending on the well pressure being held by the annular. Subsea annulars have some degree of self-seal ability from well pressure, but less than onshore units because of water-depth pressure considerations. With the aid of surge accumulators (usually 15-20 gal) precharged to account for water depth on the open and close ports, tool joints can be “stripped” slowly through a sealed annular element. Almost all subsea BOP stacks have two annulars in the LMRP, both with the same pressure rating. However, in some cases the lower unit might have a lower rating. Most annular designs have better stripping characteristics with lower-pressure rated elements (5,000 psi WP vs. 10,000 psi WP), which explains the use of this option. The upper or top annular is usually considered the “working” annular and is the first to be shut in for a kick, with the lower annular serving as backup.

Ram BOPs

All ram BOPs (Figure FD-17) used in well control are of the “split gate” type, with two halves closing to the center of the wellbore via piston action. Unlike annulars, designated types of ram blocks will only close around a designated OD size or

IADC Drilling Manual

Pipe rams close around a set OD size and most subsea BOP stack rams will have at least one size for the drillpipe across the rams when drilling. Another option is to have a casing ram (e.g., 7 in., 7 ⅝ in. or 10 ¾ in.). For a tapered drill string (e.g., 4 in., 5 ½ in. and 6 ⅝ in.) the 6 ⅝-in. would be the BOP stack ram size, because that size should be across the BOPs when drilling ahead. It could also be a VBR with a maximum size of 6 ⅝ in. or 7 in. VBRs lack the drill string hang-off weight rating and packer life durability of standard pipe rams. This can be very important, because the standard shut-in procedure for floating drilling is to first shut the diverter element, then the upper annular, space out the drill string tool joints, close one or two pipe and/or VBR rams, and then set the drill string via a tool joint down on the top ram. All manufacturers have tables showing maximum tubular weight and size ratings for various ram sizes. Using pipe and/or VBR rams to strip drill pipe into or out of the wellbore has been done subsea, but it is a very unusual operation, and only performed in unusual circumstances and at low wellbore pressure. The use of rams that can shear tubulars started in the late 1960s and has developed over the years. The necessity to shear pipe during an emergency disconnect of the LMRP is obvious. Consequently, it’s important to be able to shear and seal whatever the BOP stack holds. It might also be necessary if complete well control is lost. Since the MODU cannot instantly move off location in a blowout situation, the well must be shut in. There are three types of CSO ram blocks. These are blind rams that only seal and do not shear; shear rams designed to cut most drill pipe and seal; and casing shears that only shear and do not seal. Blind rams are rarely if ever used in a subsea BOP stack. Figure FD-19 shows a typical sealing shear ram.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS operate at 3,000 psi above ambient, because of the necessity to have sufficient energy to shear tubulars that might be in the BOP stack. Many subsea control systems are even programmed to operate all shear rams at 5,000 psi above ambient, but this especially applies to casing shears. Operating pressures above 5,000 psi are not common, because the operating piston chambers are not designed for high pressures. For all-hydraulic control systems, the higher pressure also reduces reaction time, which improves well control response.

Figure FD-20: Graphic of a dual fail-safe subsea gate valve. Courtesy Control Flow Inc. Casing shears are generally for very heavy tubulars and casing. The energy to shear is so great that sealability technology is not currently available. All vendors conduct shear tests for their shear and casing rams on varying tubular sizes and for differing OD sizes and grades of steel material (ductility and tensile). Temperature and ram pressure are also monitored closely, along with internal wellbore pressure. Like the annulars, ram blocks (all but casing shears) are self-sealing after an initial seal and a differential pressure is set across them. Hydrostatic water-depth pressure and the effect of mud weight must also be accounted for in determining the ability to shear tubulars. Formulas and shear tables are available from vendors on their shear-ram designs and shearing ability. Generally the higher the tensile and ductility rating the easier the tubulars are to shear. In other words for comparable OD and wall thickness, grade E is harder to shear than grade S-135. Most regulators require via the drilling permit that the operator and drilling contractor demonstrate that they can shear and seal most tubulars that might cross the BOP stack. Rams must have a locking mechanism on at least the pipe or VBR rams. There are a number of designs but most have a piston wedge activated behind the ram piston rod that closes to lock the ram closed. Another popular design is the ratchet or piston sleeve that locks as the ram is fully closed. The design does not require an additional function whereas the wedge design does. In an emergency, the wedge also takes time to activate shut in. Some shear seal and casing shear BOPs have ram locks, but most do not, as a result of their bigger operating piston and overall ram length. A hydraulic lock via a valve circuit on the operating circuit is another alternative. While it is less “positive” as a mechanical lock, it is usually suitable for subsea rams. The reliability of locks must be very high, since a ram-lock failure subsea on a wellhead constitutes a major problem. Operating pressure can be an issue for shear rams, with the standard pressure being 1,500 psi above ambient pressure. However, most subsea control systems are programmed to

IADC Drilling Manual

Kill and choke valves

All subsea BOP stacks have high-pressure gate valves (Figure FD-20). Most are designed for fail-safe close, but a few are designed for fail-safe open. Fail-safe means the valve will default to an open or closed position, should operating pressure be lost. Most BOP stacks have at least two outlets on the BOP stack for kill function (pump into the well) and two choke outlets (flow out of the wellbore); however, under certain circumstances, their use might be swapped. All well control piping running from the BOP stack has double valves, i.e., an inner and outer valve on the same valve block body and on the same outlet. Both valves are usually in the same horizontal position. This arrangement ensures that, should erosion occur, it would be outside the BOP stack bore, ensuring that the valves can shut in the wellbore safely. Other high-pressure valves might be on the BOP stack, i.e., one enabling circulation of any kick gas trapped under the annular BOP after a well kill. The LMRP might also have single valves on the kill and choke runs, so that the crews can test the lines while running only the LMRP. The LMRP will also have one low-pressure valve (usually 5,000 psi) above the flex joint called the mud-circulating valve. This is not a well control valve. It is used to circulate the riser with additional mud to increase annular velocity of the circulated mud to combat the increase in slip velocity of the cuttings when mud leaves the smaller-diameter casing and enters the large diameter of the BOP stack and riser. The operating pressure for all these valves is 1,500 psi above ambient pressure. The valves are designed to be pressure balanced for water depth and mud weight. The position of the choke valves on the BOP stack during drilling will depend on the desired type of shut in, as follows: •• A “soft shut in” during a suspected kick means the valves are left open and the pressure is measured at the surface immediately; •• A “hard shut in” means the valves are closed while drilling and during the initial shut in of the BOP stack on a suspected kick. The valves are later opened to determine annular pressure at the BOP stack.

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Today, probably the most standard subsea BOP stack arrangement is the five-ram, two-annular setup.

Figure FD-21: The bottom of a hydraulic wellhead connector. Courtesy GE Oil & Gas.

Arrangement of a subsea BOP stack

Modern BOP stacks usually will feature at least two annulars and from 4-7 ram cavities, in addition to a number of kill and choke runs. Today all modern BOP stacks have flanged connections, rather than clamps, because flange connections are more reliable and durable. Flanges also have higher bending-moment capacity than clamps. This is important should the MODU move off location with the LMRP connected because high bending moments could be placed on the entire BOP stack and lower portion of the marine riser. Clamp connections are reliable, but must be constantly checked for proper fit and pressure-sealing ability via routine pressure tests. The number and arrangement of rams and kill/choke outlets is almost infinite. The pros and cons can be debated endlessly. One is constant is the annulars with the lower pressure rating, are atop the rams. Since the top annular is also the “working” BOP their elements also wear out more quickly and as stated have a shorter life than ram packers. Therefore, LMRP exist such to be able to pull the annulars, including the more maintenance-prone control pods, to the surface for repair and maintenance. Until recently most subsea BOP stacks had four rams, with one a shear seal ram in the top cavity, while the other three being VBR. The bottom ram would sometimes be a pipe ram of the most common size OD run through the BOP stack, thus leaving two VBRs above it. More recently, a fifth ram was added with casing shear blocks right below the shear seal ram. Due to shear and seal concerns, some operators wanted two shear seal rams on top, with the casing shear below the latter two shear seal rams. Some operators then became concerned that there were too few VBR and/or pipe rams and move to a two shear seal rams, casing shear, three VBR and one pipe ram on bottom ending in 7 ram cavities.

IADC Drilling Manual

When arranging a BOP stack, one consideration for an ultra-deepwater stack is trip time, with test tools to test the BOP stack. Generally BOP stacks are tested every two weeks, unless a casing point is being reached and/or another operation indicates a test in the near future. Some users want a “test ram” on the bottom with no outlets below it, allowing for the stack to be tested from above and thus reducing the number of trips with test tools. Trip time in 5,00010,000-ft water depths can add significant time and cost. However, the test ram uses a ram cavity not for well control, but solely for BOP stack testing. As a result, some users are reluctant to accept this arrangement. Most BOP stacks consist of two double ram cavities and, for a 5-ram BOP stack, a single. It is not common to see triple 18 ¾-in., 15,000-psi WP rams in one body because they are too heavy to handle in most situations and the distance between cavities does not provide for tool joint length; i.e., if the tool joint is set down on a ram, the ram above it will not be able to close because of the tool joint. Most BOP stacks only have two choke and two kill outlets, with one outlet below the “working ram” that will be closed with the tool joint set down upon it following closure of the upper annular. The next choke outlet is usually below the next ram that will be shut. The kill outlets are arranged so that the well can be pumped into with the rams closed. Thus, a kill outlet is usually below the two choke outlets and the bottom ram.

Hydraulic wellbore connectors

All subsea BOP stacks have at least two full-bore hydraulic connectors (Figure FD-21), one on the bottom to latch onto the subsea wellhead and one between the Lower BOP stack and LMRP. Almost all BOP stacks are standardized for the same model connector and pressure rating at both locations. At one time, LMRP connectors were designed to release at higher lift-off angles than wellhead connectors. However, this feature was eliminated, following requirements for additional hydraulic and electrical connections between the lower BOP stack frame and LMRP frame that prohibited high angle releases. All wellbore connectors operate identically: a set of vertical pistons drive a wedge ring up and down to drive individual wedges into a profile on the wellhead or riser mandrel atop the lower BOP stack. All connectors have a primary and a secondary set of pistons. Should a leak occur or a control line to the primary circuit be broken, the secondary system should be able to release the connector. Often the primary and secondary are programmed to open simultaneously to add additional release capabilities to the wellhead connector.

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Figure FD-22: Flex joint installed on an upper annular BOP. Courtesy GE Oil & Gas. All items on the BOP stack are connected and seal via metal-to-metal seal rings. API designates most as “BX” rings for subsea use, despite the existence of other ring designs. BX rings are static seals; however, wellbore connectors must also be able to have a remote seal between the connector and wellhead and the riser mandrel. These are designated “AX” or “VX”, depending on design, and are metal-to-metal seals. Both are now standard API seal rings. Resilient seal rings are used if a seal area is damaged. However, these are often considered only temporary and used only to finish drilling the well. Multiple designs exist for resilient AX and VX seals, but usually each includes a packer arrangement on the seal ring. Wellhead connectors all operate at 1,500 psi above ambient pressure.

Flex joint

A pivot point is required just above the LMRP to reduce bending loads imposed by the riser on the BOP stack. Originally, the industry used “ball joints” for this purpose. Seals were built into the ball joints, and would pivot under correct operating pressure conditions. These types of pivot joints are still used as part of the diverter-to-slip joint connection to provide flexibility between the substructure of the rig and slip joint. For the “lower ball joint” just above the LMRP, a “flex joint” was developed by industry in the 1970s as an outgrowth of the space program. Figure FD-22 is a cutaway drawing of a modern flex joint. Laminate layers of material interwoven with steel fingers allows the design to flex up to 10°. The laminated layers provide resistance to bending moments that must be accounted for included in marine riser analysis. If the flex-joint angle between the marine riser and the BOP stack is too large, it can cause drill string wear and key seating. As a general guideline, the angle at the BOP stack

IADC Drilling Manual

Figure FD-23: All-hydraulic BOP control pod. Courtesy Mark Childers. should be less than ¾° from vertical. The key to prevention of excessive wear is to keep the flex-joint angle as near vertical (zero differential angle) as possible. Most flex joints now have wear sleeves that can be replaced in the field in the event of severe wear. Flex joints must have tensile strengths and bore pressure ratings appropriate for anticipated loads. They must withstand the weight of the BOP stack when being run and pulled by the marine riser tensioner system. Their design must allow for the differential pressure between mud weight inside the riser and seawater outside. This represents millions of pounds of force applied to the flex joint. This demands very robust designs with correspondingly high costs, especially for ultra-deepwater units.

BOP control pods

The two control pods mounted on the LMRP are major components of the BOP stack. These two pods are often referred to as the “yellow” and “blue” pods. Today, there are two types of control pods, “all hydraulic” and “multiplex”, which is a combination of coded electronic signals controlling hydraulic solenoid pilot valves. Figure FD-23 shows the all-hydraulic control pod and Figure FD-24 the multiplex (MUX) pod. Both pod types operate in the same manner. Hydraulic fluid is pumped down umbilical lines attached to the marine ris-

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FD-25

er and through accumulators on the BOP stack. Pilot signals are transmitted via small pilot hoses (3/16-in. OD) for the all-hydraulic system. For the multiplex system, coded electronic signals are sent via a shielded cable from the surface to small control valves in the pods that then direct a hydraulic signal to a large pilot valve. The large pilot valve directs the power fluid to the designated function on the BOP stack. Pods have a receiver plate on the lower BOP stack and another receiver plate on the LMRP that allows hydraulic fluid to pass from the pod to the desired function. All-hydraulic pods (5,000-10,000 lb) are considerably smaller and lighter than the 40,000-lb-plus multiplex pods. For maintenance and repair, hydraulic pods are generally retrievable by guidelines and/or ROV, but multiplex pods are routinely not retrievable. However, in dire emergencies MUXs have been retrieved and re-run. Receiver plates are required for the pods to be detached from the LMRP. More discussion will be given in the BOP control section.

BOP stack frame

The BOP stack frame, which binds all subsea BOP components together, at first glance appears to be a mundane steel frame. However, it is in fact a very complex structural frame with significant strength, flexibility and durability. The BOP stack frames of 40-50 years ago were used solely to run the assembly down guidelines. However, over time the number, size, weight and pressure ratings of BOP rams, annulars and components increased. Similarly, other equipment was added, such as ROVs, EDS and numerous deepwater hydraulic accumulators. Further complicating the design at the stack frame, the increased size of the BOP stack made it necessary to ship the entire assembly on its side. Rigs further must have the capability to fish the assembly off the bottom of the ocean, if dropped. All these factors resulted in the massive and complex frames of today. When applying 15,000-psi pressure to the rams, kill and choke lines and the wellhead connectors, the entire BOP assembly flexes, putting significant strain on connections in the frame and BOP components. This is especially true between the lower BOP stack and LMRP. It is imperative that hydraulic stingers between components align and seal properly. Consequently, another critical function of the stack frame is to ensure this alignment. If an accident should knock the frame out of alignment, it will render the entire BOP stack inoperable, or at least impair function. It is also important, as with all subsea components, to ensure that the frame is properly coated to avoid damage from trips into and out of the very corrosive seawater environment. Specially designed high-pressure hoses are used to plumb between the functions and the pods. Standard wire-braid hose will not survive the corrosive environment or the abuse put on subsea BOP stacks. These hoses must be protected

IADC Drilling Manual

Figure FD-24: Multiplex or MUX control pod. Courtesy GE Oil & Gas. against seawater. Pulling a BOP stack for a failed hose could cost millions of dollars, so using high-end and specifically designed subsea BOP hose is wise, despite the expense.

Auxiliary and miscellaneous items

Numerous auxiliary and additional items are attached to subsea BOP stacks. For example, the BOP stack will include several accumulators facilitating faster closing times and operating emergency disconnect and closure functions. These large and heavy accumulators are placed on the lower BOP stack and LMRP. Also, they must have the proper nitrogen pre-charge to account for water depth. ROV control manifolds on the lower BOP stack and LMRP are also common on modern BOP stacks. The number of functions varies, but the ROV manifolds are primarily for emergency operation in case of a well control situation or to release the BOP stack and/or LMRP, if the primary and secondary control system fails. Most ROV system enable a hose from the surface to be used to pump into the selected function once the ROV plugs the hose into that function. At a minimum, most modern BOP stacks haul ROV interfaces for the wellhead and LMRP connectors, shear seal ram and at least one pipe ram. Equipment to monitor and log all BOP-stack functions have also become common on the stack. More than 100 items can be monitored, including closing times, ram position, volumes of fluid used for an operation, pressures and temperatures in the BOP stack wellbore, operating pressures of the control system, accumulator pre-charge, etc. This data can also be used to help determine when maintenance is required by tracking the number of openings and closures

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All hydraulic BOP control system FD-26

FLOATING DRILLING EQUIPMENT AND OPERATIONS

Figure FD-25: Schematic of an all-hydraulic BOP control system.

Subsea BOP control system

The basic operating system for a subsea BOP control system might look very complicated, but it is actually very straightforward. Figure FD-25 shows an all-hydraulic BOP control system and similarly Figure FD-26 shows a MUX control system. The only difference in the methodology between the two is how the control signal is sent, verified and imple-

mented from the surface to the subsea pods. All the other system components function essentially the same. Besides controlling the subsea BOP stack, the control system also controls the diverter system. The BOP stack and diverter system share a common hydraulic supply system, but are isolated to avoid power fluid from each other. The control panels, etc., are typically located together on a common

Fig 2.2-1

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Basic multiplex BOP control system FLOATING DRILLING EQUIPMENT AND OPERATIONS

FD-27

Figure FD-26: Schematic of a multiplex (MUX) BOP control system. or adjacent skids. BOP control systems are designed, regulated and built to API Spec 16D and in accordance with API Standard 53. Operators often refer to the latter documents in their drilling contracts with drilling contractors; therefore, they are the governing documents in how these systems are designed and built.

Surface control equipment

The standard major components on the surface control system for a subsea BOP are: •• Pump-accumulator-mixing (PAM) unit usually located in the hull or deck house area; •• Hydraulic manifold or multiplex electronics cabinet(s) similarly located; •• Driller’s control panel on the drill floor;

Fig 2.2-2

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

•• Remote control panel, usually located in the OIM’s office or bridge; •• Two hose/cable reels located in the cellar deck or moonpool area, and all interconnecting electrical, electronics and hydraulic hoses. There are also support items, such as motor control centers (MCC), data recording systems, and UPS units, along with store houses for the spare parts and a large workshop. The PAM unit is usually one skid, although the accumulators are located in separate banks to allow internal components — floats, bladders and valves — to be changed out and maintained. The PAM also features multiple pumps with diverse power supplies. There are usually two or more electric triplex pumps powered from main and/or emergency electrical supplies, as well as air-drive pumps powered from rig air and/or a dedicated nitrogen back up. The PAM also incorporates a mixing system to combine water (base fluid), a concentrated lubricant agent and glycol (when required for freeze protection) at selectable ratios. The hydraulic manifold features rows of selector valves with electronic or pneumatic actuators that switch the valves from open to close or vent. Pressure regulators for operating pressure that send signals to subsea regulators are also part of the manifold. For MUX systems, the items discussed above are software driven in an electronic processor that sends coded signals down coaxial cables to the pods. The pods’ processor returns properly coded verification signals of verification. The driller’s control panel is located on the drill floor with a graphic schematic of the BOP stack. When in active mode, it is the master control unit. The BOP can also be controlled from the backup panel, usually located in the OIM’s office or bridge. Some systems may also have additional stations at lifeboat stations or other manned spaces. The control system can also be operated from the PAM unit. The hose bundles for all-hydraulic or MUX coax reels are located in the cellar deck or moon pool area. They can be very large, because for ultra-deepwater units they must hold over 10,000 ft of cable approximately 1 ¼ in. in diameter. The reel has a hydraulic swivel (all hydraulic) or electric slip ring-type arrangement (MUX) in the axle of the reel so that the BOP stack can be controlled while it is being run or pulled. On hydraulic systems, a hose bundle called an umbilical is used. For modern systems the umbilical may have 60-70 or more 3/16-in. diameter, very high-pressure pilot lines. The hydraulic umbilical, lightweight in seawater, is usually 4 ¼-5 ½ in. OD. However, the umbilical’s air weight can be significant, especially if full of fluid. The signal response time for all-hydraulic systems can be as high as 15 sec or more,

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usually entailing pressure up one side of the pilot valve and bleeding off the other side. The bleed off can take longer than the pressure up, depending on what pressure the pilot valve will shift in the pod. If glycol is added to the fluid for cold weather, it may slow reaction time down at least 30%, depending on glycol concentration. It is important to use a BOP control fluid with high lubricity, fungicidal and anti-bacterial content. Without the proper fluid additives, significant problems can occur with growth of microbes, corrosion and significant wear of parts. Unlike the MUX reel, usually only limited functions can be controlled with an all-hydraulic system while running the BOP stack, because a limited number of hydraulic functions are available through the axle. Once the reel is finished rotating, a junction plate is connected to control the rest of the BOP functions.

Subsea control pods

Every subsea BOP stack has two control pods, usually designated “yellow” and “blue” mounted on the LMRP as previously described above. Figure FD-24 shows a MUX control pod with the covers off. The MUX pod has a number of ports that go from the pod to a receptacle on the LMRP, and others that go directly through the LMRP plate receptacle to a second receptacle on the lower BOP stack receiver frame. Also some individual stingers may be included for specific functions. Each pod has at least two electronic processors, as well as numerous hydraulic solenoid valves to shift the pilot valves, batteries, regulators and test ports. It also includes other sensors for riser angle, wellbore pressure, temperature and sometimes television and other functions. MUX pods can weigh over 40,000 lb and are very difficult to impossible to retrieve to the surface independent of the LMRP. Figure FD-23 is a large deepwater, all-hydraulic pod that is nonetheless considerably smaller than the MUX pod shown in Figure FD-24. This pod cannot conduct electronic monitoring or data transmission. It consists of small pilot actuating valves shifted by pressure signals from the surface via the pod umbilical hoses that then shift the pilot valves. When the pilot valves shift, the power fluid in the hydraulic conduit on the marine riser and accumulators on the BOP stack actuate the selected function. In water depths of less than approximately 4,500 ft and when using guidelines, these pods can be pulled to the surface, repaired and rerun on short notice. If there are no guidelines, ROVs have successfully enabled the pods be retrieved and rerun.

Diverter control system

The diverter control system is part of the BOP control system. The diverter portion usually depends on the BOP control system for hydraulic supply, but is isolated hydraulically from the rest of the control system. Neither system is impaired by the failure of the other, should a leak or excessive drainage of fluid occur. The diverter system controls over-

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

Vacuum breaker

Vent up derrick

Pressure relief valve

Bursting disk Flow Pressure relief valve P1

Pressure indicator

F1

Flow indicator

Rated to 60-psi working pressure

P1 Rotary hose

MGS

Mud pumps

IBOP

Mud system

P1 F1 Cement unit pump

Diverter

Closed sealing element Open sealing element

FD-29

Port overboard

F1

Diverter line

F1 Flow line

Starboard overboard

Slip joint

Slip joint packer rated to 100 psi or 500 psi

Diverter packer rated to 500 psi

Figure FD-27: Schematic of a diverter system aboard a modern floating MODU.

Diverter system

board discharge and shale shaker valves, as well as the packer element just below the rotary to safely redirect wellFig dis- 2.3-1 charges away from the personnel on the drill floor. It might also control remote valves leading to the mud gas separator (MSG) or poor-boy degasser and derrick vent lines.

Auxiliary and miscellaneous Items

A number of auxiliary and miscellaneous items are associated with the BOP control system. These include ROV intervention panels for BOP and LMRP functions, hydrate prevention injection lines, TV monitoring for MUX systems, and auto-shear and deadman circuits to close in the well in the event of loss of BOP control. The acoustic backup system might also be associated with the BOP control system. Figure FD-28: Annular-type diverter. IADC drawing.

Diverter systems

The diverter system, especially on a floating MODU in deepwater and ultra-deepwater, is one of the rig’s most essential and critical well control systems. When drilling ahead, gaseous mud and/or a gas bubble might be circulated past the subsea BOP stack. Due to decreasing hydrostatic pressure, the gas at some point after passing the BOP stack will flash from liquid phase into gaseous phase, resulting in rapid expansion and potential evacuation of the low-pressure marine riser. To prevent significant damage to equipment and harm to the crews, a device is necessary to divert the gas and fluids away from equipment and personnel. Figure FD-27 is a schematic of a modern floating MODU diverter system. It is set up to divert primarily “unplanned” and secondly “planned” diversion. When a kick or mud starts to have excessive flow out the bell nipple, the diverter packer is the first item closed in a well control plan. Overboard valves, usually 12-14 in. OD, are opened, if not already in the open position, so that flow can be directed overboard. It is suggested the valves should be left open, since being

IADC Drilling Manual

closed may hinder diversion initially. If wind direction is an issue, the upwind valve can be closed. These valves can be gate or ball valves and are controlled by hydraulic operators. During this process, the subsea BOP has been shut in and the concern is now the gas in the marine riser. The flow overboard can be extremely noisy and forceful. Therefore, all piping and equipment must be designed to withstand extreme forces. In the case of a complete diversion, all gas, oil, mud, formation, sand, etc., are blown overboard. Pollution can be of concern if oil is present. Further, if the mud is mineral based, its loss will be expensive. Conversely, if it has been verified that gas breakout in the marine riser is minimal or nominal and controllable, the flow can be directed through the mud gas separator (MGS) and the mud can be separated from the gas and saved. (The MGS is sometimes referred to as the “poor-boy degasser”.) In addition, if crude is present, it will not be discharged overboard. After going through the MGS, the gas will be vented

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

Drill floor Diverter Upper FJ Tensioner rig Outer barrel Intermediate FJ Termination joint and pup joints

Buoyant joints

Figure FD-29: Drawing of an “insert packer” type diverter without the insert shown. Courtesy GE Oil & Gas. 15 slick joints

up the derrick vent pipe (usually 8- 10 in. OD). Since the MGS and associated piping is an extremely low-pressure and very small volume system, this approach can only be used in very well-planned operation with extremely low volumes. The diverter packing assembly is right below the rotary and firmly attached to the substructure, because significant upward forces will occur when making a right angle diversion. Figure FD-28 is a drawing of an “annular” type diverter assembly. This type diverter is very similar to a typical annular on the BOP stack, but usually features a much larger ID and only 500 psi WP. The other type, which is much more common on older MODUs, is the “insert packer” type shown in Figure FD29. This system requires the crew to install a donut insert into the assembly. The outer seal assembly via operating pressure behind it squeezes the donut around the tubular across from it. Donut packers come in all sizes of ID and even blanks or CSO type inserts. Donut inserts must be installed and taken out on every trip. The CSO insert can be installed while the drill string is out of the wellbore. One of the problems with diverter systems is that they occupy a lot of vertical height beneath the drill floor, thus requiring an elevated drill floor. This then requires a larger MODU for greater stability. Activation for diverter systems should be under 15 sec, including the packer, overboard valves and any other device that must function.

IADC Drilling Manual

Lower FJ LMRP

BOP

Wellhead

Seabed

Figure FD-30: Generic drilling riser stack up. Courtesy 2H Offshore.

Marine risers

FD-Riser1

A riser is a long tubular structure typically made of steel that connects a subsea well to an offshore vessel or platform. For MODU drilling operations, a marine drilling riser is used. The marine drilling riser provides a conduit through which drilling operations are performed. The drilling riser provides the following functions: •• Allows fluid transfer between the vessel and well; •• Guides and protects the drill bit, logging tools and other equipment as they pass through the water column; •• Supports external lines such as choke, kill and auxiliary lines used to control subsea equipment; •• Lands and retrieves the BOP stack. A generic drilling riser stack-up is shown in Figure FD-30. From bottom to top a generic drilling riser stack up is as follows: •• Outer conductor and inner casings (in the seabed): This is part of the well itself. However, the size and material of the conductor and casings, along with their interaction with the soil, play an important role in the response of the drilling riser; •• Wellhead: This is part of the well itself however the size and material of the wellhead play an important role in the response of the drilling riser; •• Blowout preventer (BOP): The subsea equipment used

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

••

••

••

••

••

•• ••

••

to prevent loss of well fluids to the environment in case of well control emergencies. The BOP is discussed in further detail in its own section; Lower marine riser package (LMRP): The LMRP contains all subsea equipment connecting the riser system with subsea BOP. The LMRP connects all systems and external components to the subsea equipment and provides control of the subsea equipment through these systems. Further, the LMRP might contain its own annular BOPs. It also has the capacity to disconnect subsea equipment in the case of an emergency; Lower flex joint: Located atop the LMRP is the lower flex joint. The flex joint allows relative angular rotation of connected components. By allowing an angle between the riser and the LMRP, the flex joint decreases the forces at the connection, decreasing size and strength requirements for riser components. Flex joints typically have an associated rotational stiffness between 10,000 and 30,000 ft-lb per degree. Riser joints: The steel pipe that spans the majority of the distance between the sea floor and the vessel. Joints can be either: ww Slick joints: Bare pipe without buoyancy; ww Buoyant joints: Pipe encased in buoyant material. Buoyant joints are used to decrease the payload of the riser on the vessel. More information on buoyancy is provided in the buoyancy module section below. ww Pup joint/termination joint: Shorter riser joints used to match the length of the riser to the water depth; Intermediate flex joint (optional): Located below the telescoping joint, an intermediate flex joint allows angular rotation of the riser before its initial connection to the vessel. This angular rotation decreases the bending loads that must be carried by the riser pipe and correspondingly decreases the size and strength requirements of the riser joints; Telescoping joint (slip joint) outer barrel: The larger barrel of the telescopic joint that connects to the tension ring. The function of the telescoping joint is for the inner barrel to stroke in and out of the outer barrel as the vessel heaves up and down. This decouples the riser from vertical vessel motions; Tension ring: The tension ring connects the tension system to the riser; Tensioners: The tensioner system provides vertical support to the riser. It is connected to the riser through the tension ring at its base and to the vessel at the top. The tensioner system provides upward force to hold the riser while stroking in and out to accommodate vessel motions. Further detail on the tensioner system can be found in the tensioner section; Telescoping joint (slip joint) inner barrel: The telescopic joint inner barrel moves with the vessel and strokes in and out of the telescoping joint outer barrel (Figure FD-33). Telescoping joints are discussed further later in this chapter;

IADC Drilling Manual

FD-31

Table FD-4: Typical marine drilling riser dimensions Outer Diameter (in.)

21

Wall Thickness (in.)

1-2

Joint Length (ft)

75

Pup Joint Length (ft)

5 - 40

Joint Weight (lb)

40,000

•• Upper flex joint: The upper flex joint provides a flexible connection between the diverter and the telescoping joint inner barrel. The upper flex joint allows the telescopic joint to accommodate riser deflection by way of an angular rotation. This angular rotation decreases the forces concentrated at riser’s connection to the vessel; •• Diverter: The diverter is located atop the riser and is connected to the vessel drill floor. The diverter is used to divert fluids away from the drill floor when a well control event occurs and the well cannot be shut in. The diverter is discussed later in this chapter; •• External lines: Along its length, the riser is supported external lines such as choke, kill and auxiliary lines (hydraulics and boost mud). The BOP pod hoses (or MUX cables) used to control subsea equipment are attached to the outside of the riser. Typical marine drilling riser joint dimensions can be found in Table FD-4:

Physical operating principles

Risers are complex structures due to their immense length compared to their relatively small diameter. Because they are so slender, risers are not capable of supporting their own weight. They therefore must be kept in tension at all times. Should a riser go into compression due to excessive vessel heave, tensioner failure or any other event, the riser pipe is likely to buckle and is considered to have failed. In addition to constantly maintaining tension, the riser system must resist environmental loads. As current and waves move past the riser, they push on the pipe and can cause large forces over the length of the riser. Since risers are only supported at the two ends (the wellhead and the vessel) these environmental loadings are concentrated at those locations. During riser design, finite element analysis is required to assess the stress response of the riser exposed to known operating conditions (combinations of wave, current and vessel motion). The analysis must confirm that factors of safety are within acceptable ranges before the riser design can be employed.

Buoyancy modules

Buoyancy modules are installed on riser joints in order to reduce the weight of the riser and tension needed for stabilization. These modules can eliminate up to 90% of the risers

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

dry weight when submerged in water. This limits the stress on the riser tensioner system greatly. The modules are made of a thermoset resin with microspheres of air. Buoyancy module density and size vary by the water depth at which they are to be deployed to accommodate increasing water pressures. Buoyancy modules may or may not also encase the choke, kill and auxiliary lines.

Marine riser handling

The marine riser is an essential part of drilling a well from semisubmersibles and drillships and constitutes the link between the seabed and the drill floor. Riser joints vary in length, from as short as 50 ft to as long as 90 ft, though the latter are rare. The most common riser joints are 75 ft long. Water depth and design pressure will primarily dictate the wall thickness of the riser joints. Attached to the riser are choke and kill (C&K) lines, booster line and hydraulic line(s), which contribute to the overall weight. To decrease the load on the tensioners from long strings of riser joints in deeper waters, buoyancy modules are attached to the outside of the riser. Combined, all of the items listed above can give a marine riser joint a dry weight of over 60,000 lb. Mechanized handling devices must be used to safely and efficiently move a marine riser joint from the riser storage area to the well center. The most common device is a gantry crane mounted on rails near the riser rack(s). The riser joint handling crane is operated from a dedicated operator’s cab located on the gantry crane A-frame. Marine riser joints can be stored either horizontally or vertically in dedicated storage area(s), depending on rig design or drilling contractor’s preference. Each storage position has its own handling and delivery requirements. Horizontal storage on the main deck is the most common. Some drillships have stored their marine riser joints in a hold below the main deck. Horizontally stored riser joints can be laid on timber-faced racks, cordwood style, between timber-faced fixed buttresses spaced. This permits risers with different water depth ratings to be stored in dedicated bays, or with timber fences at both ends of the racks to restrict forward and aft movement during transit conditions. The above-deck riser handling gantry crane runs on rails mounted either on the drill floor or the support structure of the riser storage area and/or on a rail(s) on the main deck. The crane generally moves port/starboard, allowing the delivery of riser joints to the catwalk machine, which in turn delivers the riser joint to the drill floor. Pin and box joints are inspected either by portable platforms or an inspection basket handled by the gantry crane. The

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basket, rated for 250-kg SWL, is designed to accommodate two people. The basket movement is remotely controlled by wireless radio. Alternatively, riser joints can be stored in individual bays with a structural framework at both ends that captures the flanges and restricts both longitudinal and transverse movement. Inspection walkways at the pin and box joint levels are built into this framework with ladders to each level. Buoyancy material development permits riser joints to be stacked nine high on the racks. The introduction of two flat surfaces on the buoyancy modules, 180° apart, stabilizes the riser joints when stored cordwood fashion. Bare riser joints can be fitted with dummy buoyancy modules to permit storage in the same riser racks used for risers with buoyancy modules. The riser gantry crane can be either electric or electrohydraulic powered. In the case of hydraulic, power is supplied by either the rig’s central hydraulic power unit (HPU) or the riser gantry crane’s onboard HPU. The gantry is provided with safety features such as fail safe brakes, slew stop, emergency stop, etc. In addition to the main hoists, auxiliary hoists are provided to permit maintenance work on the riser joints without the need for the main cranes. A parking or locking system is provided to prevent uncontrolled crane movement during transit or when it is not in operation. For hydraulically powered gantries, power tracks are used to contain and protect hoses and/or cable reels for electrical power, lighting and control cables. The riser gantry crane is equipped with four floodlights and two pan/tilt cameras, one at each end, so that the operator enjoys a clear view of the hook engagement. Control of the riser gantry is from a steel cabin located on one of the A-frames. The control cabin is generally equipped with the following: ••Seat; •• Control panels; •• Cab lighting; •• Independent climate control/air conditioning and heating system; ••Horn; •• Audible alarm; •• Flashing beacon; •• Emergency stop button; •• Fire extinguisher; •• Fire detector to be integrated to the central fire and gas (F&G) system; •• Power supply and rig phone; •• Power supply and area radio; •• Closed circuit TV monitors.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

FD-33

General riser gantry crane technical requirements are: •• Certification: ABS or DNV; •• Area classification: Safe area; •• Hoist capacity: 2 x 25 metric ton; •• Hoist speed: 0-15 m/min unloaded and 0-8 m/min loaded; •• Long travel speed: 0-15 m/min unloaded and 0-8 m/ min loaded; •• Trolleys capacity: 50 metric ton; •• Auxiliary hoists speed : 0-15 m/min; •• Trolley speed: 0-12 m/min.

Horizontal riser handling

The riser gantry will handle horizontal riser joints by means of fail-safe, hydraulically operated hooks, yoke, and stabilizers (Figure FD-31a). A riser yoke is fitted with guides to stabilize riser joints during handling. The operator will select a riser joint, lower the yoke until it rests on the buoyancy jacket and activate the hooks to enter the annulus of the joint. After a signal is received in the control cabin that hooks are engaged, the operator raises the joint and moves the gantry over the catwalk machine. The joint is then lowered, and, once resting on the catwalk machine, the hooks are retracted and the yoke raised clear. The gantry moves away from the catwalk machine to retrieve another joint and the catwalk machine moves toward the well center. When the slip joint is stored adjacent to the riser racks, a slip-joint spreader bar can be attached to the riser gantry hooks to move the slip joint to the riser catwalk machine. When the risers are stored in individual bays, the riser crane can be automated to move and stop at each riser bay position using automatic riser bay indexing. The crane is equipped with encoders and necessary instrumentation for fully automatic operation. The control cabin contains a key switch that is used to override the automated function to allow single function operation of the crane at limited speed in the event of a load cell or encoder failure. The riser gantry delivers a riser joint to the riser catwalk machine for transporting to the well center for running. The catwalk machine is generally designed to handle the following equipment typically found on current-generation semisubmersibles and drillships: •• 75-ft riser joint (slick); estimated weight 45,000 lb; •• 75-ft riser joint (buoyant); estimated weight 62,000 lb; •• 75-ft slip joint with 60-ft stroke; estimated weight 80,000 lbs; •• Conductor casing of 30 in. and 36 in., with estimated weight of 19,000 lb; •• Push/drive transporter cart with diverter assembly, spider/gimble, etc.

IADC Drilling Manual

Figure FD-31: Figure FD-31a (top) shows a horizontal riser-storage system, while Figure FD-31b depicts vertical storage. Courtesy Friede & Goldman. The riser catwalk extends, as a minimum, the full length of the riser rack. The riser catwalk machine is designed to meet ABS or DNV requirements and is certified for operation in hazardous Zone 1 areas. The riser catwalk machine consists of a structural frame with steel bed for tubular transfer, a lift ramp mounted on the well end, carrier in the back, stainless steel drag chain, hydraulic drive motor and gear assembly. A riser articulating arm is installed for tail-in and tail-out functions, with a maximum buoyancy module diameter of 58 in. The catwalk machine runs on flush-mounted rails extending from the riser rack to the well center. The riser catwalk machine is controlled from the driller’s control cabin and/or from a radio remote operator panel. The control system includes an anti-collision system.

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FD-34

FLOATING DRILLING EQUIPMENT AND OPERATIONS the fingers for delivering the riser joints to the riser elevator located at the edge of the drill floor. All riser joints are restrained by a pair of hydraulically operated latches attached to the top of the fingerboard. These latches hinge vertically to release the riser for transport to the drill floor. The latches are fail-safe closed to ensure they remain closed in case of a power failure. All latches are fitted with contoured polyurethane ends to suit the buoyancy diameter and prevent damage to the module skin. Latch assemblies consist of a support bracket, latch and hydraulic cylinder and are unitized to facilitate replacement and maintenance. The latch mechanism is sufficiently sensitive to rotate with the vertical movement of the riser during removal and storing operations. The fingerboards have a polyurethane strip on their vertical webs to prevent damage to the buoyancy modules during riser movements.

Figure FD-32: Moving marine riser pipe onto the rig floor. A transport cart installed on the riser catwalk machine is utilized to transport diverter, top drive assemblies, spider/ gimble, tools, etc., to the well center. The transport cart is provided with rollers and is affixed to the forward end of the riser catwalk machine. The transport frame is rated for 75 metric ton. It is fitted with parking bolts.

Vertical riser handling

The riser gantry crane, similar to the gantry used to handle horizontal riser, will handle riser joints by lifting them vertically. The crane uses a fail-safe, hydraulically operated handling tool that stabs into the pin end of the joint and expands to engage a recess machined into the pin. Hydraulic stabilizers will restrict swinging of the riser during transport to the drill floor elevator. (See Figure FD-31b.) The riser storage area or bucket is located adjacent to the drill floor. Recessed into the upper hull between the longitudinal and transverse bulkheads, the bucket provides storage for 75-ft marine riser joints, complete with C&K, hydraulic and booster lines and buoyancy modules, and the slip joint. Risers are stored in fingerboards similar to those in the derrick. These fingerboards restrain the vertically stored risers above their center of gravity. They can be orientated longitudinally or transversely, as determined by the geometry of the bucket, either at the forward and aft ends or port and starboard sides of the bucket. There is a center aisle between

IADC Drilling Manual

Stainless-steel all-hydraulic lines to the latch cylinders top the fingerboards for easier inspection and maintenance. All connections from the fingerboard piping to the latch cylinders are flexible. A grating walkway is attached to the top of the fingerboards, above the hydraulic lines, with removable sections adjacent to each latch unit. The riser fingers are locked together to offer improved structural integrity and reduce the loading forces on the fingers during rig movement when the fingers are full. This locking mechanism is automated to eliminate the need for personnel working at height to secure the riser-support fingers. A protective “donut” or hat with a flange is provided under the storage position of each joint of riser to protect the riser box and flange. A guide system contains the bottom flange of the riser while it is being moved around the storage area. The system consists of fabricated steel plates and brackets welded to the bottom of the riser bucket. It restrains the riser during transportation to and from the riser elevator. The guides have sloping tops to ensure that the riser flange cannot become lodged on top of the guide. Design of the vertical riser-handling gantry crane is similar to that of the horizontal riser-handling crane. Operation can be either manual or programed to move the gantry crane to every riser location. Under normal operation, control of the riser flaps is performed from the control cabin. A touchscreen interface unit allows the operator to select the riser flap to disengage and make the riser available for removal or replacement. A secondary or back-up control point on a platform located at fingerboard level at the edge of the riser bucket has a touch-screen interface with an additional joy-

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

Inner barrel

Dual packer

Tensioner ring

Kill and choke connections

Swivel

FD-35

riser elevator is to facilitate handling the riser from the riser bucket storage level to the drill floor level and rotate the riser from vertical to inclined positions. Riser joints placed in the riser elevator by the riser crane are inclined (up to 30°) towards the well for attachment of the lifting equipment. When the elevator reaches the appropriate inclination, the elevator lifts the riser upwards to meet the running tool. After the running tool is engaged and the two securing arms are released, the riser is picked up with the traveling equipment and the lower end of the riser is guided by the guide trolley on the elevator assembly and/or floorhand.

Telescopic joints in marine riser systems

Outer barrel

Figure FD-33: Telescopic riser joint. The outer barrel supports the entire riser string through the tension ring and riser tension. The inner barrel is connected to and moves with the vessel. Courtesy GE Oil & Gas. stick. Either the touch screen or the joystick can be used for control. The joystick gives the operator an option for control, should the operator be wearing gloves. Riser inspection positions are located in the corners of the riser bucket, out of riser movement paths. These dedicated positions provide rigid support of the riser during inspection and maintenance operations. The inspection positions are not intended for riser stowage. A fixed shelf, located approximately 1.5 m above the bottom of the riser bucket, supports the riser. A large inspection hole in the shelf allows personnel to inspect the seal area, flange and service lines. Near fingerboard elevation is a hydraulically actuated securing system that closes around the buoyancy module and prevents riser movement during inspection. The securing system is operated from the control cabin of the handling crane. Ladders and an inspection platform are installed around the top of the riser to provide for inspection of the pin end of the riser. These also provide access to various service lines and components requiring inspection and maintenance. The riser-handling gantry delivers a riser joint to the riser elevator, located at the edge of the drill floor, and places it in the elevator and is captured by two hydraulic arms. At this time the riser is in a vertical position. The purpose of the

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The telescopic joint (Figure FD-33), also referred to as the slip joint, is a unique piece of the overall of marine riser system. It serves many purposes, including: •• Acts as an adapter between the marine riser system and the rig substructure; •• Compensates for the motion (vertical and horizontal) that occurs between the sea floor and the surface of the ocean on floating MODUs. Dynamic seal assemblies are used to prevent discharge of drilling fluids to the sea; •• Acts as an interface point between the marine riser tensioning system and the marine riser system; •• Provides fluid connection point between the rig drilling fluid systems, services and the marine riser, such as the kill and choke lines, mud-circulating line and BOP control hydraulic power line. BOP control umbilicals may also attach to the telescopic joint. Telescopic joints are specially designed and built to accomplish the tasks above. The telescopic joint is a double pipe wall construction, with an inner pipe (“inner barrel”) able to telescopically move within the outer pipe (“outer barrel”), with a sealing element between them. The inner barrel is connected to the diverter system, which in turn is connected to the substructure. The outer barrel is connected via the tension ring to the marine riser joints running down to the BOP stack. The tension ring is the interface point onto which the marine riser tensioners place their combined loading force. The standard telescopic joint has a stroke distance of 50 ft; however, for deepwater and ultra-deepwater, the stroke distance can be as long as 65-75 ft. This is necessary, because in deepwater and ultra-deepwater the “watch” circle for vessel position can become very large. (The watch circle is the rig offset perimeter around the well location for which special procedures are to be initiated to prepare to disconnect the drilling riser or actually implement the disconnect to prevent damage due to excessive offset.1) 1. IADCLexicon.org and API Spec 16D, Specification for Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment, 2nd Edition, July 2004.

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FLOATING DRILLING EQUIPMENT AND OPERATIONS

It therefore requires more stroke of the telescopic joint. Telescopic joints are also the heaviest part of the overall marine riser systems, weighing up to 95,000 lb. Because of their length and weight, they require special storage, handling and running procedures.

The basic emergency disconnect sequence involves: •• Closing both the high-pressure blind shear ram and high-pressure casing shear ram; •• Close choke and kill valves; •• Unlatch the LMRP, choke and kill line connectors.

Floating MODUs move dynamically because of sea conditions relative to the sea floor. The inner and outer barrel construction allows the telescopic joint to extend or reduce its overall length as needed. A dynamic sealing assembly serves as the only connection between the inner and outer barrel to prevent drilling fluid returning to the vessel via the marine riser from exiting the marine riser system. There are usually two packers, one primary and one back up, with only one activated at a time.

Floating MODUs are also equipped with automatic mode function (AMF) safety system, also called a “deadman”. The AMF IS designed to automatically shut in the BOPs in the event of a simultaneous absence of hydraulic supply and control system power of both subsea control pods.

Activation is usually accomplished by hydraulic pressure of around 10-15 psi on the packer. This allows some mud lubrication between the inner and outer barrel to reduce packer wear. In the event of a wellbore divert situation with fluid flowing up the marine riser and with the closure of the diverter packer, the control system is programmed to increase pressure on the packer up to 500 psi to prevent fluid from discharging out between the two barrels. A locking system is also installed to allow the inner and outer barrel to be collapsed and locked together in its reduced length to facilitate handling onboard when motion compensation is not required. This is done during running or pulling operations when not connected to the sea floor. The outer barrel near the packing housing is where the marine riser tensioners are connected. Usually 6-12 tension lines are connected by wire rope or rod tensioner. The tensioner ring for dynamically positioned MODUs contains a horizontal rotating bearing allowing the vessel to change heading without tangling auxiliary lines. Some systems have part of the tensioner system latched into the diverter housing with the lines hooked up. In this way, the telescoping joint, when run through the rotary, simply latches on to the ring, thus saving considerable time in hook up. For rod tensioners a split ring may be used to latch around the outer barrel as an installation method. Hooking up the kill, choke, mud circulating and hydraulic line is also necessary. The two BOP control system umbilicals (multi-hose bundle or coax cable) will be hooked onto the outer barrel. If control pods are retrievable via wireline, then hose wirelines will be involved. Since this equipment is very heavy and awkward, a suitable handling system is necessary.

Once the AMF is armed, programmable logic controllers in the system will look for the three conditions below: •• Loss of electrical power and communication from the multiplex umbilical; •• Loss of communication from the other pod; •• Loss of conduit pressure. If all three conditions are satisfied, the EDS/AMF sequence will be activated. The sequence of steps are listed below: •• Energize LMRP stinger, extend; •• Energize stack stinger, extend; •• Energize LMRP stinger seals, energize; •• Energize stack stinger seals, energize; •• De-energize (vent) LMRP stinger, extend; •• De-energize (vent) stack stinger, extend; •• Energize LMRP accumulator; •• Energize high-pressure blind/shear ram close; •• De-energize (vent) high-pressure blind/shear ram close. The time for each step can vary.

Emergency disconnect sequence

An emergency disconnect sequence (EDS) activates during an uncontrolled drift off of a MODU from location or other emergency condition. Either the toolpusher or driller can activate the EDS from his respective control panel.

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HIGH PRESSURE DRILLING HOSES

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THE IADC LEXICON

D E F I N I N G T H E D R I L L I N G S PAC E ! IADC Lexicon puts critical definitions at your fingertips. Imagine thousands of the most pertinent definitions and terms relevant to drilling, all in a single convenient repository – the IADC Lexicon. The IADC Lexicon draws from the most critical legislation, regulations, standards and guidelines worldwide. The European Union requested that IADC, as the authority in the drilling space, create the Lexicon to aid in regulation and understanding our industry. Use the IADC Lexicon as a dictionary or to quickly and easily identify a relevant standard, guideline or regulation. Or, use it as a template to develop instructions for your own company.

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HIGH PRESSURE DRILLING HOSES

HP-i

CHAPTER

HP

HIGH PRESSURE DRILLING HOSES

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. CONTRIBUTORS Ron Trujillo, Global Oilfield Consulting LLC Dr Tibor Nagy, Rubber-Consult Ltd. CO-AUTHORS Alexandra Bukszár, ContiTech Rubber Industrial Ltd. Attila Mihály, ContiTech Rubber Industrial Ltd. Jocelyn Mangunsong, ContiTech Oil & Marine Corp.

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HIGH PRESSURE DRILLING HOSES

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9909049-8-4

Printed in the United States of America.

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HIGH PRESSURE DRILLING HOSES CHAPTER HP

HIGH PRESSURE DRILLING HOSES

Introduction..................................................................... HP-1 Mechanical properties................................................. HP-1 Dimensions and tolerances................................ HP-1 Connections............................................................ HP-1 Test pressure..........................................................HP-2 Working pressure..................................................HP-2 Flexible specification levels (FSL)....................HP-2 Temperature ranges.............................................HP-2 Burst pressure........................................................HP-2 Marking....................................................................HP-2 Recommended dimensions................................HP-4 Care and maintenance.................................................HP-5 Handling..................................................................HP-5 Twisting...................................................................HP-5 Clearance................................................................HP-5 Safety chains/slings.............................................HP-5 Vibration and pulsation......................................HP-5

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HP-iii

Contents Operating temperature.......................................HP-5 Oil-based muds.....................................................HP-5 Barge-attended offshore rigs............................HP-5 Operating limits....................................................HP-5 Inspection and testing..................................................HP-5 Flexible choke and kill hose........................................HP-6 Introduction...........................................................HP-6 Design......................................................................HP-6 Dimensions and tolerances...............................HP-6 End connectors.....................................................HP-6 Performance verification tests.........................HP-6 Working pressure.................................................HP-8 Flexible specification levels (FSL)....................HP-8 Temperature ranges............................................HP-8 Flexible well test hose..................................................HP-9 References.......................................................................HP-9

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HIGH PRESSURE DRILLING HOSES

HP-1

Introduction

Rotary drilling hose is the flexible connector between the top of the standpipe and the swivel, which allows for vertical travel. It usually comes in lengths of 45 ft and longer (Figure HP-1). Rotary vibrator hoses are flexible connectors between the mud pump manifold and the standpipe manifold to accommodate alignment and isolate vibration. They are normally 30 ft in length or less (Figure HP-2). High-pressure cement hose functions as a flexible connection between the cementing pump and the overhead drilling system (Figure HP-3). High-pressure mud hoses should not be used for gas service or operations where it is intended or likely that the hoses will be exposed to well effluent. These hoses are covered by API RP 17B - Flexible Pipe, 5th Ed. Mud and cement hoses should not be used as choke and kill lines, which are covered in API Spec 16C - Choke and Kill Systems.

Figure HP-1: Example of a rotary hose. Courtesy ContiTech.

Note: work at API is in progress to include requirements for flexible hoses used in air, gas, foam or mist drilling.

Mechanical properties Dimensions and tolerances

The length of each hose assembly should comply with the dimension specified in the purchase agreement within the tolerances specified below and in Figure HP-4. All dimensions discussed in the following paragraphs are detailed in Figure HP-4 and Table HP-1. For hose assembly lengths up to 6 m (20 ft), the finished unpressurized hose length tolerance should be ±65 mm (±2.5 in.). For hose assembly lengths up to 6 m (20 ft), the lengths of the hose assembly after pressurization to its specified working pressure should not differ by more than 65 mm (2.5 in.) + 0.01L, where L is the length of the hose assembly.

Figure HP-2: Vibrator hoses. Courtesy ContiTech.

The tolerance for finished, unpressurized hose assembly lengths exceeding 6 m (20 ft) is ±1%. For longer hoses, the lengths of the hose assembly after pressurization to its specified working pressure should not change by more than ±2 %.

Connections

Rotary hose assemblies should be furnished with either swaged or chemically bonded couplings. Hose couplings should be crimped, designed and manufactured to be fit for purpose with the hose assembly they are attached to. End connectors that are attached to the hose couplings with line pipe threads should not be used in hose assemblies with working pressures exceeding 34.5 MPa (5,000 psi). The

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Figure HP-3: Cement hoses. Courtesy ContiTech.

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HP-2

HIGH PRESSURE DRILLING HOSES pulsations are not expected; ŸŸ FSL Level 4: Rotary and vibrator hoses used in air, gas, foam or mist drilling - high-frequency pressure pulsations are expected.

Temperature ranges

Figure HP-4: Rotary vibrator and drilling hose dimensions. Refer to Table HP-1. Courtesy ContiTech.

end connector should either be butt-welded onto the hose coupling or machined from the same piece of material that the hose coupling is made of.

Test pressure

Each high-pressure hose assembly with rated working pressure up to 7,500 psi should be hydrostatically tested to 2.0 times the working pressure; 69-MPa and 103.4-MPa (10,000-psi and 15,000-psi) cement hoses should be tested to 1.5 times the working pressure, as specified in Table HP-1, using water as the test medium. Hold test pressure should for at least 15 min. The pressure test should be recorded on chart or graph and kept on file by the manufacturer for a minimum of 10 years. Work is in progress at API to change test pressure to 1.5 times working pressure for all high-pressure hoses.

Working pressure

Pressure surges are added to the operating pressures and the total pressure must not exceed the working pressure rating in Table HP-1.

Flexible specification levels (FSL)

Flexible specification levels (FSL) define different levels of design verification requirements. ŸŸ FSL Level 0: Cement hoses – with no pressure pulsation requirement; ŸŸ FSL Level 1: Rotary and vibrator hoses for vertical (non-directional) drilling – low-frequency pressure pulsation requirement (NOT recommended for directional drilling); ŸŸ FSL Level 2: Rotary and vibrator hoses for directional drilling high-frequency pressure pulsation requirements (recommended for directional drilling with downlinking). Work is in progress at API to include further flexible specification levels, namely: ŸŸ FSL Level 3: Rotary and vibrator hoses used in air, gas, foam or mist drilling - high-frequency pressure

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The minimum operating temperature of hose assemblies covered by API Spec 7K is -20°C (-4°F). The manufacturer may specify a lower temperature.

Each hose assembly should be rated by the manufacturer to operate in one of the three temperature ranges specified as follows: Temperature range I: -20°C to +82°C (-4°F to +180°F); Temperature Range II: -20°C to +100°C (-4°F to +212°F); Temperature Range III: -20°C to +121°C (-4°F to +250°F). If the minimum operating temperature specified by the manufacturer is lower than –20°C (–4°F), the low-temperature bending test should be carried out at the minimum operating temperature specified by the manufacturer.

Burst pressure

High-pressure mud hose assemblies should be designed to have a minimum burst pressure of 2.5 times the working pressure. Hose assemblies with rated working pressure of 69.0 MPa (10,000 psi) or higher should be rated with a minimum burst pressure of 2.25 times the rated working pressure. The test medium should be water. Maximum surge pressures encountered in the hose should be included in the working pressure.

Marking

The hose assembly manufactured to comply with API Spec 7K should be marked with API 7K, the month and year of manufacture, the rated working pressure, the test pressure, the working temperature range, FSL level, operating and storage MBR, and the manufacturer’s identification. Each hose assembly should have a longitudinal lay line of a different color than the hose cover. (Figure HP-4) D = Inside diameter F = For rotary hose, dimension should be 6-18 in. from the inboard to the end of the coupling. For vibrator hose, dimension should be 6-10 in. from the inboard end of the coupling. L = Nominal length NOTE: Hose manufacturers should mark the hose with the notation “Attach Safety Clamp Here.”

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HIGH PRESSURE DRILLING HOSES

HP-3

Table HP-1: Dimensions and pressures for rotary drilling, vibrator, cement, and mud-delivery hoses Inside Diameter mm (in.)

50.8 (2.0)

63.5 (2.5)

76.2 (3.0)

88.9 (3.5)

101.6 (4.0)

127.0 (5.0)

152.4 (6.0)

API Grade

Rated Working Pressure MPa (psi)

Test Pressure MPa (psi)

Safety factor

Minimal Burst Pressure MPa (psi)

MBR operationala m (in.)

A

10.3 (1,500)

20.7 (3,000)

2.50

25.8 (3,750)

0.9 (36)

B

13.8 (2,000)

27.6 (4,000)

2.50

34.5 (5,000)

0.9 (36)

C

27.6 (4,000)

55.2 (8,000)

2.50

69.0 (10,000)

0.9 (36)

Remark

D

34.5 (5,000)

69.0 (10,000)

2.50

86.3 (12,500)

0.9 (36)

F

69.0 (10,000)

103.4 (15,000)

2.25

155.2 (22,500)

1.2 (48)

cement only

G

103.4 (15,000)

155.1 (22,500)

2.25

232.7 (33,750)

1.4 (55)

cement only

A

10.3 (1,500)

20.7 (3,000)

2.50

25.8 (3,750)

0.9 (36)

B

13.8 (2,000)

27.6 (4,000)

2.50

34.5 (5,000)

0.9 (36)

C

27.6 (4,000)

55.2 (8,000)

2.50

69.0 (10,000)

0.9 (36)

D

34.5 (5,000)

69.0 (10,000)

2.50

86.3 (12,500)

0.9 (36)

E

51.7 (7,500)

103.4 (15,000)

2.50

129.3 (18,750)

1.2 (48)

F

69.0 (10,000)

103.4 (15,000)

2.25

155.2 (22,500)

1.2 (48)

cement only

G

103.4 (15,000)

155.1 (22,500)

2.25

232.7 (33,750)

1.5 (60)

cement only

C

27.6 (4,000)

55.2 (8,000)

2.50

69.0 (10,000)

1.2 (48)

D

34.5 (5,000)

69.0 (10,000)

2.50

86.3 (12,500)

1.2 (48)

E

51.7 (7,500)

103.4 (15,000)

2.50

129.3 (18,750)

1.2 (48)

F

69.0 (10,000)

103.4 (15,000)

2.25

155.2 (22,500)

1.5 (60)

G

103.4 (15,000)

155.1 (22,500)

2.25

232.7 (33,750)

1.6 (64)

cement only

H

138.0 (20,000)

207.0 (30,000)

2.25

310.0 (45, 000)

1.8 (72)

cement onlyb

C

27.6 (4,000)

55.2 (8,000)

2.50

69.0 (10,000)

1.4 (55)

D

34.5 (5,000)

69.0 (10,000)

2.50

86.3 (12,500)

1.4 (55)

E

51.7 (7,500)

103.4 (15,000)

2.50

129.3 (18,750)

1.4 (55)

F

69.0 (10,000)

103.4 (15,000)

2.25

155.2 (22,500)

1.6 (64)

C

27.6 (4,000)

55.2 (8,000)

2.50

69.0 (10,000)

1.4 (55)

D

34.5 (5,000)

69.0 (10,000)

2.50

86.3 (12,500)

1.4 (55)

E

51.7 (7,500)

103.4 (15,000)

2.50

129.3 (18,750)

1.5 (60)

F

69.0 (10,000)

103.4 (15,000)

2.25

155.2 (22,500)

1.8 (72)

G

103.4 (15,000)

155.1 (22,500)

2.25

232.7 (33,750)

2.0 (79)

cement onlyb

H

138.0 (20,000)

207.0 (30,000)

2.25

310.0 (45,000)

2.2 (87)

cement onlyb

C

27.6 (4,000)

55.2 (8,000)

2.50

69.0 (10,000)

1.5 (60)

D

34.5 (5,000)

69.0 (10,000)

2.50

86.3 (12,500)

1.5 (60)

E

51.7 (7,500)

103.4 (15,000)

2.50

129.3 (18,750)

1.8 (72)

F

69.0 (10,000)

103.4 (15,000)

2.25

155.2 (22,500)

2.0 (79)

D

34.5 (5,000)

69.0 (10,000)

2.50

86.3 (12,500)

1.8 (72)

E

51.7 (7,500)

103.4 (15,000)

2.50

129.3 (18,750)

2.0 (79)

F

69.0 (10,000)

103.4 (15,000)

2.25

155.2 (22,500)

2.2 (87)

Continued on page HP-4.

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b

b

HIGH PRESSURE DRILLING HOSES

HP-4

Table HP-1 (cont'd): Dimensions and pressures for rotary drilling, vibrator, cement, and mud-delivery hoses Inside Diameter mm (in.)

203.2 (8.0)

Test Pressure MPa (psi)

Safety factor

Minimal Burst Pressure MPa (psi)

MBR operationala m (in.)

API Grade

Rated Working Pressure MPa (psi)

D

34.5 (5,000)

69.0 (10,000)

2.50

86.3 (12,500)

2.5 (98)

b

E

51.7 (7,500)

103.4 (15,000)

2.50

129.3 (18,750)

2.7 (106)

b

F

69.0 (10,000)

103.4 (15,000)

2.25

155.2 (22,500)

3.0 (118)

b

Remark

a MBR is taken to the center line of each hose. b Not included in API Spec 7K, 5th Ed., but expected to be part of 6th Ed. Addendum. Source: API Spec 7K, 5th Ed.

Recommended dimensions

Use the following equation to determine the recommended length of hose:

Hose length

To avoid kinking the hose, ensure that the hose length of the hose and standpipe height are such that the hose has a normal bending radius at the swivel when the hose is in its lowest drilling position and at the standpipe when the hose is at its highest drilling position

C = Coupling length, m (ft) Hs= Vertical height of stand pipe, m (ft) R = Min. radius of bending of hose, m (ft) LT = Length of hose travel, m (ft) Z = height, m (ft) from top of the derrick floor to the end of hose at the swivel in its lowest drilling position

LH = LT/2 + π R + 2C + S Where: LH = Length of hose in meters (ft) LT = Length of hose travel in meters (ft) R = Minimum bend radius in meters (ft); for values see Table HP-1 C = Coupling length in meters (ft) S = 0.3 m (1 ft) allowance for contraction in LH due to maximum recommended working pressure in feet, which is one foot for all sizes

Standpipe height

Use the following equation to determine the recommended standpipe height: HS = LT/2 + Z Where: HS = Vertical height of standpipe in meters (ft) LT = Length of hose travel in meters (ft) Z = Height in meters (ft) from the top of the derrick floor to the end of the hose at the swivel when the swivel is at its lowest drilling position When the actual hose length is greater than the calculated length, the standpipe height should be increased by half the difference between the actual length and calculated height. Configuration analysis is recommended to avoid over-bending and early failure of high-pressure mud and cement hoses. 3-D computer modeling can be used for the analysis.

Hose end connections

Figure HP-5: Layout for rotary hose. Courtesy ContiTech.

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Rotary hose assemblies with working pressure greater than 34.5-MPa (5,000 psi) line pipe threads should not be used to affix the end connections to the hose coupling. End connectors should not be welded to hose assemblies in the field, as this will damage the hose. In all applicable situations, it’s recommended that all rotary hoses have either one-piece or

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HIGH PRESSURE DRILLING HOSES butt-weld couplings. The connections between the rotary hose, standpipe and swivel should be consistent with the design working pressure of the system. The connections attaching the hose to the swivel and to the standpipe should be as tangential as possible. The use of a standard connection on the swivel gooseneck will ensure this relationship at the top of the hose. The gooseneck on the standpipe should be selected to provide for connecting the rotary hose at an angle 15° from vertical.

HP-5

Vibration and pulsation

Continuous flexing damages the drilling hose and reduces its service life. Pulsation dampeners should be installed in the mud pump discharge line and suction stabilizers installed in the mud pump inlet line to reduce the magnitude of the pressure surges. The manufacturer should provide the pre-charge pressures for the dampeners and stabilizers.

Operating temperature

Hose assembly operating temperature should not be outside the designated temperature range specified earlier. Operating a hose assembly outside its designated range will shorten its service life and may lead to an accident.

Care and maintenance Handling

To minimize the danger of kinking, the hose should be removed from its crate, laid out in a straight line, and then lifted by means of a catline attached near one end of the hose. If a catline is used to remove the hose from its crate, the crate should be rotated as the hose is removed. It’s recommended to use a carrier to protect the hose when moving to a new location. It is considered bad practice to handle hose with a winch, to bang the hose from a truck gin pole, or to place heavy pieces of equipment on the hose.

Twisting

Hose should not be intentionally back twisted. Twisting is sometimes employed to force the swivel bail out of the way. This places injurious stresses on the structural members of the hose body, because one spiral of reinforcing wires is opened and the other is tightened, thus reducing the resistance of the hose to bursting and kinking. In order to prevent twisting, it is suggested that a straight swivel be installed on one end of the hose. Each length of hose has a longitudinal lay line of a different color than the hose cover. This should be used as a guide in making certain the hose is installed in a straight position.

Clearance

Hose installations should provide adequate clearance between the hose and the derrick or mast.

Safety chains/slings

Safety chains/slings should be as short as possible, without restricting the movement of the hose when the swivel is at its highest or lowest point of operation. The safety chain/ sling at the standpipe end of the hose should be attached upright to the derrick upright, rather than to a transverse girt. The chain/sling can then move upward, if the traveling block is raised too high. The safety chain/sling at the swivel end of the hose is attached to the lug on the swivel body or housing. The minimum breaking strength of chains/slings up to 4-in. hose size is 16,000 lb, and above 4-in. hose size is 32,000 lb.

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Oil-based muds

The use of oil-based muds with an excessively high aromatic content will cause the hose inner liner to swell and shorten its service life. It is recommended that oil-based muds be held to a minimum aniline point of 150°F.

Barge-attended offshore rigs

When rotary hose is used as a flexible line between barges and offshore drilling rigs, use care to ensure that the hose aligns between both end connections. It is recommended that swivel joints be used at both ends. Drilling in rough weather and high seas will result in abnormal flexing and jerking of the hose, and cause premature failures.

Operating limits

Operating personnel should be advised on the highest and lowest drilling positions, length of standpipe, etc., for which the hose was selected and drilling operations should be carried out within such limits.

Inspection and testing

It is essential to properly care for the flexible hose once installed and in service. The frequency and degree of inspection depends upon the severity of service. It is recommended that the operator record all inspection data for the hose. This information will be used by the manufacturer when evaluating the condition of the hose during the inspection schedules. In general, the hose should be inspected regularly. Follow or exceed these minimum guidelines: ŸŸ Once a month (or during installation/removal): Visual inspection; ŸŸ Once or twice a month: On-site pressure test; ŸŸ Initial and every six months: Major inspection; ŸŸ Annually: 2nd major inspection. There are a number of critical elements in the hose that cannot be thoroughly checked through standard inspection techniques. Apart from dissecting the hose body, the best way to evaluate the condition of the hose is through review

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HP-6

HIGH PRESSURE DRILLING HOSES ŸŸ Permissible test media: mud, oil and water, with the precaution that all air should be bled off; ŸŸ Duration of test pressure limit should not exceed 10 min; ŸŸ Field test pressure should not exceed 1.25 times the maximum rated working pressure (Table HP-1).

Flexible choke and kill hose Introduction

The flexible choke and kill hose can be used as an integral part of the blowout preventer. These hoses are important when a kick occurs during drilling. (A kick is an unexpected entry of water, gas, oil or other formation fluid into the wellbore.) This can occur when the pressure of the medium entering in the wellbore is higher than expected. To prevent the blowout, high density mud is pumped through the kill hose. The pressure of the well is adjusted by the quantity of the mud passed through the choke line (Figure HP-6 and Figure HP-7). Figure HP-6: Flexible choke and kill hose installed on a jackup drilling rig. Courtesy ContiTech.

At the date of the writing this document, API Spec 16C, 1st Ed. is the valid standard, but work is in progress at API to issue API Spec 16C 2nd Ed.

Design

Typical constructions of bonded and non-bonded flexible choke and kill lines (Figures HP-8 and HP-9, respectively). Bonded and non-bonded assemblies are shown in Figures HP-10 and HP-11, respectively.

Dimensions and tolerances

Figure HP-7: Choke and kill hoses on subsea BOP stack. Courtesy ContiTech.

of the operating conditions recorded during the hose service life, in particular maximums and peak conditions. Field testing of rotary hoses, when required for establishing periodic safety levels of continued operations, should be conducted with these factors as a guide: ŸŸ During visual inspection, examine all external damage to the body, end fitting, and couplings. Safety chains/ slings should be checked and properly attached for safety compliance; ŸŸ All back twist must be avoided; ŸŸ Hose should be suspended in normal unstressed position from standpipe to swivel; ŸŸ Rate of pressure should rise not less than 1,000 psi/ min, nor greater than 10,000 psi/min;

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See Table HP-2. The length of each hose assembly should comply with dimensions specified in the purchase agreement within the proper tolerances. The standard overall length tolerances of flexible hoses up to 6 m (20 ft) should be ±65 mm (±2.5 in.) with the tolerance of longer lines being ±2%. The standard tolerance for length change from atmospheric to working pressure is a maximum of ±2% of the overall length. The length tolerance for LMRP choke and kill hose is to be specified by the manufacturer, after lengths and orientation (3D) modeling is completed.

End connectors

Flexible choke and kill hose end connectors should have welded or one-piece pipe design. The pressure rating should be equivalent and not higher than the pressure rating of the flexible hose. Pipe threads are not acceptable end connections. Figure HP-12 shows typical flexible choke and kill hose end connectors.

Performance verification tests

Since choke and kill hoses may be employed as an integral part of the blowout prevention equipment, API Spec 16C

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HIGH PRESSURE DRILLING HOSES

1: Fluid-containing inner tube 2: Rubberized textile 3: Reinforcement windings

4: Cover rubber 5: Outer armoring

Figure HP-8: Typical bonded flexible choke and kill line constructions. Courtesy ContiTech.

1: Fluid-containing inner tube 2,8: Tape 3,4,6,7: Reinforcement windings

5: Intermediate sheath 9: Cover 10: Outer armoring

Figure HP-9: Typical non-bonded flexible choke and kill line constructions. Courtesy ContiTech.

Figure HP-10: Typical bonded flexible line assembly. Courtesy ContiTech.

Figure HP-11: Typical non-bonded flexible line assembly. Courtesy ContiTech.

Figure HP-12: Typical flexible choke and kill hose end connectors. Courtesy ContiTech.

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HP-7

HP-8

HIGH PRESSURE DRILLING HOSES

Table HP-2: Flexible choke and kill line sizes and rated working pressures Inside Diameter in. (mm)

Rated Working Pressure psi (MPa)

Test Pressure psi (MPa)

Minimum Burst Pressure psi (MPa)

2 (50.8) 3 (76.2) 3 1/2 (89) 4 (101.6)

5,000 (34.5)

10,000 (69.0)a

11,250 (77.6)

2 (50.8) 2 1/2 (63.5) 3 (76.2) 4 (101.6)

10,000 (69.0)

15,000 (103.5)

22,500 (155.0)

2 (50.8) 2 1/2 (63.5) 3 (76.2) 4 (101.6)b

15,000 (103.5)

22,500 (155.0)

33,750 (233.0)

2 (50.8) 2 1/2 (63.5) 3 (76.2) 4 (101.6)b

20,000 (138.0)

30,000 (207.0)

45,000 (310.0)

a

Test pressure of 5,000 psi choke and kill lines will be changed to 7,500 psi in of API 16C, 2nd Ed. 4 in. 15,000 and 20,000 psi are not included in present API 16C, but are expected to be in 2nd Ed. Source: API RP 16C b

Table HP-3: Flexible choke and kill line flexible specification levels (FSL) Flexible Specification Level

Definition

FSL 0

Includes all design, material and design validation test requirements including hydrostatic internal pressure, bending flexibility, burst test and exposure test.

FSL 1

Includes FSL 0 and flexible line fire test.

FSL 2

Includes FSL 0 and flexible line high temperature exposure test.

FSL 3

Includes FSL 0, flexible line fire test and flexible line high temperature exposure test.

defines design verification testing, a series of mechanical tests, including exposure to high concentration of H2S, hydrostatic internal pressure test, bending flexibility test, burst test, decompressions etc. In addition, a fire test minimum of 1,300°F (704°C) for 30 min. might be required. The test pressure is specified in Table HP-2.

Working pressure

Pressure surges are added to the operating pressures and the total pressure must not exceed the working pressure rating in Table HP-2.

Flexible specification levels (FSL)

Temperature ranges

Each hose assembly should be rated by the manufacturer to operate in one of the five temperature ranges specified as follows: ŸŸ Temperature range A: -20°C to 82°C (-4° F to 180°F); ŸŸ Temperature range B: -20°C to 100°C (-4°F to 212°F); ŸŸ Temperature range K: -60°C to 82°C (-75°F to 180°F); ŸŸ Temperature range P: -29°C to 82°C (-20°F to 180°F); ŸŸ Temperature range U: -18° C to 121°C (0°F to 250°F). Note: API 16C Spec 2nd Ed. is expected to contain additional temperature levels, and will allow combinations of different temperature levels.

FSL designations are not included in the present API Spec 16C, but are expected to be in the 2nd Ed. FSL listed in Table HP-3 define different levels of design verification requirements.

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HIGH PRESSURE DRILLING HOSES

Flexible well test hose

There is no recognized industry standard for well-test hoses. However, in view of the typical operating conditions (5,000 psi operating pressure or lower, with a very high variation in the duration and frequency of operation), the API specifications for choke and kill hoses (API Spec 16C) and production hoses (API Spec 17K- Bonded Flexible Pipe, 2nd Ed. and Spec 17J - Unbonded Flexible Pipe, 4th Ed.) should be considered. Choke and kill hoses are designed to withstand short-term high-pressure operation; production hoses must withstand continuous periods of operation with a high risk of rapid decompression. Such decompression can cause collapse of the hose liner as entrained gas, which has entered the hose body during the long periods of operation under pressure, permeates back into the hose cavity. Since choke and kill hoses may be designed for short-term gas exposure, the manufacturers should be consulted regarding applicability to well testing.

HP-9

References 1.

API Spec. 7K 5th Ed. (2010) Drilling and Well Servicing Equipment

2.

API RP 7L 1st Ed. (1995) and Addendum 2 (2006) Procedures for Inspection, Maintenance, Repair and Remanufacture of Drilling Equipment.

3.

API RP 17B 5th Ed. (2014) Recommended Practice for Flexible Pipe.

4. API Spec. 17K 2nd Ed. (2005) Specification for Bonded Flexible Pipe. 5. API Spec. 17J 4th Ed. (2014) Specification for Unbonded Flexible Pipe. 6. API Spec. 16C 1st Ed. (1993) Specification for Choke and Kill Sytems. 7.

7. API Spec. 16C 2nd Ed. (2015 in print) Specification for Choke and Kill Equipment.

8. 8. API Spec. 5B 15th Ed. (2008) Specification for Threading, Gauging and Thread Inspection of Casing, Tubing, and Line Pipe Threads.

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LU

LUBRICATION

IADC Drilling Manual 12th Edition IADC Drilling Manual • Copyright © 2015

Enhancing operational integrity by ensuring a competent workforce

Accreditation & Credentialing

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LUBRICATION

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CHAPTER

LU

LUBRICATION

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. PRINCIPAL AUTHOR Sean Komatinsky, Castrol REVIEWERS Mike Faulkner, ENSCO Tom Reynolds, Castrol

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LUBRICATION

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9906220-2-4

Printed in the United States of America.

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LUBRICATION Contents CHAPTER LU

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Contents

LUBRICATION

Tribology.......................................................................... LU-1 Mechanisms of wear.............................................. LU-1 Types of lubrication................................................ LU-2 Boundary lubrication......................................... LU-2 Mixed-film lubrication...................................... LU-3 Hydrodynamic lubrication............................... LU-3 Hydrostatic lubrication..................................... LU-3 Functions of a lubricant........................................ LU-3 Lubricant formulation............................................ LU-4 Base oils................................................................ LU-4 Lubricant additives............................................ LU-5 Lubricant properties............................................... LU-5 Applications.............................................................. LU-7 Engines.................................................................. LU-7 Gears..................................................................... LU-7 Greased applications........................................ LU-8

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Lubrication program and practices........................ LU-10 Introduction............................................................ LU-10 Lubrication program baseline............................ LU-10 Goals of a lubrication program......................... LU-10 Lubrication opportunities................................... LU-11 Lubrication survey................................................ LU-11 Lubricant suppliers............................................... LU-11 Management of change (MOC).......................LU-12 Fluid conditioning & contamination control......................................................................LU-12 Lubricant storage and handling........................ LU-14 Used oil analysis.................................................... LU-14 Used oil analysis service selection..................LU-15 Appendix: Definitions............................................... LU-A1

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THE IADC LEXICON

D E F I N I N G T H E D R I L L I N G S PAC E ! IADC Lexicon puts critical definitions at your fingertips. Imagine thousands of the most pertinent definitions and terms relevant to drilling, all in a single convenient repository – the IADC Lexicon. The IADC Lexicon draws from the most critical legislation, regulations, standards and guidelines worldwide. The European Union requested that IADC, as the authority in the drilling space, create the Lexicon to aid in regulation and understanding our industry. Use the IADC Lexicon as a dictionary or to quickly and easily identify a relevant standard, guideline or regulation. Or, use it as a template to develop instructions for your own company.

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LUBRICATION

Tribology

The fundamentals of lubrication are derived from tribology, which is the study of surfaces moving relative to each other. Tribology evaluates the aspects of friction, lubrication and wear. There are a number of factors that can influence how these surfaces interact, including surface roughness, material types, speed, pressure and contamination. Successful utilization of lubrication, however, can be a highly effective tool at minimizing negative outcomes such as premature wear. The basic reason for lubricating components is the need for equipment to perform a specific task with an acceptable level of efficiency, reliability and cost. What is acceptable can vary from organization to organization, but many equipment manufacturers have provided a baseline expectation for their equipment with respect to lubrication and maintenance regimes. Despite the established baselines, there are many lubrication opportunities to improve efficiency and reliability, resulting in overall lower costs. These opportunities will be discussed later in this chapter. The costs associated with poor lubrication are quite staggering, according to several estimates. Nearly 70% of equipment failures can be attributed to lubricant-related failures at a cost of over $7 billion annually. This is a cost that cannot be recovered. Poor utilization of lubricants has a cascading damage effect that cannot be reversed by corrections in improper practices. Correcting lubrication problems as early possible helps avoid further damage progression, but attentiveness to utilizing lubrication best practices from the start yields the maximum benefit of reliability, efficiency and cost-effectiveness. The opportunities to develop a lubrication program are numerous, and the benefits are quite extensive. Although there is a baseline expectation on what a lubricant can do, this is merely an average and minimum expectation of performance in various applications. A better understanding of lubrication and the increased availability of lubrication tools has yielded increased improvements with minimal investment. The amount of the return will vary from organization to organization and also be dependent on the current lubrication culture and resources available to implement additional initiatives. The most obvious benefits, however, will fall into three primary groups. 1. Reduced equipment life cycle costs a. Reduced maintenance costs b. Reduced lubricant expense 2. Improved operational reliability a. Reduced unplanned downtime

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LU-1

b. Improved plant availability and reduction in lost production 3. Efficiency improvements a. Lower energy costs

Mechanisms of wear

The necessity of lubrication and the possible opportunities are based on component tribology, or evaluation of how internal component surfaces move relative to each other. Each lubricated application has unique operating conditions and stresses which can make it subject to different mechanisms of wear. It is important to understand the wear causes and opportunities of different applications to enable proper avoidance of these conditions. Abrasive wear: The most common type of wear, normally caused by contaminants moving between the surfaces in the lubricant. Contamination sources could come from surface base metal or dirt from external sources. These particles are normally the same size or larger than the lubricant film thickness and result in scratching or scaring of the surface. Particles which cause abbraisve wear can be embedded into component surfaces or broken into smaller particles which can cause Erosive wear.

Deep scratch due to abrasive wear

Figure LU-1: Visual depiction of abrasive wear.

Abrasive wear is the most common type of wear and results in nearly four of every five component failures. This type of wear can be managed through proper lubricant handling, minimizing sources of external contamination and utilization of filtration. Adhesive wear: The result of the welding of surfaces due to insufficient lubricant film thickness or insufficient additive chemistry. The welding of surfaces is then followed by

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LU–2

LUBRICATION

the shearing of these welded sections from the base metal. Factors that can increase the potential for adhesive wear include utilizing a lubricant viscosity that is too low for the application, using a lubricant which has insufficient additive chemistry which does not adequately protect from incidental surface contact or abnormally heavy component loading including high speeds or high temperatures. Normally this type of wear is very catastrophic to internal components and is caused by improper lubricant selection or changed operating condition which the lubricant film strength or additive chemistry is no longer sufficient to mitigate. LOAD

Material transfer or particle formation

Figure LU-2: Visual depiction of adhesive wear.

Avoidance of adhesive wear is normally mitigated by proper lubricant selection for the operating conditions of the equipment, proper lubricant conditioning and validation of lubricant properties through used oil analysis. Fatigue wear: Heavy cyclic loading of surfaces can result in the weakening of surfaces, leading to cracks and separation of surface material. Surface material released is normally much larger than the fluid film and can result in deep scaring or additional stress on component surfaces. This type of wear is also commonly referred to as micro-pitting . Fatigue wear is normally mitigated by utilization of the correct lubricant with regard to viscosity and additive blend to

manage the cyclical loading. Observations of changing component conditions through vibration and used oil analysis may indicate a condition of increased wear prior to serious failures. Erosive wear: Caused by the impact of particles in the lubricant that erodes internal components. High levels of contamination in systems cause this type of wear as the lubricant carries particulates through the system. High system pressures, fluid velocity or particulate hardness can increase the erosive wear of system components. Erosive wear is similar to the process of sand blasting. Minimizing external contamination and effective use of filtration will resolve this. Corrosive wear: Corrosion of internal components is caused by the presence of moisture on ferrous components or a chemical reaction. Some lubricant additives could be corrosive to some internal metals. Common examples include extreme-pressure gear additives with yellow metals in worm gears or zinc anti-wear additives with silver lined components in Electric Motive Diesel (EMD) engines.

Types of lubrication

Now that we have evaluated the types of common wear mechanisms, we can evaluate the different types of lubrication that will help minimize component damage from premature wear. Each lubricated application has unique internal operating conditions and stresses that are a function of system design, component condition, equipment loading and operating conditions. Throughout the operation of a component, there are various stages of lubrication that ensure a level of protection of internal surfaces. These four primary types of lubrication are boundary lubrication, mixed-film lubrication, hydrodynamic lubrication and hydrostatic lubrication. Typically a given component experiences at least two types of lubrication during its normal operation.

Boundary lubrication

Boundary lubrication exists when there is little to no lubricant between the surfaces, and some contact is expected between the metal surfaces. This condition is existent in almost all applications upon startup as there is insufficient motion or hydrostatic lubrication (described below) to separate the surfaces. Lubrication in this scenario is provided by the accumulation of anti-wear wear additives on internal surfaces, such as zinc dialkyldithiophosphates (ZDDP) or molybdenum disulfide (MOS2), which provide a softer cushion that releases as the surfaces touch each other under pressure. Although the anti-wear additive handles most of the loading in this lubrication type, some contact and wear between surface base metals can be expected. Figure LU-3: Visual depiction of fatigue wear.

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LUBRICATION

LU–3

Oil film Figure LU-4: Visual depiction of boundary lubrication.

Mixed-Film Lubrication

Mixed-film lubrication is a mixture of a partial lubricant film to separate the surfaces but is not sufficient to prevent higher points in the surface from touching. In this condition the chemical anti-wear additives on the surface provide lubrication for any touching of surfaces.

Figure LU-6: Visual depiction of hydrodynamic lubrication.

boundary lubrication (metal-to-metal) contact is not acceptable at any point. An example where hydrostatic lubrication is commonly used is on gas turbines or generator bearings to reduce potential wear on startup.

Figure LU-5: Visual depiction of mixed-film lubrication.

Mixed-film lubrication is a condition most observed during equipment startup periods where there is not a sufficient speed to move the lubricant and create full separation of the surfaces. This condition could also exist at normal operating speed when the lubricant viscosity is too low for the operating conditions.

Hydrodynamic lubrication

Also referred to as “full-fluid film lubrication,” it is represented by a full separation of the surfaces with no metal-to-metal contact. The full load is carried by the lubricant film. Hydrodynamic lubrication is the most desirable state of lubrication, where internal contact of moving surfaces is minimized. To achieve this level of lubrication, the proper lubricant viscosity is necessary for a given component operational temperature, speed of movement between the surface, component loading and clearance tolerances between the surfaces.

Hydrostatic lubrication

Hydrostatic lubrication is achieved with the forcing of a lubricant film into internal contact points to support the loading in a static or starting position. This is normally achieved through pre-lube pumps and used on applications where

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Oil pumped Figure LU-7: Visual depiction of hydrodynamic lubrication.

Functions of a Lubricant

With an understanding of different wear patterns in components and the types of lubrication, we now evaluate the specific functions of a lubricant that mitigate component stresses or improve efficiency by performing a number of functions: Reduce or Modify friction/wear: Friction from the movement of internal parts is an engineering reality along with the byproducts of wear, heat and noise. The sliding of two surfaces against each other without any separating medium has an unacceptable level of friction from wear, efficiency and reliability perspectives. Thus, the primary function of a lubricant is to modify this friction to a point at which a component can be expected to efficiently and reliably perform

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LUBRICATION

its task. The reduction in wear from the modification of friction between internal surfaces is the most significant benefit of effective lubrication. Remove heat: Relative motion from the movement of internal surfaces creates heat that can be potentially damaging to internal components. Lubricants serve as a cooling medium by absorbing heat as it passes internal surfaces. This heat is then carried to oil coolers or sumps to further remove the internal heat from the component. Prevent corrosion: The presence of heat and moisture in applications with ferrous components creates a significant potential for internal corrosion and damage to internal surfaces. Lubricants contain corrosion inhibitors to prevent the potential for damage when moisture and heat are present. The additives serve to coat internal surfaces and protect them from exposure to corrosion-developing conditions. Corrosion can also form as a result of the creation of corrosive byproducts during normal operation. Lubricants may also contain additives that neutralize these harmful byproducts. In the case of diesel engines, lubricants contain a base additive to neutralize acids that are created from the combustion of sulfur in the fuel. Remove contaminants: Internal contamination is existent with most component designs based on the various internal stresses, equipment duty cycles and sources of external exposure. The lubricant utilizes a two-pronged approach to removing contamination by cleaning internal surfaces of these deposits and transporting the contamination to installed filtration. Provide a seal: Lubricants also serve as a barrier or medium to seal internal components from the ingress of external contaminants. Sealing lubricants include greases that encapsulate contaminants in seal areas or highly viscous lubricants under pressure to seal out contaminants such as water.

Lubricant formulation

Now that we have a an overview of the internal component mechanisms of wear, types of lubrication and functions of a lubricant, we can evaluate how a lubricant is formulated to provide effective lubrication in a variety of components. Lubricants are a complex formulation of two primary components, a base oil and additives, to efficiently and reliably operate a given component. The variations of base oils and additives can be significant depending on the needs of the application’s design and operational demands. Together, these components provide the right balance necessary to achieve the expected operation of the component.

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Base Oils

Base oils are the foundation of any lubricant formulation and serve several key functions, including: • • Establishes the viscosity of the oil that has the primary impact on the fluid film thickness and supporting of the load during component operation; • • Serves as the medium to deliver the additives for the purpose of protecting internal system components and the base oil itself. Base oil types: Base oils have the greatest influence on the function of the lubricant and can have significant variation depending on feed stock and refining process. Base oils are refined (mineral) or manufactured (synthetic) with some very significant different variations in composition and performance. Each of these base oils are categorized into five different groups based on their composition and physical properties (Table LU-1). Table LU-1: Base oil types and composition. Base oil Group

Saturates % Wt

Sulphur % Wt

Viscosity Index

Group I (mineral)

Less than 90%

Greater than .3%

80 to 120

Group II (mineral)

Greater than 90%

Less than .3%

80 to 120

Group III (mineral)

Greater than 90%

Less than .3%

121+

Group IV (synthetic)

Polyalphaolefins (PAO)

Group V (synthetic)

All Synthetic base stocks other than PAO

The mineral base oil groups (1-3) are separated by the evaluation of the levels of saturates and sulphur and the viscosity index of the fluid. The quality of the base oils is represented in ascending order: • Group I (Mineral): Group I mineral base oils are the lowest-quality base oil stocks that are categorized by their higher level of impurities, high aromatic content and poor viscosity index. Due to greater utilization and performance demands from OEM applications, Group I base oil usage has declined significantly; • Group II (Mineral): Group II mineral base oils have reduced impurities including sulfur, wax and arromatics, providing better viscosity index and thermal stability. Group II mineral base oils have become the standard in most of today’s modern mineral lubricants, providing a “best value”with respect to cost and performance; • Group III (Mineral): Group III mineral base oils, also referred to as “highly refined base stocks,” have many performance properties that can be comparable to some synthetic base oils;

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LUBRICATION • Group IV (Synthetic): Group IV is comprised of polyalphaolefin base stocks and is often referred to as PAO. Like all synthetics, polyalphaolefins are derived from chemicals to produce a highly uniform and stable base oil. PAOs have excellent thermal stability, high resistance to oxidation, good flow at low temperatures and a high viscosity index. Polyalphaolefin base oils are the most commonly used synthetic base oil type and are used in a number of applications including engines, hydraulics, gearboxes and some compressors; • Group V (Synthetic): Group V synthetics encompass all other synthetic base stocks. Like the Group IV polyalphaolefins, Group V synthetics are also derived from chemicals and chemical reactions. Group V base oils have historically been used in niche applications, but have expanded in use due to the increased complexity of offshore equipment designs, increased stress on components and an advancing lubricant culture of operators to more effectively utilize these advance fluids. Group V base stocks used in the E&P market include polyalkylglycols for high-temperature gearbox or gas compression, synthetic esters for reciprocating compressors and environmentally responsible hydraulics, and polyolesters for refrigeration applications.

•

• •

•

•

Lubricant additives

Because base oils have certain limitations by themselves, lubricant additives are necessary to achieve an expected level of performance in a component. This expected performance includes achieving an expected life of the oil and of the component in normal operating conditions. Thus, lubricant additives are specific components which are added to base oil for the purpose of protecting or enhancing the base oil, cleaning and protecting internal system components or neutralizing internal contaminants. Below are a list of the most common types: • Anti-oxidant: Minimizes the formation of resins, varnish, acids, sludge and polymers; • Anti-wear: Designed to adhere to internal surfaces to provide a sacrificial layer in the event of slight metal-tometal contact. This additive is most important during mixed-film lubrication where the fluid separates most of the surface, but some contact is likely to occur; • Friction modifier: Used to achieve either reductions in friction in applications like engines or a specific level of friction in transmissions or fluid couplings; • Tackifier: Used to assist the lubricant in adhering to a surface so a fluid film can be maintained; • Extreme pressure: Also referred to as EP additives, these are required for applications, such as gearboxes, which are under heavy load. The EP additive adheres to the gear surface and is activated by temperature to provide a cushion between contact of the gear teeth.

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•

•

LU–5

Solid lubricants, such as MOS2, can be used in application where there are very extreme loading conditions that create temperatures too high for traditional sulphur phosphorus EP additives; Foam inhibitor: Additives that inhibit the formation of foam from the churning of air in the component by facilitating the release of the air from the lubricant. The formation of foam can significantly reduce the fluid film strength by enabling air pockets to penetrate between internal surfaces. Foaming is normally caused by low oil levels or leaking fittings that enable air to enter the system. Significant foaming can lead to increased wear of the surfaces and significantly lead to foam inhibitor additive depletion; Dispersant: Additives that encapsulate contaminants in the lubricant so they can be carried to installed filtration; Emulsifier: Allows mineral oil to be mixable with water. Frequently used in metal-cutting oils and in some lubricants for wet applications; Detergent: Additives used to keep internal surfaces clean from contaminants. Detergents are designed to coat internal surfaces of components during normal expected operation to prevent deposits from forming. Detergents may have a limited abilty to clean existing system deposits; Oxidation inhibitors: This additive type is necessary as equipment operation causes heat, moisture and other contaminants to degrade the base oil. Oxidation inhibitors significantly reduce the rate of oxidation to an acceptable level so a reasonable fluid life can be achieved; Viscosity index improvers: Viscosity index improvers enhance the base oil to provide better stability with regard to changes in the fluid’s viscosity through temperature changes. Viscosity index improvers can also critical when operators face significant changes in operating temperatures, such as aviation applications and arctic operations. A higher viscosity index enables the lubricant to either thicken or thin at a slower rate as operating temperatures fall or rise; Pour-point depressants: The pour point of a lubricant is the temperature at which a lubricant becomes a semi-solid and no longer maintains its expected flow characteristics. Pour-point depressants enable a lubricant to flow at very low temperatures to prevent lubricant starvation to components; Corrosion/rust inhibitors: Internal metallic components are subject to corrosion in the presence of moisture and heat. Lubricant corrosion/rust Inhibitors serve to slow the corrosion process on internal surfaces.

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LUBRICATION

Table LU-2: ISO industrial lubricants viscosity grades. Ranges are listed in centistokes at 40°C. Grade 2

Minimum 1.98

Maximum 2.42

3

2.88

3.52

5

4.14

5.06

7

6.12

7.48

10

9.00

11.0

15

13.5

16.5

22

19.8

24.2

32

28.8

35.2

46

41.4

50.6

68

61.2

74.8

100

90

110

150

135

165

220

198

242

320

288

352

460

414

506

680

612

748

1,000

900

1,100

1,500

1,350

1,650

Lubricant properties

Viscosity is the measurement of a fluid’s resistance to flow and is the single most important property of a lubricant. Viscosity in any application determines the fluid film thickness to satisfy the type of lubrication. Viscosity is normally determined by measuring a fluid’s flow at a given temperature depending on the classifying body. International Standards Organization (ISO) viscosity grades: The vast majority of industrial lubricants have their viscosity specified by the International Standards Organization and are measured in centistokes (cSt) and normally at the reference temperature 40°C. ISO viscosities range from 2 centistokes to 3,200 centistokes as shown in Table LU-2. Society of Automotive Engineers (SAE) viscosity grades: Automotive engine and gear lubricant viscosities are specified by SAE grades. Each SAE engine and SAE gear viscosity range is different and should not be used as a comparison. SAE engine oil viscosities include 0, 5, 10, 15, 20, 25, 30, 40, 50 and 60. Multi-grade, or multi-weight, oils are referred to by a W following the cold start viscosity. For example, a 15W40 diesel engine oil has a viscosity in line with a SAE 15 at cold temperature startup. The multi-viscosity lubricants utilize additives called copolymers that expand as the equipment reaches full operating temperature. The effect of these copolymers is to change the viscosity of a lower-viscosity oil and enable it to have a viscosity of a higher SAE grade at full

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operating temperature. SAE gear oils are specified on a scale of 10 to 140 and are measured at 212°F. Multi-grades are also classified similarly to SAE engine oil ratings by giving both the winter and hot weight of the oil. Examples of common multi-viscosity grades include 80W90 and 85W140 for mineral SAE gear oils and 75W90 and 80W140 for synthetic SAE gear oils. Saybolt universal seconds (SUS): A less commonly used form of kinematic viscosity that is a measurement of a fixed quantity of a lubricant through a tube at a given temperature. Some OEMs still reference this as part of their specification when selecting an oil viscosity, and it is best to convert this specification to ISO or SAE when evaluating the correct oil viscosity to utilize. Figure LU-8 compares the scales of the different viscosity classifications. To use the chart, select a viscosity on a designated scale (ISO, SAE Engine, SAE Gear or SUS) and draw a line straight across. This will give the reference to other lubricants within other viscosity scales. Note that this does not ensure that another lubricant may be suitable because other factors, including additives, may not be appropriate for some applications. This chart compares the property of viscosity only and is only a tool to compare and identify possible suitable lubricants. Viscosity index is an indicator of how the viscosity changes with changes in temperature. As a lubricant cools it becomes less viscous, or thicker, and as it heats up it becomes more viscous, or thin. This is applicable across all lubricant types. However, the rate at which it becomes more or less viscous can have important implications to the fluid film thickness depending on our operations. Viscosity index is represented as a numerical number in which 95 is the lowest industry standard and increases up to 500+. In this scale, the higher numbers represent a fluid that changes at a slower rate with regard to temperature. Higher viscosity fluids thicken slower as temperature falls and thin slower as temperature rises. The table below provides a comparison of three different fluids with different viscosity indexes (Table LU-3). Table LU-3: Influence of Viscosity Index on rate of viscosity change. Fluid

Viscosity Index

Viscosity at 40°C

Viscosity at 100°C

Castrol Alpha SP 220 Mineral EP Gear Oil

95

220 cSt

18.7 cSt

Castrol Alphasyn EP 220 Synthetic PAO Gear Oil

140

220 cSt

25 cSt

Castrol Alphasyn PG 220 Synthetic PAG Gear Oil

235

220 cSt

39.7 cSt

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LUBRICATION Kinsmatic viscosities cst 40ºC

800

cst 100ºC

Saobolt viscosities

Grade systems ESO

AGMA

40

680

8

30

450

7

320

6

SAE Engine oil

SAE gearoil

SUS 210ºC

200

4000

150

3000 2500

600 500 400 350 300 250

20

220

5

15

150

4

100

3

68

2

200 150 100 80

10 9

60

8

50

7

40

6

30

20

5 4

46

1

150

125

50 40 30 20

15

15

10

10

50W 25W

1800

1500 1200

1000

80

800

70

600

55 50 45

40

combustion process, to cartridge or separator filtration for removal; • Neutralize acids created from the combustion in fuel sulphur, which can corrode internal piston liners, rings and valves. Although diesel engine lubrication technology has not changed significantly in some respects, there have been changes in several diesel engine-associated factors that are working to change this.

500 400 300 250 200 150

10W 5W

2000

90

60

15W

32 22

100

90

SUS 100ºC

LU–7

100 50 70 55

Figure LU-8: Comparative viscosity classifications.

As we learned above, for equipment to operate effectively, we need the proper lubricant fluid film to ensure separation of internal surfaces. This acceptable fluid film is normally a range where the viscosity enables sufficient flow between the surfaces and sufficient thickness to separate the surfaces. If an oil thickens too quickly as temperature falls, it could starve the internal surfaces of proper lubrication, resulting in increased wear, stress on internal bearings and reduced cooling capacity. When the oil becomes too thin, it no longer supports full separation of internal surfaces and results in increased wear. Selecting a fluid with the right viscosity index for your operations can ensure you have the right fluid film throughout daily and seasonal temperature changes.

Applications Engines

Diesel engines remain the heart of the vast majority of E&P operations and are relied on to generate the electrical power necessary to operate nearly all components involved in the drilling and production processes. Engine oil lubrication is designed to mitigate the stresses of the various components and reactions occurring during normal rotation and combustion process. The primary functions of diesel engine oil are to: • Lubricate internal bearings to minimize friction and wear; • Remove heat from combustion components, including pistons; • Remove contaminants from internal surfaces to facilitate proper lubrication of piston rings and cooling of piston under crowns; • Carry contaminants, normally carbon from the

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Significant reductions in global fuel sulphur content have changed oil stress by minimizing the need for higher total base number (TBN) additives to neutralize the sulphuric acid created from the combustion of fuel sulphur. However, this has led to increased stress on other aspects of the lubricant, as TBN is no longer a leading limiting factor in the condemning of diesel engine oils. Low engine loading conditions are also creating additional internal soot which places stress on engine oil detergents and dispersants. Changes to engine designs including increased horsepower-to-weight ratios, fitting of exhaust after treatment and increased use of turbochargers are further creating stresses on other components of the oil.

Hydraulics

Hydraulic systems fluids are designed to facilitate mechanical functions and transfer of power through fluid flow under pressure. The hydraulic system utilizes a number of key components including, a reservoir, pumps, directional valves, relief valves, actuators, heat exchangers, pipes, hoses, accumulators and filters to transmit force into a mechanical action. Modern rig designs have increased the utilization of hydraulics in many applications of the drilling rig systems including valve control, materials handling, dynamic positioning, top drives and Blow out Preventer applications. The reliable and efficient transmission of power is dependent on a variety of factors including the proper viscosity to transmit power at desired rates, the correct fluid type to ensure proper protection of internal system components and the right filtration to maintain an acceptable level of fluid cleanliness. Hydraulic components are highly susceptible to internal damage from contamination due to the small component tolerances, pressures and duty cycles of the system. The vast majority of component failures, over 75%, can be attributed to system contamination from either moisture or particulate. Viscosity selection is primarily a function of system design, pump type and operating temperatures to achieve the correct flow of hydraulic oil to system actuators. Selecting a viscosity which is too low can risk damage to system com-

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LU–8

LUBRICATION

ponents by not providing a sufficient fluid film and too high of a viscosity may cause slow response times and potential damage from cavitation. Cavitation occurs when vapor voids are created due to restricted inlet flow at the pump inlet. As pressure increases the vapor void implodes causing a shock which can damage internal system surfaces. Hydraulic system cleanliness is imperative on attaining the maximum life of system components and the hydraulic fluid. Fluid contaminants wear internal component surfaces and, in some severe cases, particles can block servo or spool valves causing system inoperability and catastrophic failure to these components. Additionally, this wear and particulate movement through the fluid also generates heat which impacts the life of the hydraulic fluid as heat contributes to fluid oxidation. Maintaining a cleanliness level at or better than OEM or industry standards can extend system component and fluid life by several multiples compared to current operating conditions. When evaluating hydraulic fluid cleanliness there are four primary elements to maintaining the proper cleanliness level in hydraulic systems and are: • Utilization of the correct installed filtration – Most hydraulic • Use of good lubricant transfer practices when filling system reservoirs • Use of Desiccant Breathers and/or reservoir vent filtration to minimize the ingress of moisture and particulates • Utilization of secondary installed filtration or external filtration • Finally, the fluid type is of critical importance as the fluid needs to meet several key system design and operating properties including: • OEM Specification • Viscosity Index requirements • Excellent Oxidation Resistance • Anti-wear for protection of internal components

• • • • • • •

Good air release properties Good water separability properties Good shear stability Excellent filterability Seal compatibility Environmental performance where required Fire resistance for high temperature application

Gears

The lubrication of gears has an important role in oilfield operations as the loading profiles and duty cycles have increased significantly. The fundamentals of gear lubrication come down to a few different concepts including: Gear design: Different gear designs present different lubricant needs depending on the orientation and forces on the gears. Gears can transfer power directly in line with the gears or have thrusting loads as they transfer power. Gears can also transfer power at right angles, which may require gear designs and lubricants that can accommodate slide forces between the gears. Some gear designs, such as worm gear drives, may have yellow metal components that require specific lubricant types to avoid surface corrosion from the extreme pressure additives in traditional EP gear oils. Gear loading: The loading profile, including both force and shock loading, has created a need for additional lubricant base oils and additives to handle exceptionally high loads. For extreme loading conditions, the oil film is mostly displaced from between the gear teeth, forcing the extreme pressure additives on the surface to carry more of the load of the gears. Excessive shock loading may require additional solid additives to absorb the shock loads and avoid surface fatigue of the gear surfaces. The most common form of surface fatigue is micro-pitting, which is observed in applications such as high-pressure mud pumps.

Table LU-4: AGMA to ISO gear oil scale. Viscosity ranges for AGMA Lubircants Rust & Oxidation inhibited gear oils AGMA Lubricant #

Extreme Pressure gear lubricants AGMA Lubricant #

Synthetic Gear Oils AGMA Lubricant #

ISO Equivalent grade

0

0S

32

1

1S

46

2

2 EP

2S

68

3

3 EP

3S

100

4

4 EP

4S

150

5

5 EP

5S

220

6

6 EP

6S

320

7, 7 Comp

7 EP

7S

460

8, 8 Comp

8 EP

8S

8A Comp

8A EP

9

9 EP

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680 1000

9S

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1500

LUBRICATION

LU–9

Table LU-5: NLGI grease grades.

NLGI Grade

Worked Penetration at 77°F (25°C) mm/10

Application

Description

000

445 to 475

Semi-fluid

Softest grease. Just enough thickener to keep the oil from running out. Gear case lubricant.

00

400 to 430

Very soft

Gear case lubricant.

0

355 to 385

Soft-grease gun

Low temperature handling in centralized lubrication systems.

1

310 to 340

Grease gun

Needle and multiple row roller bearings. Number 0 and 1 greases generally are used for low-temperature operation in centralized lubrication systems.

2

265 to 295

Grease gun

Ball and roller bearings, moderately loaded and mediumspeed applications. Most common grease grade for general purpose greasing.

3

220 to 250

Grease cup

Wheel bearings, precision and high-speed use. Pre-lubed ball bearings, double-sealed and double-shielded type.

4

175 to 205

Grease cup

High-speed, lightly loaded applications. Water-pump grease.

5

130 to 160

Grease cup - Brick type

Very stiff grease. Also used in high-speed and valve applications. Rarely used in modern equipment

6

85 to 115

Brick grease

Solid-type grease. Pillow-block lubrication. Rarely seen in modern equipment.

Gear Oil Standards: Although some OEMs still list specific oils approved for use, many gear OEMs utilize different gear lubrication standards such as the American Gear Manufacturer’s Association (AGMA), ISO or API GL(Table LU-4).

lower base-oil viscosity. Likewise, additives such as rustand oxidation-inhibitors, extreme-pressure additives and solid lubricants are used in greased applications with similar operational demands as traditional lubricants.

Greased applications

The consistency (hardness) of a grease is graded by the penetration of a weighted cone into the surface of the grease. The NLGI has established a set of standards based upon penetration limits to indicate the various consistency grades (Table LU-5).

Greased applications remain one of the most challenging applications to lubricate for several different reasons. This is in part because many operators do not fully understand the fundamentals and challenges of greasing various component types. To better enable and understand we must first understand what a grease is and the primary components of its formulation. A lubricating grease is a fluid oil lubricant in combination with a thickening agent that produces a plastic-like material and is used in areas where fluid oil lubrication is mechanically unsuitable. The thickener acts like a sponge to hold the lubricant and additives in the right place to lubricate the internal components. Grease comprises three major components: the base oil, additives and the thickening agent. The major constituent of grease is the lubricating oil, which represents approximately 80-85% of the grease. The thickener represents 7-12% of the remaining product and additives the remaining content. The considerations of grease selection with regard to base oil viscosity and additives are very similar to those of traditional lubricants. Slower-speed applications normally utilize a higher base-oil viscosity and higher-speed applications a

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The first challenge of greasing is that there is not a visual or measurable indication of the grease condition or quantity inside of greased applications. Unlike most traditional lubricated applications, there are no fill levels for validation. Furthermore, grease distribution is a function of system design and proper greasing techniques to ensure the grease is fully distributed. Greased systems also rely on specific procedures to pregrease or fill bearings or components prior to assembly and shipping. Failure to properly grease prior to assembly or commissioning may not be noted by equipment operators during the commissioning and early part of the equipment’s life cycle. This period is critical, as improper greasing of new bearings can cause unrepairable damage which significantly reduces the bearing life. Greased systems may also have limited lubrication points that can make full distribution of new grease challenging if operators do not understand these limitations.

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LU–10

LUBRICATION

Calcium Complex

Calcium Sulphonate

Clay

Lithium Stearate

Lithium 12 Hydroxy

Lithium Complex

Polyurea Conventional

Polyurea Shear Stable

Aluminum Complex

Calcium 12 Hydroxy

Borderline

Calcium Stearate

Incompatible

Barium Complex

Compatible

Aluminum Complex

Table LU-6: Grease thickener compatibility chart. In addition to considering thickeners, attention should also be paid to additives. To assure additives are compatible, check with the lubricant manufacturer.

I

I

C

I

B

I

I

I

C

I

C

I

C

I

C

I

I

I

I

I

B

C

I

C

C

C

B

C

I

C

B

B

C

C

C

C

I

C

I

I

I

I

C

C

C

I

B

B

C

I

C

I

I

I

I

B

C

C

I

C

C

I

C

I

C

Barium Complex

I

Calcium Stearate

I

I

Calcium 12 Hydroxy

C

C

C

Calcium Complex

I

I

I

B

Calcium Sulphonate

B

C

C

B

I

Clay

I

I

C

C

I

I

Lithium Stearate

I

I

C

C

I

B

I

Lithium 12 Hydroxy

I

I

B

C

I

B

I

C

Lithium Colmplex

C

I

C

C

C

C

I

C

C

Polyurea Conventional

I

I

I

I

C

I

I

I

I

I

Polyurea Shear Stable

C

B

C

C

C

C

B

C

C

C

C C

In addition to the challenges above, there are also a number of aspects of different greases that have a significant impact on the compatibility between two greases. While we still focus on the base oil and additive compatibility, we must also evaluate the impact to the thickeners when mixed with other greases. The mixing of incompatible thickeners will compromise the primary function of a grease by holding and distributing the lubricant in the bearing. Incompatibilty between thickeners will cause either the hardening or softening of the thickener which will lead to starvation of lubricant to the bearing and wear. See Table LU-6.

current program should be completed. It would also be helpful to consult a lubrication professional to review your program and provide objective feedback on strengths, weaknesses and opportunities. The particular need for an outside assessment is that the current status of lubrication program is the output of the experience and perceived needs of the members of the organization. A new set of eyes, and someone with experience beyond your particular organization, can have a fresh perspective and view of other successful industry practices that may be a good fit and value- driver for your program.

Lubrication Program and Practices

This review should encompass not only a review of the procedures and equipment status, but an evaluation of the Lubricant Culture of the organization. Lubricant Culture will focus on the values and behaviors of all levels of the organization regarding lubricant-related activities. This can encompass all levels including Management, Procurement and Maintenance. An evaluation of the relationship with the lubricant and lubricant service suppliers can also be helpful to determine if their culture adds value to your operations.

Introduction

The fundamentals of a lubrication program for E&P organizations and operations comprise a systematic approach to lubrication that encompasses the entire life cycle of lubricated applications. These fundamentals are meant to provide the necessary focus, management commitment, procedures and resources to the lubrication program, as there is significant value to be realized when the program is implemented correctly.

Lubrication program baseline

Before any actions are taken in developing or fine-tuning an organizations lubrication program, a full assessment of the

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Goals of a lubrication program

Following the baseline evaluation of the lubrication program, there should be some realistic goals of further development of the program. With the increased availability of lubrication tools, resources and guidance, there are a number of oppor-

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LUBRICATION tunities for every customer. A few of the main goals that are normally part of any program typically fall into one of the categories below: • Reliability: Equipment downtime is very costly, particularly when it is unplanned, so equipment reliability becomes one of the most common goals of any lubrication program. Equipment reliability should be compared to OEM normal expectations when good routine maintenance practices are employed. Through proper utilization of lubricants, the exceeding of OEM overhaul periods is becoming more prevalent and achievable; • Standardization: Standardization can be applicable to many different aspects of lubrication, including processes associated with lubricant selection, utilization and review of effectiveness. Every organization has standards with regard to lubrication but may have variations from worksite to worksite that may include use of different oil types, different oil suppliers, different storage and handling procedures and different focuses regarding the utilization of lubricants; • • Reduce life cycle costs: Goals associated with reducing life cycle costs include, but are not limited to, extended overhaul intervals, extended oil drains and reduced manpower costs; • • Lubricant culture development: Perhaps the most important goal to consider is the development of the lubricant culture, which focuses specifically on the advancement of the processes and behaviors associated with the utilization of lubricants within an organization’s operations; • An entrenched approach to lubrication is still very common in most industries despite increasing competency of the understanding of lubrication and the opportunities. Time-based change intervals, failure to utilize oil analysis in an effective manner, poor handling, significant contamination and failure to achieve reasonable equipment life targets are all signs that the lubricant culture may not be penetrating through all levels of the organization; • Developing the lubricant culture is nothing that changes overnight, so expect this to be a longerterm goal. A good lubricant culture takes a commitment from the highest levels of the organization down to the lowest levels. The necessary support and resources need to be employed to ensure that the necessary education, procedures, personnel and equipment are in place to move from a “reactive” lubricant culture to a proactive one.

Lubrication opportunities

From the lubrication program assessment and review of goals should come a list of lubricant opportunities that are a

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LU–11

combination of the opportunities that will have the biggest impact and ones that could be quick wins. When reviewing opportunities that will have the biggest impact, consider all impacts such as financial, manpower and reliability to the operations. Resolving problems can demonstrate the value and positive contribution that effective lubrication can contribute to an organization. This approach will facilitate a better appreciation and focus within the organization’s maintenance group, leading to a greater discipline and positive attitude in conducting lubrication-related activities.

Lubrication survey

The lubrication survey is the primary control document to document every lubricated component at a worksite. It is one of the most important tools in managing lubricant activities, as it provides guidance to field personnel regarding what products to lubricate equipment with. The Lubrication Survey is a “living document” and evolves as the worksite changes equipment, operating area or operating condition. In addition to making changes as they arise, it is best practice to review this document at least every two years to validate that all components and lubricants remain valid. This document should be controlled by a single person to avoid any unauthorized changes. The lubrication survey should capture all important details of each lubricated application including: • Component name; • Component OEM and model; • Lubricant in use; • Component lubricant capacity; • Component sampling identification name; • Component sampling frequency.

Lubricant suppliers

There are differing levels of opportunities that may exist from different lubricant suppliers. These can include the lubricant manufacturer and the lubricant distributor. Most lubricant manufacturers no longer maintain a staff and fleet resources to deliver the lubricant to the end user, but instead rely heavily on a network of third-party lubricant distributors. These distributors are relied on to store, repackage, filter and deliver lubricants in the manner prescribed by the customer. Lubricant distributors, as an authorized agent for the lubricant manufacturer, may have the flexibility to customize their approach to supplying a customer’s needs, but they also have limitations, as they have some firm procedures to follow specified by the lubricant manufacturer. When considering a lubricant provider, note that there are no two lubricant providers that provide the same service. This can include a number of different factors, and considering the five “rights” of lubrication can be a tool to help evaluate which lubricant provider is best for your needs.

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LU–12

LUBRICATION

• Right price: Price is a key component, but different prices can be evident if suppliers propose different lubricant types; • Right product: The correct product is necessary to properly lubricate equipment. This right is without exception, and a supplier should be able to supply products that meet your component and operating demands; • Right packsize: The right packsize provides the balances the needs of product quality, limitations on storage and safety of transfer. Package sizes that are well in excess of what one could use over 12-18 months deterioration beyond the point of usability. Package sizes should also be appropriate for safe handling, including the use of bulk storage containers, such as offshore totes, which are safer to handle than multiple drums; • Right location: It is also imperative that the supplier has the products you need in the location you need them. In emerging markets where there is limited supply from most or all suppliers, it may be necessary for the customer to coordinate their own logistics as a matter of reality. Your supplier, however, should be able to assist in providing the most efficient, reliable and effective route to market; • Right service: Selecting a lubrication supplier with the right service can add significant value, depending on the availability of internal lubricant expertise and the effectiveness of the organization’s lubrication culture. There are a number of service opportunities which a Lubricant Supplier can provide, including: • Technical assistance on lubricant selection; • Lubricant rationalization; • Review of lubrication practices; • Review of lubrication storage; • Lubricant training; • Development of a management of change protocol; • Used oil analysis; • OEM interface; • Root cause failure analysis.

Management of change (MOC)

Any change within an organization should be a managed process that includes a full evaluation of the proposed change and a detailed plan to execute this change. This should be completed for any change in lubricant for any application. For simplicity, most OEM recommendations surrounding lubricant viscosities are communicated based on ambient air operating conditions. It is important for operators to pay particular attention to the temperature bands reflective of the annual seasonal changes. The selection fot he right lubricant and viscosity should ensure the lubricant meets the service requirements specified by the OEM over this entire temperature range. In extreme changes of temperature, a

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change to a different oil viscosity may be required. Training is the single most effective way to improve your lubrication program and develop the culture that is desired. All personnel that manage, procure or handle lubricants should be participants in a level of training surrounding lubrication. A part of this education should also include an overview of the organization’s lubrication program, program goals and commitment to achieve these goals. An effective training program will be quickly noted on the bottom line. Training resources are available from a number of areas, including lubricant supplier technical representatives, professional publications, professional certifying groups and independent professional lubrication consultants. These resources are highly effective and can range from providing very basic-level training to more advanced training, which can also lead to attaining a professional lubrication certification.

Fluid conditioning & contamination control

Fluid conditioning is an expanding practice in offshore lubrication management programs with the goal of extending equipment and lubricant life through effective contaminant removal. Increased availability of advanced filtration equipment along with improved lubricant blending technology has enabled the effective filtration of contaminants without stripping the lubricant of key additives. The vast majority of contaminants in lubricated components fall into three primary categories, particulates, moisture or process fluids. Particulates represent the most prevalent form of contamination in lubricants, but can be the easiest to resolve. While most installed filtration is adequate to deal with contamination from normal operations, it can easily become overwhelmed and ineffective when excessive contamination is introduced. Improvements in installed filtration and external filtration units has significantly improved the operators ability to manage excessive contamination at the worksite. The financial benefits in reduced maintenance costs, extended component and fluid life are well documented and has enabled several operators to justify the installation of permanent advanced filtration units on key components. Additionally, use of pre-delivery filtration services for new oils has enabled both the effective commissioning requirements of Turbine and Subsea component manufacturers but served a benefit for the continual operation of other components as well. Particulate contamination is normally a key part of used oil analysis for critical components which may have close tolerances between internal components. Common applications for this type of analysis include turbines, hydraulic systems, bearings, pumps, and valves. Particulates are evaluated

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LUBRICATION

Table LU-7: NAS 1638 particulate count reference scale. NAS 1638 Cleanliness Level

Maximum Particulate Count per size range

LU–13

Table LU-8: ISO 4406:1999 particulate count reference scale. Source: ISO 4406. Number of particles per milliliter

ISO 4406 Scale Number

5-15 μ

15-25 μ

More than

0

250

44

1

500

89

2,500,000

2

1000

178

3

2000

356

4

4000

712

5

8000

1425

6

16000

2850

7

32000

5700

8

64000

11400

9

128000

22800

10

256000

45600

11

512000

91200

2,500

5,000

19

182400

1,300

2,500

18

12

1024000

and reported by size ranges via two primary standards, the National Aerospace Standard (NAS) 1638 (Table LU-7) or International Standards Organization (ISO) 4406:1999 (Table LU-8). These methods break down the particulate counts by specific size ranges to help operators understand the potential damage to systems with known internal clearances. Although the NAS 1638 standard is still utilized by some operators and OEMs, the ISO 4406:1999 is becoming the preferred standard particulate test as it further stratifies the particulates into three distinct key micron size ranges of 4μ, 6μ and 14μ. The NAS 1638, however, only evaluates two ranges which are 5-15μ and 15-25μ. Because the ISO 4406 goes into a greater level of detail it would be recommended to standardize to this standard. OEM or maintenance system references can easily be converted utilizing the conversion chart below. OEM or maintenance system references can easily be converted from NAS 1638 to ISO 4406 utilizing the conversion chart (Table LU-9). The next step in particulate contaminate control is to establish the target cleanliness levels for each component. Target cleanliness levels can sometimes be established by the OEM for critical components, but operators may have to further evaluate the opportunities and risks for other components which should be part of the contaminant monitoring program. Some considerations in this process should include component sensitivity, duty cycle, downtime costs, replacement costs and component life expectancy. These variables should be considered against the costs to achieve various cleanliness levels to find the right balance for the component and operations. The second most significant source of contamination is moisture which can come numerous sources. However, installed filtration is normally cartridge type filters which have no or little effect on the removal of moisture. Exces-

IADC Drilling Manual

Up to and including

>28

1,300,000

2,500,000

28

640,000

1,300,000

27

320,000

640,000

26

160,000

320,000

25

80,000

160,000

24

40,000

80,000

23

20,000

40,000

22

10,000

20,000

21

5,000

10,000

20

640

1,300

17

320

640

16

160

320

15

80

160

14

40

80

13

20

40

12

10

20

11

5

10

10

2.50

5.00

9

1.30

2.50

8

0.60

1.30

7

Table LU-9: NAS 1638 to ISO 4406 conversion chart.

Conversion of NAS 1638 scale to ISO 4406 NAS 1638 Cleanliness Level

ISO 4406 Cleanliness Level

0

12/9/2006

1

13/10/7

2

14/11/8

3

15/12/9

4

16/13/10

5

17/14/11

6

18/15/12

7

19/16/13

8

20/17/14

9

21/18/15

10

22/19/16

11

23/20/17

12

24/21/18

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LUBRICATION

sive moisture can also cause significant damage to internal filters, reducing their ability to effectively remove particulate as well. Because of the challenges of moisture on internal components and filtration, the use of a filtration system designed to handle moisture is recommended. Although removing the source of the moisture is the most effective solution, it is not always a design or operational reality. So the use of coalescing type filters or vacuum dehydrators may become a necessity to manage the moisture to a reasonable level. The contamination of process fluids is a bit more challenging as chemicals or oils can easily mix and contaminate the lubricant. The removal of this type of contamination is cost prohibitive, would have to be completed at a shore based facility and may not even be possible. In the cases of contamination from process fluids it is best to control the source, flush the component and refill.

Lubricant storage and handling

Lubricant storage and handling have a significant impact on the quality of lubricants that will be put into various components. Because some applications, such as turbines and hydraulics, have very tight internal tolerances, it is critical to ensure new lubricants remain clean, dry and free of contamination in storage and when transferred. Improper storage increases the potential for contamination to enter equipment, as moisture and particulates can enter through container or tank vents or access points. Lubricants that have high-demand volumes for the operations should be stored in storage tanks that are hard-piped directly to the equipment sumps if possible. Drum- and pail-packaged products should be stored in an enclosed space to avoid the intrusion of moisture or particulate and exposure to direct sunlight. All storage, fluid transfer equipment, and fill points must be tagged and labeled. New (neat) fluids should be sampled by a laboratory on arrival to verify cleanliness and to establish baselines. Since most fluids are not delivered “ISO Clean”, the product should always be filtered before adding it to the equipment’s reservoir. Product bulletins and MSDS sheets should be accessible to all users. Lubricants should be transferred with the understanding that contamination can come in the form of particulates that collect in transfer equipment (pumps and fill containers) that may not have secure lids or in the form of cross-contamination from lubricant residue. Transfer containers should contain lids that prohibit the collection of airborne particulate. Additionally, containers should be used for each fluid type to ensure that there is not any contamination from additives from the residue of another lubricant that may not be appropriate. These product groups include engine oil, zinc-free engine oil, hydraulic oil, gear oil, and automatic

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transmission fluids. Transfer pumps should also be dedicated for each product group if feasible. If this is not possible, then a flushing procedure should be executed for each time the pump is used. Shelf life of packaged lubricants is another common issue with lubricant storage, as there are a number of packaged lubricants on a worksite that may be past the fluid’s usable life. Each product is manufactured with a limitation as to how long it will meet the advertised performance. This limitation is a function of many factors including time, fluid type and storage conditions. Over time, lubricants can be subject to the additives gradually falling out of suspension and oxidation of the base oil. Specific fluid types of fluids can also have different usable life, as each base fluid has different limitations. Finally, the conditions of where the lubricant is stored have a big impact, as exposure to moisture and heat can further degrade the fluid. Each product is manufactured with a specific date of manufacture, and most usable lubricant life is between 2-8 years, depending on the product and storage conditions. Contact your lubricant supplier to make sure you have an understanding of the anticipated life of the product if you have questions or concerns.

Used oil analysis

A key component of any Reliability Program is an effective Used Oil Analysis Program. Used oil analysis should be used to support and validate the operational condition of a component and the suitability of the lubricant to support the operational condition. There are four different ways to conduct an evaluation of the fluid and each method has unique opportunities and challenges with regard to the timely and accurate review of a lubricant’s and components operational condition. Additionally, different means of testing may only provide raw data requiring interpretation, either at the worksite or through an experienced fluid-condition analyst. 1.

Visual analysis: A visual analysis is a useful tool that should be utilized for oils to identify serious levels of contamination. For clean oils, such as hydraulic or turbine oils, the presence of small quantities of water or visible particulate can be easily observed in the sample. The presence of water in hydraulic or turbine oil samples causes the sample to appear hazy. For higher-viscosity oils, such as engine or gear oils, it can be helpful to let the samples settle for twelve to twenty-four hours to see if there are any layers of contamination that have settled out of the sample. Excessive moisture in gear or engine samples can give the oil a milky appearance. 2. Laboratory used oil analysis: The sampling of used lubricants at a shoreside laboratory location is the core part of most reliability programs. This level of analysis utilizes the correct testing equipment and methods to

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LUBRICATION attain accurate results for a variety of key lubricant parameters and is also interpreted by an experienced lubricant professional. 3. Worksite Used Oil Analysis: Significant advancements in onboard used oil analysis equipment have simplified onboard testing with improved accuracy over previous onboard test kits and can provide immediate test results with a decent level of accuracy. This type of testing is recommended for use in operational locations where there is a poor availability of shore-side used oil analysis services or if there are very long logistics options to get samples to a reliable testing facility. Some testing devices utilize software to store and trend the test data for better operator review. The use of this equipment requires a level of understanding on interpretation of results into maintenance actions. However, onboard testing equipment should only be used to enhance, not replace laboratory testing. 4. Real-time installed sensors: Advancements in sensor technology and demands for better real-time information have increased the use of sensors to evaluate oil conditions such as water content, particulate content, etc. The use of these sensors can be valuable in critical components such as thrusters and turbines to receive sufficient advanced warning of potential lubricant or component failure. Although this technology can be useful in a number of applications, it is very costly and may not provide value in less critical or sensitive applications. Despite the ability to provide critical analysis of the lubricant real-time, laboratory oil analysis should still be conducted to validate all parameters of the lubricant’s condition.

Used oil analysis service selection

When evaluating and selecting a service which meets your operational needs, it is important to also evaluate what the laboratory can do for your operations as your lubrication culture matures. There are a number of different providers which offer a variety of services, but the goal is in selecting the service which is right for you and your operations. 1.

Develop a list of three or four labs to evaluate as part of the process. Speak with lubricant professionals or peers at other organizations to see what opportunities may be available. Visit the labs to engage in a discussion on their operations and what opportunities may be appropriate for your organization, including setup, test suites, sample processing times, reporting, lab qualifications, advanced testing and training. The lab culture should be in line with the culture of your maintenance program and also facilitate growth to where you want your program to be in the future. When visiting any laboratory verify the quality control methodology that is place by visiting each work station, view the documentation at the work stations and query the technicians knowledge. Additionally, ask for the safety stats for that individual laboratory as well as the documentation of any audits done in the last 12 months. 2.

3.

Select test suites for each component type that will provide the level of information needed to evaluate component and oil stress. Availability of advanced testing may also be appropriate for conducting expanded evaluation of oils in critical applications. Testing such as analytical ferrography can be useful in identifying contamination sources and the severity of contamination beyond traditional particulate testing methods. Select a delivery format that communicates results in a way that is understood by operators and adds value to maintenance decisions. Evaluate the reporting formats and web-based platforms of different providers to see what opportunities may be available. If operations are international, consider a multi-lingual service to help facilitate a clear understanding with all staff.

Try to select only one provider, if possible, to establish consistency in your reliability program. Some laboratory providers now offer a network of global labs that can help standardize the testing and reporting to provide a consistent level of service. Another option is to consider is sending all samples from global operations to a single processing point to ensure consistency in testing and interpretation.

Review the equipment to be sampled and the testing frequency to determine the necessary scope of service.

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LUBRICATION

APPENDIX: DEFINITIONS Additive: A chemical added in small quantities to a petroleum product to enhance particular properties. AGMA: American Gear Manufacturers Association. One of their activities is to establish and promote standards of gear lubricants on an industry-wide basis. API: American Petroleum Institute. A society to further the interests and standards of the petroleum industry. Some of the API projects have been the crankcase oil service classifications and drilling industry thread compounds. ASTM: American Society of Testing Materials. An organization devoted to “the promotion of knowledge of the materials of engineering, and the standardization of specifications and methods of testing.” Many of the current petroleum product tests are in accordance with ASTM test standards. Anti-seize compound: A grease-like material containing powdered metals or metallic oxides, frequently applied to threaded joints to facilitate separation and to prevent seizure. Ash content: In lubricating oils, generally referred to as “sulphated ash.” Represents the non-combustible residue, usually due to the presence of metallic additives. The choice of engine crankcase oils in some cases is dependent on the sulphated ash content of the oil. Demulsibility: The separation of an oil/water emulsion. Lubricants with good demulsibility qualities will rapidly separate from water when the mixture is at rest. Dropping point: Lowest temperature at which a grease becomes sufficiently fluid to drip under a particular ASTM test. Has only limited significance to service performance. Gear oil (industrial): High-quality oil for gear cases. Performance levels typically specified by AGMA lubricants numbers. Where EP properties are not required, turbine oils with rust and oxidation inhibitors are generally recommended. For worm gears and heavily loaded gear cases, and EP-type gear oil, different from automotive gear oils are used. Industrial EP gear oils should not be used in automotive service.

Oxidation stability: The resistance of a petroleum product to oxidation. Used as an indication of the service life and storage life of lubricants. pH: A measure of acidity or alkalinity. Used to evaluate the condition of used oils. Pour point: The lowest temperature at which anoil will start to flow. Of limited use in determining cold weather capabilities of an oil, but often used as an indicator. SAE grades: Viscosity grades of both crank-case oils based on kinematic viscosity measurements. Saybolt universal seconds (SUS or SSU): The reported viscosity of a given oil at a given temperature as determined in a Saybolt viscosimeter. This method of determination has been largely superseded by kinematic systems where the unit is the stoke or centistoke. Turbine oil: Top-quality rust- and oxidation-inhibited oil used for long-service or exacting applications. Viscosity: Measure of a fluid’s resistance to flow. It is usually expressed in terms of the time required for a standard quantity of fluid at a specified temperature to flow through a standard orifice. The higher the value, the more viscous the liquid. Viscosities of petroleum oils are commonly reported in Saybolt Universal Seconds (SUS or SSU). Kinematic viscosities are reported in centistokes (Cs). European systems include Redwood and Engler, all of which can be related to Saybolt Universal Seconds. SAE, ASTM and AGMA have established viscosity grades that have been recognized throughout the industry. Viscosity index (VI): The measure of the rate of change of viscosity within a given temperature range. A lubricant with a low viscosity index changes in viscosity faster with temperature compared to a lubricant with a higher viscosity index. Highly refined mineral and synthetic lubricants have higher viscosity indexes than most.

Grease: An oil lubricant in combination with some thickening agent to produce a plastic-like material, used where fluid oil lubrication is mechanically unsuitable. Common thickening agents are various metallic soaps, silica gel, silicones and clay. The major component of the grease is the lubricating oil, while the thickening agent allows the lubricant to remain in a semi-fluid state.

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MANAGED PRESSURE, UNDERBALANCED AND AIR/GAS/MIST/FOAM DRILLING

IADC Drilling Manual 12th Edition IADC Drilling Manual • Copyright © 2015

Enhancing operational integrity by ensuring a competent workforce

Accreditation & Credentialing

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CHAPTER

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MANAGED PRESSURE, UNDERBALANCED AND AIR/GAS/MIST/FOAM DRILLING

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. PRINCIPAL AUTHORS Don Hannegan, P.E., Weatherford George Medley, P.E., Signa Engineering Bill Rehm, Drilling Consultant Reuben Graham, Weatherford

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MANAGED PRESSURE

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9915095-6-0

Printed in the United States of America.

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MANAGED PRESSURE Contents CHAPTER MP

MANAGED PRESSURE, UNDERBALANCED AND AIR/GAS/MIST/FOAM DRILLING Introduction................................................................... MP-1 Air, gas, mist and foam drilling......................... MP-2 Underbalanced drilling......................................... MP-3 Managed pressure drilling.................................. MP-3 Variations of managed pressure drilling........ MP-3 Deepwater applications of MPD......................MP-5 IADC UBO/MPD committee Technical support.............................................MP-5 Key enabling equipment......................................MP-5 Managed pressure drilling..........................................MP-5 Continuous circulating devices................................. MP-7 Constant bottomhole pressure................................. MP-7 Constant bottomhole pressure/bottle-up (or trapped) pressure......................................... MP-7 Constant bottomhole pressure/backpressure control....................................................MP-8 Dual-gradient drilling..................................................MP-8 Dual-gradient subsea pump.............................MP-8 Controlled annular mud level...........................MP-8 Mud line pumping (Riserless)..........................MP-9 Dual-gradient/mix fluid using gas..................MP-9 Dual-gradient/mix fluid using liquid..............MP-9 Mud cap drilling...........................................................MP-10 Floating mud cap drilling.................................MP-10 Pressurized mud cap drilling...........................MP-10 Other MPD techniques............................................MP-10 RCD only................................................................MP-10 Enhanced kick/loss detection only................MP-10 Constant bottomhole pressure/backpressure control using gas injection..............MP-11 Equivalent circulating density Reduction tools....................................................MP-11 ECD control: Concentric drill pipe..................MP-11 Common MPD equipment components.............MP-11 Rotating control devices....................................MP-11 Returns flow path................................................MP-11 Chokes/manifolds...............................................MP-11 Flow meters...........................................................MP-12 Auxiliary pumps...................................................MP-12 Gas busters/separators.....................................MP-12 Drill string float valves.......................................MP-12 Underbalanced drilling.............................................MP-12 Introduction.........................................................MP-12 Why drill underbalanced?...............................MP-13

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MP-iii

Contents Designing and planning an underbalanced drilling well.............................MP-13 Impact of UBD operations on regular rig personnel........................................................MP-14 Rotating control devices...................................MP-14 Drill string non-return valves (NRVs or floats).................................................MP-15 References............................................................MP-15 Air/gas/mist drilling..........................................MP-15 Why drill with air/mist?...................................MP-16 Typical air drilling problems............................MP-17 Wet hole...........................................................MP-17 Mud rings.........................................................MP-17 Key seat and dropped pipe.........................MP-17 Downhole fire..................................................MP-17 Shale, oil shale, gilsonite, coal and other common formation problems................................MP-17 Air volume requirements.................................MP-18 Mist drilling rules...............................................MP-18 Corrosion problems and solutions................MP-18 Drying a wet hole...............................................MP-18 Foam drilling........................................................MP-19 Introduction.........................................................MP-19 The history of foam.......................................MP-19 Foam, mist and in between........................MP-19 The advantages of foam..............................MP-19 Typical foam drilling problems...................MP-20 Gas volume fraction......................................MP-20 Water volume (liquid volume)...................MP-21 Gas volume......................................................MP-21 Corrosion issues.............................................MP-21 Operational considerations.............................MP-21 One-pass system.................................................MP-21 Recycle foam.........................................................MP-21 Air hammer drilling...................................................MP-21 Limits to the air hammer.................................MP-22 Air/gas directional drilling........................................MP-22 Primary equipment for foam gas drilling.............MP-22 Surface air lines and the blooie or flow line....................................................................MP-23 Blooie or flow line..............................................MP-23 Sample catching.................................................MP-23 Airline manifold..................................................MP-23 References............................................................MP-23

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IADC Safety Toolbox Essential safety alerts and other tools for the crew on the rig floor

IADC SAFETY TOOLBOX

DESIGNED TO SHARPEN SAFET Y SKILL S Sharpen your safety skills with the new IADC Safety Toolbox. Available at no charge at www.IADC.org/safety-toolbox, the searchable IADC Safety Toolbox provides easy access to key IADC safety information, including safety alerts, safety meeting topics, near miss/hit forms, safety posters and more. The IADC Safety Toolbox is easy to use. Users can narrow their search by type of operation (rigging up, lifting, etc), incident classification (LTI, equipment damage, etc.), body part, location (rig type, etc.), incident type (slip, etc.) and equipment. The Online Safety Toolbox provides a practical, user-friendly resource that will seamlessly integrate into daily drilling operations. Contents include: • 700 IADC Safety Alerts; • 125 Safety Meeting Topics for JSAs or other meetings; • Near Miss/Hit Report forms for both drilling and well servicing/workover; • 60 IADC Safety Posters. The Online Safety Toolbox puts critical safety related tools and resources directly in the hands of the rig crew, and is one of several IADC initiatives aimed at enhancing safety in the industry. Access it today!

www.iadc.org/safety-toolbox

MANAGED PRESSURE

Introduction

Depending upon the subsurface characteristics of a specific well, the challenges to drilling with a conventional mud system whose annulus returns are open to atmosphere may include: • • • •

• • •

•

•

Slow rate of penetration (ROP); Excessive drilling fluids cost; Excessive non-productive time (NPT); Well-control scenarios associated with drilling hazards such as kicks, losses, differential sticking and ballooning phenomena; Prospect being deemed un-drillable for economic, safety or technical reasons; Reservoir damage due to mud and cuttings evasion; Hydrostatic pressure due to the column of fluid in the annulus causing mud losses requiring an excessive number of casing strings, especially in deep water; Situations where the safe mud-weight window between the well either flowing or falling in and losing returns is very narrow; Need to characterize the reservoir while drilling.

This chapter discusses drilling methods in the order each became generally accepted for their ability to mitigate these and other challenges to conventional overbalanced drilling operations (UBO): air, mist, foam drilling, underbalanced drilling (UBD) and managed pressure drilling (MPD). In most cases these drilling methods are practiced with the support of service contractors who provide the location with applicable enabling tools and technology. However, when such operations are being conducted, duties of regular rig personnel are usually impacted in some way. The purpose of this chapter is to provide some valuable “need-to-know” information about these drilling methods and applicable required equipment. This information will help rig personnel better understand why the method is being practiced, as well as to work safely around and with this specialized equipment, while contributing to a successful drilling operation. An influencing factor on the development of these technologies and their specialized equipment is that much of the world’s remaining prospects for conventional and non-conventional oil and gas resources are increasingly more difficult to drill safely, effectively and/or efficiently with conventional circulating fluids systems. It may be said that most of the “easy” wells have already been drilled, and those remaining promise to be more challenging, with a growing number being un-drillable with conventional means for safety, technical and/or economic reasons. It may also be said that the old proverb “Necessity, who is the mother of invention” is

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MP-1

applicable to the development, broad industry acceptance and range of practical uses of each of these drilling methods. For over a century, conventional rotary drilling with jointed pipe and weighted drilling-fluid (mud) systems has largely been practiced with annulus returns (mud and cuttings) that are open-to-atmosphere under the rig floor. When the rig’s mud pumps are on, annulus returns exit the top of the wellbore through a drilling or bell nipple and gravity flow from beneath the rig floor to mud-gas separation and solids control equipment. When the mud pumps are off, the weight of the mud in the hole is intended to overbalance pressure in formations that are exposed to the wellbore. The primary well control barrier is the hydrostatic head (pressure) generated by the column of mud and cuttings in the wellbore annulus during static conditions. Annulus returns must surface at or very near atmospheric pressure for drilling to progress without interruption. Should the mud column height fall or the returns rate increase, an interruption to drilling ahead may be the least consequence. The most troublesome inherent weakness of a conventional circulating fluid system is the fact that the only way to immediately adjust the equivalent weight of the mud in the hole to deal with changing and/or unexpected downhole pressure environments is to change the pump rate. Initially all wells drilled with cable tool rigs were underbalanced. In 1895, rotary drilling with joined pipe was introduced with a fluid that had to be circulated to transport cuttings out of the hole. As time went by, attitudes changed from the early “gushers” when a blowout was a time for celebration to realizing that such an uncontrolled release was a health and safety issue and resulted in environmental damage, not to mention a waste of natural resources. This set the stage for today’s conventional wisdom—drilling with an open-to-atmosphere mud returns system (drilling nipple or riser) under the rig floor, where a weighted mud serves as the primary well-control barrier by overbalancing the formation drilled into. A key to successful drilling programs has been and remains linked to the ability to efficiently navigate changing and sometimes relatively unknown safe mudweight windows to as deep an exposed wellbore depth as practical. Safe mud weight windows are those between formation pore pressure and fracture pressure or wellbore stability gradient at a specific depth, and in English units of measure, often expressed in ppg equivalent (ppge). A map of downhole pressure environments at various depths and formations, Figure MP-1, provides some insight of the challenge.

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MANAGED PRESSURE is much higher than that of air or mist. Very soft formation or unstable shale generates problems for drilling with foam, as the wellbore integrity is poor.

Underbalanced drilling

The IADC UBO/MPD Committee’s Glossary of Terms describes underbalanced drilling (UBD): “A drilling activity employing appropriate equipment and controls where the pressure exerted in the wellbore is intentionally less than the pore pressure in any part of the exposed formations with the intention of bringing formation fluids to the surface.”

Figure MP-1: Predictions of safe mud weight windows used for planning fluids and casing programs. Courtesy Weatherford.

Air, gas, mist and foam drilling

Air and gas drilling was introduced in the 1950s primarily for purposes of optimizing drilling performance and cost, typically in hard-rock formations or in grossly depleted formations. Of all drilling fluids, air and gas offer the greatest penetration rates, are least likely to cause formation damage, and have the greatest ability to drill in loss circulation zones. However, air and gas drilling also has the least ability to drill safely in high-pore pressure zones or to cope with formation water. Drilling with air, gas or mist is not a common practice in marine environments. Mist drilling is where compressed air or other gas (e.g., nitrogen or natural gas) is injected into the well with incompressible fluids such as fresh water, formation water or formation oil. The history of foam drilling also dates back to the 1950s and is commonly used to enable loss circulation zones to be drilled with returns to surface. Recyclable foams were not available until late in the 1990s, which enabled the utilization of foam drilling offshore due to smaller footprints and environmental regulation. Foam drilling operations may obtain penetration increases of seven to nine times that of conventional mud drilling (mostly in hard rock). The advantage of no lost circulation (in most cases) is a critical economic and environmental advantage. The ability to recover samples in the form of drill cuttings can be extremely important in exploratory wells. In addition, foam allows the use of much lower velocity in large wellbore wells versus dry gas or mist drilling, resulting in lower equipment needs. The ability of foam to carry out produced water

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The official definition of UBD by the Alberta Energy Board is somewhat more descriptive: “Drilling with the hydrostatic head of the drilling fluid intentionally designed to be lower than the pressure of the formations being drilled. The hydrostatic head of the fluid may be naturally less than the formation pressure, or it can be induced. The induced state may be created by adding natural gas, nitrogen, or air to the liquid phase of the drilling fluid. Whether the underbalanced status is induced or natural, the result may be an influx of formation fluids which must be circulated from the well and controlled at surface.” Put more simply, UBD is drilling with a hydrostatic mud weight intentionally maintained below adjacent wellbore reservoir pressures to invite hydrocarbons to be produced to the surface. UBD-specific well control principles apply. The primary objective of UBD may be to either reduce non-productive time when drilling zones where kicks and/ or losses are prevalent or to enhance the productivity of the completed well or reservoir characterization while drilling. UBD may be practiced on land and offshore. Drilling ahead with hydrocarbons being produced to surface in marine environments is regulatory-restricted in some jurisdictions and requires specific approval in advance. Producing reservoir fluids to surface while drilling underbalanced offshore can present rig space and logistics challenges that must be carefully considered. Several methods are used to invite the well to flow while drilling. Drilling with twp-phase fluids (nitrified fluids) and injection of an inert gas in the annulus returns path (dual-gradient UBD) are common when drilling into depleted formations. The flow drilling method is applicable when drilling horizontally into inclined fractures, such as found in the Austin Chalk in Texas and Louisiana. In this case, the formation is not depleted, per se, but mud is lost in the fracture below, allowing reservoir pressure gas to enter the wellbore from above, resulting in an underbalanced condition. UBD requires dedicated specialized equipment, careful pre-planning, hydraulic flow modeling, HazId/HazOp processes, crew training and interactive drilling program imple-

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MANAGED PRESSURE mentation for safe and effective application. It also requires all involved parties to know when to engage conventional well control procedures and when they are not required.

Managed pressure drilling

The specialized equipment and techniques to practice MPD safely and effectively have evolved on many thousands of land-drilling programs over the past four decades. The use of its key enabling tools and application of its root concepts have become so commonplace that many consider drilling with a rotating control device (RCD) and drilling choke is ‘just the way you drill’ and may not relate such to MPD technology, per se. (The main function of an RCD is to divert flow and to prevent any surface release from returning fluids, thus maintaining a safe environment on the rig floor. See separate section on Rotating Control Devices.)

MP–3

An influx of hydrocarbons is not invited, but everything is in place to contain any that may be incidental to the operation. The primary objectives of MPD are to reduce NPT by mitigating drilling hazards, enhance well control and drill prospects otherwise deemed un-drillable for safety, economic or technical reasons. MPD may be practiced on any type of rig, whether it has a surface or subsea BOP.

Variations of managed pressure drilling

There are four key variations of MPD, each intended to address specific challenges to conventional drilling programs. Constant Bottomhole Pressure (CBHP): Applicable to drilling in narrow, shifting and/or relatively unknown mud weight (EMW) windows that manifest kick/loss scenarios such as illustrated in Figure MP-2.

This is in part due to the fact that the term was not coined until its onshore pioneered root concepts were introduced to offshore drilling decision-makers in 2003. A predominant difference between UBD and MPD is that the former invites the well to flow while drilling and the latter does not. This key distinction opens considerable opportunity for MPD to be practiced on all types of offshore rigs. The IADC UBO/MPD Committee describes MPD as: “MPD—an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. It is the intention of MPD to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be safely contained using an appropriate process. “MPD process employs a collection of tools and techniques which may mitigate the risks and costs associated with drilling wells that have narrow downhole environmental limits, by proactively managing the annular hydraulic pressure profile. “MPD may include control of back pressure, fluid density, fluid rheology, annular fluid level, circulating friction and hole geometry, or combinations thereof. “MPD may allow faster corrective action to deal with observed pressure variations. The ability to dynamically control annular pressures facilitates drilling of what might otherwise be economically unattainable prospects.” MPD is drilling with an equivalent mud weight (EMW) equal to or greater than formation pressure or the pressure required for wellbore stability and less than fracture or leakoff pressure. The mud weight itself may or may not impart a hydrostatic head pressure less than formation pressure.

IADC Drilling Manual

Figure MP-2: Well flows when not circulating and mud losses occur when circulating due to the addition of circulating annular friction pressure (AFP). Courtesy Weatherford.

CBHP enables drilling with a lighter mud that avoids losses when circulating and applies surface backpressure (BP) when not circulating to prevent well flow, as illustrated in Figure MP-3. Pressurized Mud Cap Drilling (PMCD): Applicable to drilling in severe to total loss circulation zones with a sacrificial fluid and no returns to surface, as illustrated in Figure MP-4. Returns Flow Control for HSE (RFC-HSE): Applicable when drilling with a closed-loop circulating-fluids system for health, safety and environmental reasons only. Key components of a closed-loop system are an RCD, drill string non-return valves (floats) and a dedicated choke system that is manual, semi-automatic or programmable logic controlled (PLC) automatic. A PLC automatic choke

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MP–4

MANAGED PRESSURE Dual-Gradient Drilling (DGD): Applicable for achieving two or more depth versus pressure gradients in the mud returns path primarily for managing the wellbore pressure profile, as illustrated in Figure MP-5: For CBHP, PMCD, and RFC-HSE variations, some of the same dedicated equipment required for UBD is used: e.g., drill string non-return valves in most cases, a fit-for-purpose RCD design, and a dedicated drilling choke manifold. For DGD and depending upon the specific method, a dual gradient in the returns path back to the rig may be achieved by injecting a gas, lighter mud or by using subsea mud-lift pumps in deepwater.

Figure MP-3: The amount of surface BP applied during jointed pipe connections is typically equal to the circulating AFP experienced while drilling the last stand. Courtesy Weatherford.

Like UBD, all variations require careful pre-planning, hydraulic flow modeling, HazId/HazOp processes, crew training and interactive drilling program implementation for safe and effective application. Also like UBD, all variations require all involved to have a clear understanding of when and when not to engage conventional well control procedures. However, unlike UBD, which may not be permitted offshore by a regulatory body, MPD is likely to be permitted on a caseby-case basis provided that operator objectives are clearly defined and adequate pre-planning and well control contingency plans are well defined and understood by all stakeholders.

Figure MP-4: PMCD involves placement of a heavy viscous mud cap above the source of severe to total losses, augmented by surface BP to prevent reservoir fluids’ migration to surface, and drilling with a sacrificial fluid such as seawater. Courtesy Weatherford.

system enables early kick-loss detection, identification of ballooning phenomenon in real-time, and the ability to conduct frequent dynamic formation integrity tests (FITs) and leak-off tests (LOTs) without drilling interruption. Dynamic FITs are particularly beneficial because it’s better to know sooner than later if the fracture pressure is less than what is required by subsequent drilling, casing running and cementing operations

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Figure MP-5: DGD is accomplished by using mud-lift pumps, mud dilution or inert gas injection that removes some or all of the hydrostatic head otherwise generated by the column of mud and cuttings above. For example, if mud-lift pumps are on the seafloor for deepwater DGD, all of the hydrostatic head otherwise created by a tall column of annulus returns in the marine riser is removed, and the wellbore is exposed only to seawater gradient. Courtesy Weatherford.

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Deepwater applications of MPD

CBHP and PMCD have been safely and effectively practiced globally on prospects deemed un-drillable with conventional means for safety, economic or technical reasons. This is understandable when considering that new technology is most often applied only when conventional wisdom fails. RFC-HSE is just beginning to be seen as maybe a better way to drill some prospects that could be drilled conventionally. Although there have been hundreds of riserless DGD applications, DGD with a marine riser and subsea BOP is still in its infancy. On floating rigs such as moored semisubmersibles and dynamically positioned drill ships, the kit required to practice CBHP, PMCD and RFC-HSE variations has evolved to include several offshore RCD configurations, PLC automated choke manifold systems for early kick-loss detection, real-time determination of actual drilling windows, ability to conduct frequent dynamic FITs and quantify ballooning phenomenon upon each jointed pipe connection. The RCD should be tested and rated by the provider in accordance with API 16RCD. Deepwater designs include those suitable for being configured on top of a collapsed upper marine riser slip joint, above the marine riser tension ring and below the slip joint, below the marine riser tension ring, and anywhere within the marine riser itself above the subsea BOP. The bodies of the RCD designs to be configured below the riser tension ring to serve as a marine riser spool section and therefore must have suitable tensile strength, typically 3,000,000 lb. Another marine design is the “Docking Station RCD”, Figure MP-6, whose body is configured above the tension ring and below the rig’s telescoping slip joint. In this configuration, the slip joint above requires an inside diameter that permits deployment and retrieval of the RCD’s bearing and annular seal assembly. Each design requires a dedicated running tool for deploying the RCD’s bearing and seal assembly, facilitating transition from conventional drilling to MPD and vice versa. Figure MP-7 is a schematic that may be considered a stateor-the-art equipment configuration for the practice of CBHP, PMCD and RFC-HSE variations. In this case, the RCD is configured below the marine riser tension ring, a location that does not require modifications to the rig’s existing upper marine riser system, as well as enabling significant headings changes on drill ships. The ease at which the RCD’s bearing and annular seal assembly may be deployed and retrieved facilitates relatively rapid transition from conventional drilling to MPD and vice versa.

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IADC UBO/MPD Committee technical support

The IADC UBO/MPD Committee has been active in developing recommended practices and HSE Guidelines for both MPD and UBD. Subject matter experts on the committee have strived to aid the industry in safe and effective practice of both drilling methods, and those interested in practicing UBO or MPD are encouraged to access the results of their collective thinking via IADC’s website.

Key enabling equipment

One enabling tool that is most common to the drilling methods discussed in this chapter is the RCD. The availability of RCD designs applicable to enable drilling on any type of land and offshore rig with closed and circulating fluids that can be pressurized have played key role in the evolution and wide acceptance of the drilling techniques discussed in this chapter. Methods of applying surface back pressure may also require the use of drill string non-return valves or floats. Choke systems may be manually operated semi-automatic or PLC automatic. UBD and MPD can be safely practiced with a manual or semi-automatic manifold system. However, applications of MPD on challenging onshore wells and most offshore wells have prompted the development of PLC automatic choke control systems. Other key enabling equipment to practice the drilling methods discussed in this chapter that is likely to be in addition to the rig’s regular equipment includes downhole deployment valves, mud /gas separators of sufficient capacity, nitrogen production units, pitless air drilling systems, air compression, mass-flow meters, gas chromatographs, continuous circulating systems, and systems to make and break foams. Such specialized equipment is most often provided by service providers and often rented or leased by the operator or rig contractor. When air/gas/mist/foam drilling, UBD or MPD are practiced on their rig, regular rig personnel should familiarize themselves with the required specialized equipment and receive training from the provider if asked to assist in its safe operation and/or maintenance.

Managed pressure drilling

As mentioned in the introduction to this chapter, MPD is defined as “an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. It is the intention of MPD to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be safely contained using an appropriate process.”

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Figure MP-6: Marine Series RCD whose body is an integral component of the marine riser system. Courtesy Weatherford.

MPD includes the four variations briefly described in the introduction. They and subsets based upon their root principles have been described by the IADC in their MPD Selection Tool. Go to http://mpdtool.iadc.org/ to register and use the tool. Or scan the QR Code.

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These different variations and techniques precisely control annular pressure using combinations of applied pressure (usually at the surface), hydrostatic head and dynamic friction. These three elements of annular pressure are in turn affected by altering the combination of back pressure, fluid

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Figure MP-7: A state of the Art MPD equipment configuration may be used for multiple variations of MPD. Courtesy Weatherford.

density, fluid rheology, wellbore geometry, and circulation rate to generate appropriate pressure downhole in the annulus to accomplish the objectives described in the definition. The primary variations of MPD and subsets based on their root concepts currently recognized by the IADC and spoken to in the aforementioned MPD Candidate Selection Tool are briefly described below.

Continuous circulating devices

A continuous circulation device (CCD) allows circulation to be maintained when the drill string is broken for a connection. The mud pumps are never intentionally stopped or restarted during the connection process. One type of CCD device encloses the tool joint within a pressurized chamber while breaking or making a connection, enabling full “drilling” circulation with the rig pumps while a new stand is made up to the drill string.

pumping is stopped (planned or unplanned), BHP drops. The only ways to change BHP are to change either the rig pump rate (frictional pressure) or the mud weight. The system is applicable offshore and on land. These systems can be used in combination with other MPD techniques to provide more flexibility. Static mud column pressure may be less than pore pressure.

Constant bottomhole pressure

CBHP drilling refers to any technique wherein the bottomhole pressure remains essentially constant whether the rig mud pumps are on and fluid is circulating or rig mud pumps are off and the well is static.

Constant bottomhole pressure/bottle-up (or trapped) pressure

Alternative methods utilize pump-in subs (one per stand) made up on the drill string as part of each new connection that divert flow below the tool joint being made up and also allow continuous circulation while making connections.

The trapped pressure form of CBHP MPD entails closing a valve (usually a choke) to trap pressure at the surface to compensate for reduced dynamic friction effects as the rig pump rate is reduced prior to a connection. This simple MPD technique can be attempted using the rig annular BOP and a choke (“bottle- up” technique) similar to a well control choke.

This functionality allows for constant BHP once circulation is initiated. Circulating friction maintains the BHP, so when

When the pump is stopped, EMW BHP equals mud weight plus the trapped surface annular pressure. As the rig pump

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is started up, the choke is gradually opened to compensate for the increase in friction pressure at the bottom of the hole. A balanced combination of circulating friction pressure, mud weight and back pressure maintains BHP and avoids or mitigates pressure spikes during normal operations and in the event of problems such as pump failures, RCD leaks, choke washing/plugging, etc. The only methods of changing static BHP or BHP range are by changing the mud weight, the annular pressure or both. The system is applicable to land and marine operations. Static mud column pressure may be less than pore pressure.

Constant bottomhole pressure/back-pressure control

CBHP or backpressure control MPD, also known as dynamic annular pressure control (DAPC), can be used with either hydrostatically underbalanced or hydrostatically overbalanced drilling fluids. An RCD is typically used to close the annulus while manual or automatic manipulation of a surface choke imposes or relieves annular back pressure at the surface corresponding to decreases or increases in circulation rate. Any time the rig mud pumps are off during connections, an auxiliary pump or backpressure pump introduces a flow stream through the surface choke to impose pressure on the annulus and maintain a constant bottomhole pressure. This pump may also be used at other times when the rig mud pumps are off, such as when tripping. In this way, choke pressure is substituted for friction pressure as the circulation rate is decreased. When the rig mud pumps are brought back online and the circulation rate is increased, the backpressure pump may be turned off as the choke pressure is reduced. This affects more precise control of annular pressure than the bottle-up (or trapped) pressure technique because the choke is never 100% closed. This may facilitate detection of reservoir fluid influxes or loss of circulation by various means including annular pressure increase or decrease, increased or decreased returns rate, choke position changes, etc. These changes can be corrected by closing or opening the choke to increase or decrease BHP.

Dual gradient drilling

Dual-gradient drilling refers to drilling with two fluids of different density in the wellbore at the same time. Normally, one fluid extends from the rig to the bit and back up the annulus a certain distance. The second fluid then exists in the annulus from the top of the first fluid back to the rig level. Several variations of dual-gradient drilling are recognized by IADC.ß

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Dual-gradient subsea pump

Dual-gradient subsea pump (also known as dual-gradient mudlift or subsea mudlift) systems are used on offshore installations after the rig BOP and marine riser are installed. They use two fluids of different density to achieve a desired bottomhole pressure. Typically a heavy mud is in the wellbore up to or slightly above the mud line, with a lighter-weight fluid, usually close to seawater gradient, in the riser. A pump is used to lift cuttings and returning mud from the wellbore near the mud line back to the drilling vessel. Mudlift systems incorporate a rotation seal above the BOP and, through manipulation of the pump speed, can create back pressure on the wellbore. Mudlift systems have significant flexibility in adjusting and modifying the wellbore pressure profile. A subsea anti-U-tube valve often proves useful with these systems to simplify and/or improve well control procedures and to prevent the unwanted u-tube effect of having a heavier equivalent mud from the surface to TD inside the drill string than what is in the annulus. Either pump speed or pump power can be used to measure flow from the well to detect kicks early and limit the size of any influx. The rotating seal at the BOP allows the kick to be stopped and circulated out of the wellbore without having to shut the BOP.

Controlled annular mud level

Controlled-riser mud level systems are applied after the riser and BOP are in place and use an instrumented marine riser joint and pump system to return cuttings and fluid back to the drilling vessel. These systems also use two fluids of different densities to control the wellbore pressure gradient. The system can be utilized to place the annular fluid at different levels in the riser to achieve variable control over the wellbore pressure, the effectiveness being based on fluid density and placement. Unlike mudlift drilling, these systems do not have a rotating seal above the riser. These systems work by adjusting the level of heavy mud in the riser, thus changing the hydrostatic head. The BHP (both dynamic, for equivalent circulating density (ECD) effects, and static, for trip/connection margins) can be adjusted up or down by changing the fluid level in the riser by increasing or decreasing the return pump rate with respect to the surface pump rate. These systems can also be used to adjust for ECD during cementing, completion and intervention operations. The systems are applicable to intermediate water depth in subsea marine operations.

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Mud line pumping (Riserless)

Mud line pumping is a variation of riserless drilling, which has historically been used for top-hole drilling before the rig BOP and marine riser are run. Mud line pumping differs from conventional riserless drilling in that subsea pumps move the drilling fluid, including cuttings, from the subsea wellhead back to the rig through a small bore riser. This allows engineered mud to be used in the top sections of the well. This has significant safety and operational advantages compared to drilling with seawater or using a pin-connector and riser. The system is applicable in subsea marine operations, typically in shallower water depths. Static fluid column pressure is greater than pore pressure. Two other variations of dual-gradient drilling rely on dilution of drilling fluid. One method mixes gas with the drilling fluid, while the other mixes liquid with the drilling fluid.

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accomplished in one of several ways, including through an external parasite tubing attached to a surface or intermediate casing string, through an annulus formed by a temporary concentric casing string, or, in offshore applications, through a riser boost line near the mudline. The lower density fluid or light material is separated from the original circulating fluid at the rig so that it can be reused; otherwise, a continuous supply of the base mud and light-weight additive must be available. The original mud is returned to the pits for pumping down the drill string. Due to the depth of the injection point, there may be a delay in achieving the desired effect until the mixing process results in the required mixture density. Due to the constantly changing fluid density profile in the riser, achieving a constant BHP may be challenging and require automation. The system is applicable from intermediate to deepwater subsea marine operations. Static mud column pressure is greater than pore pressure. ß

Achieving a dual gradient by mixing gas with the drilling fluid may be done either onshore or offshore, although it has historically only been done onshore. When done offshore, this system is used after running the rig BOP and marine riser. Hydrostatic head of the circulating fluid is reduced by injecting gas (e.g., nitrogen [N2]) into the drilling annulus. The gas injection may be accomplished in one of several ways, including through an external parasite tubing attached to a surface or intermediate casing string, through an annulus formed by a temporary concentric casing string, or, in offshore applications, through a riser boost line near the mudline. The gas is not normally recovered; thus, a continuous supply must be available. After removal of the gas, typically through a mud-gas separator, the original weight mud is returned to the pits for circulation down the drill string. The amount of gas introduced into the annulus determines the relative reduction in BHP. Due to the depth of the injection point, there is a delay in achieving the desired effects as the existing mud/gas mixture in the riser changes to the new mixture average density. The compressible nature of gas makes achieving a constant BHP challenging and requires a wider operating-pressure window than when using an incompressible fluid. Static mud column hydrostatic pressure is greater than pore pressure.

Sea Floor

Dual-gradient/mix fluid using liquid

When this system is used offshore, the BOP and marine riser are in place. The hydrostatic head of the circulating fluid is reduced by injecting a lower-density incompressible fluid or material into the drilling annulus. The injection may be

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Figure MP-8: The Controlled Annular Mud Level variation of DGD allows control over wellbore pressure by varying hydrostatic head. Courtesy Signa Engineering.

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Mud cap drilling

Mud cap drilling (MCD) refers to techniques wherein total or near-total loss of circulation occurs and drilling is accomplished by maintaining a “cap” of mud in the annulus, while injecting a sacrificial drilling fluid down the drill string with no returns to surface.

be held on the annulus at all times while drilling below an RCD. Increasing surface pressure indicates hydrocarbon migration up the annulus. Additional annular fluid is periodically injected into the annulus in order to bullhead any formation fluid influx back into the formation, thus decreasing the annular pressure back to the initial value. This makes the process extremely predictable.

Floating mud cap drilling

If the fluid level is not maintained at the surface (similar to floating mud cap drilling described above) but can be measured and monitored to maintain it more or less at a continuous level, this may be considered to be PMCD by some.

Drilling continues with a sacrificial drilling fluid, usually water, pumped down the drill string according to conventional bit hydraulics and to facilitate hole cleaning. Fluid may be pumped continuously into the annulus to mitigate any potential influx from the formations. This method typically requires a large volume of sacrificial fluid. The system is applicable to land and marine operations, although it has historically been applied primarily onshore. Static mud column pressure is equal to or greater than pore pressure.

PMCD, like other forms of MCD, requires a good supply of annular fluid as well as of sacrificial drilling fluid, which is usually water. The system is applicable to land and offshore operations of all types. Static mud column pressure is slightly below or equal to pore pressure.

Floating mud cap drilling is simply drilling without returns. The mud level in the annulus drops to a level that the pore pressure in formations open to the wellbore will support.

Other MPD techniques

Other recognized MPD variations may offer little actual annular pressure control and are meant primarily for monitoring or diversion of fluid returns only.

RCD Only

The RCD-only technique simply adds an RCD to the conventional BOP stack on the rig to divert all fluid (either liquid or gas) returns from the rig floor. No additional devices to determine kicks or losses such as flow meters, pressure sensors, pit level indicators, flow restriction devices, etc. are used. This is a reactive rather than a proactive MPD technique and is somewhat limited in that it does not actually manage the BHP.

Enhanced kick/loss detection only

Objectives of early kick/loss detection (EKLD) include quick identification of kicks or circulation losses, thus facilitating mitigation before these events can escalate into a major well-control event. Seabed

Figure MP-9: Mud line pumping is a variation of riserless drilling, which has historically been used for top-hole drilling before the rig BOP and marine riser are run. Courtesy Signa Engineering.

Pressurized mud cap drilling

PMCD, also known as closed-hole circulation drilling (CHCD), is drilling without returns but with the annulus fluid level maintained at the surface. The annular fluid has a hydrostatic head that is slightly below pore pressure equivalent, requiring a slight back pressure to

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EKLD systems also help to differentiate kicks and losses from other downhole events such as ballooning and breathing. This is accomplished through the employment of various equipment on the rig consisting of combinations of flow meters, pressure sensors, pit level indicators, etc., in addition to conventional drilling operation monitoring systems. The operator is only alerted to a potential event. No incremental response or reactive systems are present. This is a very limited MPD technique in that it does not actually manage the BHP, but only helps monitor potential changes to the BHP. Still other MPD variations are less likely to be encountered in the field, as they are in the development stage or have limited applicability.

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Constant bottomhole pressure/back-pressure Control Using Gas Injection

CBHP or backpressure control using gas injection is carried out almost exactly like the CBHP/back-pressure control technique, except that the circulating fluid density is reduced by the addition of a gas phase. The technique can utilize either hydrostatically underbalanced or hydrostatically overbalanced drilling fluids. Gas is most commonly introduced into the circulating fluid either through the drill string or into the casing-drill string annulus using either an external parasite tubing string or a temporary concentric casing string. An RCD is typically used to close the annulus while manual or automatic manipulation of a surface choke imposes or relieves surface annular back-pressure corresponding to decreases or increases in circulation rate. Control of annular pressure is most commonly accomplished using the bottle-up (trapped) pressure method, but may be accomplished, at least in theory, by utilizing an auxiliary annular pump as described in the other CBHP method sections. If necessary, choke pressure is substituted for friction pressure as the circulation rate is decreased and vice versa when the circulation rate is increased. Use of annular pressure may facilitate detection of reservoir fluid influxes or loss of circulation by various means including annular pressure increase or decrease, increased or decreased returns rate, choke position changes, etc. These changes can be corrected by closing or opening the choke to increase or decrease BHP. Due to fluid system compressibility, modifications require more time to affect the bottomhole pressure than when using incompressible fluid systems commonly used with other CBHP/back-pressure methods.

Equivalent circulating density reduction tools

This technology involves installing a turbine pump in the drill string to pump all or part of the returning circulating fluid up the annulus to counteract the incremental pressure drop of the fluid circulating through the annulus and thus maintain a constant BHP. The tool must be positioned deep enough to provide sufficient benefit yet shallow enough to continue the benefit as the tool moves deeper when drilling progresses. These tools are normally restricted to the cased portion of the well and thus may need repositioning as drilling progresses. The system is applicable to offshore and land operations. These systems can be used in combination with other MPD techniques to provide more flexibility. Static mud column pressure is more than pore pressure.

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ECD control: Concentric drill pipe

This technology uses a concentric drill pipe that allows drilling fluid to be pumped down the annulus between the inner and outer strings of concentric pipe with returns up the inside of the inner string. This de-couples the annulus from the circulating drilling fluid hydrostatic pressure, enabling a different fluid density to be maintained in the concentric drill pipe/wellbore annulus.

Common MPD equipment components

Rotating control devices

Virtually every MPD operation requires the installation and utilization of an RCD, including rotating BOPs and the more common rotating head (RH). The RCD seals around the drill pipe and allows the annulus to become pressurized, thereby facilitating choke backpressure for unconventional drilling operations. An RH affects a seal on the annulus by friction between the RH sealing element and the drill string. The seal around the drill string with a rotating BOP is affected by hydraulic pressure exerted behind the sealing element similar to the manner in which a BOP element seals around pipe. Unlike a BOP ram or annular preventer, an RCD allows the rotation and vertical movement of drill pipe. RCDs should not be confused with BOP devices. Although the RCD helps to isolate a pressurized wellbore, they are not designed or required to be part of well control operations, or to be a part of BOP equipment.

Returns flow path

Many of the failures in MPD operations can be directly attributed to poor flow path and piping designs and rig-up. For example, a 100-ft run of 4-in. XXH piping with several right-angle turns can produce as much as 50 psi induced pressure at 400-500 gal/min (depending on fluid properties). On a well with a true vertical depth (TVD) of 4,000 ft, this equates to an extra 0.24 lb/gal equivalent seen solely due to surface piping by the wellbore at depth. This increased pressure may very well put the pressure profile outside a safe drilling window. In general, at a given flow rate, the larger the piping internal diameter (ID), the lower the pressure drop per foot. Straight piping runs are better than turns. If a turn is required, large radius turns produce less pressure drop than a more acute turn. It is also important to keep the flow piping the same ID, since changing ID creates additional pressure drop.

Chokes/manifolds

In many MPD variants an MPD choke manifold is a critical component of the MPD equipment spread. The choke man-

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ifold houses the choke, which creates the variable flow restriction that controls the wellhead pressure, which in turn controls or manages the wellbore pressure profile, often at a relatively constant bottomhole pressure (BHP) in both static and dynamic conditions. The choke in MPD operations is used to control wellbore pressure, but unlike conventional drilling choke manifolds, MPD choke manifolds are not used as secondary well-control equipment. The MPD choke manifold can be designed for the chokes to be operated manually or automatically. In automatic MPD choke systems, computer control manipulates the choke automatically via an algorithm to maintain the desired pressure. Even if an automated system is used, the ability to operate the manifold and chokes manually must be in-place.

Flow meters

During MPD operations, returns flow from the wellbore is typically diverted from the normal (or conventional) surface flow path. The conventional flow line is not used while drilling with MPD, and therefore the rig’s return flow sensor (flow paddle or “flow show”) may not be in the fluid flow path. Often a flowmeter is used in the return flow path to provide the driller and rig/well management with an important sensor that they are accustomed to using, providing them with an indicator of wellbore flow. Additionally, if the MPD process involves holding some surface backpressure, a flowmeter assists in preventing choke operations from masking changes in returns flow.

should be analyzed and the MGS equipment rating should be checked to ensure it can handle any contingency flow.

Drill string float valves

Many MPD operations involve situations where backpressure is held on the annulus during connections or any time circulation is not underway. This backpressure is effectively applied throughout the system and results in a “U-tube” effect from the drilling annulus into the drill string. To counteract the U-tube and prevent flow up the drill string, nonported floats (also known as non-return valves or NRVs) are commonly carried as part of the string near or in the bottomhole assembly. This facilitates trips and connections and protects the crews, isolating the inside of the drill pipe from any pressure. Various types of non-ported float have been used effectively. The choke in MPD operations is used to control wellbore pressure, but unlike conventional drilling choke manifolds, MPD choke manifolds are not used as secondary well-control equipment.

Underbalanced drilling Introduction

Auxiliary pumps

The world’s first commercially successful hydrocarbon well was drilled underbalanced, with what today would be considered akin to a cable tool rig. It is likely that the world’s last well will be drilled underbalanced due to the grossly depleted nature of future reservoirs. In fact, the world’s last well for hydrocarbons energy will likely not be for conventional oil or gas, or even shale gas or oil. That final well may well be drilled for commercial quantities of the world’s last abundant resource of hydrocarbon energy, methane hydrates. Given that methane hydrates disassociate in accordance with Boyle’s Law, it is reasonable to suspect that those drilling programs will dictate the use of UBD concepts and key enabling equipment.

Gas busters/separators

However, for the foreseeable future, UBD’s trademark benefits, which range from drilling into grossly depleted formations without damaging well productivity to increasing recoverable reserves by drilling otherwise un-drillable prospects, will remain core values of the technology.

In the CBHP variations of MPD, auxiliary pumps are often used to maintain appropriate wellbore pressure and sometimes fluid level during connections or other MPD operations. These pumps need to have a delivery rate of about 2-3 bbl/min. They do not need the same pressure capability as a rig pump, which is typically 5,000 psi or greater. An auxiliary pump for MPD purposes may only need a pressure rating of 500 psi, but this varies with application.

Since MPD projects (by IADC definition) are intended to avoid continuous influx, the use of a specialized mud-gas separation system is usually not warranted, unless a gasified fluid is being used as the drilling mud. If a mud-gas separator (MGS) is incorporated into MPD surface equipment design, it will typically be a safety precaution because the margin between mud weight and pore pressure is likely to be less than in conventional operations. The rig’s MGS is typically adequate to handle any influx scenario, especially for offshore applications. Flow rates

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It is important to understand the difference between MPD and UBD. Both may use essentially the same equipment, such as an RCD, drill string non-return valves (floats) and a drilling choke manifold of some type. However, MPD does not invite the well to flow, and formation influx potential is suppressed by precise management of the wellbore pressure profile, e.g., maintaining ECD above formation pressure at all times. This is true whether the rig’s mud pumps are on

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MANAGED PRESSURE (circulating fluids system) or off (static fluids system) and whether or not the mud in the hole at the time is hydrostatically underbalanced. The CBHP variation of MPD often uses a hydrostatically underbalanced fluid, but ECD or bottomhole pressure is maintained above formation pressure typically by applications of surface backpressure. Any operation with bottomhole pressure in excess of formation pressure, regardless of how the overbalance is arranged, is not UBD. Nor does drilling with a hydrostatically underbalanced fluid within itself imply UBD.

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UBD techniques encourage formation flow to surface by manipulating fluid density, fluid properties, circulating rate and wellhead pressure. Bottomhole pressure is kept intentionally below formation pressure, allowing formation fluid influx into the wellbore. This means hydrocarbons are produced to surface while drilling and explains in part why UBD is more commonly practiced onshore than offshore. The official definition of UBD originates from the Alberta (Canada) Energy Board and is also defined by the IADC UBO/MPD committee as: • “Drilling with the hydrostatic head of the drilling fluid intentionally designed to be lower than the pressure of the formations being drilled. The hydrostatic head of the fluid may naturally be less than the formation pressure or can be induced. The induced state may be created by adding natural gas, nitrogen, or air to the liquid phase of the drilling fluid. Whether the underbalanced status is induced or natural, the result may be an influx of formation fluids which must be circulated from the well and controlled at the surface.” In UBD, the fluid in the wellbore annulus no longer acts as the primary well control barrier as it would in conventional overbalanced drilling. Instead, the surface equipment used for UBD operations, such as the RCD and the dedicated drilling choke manifold, has replaced the function of the primary well control barrier. The secondary well control barrier in the form of the BOP stack remains exactly the same as with conventional overbalanced operations. It is important that the secondary well control equipment is not used for routine UBD operations; the BOP must remain the secondary barrier, dedicated to well control. This means that both the well and the surface equipment must be maintained at all times when drilling underbalanced.

Why drill underbalanced?

Common reasons for choosing UBD include: •

Minimizing pressure-related drilling problems. Most drilling problems related to pressure such as differential sticking, fluid losses, and slow rate of penetration can be minimized through the use of UBD. This explains

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why the majority of UBD wells are for infill drilling in mature, depleted reservoirs. However, one must note that if mitigating such drilling hazards is the only objective of UBD, MPD may offer a more cost-effective solution in many cases and do so without producing hydrocarbons to the surface in the process. Maximizing hydrocarbon recovery of the completed well. At first this was not a primary reason for the selection of UBD techniques. Early focus on UBD was that of mitigating the aforementioned pressure related drilling problems, and today such issues are predominantly addressed by MPD. However, operators began to notice that UBD wells indicated significant improvement in reservoir productivity. The reason was traced to the fact that by avoiding invasion of solids or mud filtrates into the formation, the productivity of the well increased. This combined with the ability to drill infill wells in depleted fields significantly increased the life of the field. Generally speaking, the long-term production profiles of UBD wells show a much slower decline curve than conventionally overbalanced wells, particularly in depleted fields. Characterizing the reservoir. The ability to identify fractures and prolific reservoir zones, as well as productive zones previously believed to be nonproductive and doing so while drilling, allows reservoir engineers to gain better understanding of the reservoir and consequently its potential for viable production. This ability in combination with the ability to steer wellbores in real time enables targeting the more productive features of the reservoir. It has been valuable to the industry and is destined to become more so as reservoirs deplete over time.

Designing and planning an underbalanced well

The design and pre-planning of UBD wells follow a set pattern for most wells, but there are some additional steps required. Offsetting well data collection and engaging a good reservoir candidate-selection process are essential elements for good planning. Timings for planning a UBD well are very much dependent on the well objectives and the complexity of the reservoir, as well as that of the drilling operation itself. If this is the first UBD well in the field and/ or the first for the rig and its regular personnel, one should expect a longer planning and training period. Fluids selection may include gasified fluids or single-phase fluids if formation pressures are high enough to provide the desired underbalanced conditions. Many oil reservoirs are drilled with native crude that provides sufficient underbalanced conditions. A gas-lift system to achieve a dual gradient in the mud returns path may be applicable by injecting a gas (typically nitrogen) via concentric casing or parasite string.

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Depending on the fluids and gasses used, different hydraulic flow models may have to be used to verify the safe and most effective operating window for UBD. A multiphase model may have to be used if two-phase fluids are used and should include the following:

should be tested and rated by its provider in compliance with API 16RCD. This does not mean it must have the API monogram, but that its stated static, dynamic and stripping pressure ratings should have been established by the guidelines of this specification.

• •

RCDs provide a seal at the uppermost part of the circulating fluids system, diverting annular flow to processing and measurement equipment. A section of API Recommended Practice 92U Underbalanced Drilling Operations states:

• • •

Prediction of flow regime at any given depth; Liquid holdup calculations at any given point in the well; Frictional pressure loss (circulating annular friction pressure) calculations; Thermal pressure/volume/temperature (PVT) calculations; Hole cleaning and cuttings transport indications.

These basic pre-drill steps help determine the operating limits and MPD equipment specifications and serve to define contingency plans for the circulating system that are to be put in place before commencing drilling operations. An inherent process is that of developing a well-specific UBD well control matrix, one that clearly defines safe operational limits for surface equipment under various pressure and flow conditions and specifically identifies when conventional well control procedures must be engaged.

Impact of UBD operations on rig personnel

The aforementioned planning operations typically are done by engineers planning the well, with the assistance of UBD service providers. Well-specific HazId/HazOp processes should be engaged. It is at this point regular rig personnel are likely to get involved.

“In selection and design of UBD flow-control equipment it is necessary to accept the fact that equipment can fail during the operations. Experience has shown that the RCD and the UBD choke manifold are the components of the system most likely to fail due to operational wear and tear. Therefore, planned monitoring, preventative maintenance and some redundancy are necessary to prevent failure.” The RCD is a safety-critical item rig personnel are likely to be required to maintain. The RCD, particularly the RCD seal element, is among the most failure-prone individual component in a UBD program. RCD seal elements are “expendables” in that they wear during service, somewhat akin to automobile tires. Like automobile tire life, certain things can be done to help ensure the least wear and longest dependable service life. Rig personnel are encouraged to give special attention to ensure that any situations that could potentially shorten the element service life are eliminated or minimized. The working seal(s) in the RCD can be damaged by:

Specialized personnel may be on location in addition to regular rig personnel during UBD operations, such as a UBD choke operator, dedicated multiphase separator personnel, etc. The “UBD kit” varies with the requirements of the drilling program and fluids used. A detailed discussion of all the equipment possibilities is beyond the scope of this document. In cases where rig personnel are involved in operation and/or maintenance of such UBD-specific equipment, the service provider or someone very familiar with the equipment should provide appropriate training to assure both safety and efficient operations.

•

Typically, most rig personnel interface with a UBD operation on their rig with several key enabling tools, the RCD and drill string non-return valves.

•

• • •

The working seal(s) in the RCD can be damaged by: • •

•

Rotating control devices

The main function of the RCD is to divert flow and to prevent any surface release from returning fluids, thus maintaining a safe environment on the rig floor. During UBD operations, the RCD is a primary containment device. Its failure can have catastrophic consequences. For this reason the RCD

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Drill pipe roughness and identification grooves in tool joint; Fast tripping of the drill string; Misalignment of the traveling block fall in respect to the rotary table; Chemical incompatibility and elevated temperatures.

•

Review BOP stack drawings and interface with the rig; Confirm drill string size(s) to be used per UBD program; Confirm that a suitable grade of sealing elements (such as stripper rubbers), in the right sizes, are on site in appropriate quantity and stored properly; Confirm that the RCD is the right design specified in the drilling program and that it meets the required specifications for static, dynamic and stripping pressure ratings; Check other items such as RPM rating, maximum temperature tolerance of the sealing element and potential for chemical incompatibility with drilling fluids used.

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MANAGED PRESSURE

Drillstring non-return valves (NRVs or floats)

There are two types of non-retrievable drill string non-return valves or ‘floats’ which are made up in the drill string – plunger and flapper types, illustrated below. These are made up in the drill string and cannot be relocated or retrieved without tripping out the drill string. Consequently, non-retrievable NRV’s are not the preferred type for UBD and some MPD applications.

•

Wireline retrievable NRVs (WL-NRV) are typically preferred and commonly used on UBD and CBHP MPD applications. The WR-NRV is a flapper-style, drill-float valve designed to manage backpressure in the drillstring. Unlike a fixed-float valve, the WL-NRV can be changed out or removed on wireline, eliminating the need to trip pipe. The high-pressure valve enhances safety by allowing pressure above the valve in the drillstring to be bled off when making and breaking connections.

•

Multiple valves are typically positioned at intervals of about 500 ft (150 m) in the string to enable incremental bleed back of any existing pressure and later incremental repressurization. This procedure eliminates the time associated with bleeding pressure off the entire drillstring, as required with fixed valves positioned in or near the bottomhole assembly (BHA). In contrast to fixed-float valves that are made up as part of the drillstring, the WR-NRV makes up to an industry standard X-lock assembly that is latched into a drillstring profile sub. Using this common industry connection facilitates quick recovery by wireline, which enables valve replacement without killing the well. It also makes it possible for fishing operations to reach the BHA, which is prevented with fixedvalve configurations. Rig personnel should familiarize themselves with recommendations for the use of non-return valves (NRV): • •

•

•

•

NRV bleed-off equipment should have a pressure rating equal to or greater than that of the BOP stack. A minimum of two NRVs should be installed as close to the bit as possible, or directly above the drilling motor. One of the devices can be a profile nipple designed to accommodate a pump-down back-flow device. When an NRV is pulled to the floor to make jointed pipe connections, bleed-off procedures and equipment should be used to remove trapped gas below the float before being removed from the string. Operational procedures should specify actions to be taken in the event that either of the two NRVs fails to hold pressure. NRVs should be spaced apart in suitable intervals

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•

•

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to avoid an excessive number in the drill string while avoiding excessively long connection bleed-off times. Screens should be used on the mud pump suction and above measurement while drilling (MWD) tools to prevent scale and solids from plugging NRVs and other bottomhole assembly components, or damaging the sealing surfaces. Remove all adhesive labels from downhole tools. They may dislocate in the hole and could possibly plug downhole components. NRVs and the possible presence of energized fluid below the valve are routine in UBD operations. Installation, bleed-off and removal procedures in onsite practice training are important because the application differs substantially from conventional operations. The bleed-off hose connected to the NRV bleed-off tool should be secured, or hard-lined, to ensure bleed-off is directed away from the rig floor and potential escape routes. Relieve pressure to the separator for high pressure. Into atmosphere for low pressure is usually a good practice.

References

Further discussion on RCDs, NRVs and other UBD-specific equipment may be found in API RP Underbalanced Drilling Operations, as well on the website for the IADC Underbalanced Operations & Managed Pressure (UBO/MPD) Committee. This committee comprises industry experts. When UBD is to be practiced on your rig, regular rig personnel would be wise to take advantage of the wisdom and experience committee members have provided. Another resource is the Canadian Drilling & Completion Committee’s Industry Recommended Practice (IRP) – Underbalanced Drilling (UBD) and Managed Pressure Drilling (MPD) Operations Using Jointed Pipe.

Air, gas, mist and foam drilling

Drilling equipment, procedures and problems discussed in this chapter include drilling with the compressible drilling fluids (air, gas, and mist) and with the use of the air hammer. This section explains the basic concepts of air and gas drilling. Therefore, the purpose is to: • • •

•

Provide an understanding of related standard operating procedures and monitoring requirements; Discuss the different techniques and equipment; Describe potential problems that may be encountered that can be recognized and dealt with at the earliest possible stages; Provide some, but certainly not all the information rig personnel may need to be aware of when drilling with compressible fluids that could impact their usual tasks on the rig or drilling location;

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MANAGED PRESSURE

Encourage rig personnel to work with and communicate closely with the compressible fluids drilling service provider.

Offshore applications of compressible fluids drilling systems have been limited to date, so this discussion of the systems and equipment is primarily concerned with land-based systems. The drilling methods listed above utilize compressed air or a gas as a rotary drilling circulating fluid to carry the rock cuttings to the surface. The compressed air or other gasses such as nitrogen or natural gas can be used alone or injected into the well with incompressible fluids such as fresh water, formation water or formation fluids (Figure MP-10). The most common compressible fluid used for drilling is air. Natural gas from the lease or a pipeline is also common, but nitrogen is gradually becoming the gas of choice. While it is possible to drill into dry natural gas zones with an air system, if the zone contains a condensate, a downhole fire or explosion will occur. In the case of condensate in the wellbore, natural gas or nitrogen is the fluid of choice. Some single-stand rotary drilling rigs have the required specialized air drilling equipment incorporated into the rig design. More often air, gas and mist drilling operations require specialized surface equipment not normally used in conventional mud drilling operations.

In addition to the contracted rig itself, the specialized equipment is usually provided by service providers. These contractors supply the rotary drilling contractor’s rig with the necessary surface equipment to convert the drilling rig to one capable of drilling with a compressible fluid.

Why drill with air/mist?

Advantages include: • Increased ROP, normally the primary consideration; • Reduced or eliminated risk of lost circulation; • Improved or extended bit life; • Identify often overlooked reservoirs; • Decrease potential damage to productive formations; • Eliminate the risk of differential sticking; • Reduced overall well costs by reduction of time on well; • Lack of conventional mud system to clean up or dispose of at the surface. The permeability of the formations being drilled has a significant influence on the finished well’s productivity. Sandstone, for example, has a relatively high permeability that can be damaged if drilled with a conventional overbalanced mud system. Therefore, productivity of sandstone formations benefits greatly from being drilled with air by avoiding permeability damage.

Figure MP-10: Compressible drilling systems include all systems above. Offshore applications of compressible fluids drilling systems have been limited to dateTherefore, this section will primarily discuss land operations.

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Flammability: Oxygen vs Methane % Methane

14 Non-Flammable Non-Flammable

12 10 8

Flammable

6 4

21

20

19

18

17

16

15

14

13

12

% Oxygen

Figure MP-12: Using natural gas (methane) or nitrogen reduces or even removes oxygen in the well, greatly reducing the risk of downhole fire or even explosion.

Key seat and dropped pipe

Typical air drilling problems

A dry hole has two general tripping problems. 1. Running in the hole, the bit may hit a ledge and cause the elevators to unlatch and drop the pipe. The solution is to not run in the hole by dropping the pipe; control the running speed. 2. Coming out of the hole, a tool joint may keyseat in a ledge. Pulling on it only jams it tighter. The best solution is to work or jar down.

Wet hole

Downhole fire

Figure MP-11: Mud rings occur when dust is wetted by any form of moisture, either in the drilling media or from the wellbore.

The primary air or gas drilling problem is the presence of water or moisture in the formation. The cuttings from damp or wet formations become muddy and require additional moisture and soap from a misting pump (drilling with mist) to disperse them. Moisture reduces the ability of the air or gas to lift cuttings from the hole and in shale or broken formations causes hole instability. Hole instability generally starts with washouts in the open hole. The washed-out area reduces the air velocity opposite it and causes a buildup of cuttings that can fall back on a connection and cause hole fill-up or stuck pipe.

Mud rings

When damp formations are drilled, the cuttings build up on top of the drill collars where the air/gas velocity decreases due to a larger annulus. The damp cuttings form a mud ring in the annulus above the drill collars that reduces the ability to clean the bit and around the collars and may cause a stuck bit on a connection (Figure MP-11). Mist (water and detergent) is required to cut the mud rings.

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A downhole fire (or explosion) only occurs when drilling with air and almost always occurs when a condensate-bearing gas flow is encountered. The use of natural gas or nitrogen removes or reduces the oxygen in the hole so fire cannot occur (Figure MP-12). The technical explanation is that a fire or explosion downhole requires a flammable mixture and an ignition source. Air contains approximately 20% oxygen, which only requires a small amount of condensate to become explosive. The source of ignition can be a drill collar or tool joint that has become red-hot by rubbing against a dry rock.

Shale, oil shale, gilsonite, coal and other common formation problems

Air/gas drilling works best where the formations are hard and brittle. Some common problems with air/gas drilling are related to the characteristics of the formation. • Shale: Shale can be very dry and brittle and will drill with air/gas very rapidly. Thick shale formations are often geopressured and contain a lot of pore space water. If mist is used or the formations become wet, they start to become unstable in three or four days, the hole caves, and it becomes difficult to continue with an air/ gas system;

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•

•

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Oil Shale: Shale containing a high percentage of kerogene or oil has a tendency to ball the bit and cause mud rings. This is difficult to overcome with mist. The injection of dry graphite or a powder can overcome the sticky problem, but it is difficult to inject dry powder into the air stream; Gilsonite: Gilsonite, which is found in Utah in the United States, and similar very kerogenous coal or shales found elsewhere in the world are not suitable gas drilling projects; Coal: Coal is a very general term for the driller, since it ranges from soft to hard and broken to compact. At this time there does not seem to be any general rule about air/gas coal drilling problems. Local information is the best source of ideas and is generally most correct. • Some coal beds are broken and pulverized and will not stay open with air/gas drilling. Washed-out coal sections (coal beds) are one of the main problems that limit air/gas drilling. The coal bed collapses to a large enough washout that the cuttings cannot rise past that point; • In other coal, the bedding is intact enough that it will drill and hold a near-gauge open hole. In parts of the eastern United States, the hard coal (anthracite coal) is compact and brittle enough that directional and horizontal holes can be drilled with air.

Air volume requirements

Air volume requirements are based on hole size (annular size) and depth. Washouts or larger-diameter casings require more air than calculated for the open-hole size. A graph for volume requirements is shown in “Underbalanced Drilling: Limits and Extremes”, Bill Rehm, et al, p 322 (Gulf Publishing, 2012; published under the auspices of the IADC Technical Publications Committee). The table is drawn up for minimum volume in a gauge hole. Because most holes are washed out or overgauge, table values for long open hole or misting are about 20% low.

Mist drilling rules

Almost all air and gas drilling operations end up using mist to extend drilling in damp holes or where there is a problem cleaning the hole. Mist requires an increase in air/gas volume of about 20% and increases the injection pressure requirements by 5 to 10%. Mist drilling requires between 5 gal/min (20 l/min) and 15 gal/min (35 l/min) of water injection into the air line depending upon the air volume. Too little air only wets the cuttings and makes the lifting and mud ring problem worse; too much water forms slugs that destabilize the hole. The water must be injected evenly and consistently despite any chang-

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es in air pressure. If the blooie line shows alternate slugs of water and air, too much water and/or not enough detergent is being used. To avoid corrosion, the injection water must have a pH of above 9.5 at the blooie line and contain a corrosion inhibitor. The injection water may also contain shale-swelling inhibitors. Probably the most common is potassium hydroxide. Another effective inhibitor may be the synthetic shale inhibitor. Slugs of water and foamer (detergent) from the mist pump are often used to help clean the hole of cuttings. If it works, it is a useful technique, but it is best not to use too much water because it contributes to destabilization of the hole.

Corrosion problems and solutions

Look at the top, middle and bottom of the drill pipe for pits or orange or black stain. These are signs that corrosion is starting. Look carefully at any tong die marks near the tool joint; these are often where corrosion starts. A black stain on the pipe can be the sign of sulphate corrosion, and an orange stain indicates oxygen corrosion or rust. The color stain may not be important, or it may be the sign of the start of serious corrosion. Water or moisture and oxygen cause drill pipe and casing corrosion. The first defense is to have a pH above 9.5. This can be obtained with caustic soda (NaOH), potassium hydroxide (KOH3) or soda ash (NaHCO3). Check at the blooie line to be sure the pH is 9.5 or higher. The second defense against corrosion is a corrosion inhibitor. There are a large number of corrosion inhibitors for air drilling. Check at the blooie line for excess inhibitor, which means that the pipe is protected. There are a number of corrosion inhibitors that do not work well with air drilling. Among them are filming amines used for pipe on the rack. It is not a good choice for drilling operations; it is too soft and washes off the pipe in the hole and is generally not compatible with drilling fluid systems.

Drying a wet hole

It is often necessary to dry the casing or open hole when starting to air or gas drill. This always takes more time than seems reasonable. It is very time-consuming to dry a long section of open hole that was drilled with a liquid. Start with a quart or half-gallon of foamer down the drill pipe and then blow on the hole. The foamer treatment can be done several times. The pipe can be rotated slowly. Rotating helps because the

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MANAGED PRESSURE pipe will bang against the side of the casing or open hole and loosen wet cuttings and mud. Be careful with rotation of the drill pipe. Fast drill pipe rotation can cause the bottom joints to unscrew when the pipe is stopped or drags. Finally, to finish drying the hole it will be necessary to drill and let the cuttings adsorb the last of the water. Drill a few ft and circulate, and repeat this process until the hole starts to dust. In some cases, shutting in the hole and building pressure inside the wellbore, then releasing the pressure to the blooie line will help blow the mud and water out of the hole. This technique needs to be discussed to be sure that it does not conflict with the contractor’s or operator’s policies.

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Mist normally has these same three components with a lower concentration of both water and surfactants. In foam the liquid and the gas travel together as part of a bubble structure, which carries the cuttings out of the well. In mist, gas carries both the liquids and the cuttings out of the well, requiring much higher annular velocities, resulting in higher gas flow rates and more compression equipment. The question of how we know the system will behave as foam or as mist then arises.

Advantages of foam

Foam has the highest lifting capacity of any lightweight drilling fluid. It is, for example, an excellent milling fluid because it will lift steel cutting out of the hole with very little slip velocity. Foam exerts a pressure against the formation to help restrict formation flow or hole instability.

Foam drilling Introduction

Drilling equipment, procedures and problems discussed in this section are concerned with foam drilling. Foam is quite different than air/mist systems, and the two are not compatible for use at the same time, although a mist-drilled hole can be converted to foam or a foam-drilled hole could be converted to mist. Foam is a fluid with a structure. It could be represented as a figure as a six-sided gas bubble surrounded by a stiff coating of water. In the three-dimensional annulus, the six-sided gas bubble is actually 12-sided, but the effect is the same: foam has a structure.

History of foam drilling

The history of foam drilling dates back to the 1950s and has been a proven technology for many years. Recyclable foams were not available until late in the 1990s, which enabled the utilization of foam drilling offshore due to smaller footprints and environmental regulation. Many operations obtain penetration increases of seven to nine times that of overbalanced drilling (mostly in hard rock). The advantage of no lost circulation (most cases) is a critical economic and environment advantage. In addition, foam allows the use of much lower velocity in large wellbore wells versus dry gas or mist drilling, resulting in lower equipment needs. The ability of foam to carry out produced water is extremely high. Very soft formation or unstable shale generates problems for drilling with foam, as the wellbore integrity is poor.

Figure MP-13: Example of mist flow. Courtesy Weatherford International.

Foam, mist and in between

Figures MP-13 and MP-14 show how the returns look like in the systems called foam and mist. Foam requires the combination of a liquid (usually water), surfactants and a gas.

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Figure MP-14: Example of foam flow. Courtesy Weatherford International.

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MANAGED PRESSURE Corrosion of drill pipe can be a problem. The pH needs to be kept above 9.5 and corrosion inhibitors kept in the system on a consistent basis.

The wellbore pressure exerted by foam increases with depth because when the air or gas in the foam compresses, there is more fluid in the foam, and pressure increases with depth.

The compressors and fluid pump need to be kept coordinated to make a consistent fluid.

Foam is a good lost circulation blocker. In addition to being lighter than a drilling mud, the foam bubbles act like a lost circulation material to block loss of foam to the formation.

Foam circulates very slowly, and it can take an hour or more to circulate the annulus.

Foam uses very little water (or oil), because it is mostly gas. This is an advantage in desert areas or where disposing of drilling fluids is a problem.

Gas volume fraction

The gas volume fraction (GVF) is simply the volume of gas at given conditions divided by the total volume of the mixture. GVF is then a volumetric relationship that has nothing to do with how good the foam actually is. In any subsequent discussion in this document about this property, we will call this relationship GVF instead of using the confusing term “foam quality”.

Downhole fires will not normally occur with air foam. However there have been fires drilling with foam in a condensate-bearing formation probably because the condensate killed the foam. With condensate-bearing formations, it would be prudent to use nitrogen as the gas. Well kicks from gas or water can be controlled with fluid density by adding more liquid or reducing the gas.

The GVF can be confusing until you realize that the GVF could be 500:1 (500 cu ft of gas to 1 cu ft of water) at the surface, but only 0.25:1 at 10,000 ft (3000 m) downhole due to compression of the gas. It all depends upon:

Typical foam drilling problems

The primary problem with foam is composition. The gas and liquid must be added at a consistent rate. Bypassing air from a compressor is not good practice.

• • •

Foam chemical additions need to be added precisely to keep the fluid consistent.

Shale shaker Well fluid

Shaker pit Do not stir

Surface GVF (how much gas and water are being injected); Vertical depth of the hole; Backpressure held at the surface.

Pit level in shaker pit at 3/4

N2 Compressor To Well

Pump from shaker pit to pit # 2

Pit # 2

Mist Pump & Tank

Mix Pit

Recycle from this pit-discharge from this pit

Suction Pit

pH 10+ mix corrosion chemicals here

Figure MP-15: Foam recycle system.

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Soap injection pump

MANAGED PRESSURE

Water volume (liquid volume)

Foam uses a very small liquid volume because annular velocity is not critical. Foam lifts cuttings out of the hole by holding the cuttings in its structure, so there is very little slip or settling. Liquid volumes for foam can be as small as 20 gal/min (75 l/min) when rotary drilling a 5 ½-in. (72.6-mm) hole. Water volume increases as hole size gets larger.

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be some persistent fluff of foam on the surface. The recovered water can be mixed with makeup water and reused in the system.

Recycle foam

Gas volume

The foam can be recycled via a de-foaming process and rebuilding process. As the foam comes out of the RCD, defoamer is injected with extra water (as required). This action breaks the foam (breaking is a 95% action—it never breaks into just water and gas). To counter this fact it is a good idea to keep a low level in the first pit (no more than ¾ full. The broken foam will have a fluff-like top. Most of the defoamers contain alcohol so the top will also contain more alcohol. That is why the first pit is not stirred (let the alcohol build up). This practice makes it easier to re-foam the liquid.

Corrosion issues

When recycling, the makeup surfactant should be less than 0.4%, but let the foam tests dictate how much to use. It is often necessary to dump produced water out of foam systems, normally the second pit. Normally it is necessary to pump the liquid from the first pit to the second pit (do not flow over the top). It may seem as if these precautions are unnecessary, but they are important in keeping the foam job running smooth.

The liquid volume is much higher when using a drilling motor because the total volume of water plus compressed air at the pressure at the motor must be enough to efficiently operate the motor.

The injected gas volume at the surface is generally between 200 and 500 times the volume of liquid. Less than 200 times water volume generally does not constitute a good downhole foam, and more than 500 times water volume hampers efforts to prevent the foam from turning into a mist. (Remember in the English system, there are 7.48 gal/ cu ft).

In any mixture of air and water there will be some corrosion problems. Corrosion generally starts to show up as shallow pits in the pipe. Black stain on the drill pipe can be a sign of sulfide corrosion or some other reaction. A red stain can be the beginning of oxygen corrosion or just some rust on a trip. To avoid corrosion in water/air foam systems, the pH should be at least 9.5 at the flow line. Corrosion inhibitors should be checked at the flow line to be sure that there is excess inhibitor in the system. Bad corrosion generally is found in areas where there is serious corrosion in oil or gas production. Take special care to be aware of corrosion in those areas.

Operational considerations

The first operational consideration in using foam as a drilling medium is whether to use a one-pass system or to recycle the foam. Many factors enter into this decision. Probably the major one is environmental concerns. Recycling allows the minimizing of leftover fluid, especially for long jobs. However, recycling is more complex than a one-pass system.

One-pass system

For a one-pass system, the foam is flowed out to a pit or other storage system. Water can be recovered from the bottom of the storage pit after the foam has dissipated. Normal foams will break within about an hour, but there will

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Good practice involves using a desilter to clean the foamed liquid because the foam carries little pieces of dirt/rock that potentially interfere with further cutting carrying capacity.

Air hammer drilling

The air hammer is one of the best tools to use with air and foam drilling. It drills faster than straight rotary drilling. The most important part of hammer drilling is that it drills fast with the very light bit weight required to keep the hole straight. With the light bit weight required with a hammer, a simple pendulum assembly is sufficient. The oilwell drilling air hammer blows a free-floating hammer (piston) up and down on top of the anvil that is part of an air-drilling bit (Figure MP-16). The arrangement of the hammer hitting on the top of the air bit reduces the hammering effect on the drill string and collars and allows all the energy from the hammer strike to go into the bit. Typical hammer operation is 1,800 strikes/min. The vibration rate can be measured with a simple vibration meter held against the drill pipe. This is one of the best ways to see if the hammer is working properly. The impact force between the bit and the formation only requires enough bit weight to keep the hammer firmly on bottom, about 500-600 lbf/in. of bit diameter (1,050 N/cm), depending on the formation. Excessive bit weight actually slows the drilling rate.

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MANAGED PRESSURE

Air/gas directional drilling

Directional and horizontal holes can be drilled with foams. This has been done in the past with bent housings and “wagging” techniques with conventional bits. The use of an air hammer is more complex, because it must be rotated at least 20 rpm at all times. A major limitation to foam is the MWD survey. Mud pulse does not work in foam. However, there are other tools and techniques to overcome this problem. Bits used with directional air holes should produce very small cuttings that will blow out of the hole. Large cuttings will just roll around until they are broken to dust and then will blow out of the hole. Check for local advice on hole stability and directional equipment. Air/gas drilling produces vibrations that are very hard on downhole survey equipment.

Figure MP-16: Air hammers use high-shock energy for air-drilling operations through vertical and lateral intervals in hard rock formations. Air hammers drill quickly with very light bit weight needed to keep the hole straight. Courtesy Schlumberger.

The bit must be rotated when drilling on bottom; otherwise it will drill a triangular hole and become stuck. Rotation speed needs to be between 20 rpm and 60 rpm. Unlike rotary drilling, higher rotation speed does not necessarily mean higher drill rate. Try several speeds to see which is the most effective. Air hammers need lubrication; be sure to follow the recommendations of the service provider.

Limits to the air hammer

Fluid down the drill pipe and in the hole limits hammer efficiency. Most of the modern air hammers will work with foam if the formation is brittle and not too much water is used. Experience is about the only guide on the effectiveness of any brand of hammer with foaming operations. The local service provider should have an idea of the limits. • The hammer must be rotated at all times; • Undergauge hole is a very common problem as the bit wears. It may be necessary to reduce the hole diameter by 1/8 in. (3-4 mm) with each bit run; • Air hammers cannot be used to ream; • String reamers do not work well with foam; they restrict the expansion of air.

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Primary equipment for foam gas drilling

The minimum components needed for a straight air drilling set up include: • Primary compressors that develop 150-350 psi of air pressure; • High-pressure boosters that generally produce up to 1,200 to 1,500 psi of air pressure; • Interconnected and staked-down air lines and manifolds; • Blooie line or flow line and flare; • RCD to control the annulus flow; • Non-return valves are required at the bit and in the upper drill string. The compressors and boosters are placed in a safe area, i.e., not in a hazardous zone. The obvious reason for this is that large quantities of air are being withdrawn from the atmosphere, and there must be very little residual risk of the air containing hydrocarbons that may be returning from the well. The engines should be muffled, and in some areas spark arrestors are required. The diesel engines also require that they be run in a safe area free of hydrocarbon gas and free from dust at the blooie line. The fuel supply system will be in close proximity to the diesel- or natural-gas-driven equipment for similar reasons and to minimize lengths of fuel line running around the location.

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Surface air lines and the blooie or flow line

References

Blooie or flow line

IADC. “Well Planning”. Originally published in IADC Deepwater Well Control Guidelines. 2001.

High-pressure air lines need to be staked down, and quick-connects on the piping need to be chained. The pressure system should be tested before starting operations.

The blooie line, or flow line, should have at least as great an internal area as the top section of annulus. It should be straight without curves or corners that would cause it to move with slugs or water or cuttings. The longer blooie line, if used, should be staked down so that it cannot move. Because the blooie line is light pipe, it should have no obstructions or valves. Any valve at the blooie line should be at the BOP stack.

Aadnoy, Bernt, Iain Cooper, Stefan Miska, Robert F. Mitchell and Michael L. Payne. Advanced Drilling & Well Technology. Richardson, TX: Society of Petroleum Engineers, 2008.

IADC UBO/MPD Committee. UBO & MPD Glossary. UBO & MPD Glossary. IADC, 2011. http://www.iadc.org/wp-content/uploads/UBO-MPD-Glossary-Dec11.pdf. Lyons, William C and William C Lyons. “Air and Gas Drilling Manual.” Amsterdam: Elsevier/Gulf Professional Pub., 2009.

A common addition to the blooie line is a nozzle set at 4560° pointing downstream to produce a venturi effect with air/gas bypassed on a connection. This is typically placed either upstream near the BOP stack or near the end of the blooie line. Bypassing the air/gas on a connection through the venturi pulls a slight vacuum on the blooie line that reduces any gas buildup near the BOP stack or on the drill floor.

Rehm, Bill. Underbalanced Drilling: Limits & Extremes. Houston, Texas: Gulf Publishing Company, 2012.

Sample catching

Calderoni, Angelo, James Dennis Brugman, Rodney Elliot Vogel, and James William Jenner. 2006. “The Continuous Circulation System—From Prototype To Commercial Tool.” SPE Annual Technical Conference and Exhibition, San Antonio.

In many foam recycle drilling operations, closed commercial sample catchers are used to collect cuttings. There are also a large number of home-built sample catchers for onepass systems. One of the simplest is a 2-in. (50-mm) nipple welded on the bottom near the end of the blooie line. A short section of pipe with a valve on the end will collect the larger cuttings. A small ledge (often an old pipe die) can be welded inside the blooie line just below the nipple to help deflect cuttings into the catcher Poor cutting collection can mean that there are no large cuttings coming to the surface. This can be caused by insufficient air volume, washouts in the hole, or mud rings and dampness in the hole.

Air line manifold

There needs to be a manifold on the air/gas line before the air/gas enters the standpipe. The manifold should allow the air/gas to go to the standpipe or be blocked from the standpipe and sent to the venturi on the blooie line during connections and surveys.

IADC Drilling Manual

Rehm, Bill. Managed Pressure Drilling. Houston, Texas: Gulf Publishing Company, 2008. Well Control School. “Guide to Blowout Prevention.” Houston: 2014.

Calderoni, Angelo, Andrea Chiura, Pietro Valente, Farag Soliman, Enrico Squintani, Rodney Elliot Vogel, and James William Jenner. 2006. “Balanced Pressure Drilling With Continuous Circulation Using Jointed Drillpipe—Case History, Port Fouad Marine Deep 1, Exploration Well Offshore Egypt.” SPE Annual Technical Conference and Exhibition, San Antonio. Solvang, S.A., C. Leuchtenberg, I.C. Gill, and H. Pinkstone. 2008. “Managed-Pressure Drilling Resolves Pressure Depletion-Related Problems In The Development Of The High-Pressure High-Temperature Kristin Field’. SPE/IADC Managed Pressure Drilling and Underbalanced Operations Conference And Exhibition, Abu Dhabi.

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POWER GENERATION AND DISTRIBUTION

IADC Drilling Manual 12th Edition IADC Drilling Manual • Copyright © 2015

Enhancing operational integrity by ensuring a competent workforce

Accreditation & Credentialing

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he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. AUTHORS AND REVIEWERS Scott Gordon, Helmerich & Payne International Drilling Co. James Cue, Caterpillar Oil & Gas Bob Niederhauser, Louisiana CAT (formerly of MTU America) Lance Ellington, National Oilwell Varco David DeLaughter, National Oilwell Varco Mark Grimes, National Oilwell Varco

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POWER GENERATION AND DISTRIBUTION

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9915095-8-4

Printed in the United States of America.

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POWER GENERATION AND DISTRIBUTION Contents CHAPTER PW

PW-iii

Contents

POWER GENERATION AND DISTRIBUTION Introduction...................................................................PW-1 Engines............................................................................PW-1 Engine fuels.............................................................PW-1 Diesel fuel................................................................PW-2 Maintenance............................................................PW-2 Fuel heaters.............................................................PW-2 Switching grades / types of fuel.......................PW-2 Diesel fuel sulfur................................................... PW-3 Ultra-low sulfur-diesel (ULSD)......................... PW-3 Sulfur-free diesel fuel........................................... PW-3 Low-sulfur-diesel (LSD)...................................... PW-3 International Maritime Organization (IMO). PW-3 Diesel fuel sulfur impacts................................... PW-3 Biodiesel fuel.......................................................... PW-3 Additional maintenance requirements........... PW-4 United States engine emissions........................ PW-4 Engine installation....................................................... PW-5 Engine operations........................................................PW-7 Engine starting........................................................PW-7 Cold weather starting...........................................PW-7 Heaters.....................................................................PW-7 Air starting motor..................................................PW-7 Starting with ether................................................ PW-8 Fuel precautions.................................................... PW-8 Urea precautions................................................... PW-8 Intake vacuum vs load (API standard)........... PW-8 Instructions for use.............................................. PW-8 Engine shutdown......................................................... PW-9 Emergency stopping............................................ PW-9 Emergency stop button...................................... PW-9 Air shutoffs............................................................. PW-9 Manual stop procedure...................................... PW-9 After stopping engine....................................... PW-10 Engine maintenance ................................................ PW-10 Typical maintenance interval schedule........ PW-10 Lubrication............................................................ PW-10 Cooling system.................................................... PW-10 Air cleaners.......................................................... PW-12 Fuel supply system............................................ PW-12 Leaks or damage................................................. PW-12 Malfunctioning or needed repair................... PW-12 Engine troubleshooting........................................... PW-14

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Troubleshooting mechanical engines............ PW-14 Troubleshooting electronic engines.............. PW-15 Engine safety ....................................................... PW-15 Engine mounting/dismounting....................... PW-17 Engine starting..................................................... PW-17 Engine stopping................................................... PW-17 Engine electrical system................................... PW-18 Engine storage..................................................... PW-18 Putting engine into storage.............................. PW-18 Removing engine from storage....................... PW-18 Generators.................................................................. PW-19 Generator stator................................................. PW-19 Generator rotor................................................... PW-19 Generator bearings............................................ PW-19 Generator connection boxes........................... PW-19 Generator excitation system........................... PW-19 Optional generator PMG system................... PW-20 Other generator options................................... PW-20 Generator operations.............................................. PW-20 Generator startup checklist............................. PW-20 Generator startup .............................................. PW-21 Generator continuous operation..................... PW-21 Guide to allowable phase unbalance............. PW-21 Generator idling................................................... PW-21 Generator parallel operation............................ PW-22 Generator maintenance.......................................... PW-22 Generator maintenance schedule.................. PW-22 Generator safety.................................................. PW-25 Generator isolating for maintenance............. PW-25 Generator storage..................................................... PW-25 Putting generator in storage............................ PW-25 Removing generator from storage.................. PW-26 Transmissions............................................................ PW-26 Transmission maintenance............................... PW-26 Transmission troubleshooting......................... PW-27 Transmission safety............................................ PW-27 Transmission storage......................................... PW-27 Power distribution..................................................... PW-27 Introduction.......................................................... PW-27 DC/DC and SCR systems................................. PW-27 DC drilling motors............................................... PW-28 SCR (AC/DC) power systems.............................. PW-28

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POWER GENERATION AND DISTRIBUTION

AC electrical power generation...................... PW-28 Engines................................................................... PW-28 Generators............................................................ PW-28 3-phase power..................................................... PW-28 AC switchgear...................................................... PW-28 Electronic controls..............................................PW-30 Braking................................................................... PW-31 AC distribution..................................................... PW-31 VFD power systems................................................. PW-32 Theory of operation...........................................PW-33 Basic design..........................................................PW-33 Rectifiers................................................................PW-33 DC link....................................................................PW-33 Inverter...................................................................PW-34 DC/DC power systems..........................................PW-34 Controls.................................................................PW-34

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Braking................................................................... PW-35 System protection............................................... PW-35 Driller’s console...................................................PW-36 Maintenance.............................................................. PW-35 SCR controls......................................................... PW-35 Variable frequency drive (VFD)......................PW-36 AC generator controls........................................ PW-37 Motor control center (MCC) and switchgear.......................................................... PW-37 Driller’s console and foot throttle..................PW-38 Cable and wiring.................................................PW-38 Electric brake........................................................PW-39 DC motors and generators...............................PW-39 AC motors and generators...............................PW-40 Transformers........................................................PW-40 References..................................................................PW-41

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PW-1

Introduction

Engines provide the primary power source for drilling rigs. Drilling rigs are described as mechanical or electric. These terms refer to the method in which power is supplied to the equipment on the rig. On mechanical rigs, power from the engine(s) drives the rig equipment either directly or through a torque converter. From these devices clutches control the smooth transfer of power from the engine to the transmission. The transmission allows changes in speed and torque to be transferred from the engines to the rig equipment, such as draw works and mud pumps. Electric rigs use engine power to drive one or more generators. The generated electricity is then used to operate motors for the larger equipment on the rig. Typical rig equipment, for both mechanical and electric, include a draw works, a rotary table and mud pumps. These equipment items are among the larger equipment on the rig and will have the most significant and important power requirements. The basic operations, maintenance, and troubleshooting for the following drill rig components will be covered in this chapter for engines and generators. Content within each section progresses from older to newer technology.

Engines

There are two types of engines classified by how they are governed: mechanical and electronic. Mechanical engines are controlled without the use of electronics. They rely on mechanical governing (speed control) devices to operate the engine. Electronic engines are similar to mechanical, except that they use electronic governing devices to operate and monitor the engine. Electronic engines control engine performance and exhaust emissions more efficiently, and some have some built in diagnostic capabilities.

Engine fuels

Engines can use various fuels. Number 2 Diesel is the predominant fuel used in the drilling industry; however, natural gas engines and engines that use a diesel and natural gas mixture are gaining popularity. Always consult your diesel engine manufacturer for fuel usage recommendations. Figure PW-1: Examples of engines in use on drilling rigs. Clockwise from top: Cummins, Caterpillar and Detroit Diesel.

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POWER GENERATION AND DISTRIBUTION

Diesel fuel Types

The two basic types of distillate diesel fuel are No. 2 diesel fuel and No. 1 diesel fuel. No. 2 diesel fuel is the most commonly available summer grade diesel fuel. No. 1 diesel fuel is a winter-grade diesel fuel. During the winter months fuel suppliers will typically blend No. 1 and No. 2 diesel fuel in various percentages. Blending allows the fuel to meet the historical low ambient temperature cold-flow needs for a given area or region. No. 2 diesel fuel is a heavier diesel fuel than No. 1 diesel fuel. In cold weather, heavier fuels can cause gelling (cloud point) problems in fuel filters, fuel lines, fuel tanks, and fuel storage. Heavier diesel fuels such as No. 2 diesel fuel can be used in diesel engines that operate in cold temperatures with an appropriate amount of a proven pour point depressant additive (typically kerosene). For more information on fuels which include blends of No. 1 and No. 2 diesel fuel, consult your fuel supplier. There are several methods used to compensate for fuel qualities that might interfere with cold-weather operation. These methods include the use of starting aids, engine coolant heaters, fuel heaters, and de-watering. In addition, the manufacturer of the fuel can add cold flow improvers and/or blend No. 1 and No. 2 diesel in various percentages. Not all areas of the world classify diesel fuel with the No. 1 and No. 2 nomenclature. But the basic principles of using additives and/or blending fuels of different densities are identical.

Maintenance

• Use fuel that meets or exceeds the manufacturers’ requirements for distillate diesel fuel; • Confirm with the filter manufacturer that the fuel filter/ filters to be used are compatible with the fuel type that will be filtered; • Fill tanks with fuels of “ISO 18/16/13” cleanliness level or cleaner and/or as recommended by your diesel engine manufacturer; • It is recommended that fuel be filtered through a series of filters (fuel/water separators) when transferring from one storage tank to another. This includes from shipping to storage, and from storage to consumption; • Test for microbial contamination on a regular basis and take proper corrective action if contamination is present; • Drain water and sediment from the fuel storage tank weekly or when refilled. After the fuel tank has been filled, allow the fuel to settle for 10 min to let the water and sediment separate from the fuel; • Drain water and sediment from the engine fuel tank daily;

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• Top off fixed roof fuel tanks as often as practical. Keeping the tank full reduces the amount of condensation generated water; • Diesel fuel has a maximum shelf life of 1 year from production.

Fuel heaters

• The fuel heater heats the fuel above the cloud point before the fuel enters the fuel filter, which prevents wax from blocking the filter. Fuel can flow through pumps and lines at temperatures below the cloud point because the pour point is often lower than the cloud point. While the fuel can flow through these lines, the wax in the fuel can still plug the fuel filter; • In some cases cloud point can be eliminated or reduced by adding insulation and/or changing the location of fuel filters and supply lines. In extreme temperatures, heating of the fuel may be required to prevent the filters from plugging. There are several types of fuel heaters that are available. The heaters typically use either engine coolant or exhaust gas as a heat source. These systems may prevent filter plugging problems without the use of de-watering or cold flow improvers (kerosene); • A fuel heater should be installed so that the fuel is heated before flowing into the fuel filter; • A fuel heater is not effective for black starts unless the fuel heater can be powered from an external power source. External fuel lines may also require heaters. Long runs of fuel lines may require in-line heaters; • Only use properly sized fuel heaters that are controlled by thermostats or use fuel heaters that are selfregulated. Thermostatically controlled fuel heaters generally heat fuel to 15.5° C (60° F). Do not use fuel heaters in warm temperatures; • If a fuel with a low viscosity is used, fuel cooling may be required to maintain proper viscosity at the fuel injection pump. Fuels with a high viscosity might require fuel heaters in order to lower the viscosity to the proper level. Consult with your engine manufacturer for proper viscosity levels; • When you use fuel heaters, do not allow the fuel temperature to reach above 52°C (125°F). Never exceed 75°C (165°F) with straight distillate fuel. The high fuel temperatures affect the fuel viscosity.

Switching grades/types of fuel

• The fuel storage tanks must be cleaned thoroughly before converting to Ultra Low Sulfur Diesel (ULSD) (15 ppm or less sulfur) and/or biodiesel/biodiesel blends; • Conversion to ULSD and/or biodiesel/biodiesel blends can loosen fuel system and fuel storage tank deposits. Fuel filters should be changed more often initially to allow for this cleaning effect.

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Diesel fuel sulfur

• Various emissions laws, regulations and mandates control the maximum allowable fuel sulfur level. Consult federal, state, and local authorities for guidance on fuel requirements for your area.

Ultra-low sulfur diesel (ULSD)

• U.S. EPA regulations require the use of Ultra Low Sulfur Diesel fuel (ULSD), ≤ 0.0015% (≤ 15 ppm (mg/kg)) sulfur, for nonroad and stationary Tier 4 EPA certified engines using fuel sensitive technologies such as SCR systems and particulate filters. Fuels other than ULSD can cause damage in those engines and should not be used (Figure PW-2). • ULSD was introduced for the US on-highway diesel engine market in October 2006. ULSD is available since December 2010 for nonroad diesel engines and machines. Refer to the U.S. EPA for the required ULSD point of sales dates for various nonroad applications. • Engines certified to nonroad Tier 4 standards (Stage IV in Europe) and are equipped with fuel sulfur sensitive exhaust after treatment systems are designed to run on ULSD only. Use of LSD or fuels higher than 15 ppm (mg/kg) sulfur in these engines will reduce engine efficiency and engine durability and will damage emissions control systems and/or shorten their service interval. Failures that result from the use of fuels are not manufacturer defects; therefore, the cost of repairs would not be covered by the manufacturer’s warranty. • Certain governments/localities and/or applications MAY require the use of ULSD fuel. • The maximum allowable fuel sulfur level for most pre-Tier 4 engines that are equipped with DOC (Diesel Oxidation Catalyst) is 0.05% [500 ppm (mg/kg)]. Some DOC equipped engines require the use of fuel with a maximum of 0.005% (50 ppm (mg/kg)) fuel sulfur. Refer to your engine manufacturer’s recommendations.

Sulfur-free diesel fuel

• European sulfur-free fuel, 0.0010% (10 mg/kg) sulfur, fuel is required by regulation for use in engines certified to EU nonroad Stage IIIB and newer standards and that are equipped with exhaust after treatment systems. This is defined in “European Standard EN 590:2004.”

Low-sulfur diesel (LSD)

• Low sulfur diesel (LSD - S500) is defined by the U.S. EPA as a U.S. diesel fuel with sulfur content not to exceed 500 ppm or 0.05% by weight. • Note: Both ULSD and LSD must meet the fuel requirements outlined in the most current revision level of “ASTM D975.”

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PW–3

International Maritime Organization (IMO)

• The IMO regulates the fuel sulfur level for ocean going ships. Current marine fuels at sea that are regulated by the IMO can have sulfur levels up to 3.5% (35,000 ppm) prior to the year 2020. As of January 1, 2020, ships operating in international waters are required to use fuels with sulfur levels below 0.5% (5,000 ppm).

Diesel fuel sulfur impacts

• Sulfur in the fuel results in the formation of sulfur dioxide (SO2) and sulfur trioxide (SO3) gases during the combustion process. When combined with water, this exhaust gas can form acids. These acids can impact engine components and engine lubricants. • Typical after treatment systems include Diesel particulate Filters (DPF), Diesel Oxidation Catalysts (DOC), Selective Catalytic Reduction (SCR) and/or Lean NOx Traps (LNT). Other systems may apply. • Sulfur in the exhaust gas can interfere with the operation of after treatment devices causing: ŠŠ Loss of particulate trap/regeneration performance; ŠŠ Reduced catalyst efficiency; ŠŠ Increased particulate matter emissions. • Use of fuels with higher than recommended and/or maximum allowed fuel sulfur levels can and/or will: ŠŠ Increase wear of engine components; ŠŠ Increase corrosion of engine components; Increase deposits; ŠŠ Increase soot formation; ŠŠ Shorten the time period between oil drain intervals (cause the need for more frequent oil drain intervals); ŠŠ Shorten the time interval between after treatment device service intervals (cause the need for more frequent service intervals);Negatively impact the performance and life of after treatment devices (cause loss of performance); ŠŠ Lower fuel economy; ŠŠ Increase overall operating costs. • Fuel sulfur levels above 0.1% [1000 ppm (mg/kg)] may significantly shorten the oil change interval.

Biodiesel fuel

Biodiesel is a fuel that can be made from various renewable resources that include vegetable oils, animal fat, and waste cooking oil. Soybean oil and rapeseed oil are the primary vegetable oil sources. Biodiesel can be blended with distillate diesel fuel. The blends can be used as fuel. The most commonly available biodiesel blends are B5, which is 5% biodiesel and 95% distillate diesel fuel, and B20, which is 20% biodiesel and 80% distillate diesel fuel. Note the percentages are volume-based. U.S. distillate diesel fuel specification “ASTM D975-09a” includes up to B5 (5%) biodies-

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POWER GENERATION AND DISTRIBUTION

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PW–4

During 2011-2012, it was possible to buy engines from three different tiers. you cannot Tierdo 1 std If you do Therefore, only two tiers are possible for 2015 and beyond TPEM program under 40 CFR Part 89 Figure PW-2: US EPA emissions categories. Tiers 1-4 showing flexibility allowances for engines greater than 560 kW/750 hp.

el. Currently, any diesel fuel in the U.S. may contain up to B5 biodiesel fuel. European distillate diesel fuel specification “EN 590” includes up to B5 (5%) and in some regions up to B7 (7%) biodiesel. Any diesel fuel in Europe may contain up to B5 or in some regions up to B7 biodiesel fuel. Storage life is a maximum of 6 months from production. For biodiesel and biodiesel blends that are greater than B20 it may be much shorter than 6 months.Always consult your diesel engine manufacturer for fuel usage recommendations.

Additional maintenance requirements

• When biodiesel fuel is used, crank case oil and after treatment systems may be influenced. This influence is due to the chemical composition and characteristics of biodiesel fuel such as density and volatility. Chemical contaminants can be present in this fuel, such as phosphorous, alkali and alkaline metals (sodium, potassium, calcium, and magnesium). Oil analysis is highly recommended when using any biodiesel blend; • Crankcase oil fuel dilution can be higher when biodiesel and/or biodiesel blends are used. This increased level of fuel dilution when using biodiesel and/or biodiesel blends is related to the typically lower volatility of biodiesel. In-cylinder emissions control strategies utilized in many of the latest engine designs may lead to a higher level of biodiesel concentration in the sump. The long-term effect of biodiesel concentration in crankcase oil is currently unknown. Oil analysis is highly recommended when using any biodiesel blend; • Biodiesel fuel contains metal contaminants (phosphorous, sodium, potassium, calcium and/or magnesium) that form ash products upon combustion in the diesel engine. The ash can affect the life and performance of after treatment emissions control devices and can accumulate in Diesel Particulate Filters (DPF). The ash accumulation may cause the need for

IADC Drilling Manual

TPEM program under 40 CFR Part 1039

EPA

Year NOx + HC PM

Tier 1 2000 Tier 2 2006 Tier 3 2011

9.2 + 1.3 0.54 6.40

0.20

3.5 + 0.4 0.10

Tier 4 2015 3.5 + 0.19 0.04 Figure PW-3: New emissions regulations for land-drilling engines exceeding 750 hp when into effect in 2001, 2006 and 2011, with another changes scheduled for 2015.

more frequent ash service intervals and/or cause loss of performance.

United States engine emissions

The issue of emissions regulations into the oilfield is a complex one and must be approached with caution when it is time to repair or replace existing equipment. Consult with your original engine manufacturer in making the best decision based on your time, budget and application. Note that many countries (e.g., Canada) are adopting US EPA regulations for their own standard levels. Each of the changes in regulations are geared to reduce the amount of NOx, HC (hydrocarbons) and PM (particulate matter) in the exhaust stream from running reciprocating engines – whether the fuel source is gaseous or diesel. Some regulations even go so far as to prohibit the import of equipment that do not meet the current emissions requirements. The general rule of thumb is as follows: you can repair an existing engine and keep it “grandfathered” or you may replace

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POWER GENERATION AND DISTRIBUTION

Figure PW-4: Parallel or bore misalignment occurs when the cdenterlines of the driven equipment and the engine(s) are parallel but not in the same plane.

an engine with a “like for like” replacement (same model, HP and speed if available) – otherwise a current emissions certified product must be installed into the application. In simple terms - if you increase the horsepower or kW of the engine – you may then have to use a new engine to meet the current emissions Tier level requirement. As indicated in Figure PW-3, for land-drilling engines greater than 750 hp, new emissions regulations went into effect in 2001, 2006 and 2011, with another change scheduled for 2015. Even this rule of thumb can get complicated as local agencies may override the “grandfather” clause or regional laws may require “Best Available Control Technology” (BACT). When a BACT is determined, factors such as energy consumption, total source emission, regional environmental impact, and economic costs are taken into account and require any equipment used in that governing bodies area of responsibility meet the most stringent current standard. Places within the continental US that may require BACT are the States of California and Wyoming - amongst others. Consult with your engine manufacturer to determine the laws and regulations in effect for the region of the world you are working in, or wish to relocate equipment into.

PW–5

Figure PW-5: Face runout is the distance that the face of the hub is out of perpendicular to the shaft centerline.

equipment should comply with the recommendations of both engine and driven equipment manufacturers. Before aligning, both engine flywheel and flywheel housing, as well as the driven equipment, should be checked for run-out resulting from handling or service. Alignment may be maintained with shear blocks or dowel pins; Parallel (or bore) misalignment occurs when the centerlines of the driven equipment and the engine(s) are parallel but not in the same plane as shown above. 4. Flexible Coupling and Drum or open-type Air Clutches: During initial installation of driven equipment, shafts and hubs should be aligned to the flywheel before installing coupling or clutch. Proper alignment procedure considers angular, parallel and runout (Figure PW-4). Extreme caution must be exercised to prevent thrust loading of the engine crankshaft. This and misalignment can result in severe damage to the engine. Most flexible couplings will tolerate only a minimum of misalignment. Refer to the manufacturer’s specifications for maximum limits; Face runout refers to the distance the face of the hub is out of perpendicular to the shaft centerline as shown in Figure PW-5.

Engine installation

1. Mounting: All engines should have solid, vibration-free, mounting. Installation of box-base type engines with full-length supports is desirable. Shims or other precision methods should be used to avoid uneven support and distortion of the engine structure; 2. Leveling: Engines should be as level as possible. Install shims when necessary (preferably stainless steel); 3. Alignment: The alignment of the engine with the driven

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Angular or face misalignment occurs when the centerlines of driven equipment and the engine(s) are not parallel as shown Figure PW-6. 5. Sheaves, bearings and clutch shafts: Drive pulleys should be mounted as close to the engine as possible. This places the load near the clutch main bearing and

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POWER GENERATION AND DISTRIBUTION

Figure PW-6: Angular or face misalignment occurs when the centerlines of driven equipment and the engine(s) are not parallel.

tends to reduce the overhang load on the bearings. Heavy tools should not be used to drive sheaves or similar equipment on the clutch shafts. Such procedure can damage bearings and cause difficulty in the removal of sheaves. Caution should be exercised in installing excessively large diameter or heavy-drive pulleys. The recommendations of the manufacturer for such installation should be carefully followed. Excessive force should not be used to drive sheaves or similar equipment on the clutch shafts. Such procedure can damage bearings and cause difficulty in the removal of sheaves. Taper bushing type is best; Bore runout refers to the distance the driving bore of a hub is out of parallel with the shaft centerline as shown Figure PW-7. 6. Engine exhaust: Each engine exhaust system should be of sufficient size so that back pressure at the engines does not exceed manufacturer’s recommendation. It is desirable to include in the exhaust piping a short section of flexible tubing or expansion bellows for vibration isolation, thermal expansion, and ease of alignment on installation. Exhaust piping should be independently supported to prevent damage to the engine. Care should be exercised to prevent welding slag or any foreign material from entering the engine during installation. Do not connect exhaust from several engines to a common header. All exhaust systems should be protected against water entry and a suitable trap and drain provided to prevent condensate from returning to the engine; 7. Protection against weather: Proper protection against weather should be provided during storage or installation. For storage longer than a few days, use the protection materials and methods recommended by the engine manufacturer. Engines should not be stored with the cooling system in a dry condition as this promotes

IADC Drilling Manual

Figure PW-7: Bore runout refers to the distance the driving bore of a hub is out of parallel with the shaft cdenterline.

rust and deterioration of seals. The cooling system should be flushed, filled, circulated and stored with a sufficient solution of clean water, antifreeze, and rust inhibitor; 8. Engine cooling system: Only clean water, soft or treated, should be used in the engine cooling system. Do not use chemically-softened water. The use of corrosion inhibitors should be added every 250 hours (1 month) of operation; Permanent antifreeze contains a rust inhibitor which deteriorates in a short period of time and must be replaced at regular intervals. Some antifreeze has no rust inhibitor. Provide and mark suitable system drains. Unless anti- freeze is to be used, drain complete system including air intercoolers and intercooler circulating lines in cold weather. All water system piping should comply with engine builder’s size recommendations. The top tank of the radiator, or the expansion tank when using heat exchangers, should always be the highest point in the system and always higher than the cylinder heads with no high point air traps. 9. Cooling air: Engines should be oriented to take advantage of prevailing winds. Suction or blower fans should be used as best suited to conditions. When engines are installed inside buildings, sufficient openings should be provided for the intake and exhaust of cooling air. Any danger of recirculating the cooling air should be eliminated by the use of ducts. Where thermally actuated cooling water control valves are used, the capillary tubing should be as short as practical in order to prevent interference from outside temperature sources. Exhaust stacks, crank-case breathers and other sources of oily vapors should be vented to prevent build-up on radiator cores and the contamination of dry-type air cleaners;

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POWER GENERATION AND DISTRIBUTION 10. Fuel system: When installing fuel piping, all foreign material should be removed from lines before they are connected to the engine. Lines of adequate size should be installed and adherence to safety codes should be observed. Adequate strainers and liquid traps should be provided in the fuel system. Day tanks are recommended for diesel engines. It is desirable to include a section of flexible tubing for vibration isolation. Non-restricting shut-off valves should be provided in the fuel lines immediately adjacent to the engine. Gas regulators, their orifices and springs should comply with the engine builder’s recommendations; 11. Battery starting systems: The battery should be installed in a clean, cool, ventilated, accessible, and vibration-free location, which is as close to the starting motor as practicable. Before installation, the battery should be checked for correct polarity. Cable size must be adequate to prevent excess voltage drop; 12. Air and gas starters: Gas starters must have sealed pinions so that gas cannot enter engine flywheel housing. Where gas starters are used, exhaust gas should be piped a safe distance from the engine. Air starters should have a lubricator. The air receiver should be drained daily to keep water from entering the starter; 13. Control equipment: Consideration should be given to the use of engine temperature control equipment and to the use of safety devices such as low oil pressure and high water temperature cutoffs. Such devices should be operable and not blocked out; 14. Transporting, loading and unloading: Engines can suffer twisted frames or other harm from careless handling. During loading and unloading operations, adequate tools for skidding, or non-crushing slings should be used to prevent such damage. Lifting by winch lines hooked around the engines is not recommended. Lifting eyes on engines and generators are for installation only and should not be used to lift a complete package. Jacking or pushing against the vibration damper or flywheel can cause severe damage. Always check runout after moving engine to new location. Do not use steel bands, load binding straps or chains across the engine crankshaft or PTO shaft when hauling engines; 15. Fire and explosion hazards: Consideration should be given to the elimination of all possible sources of fires and explosions, particularly in hazardous locations.

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PW–7

Engine operations Engine starting

Before starting the engine do a walk-around inspection looking for and correct any of these conditions: • Any type of leaks (coolant, lube or fuel). If leaking is suspected, check the fluid levels more often than recommended until the leak is found or fixed, or until the suspicion of a leak is proved to be unwarranted; • Loose or deteriorated parts; • Drive belts; • Guards in the proper place; • Ensure that the areas around the rotating parts are clear; • Low fluid levels; • Air cleaner service indicator; • Loose/damaged electrical connections.

Cold weather starting

Starting fluid is required for temperatures below 0 °C (32 °F). The use of other optional cold starting aids is recommended for temperatures below -18 °C (0 °F);

Heaters

• Oil pan immersion heaters are not recommended for heating the lube oil. To ensure the compatibility of the components, only use equipment that is recommended by the manufacturer; • Startability will be improved at temperatures below 12 °C (55 °F) with a starting aid. A jacket water heater may be needed and/or the crankcase oil may need to be warmed; • A jacket water heater is available as an option for starting in temperatures as low as 0 °C (32 °F). The jacket water heater can maintain the water temperature at approximately 32 °C (90 °F). The heated water will help to keep the oil in the engine block warm enough to flow when the engine is started; o Note: The fluid that is heated must be continuously circulated. This will help to prevent localized overheating of the fluid; • When No. 2 diesel fuel is used, a fuel heater will maintain the temperature of the fuel above the cloud point. Fuel line insulation will help to maintain the fuel temperature.

Air starting motor

The maximum air pressure for starting must not exceed 1,030 kPa (150 psi). To start the engine at colder temperatures, the following conditions may be necessary: • Maximum air pressure for the starting motor; • An additional volume of air.

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POWER GENERATION AND DISTRIBUTION

Table PW-1: The manifold vacuum and horsepower an engine will develop decreases with altitude.

Intake manifold vacuum (in. of mercury)

Sea Level

20 in.

2,000 ft

18 in.

4,000 ft

16 in.

6,000 ft

14 in.

8,000 ft

12 in.

10,000 ft

10 in.

• Additional injections may be necessary in order to start the engine. Press the starting aid switch about every two seconds until the engine begins to idle smoothly. Percent of engine horsepower

Figure PW-8: Vacuum load curves vs percentage of power.

Starting with ether

WARNING: Personal injury or property damage can result from alcohol or starting fluids. Alcohol or starting fluids are highly flammable and toxic and if improperly stored could result in injury or property damage. Ether starting aid is the only system that is recommended for the injection of starting fluid. Perform the procedures that are described in your engine manufacturer’s Operation and Maintenance Manual. • Ensure that the driven equipment is unloaded; • Move the throttle so that fuel is provided to the engine; • NOTICE: Do not crank the engine continuously for more than 30 seconds. Allow the starting motor to cool for two minutes before cranking the engine again. • Crank the engine. Use of the starting aid depends on these conditions: ŠŠ The engine control module controls the duration of automatic ether injection in these circumstances: ŠŠ The jacket water coolant temperature is between -40 to 30 °C (-40 to 86 °F); ŠŠ The engine rpm is more than 75 rpm and less than 400 rpm; • Manual ether injection can be performed in these circumstances: • The momentary contact switch for the ether injection is activated; • The jacket water coolant temperature is between -40 to 30°C (-40 to 86°F); • The engine rpm is more than 75 rpm and less than 400 rpm; • Excessive starting fluid can cause piston and ring damage; • Use starting fluid for cold starting purposes only. Do not use excessive starting fluid during starting or after the engine is running; • To inject ether manually, press the starting aid switch. Release the switch immediately;

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Fuel precautions

Diesel fuel begins to gel at approximately 15°F. Consult with your fuel supplier when it is appropriate to use blended fuel for cold weather operations. Consult with your diesel fuel supplier for storage recommendations and equipment.

Urea precautions

Engines using Selective Catalytic Reduction (SCR) to meet emissions regulations will use urea solutions to reduce NOx emissions. The freezing point for these solutions is also approximately 15°F. Urea lines need to be heated to prevent freezing in cold weather. Consult with your urea supplier for storage recommendations and equipment.

Intake vacuum vs load (API standard)

(For use on four cycle engines of two or more cylinders equipped with carburetors for liquid or gaseous fuels.) The vacuum load curves shown in Figure PW-8 are an index of the approximate percentage of power (within three percent on new engines), that an average engine in proper adjustment will develop at a given location. These curves are average of curves obtained from six representative engine manufacturers covering many models of 2 1/2-in. to 9 3/8-in. bore. They can be used at any altitude at which any non-turbocharged engine can be used. The curves shown cannot be used on turbocharged engines.

Instructions for use

1. Ensure that the engine being checked is in good adjustment. Check spark, gas supply, gas pressure, and carburetor adjustment before taking vacuum readings. Use a conventional vacuum gauge with dial graduated to read inches of mercury; 2. Run engine at normal operating speed NO LOAD and note manifold vacuum;

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POWER GENERATION AND DISTRIBUTION

PW–9

3. Run engine at normal operating speed LOADED and note manifold vacuum;

stop button, see the instructions that are provided by the OEM of the equipment.

4. Select curve to vacuum line indicated on the LOADED engine (Item 3). From this point on, the curve follows down vertically to the percentage of load indicated on the horizontal line.

NOTICE: Do not start the engine until the problem necessitating the emergency stop has been located and corrected.

NOTE: The manifold vacuum and horsepower an engine will develop decreases with an increase in altitude. Engine manufacturers consider sea level barometric pressure (29.92 in. of mercury) standard. The power developed decreases about 3% with each thousand feet in altitude. Likewise, the no-load vacuum decreases with increasing altitude. An engine that will show 20-inches no-load vacuum at sea level will show the following no-load vacuum altitudes noted at normal operating speeds. EXAMPLE: Operator observes engine developing 17-in. vacuum at no load and normal speed. Load is applied and engine develops 10-in. vacuum. Follow down 17-in. curve until it crosses 10-in. horizontal. Drop down vertically at this point to base line. Engine is developing approximately 48% of full power. Failure to duplicate former readings on properly adjusted engine when running at NO-LOAD NORMAL SPEED, will indicate poor engine condition due to poor gas supply, loss of compression, ignition timing, etc. Failure to obtain former readings at NORMAL LOAD and SPEED will indicate either change in engine efficiency or change in load. Field men should become familiar with vacuum curve readings on their engines properly adjusted and in good operating condition to enable them to detect variation in either load or engine condition.

Engine shutdown Emergency stopping

NOTICE: Emergency shutoff controls are for EMERGENCY use ONLY. DO NOT use emergency shutoff devices or controls for normal stopping procedure. Ensure that any components for the external system that aid the engine operation are secured after the engine is stopped.

Emergency stop button

Use of the emergency stop will shut off the fuel. The air shutoffs will also be activated. For operation of the emergency

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It may be necessary to reset the emergency stop button before the engine can be restarted. If the emergency stop button is used, both of the air shutoffs must be reset before the engine can be restarted. The power for the control system must be cycled before the engine can be restarted.

Air shutoffs

The air shutoffs are actuated by either electric current or oil pressure when energy to a solenoid is interrupted. Each air shutoff uses a moving plate to block inlet air to the aftercooler. The engine stops because of the restricted air supply to the combustion chamber. The air shutoffs will actuate for the following conditions: • The emergency stop button is pressed; • The air shutoff is activated; • An overspeed shutdown occurs; • The electronic control module loses power. Note: A “master kill switch” may be supplied by the customer in order to activate the air shutoffs. The air shutoffs must be manually reset before the engine is restarted. To reset the air shutoffs, turn the reset knobs to the “OPEN” position. Ensure that both of the air shutoffs are reset.

Manual stop procedure (non-emergency)

NOTICE: Stopping the engine immediately after it has been working under load can result in overheating and accelerated wear of engine components. Allow the engine to gradually cool before stopping the engine. Excessive temperatures in the turbocharger center housing will cause oil coking problems. There may be several ways to stop the engine. Ensure that the stopping procedure is understood. Use the following general guidelines for stopping the engine. 1. Disengage the driven equipment. Unload the compressor or pump; • Disengage the clutch (if equipped); • Place the transmission and/or other attachments for the power take-off in NEUTRAL; 2. Reduce the engine RPM to low idle. Operate the engine at low idle rpm for a cool down period before stopping the engine;

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PW–10

POWER GENERATION AND DISTRIBUTION

• If the engine has been operated at a low load, operate the engine at low idle for approximately 30 seconds before stopping the engine; • If the engine has been operated at a high load, operate the engine at low idle for three to five minutes before stopping the engine; 3. Shut off the engine according to the instructions that are provided by the manufacturer.

After stopping engine

Check the engine coolant and crankcase oil levels. Perform a visual inspection. If necessary, perform minor adjustments. Repair any leaks and tighten loose bolts.

Engine maintenance Typical maintenance interval schedule

See Figure PW-9 for general engine nomenclature and components locations. General engine maintenance varies by engine size, manufacturer, and usage (load profile). Consult the engine manufacturer for specific recommendations. These should be read and used. The lubrication and oil change intervals recommended in these manuals are very important and should not be extended without consulting with the manufacturer or his representative. The following suggestions will help to establish a good Preventative Maintenance Program. This material may or may not be covered in the manufacturer’s manual. All work done, the hours of engine operation and the amounts of oil, antifreeze, rust inhibitor and special lubricants used should be recorded daily. Also all gauge readings should be recorded along with ambient temperature and the type of activity you are using the engines for, such as drilling, WOC, or tripping. Extended maintenance intervals may be achieved by developing a maintenance program with stringent oil and coolant sampling procedures as well as personal experience with the rig maintenance personnel. Consult the engine manufacturer for more details on how to develop a program to potentially extend maintenance intervals. When required: • Replace batteries; • Clean/replace air cleaner elements; • Prime fuel system; • Clean radiator.

• • • • • • • • •

Inspect/replace/lubricate driven equipment; Check air cleaner differential pressure; Clean air precleaner; Check engine oil filter differential pressure; Check engine oil level; Check fuel system fuel filter differential pressure; Drain fuel tank water and sediment; Inspect instrument panel; Walk-around inspection.

Lubrication

The crankcase oil level in both main and starting engine should be checked and oil added if needed. Be careful not to overfill the crankcase as this can damage crankshaft seals and cause the oil to foam. At this time the oil should be inspected for signs of water, fuel dilution, dirty beyond normal conditions, or obviously thickened, or thinned. If any of these exist they should be corrected immediately and the oil replaced at this time. The proper lubricants recommended by the manufacturer must be used. Different manufacturers recommend different grades of crankcase oil for their engines. All points recommended by the manufacturer as requiring daily attention should be checked, e.g., fan drive and clutch bearings.

Cooling system

Coolant water level should be checked and a proper coolant added if necessary. Do not overfill. Coolant level should be above the radiator core. If not, this will cause aeration and result in cracked cylinder heads. When checking the coolant level, the coolant should be checked for signs of oil (crankcase, torque converter, etc.), air bubbles (combustion gases), rust or scum. If any of these conditions exist, the cause should be repaired immediately and the coolant replaced. The entire cooling system including water lines, cylinder block and head should be checked for leaks. These should be repaired immediately to prevent aeration and loss of coolant. Any hoses that have become hard or brittle need to be replaced. If an overheating problem exists and cannot be corrected by yourself, call for help. Do not put a water hose in the radiator and let it overflow as this will destroy your radiator cores. Do not remove thermostats from your engines as this will cause further overheating. Radiator caps on pressurized cooling systems should be removed only when the engine is at low idle or stopped and then only with extreme caution. Always keep the radiator cap installed on a pressurized system and be certain it is holding pressure. On air cooled engines, the flywheel air screen and air intake stack should be checked, and any foreign material removed. If flywheel air screen or intake stack is very dirty, the fins on heads and cylinder blocks should be inspected and cleaned, if necessary. If cylinder block fins are rusty, they should be thoroughly cleaned with a wire brush.

Typical daily checklist: • Check coolant level;

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POWER GENERATION AND DISTRIBUTION

Control Panel

Aftercooler (Intercoler)

Air shutoff valve

PW–11

Air filer housing (Turbo and exhaust behind this)

Breather

Fuel filter housing Oil filter housing Information plate (behind the wiring)

Serial number plate (behind the wiring)

Engine control module SCAC pump

Left side

Oil dipstick

Right side Air filer housing (Turbo and exhaust behind this)

Oil cooler

Fuel, Oil, and Water pumps

Figure PW-9: Left (top) and right sides of typical drilling engine. Courtesy Caterpillar.

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POWER GENERATION AND DISTRIBUTION

Air cleaners

Air cleaners and breather opening should be checked and cleaned as required according to the design and condition of the cleaner. Oil bath air cleaners should never be run without oil. When cleaning dry type, care should be taken not to damage the sealing surface or to knock or blow a hole in the element. In extremely dusty conditions air cleaners may need to be serviced several times a shift. Stopped-up air cleaners are a major cause of turbocharger failures. Precleaners and two-stage air cleaners are available and should be considered if extremely dusty conditions prevail.

•

•

•

Fuel supply system

The fuel-supply system should be checked by draining the sump traps and strainers. Water (condensation) should be drained from all diesel tanks. Excessive amounts of water should be recorded and reported to rig manager. Buy clean fuel and keep it clean.

•

•

Leaks or damage

A visual inspection should be made of all water, fuel, lubricant lines, fittings, and valves for indications of leaks or damage. Report and repair any broken or loose mounting bolts, any indication of misalignment or physical damage.

•

Malfunctioning or needed repair

•

Any malfunction or necessary repair should be reported. Always furnish model, serial number and specification number.

fins on heads and cylinder blocks. Always dry and relubricate governor and control linkage joints after cleaning. Water pump: Water-pump seals should be inspected and packing on packed-type pumps should be tightened or replaced, if necessary. Fan belts: Fan belts should be checked for proper tension and tightened or loosened, if needed. Do not over-tighten. Lubrication of generator and accessories: Check your manufacturer’s lubrication guide for proper lubrication of all accessories. If you do not have one, ask for help. Many accessories need special lubrication or have hidden or unapparent lubrication points. The oil level on hydraulic governors should be checked and proper oil added if needed. Power take-off clutch: The power take off clutch should be lubricated and, if required, adjusted according to the instructions of the manufacturer. Do not over-lubricate. Gas regulators: Gas engines should be checked for gas pressure at the primary and final regulators. Breather Elements: All removable breather elements should be carefully cleaned and washed in non- toxic, non-explosive solvent (not gasoline). Change oil on those elements requiring re-oiling. Follow instructions carefully on dry type element service. Diesel fuel filters: Diesel fuel system strainers should be cleaned and filters replaced as scheduled, by the engine builders.

Every 500 service hours: • Change engine oil and filter (without centrifuge).

Initial 250 service hours: • Inspect/adjust engine valve lash; • Inspect/adjust fuel injector. Every 250 service hours: • Check battery electrolyte level; • Inspect/adjust/replace belts; • Collect coolant sample and analyze; • Test/add coolant additives; • Collect engine oil sample and analyze; • Inspect/replace hoses and clamps. Here are some additional maintenance guidelines: • Daily inspection items: All of the daily inspection items as given previously should also be performed in the weekly inspection. • Cleaning: If necessary, the engine exterior should be thoroughly cleaned with a non-toxic, non-explosive solvent (not gasoline). Compressed air or hot water should be used for flushing and drying. Care should be taken to not wash or blow dirt into inaccessible locations behind filler openings or into ignition or injection equipment; or on air-cooled engine, into the

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Every 1,000 service hours: • Clean engine; • Clean crankcase breather; • Check engine protective devices; • Clean/inspect/replace fuel system primary filter; • Replace fuel system secondary filter; • Change engine oil and filter (with centrifuge). • Daily and weekly inspection items: All of the daily and weekly inspection items as given previously should also be performed in the monthly inspection. • Ignition system: On spark ignition engines the following ignition devices, depending upon the type used, should be checked: ŠŠ Magneto point condition, clearances and timing; ŠŠ Impulse function; ŠŠ Spark-plug gap and heat range; ŠŠ Distributor condition with respect to the automatic advance mechanism. • Valves: The external appearance of the valve mechanism should be checked, as well as the condition of the valve rockers, push-rod ends, and valve stems.

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POWER GENERATION AND DISTRIBUTION

•

•

•

• •

•

All valve clearances should be set according to the instructions of the engine manufacturer. Valve timing should be checked if an adjustable timing device is provided. The compression on all cylinders should be measured, if the engine lacks power or if the condition of valves and rings is questionable. The functioning of the compression-release device should be checked on diesel engines, if it is used. Engines using hydraulic valve lifters should be checked for sounds of lifter malfunction and the manufacturer’s inspection procedure followed. Starting equipment: The starting equipment should be carefully tested and inspected. Starting engines should be checked for lubrication and general condition; special attention being given to the mounting bolts, bendix drive lubrication, engagement link- age, pinion-gear teeth mesh and adjustment, and fuel-tank strainer. Manufacturer’s recommendations for specific makes and types of engines should be observed. Add the recommended lubricant to air starter lubricant reservoirs and clean air traps of dirt. If electric starters are used, the system should be checked for loose connections, worn wires, or makeshift repairs. Engine mounts: Engine mounts should be inspected and tightened, if required. A check should be made for signs of engine shifting, misalignment, loosening of coupling or sheave, or improper loading. Any shifting should be corrected and all points of alignment rechecked. Cooling fan: The cooling fan should be examined for evidence of physical damage or cracking in the hub or spider area. If the fan-hub bearings require lubrication by disassembly and packing or by installation of a special grease fitting, this operation should be performed. Safety shields: All fan belt and shaft safety shields should be repaired and reinstalled. Rocker covers and inspection doors: New gaskets should be used on all rocker covers and inspection doors, if removed. Season check of cooling system: Particularly at the changes of the season and when starting to use or remove antifreeze, the cooling system should be flushed thoroughly. The thermostats should also be removed and tested for correct functioning. Evidence of scale, sludge, or rust deposits in the cooling system warrants further investigation, and a special cleaning of oil coolers and heat exchangers may be necessary. The proper mix of antifreeze and water is very important. A 50/50 mixture is considered the best except in extremely cold climates. Never run pure antifreeze in a cooling system. Rust inhibitor recommended by the manufacturer should be used at all times and the required additional amounts added every month or 250 hours operating time. Inhibitors recommended by the

IADC Drilling Manual

•

•

•

•

•

PW–13

manufacturer should be used. Soluble oil can damage O-rings. Crankcase: Inspection plates should be removed, if the crankcase is so equipped, and a check made for sludge in the crankcase. The oil-pump screen should be checked, and cleaned if necessary. Safety devices, generator and battery: A check should be made of safety devices. Check the actual function of over temperature, low oil pressure, and overspeed shutdowns. If the engines are equipped with backfire valves or crankcase explosion relief valves, these should be checked for condition and evidence of damage. Vibration damper: Inspect the vibration damper for damage, run out, signs of deterioration or loss of viscous material, or looseness. Turbocharger: Inspect turbocharger compressor impeller for accumulations of dirt, dust and oil. Clean according to manufacturer’s recommendations. If slack in the bearing or signs of the compressor impeller touching the housing is found, this should be corrected immediately. Throttle and governor: The governor linkage and butterfly-shaft end should be checked for free movement through their full range. Minor governor adjustments should be made, if needed; and throttle and governor controls should be lubricated. Compounded engines should be synchronized and a careful check made for proper functioning of vacuum gauges, pyrometers, tachometers, oil pressure gauges, torque converter pressure and generator outputs.

Every 2,000 service hours: • Inspect crankshaft vibration damper; • Check driven equipment; • Check engine mounts; • Inspect turbocharger. Every 3,000 service hours or 3 years: • Change coolant or add coolant extender. Every 4,000 service hours: • Inspect/adjust valve lash; • Inspect/adjust fuel injector. Every 6,000 service hours or 3 years: • Inspect water pump. Every 6,000 service hours or 6 years: • Inspect alternator; • Change coolant; • Replace water temperature regulator; • Inspect starting motors; • Inspect water pump.

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PW–14

POWER GENERATION AND DISTRIBUTION

Overhauls (top end and major) • Consult with the engine manufacturer.

Engine troubleshooting Troubleshooting mechanical engines

When an internal-combustion engine fails to function properly, the causes must be found and corrected promptly. Since most internal-combustion engines react in much the same way to specific maladjustments, a check list of possible causes of trouble often will be helpful in locating the difficulty. Following are trouble shooting hints for diesel engines. When contacting the engine manufacturer’s local dealer to fully service the engine, be sure to have the engine make and generator’s serial number available, as the dealer will need it to repair the engine in a more timely fashion.

Starting difficulty

If a diesel engine fails to start or does not start readily, the following possible causes of trouble should be checked in an effort to locate the difficulty.

Fuel failure, low-pressure side: 1. 2. 3. 4. 5. 6. 7. 8. 9.

Line valves not open; tank empty; Safety switch not being held open by operator; Cold fuel; Plugged fuel filters, or dirt in lines between filter and pump; Fuel tank too low in relation to transfer pump; Dirt under transfer-pump valves or worn valves; Air lock in fuel pump or injection pump; Ice in lines or traps; Fuel transfer pump from tank not operating properly.

The foregoing items may be checked by opening the bleeder valve and cranking the engine. A pressure gauge should be used in the bleeder-valve hole to check for primary pump pressure. A hand plunger may be used on the transfer, if desired. A substantial flow of fuel without air bubbles should exit from the bleeder opening.

Fuel failure, high-pressure side:

1. Enrichment lever not in proper position; rack partly closed in cold weather; 2. Engine control switch in wrong position; 3. Air locks in high-pressure lines; 4. Broken or disconnected pump-drive coupling; Note: The foregoing items can be checked by loosening the line-coupling nuts a few turns at each nozzle and cranking engine. A substantial flow of fuel should occur at each injec-

IADC Drilling Manual

tion impulse. If no fuel appears and an equate flow of fuel is known to have reached the plungers, either the plungers or delivery valves may be stuck as a result of poor fuel, improper storage, or inadequate lubrication. 5. Poor nozzle spray pattern or gummed or corroded nozzles; 6. Faulty injection timing; 7. Glow plugs too cold (when equipped); 8. Battery voltage low (A fully charged 12-volt heavy-duty battery at normal temperatures will show 10.5 volts while cranking); 9. Poor compression (Check each cylinder); 10. Liquid lock between piston crown and cylinder head due to flushing oil from storage, leaking head 11. gasket, or leaking injector; 12. Low cranking speed due to weak batteries, poor starter condition, or thick, cold oil. Engine stops running: If the diesel engine suddenly stops running, the following possible causes of trouble should be checked in an effort to locate the difficulty. 1. Lack of fuel; 2. Fuel lines obstructed or broken; 3. Automatic low oil-pressure or high water- temperature safety control may have operated; 4. Excessive overload or improper governor adjustment may cause the engine to stall; 5. Plugged fuel-tank vent; 6. Damaged transfer or injection pump drive. Low power: If the diesel engine has low power and runs unevenly, the following possible causes of trouble should be checked in an effort to locate the difficulty. 1. Inadequate supply of fuel to pump; 2. Fuel-tank vent partially plugged; 3. Faulty timing; 4. Delivery valves not operating properly; 5. Dirty or damaged injection plunger; 6. Leaking fuel lines or air in lines; 7. Damaged or excessive clearance in blowers; 8. Overflow valve or injector drain line feeding back into primary pump inlet; 9. Dirty or clogged nozzles; 10. Air cleaner or manifold obstructed; 11. Low or uneven compression: a. Broken valve spring; b. Sticking valves; c. Badly worn rocker arms; d. Sticking cam followers; e. Bent throttle control linkage; f. Binding of injector-rack control tube or injector racks; 12. Fuel oil not to specification; 13. Restricted exhaust line;

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POWER GENERATION AND DISTRIBUTION 14. Leaking turbocharger air connections; 15. Dirty or damaged turbocharger; 16. Improper intercooler operation. Surging or irregular speed: If the diesel engine develops a surge or irregular speed, the following possible causes of trouble should be checked in an effort to locate the difficulty: 1. Governor needs lubrication; 2. Improper grade of governor oil (hydraulic governors); 3. Governor improperly adjusted; 4. Injection pump: a. Lack of lubrication; b. Insufficient fuel supply for primary system; c. Irregular operation of automatic bleeder valve; air entrapment in pump and lines, valves, or nozzles; d. Inaccurate pump timing; 5. Slipping clutch or belt drive; wide variation in loads of poor regulation on electrical equipment; 6. Dirty or damaged turbocharger system. Overheating: If the diesel engine overheats, the following possible causes of trouble should be checked in an effort to locate the difficulty: 1. Excessive exhaust back pressure: 2. Restricted muffler or loose baffles in muffler; 3. Cooling system: a. Insufficient coolant; b. Radiator frozen or clogged (tubes and tanks); c. Radiator core dirty (external); d. Water hose clogged; e. Slipping fan belt; f. Thermostat stuck; g. Cooling system inadequate; h. Improper air recirculation; i. Aeration of water from leaking gaskets or pump; j. Defective water pump; k. Excessive back pressure on external cooling system; l. Air shroud, air stack, cylinder-head fins or cylinderblocked with debris; 4. Combustion: a. Improper fuel; b. Faulty injection timing, retarded or wrong cycle; c. Faulty injection nozzle; d. Pump setting incorrect; 5. Lubrication: a. Improper or excessive time between oil changes; b. Air-locked or plugged oil filter, cooler, or screen; 6. Load: a. Prolonged service at excessive load; b. Improper synchronization of two or more engines; 7. Installation: a. High exhaust back pressure due to improper piping or muffling; b. Insufficient air circulation when engines are

IADC Drilling Manual

PW–15

operating in closed spaces; c. Improper turbocharging; intercooler too hot. Low or fluctuating oil pressure. If the diesel engine develops a low or fluctuating oil pressure, the engine should be stopped at once and the following possible causes of trouble should be checked in an effort to locate the difficulty: 1. Oil: a. Insufficient oil; b. Dirty filters, oil coolers, or sump screen; c. Improper grade of oil; d. Foaming oil due to water leakage; 2. Valve: a. Worn, sticking, or loose relief valve; b. Vent behind relief valve plugged; c. Inaccurate pressure gauge.

Troubleshooting electronic engines

The basic principles of the troubleshooting electronic engines are similar to those of mechanical engines. However, electronics can add a layer of complexity as the electronics themselves can be a contributor to the problem. Some engines have control panels which give you engine diagnostics. Some engines require a laptop and special software to diagnose and fix. It is strongly recommended to contact your engine manufacturer’s local dealer to service the engine.

Engine safety

Caution should be used in working on engines. Hot parts or hot components can cause burns or personal injury. Do not allow hot parts or components to contact your skin. Use protective clothing or protective equipment to protect your skin. Do not operate or work on this equipment unless you have read and understand the instructions and warnings in the Operation and Maintenance Manual. Failure to follow the instructions or heed the warnings could result in injury or death. Refer to the equipment manufacturer’s manuals. Unless other maintenance instructions are provided, never attempt adjustments while the engine is running. Proper care is your responsibility. Always utilize appropriate PPE such as a hard hat, protective glasses, ear protection, and other protective equipment and clothing as required. Utilize lock-out tag-out before the engine is serviced or repaired. When appropriate, disconnect the starting controls. Do not allow unauthorized personnel on or around engine when engine is being serviced.

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PW–16

POWER GENERATION AND DISTRIBUTION

Stay clear of all rotating parts and of all moving parts. Leave the guards in place until maintenance is performed. After the maintenance is performed, reinstall the guards. Keep objects away from moving fan blades. Cautiously remove the following parts. To help prevent spraying or splashing of pressurized fluids, hold a rag over the part that is being removed: • Filler caps; • Grease fittings; • Pressure taps; • Breathers; • Drain plugs. Unless other instructions are provided, perform the maintenance under the following conditions: • The engine is stopped. Ensure that the engine cannot be started; • The protective locks or the controls are in the applied position (lock-out, tag-out); • Disconnect the batteries when maintenance is performed or when the electrical system is serviced. Disconnect the battery ground leads. Tape the leads in order to help prevent sparks; • When starting a new engine, make provisions to stop the engine if an overspeed occurs. If an engine has not been started since service has been performed, make provisions to stop the engine if an overspeed occurs. Shutting down the engine may be accomplished by shutting off the fuel supply and/or the air supply to the engine; • Do not attempt any repairs that are not understood. Use the proper tools. Replace any equipment that is damaged or repair the equipment; • Start the engine with the operator controls. Never short across the starting motor terminals or the batteries. This method of starting the engine could bypass the engine neutral start system and/or the electrical system could be damaged.

hands to check for leaks. Always use a board or cardboard for checking engine components for leaks. Ensure that all of the clamps, the guards, and the heat shields are installed correctly. Lines and hoses must have adequate support and secure clamps.

Exhaust

Exhaust fumes can be hazardous to your health. If you operate the equipment in an enclosed area, ensure for adequate ventilation.

Asbestos information

Use caution and follow guidelines when you handle any replacement parts that contain asbestos or when you handle asbestos debris.

Engine coolant and oils

When the engine is at operating temperature, the engine fluids will be hot. Fluids may be under pressure. Allow engine system components to cool before any system is drained. Check fluid levels after the engine has stopped and the engine has been allowed to cool. Cooling system conditioner contains alkali. Alkali can cause personal injury. Do not allow alkali to contact the skin, the eyes or the mouth. Hot oil and hot lubricating components can cause personal injury. Do not allow hot oil or hot components to contact the skin. If the application has a makeup tank, remove the cap for the makeup tank after the engine has stopped. The filler cap must be cool to the touch.

Engine batteries

The liquid in a battery is an electrolyte. Electrolyte is an acid that can cause personal injury. Do not allow electrolyte to contact the skin or the eyes. Do not smoke while checking the battery electrolyte levels. Batteries give off flammable fumes which can explode.

Pressurized air and water

Pressurized air and/or water can cause debris and/or hot fluids to be blown out which could result in personal injury. When pressurized air and/or pressurized water are used for cleaning, wear protective clothing, protective shoes, and eye protection. Avoid direct spraying of water on electrical connectors, connections, and components.

Lines, tubes and hoses

Do not bend or strike high-pressure lines. Do not install lines, tubes, or hoses that are damaged. Inspect all lines, tubes, and hoses carefully. Repair any fuel lines, oil lines, tubes, or hoses that are loose, leaking or damaged. Do not use bare

IADC Drilling Manual

Always wear protective glasses when you work with batteries. Wash hands after touching batteries. The use of gloves is recommended.

Engine fire hazards

All fuels, most lubricants, and some coolant mixtures are flammable. Flammable fluids that are leaking or spilled onto hot surfaces or onto electrical components can cause a fire. Do not operate a product when a fire hazard exists.

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POWER GENERATION AND DISTRIBUTION

PW–17

Determine whether the engine will be operated in an environment that allows combustible gases to be drawn into the air inlet system. These gases could cause the engine to overspeed. If the application involves the presence of combustible gases, consult your equipment manufacturer for additional information about suitable protection devices.

49°C (120°F). Keep ether cylinders away from open flames or sparks.

Pay particular attention to these cautions: • Store fuels and lubricants in properly marked containers; • Do not expose the engine to any flame; Exhaust shields (if equipped) must be installed correctly.

Mount the engine and dismount the engine only at locations that have steps and/or handholds. Do not climb on the engine, and do not jump off the engine. Face the engine in order to mount the engine or dismount the engine. Do not use any controls as handholds. Do not stand on components which cannot support your weight. Use an adequate ladder or use a work platform. Do not carry tools or supplies when you mount the engine or when you dismount the engine.

Wiring must be kept in good condition. Properly route and attach all electrical wires. Check all electrical wires daily. Repair any wires that are loose or frayed before you operate the engine. Clean and tighten all electrical connections. Eliminate all wiring that is unattached or unnecessary. Do not use any wires or cables that are smaller than the recommended gauge. Do not bypass any fuses and/or circuit breakers. Inspect all lines and hoses for wear or for deterioration. Properly install all oil filters and fuel filters. The filter housings must be tightened to the proper torque. Use caution when refueling an engine. Do not smoke or refuel an engine near open flames and always stop the engine before proceeding. Gases from a battery can explode. Keep any open flames or sparks away from the top of a battery. Do not smoke in battery charging areas. Never check the battery charge by placing a metal object across the terminal posts. Use a voltmeter or a hydrometer. The batteries must be kept clean. The covers (if equipped) must be kept on the cells. Use the recommended cables, connections, and battery box covers when the engine is operated. Use proper jumper cables and do not jump/charge a frozen battery. Make sure that a fire extinguisher is available. Be familiar with the operation of the fire extinguisher. Inspect the fire extinguisher and service the fire extinguisher regularly. Obey the recommendations on the instruction plate.

Ether

Ether is poisonous and flammable. Do not inhale ether, and do not allow ether to contact the skin. If using ether, do so in a well-ventilated area. Do not smoke while you are replacing an ether cylinder or while you are using an ether spray. Do not store ether cylinders in living areas, in the engine compartment, in direct sunlight, or in temperatures above

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Do not spray ether into an engine if the engine is equipped with a thermal starting aid for cold weather starting.

Engine mounting/dismounting

Engine starting

IMPORTANT: For initial start-up of a new or rebuilt engine, and for start-up of an engine that has been serviced, make provision to shut the engine off should an overspeed occur. This may be accomplished by shutting off the air and/or fuel supply to the engine. Before starting the engine, ensure that no one is on, underneath, or close to the engine. Ensure that the area is free of personnel. If equipped, ensure that the lighting system for the engine is suitable for the conditions. Ensure that all lights work properly, if equipped. Do not bypass or disable the automatic shutoff circuits. See the Service Manual for repairs and for adjustments. Always start the engine according to the procedure that is described in the Operation and Maintenance Manual, or your company’s procedures.

Engine stopping

To avoid overheating of the engine and accelerated wear of the engine components, stop the engine according to the manufacture’s Operation and Maintenance Manual. Use the Emergency Stop Button (if equipped) ONLY in an emergency situation. DO NOT use the Emergency Stop Button for normal engine stopping. If an emergency shutdown occurs, do not restart engine until a cause is identified and the corrective actions are completed. Use caution when removing crank case covers to avoid flash fires. On the initial start-up of a new engine or an engine that has been serviced, make provisions to stop the engine if an overspeed condition occurs. This may be accomplished by shutting off the fuel supply and/or the air supply to the engine.

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Engine electrical system

Battery electrolyte is an acid. Electrolyte can cause personal injury. Do not allow electrolyte to contact the skin or the eyes. Always wear protective glasses for servicing batteries. Wash hands after touching the batteries and connectors. Use of gloves is recommended. Never disconnect any charging unit circuit or battery circuit cable from the battery when the charging unit is operating. A spark can cause the combustible gases that are produced by some batteries to ignite. The electrical systems for the generator, the engine and the control systems must be properly grounded. Proper grounding is necessary for optimum performance and reliability. Improper grounding will result in uncontrolled electrical circuit paths and in unreliable electrical circuit paths. Uncontrolled electrical circuit paths can result in damage to main bearings, to the surface of crankshaft journals, and to aluminum components. Uncontrolled electrical circuit paths can also cause electrical activity that may degrade the performance of the generator set’s electronics. The alternator and the starting motor must be grounded to the negative “−” battery terminal. A ground plate with a direct path to the negative “−” battery terminal may be used as a common ground for the components of one engine system. For engines with an alternator that is grounded to an engine component, a ground strap must connect that component to the negative “−” battery terminal. Also, that component must be electrically isolated from the engine. The ground strap for the alternator must be of a size that is adequate for carrying the full charging current of the alternator.

Engine storage

This section provides high-level procedures and recommendations on engine preparation for storage up to one year. Always consult your engine manufacturer for full details on preserving the engine. If long term storage for a period of time that exceeds one year is necessary, consult your engine manufacturer. Otherwise for periods less than one year, the following represents the typical procedures for preparing and removing engines from short term storage.

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Putting engine into storage

1. Clean the outsides of the engine and touch up any rusty surfaces; 2. Drain the oil and remove the filters. Replace with new oil and filters; 3. Add a mixture of volatile corrosion inhibitor (VCI) and oil into the engine at various points per your engine manufacturer’s procedures; 4. Drain diesel fuel, change fuel filters, and fill with kerosene or calibration fluid; 5. Drain coolant, clean the cooling system, and refill the system with new coolant. Raw water is not recommended; 6. Apply grease to all outside parts that move such as rod threads, ball joints, linkage, etc; 7. Install all covers over any water ingress points including exhaust systems and ensure that weatherproof tape has been installed over all openings; 8. It is best to remove the batteries. If the batteries are not removed, wash the tops of the batteries, disconnect the battery terminals, and place a plastic cover over the batteries; 9. Loosen all belts; 10. Place a waterproof cover over the engine; 11. Remove the waterproof covers in order to check for corrosion in two to three months intervals. If the engine has signs of corrosion at the time of the check, repeat the protection procedure.

Removing engine from storage

1. Remove all outside protective covers; 2. Change the oil and filters; 3. Check the condition of the fan and alternator belts. Replace the belts, if necessary. Tighten to specification; 4. Replace the fuel filter elements; 5. Use a bar or a turning tool to turn the engine in the normal direction of rotation in case there are hydraulic locks or any resistance; 6. Before starting the engine, remove the valve cover or covers. Put a large amount of engine oil on the camshaft, cam followers and valve mechanism in order to prevent damage to the mechanism; 7. Pressurized lubricating of the engine is necessary to ensure immediate lubrication. Also, pressurized lubricating will prevent damage to the engine. The damage occurs in the first seconds after start-up; 8. Check the condition of all rubber parts. Replace if necessary; 9. Before start-up, test the coolant. Adjust the coolant mixture if necessary; 10. Prime the engine with clean diesel fuel before starting; 11. Follow the engine manufacturer’s procedure for initial operation requirements once the engine starts;

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12. On the first day of operation, check the entire engine several times for leaks and correct operation.

Generators Generator stator

The stator consists of the supporting frame, core, and armature windings. The stator core is made from laminations, thin sheets of electrical steel, which are stacked and held in place by steel endrings and support bars. The rings and bars are welded to or are part of the steel frame. Base mounting plates are welded to the bottom of the frame. The base mounting plates allow the assembly to be mounted on the genset base. The windings (coils) are constructed of layered and insulated copper wire. The coils are inserted in the core slots, connected together, and the entire assembly is vacuum-pressure impregnated with resin. Stator leads terminate in standard connection lug or strap terminals for ease of connection to the load.

Generator rotor

The main rotor assembly is the revolving field. It consists of windings in a core, which is in turn mounted on a steel shaft. The exciter armature assembly and optional permanent magnet generator (PMG) rotor are also mounted on the shaft as are the fan(s) and other optional accessories. The core consists of laminations, thin sheets of electrical steel, which are stacked together. The core makes the salient poles (four, six, eight or 10). With six or more poles, the poles are typically attached to a center hub. The rotor windings consist of insulated magnet wire wound around each pole. V-blocks between each pole keep the rotor windings in place. Damper windings consist of copper or aluminum rods that are inserted through each pole surface and are brazed to copper or aluminum damper end plates at each end of the lamination stack. The end plates are brazed to adjacent poles to form a continuous damper winding. The ends of the windings are supported with bars or aluminum pole shoes. The rotor either has resin applied during the winding process or is vacuum-pressure impregnated with resin. The shaft is made from high-strength rolled or forged steel and machined to accommodate all the rotating generator components. Keyways in the shaft ensure precise positioning of the rotor, exciter armature, and optional PMG rotor as well as drive couplings. On the exciter side, the shaft has a slot or hole in its centerline for running the revolving field leads to the rectifier.

IADC Drilling Manual

Figure PW-10: Cutaway of generator for drilling rig. Courtesy Caterpillar.

Generator bearings

The generator may contain either one or two bearings. Bearings are typically ball or roller type and are either: • Heavy duty double shielded bearings, typically used on smaller generators and are greased for life; • Re-greaseable bearings, which contain fill and drain ports for easy lubrication. Sleeve bearings are optional on some designs. A supplementary instruction will be included in the manual package for sleeve bearings if they are applicable to this generator.

Generator connection boxes

The main lead connection box houses the load lead terminals. In addition, the generator may have auxiliary connection boxes for connecting temperature detector outputs, space heater connectors and sensing outputs.

Generator excitation system

The excitation system consists of the exciter stator assembly and the exciter armature assembly: The exciter stator assembly comprises windings in a core constructed from steel laminations that are stacked and welded together. The main exciter stator coils reside in slots in the core, forming alternate north and south poles. The entire assembly is either mounted to the end bracket or mounted in a frame, in turn mounted to the end bracket. The stator is a stationary field, powered by the voltage regulator. The exciter armature assembly comprises two subassemblies: the exciter armature and the rotating rectifier. The exciter armature assembly contains steel laminations that are stacked and keyed on the shaft or on to a sleeve, which is keyed to the generator shaft. A three-phase winding is inserted into slots in the laminations. The coils are held in place by insulating wedges. The coil extensions are braced with tape. Output leads from the winding are connected to the rotating rectifier assembly.

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The rotating rectifier is a three-phase full wave bridge rectifier, converting the AC from the exciter armature to DC, which is transferred to the revolving field windings. Two aluminum steel plates, each containing three rotating rectifier diodes, are mounted on each side of an insulating hub to form the negative and positive terminals. The plates also act as heat sinks for the diodes. Excitation system functional overview: Exciter field control is established by the strength of the exciter field current developed by the voltage regulator system. The DC voltage and current levels of the exciter field signal from the voltage regulator varies depending upon the generator output voltage and the loading of the output lines (see Figure PW-12).

Optional generator PMG system

The PMG system functions as a pilot exciter, providing power to the automatic voltage regulator power supply. The PMG is an AC generator that uses permanent magnets in the rotor instead of electromagnets to provide the magnetic field. The permanent magnet generator (PMG) system consists of the PMG stator and PMG rotor: See Figure PW11. The PMG stator is a stationary armature and is located within the stator assembly that also contains the exciter stator or is a separate stator mounted next to the exciter stator. The PMG stator consists of steel laminations. The laminations are held in place by steel compression rings and are welded to the frame bars of the exciter-PMG frame. The PMG windings are placed in slots in the laminations. Insulating wedges are inserted at the top of each slot to hold the coils in position.

Other generator options

Other options include, but are not limited to, space heaters, filters, and temperature sensing devices.

Generator operations Generator startup checklist

After electrical connections have been made, perform the following checks: 1. Check all the connections to the electrical diagrams provided; 2. Secure all covers and guards; 3. Turn the rotor slowly with the appropriate starting mechanism (bar the engine or flywheel) through one revolution to see if the rotor turns freely; 4. Check the bearings to see they are properly lubricated; 5. Determine the direction of the engine rotation, and make sure that it matches the rotation of the generator; 6. Make sure the power requirements comply with the data on the generator nameplate; 7. Make sure that the engine-generator set is protected with an adequate engine governor and against excessive overspeed; 8. Make sure the output of the generator is protected with an overload protection device, such as circuit breakers or fuses, sized in accordance with national/ international electrical code and local electrical code standards. Fuses need to be sized using the lowest possible current rating above the full-load current rating (115% of rated current is commonly recommended); 9. Remove tools and other items from the vicinity of the generator.

The PMG rotor consists of rectangular permanent magnets and cast pole tips secured to a steel hub with nonmagnetic stainless steel bolts. The PMG rotor is keyed to the shaft and secured with a nut and lock washer.

Figure PW-11: Overview of excitation system (with an optional PMG).

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Generator startup

The following steps detail initial startup for generators with both automatic and manual voltage control: 1. Disconnect the generator output from the load by opening the main circuit breaker; 2. Turn the manual voltage adjust rheostat fully counterclockwise; 3. Put the auto-manual switch in the manual position; 4. Start the prime mover, and bring the set to rated speed. Turn the manual voltage adjust rheostat to reach rated voltage. Close the output circuit breaker, and apply load in steps until the rated load is reached. Adjust the manual adjust rheostat as necessary to obtain the desired output voltage; 5. Gradually reduce load, and adjust the rheostat accordingly until no load is reached. Open the circuit breaker, and stop the prime mover; 6. Actuate the auto voltage rheostat. Then start the genset, and bring it to rated speed. Adjust the voltage to the desired value; 7. Close the output circuit breaker. Then check the generator voltage and voltage regulation. Apply load in steps until the rated load is reached; 8. Check for vibration levels at no load and rated load. A slight increase is normal. As the load is maintained for 2-3 hours, the vibration levels will gradually increase and reach a final level. The following steps detail initial startup for generators with automatic voltage control only (generator has an automatic voltage regulator (AVR) with no auto-manual switch): 1. Disconnect the generator output from the load by opening the main circuit breaker; 2. Turn the voltage adjust rheostat fully counterclockwise. Start the prime mover, and bring the set to rated speed. Turn the voltage adjust rheostat to obtain the desired voltage; 3. Close the output circuit breaker, and apply load in gradual steps until the rated load is reach. Note the voltage regulation with the changes in load steps; 4. Check for vibration levels at no load and rated load. A slight increase is normal. As the load is maintained for 2-3 hours, the vibration levels will gradually increase and reach a final level.

Generator continuous operation

Operate the generator within the nameplate values. (Operating the unit beyond nameplate values may cause equipment damage or failure.) If the generator is operated below the rated power factor and voltage, decrease the kVA to prevent overheating of the field and stator windings. Consult the factory for derating factors if the application requires the unit to be operated beyond nameplate values.

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Figure PW-12: This graph enables determination of whether the generator is operating in a balanced or unbalanced phase. See instructions in text.

Rotor overheating may occur when the generator is carrying excessive unbalanced loads. Negative sequence currents flowing in the field pole face cause the rotor heating. For a general guide to the allowable phase unbalance, see Figure PW-12, which is based on a 10% equivalent negative sequence current.

Guide to allowable phase unbalance

Using Figure PW-12, follow these steps to determine whether you are within allowable phase balance: 1. Determine the minimum and maximum currents in any phase, expressed as a percent of rated current; 2. Draw an imaginary line to the right from the minimum current phase on the Y axis. Then draw an imaginary line up from the maximum current phase on the X axis; 3. The point where the two lines intersect will determine whether you are in a balanced or unbalanced phase. Loss of field excitation can result in the unit operating out of synchronization with the system when operating is parallel. This has the effect of producing high currents in the rotor, which will cause damage very quickly. Protective relays should be considered to open the circuit breaker. In the example shown in Figure PW-12, the minimum current in any phase is 20% of rated, and the maximum is 60%. As the figure shows, the intersection of the two lines lies in the excessive unbalance region.

Generator idling

Unless the voltage regulator has V/Hz protection built in, having the generator set in operating mode while idling the engine can cause permanent equipment damage. If engine adjustments require that the engine be run at idle speed and the regulator does not have V/Hz protection, make the generator regulating system inoperative during idling by one of

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the following methods: • When the generator is provided with a voltage shutdown switch, be sure the switch is set to the idle position while the engine is running at idle speed; • Where the generator set is provided with field circuit breakers, set the circuit breaker to the off position while the generator is running at idle speed; • Where the generator set is provided with an automatic/ manual control switch that has an off position, switch it to off while the engine is running at idle speed; • Where the generator set does not have any of the above options, remove the wires from the voltage regulator input power terminals when the engine is running at less than rated speed.

Generator parallel operation

For the generator to operate in parallel with a system in operation, the phase sequence of the generator must be the same as that of the system. Use transformers to reduce the voltage to an acceptable level, and then use a phase rotation meter or incandescent lamp method, described in electrical machinery handbooks, for a phase sequence check. The output voltage at the paralleling point must be the same as each instant, which requires that the two voltages be of the same frequency, same magnitude, same rotation, and in coincidence with each other. Voltmeters indicate whether the voltage magnitude is the same, and frequency meters indicate whether the frequencies are the same. Whether the voltages are in phase and exactly at the same frequency is indicated by a synchroscope or by synchronizing lamps. A synchroscope can be used to indicate the difference in phase angle between the incoming machine and the system. The generator can be paralleled by using incandescent lamps connected. The voltage rating of the series lamps must equal the voltage rating of the transformer-low voltage winding. Each prime mover in the system must have the same speed regulating characteristics, and the governors must be adjusted to give the same speed regulation as determined by applying load that is proportional to the full load rating of the generator. The voltage regulator must include paralleling circuitry. In addition, the voltage, droop settings and the V/Hz regulation characteristics must be the same for all the voltage regulators. This will allow the generators to properly share reactive loads.

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If cross-current compensation is used, paralleling current transformers must give the same secondary current. Current transformer secondary windings provide reactive kVA droop signal to the voltage regulator. Accidental reversal of this electrical wiring will cause the voltage to attempt to rise with load rather than droop. If this occurs during paralleling, stop the unit and reverse the wires at the voltage regulator terminals. If the set is provided with a unit/parallel switch, set the switch to the parallel position on the unit being synchronized. Synchronize the generator by adjusting the speed (frequency) slightly higher than the system. Observe the synchroscope or the lamps. The lamps should fluctuate from bright to dark at the rate of one cycle every 2 to 3 seconds. When the generator is in phase (the lights will be dark), close the circuit breaker. Immediately after closing the breaker, measure the line current kVAR of the generator. The readings must be within the rating of the unit. A high ammeter reading accompanied by a large kW reading indicates faulty governor control. A high ammeter reading accompanied by a large kVAR unbalance indicates problems with the voltage regulator. Adjusting the cross current or voltage droop rheostat should improve the sharing of kVAR. To shut down the generator operating in parallel, gradually reduce the kW load by using the governor to reduce speed. When kW load and line current approach 0, open the generator circuit breaker. Operate the generator unloaded for several minutes to dissipate the heat in the windings. Refer to the prime mover manual for shutdown and cool-down procedures.

Generator maintenance Generator maintenance schedule

Basic generator maintenance varies by size, manufacturer, and usage (load profile). Consult the generator manufacturer for specific recommendations. Extended maintenance intervals may be achieved by developing a maintenance program with stringent inspection procedures as well as personal experience with the rig maintenance personnel. Consult the generator manufacturer for more details on how to develop a program to potentially extend maintenance intervals. Do not clean the generator with pressurized water.

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Figure PW-14: Diagram of typical generator. Daily

• Visually check generator bearing housings for any sign of oil seepage; • Check the operating temperatures of the generator stator windings; • Check the control panel voltmeter for proper stability and voltage output; • Monitor the power factor and generator loading during operation.

Weekly

• Visually inspect the bearing exterior for dirt and clean if necessary; • If equipped, inspect generator air filters for buildup of contaminants and clean or replace as required

Every 2,000 hours or 6 months of operation

• Remove generator outlet box cover. Visually inspect the stator output leads and insulation for cracking or damage. Check all exposed electrical connections for tightness. Check transformers, fuses, capacitors, and lightning arrestors for loose mounting or physical damage. Check all lead wires and electrical connections for proper clearance and spacing;

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• Clean the inside of the outlet box, air screens, bearing housings, and air baffles with compressed air and electrical solvent if needed; • With generators that have ball or roller bearings, check machine vibrations and bearing condition with a spectrum analyzer or shock pulse; • Grease the regreaseable-type bearings.

Every 8,000 hours or one year of operation

• Check insulation resistance to ground on all generator windings, including the main rotating assembly, the main stator assembly, the exciter field and armature assemblies, and the optional permanent magnet generator assembly; • Check the space heaters for proper operation; • Check the rotating rectifier connection tightness.

Every 20,000 hours or 3 years of operation

• With generators that have sleeve oil bearings, perform a sleeve bearing inspection to include the removal of the upper bearing housing and bearing liner to inspect the liner, shaft journal, and seal surfaces for wear or scoring; • Remove the end brackets, and visually inspect the generator end windings for oil or dirt contamination.

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Excessive contamination may necessitate surface cleaning with compressed air and electrical solvent; • Inspect the fan and fan hub for damage.

Every 30,000 hours or 5 years of operation

• Disassemble the generator (this includes rotor removal); • Clean the generator windings using either (depending upon the severity of contamination): ŠŠ Compressed air and electrical solvent or; ŠŠ Degreaser and high pressure hot water wash; • Dry the windings to acceptable resistance levels; • Inspect the rotor shaft bearing journals for wear or scoring; • With generators that have ball or roller bearings, replace the bearings.

Generator troubleshooting

Listed below are common generator troubleshooting issues and fixes: • No Voltage: ŠŠ Open voltage regulator, circuit breaker or fuses: Check. Reset the circuit breaker or replace fuses if open; ŠŠ Overvoltage, under voltage, or overload devices tripped (when protective devices are incorporated into the circuit): Check for the cause of the abnormal condition. Correct any deficiencies. Reset devices. Check the generator nameplate for nominal operating values; ŠŠ Open circuit in exciter field: Check continuity of shunt field and leads to voltage control. (Use ohmmeter or whetstone bridge) If open in field coils, remove exciter field assembly and return assembly to factory for repair; ŠŠ Loss of residual magnetism in exciter field poles: Restore residual magnetism or flash field. When the voltage regulator is a model that requires flashing, install an automatic field flashing system; ŠŠ Open circuit in stator windings: Check for continuity in the windings. Return the generator to the factory for repair if open; ŠŠ Malfunction of automatic voltage regulator: See the manufacturer’s troubleshooting guide for the voltage regulator. Correct deficiencies; ŠŠ Short-circuited generator output leads: Clear lead to restore voltage buildup; ŠŠ Open in rotating rectifiers: Check rotating rectifiers, and replace if open; ŠŠ Open in generator field: Check for continuity and return rotor to factory for repair if field coils are open; ŠŠ Shorted or grounded surge protector: Check for shorts or grounds. Replace;

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ŠŠ Shorted or grounded rotating rectifier: Check for shorts grounds. Replace or repair; ŠŠ Shorted or grounded exciter armature: Check for shorts or grounds. Replace or repair; • Low voltage: ŠŠ Shorted leads between the exciter armature and generator field: Test and repair; ŠŠ Incorrect stator connections: Check the connections, and reconnect; ŠŠ Improper adjustment of voltage adjust rheostat: Adjust rheostat; ŠŠ Excessive load: Reduce load. With three-wire, single-phase and four-wire, three-phase generators, the load on each leg must be as evenly balanced as possible and must not exceed the rated current on any leg; ŠŠ Line loss: Increase the size of the line wire; ŠŠ High resistance connections (hot): Make better connections; ŠŠ Shorted main or exciter field: Test the field coils for possible short by checking resistance with an ohmmeter or resistance bridge. Return the rotor assembly to the factory for repair if field coils are shorted; ŠŠ Low power factor: Reduce inductive (motor) load. Some AC motors draw approximately the same current regardless of load. Do not use motors of larger horsepower rating than is necessary to carry the mechanical load; ŠŠ Weak field due to operating in a warm temperature: Improve the ventilation of the generator. Field current can be increased providing the generator temperature rating stamped on the nameplate is not exceeded; ŠŠ Defective rectifiers in rectifier assembly (stationary): Check rectifier assembly. Replace defective fuses or rectifiers; ŠŠ Excessive load: Reduce load to rated value; ŠŠ Defective bearing: Replace the bearing; ŠŠ Improper speed of engine driven generator set due to defective governor, ignition system or carburetor: Check and correct deficiencies; ŠŠ Voltage regulator not operating properly: Check the regulator. Adjust, repair or replace; • Fluctuating voltage: ŠŠ Prime mover speed fluctuating: Check frequency and voltage of incoming power when the generator set is motor driven. Check engine governor on engine-driven generator sets; ŠŠ Loose internal or load connections: Tighten all connections; ŠŠ Generator overloaded: Reduce load to rated value; ŠŠ DC excitation voltage fluctuating: Trace DC excitation circuit. Correct any defects;

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POWER GENERATION AND DISTRIBUTION ŠŠ Overspeed: Correct speed of prime mover; ŠŠ Voltage regulator not operating properly: Check the regulator. Adjust, repair or replace; • High voltage: ŠŠ Improper adjustment of voltage adjust rheostat or voltage regulator: Adjust rheostat and/or voltage regulator; ŠŠ Voltage regulator not operating properly: Check the regulator. Adjust, repair or replace; • Overheating: ŠŠ Clogged ventilating screens and air passages: Clean all screens and air passages; ŠŠ Dry or defective bearings: Replace defective bearings; ŠŠ Coupling misaligned: Align the generator set; ŠŠ Generator field coils shorted or grounded: Test field coils for shorts. Replace shorted rotor or return it to the factory for repair; ŠŠ Unbalanced load or overload, low PF: Adjust load to nameplate rating; • Vibrations: ŠŠ Defective or dry bearings: Replace defective bearings; ŠŠ Misalignment of generator and prime mover: Align the generator set; ŠŠ Generator not properly mounted: Check mounting. Correct defective mounting; ŠŠ Transfer of vibration from another source: Isolate the generator set from the source of vibration by installing vibration dampeners between generator set base and foundation.

Generator safety

See the Engine Safety section for common safety practices.

Generator isolating for maintenance

When you service an electric power generation set or when you repair an electric power generation set, follow the procedure below: 1. Stop the engine; 2. Utilize lockout/tagout on the engine prime mover starting circuit. Disconnect the engine starting circuit; 3. Disconnect the generator from the distribution system; 4. Utilize lockout/tagout on the circuit breaker. Manually throw the breaker. Verify that all points of possible reverse power flow have been locked out; 5. For the following circuitry, remove the transformer’s fuses: a. Power; b. Sensing; c. Control; 6. Utilize lockout/tagout on the generator excitation controls; 7. Remove the cover of the generator’s terminal box;

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8. Use an audio/visual proximity tester in order to verify that the generator is de-energized. This tester must be insulated for the proper voltage rating. Follow all guidelines in order to verify that the tester is operational; 9. Determine that the generator is in a de-energized condition. Add ground straps to the conductors or terminals. During the entire work period, these ground straps must remain connected to the conductors and to the terminals.

Generator storage Putting generator into storage

When storing an enclosed generator set for short or long term, the enclosed generator set must be supported under each sub-base section to prevent damage. A minimum of five support blocks that are spaced evenly along the length of the enclosure are to be used to support the enclosure. When a generator is in storage, moisture may condense in the winding insulation system. In order to minimize condensation, always put the generator in a dry storage area. Grease used in ball and roller bearing generators is subject to time deterioration. Before placing the unit into service after long-term storage, check the bearings for corrosion, and replace the grease. It is necessary to perform an insulation resistance and Polarization Index (PI) test on all generators at the beginning of storage. Record the results of the insulation test. A PI test should be performed to provide a baseline for future reference. Note: Ensure that the baseline is established with the unit dry. When in a controlled environment, the generator should be covered with a plastic cover or a similar type of protective cloth. The protective cover should extend to the ground, but the cover should remain loose around the generator in order to allow proper ventilation to the generator. Maintain the temperature of the insulated parts and the air that surrounds the parts at a temperature of at least 5°C (9°F) above ambient temperature to prevent condensation. The following methods are the normal methods for providing the required heat: • Space heaters; • Warm air blowers: Do not exceed 207 kPa (30 psi); • Light bulbs: Install a light bulb (60-watt minimum) inside the generator in the proximity of the stator core at the lowest possible location.

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POWER GENERATION AND DISTRIBUTION Use the Polarization Index (PI) test procedure to determine the moisture content of the insulation system. PI is greater than or equal to two for a “dry” insulation system. PI is a ratio of the Insulation Resistance Measured for 10 minutes to the insulation resistance value measured after 1 minute. Polarization Ratio equals Insulation Resistance after 10 minutes divided by Insulation Resistance after 1 minute.

Note: The light bulb method only works if there is no air movement around the generator

Insulation resistance readings with a 50 percent reduction or more from the previous reading, or a PI reading of less than 2 may indicate that the winding has absorbed too much moisture. The generator needs to be dried and retested. If the retest still comes out low the generator will have to be sent to a rewind shop for service. If cleaning or drying is necessary, refer to the manufacturer’s maintenance manual.

Ensure that the generator rotor shaft is rotated 10 revolutions every 60 days throughout the storage period.

Transmissions

Figure PW-15: Transmission for drilling engine. Courtesy Allison Transmission.

When in an uncontrolled environment where exposed to temperature and humidity fluctuations, prepare generator as follows: • Install desiccant bags in the exciter cover and inside the end bells; • Vacuum seal the unit in a covering of plastic or other material designed for that purpose. Ensure that the generator rotor shaft is rotated 10 revolutions every 60 days throughout the storage period.

Removing generator from storage

Operate space heaters for at least 24 hours prior to removing covers. Remove all protective covers. If the unit does not have a space heater, use an alternate means in order to raise the temperature to at least 5°C or 9°F higher than the ambient temperature. The following methods are the normal methods for providing the required heat: • Space heaters; • Warm air blowers: Do not exceed 207 kPa (30 psi); • Light bulbs: Install a light bulb (60 Watt minimum) inside the generator in the proximity of the stator core at the lowest possible location.

Transmissions are used to increase and decrease speed through gear ratios when directly coupled to mechanical devices.

Transmission maintenance Basic maintenance interval schedule

General transmission maintenance varies by engine size, manufacturer, and usage (load profile). Consult the engine manufacturer for specific recommendations. Extended maintenance intervals may be achieved by developing a maintenance program with stringent oil sampling procedures as well as personal experience with the rig maintenance personnel. Consult the transmission manufacturer for more details on how to develop a program to potentially extend maintenance intervals. When required: Replace or clean breather as necessary;

Every 10 service hours • Check oil level;

Initial 100 service hours • Replace oil filter;

Initial 500 service hours • Replace oil filter;

Note: The light bulb method only works if there is no air movement around the generator Before start-up of a generator, visually inspect the generator for any foreign material. Use an insulation tester to check insulation resistance for moisture and/or foreign material. Refer to the generator operation and maintenance manual for the procedure.

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Every 500 service hours or 6 months • • • •

Clean breather; Clean magnetic screen; Replace oil filter; Obtain oil sample: change oil as necessary.

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F

Series Field

Armature

A

PW–27

A

F

Armature

Shunt Field

Figure PW-16: DC Shunt Motor Schematic.

Transmission troubleshooting

Listed below are common transmission troubleshooting issues and fixes. • Excessive clutch noise: • Throwout bearing: replace/lubricate; • Bad clutch shaft pilot bearing: replace; • Noise from the clutch linkage: lubricate; • Clutch slips: • Worn pressure plate or clutch plate; • Oil-soaked clutch plate; • Insufficient pedal free-play; • Bad waste or slave cylinder; • Low fluid; • Clutch drags or fails to release: • Too light transmission lubricant or low lubricant level; • Improperly adjusted clutch linkage; • Bad cylinder; • Low fluid; • Air in line; • Transmission shifts hard: • Improper lubricant viscosity or lubricant level; • Clutch linkage needs adjustment/ lubrication; • Transmission leaks lubricant: • Lubricant level too high; • Cracks in the transmission case; • Loose or missing bolts; • Drain or fill plug loose or missing; • Vent hole plugged; • Transmission is noisy in gear: • Insufficient lubricant; • Worn gears (excessive end-play); • Worn bearings; • Damaged synchronizers; • Chipped gear teeth; • Transmission is noisy in neutral: • Insufficient/ incorrect lubricant; • Worn reverse idler gear; • Worn bearings or gear teeth.

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Figure PW-17: DC series motor schematic.

U1-1

Transmission safety

Figure Shunt Motor Schematic See the EngineU1-1: Safety DC section for common safety practices.

Transmission storage

See the Engine Storage section for basic storage practices.

Power distribution Introduction

There are three types of electric drilling rig systems—DC/ DC, AC/SCR, and AC/AC (VFD). Each system consists of engine/generator sets, control systems and electric motors. AC/DC motors are used on mud pumps, drawworks, top drives and rotary tables; and AC motors are used to power auxiliary functions on all types of systems. The electric drilling rig is similar to the mechanical rig. Power is produced by engines on both mechanical and electric drilling rigs. This engine power is transmitted to the rig equipment through electric cables to motors on the electric rig. The mechanical rig uses chains, compounds, torque converters and v­belts to transmit the engine power to the rig equipment.

DC/DC and SCR systems

DC/DC systems typically include multiple engine/DC generator sets and control systems connected by cable to DC motors. Each generator is assigned to a specific motor. The DC/DC systems are generally arranged so that each motor can receive power from two or more engine/generator sets to provide back­up in case any engine/generator set is not functioning (Figures PW-16 and PW-17). SCR systems typically include multiple engine/AC generator sets, AC to DC conversion systems, and controls connected to DC motors. All the engine/generator sets are connected to a common AC bus. The SCR system converts the AC cur-

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rent to DC current and transmits the DC current to the DC motors.

DC drilling motors

The motors used with SCR or DC/DC systems are either shunt or series­type and are usually rated 800-­1,250 hp for drilling applications. The DC motor is used because of its ease of control and high torque at low RPM.

dent upon the power requirements of the individual drilling rig. The deeper the drilling depth rating of the rig, the more power will be required to operate the rig. This section will attempt to provide a general understanding of power generation by dividing the information into three subtopics. • Engines • Generators • AC Switchgear

The shunt motor differs from the series motor both in its connection configuration and its operational characteristics. The shunt motor requires a separate DC power source to provide the field current (Figures PW-16), while the series motor allows the armature current to also flow through the field (Figures PW-17).

Engines

The shunt motor is the simplest to control since its speed is directly proportional to the DC volts supplied across its armature and its torque output is directly proportional to amperes. Load does not appreciably affect the speed of the motor.

The generator converts rotating motion or torque of the engine to electrical power.

Speed feedback and regulation

The speed of an uncontrolled series motor is greatly affected by its load. With light loads, a series motor could over speed and damage itself and the equipment it is driving. There are many methods in use today to protect the motor and equipment from this over­speed condition. These include: • Electronic circuitry to make the series motor characteristic simulate that of a shunt motor. (Load has the appreciable effect on speed.); • Speed regulation is provided via a motor mounted tachometer; • A motor mounted over­speed device shuts off the motor if it exceeds a set speed; • The motor is shut down any time the load (current) decreases below a given volume signifying a broken chain, belt, sprocket, etc. Series motors have excellent speed­/torque characteristics for accelerating loads from a standing start to full speed which is perfect for efficient drawworks operation. Series motors also have excellent load sharing characteristics for multiple motor loads.

SCR (AC/DC) power systems AC electrical power generation

Although it is sometimes feasible to use utility power, electrical power for an SCR type drilling rig is typically provided by alternating current (AC) generators driven by engines. The size and quantity of engine/generator sets is depen-

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The engine converts a fuel to mechanical torque that turns the AC generator. Although diesel engines are the most common source of power, other types such as gasoline, natural gas or gas turbines are also used to a lesser degree.

Generators

Synchronous type AC generators or alternators are the most common units used. They provide an output of 600 volt,

3­-phase power

A synchronous type generator is composed of three main elements(see Figure PW-14). • Rotor • Stator • Exciter The rotor is mounted on a shaft driven by the engine. Electromagnets called “field poles” are mounted upon the rotor. Each pole is wound with a wire so connected that when direct current is supplied to the coils, from the exciter, alternate North and South magnetic poles are produced. The rotor revolves within the stator, or armature, which has insulated electrical conductors wound around a laminated steel core. As the rotor revolves at rated speed its magnetic fields generate alternating current of the proper voltage and frequency in the conductors. This generated voltage is transmitted via power cables to the AC switchgear. The exciter is controlled by a voltage regulator which is typically installed in the AC switchgear. Two types of exciters can be obtained. The first is the “brush” type exciter which uses brushes and a commutator. The “brush­less” type (rotating rectifier) exciter, which eliminates the brushes and commutator, is becoming more popular as it requires less maintenance.

AC switchgear

The three main functions of the AC switchboard are: control, protection and metering.

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Control

• Voltage regulator: The output of the generator is controlled by the voltage regulator. The voltage regulator monitors the generated voltage and varies its output to the generator exciter to control the amplitude of the generator voltage.A second function of the voltage regulator occurs while two or more generators are connected in electrical parallel. The voltage regulators will force the paralleled generator to share the kVAR load equally. • Governor control: The speed or torque output of the engine is controlled by an electronic governor that controls the engine fuel. On a mechanical engine, the actuator increases or decreases the engine fuel rack setting to provide constant speed. On electronic engines the electronic governor controls the engine control module controls to provide constant speed. With multiple engine generators in parallel, the power output (in Kilowatts [kW]) of each generator is controlled to provide equal load sharing. • Synchronization circuitry: Generators to be operated in electrical parallel must be operating at the same frequency, voltage and phase rotation. Most AC switchboards will have circuitry to monitor these three conditions. If any or all of the above conditions are not met, the circuit breaker of the generator to be paralleled will not close.

Protection

• Generator circuit breaker: The Generator circuit breaker protects the generator and cables from short circuits and undesirable overload condition. It also acts as a device to connect or disconnect its generator from the main AC bus. The generator circuit breaker typically is provided with an undervoltage release feature that prevents the circuit breaker from being closed when the generator is not energized. Usually a shunt trip mechanism that allows the circuit breaker to be opened remotely by other protective devices is also furnished. • Reverse power protection device: The loss or reduction of engine torque, during parallel operation of two or more engines will result in a condition of the generator called “motoring.” This condition occurs when current flows into a generator from other generators. It can cause engine or generator damage. The reverse power relay monitors the generator output and will open the associated generator circuit breaker during a sustained reverse power condition. • Under frequency protection device: During periods of

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under speed operation of an engine, the voltage regulator out­put is reduced by the under frequency protection device. This protects the voltage regulator, the exciter and generator from damage. • Over voltage protection device­The over voltage protective device will remove power from the voltage regulator during conditions of over voltage (typically 125 ­150%). • Power limiting: The power limiting circuit compares the generator power available with the power being used or demanded. If the power demand exceeds the power that is available, some of the load will be reduced to protect the engine/generators from overload and a possible complete “blackout” of the rig power system. • Ground fault detection: Monitors system and detects AC and or DC grounds in cables and equipment.

Metering

The following metering is typically provided in the AC switchgear to monitor the output of the engine generator sets: • AC ammeter: Measures the current output from the generator and is used to check for load balance. • AC voltmeter: Monitors the generator output potential. • AC wattmeter: Monitors the kilowatt or real power output of the generator and is used to assure equal division of the kilowatt load between paralleled generators. • kVAR meter: Monitors the reactive power output of the generator and may be used to balance reactive power division between generators. • Power factor meter: Monitors the generator power factor and sometimes used in lieu of a KVAR meter to balance reactive power between generators. • Frequency meter: Indicates the generator or main bus frequency in Hertz (or cycles) per second. • Synchroscope: Provides a visual indication of the relationship of the frequency or speed of the generator to be paralleled to that of the energized main bus.

AC/DC conversion

This section will describe the workings of the SCR system itself in converting AC power to DC power. Following is the simple one line flow diagram of a SCR converter system.

General

The SCR system changes the constant voltage AC power to an adjustable voltage DC power to enable speed control of the DC drilling motors, which in turn power the drilling functions and control rotary table speed, mud pump pressure and flow, etc.

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Figure PW-18: SCR single-line diagram.

The following is a list of components found in all SCR control systems: • Circuit breakers; • Power fuses; • SCR ­heat sink assembly into a 3­phase full control bridge rectifier; • Electronic controls; • Driller’s console; • DC assignment contactors (Figures PW-18 and PW-19).

Protection

Circuit Breakers • The circuit breaker connects and disconnects the 3­phase AC power bus to the SCR rectifier section with the added function of limiting fault current. Fuses • Aiding in this protective function are current limiting power fuses. All SCR systems have fuses on the AC or line side of the bridge. All power fuses have the task of limiting damage to the SCR and other components in a fault condition.

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SCR heat sink assemblies • Since SCRs control a great deal of current, a considerable amount of heat is generated. This heat is removed by mounting the SCR in a heat sink assembly consisting of an aluminum extrusion. The heat is passed from the SCR to the heat sink and then to the air by forcing a large volume of air over the heat sinks (by a blower assembly). When the cabinet doors of most SCR cubicles are opened, the heat sinks are usually the most obvious components in view.

Electronic controls

The DC control electronics have five basic functions: • Receive a throttle signal; • Convert this signal to a synchronized gate firing signal to turn the SCRs on at the proper time; • Measure the result (DC power output) and make any error corrections; • Measure the DC current being produced and compare it to the current limit setting and inhibit the current from exceeding that setting; • Accept power limit signal from AC generator control section.

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PW–31

Figure PW-19: SCR bridge 3-line diagram.

Throttle Signal

Braking

consists of the following: • 600 volt distribution circuit breaker; • 600 to 480 volt distribution transformer; • 600 (or 480) to 120/208 volt lighting transformer; • Motor control centers; • Lighting panel; • Auxiliary feed for other electrical needs (e.g. camp power).

Braking (Dynamic)

600-480-volt distribution transformer

The throttle signal comes from the driller’s console and rep­ resents a desired speed for a drilling load (mud pump strokes per minute or rotary table rpm). By determining when a SCR turns on in an electrical cycle the output DC voltage can be varied from 0 to 750 volts DC.

Braking is necessary to stop the freewheeling drawworks motor. The braking action is induced by causing the motor to act as a generator. To rapidly stop the armature rotation, a load resistor is connected across the armature which slows the motor to “cat head speed” (a low speed). At that moment, the motor is disconnected from the resistor and reconnected to the SCR.

Braking (Regenerative)

Instead of connecting the freewheeling drawworks motor to a resistor, it is connected through a reversing contact and the SCR bridge to the main 600 volt bus. The armature’s rotational energy is dissipated through other electrical loads on the rig instead of heat in the resistor.

AC Distribution

Electric rig power is produced typically at 3 phase, 50 or 60 hertz, 600 volts AC. Most AC motors of the size required on a drilling rig are built to use 3­phase, 60 hertz, 480 volt AC. A transformer is used to convert 600 volts to 480 volts AC. Other voltages and frequencies may be used in various geographical regions.

Motor control center (MCC)

This 480 volts AC is used to power a motor control center which is a self-contained collection of AC motor starters and breakers all connected internally to a common AC bus. The output of each starter is wired to a given AC motor on the rig. The starters all contain a disconnecting device (electrically operated switch) and an overload relay to protect the motor against a continuous overload.

There are many AC motors and loads on a rig which require a means of distributing the power in a safe, efficient manner. Every rig has some sort of AC distribution which normally

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Lighting and auxiliary panel

Most lighting circuits run on 120 volts AC or 208 volts AC and, therefore, most rigs have another transformer which is connected to a lighting circuit breaker panel (just as a house has) which is connected to the lights on a rig.

VFD power systems

Variable Frequency Drive systems (VFDs) have been utilized on drilling rigs since 1996, where they were first installed on the Troll A platform’s top drive. Since then, the number of drilling rigs utilizing VFD systems has steadily increased on both land and offshore installations. The use of VFDs and AC induction motors is now widespread, with VFD technology outpacing SCR systems, and are used to power the

3 PHASE INPUT POWER – 600V 60HZ

drawworks, mud pumps, top drives, rotary tables, as well as many electric cranes, piperackers, and other equipment typically found on a modern drilling rig. One of the main reasons that VFDs have gained popularity in drilling applications is due to the ruggedness and low maintenance requirements for the AC induction motor, as well as its suitability for use in hazardous locations. There a number of VFD types in use today, however the predominant VFD used in drilling applications is known as a voltage source inverter (VSI), whose main characteristic is that its DC link has a large amount of capacitance connected between the positive and negative DC buses. With only a few rare exceptions, low voltage VSIs utilize 6 pulse, single level IGBT inverter bridges. This is the type of VFD

PULSE WIDTH MODULATED AC POWER 0V-575V; 0HZ-300HZ

CONSTANT DC VOLTAGE 800V935V 2.1

Inv LL( t ) g LL( t )

− 2.1

3 PHASE RECTIFIER

0

0.04

t

3 PHASE INVERTER

Figure PW-20: 19: A VFD first converts AC voltage and current to DC, then converst DC back to AC using a switching scheem known as pulse wideth modulation (PWM). PWM simulates 3-phase AC voltage and current. This diagram shows the power-conversion process. Courtesy National Oilwell Varco.

Figure PW-21: The basic components of a modern VFD.

Reactors

Rectifier

DC Link

Inverter

M

Input: Fixed voltage, fixed frequency

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Output: Variable voltage, variable frequency

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PW–33

commonly used on drilling rigs around the world, and is the subject of this section.

Theory of operation

A VFD first converts AC voltage and current to DC voltage and current, then converts DC power back to AC power using a switching scheme known as Pulse Width Modulation (PWM), which simulates 3 phase AC voltage and current. There are many methods employed by various VFD manufacturers to accomplish the conversions, but they all accomplish the fundamental transformation of converting AC power to DC power, and DC back to a 3 phase power of varying frequency and voltage. This transformation into variable voltage and variable frequency allow, for the precise speed and torque control of AC induction motors on drilling tools. A diagram showing the power conversion process is shown in Figure PW-20. A standard VFD will not typically reproduce a voltage equivalent to the input voltage. Some voltage is dropped across the VFD components, input reactors, output cables, and some voltage is limited by the VFD in the conversion process itself. This is important to consider when selection an induction motor or evaluating potential performance of a VFD system, as motor’s rated voltage plays an important role with induction motor performance above the base speed.

Basic design

The basic components of a modern VFD are shown in Figure PW-21. There are 6 main components in a VFD system: • Six-pulse rectifier bridge or converter; • DC Link; • Six-pulse Inverter; • Chopper or DC/DC converter; • AC induction motor; • Braking resistor.

Rectifiers

The rectifier bridge construction of a VFD is very similar, and in some cases identical to an SCR bridge. However, the devices used to convert AC to DC are diodes rather than SCRs. Diodes do not require control pulses to turn on and are often referred to as “line-commutated devices.” This means that as long as the bridge is connected to its AC supply, it will produce DC power without any external control, making a diode bridge a passive device. The diode bridge provides a constant DC source of power to the inverter. Depending on the input voltage, the rectifier will produce between 810VDC for a system with a 600V supply, and 932VDC for systems with 690V supplies. Most VFD drilling rigs operate within this range, however there are some offshore drilling systems which utilize up to 720V

IADC Drilling Manual

Figure PW-22: Schematic symbols for diode rectifier.

for the bridge supply. Most rectifiers include line reactors, or chokes, which are iron core inductors. The line reactors have multiple purposes, including the reduction of line harmonics, smoothing the current ripple on the DC link, and reducing the fault current seen by the bridge, DC link, and inverter. There are various symbols used to identify the diode bridge, which is also referred to as a converter in some manufacturer’s technical literature. A few common symbols used for the rectifier bridges are shown in Figure PW-22. A typical 6 pulse diode bridge schematic is shown in Figure PW-23. A diode bridge may or may not be protected with fuses, while nearly all have some temperature monitoring and protection. In Figure PW-23, the bridge is protected with both temperature switches and resistance temperature detectors (RTDs). RTDs allow continuous temperature monitoring of the bridge and those temperatures may be displayed by the supervisory control system. Temperature switches are normally used to open the circuit breaker feeding the diode bridge if the heatsink temperature reaches a preset critical level. Some rectifier bridges also incorporate snubbers, which are series connected RC circuits in parallel with the diodes. They are designed to protect the diodes from transient voltages. They have the added advantage in AC drives of suppressing electromagnetic noise produced by the inverter switching, which when conducted into the main voltage supply, may disrupt rig telecommunications, fire detection, or other sensitive instrumentation.

DC link

The DC link of a typical drilling VFD contains a large amount of DC bus capacitance, comprised of multiple large electrolytic capacitors connected series- parallel. A few smaller VFDs may utilize an additional DC link inductor, although these are not commonly found anymore. The DC link capacitors are most commonly built into the inverters themselves, although several VFD manufacturers have separate capacitor banks which occupy their own cabinet. Whether or not the DC link of the VFD has integrated or separate capacitor banks, they all contain resistors which balance the voltage across the capacitors while the drive is operating, and serve to discharge the bank when the drive is

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shut down. A basic diagram of a common VFD’s DC link is shown in Figure PW-24.

Inverter

The electrolytic capacitors found in most VFDs have an average lifetime of 7 to 8 years, and must be replaced.

DC/DC power systems

DC/DC electric drilling rigs have been built in various designs for some 40 years. They range from a totally electric system to several hybrid configurations. The hybrid configurations generally have a compound which is used to drive the mud pumps, one or more DC generators, and sometimes the drawworks. The drawworks and/or rotary table are electrically driven by a DC drilling motor. The main attractiveness of such rig power arrangements is the rotary torque control. Secondary advantages include reduced maintenance, fewer chain alignment problems, speed control and improved fuel efficiency.

Controls

There are four main components to a DC/DC rig: • DC generators • Motors • Control cabinet • Driller’s console On present day DC/DC rigs, the motors and generators are usually interchangeable (the hubs may have to be changed). This greatly reduces the required spares. The driller’s console is a remote command post for the control cabinet.

The heart of a DC/DC control system is the voltage regulator. It is an electronic module that controls the output of the generator following commands from the driller’s console. There are no other active components in the system. All other components (i.e., blower starters, transformers, meter, etc.) are passive. The drilling motor speed and torque is controlled by regulating the generator output. This means each motor that is operating must have one generator assigned to it. Usually each generator can be assigned to either of two motors. These assignments as well as the speed and torque adjustments are made from the driller’s console. Because of the one-on-one assignments described in the foregoing, the generators are not “pooled” into a common bus. This means the engines do not have to be operated at the same speed. The speed of each drive engine can be varied in accordance with the power required. There is no need to parallel or synchronize generators. There are no engine/ generator load sharing adjustments required. There are several choices in engine speed controls generally available with DC/DC systems: • Constant full speed; • Constant full speed with automatic idle when not loaded; • Constant or variable speed as selected by switches on the driller’s console. In the past, fuel savings were made possible with an air operated governor system, but are now generally done with

Figure PW-23: Typical 6-pulse diode bridge scematic. A diode bridge might or might not be protected with fuese, while nearly all have some temperatures monitoring and protection.

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Optional DC link filter inducer

PW–35

+ DC bus

Electrolytic capacitors 20,000 30,000 μF

Balancing resistors 2kΩ typical

- DC bus Figure PW-24: Basic diagram of a typical VFD’s DC link.

electronic governors. This engine speed control is an option not supplied on all systems and, when supplied, generally can be simply bypassed for operation at a constant engine speed. Variable speed is the recommended mode of operation, when available, for best fuel consumption and improved engine life.

Braking

To brake the drawworks motors down from hoisting speeds (foot throttle) to the cat head speed (hand throttle), DC/ DC systems brake via regeneration - not dynamic braking. No resistor grids are required. The motor, which is rotating due to its own inertia, acts as a generator and drives current back to the generator. The generator acts like a motor and tries to increase the engine speed. The engine acts like an air compressor and dissipates the energy as heat and friction.

System protection

• Generator over-current trip: Open power contactor when generator current exceeds the current limit due to a failure of the control circuit; • Ground Relay: Detects the presence of a leakage or short circuit to ground and stops all operations. Operation can continue with ground relay bypassed until the problem is corrected. (Bypass is normally simply done with a selector switch within the control cabinet.); • Circuit Breakers: Used at many points in a control system to protect wiring and devices in case of short circuits. The AC circuits feeding the field supply panels and blower starters, for example, are protected with circuit breakers; • Enclosure: Because of the low heat generation of the DC/DC control components, an air conditioned control house is not usually required. The standard cabinet is often mounted outside with no additional protection.

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Driller’s console

The driller’s console is the command post for the DC/DC system. The following are some of the controls and indicators usually included: • Hand throttle for each function (mud pump, rotary table, cat head, etc.); • • • •

Foot throttle (drawworks speed control when tripping); Assignment switch for each generator; Reversing switches (rotary table and/or drawworks); Ammeters and voltmeters to indicate motor speed and torque; • Lights to indicate: • The motor blowers are operating; • The ground relay has shut down the system due to a ground fault.

Maintenance

These maintenance procedures are guidelines to be used by the drilling contractor in his maintenance programs. In addition, refer to the manufacturers’ maintenance manuals. In general, electrical equipment requires a minimum amount of attention to keep it functioning properly. A carefully planned maintenance program by the drilling contractor will prevent many failures that occur due to neglect and abuse. Each rig manager should maintain maintenance records on all equipment and document failures, replacements, repairs, or inspections. Name plate information and other special data recorded will also aid in ordering and replacing parts.

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Care and caution should be used when inspecting, repairing, or replacing electrical equipment. Only authorized persons who have been trained in the operation and repair of the equipment should be allowed to perform these operations since shock, death, or equipment damage can occur. It is suggested that warnings be placed on equipment to alert personnel of the dangers that exist with electrical equipment. Typical of these signs are the following:

Warning

The electrical equipment contains hazardous voltages. When working on high voltage equipment, ensure that all power has been removed. Use appropriate lock out tag out procedures.

Caution

Do not use sandpaper, emery paper, or other abrasive materials to clean plugs, contactor tips, relay tips, or other electrical connections. Use a dry cloth, proper solvents, or pencil eraser to perform these operations.

SCR controls

CAUTION: These procedures should only be performed by trained personnel. Do not touch live electrical parts.

Daily maintenance

1. Inspect exterior surfaces of panels for dirt, grease, oil or physical damage. 2. Visually inspect interior for dust, dirt, oil, grease, metal, water, or corrosion. 3. Inspect all air filters for cleanliness; clean or replace as necessary. 4. With power off, check for loose hardware in the equipment, during rig moves or down time. 5. During rig operation, inspect all meters, instruments and lamps for faulty operation or damage; replace as necessary. 6. Inspect plugs and receptacles for cleanliness, damage or loose connections. 7. Inspect printed circuit boards, electronic modules and other electrical components for damage or overheating. 8. Check operation of all controls including assignments, reversing, dynamic braking, operation of mud pumps and other functions.

Monthly maintenance

CAUTION: Be sure all power is off before performing any procedure. • Clean each SCR bay monthly to remove dust and dirt by using the suction side of a vacuum cleaner. Never blow the equipment with forced air to clean it. • Properly tighten all bolts and hardware in the equipment according to the manufacturer’s

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recommendations. Inspect for and replace any missing hardware. •. Check all contactor tips for pitting or wear; replace as necessary. • Inspect and clean air conditioning systems on the SCR house.

Repair

All repairs should be performed by competent, trained electricians or technicians who are familiar with the SCR equipment; Those items that can be easily repaired or replaced are included in the following list and are considered modules or significant components. Repair of printed circuit cards, or other electronic components, should not be attempted except in emergencies. • Replace fuses; • Replace SCR bridges, cells, or assemblies; • Replace printed circuit cards; • Replace control modules, such as AC module, DC module, voltage regulator governor, reverse power relay or similar assemblies; • Repair wiring terminations; • Replace damaged DC contactor tips; • Replace defective relays; • Repair mechanical damage; • Replace any overheated component and determine cause of problem.

Variable frequency drive (VFD)

CAUTION: These procedures should only be performed by trained maintenance personnel. Do not touch live electrical parts.

Daily maintenance

• Inspect exterior surfaces of panels for dirt, grease, oil or physical damage. • Visually inspect interior for dust, dirt, oil, grease, metal, water, or corrosion. • Inspect all air filters for cleanliness; clean or replace as necessary. • With power off, check for loose hardware in the equipment, during rig moves or down time. • During rig operation, inspect all meters, instruments and lamps for faulty operation or damage; replace as necessary. • Inspect plugs and receptacles for cleanliness, damage or loose connections. • Inspect printed circuit boards, electronic modules and other electrical components for damage or overheating. • Check operation of all controls including assignments, reversing, dynamic braking, operation of mud pumps and other functions.

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POWER GENERATION AND DISTRIBUTION • Verify operation of cooling blowers on dynamic braking resistors.

Monthly maintenance

CAUTION: Be sure all power is off before performing any procedure. • Clean each VFD bay monthly to remove dust and dirt by using the suction side of a vacuum cleaner. Never blow the equipment with forced air to clean it. • Properly tighten all bolts and hardware in the equipment according to the manufacturer’s recommendations. Inspect for and replace any missing hardware. • Check all contactor tips (if equipped) for pitting or wear; replace as necessary. • Inspect and clean air conditioning systems on the VFD house. • Inspect dynamic braking resistors for excessive heating.

Repair

All repairs should be performed by competent, trained electricians or technicians who are familiar with the VFD equipment; Those items that can be easily repaired or replaced are included in the following list and are considered modules or significant components. Repair of printed circuit cards, or other electronic components, should not be attempted except in emergencies. • • • • • • • • • •

Replace fuses; Replace VFD inverter cells and rectifier assemblies; Replace braking chopper assemblies; Replace printed circuit cards; Replace VFD control modules; Repair wiring terminations; Replace damaged AC contactor tips; Replace defective relays; Repair mechanical damage; Replace any overheated component and determine cause of problem.

AC generator controls

CAUTION: These procedures should only be performed by trained maintenance personnel. Do not touch live electrical parts.

Daily maintenance

• Inspect exterior surfaces of panels for dirt, grease, oil or physical damage. • Visually inspect interior for dust, dirt, oil, grease, metal, water, or corrosion. • Inspect meters for proper operations. Check for proper load balance between paralleled generators. • With power off, check for loose hardware in the

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equipment, preferably during rig moves or downtime. • Check all modules and equipment for overheating or electrical damage through visual inspection. • Verify operation of all controls, including voltage regulators, governor paralleling, synchronizing, load sharing, and circuit breakers. Check for instability of voltage or frequency.

Monthly maintenance

CAUTION: Be sure all power is off before performing any procedure. • Clean each generator control bay monthly with a vacuum to remove dirt, dust, and oil particles. • Properly tighten all bolts and hardware in the equipment according to the manufacturer’s recommendations. Inspect for and replace any missing hardware. • Calibrate all meters from a reference source.

Repair

All repairs should be performed by competent, trained electricians or technicians who are familiar with generator control equipment. Those items that can be easily repaired or replaced are included in the following list and are considered modules or significant components. Repair of printed circuit cards, or other electronic components, should not be attempted except in emergencies. • Replace circuit breaker; • Replace AC module, DC module, voltage regulator, electronic governor, reverse power relay, over voltage / under frequency module or other control modules; • Replace defective meters or instruments; • Replace defective voltage or speed control adjusts; • Repair wiring terminations; • Replace defective lamps; • Repair mechanical damage; • Replace any overheated components and determine cause of problem

Motor control center (MCC) and switchgear

CAUTION: These procedures should only be performed by trained maintenance personnel. Do not touch live electrical parts.

Daily maintenance

• Inspect exterior surfaces of MCC sections and controls. • Inspect interior of each section for overheating and proper operation of components. Inspect for dust and other foreign matter. • Check all circuit breakers and disconnect switches for proper operation.

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POWER GENERATION AND DISTRIBUTION

Monthly maintenance

CAUTION: Be sure all power is off before performing any procedure. • Clean each MCC cubicle and switchgear bay with a vacuum to remove dust and other debris; do not blow the dust loose with a vacuum. • Properly tighten all bolts and hardware in the equipment according to the manufacturer’s recommendations. Inspect for and replace any missing hardware. • Calibrate all meters and instruments from a reference source. • Inspect each overload relay and motor protective device.

Repair

The following items should be repaired or replaced if found defective • Circuit breakers; • Overload relays; • Contactors; • Pushbuttons, lamps, controls, switches; • Wiring terminations, connectors, plugs.

Driller’s console and foot throttle Daily maintenance

CAUTION: Be sure all power is off and the area has been determined to be gas free before opening and touching any consoles, electrical terminals, or components. • Inspect exterior of console for damage to the enclosure or instrument window. • Visually inspect exterior of console for damage to connectors, throttles, meters, switches, pushbuttons, or other components. • Inspect exterior of foot throttle for damage to pedal or connector. • Inspect air pressure equipment to console and throttle to assure positive pressure or flow. • Inspect interior of console for dust, dirt, or foreign material. • Inspect interior of console for overheated components or loose connections. • Check instruments and lamps for operation. • Operate the throttles and other controls for proper operation. • Operate the foot throttle to verify proper operation.

Monthly maintenance

CAUTION: Be sure all power is off before performing these procedures. 1. Clean the console and foot throttle monthly with a vacuum to remove dust, dirt and other debris. 2. Tighten all loose hardware and replace any missing hardware. 3. Inspect all wiring terminators and reconnect as required. 4. Operate all control functions including throttles, switches, assignments, and meters to assure proper operation from the driller’s console. 5. Operate the foot throttle in conjunction with the driller’s console.

Repair

All repairs should be performed by competent electricians or technicians who are familiar with the operation of this equipment; The following items can be repaired or replaced in the driller’s console or foot throttle: • • • • •

Throttle potentiometers or variable transformers; Meters or instruments; Pushbuttons, switches, or other controls; Connectors, wiring terminations, plugs; Mechanical components.

Cable and wiring

CAUTION: These procedures should only be performed by trained maintenance personnel. Do not touch live electrical parts.

Daily maintenance

1. Inspect all cable and wiring for mechanical damage. 2. Inspect all terminations to lugs, connectors, or compression devices. 3. Remove any grease, oil, or chemicals from the wiring insulation. 4. Protect any uncovered cables in high traffic areas. 5. Replace any tie wraps or supports that appear to be defective. 6. Inspect junction boxes for damage and water ingress. 7. Inspect for signs of arcing at points of connection or where cuts or fraying are detected. 8. Inspect ground wire connections for all equipment and skids.

Monthly maintenance

CAUTION: Be sure all power is off before performing these procedures.

IADC Drilling Manual

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POWER GENERATION AND DISTRIBUTION 1. 2. 3. 4.

Tighten all lugs and connections to cables. Replace any cut or damaged cable or wiring. Protect any uncovered cables in high traffic areas. Check all receptacles and plugs.

Repair

All repairs or replacements should be performed by competent electricians with power turned off; Repair or replace the following: • Defective or damaged cables • Defective or damaged plugs, connectors, or lugs; • Overheated connections or cable.

Electric brake

CAUTION: These procedures should only be performed by trained maintenance personnel. Do not touch live electrical parts.

Daily maintenance

1. Inspect cooling water supply to assure that proper volume of water is being supplied to the brake. 2. Inspect the exhaust ports of the brake to assure that free flow of the cooling water is assured with gravity flow. 3. Determine that brake is not overheating during operation. 4. Check coupling between brake and drawworks. 5. Check mounting bolts to brake frame for tightness. 6. Properly grease and lubricate where needed 7. Inspect cable to junction box of brake.

Monthly maintenance

1. Inspect air gap of brake through inspection ports with feeler gauge to assure concentricity and lack of corrosion buildup. Refer to brake manual for proper air gap distances. 2. With power off, check the brake coil resistance to assure continuity of each winding. Also, check for any coil grounds by measuring each coil to ground. All external connections to the brake control should be removed at the junction box for these checks. 3. With power applied to the brake control, turn the control to full on and determine that the full DC voltage is received by the brake. Operate the throttle over the full range and determine that the controller output voltage is smooth and continuous over the full range of operation. 4. Any controller in a cast aluminum box should be opened and the cooling/insulating oil replaced with clean oil. Remove any foreign liquid or matter in the box before replacing the oil. 5. Other controllers in NEMA type boxes should be kept clean and free from dust and debris.

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Repair

• The brake should only be repaired by competent mechanics and electricians who are trained for this purpose. Only external hardware should be repaired or replaced on the brake under normal conditions; • Replace any electrical cable that becomes damaged or oil soaked; • Replace the throttle if damaged and assure that the wiring is replaced correctly; • The brake control should be replaced in its entirety and not repaired at the rig site except in emergencies; • The transformer should be replaced in its entirety if damaged or faulty.

DC motors and generators

CAUTION: These procedures should only be performed by trained maintenance personnel. Do not touch live electrical parts.

Daily Maintenance

1. Inspect the motor for excessive vibration. 2. Inspect the motor couplings, sprockets, hubs, mounting, and other mechanical connections. 3. Confirm that the cooling blower motor is operating properly. 4. Inspect the cables for damage or corrosion. 5. Confirm that the motor is not overheating during operation. 6. Inspect the field supplies and measure field current on shunt motors. 7. Check bearings for excessive temperature after continuous running. 8. Blow out dust and debris with clean, dry air. 9. Check tightness of mounting bolts.

Monthly maintenance

1. Inspect brushes for proper wear and tension on the commutator. 2. Inspect brush holder and mounting hardware 3. Inspect commutator for proper surface conditioning. 4. Check cooling blower for proper operation. 5. Check mounting of hub or coupling. 6. If non-sealed bearings, lubricate bearings with proper grease per the manufacturer’s recommendation. Do not over grease. 7. Check insulation resistance of motor windings. Dry out as necessary. 8. Verify operation of motor space heaters (if equipped).

Repair

• Replace brushes and brush springs as required; • Clean commutator according to the motor manufacturer’s recommendations;

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PW–40

POWER GENERATION AND DISTRIBUTION

• Resurface commutator if evidence of uneven wear or pitting is observed; • Replace blower if found defective; • Remove motor/generator from service if bearings or windings are found defective and replace motor/ generator on rig.

AC motors and generators

CAUTION: These procedures should only be performed by trained maintenance personnel. Do not touch live electrical parts.

Daily maintenance

• Inspect for excessive vibration when running. • For single bearing generators, assure proper mating between the diesel engines and AC generators. For double bearing generators inspect coupling. • Inspect motor couplings and mounting connections. • Inspect wiring to motor and generator. • Using dry air only, blow out dust and debris on motor and generator. • Inspect and verify integrity of all grounding connections.

Monthly maintenance

1. Inspect motors and wiring for evidence of overheating or damage. 2. Inspect all mounting and coupling hardware. 3. Inspect all wiring connections.

Repair

Caution: All repairs should be performed by competent mechanics and electricians who are trained for this purpose. • Replace diodes on rotary exciter with exact replacements if required for generator.

IADC Drilling Manual

• Remove defective motors from service and replace. • Clean and dry out motors and generators if exposed to high humidity or moisture.

Transformers

CAUTION: These procedures should only be performed by trained maintenance personnel. Do not touch live electrical parts. Before performing any service on transformers, be sure all power is off. Transformers usually do not have any moving parts, except for occasional cooling fans, and require minimal attention except for keeping them clean and dry.

Daily maintenance

1. Inspect for evidence of overheating. 2. Inspect for external damage to transformer case. 3. Inspect wiring and cabling to transformer.

Monthly maintenance

1. Clean with vacuum or dry compressed air to remove any moisture or dirt from the transformer. 2. Inspect for any hot spots and insulation damage on the transformer coils. 3. Inspect transformer connections and lugs for tightness and signs of overheating. 4. Check insulation resistance with all external leads disconnected. 5. Check all winding continuity with leads disconnected. Repair: • Replace any lugs or connections to transformer that become defective. • Replace the transformer if found defective.

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POWER GENERATION AND DISTRIBUTION

PW–41

REFERENCES 1. The Electric Drilling Rig Handbook, by Will L. McNair; PennWell Publishing Company, Tulsa, OK. 1980. 2. Economic Operation of Electric Drilling Rigs, paper presented by Will L. McNair at the 1980 IADC Drilling Technology Conference in Dallas, Texas. Reproduced in World Oil Magazine in June 1980 and in Oil & Gas Journal on April 7, 1980. 3. Fuel Economy - A Ten Year Projection for The Drilling Industry, by Will L. McNair and Roger D. Morefield, Drilling -- DCW Magazine, August 1980.

5. Electrical Design Considerations for Drilling Rigs, Frank A. Woodbury and Paul J. Thomas, a paper presented to IEEE Industry Applications Society, 1975 Milwaukee, WI. 6. Self-Study Technical Series for Rig Electricians, Electric Drilling Systems, Houston, Texas. 7. A Comparison of Mechanical and Electrical Drives for Land Drilling Rigs, by Glen Webb, presented at the 1977 IADC Drilling Technology Conference, March 1977.

4. A Systems Approach to Electric Land Rigs, by William M. Stone, presented at 1979 IADC Technology Conference, March 1979, Denver, Colorado.

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PUMPS

IADC Drilling Manual 12th Edition IADC Drilling Manual • Copyright © 2015

THE IADC LEXICON

D E F I N I N G T H E D R I L L I N G S PAC E ! IADC Lexicon puts critical definitions at your fingertips. Imagine thousands of the most pertinent definitions and terms relevant to drilling, all in a single convenient repository – the IADC Lexicon. The IADC Lexicon draws from the most critical legislation, regulations, standards and guidelines worldwide. The European Union requested that IADC, as the authority in the drilling space, create the Lexicon to aid in regulation and understanding our industry. Use the IADC Lexicon as a dictionary or to quickly and easily identify a relevant standard, guideline or regulation. Or, use it as a template to develop instructions for your own company.

www.iadclexicon.org

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PM–i

CHAPTER

PM

PUMPS

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. PRINCIPAL AUTHOR Robert Urbanowski, Precision Drilling Oilfield Services Corp. REVIEWERS Gary Henderson, National Oilwell Varco Ken Kondo, National Oilwell Varco Andrew Roskey, American Block

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PUMPS

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9906220-3-1

Printed in the United States of America.

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PUMPS Contents CHAPTER PM

PM-iii

Contents

PUMPS

Introduction.................................................................... PM-1 Description/basic theory........................................... PM-1 Purpose...................................................................... PM-1 Mud pumps.................................................... PM-1 Centrifugal pumps........................................ PM-1 Physical operating principles.............................. PM-1 Mud pumps.................................................... PM-1 Centrifugal pumps........................................PM-2 Important for what and to whom?................... PM-2 Mud pumps....................................................PM-2 Centrifugal pumps........................................PM-2 Common dimensions, weight and Capacity....................................................................PM-3 Mud pumps....................................................PM-3 Centrifugal pumps........................................PM-3 Standard location on a rig site (for stationary equipment).................................PM-3 Mud pumps....................................................PM-3 Centrifugal pumps........................................PM-4 Installation................................................................PM-4 Mud pumps....................................................PM-4 Centrifugal pumps........................................PM-5 Safety and handling......................................................PM-6 Mud pumps....................................................PM-6 Centrifugal pumps........................................ PM-7 Operational risks (failure mode/operational risks/ mitigation)................................................................PM-8 Mud pumps....................................................pm-8 Centrifugal pumps........................................PM-8 Uses and operations/application.............................PM-9 Operating procedures and best practices/ process/handling for operations.......................PM-9

IADC Drilling Manual

Mud pumps....................................................PM-9 Centrifugal pumps.......................................PM-10 Environmental considerations: temperatures, pressures, rock type, drilling fluid...................PM-11 Mud pumps...........................................PM-11 Centrifugal pumps..............................PM-11 Specialized situations..........................................PM-12 Mud pumps...........................................PM-12 Centrifugal pumps..............................PM-12 Evaluation, testing, and inspection Procedures..............................................................PM-12 Mud pumps...........................................PM-12 Centrifugal pumps..............................PM-12 Troubleshooting or failures................................PM-12 Mud pumps...........................................PM-12 Centrifugal pumps..............................PM-14 General maintenance.................................................PM-15 Repairs.....................................................................PM-15 Mud pumps...........................................PM-15 Centrifugal pumps..............................PM-15 Lubrication..............................................................PM-15 Mud pumps...........................................PM-15 Centrifugal pumps..............................PM-16 Proper storage considerations.........................PM-17 Mud pumps...........................................PM-17 Centrifugal pumps..............................PM-17 Advanced theory & important calculations........PM-18 Mud pumps............................................................PM-18 Centrifugal pumps................................................PM-19 Glossary........................................................................ PM-20 References: evaluation, testing, inspection.......... PM-21 Additional references................................................. PM-21

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IADC Technical Resources

IADC TECHNICAL RESOURCES ENHANCES RIG CREW EXPERTISE

IADC brings the collective knowledge and experience of the global drilling industry to the workforce through industry-developed print, electronic and multimedia tools and resources accessible in one convenient location. From books to industry news to manuals and more—IADC is the definitive source. The Technical Resources Center contains a variety of items, including: • IADC Bookstore and e-Bookstore: textbooks, guidelines, checklists, model contracts and more. • Online Safety Toolbox: Safety Alerts, safety meeting topics, near hit/miss forms and safety posters. • Knowledge, Skill & Ability (KSA) Competencies Database: filter competencies based on various criteria and generate a unique set of KSAs for each type of position on a rig. • Industry news: quick access to Drilling Contractor magazine and IADC Drill Bits newsletter. • Reports: Onshore and Offshore US Federal Regulatory Summaries and the International Regulatory Summary provide easy to access updated information on industry regulation.

www.IADC.org/technical-resources

PUMPS Contents

Introduction

This section covers high-pressure mud pumps and centrifugal pumps. Pumps consist of a power end and a fluid end. The mud pump is the heart of a rig’s circulating system (Figure PM-1). Normally, a mud pump is a large reciprocating pump used to circulate drilling fluid through the high-pressure mud system while drilling. However, mud pumps may also be used as riser booster pumps, where additional clean drilling mud is pumped into the riser annulus of an offshore rig to assist in bringing cuttings to the surface. Mud pumps are available in a number of sizes, with a variety of prime mover configurations. Additional mud pumps may be installed on a well-servicing or drilling rig for redundancy. Although triplex pumps, featuring three cylinders, have become more common than the two-cylinder duplex pumps, some mud pumps have four or more cylinders. Centrifugal pumps can be used for a variety of purposes for moving a number of fluids. Selection of the best centrifugal pump depends on the service requirements (erosion, corrosion, etc.), application, piping size, pipe length, fittings, valves, lift required, fluid properties and pressure requirements. Not including the drive and control systems, options for centrifugal pumps include pump size, impeller diameter, impeller material, impeller shape, pump speed, prime mover speed and prime mover power. Proper installation and maintenance are key to suitable pump life.

that fluid entering the casing in a central inlet is accelerated by the spinning impeller to a much higher velocity. The circular shape of the casing causes the high-velocity fluid to flow in a circular path toward an outlet. The rotational energy fed into the impeller is converted to hydrodynamic energy of the fluid flow. A centrifugal pump’s purpose, as part of a system, is to provide sufficient flow rate and pressure to move fluid through a piping system.

Physical operating principles Mud pumps

Mud pumps have a power input end (gear end) and a fluid output end. Power is fed in the gear end of a mud pump from engines, electrical motors or hydraulic motors to turn

Rotary Hose

Standpipe

Top Drive

Mud Pump

Pump Discharge Line

Mud Cleaning Equipment / Shale Shaker

Description/basic theory

Kelly (or Drill Pipe if Top Drive used)

Drill Pipe

Purpose

Annulus

Mud pumps

Mud Return Line

Mud pumps are devices that use mechanical energy to move fluid from Mud Tank/Pit one location to another. Mud pumps can be driven by engines, electrical motors (DC or AC), through transmissions or by hydraulic motors.

Borehole Drill Bit

Centrifugal pumps

A centrifugal pump is a machine with an impeller in a casing arranged so

PM-1

Figure PM-1: The mud pump is the heart of a rig’s circulating system. © IADC. All rights reserved

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PM–2

PUMPS does not. This is the main reason pump curves use total head in ft. If pressure were used, the curves would constantly have to change every time the density changed.

Important for what and to whom? Mud pumps

Some examples of mud pump uses are as follows: • Circulate completion fluid down a well during completion; Figure PM-2: Two 1,600-hp triplex pumps, land rig. Courtesy of Precision Drilling • Circulate drilling fluids down and up a well during drilling; • Pump cement down a well when setting a steel pipe (casing) string or a drilling liner; the pump crankshaft. The pinion shaft may be directly con• Provide a controlled and precise level of pressure nected to the prime mover through chains, belts, gear boxes and flow rate during well control operations or transmissions. The power end of a mud pump is essentially a speed reducer coupled to a slider crank mechanism used to translate the rotating motion of the power source to the reciprocating piston action required for pumping fluids.

Mud pumps on a drilling rig provide hydraulic horsepower and/or impact force to the drill bit to improve drilling efficiency. Some examples of drilling fluid functions provided by the mud pumps are as follows:

Fluid enters the mud pump through suction piping into the fluid end of the pump through suction valves. As the piston compresses against the lower-pressure inlet fluid, it exits a discharge valve at a higher pressure.

• Remove rock cuttings from the wellbore; • Exert hydrostatic pressure in the wellbore to control fluid influxes from the formations; • Cool and lubricate the drillstring and bit; • Keep the wellbore open until steel pipe (casing) string can be cemented in the wellbore; • Prevent damage to the formation that might hinder production of reservoir fluids

Mud pumps can lose efficiency both mechanically (for example, lost power to turn the pump’s power end) or volumetrically (for example, discharge valve not functioning perfectly).

Centrifugal pumps

When the inlet fluid into a centrifugal pump leaves the impeller at a higher velocity, the circular casing causes the fluid to flow in a circular path. The fluid pushes against the wall of the pumps casing, which creates a pressure head. This pressure head allows the fluid to exit the tangential outlet of the centrifugal pump. The faster the impeller spins or the bigger the impeller is, the higher the fluid velocity leaving the impeller. Centrifugal pumps are “constant head” machines. If the discharge of a centrifugal pump were pointed vertically into the air, the fluid would pump to a certain height or head. Head is a measurement of the kinetic energy the pump adds to the fluid being pumped. It is important to note centrifugal pumps pump different density fluids to the same height if the pump shaft is turning the same impeller at the same speed (RPM). Pressure (resistance to flow) changes with different density (specific gravity) fluids, but head from the centrifugal pump

IADC Drilling Manual

Mud pumps can consume a large amount of the horsepower available to power a drilling rig. It is important to keep mud pumps well maintained in order to minimize rig downtime. A failed mud pump can also cause an unplanned release of pumped fluids that might create an environmental concern.

Centrifugal pumps

Some examples of centrifugal pumps uses are as follows: • Move water through a rig’s water piping system; • Provide cooling water for a water cooled drawworks brake (drum brake cooling, plate-style disc brake cooling, eddy-current auxiliary brake cooling); • Deliver working fluid for a water auxiliary brake; • Transport pressurized (supercharged) mud to the inlet of a mud pump for positive suction to improve pump performance; • Move mud through mud lines to transfer mud; • Run pit nozzles and/or mud guns for stirring drilling fluid;

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PM–3

• Move mud through the jet to draw the mud out of a vacuum degasser; • Feed drilling mud into hydrocyclones to clean the mud in the cones of a desander, desilter or mud cleaner; • Move mud through the mixing nozzle of a hopper to mix dry or wet materials in a fluid; • Pump mud from a trip tank into a wellbore to provide an accurate measurement of fluid being swabbed or lost into a well during a trip. Centrifugal pump efficiency can vary greatly depending on selection of pump size, pump speed, impeller diameter and size of pump driver. Whenever possible, the lowest pump speed Figure PM-3: Electric in-line centrifugal pumps on trip tank. should be selected to minimize wear on rotating Courtesy of Precision Drilling components. If the application requirements vary, a belt-driven pump can be used to vary pump speed mud pump can weigh 35,000 lb for the bare pump with dithrough the use of different-sized pulleys (or sheaves). mensions 15-ft long x 5-½-ft high x 8-½-ft wide. A 2,200-hp triplex mud pump can weigh 85,000 lb for the bare pump with dimensions 19-ft long x 7-½-ft high x 10-½-ft wide. A Some centrifugal pumps have specialized impellers and cas3,000-hp triplex mud pump can weigh 105,000 lb for the ings to shear either drilling mud additive products for better bare pump with dimensions 20-½-ft long x 6-½-ft high x 10mixing or drilled solids for cuttings injection downhole (for ½-ft wide. At the 3,000-hp size, a mud pump becomes an example, behind an intermediate steel pipe [casing] string). offshore pump, since it is too large to easily move on land rigs. The output pressure rating of a mud pump can also increase the weight.

Common dimensions, weight and capacity Mud pumps

Mud pump sizes can vary greatly depending on the unitized installation of the equipment and application needs. Using larger pumps on a land drilling rig might minimize the number of loads but create transportation permitting issues and regulations compliance issues as a result of weight and overall physical dimensions. Well servicing pumps might vary from 2-½-hp simplex plunger pump with just the pump weighing approximately 220 lb. A slightly larger 300-hp quintuplex plunger pump can weigh 7,000 lb for just the bare pump (pump less driver). An intermittent-duty 2,500-hp triplex plunger pump can weigh 12,500 lb for just the bare pump at 8-ft long x 4-ft high x 6-ft wide. Well-servicing pumps are built as highly portable. A unitized pump used for hydraulic fracturing can fit on a single truck trailer with a 2,500-brake hp diesel engine, multiple-speed transmission and 2,500-hp quintuplex plunger pump at 45-ft long x 12-½-ft high x 8-½-ft wide. Mud pump sizes for drilling rigs vary greatly. A 425-hp triplex pump including multiple-speed transmission, 5x4 centrifugal super-charging pump and 425-brake hp diesel engine can fit on a single oilfield skid. A 1,000-hp triplex

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Centrifugal pumps

Centrifugal pump sizes and weights vary greatly. A 3x3 centrifugal pump weighs 500 lb without any motor/drive included and is 3-ft long x 2-ft high x 2-ft wide. An 8x6 centrifugal pump weighs 700 lb without any motor/drive included and is 3-ft long x 2-½-ft high x 2-½-ft wide. A 10x8x14 centrifugal pump weighs 750 lb without any motor/drive included and is 3-ft long x 2-½-ft high x 2-½-ft wide. The weight and dimensions of the driver can vary greatly depending on the application.

Standard location on a rig site (for stationary equipment) Mud pumps

Mud pumps on well servicing rigs can vary widely depending on the requirements of the workover or completion application. In general, like drilling rigs, the pumps are generally located either unitized or in close proximity to steel tanks that hold the fluids being pumped. Mud pumps operate more efficiently with a shorter suction. Barge rigs and offshore rigs also tend to position pumps close to mud tanks.

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PUMPS

Figure PM-4 : Suction piping to triplex pumps on land rig. In placing mud pumps, consider the need to change out pump modules, discharge dampeners, engines and electrical motors. A removable roof section might be added if a mud pump is enclosed. Distances to install high-pressure piping as well as minimizing electrical cable length runs are also considerations, as above. Courtesy Precision Drilling.

On land rigs, considerations for changing out pump modules, discharge dampeners, engines and electrical motors should be considered. One might have a removable roof section added if a mud pump is enclosed. Distances to install high-pressure piping as well as minimizing electrical cable length runs can be considerations for where to locate mud pumps on a rig layout. Vibrator hoses are usually installed in the discharge piping from a mud pump to allow for misalignment and vibrations.

Centrifugal pumps

In general, centrifugal pumps are installed close to the source fluid to be pumped for a shorter suction. Centrifugal pumps are normally installed below the fluid level to be pumped to eliminate the need for priming the pump. With the need to move fluids from various positions throughout a drilling rig, standard locations vary. Centrifugal pump installations can include mud systems, water systems, fuel systems, fire pumps and cooling systems

Installation Mud pumps

Particular attention should be paid to the construction of the suction line (and the pit or tank fluid level) in relation to that of the mud pump. Proper installation and operation of the mud pump requires the minimum net-positive suction head requirements at the pump suction flange be met. Sufficient net-positive suction head ensures that the drilling fluid fol-

IADC Drilling Manual

lows the piston on the suction stroke without any voids or airspace forming between the slug of fluid and the piston. If airspace forms in this area, a knock occurs when the fluid contacts the piston at the end of the piston stroke. Besides reducing the efficiency of the pump, knocking reduces the service life of expendable pump parts and could be detrimental to the power end of the mud pump. When designing suction piping, it is best to have an upward slope toward the centrifugal pump suction inlet to prevent trapping of air or gas. Mud pumps require a boost in suction pressure to meet their net-positive suction head requirements. This pressure boost is normally supplied by a centrifugal pump placed in the suction line. The primary purpose of the pre-charging centrifugal pump is to keep the mud pump from being starved by maintaining a positive pressure in the suction line. Many benefits may result from the addition of a centrifugal supercharging pump: • • • • •

Higher pump output; Increased volumetric efficiency; Less expensive hydraulic horsepower; Smoother operation; Longer pump parts life.

It is good practice to use suction strainers, but they are a potential source of trouble and should be kept clean at all times. A restriction in the suction strainer can cause knocking in the pump.

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PM–5

Pulsation dampeners in mud pump suction and discharge lines serve to absorb the pressure-flow variations normally produced by the reciprocating motion of the pump pistons. If dampeners are not properly maintained and operated, the pressure-flow variations can produce damaging effects to piping and mud pump components. A high-pressure relief valve must be installed in the discharge line as close to the mud pump as possible. Its purpose is primarily to protect the pump and discharge line against extreme pressures such as might occur when a bit becomes plugged or a mud pump starts against a closed discharge line valve. The relief valve should be used to limit the pressure in accordance with the pump manufacturer’s rating for a given liner size. Usually, relief valves are set to exceed rated liner pressure by some given amount (i.e., no more than 10%). Ensure the high-pressure discharge relief valve is installed ahead of any valves so that accidentally starting a pump against a closed valve does not damage the mud pump. Any high-pressure relief valve must be installed before the discharge strainer in the discharge line. A plugged discharge strainer might keep the relief valve from actual discharge pressure levels at the outlet of the mud pump.

Centrifugal pumps

Centrifugal pumps should be installed below the fluid level to be pumped. A flooded suction helps to prevent cavitation. Installation of suction lines should avoid allowing air to enter the suction. Such air can also be introduced by a return line dumping close to the suction line to the centrifugal pump. Multiple centrifugal pumps should not share the same suction if they are to be run at the same time. A vortex breaker can help avoid air flowing into the suction. A concentric reducer should not be used in the suction line. An eccentric reducer with a flat side on top helps avoid air entering the centrifugal pump.

Figure PM-5: Electric vertical centrifugal pump on mud tank. Pipe fittings for centrifugal pumps should not be installed less than two pipe diameters from the suction inlet to the pump. The diameter of the suction piping should be small enough to allow a linear flow rate of at least 4 ft/sec. Courtesy Precision Drilling.

Pipe fittings should not be installed within a distance that is equal to or shorter than two pipe diameters from the suction inlet to the pump. The diameter of the suction piping should be small enough to allow a minimum of 4 ft/sec linear flow rate. Suction piping for water might be larger if the suction line is installed over a long distance. At slower speeds, solids can settle out and clog the suction piping. Discharge piping can be sized for a minimum of ten ft/sec linear flow rate. Too small a discharge piping can limit the flow rate delivered. Too large a discharge piping can overload the motor. A flexible coupling should be installed between electric motors and inline centrifugal pumps. The flexible coupling between the motor and centrifugal pump should not be used

IADC Drilling Manual

Figure PM-6:In-line centrifugal pump. Centrifugal pumps should be installed below the level of the fluid to be pumped. Flooded suction helps to prevent cavitation. Installation of suction lines should avoid allowing air to enter the suction. Air can also be introduced by a return line dumping close to the suction line. Courtesy Precision Drilling.

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PM–6

PUMPS to correct misalignment of the motor shaft and pump shaft. A flexible coupling should also be installed in the discharge piping of a centrifugal pump. These couplings can absorb vibrations that can damage the centrifugal pump. Discharge and suction piping should be supported by pipe support rather than the centrifugal pump. Valves in the suction piping and discharge piping may be required to allow removal of the centrifugal pump for servicing and replacement.

Safety and handling Mud pumps

Any time maintenance work is performed on a bladder-style pulsation dampener of a mud pump, the precharge on the dampener must be completely bled off. Component damage and personal injury could result if a dampener is disassembled while still pressurized.

Table PM-1: Cross-reference to part numbers in Figures PM-8 & PM-9 1: Cylinder Head

17: Packing

2: Cylinder Head cover

18: Gland

3: Liner Packing Adjustment

19: Gland Nut

4: Cylinder Head Packing

20: Piston Rod

5: Liner Cage

21: Valve Cover

6: Liner

22: Valve Cover Plate

7: Tell-tale Hole

23: Valve Cover Packing

8: Liner Packing Cage

24: Valve Pot

9: Liner Packing

25: Valve Seat Deck

10: Lantern Ring

26: Valve Guide

11: Liner Pulling Threads

27: Valve Spring

12: Piston

28: Valve

13: Fluid Cylinder

29: Valve Seat

14: Rear Liner Cage

30: Liner Retention Arrangement

15: Stuffing Box

31: Liner Seal Plate

16: Junk Ring

32: Cylinder Head Adjustment

Valve seats on mud pumps should be pulled with appropriate pullers rather than torch cutting. Torch cutting can damage discharge modules.

possible severe damage to the pump. It is important, therefore, that replacement parts be installed properly. Most manufacturers of pumps or pump parts publish recommended procedures for installing parts, and these instructions should be followed closely.

Mud pumps, despite their extreme size, are actually very precisely engineered pieces of equipment, manufactured to very close tolerances and fits. If good procedures are not followed and replacement parts are installed carelessly, you will most likely have shortened service life of these parts and

The moving parts of the fluid end of a mud pump should have a cover or guard installed to protect personnel from moving parts. Never hammer on mud pump parts that are under pressure. Never tighten liner packing while the pump is under pressure. Always bleed off the pressure first. Shut down and disengage the power source before working on a mud pump. Liners should never be struck directly with a hammer, since dents can damage the sleeve and/or plating material. Always use a piece of wood to absorb some shock from the hammer. Mud pump components can be extremely heavy. Always ensure personnel stay a safe distance from parts being lifted. Hydraulic (fast-change) systems can simplify and expedite removal and installation of piston rods, liner retainers, valve covers and discharge strainer covers. Hydraulic and pneumatic wrenches can also be used to loosen and tighten bolted connections. These systems can be faster and safer than swinging a sledgehammer.

Figure PM-7: Fluid end triplex pump in winterized building. The moving parts of the fluid end should have a cover or guard installed to protect personnel from moving parts. Courtesy Precision Drilling.

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High-pressure mud pumps must never be operated at speeds, pressures or hp exceeding the limitations speci-

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PUMPS

23

26 26

25 24 26

30

9

4

6

30

27 24

22 23

21

4 12

1

28 25

PM–7

4

2

20

26 9 1

28

27 28

1

6

15

J1-6

Figure PM-8: Two types of single-acting mud pumps with over and under valves, front loading. Part numbers are listed in Table PM-1.

fied by the manufacturer on the rating plate (i.e., data plate). Do not paint over the rating plate—it contains critically important information. Use caution when tightening or loosening hammer lug connections and valve covers. Always wear proper personal protective equipment (safety shoes, safety goggles, impact resistant gloves, etc.). Bladder-style discharge dampeners and suction dampeners should only be pre-charged with nitrogen. Never pre-charge these systems with air. Ensure that any manual pump rotating devices have been removed before starting the mud pump.

Centrifugal pumps

Figure J1-6: Single-Acting Mud Pump with Over & Under Valves – Front Loading

Ensure centrifugal pumps have been locked out (isolated from energy sources) and tagged out (marked “Danger/Do Not Operate”) before any maintenance or repairs are performed. Adjustments should not be made when a centrifugal pump is running. Competent personnel and/or qualified electricians should be the only ones working on electrical systems. A pump that is hot should never be worked on until it has cooled off. Centrifugal pumps should have all guards and hardware installed when starting up. Water in a centrifugal pump running against a closed discharge valve can boil quickly. Ensure any suction valves are open and a discharge valve is at least partially open before starting a centrifugal pump. Do not operate a centrifugal pump with the suction valve or discharge valve closed.

The moving parts of a centrifugal pump should be covered or guards installed to protect personnel from moving parts. Do not attempt to remove guards or covers when a pump is running. Inadequate lubrication or excessive lubrication can damage bearings.

Figure PM-9: A typical single-acting mud pumps with “I” head back loading. Part numbers are listed in Table PM-1.

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PM–8

PUMPS

26

21 22 23

27 28

24

29

25 19 18

20

3

24

19

4

1

5

7

12

9 10

6

13

24

24

Figure PM-10: Fluid end of typical duplex double-acting mud pump. See Table PM-1 for part numbers.

Operational risks (failure mode/mitigation) Mud pumps

When oil is used in drilling fluid, proper valve and piston materials should be selected that are oil-tolerant to provide an acceptable length of operating life. Contact the manufacturer for their recommendations based on fluids in use. As the piston fails in a mud pump, there is high-velocity fluid slipping between the piston flange and liner bore. When a failed piston is allowed to run, this jetting fluid causes washout damage to the piston flange and liner bore. The cost of a piston is small compared to the cost of a liner, so every effort should be made for early detection and replacement of piston failures to prevent extensive damage to the liner bore. Piston rubbers tend to wear rapidly in single action pumps if the piston and liner are not flushed adequately with coolant. The amount normally ranges from 5 to 10 gal/min per liner, but it is best to refer to the manufacturer’s recommendations in order to keep the liner cool and flush any piston leakage from the liner. A method of cooling is to direct a spray into each pump liner. Care must be taken to get complete coverage with this technique or liner walls may not be completely flushed. Dirty coolant increases piston and liner wear. Several different arrangements are in use to accomplish proper flushing and cooling. The arrangement should allow complete flushing of the entire stroked area in the liner and should increase the service life of both the piston assembly and the liner. Proper cooling becomes more critical as pump speed and drilling fluid temperatures increase. Effective coolant lubricants fluids include cool, clean, fresh water; a mixture of soluble oil and water; and a mixture of water plus detergent.

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Double-acting (i.e., duplex) mud pump piston rods must be replaced periodically because they wear on the outer diameter (OD) as the rod strokes through the rod packing. The pump rods are designed to be wear-resistant in this area, and manufacturers generally offer both a standard grade and premium grade of rod. Most of the high-pressure rods on high-hp duplex pumps require both corroJ1-7 sion- and abrasion-resistant coatings for heavy-duty applications. A premium-grade rod should be used, which may have a chrome-plated coating over case-hardened steel or a sprayed and fused layer of hard metal such as nickel-chrome-boron. The nickel-chrome-boron coating is more abrasion- and corrosion-resistant than chrome plating and generally should last longer. As the rod wears, the high polish and absence of corrosion pitting tends to reduce packing wear. The standard metal pump rods are not coated but are heat-treated to be as hard as the costlier premium rods. Although the standard rods lack the corrosion and wear resistance that premium rods exhibit, they should provide satisfactory service in lower-pressure non-corrosive environments.

Centrifugal pumps

Packing life in centrifugal pumps is reduced at higher shaft speeds. One more important point in pump selection is to pick the pump that does the required job at the lowest speed. Belt-driven centrifugal pumps with multiple sheaves can allow speed changes for changing operations as well as selection of a less costly electrical motor—based on motor speed—to drive the pump. Misalignment between electric motor (driver) and pump can cause premature bearing failure. Pumps should always

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PUMPS

107

101

115

PM–9

114

106

Figure PM-11: Section through power end of mud pump. See Table PM-2 for part numbers.

be aligned properly before starting during initial installation, when changing out pump and when changing out electric motor. An electric motor driving a centrifugal pump should be selected to handle the maximum amount of flow rate that the impeller can handle. Such an electrical motor is large enough to use the pump at any flow rate without overload.

Table PM-2: Power End Parts Numbers for Mud Pumps 101: Frame

108: Crosshead Pin*

102: Crankshaft

109: Connecting Rod Bearing*

103: Main Gear

110: Crankshaft Bearing (Main)*

104: Pinion

111: Crankshaft Bearing Housing*

105: Pinion Shaft

112: Pinion Shaft Bearing*

106: Connecting Rod*

113: Crosshead Pin Bearing*

107: Crosshead*

114: Crosshead Extension Rod (Pony)* 115: Crosshead Extension Rod Wiper*

Uses and operations/application Operating procedures and best practices/ FIGURE J1-9. Sectional through power end. process/handling for operations

* For triplex pump, the exact location of these parts is designated as right, left, or center.

See Table J1-1. J1-9

Mud pumps

In an effort to reduce mud pump downtime, some drilling contractors keep an extra piston and rod assembly ready for immediate installation. Care should be taken never to store a piston and rod assembly with the piston lying on the floor. This could cause a flat spot on the piston rubber, resulting in premature failure. Purpose-built fixtures for tightening pistons on rods can improve maintenance efficiency. Mud pump parts can be heavy and difficult to handle. Installation of trolleys and hoists can facilitate safe and efficient maintenance of mud pumps. Consideration of rig equipment layout should include how to access and change out mud pump modules. This might include: • Forklift access path to the front end of a mud pump on a land rig;

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Figure PM-12: Section through crankshaft. See Table PM-2 for part numbers.

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PM–10

PUMPS

Figure PM-13: Triplex pump module. Courtesy of Precision Drilling.

• Hatch on top of a building over modules for crane access on a land rig; • Trolley and hoist of sufficient capacity on an offshore rig installation. Never install old valves in a new seat or new valves in a worn seat (Figure PM-14). Remember, when installing new valves in the pump; always use new springs to ensure long trouble-free service from valves and seats. Otherwise, check springs for signs of corrosion, loss of tension, physical abuse or wear. Do not use worn pistons in new liners or new pistons in worn-out liners. Proper lift with adequate guiding and correct springs are necessary for optimum valve life and performance. On recirculating type liner coolant systems, a piston failure can contaminate the coolant with drilling fluid. The rod chambers and coolant pump should be thoroughly cleaned after each piston failure, and the sump filled with fresh coolant. At every routine oil change for a mud pump, the adjustment of troughs and wiper arms on splash-gravity flow system lubrication systems should be checked and the fasteners which retain these members in position should be checked for the correct tightness. Self-aligning rods can help with some misalignment, but will not correct severe misalignment

Centrifugal pumps

A centrifugal pump that has been carefully selected for its application shows less wear and that wear is uniform, thus affecting performance less adversely. A pump that is the

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Figure PM-14: Worn valve in new seat, and new valve in worn seat. Courtesy of Precision Drilling.

wrong size or the wrong design for its service can very likely fail prematurely. Requesting assistance in selecting the proper centrifugal pump from a knowledgeable centrifugal pump expert early in a design or project can save operational downtime. Packing problems are usually caused by difficulty in maintaining proper lubrication between the shaft and packing. The shaft and packing must be lubricated to prevent shaft scoring and wear as well as packing wear. The most common method for lubricating packing is to allow leakage. The most common cause of packing difficulties comes from preventing this kind of lubrication by over-tightening. Tight packing causes excessive heat that wears the shaft and packing. As

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PUMPS

PM–11

a result, the shaft is scored, and packing must be replaced frequently. Therefore, it is virtually impossible to maintain reasonable packing life or seal against a rough or damaged shaft. When repacking the stuffing box on a centrifugal, first make sure the box is clean and all old packing is removed. It is important to use a good quality, clean packing. Mechanical imbalance and misalignment produces excessive loads on the centrifugal pump because of improper (poor) piping foundation and improper installation. Solids that ball up and plug the impeller cause a mechanical imbalance and corresponding vibration loads that are damaging. Such imbalances can reduce or affect bearing life. Always check alignment when installing a new centrifugal pump with a dial indicator or straight edge. Alignment can be adjusted with spacer shims under equipment feet. Use shims large enough for the entire footing of the equipment. Do not rely on the flexible coupling as a remedy for misalignment.

Figure PM-15: Triplex pump with modules removed. Courtesy of Precision Drilling.

Always check the rotation of a newly installed centrifugal pump to ensure the electrical motor has been wired properly. If a motor driving a centrifugal pump does not start and the pump can rotate freely by hand, it is an electrical problem with the motor.

Environmental considerations: temperatures, pressures, rock type, drilling fluid Mud pumps

Urethane pistons that have failed due to excessive heat have the appearance of a melted candle. Urethane pistons that have failed due to abrasion have a rough surface with longitudinal streaks and loss of material. Cold-weather operations may require less viscous extreme pressure, non-corrosive, anti-foaming gear lubricant.

Centrifugal pumps

Piping systems and centrifugal pumps can freeze in cold weather, especially if fluids are not moving. It may be necessary to drain or blow piping down with air before it freezes in extreme cold. Drain locations should be installed in the lowest piping positions, with piping slanting to such locations. Pumping systems can also be installed in heated areas.

Drilling in areas with sour gas (hydrogen sulfide) can lead to sulfide stress cracking of mud pump components unless drilling fluid in use includes oil in the continuous phase, pH of drilling fluid is 10 or higher, and/or chemical sulfide scavengers are used in the drilling fluid system.

The pump manufacturer should be contacted when selecting a pump for pumping high-abrasive fluids, corrosive fluids and different types of fluids.

Options for valve types, valve materials and piston materials may exist for applications with higher temperature, abrasive fluids, corrosive fluids, different fluid types (oil, synthetic oil, high pH, low pH, etc.) and higher pressures. Contact the pump manufacturer or parts manufacturer for guidance in proper selections for your application.

Mud pumps

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Specialized situations Make sure a mud pump is completely primed before starting against pressure. Always start a mud pump slowly when bringing up to operating speed.

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PM–12

PUMPS

Low-speed operation of mud pumps might jeopardize proper lubrication, unless the pump has a separate lubrication system (such as an external electric motor-driven gear pump-type system).

phragm of dampeners can also fail and should periodically be visually inspected. Fluid pressure pulsations in the discharge line can shorten the life of the discharge piping and the rotary hose (Figure PM-16).

Centrifugal pumps

Streaking in liner bore or piston rubbers is generally caused by excessive sand or other abrasive or foreign materials in the drilling fluid. Keep drilling fluids as clean as possible, and inspect the liners frequently when the pump is shut down.

Make sure a centrifugal pump is completely primed and has and has adequate positive suction provided before starting.

Evaluation, testing, and inspection procedures Mud pumps

Mud pumps should be inspected when in operation for excessive knocking or leaks. Check the power end of mud pumps daily to ensure proper oil level exists. The oil in the crank case of a chain-driven pump should also be checked daily. Any pump that has been in storage or was shipped from the manufacturer needs an inspection to ensure all parts are properly in place. This inspection should also ensure no damage occurred during transportation

Centrifugal pumps

Centrifugal pumps should be inspected when in operation for abnormal noise or leaks and to ensure electrical installation is proper.

Troubleshooting or failures Mud pumps

Mud pumps do not function well if the suction line does not provide sufficient fluid flowing into the pump. Solids may settle out in a suction line when not in use if the velocity of the fluid in the line is too slow. These solids can reduce the effective size of the suction line. When the rig is moved from one location to another, the suction line (and strainer if so equipped) should always be thoroughly washed out. Other times, suction velocity is not great enough to keep mud from settling out of the line. If a hose is used in the suction line, the inner lining should be visually inspected to ensure the hose lining has not collapsed or separated due to the use of low-aniline point oils, wear or from other causes. To ensure smooth and efficient pump performance, nitrogen-charged pulsation dampeners on mud pumps should be checked to ensure proper operation and correct pre-charge level. If there is any doubt as to the correct charge for a given pumping pressure, contact the manufacturer for assistance. An incorrect charge renders the device ineffective. The dia-

IADC Drilling Manual

Figure PM-16: Nitrogen-charged discharge dampener on triplex pump. Courtesy Precision Drilling.

Pitting of liners indicates corrosive conditions. The pH of mud should be checked and increased if too low (less than 7.2 pH). Corrosion inhibitors may be considered. If corrosion is severe, the use of corrosion-resistant liners may be indicated. A fully salt-saturated drilling fluid with chlorides 200,000 ppm or higher can tie up the oxygen and become less corrosive than a drilling fluid with chlorides in the 30,000 ppm to 70,000 ppm range. Normally, a piston body wears more on the lower side than the upper, due to gravity. Wear on one side of piston or liner (other than the lower side) may be caused by pump misalignment. Check for worn crosshead slides, worn pump bores, worn stuffing boxes and junk rings, and unequal tightening of liner rod packing. The use of regular (natural rubber) piston rubbers in oilbased or oil-contaminated mud results in swelling and deterioration of the rubber. The use of oil-resisting piston rubbers in oil-emulsion muds with low-aniline point oils can also result in similar swelling and deterioration. In the latter case, failure of other parts such as pipe protectors, blowout preventer rubbers, etc., will probably also occur.

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PUMPS A starved suction or starting the mud pump without priming can result in “burning” the piston rubbers in dry lines. Rapid failure results after burning has occurred, and it is sometimes difficult to trace or identify the failure. A “squealing” in the cylinders when starting the pump or trying to pick up a prime indicates probable damage. Piston rubbers on single-acting mud pumps can be burned or can rapidly deteriorate due to improper functioning of the pump’s liner coolant spray system. The spray mechanism at the rear of the liner should be checked frequently to ensure that a full, continuous stream of coolant is sprayed into the liner. Rod breakage in the body of a rod on a mud pump can be due to cracks started by hammer blows or other external rod damage. Do not hammer on the body of the rod to remove the piston. Fluid cutting of the liner in the packing area is generally due to failure to tighten packing sufficiently, keep it tight or replace it when worn. Over-tightening will “bottleneck” the liner and possibly cause damage to other mud pump parts. Rods broken through taper (double-acting mud pumps) can be caused by pump misalignment. Check for unequal wear on piston rod, piston body or liner for evidence of misalignment. Break can also be caused by a notch or a stress concentration point or improper torque on the API High Pressure (HP) taper make-up so that the joint is not pre-stressed. Rods pulled apart in taper-end thread (double-acting mud pumps) breaks are found exclusively in the smaller tapers and are generally the result of over-tightening the piston and nut when making the piston up on a rod.

so that the new seat will not seal properly. If a deck needs reworking, it should be done by a qualified person before a new seat is installed. Crosshead extension rod wipers are the vital barrier between the power end of a mud pump and piston rod chambers, confining gear oil to the power end and the splashing or spraying coolant and drilling mud to the rod chamber. At least two and as many as four wipers or seals are used on each crosshead extension rod, and in some designs, grease is pumped between the seals to form an additional barrier against mud entering the power end. Neglect of these wipers is probably the most frequently seen power end maintenance problem on mud pumps. Failure to maintain the rod wipers inevitably leads to water, sand and mud entering the power end and contaminating the gear oil, subsequently resulting in rapid wear of the gears, cross-heads and bearings. Gear oil seepage into the rod chambers can also occur, necessitating the addition of expensive gear oil to the power end. Excess contamination of mud pump gear end oil can be due to: • Failure to thoroughly flush out the oil reservoir at each oil change; • Damaged or worn cross-head extension rods, wiper rings and diaphragm stuffing box seals; • Failing to frequently drain contaminants out of the settling compartment below the cross-heads; • Dirty oil buckets, hoses, etc. contaminating the oil when installing new oil

On single-acting mud pumps, over-torquing of the piston rod nut can cause rod breakage, thread galling and other installation and removal problems. Short packing life (double-acting mud pumps) can be a result of over-tightening of packing, insufficient lubrication, high sand content, use of worn-out rods with new packing, washouts on worn stuffing boxes, worn junk rings, misalignment or unequal tightening of the gland. Fluid-cut sealing members or parts failures on valves and seats are generally due to foreign material or lost circulation materials in the mud, or continued use of new sealing members on worn metal parts. Check all parts for wear, including upper valve guides, and replace if worn out. Fluid-cut taper between the valve seat and pump deck is due to failure to realize the importance of proper installation and replacement of valve seats. Careless use of a cutting torch in removing valve seats can also result in damaging the deck

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PM–13

Figure PM-17: Failed piston inside liner. Courtesy of Precision Drilling.

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PM–14

PUMPS

Table PM-3: Centrifugal pump troubleshooting guide. Not Pumping

Not Delivering Enough Liquid

Pump Not Primed

X

X

Speed Too Low

X

X

Discharge Head Too High

X

X

X

X

X

X

X

X

X

X

Causes

Suction Lift Higher Than Design

Noise Vibration

X

Impeller Completely Plugged Wrong Direction of Rotation

X

Plugged Suction or Discharge Line

Not Enough Pressure

X

Bearing Wear

X X

X

X

X

X

Foot Valve or Suction Line not Immersed Deeply Enough

X

X

X

Impeller Damaged

X

X

Casing Packing Defective

X

X

Impeller Diameter Too Small

X

X

X

X

X

Starts Then Loses Suction

X

Insufficient Suction Head for Hot Liquid

Excessive amount of air or gas in liquid

Uses Too Much Power

X

X

Speed Too High

X

Total Head Lower Than Design

X

Specific Gravity or Viscosity Too High

X

X

X

X

X

X

X

Bent Shaft

X

Check Electric Motor Wiring and Voltage Rotating Elements Bind

X X

Leaky Suction Line or Shaft Seal

X X

X

X

X X

Misalignment

X

Bearing Worn

X

X

Rotor Out of Balance

X

X

Excessive Internal Thrust

X

X

Lack of Lubrication / Dirt or Excessive Cooling

X

Suction or Discharge Piping not Anchored

X

Improper Foundation

X

X

X

Centrifugal pumps

The majority of centrifugal pump failures are due to bearing failures and mechanical (packing) seal failures. Over time, corrosive and abrasive fluid passing through a centrifugal pump can cause wear of the impeller and casing. A new impeller or new casing can be installed to return the centrifugal pump to its original efficiency. The Centrifugal Pump Troubleshooting Guide (Table PM-3) should be used to diagnose symptoms of poor performance.

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X

X

The most important bearing problems come from contamination. Dirt and grit in the bearing race cause rapid failure. Moisture within a bearing enclosure (usually entering from contaminated lubricant) causes rust and corrosion with subsequent bearing failure. An increase in bearing temperatures (above 200°F [93°C]) or noise indicates possible bearing failure. Complete bearing failure usually damages other pump parts. The objective is

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PUMPS to prevent complete bearing failure by changing the bearing when the above conditions are detected.

General maintenance

Repairs Mud pumps

Repairs to mud pumps should strictly follow manufacturer’s instructions. Routine maintenance performed in the field includes (but is not limited to) replacing/servicing liners, pistons, rods, rod packing and liner packing (double-acting pumps), liner flush and coolant assembly, piston clamp (single-acting pumps), fluid end modules, suction valves and seats, discharge valve and seats, suction modules, discharge modules, and liner gaskets. There are many close tolerance parts that are critical to the proper operation and service life of a mud pump. Manufacturer’s tolerances and make-up torques should be followed closely when performing repairs. The primary goal of a preventative maintenance program is to help the drilling contractor realize and control fluid circulating equipment costs. It is possible to control mud pump costs, if the life of fluid-end parts can be reasonably predicted so that they can be pulled before failure. This saves money because when a part is run to failure, the pump goes down—likely when it is needed most—and the odds are that another part is damaged or is due to fail soon. At this time, money is being lost; money is coming out of the contractor’s pocket. Some of this lost money is: • Lost footage: That all-important portion of the hole before the drilling contractor and operator reach total depth, each hour of not drilling represents NPT; • Damage to other parts: A piston run to complete failure almost invariably takes the liner with it. A liner costs four to eight times more than a piston; • Man hours on the pump: In addition to the cost of the liner, how often does the crew complain about always going into the pump? How many times has someone been hurt working on the pump? How does a preventative maintenance program operate? If a part is replaced before it fails, the change out can be made at a time most convenient to the drilling contractor and operator, not when it is unexpected or costly to be down. Parts that are left in will not be damaged and can be expected to run their full life. Those few cents per hour wasted by the item pulling a part with few hours of life left on it are more than saved. How much do you save by running the risk of shutdown attempting to get another 50-100 hours use out of a part? Schedule pump downtime, and reduce pump downtime and rig downtime, by changing parts in groups. If a part is worn out, its companion part that was installed at

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PM–15

the same time has the same level of operating hours and is also worn out. By changing parts of the pump in a group, you eliminate continually going into the pump. Time for maintenance and pre-job planning time is minimized. Since you can program a part and know when it is time to be replaced, you can then plan all your events or activities so that the pump is less likely to be down while drilling is in progress. To predict when parts will fail, a history of operating hours on both pistons and liners should be closely tracked. This history should be updated at the end of each tour. Such planned maintenance includes: (a) changing valves and seats at the same time, (b) changing liner and liner packing at the same time, and (c) changing pistons and rods at the same time.

Centrifugal pumps

The impeller should be replaced if it shows excessive erosion, wear or vane breakage. Bearings should be replaced if they appear to run rough when rotating the pump—indicating they may be loose or worn. A rise in operating temperature may also indicate a failing bearing. A bearing failure can cause the entire centrifugal pump to be damaged. Bearing failure can be caused by: • Misalignment of the pump and driver; • Bent pump shaft; • Improper lubrication; • Improper installation Basic maintenance should follow OEM procedures.

Lubrication Mud pumps

Gears, bearings, crossheads and crosshead liners are all utilized in most conventional mud pump power end designs. Reliable, long-life service from these items is primarily dependent upon proper lubrication. Therefore, routine power end maintenance must focus upon the mud pump’s lubrication system and the care and periodic inspection of components associated with it. Lubrication systems for the power end of mud pumps are normally equipped with the following items: 1) various filter and/or magnet assemblies to capture contamination, 2) dipsticks or sight glasses to check oil levels, 3) a pressurized flow or splash-gravity flow lubrication system for distributing the lubricant to various components, and 4) various sealing wiper arrangements on the crosshead extension rod to prevent drilling fluids from entering the power end. All mud pumps are equipped with bearings, crossheads and gears (chains and sprockets in some instances) that must

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PM–16

PUMPS

be continually supplied with the correct type and quantity of lubricant. Usually a high grade, extreme-pressure (EP) gear oil is recommended by most manufacturers. These gear oils must be capable of maintaining sufficient lubricant on all bearing surfaces and gear teeth under varying operating speeds and loading conditions. Failure to do so can lead to rapid wear and ultimate destruction of bearings, gears and crossheads.

the gear oil be changed every six months, or as frequently as required to maintain a relatively clean, sludge-free oil. It is important to clean any debris from the oil sump during an oil change. Magnet assemblies for capturing metallic debris should also be cleaned during an oil change. Oil filters should be replaced (or cleaned if applicable) during an oil change. Filter cartridges, strainers and magnets should be cleaned or changed at every routine power end oil change.

Pump manufacturers have thoroughly analyzed the operational speeds, loads and temperatures of their pumps and have specified lubricant viscosity grades and additive recommendations that should adequately protect against component wear and corrosion. Lubricant recommendations are usually based upon temperature of the lubricant itself within the pump. Rather than recommend particular brands of lubricant for the pump, many pump manufacturers prefer to simply state the viscosity grade requirements for various temperature ranges. (Refer to pump manufacturer’s specific lubricant recommendations.) The drilling contractor is then at liberty to contact his local or preferred bulk lubricant distributor and arrange for them to furnish a lubricant that complies with the pump manufacturer’s recommendations. There has also been an increase in the use of synthetic oil, synthetic oil blends and biodegradable lubricants. Such lubricants should be selected cautiously with input from the mud pump manufacturer.

Many high-pressure pumps include a settling chamber under the crosshead area of the pump, on each side of the pump frame. This settling area can allow mud, water, dirt and other oil contaminants to be removed before returning to the main oil reservoir in the gear end of the pump. It is a good practice to check for accumulation of contaminants weekly by removing the pipe plug. If it is necessary to clean out the settling chamber(s), the covers on each side can be removed and the entire settling chamber drained.

Contamination of the gear oil in the power end of a mud pump is an inevitable by-product of mud pump operation. Metallic particles may be worn off the working surfaces of the gears, bearings and crossheads. Dust and other debris may enter the power end through the air breather or through worn crosshead extension rod wipers or during maintenance. Water may also enter the power end through damaged or worn crosshead extension rod wipers, or it may condense as a result of temperature changes within the power end. Oil may be oxidized due to high operating temperatures and chemical reactions of the oil with oxygen in the air. Dust, dirt and metallic particles in the gear oil can attach to moving components with an abrasive, lapping action that can quickly lead to excessive clearance in bearings and scoring of the gears and crossheads. Water in the power end quickly mixes with the gear oil as the mud pump operates and imparts a cloudy or milky appearance to the oil. This condition frequently causes rusting and corrosion of bearing surfaces and accelerated wear on load-carrying members due to thinning and breakdown of the lubricant’s film thickness. Oxidation causes darkening of the gear oil color and leads to sludge formation in the sump and oil troughs. To protect against the detrimental effects of gear oil contamination, most mud pump manufacturers recommend

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Maintaining a clean, quality lubricant in the power end of the mud pump is the best insurance available for reliable, longlife service from slush pump power ends. Oil samples can also be pulled and sent to a laboratory for analysis to ensure lubricant is suitable for continued use. Oil samples can also assist in identifying sources of contamination. The gear oil dipstick or sight-glass is a very simple instrument attached to the power end reservoir, yet it is probably the most important maintenance tool provided to the slush pump mechanic. The dipstick or sight-glass not only permits checking of the lubricant level in the pump, but frequently assists the mechanic in monitoring contamination buildup in the gear oil. Failure to maintain the proper oil level within the power end can result in marginal lubrication of moving components, pump overheating and rapid wear of components. The lubricant level in the power end reservoir should be checked at least once a day with the pump shut down. It is usually best to wait several minutes after shutting a pump down before checking the lubricant level. This allows the lubricant level to stabilize in the reservoir and permit accurate readings.

Centrifugal pumps

Lubrication of the coupling should follow OEM recommendations. The electric motor should be lubricated per OEM recommendations. Avoid over-lubricating the motor. Oil levels in oil-lubricated pumps that are too high or too low can cause bearing overheating. The oil level should be checked periodically to maintain the proper level. The oil reservoir should be drained each quarter and refilled with the OEM-recommended type and grade of oil. Designs for checking oil level include dipsticks and oil-level gauges.

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PUMPS Most packing failures are a result of over-tightening or improper installation. The packing on a centrifugal pump must leak slowly to keep the packing lubricated. Too tight a packing, and the packing burns up due to lack of lubrication and cooling. At first startup, the nuts on the packing gland should be loosened to allow a steady flow of liquid. Then, the gland nuts should be tightened to establish a steady dripping. Packing requires readjustment when liquid leakage increases. Some stuffing boxes are grease-lubricated and should be lubricated at least once per day. Installation of an automated lubricating system can help keep the packing lubricated automatically. Mechanical seals require lubrication from the fluid being pumped. Centrifugal pumps with mechanical seals should not be operated dry. Grease-lubricated pumps should be greased at the OEM-recommended frequency and amounts using the OEM-recommended types of grease.

Proper storage considerations Mud pumps

When mud pumps are put into storage or rigs are idle during long periods of time, certain precautions must be taken to prevent corrosive deterioration of mud pump components. The cost of the precautionary measures is usually small compared to the loss of drilling time and expenses involved in reconditioning and replacing corrosion-damaged bearings, seals, piston rods and fluid cylinder components. The power end sump and settling chamber should first be drained and thoroughly cleaned. A rust-inhibiting oil should be sprayed on all bearings, finished surfaces and the entire inside surface of the power end. To provide air circulation and prevent condensation buildup, the drain plug may be removed and a wire mesh screen (for rodent exclusion) secured over the opening.

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On pumps equipped with pressurized, forced-flow lubrication systems, clean gear oil should be induced into the oil-circulating pump, filter housing, heat exchanger, etc. If the exterior paint on the pump has begun to deteriorate or is extensively chipped, a quality paint (coating) should be applied. For maximum frame protection against rusting, all painting operations should be preceded by the necessary sanding and surface preparations. To provide corrosion protection for the fluid end of the pump, the valves, valve seats, piston rods and liners should be removed from the fluid cylinders and all components thoroughly cleaned and dried. Coat the cylinder bores, all valve cover and cylinder-head components, and the reusable expendable parts with a rust preventative or grease. Corrosion problems can occur over long periods of time if piston rods, liners and modules are not removed from the pump before storage. The triplex pump’s liner spray system must also be protected against corrosion while in storage. All water, sand and debris should be flushed from the liner spray pump; coolant reservoir; and associated hose spray nozzles and tubes. Spray all components with a rust-inhibiting oil and fill the liner spray pump housing with oil. While in storage, the pump should be thoroughly inspected at least once each month and re coated, where necessary, with a rust-inhibiting oil. Always rotate the pump gears during each inspection. This procedure permits redistribution of the rust-inhibiting oil over the surfaces of the bearings.

Centrifugal pumps

Centrifugal pumps should be stored in a clean and dry environment. If stored outdoors, the openings should be sealed to prevent water intrusion, which can cause corrosion and rust. The pump and motor should be turned periodically. When returning the pump to service after long-term storage, the grease in the pump bearings and motor should be removed and replenished with new grease.

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Mud Pumps 1)

PUMPS

ADVANCED THEORY & IMPORTANT CALCULATIONS

HHP = GPM X P / 1,714

Where: HHP = hydraulic (output) horsepower (hp) GPM = flow rate (U.S. gal/min) P = pressure (psi) 2)

HHP (for triplex pump) = AP X S X SPM X P / 132,000

Where: HHP (for triplex pump) = hydraulic (output) horsepower (hp) AP = area of piston (sq in.) S = stroke length (in.) PM = strokes (or revolutions) per min P = pressure (psi) 3)

HHP (for duplex pump) = [( 2 X AP ) - Ar ] X S X SPM X P / 198,000

Where: HHP (for duplex pump) = hydraulic (output) horsepower (hp) AP = area of piston (sq in.) Ar = area of rod cross-section (sq in.) S = stroke length (in.) SPM = strokes (or revolutions) per min P = pressure (psi) 4)



AP = area of piston (sq in.) Ar = area of rod cross-section (sq in.) S = stroke length of each piston (in.)

7)

GPM = SPM X VPS

Where: GPM = flow rate (U.S. gal/min) SPM = strokes (or revolutions) per min VPS = volume per stroke from all available pistons (gal/stroke) 8)

Where: GPM (for triplex pump) = flow rate (U.S. gal/min) AP = area of piston (sq in.) S = stroke length (in.) SPM = strokes (or revolutions) per min 9)

GPM (for duplex pump) = [( 2 X AP ) - Ar ] X S X SPM / 115.5

Where: GPM (for duplex pump) = flow rate (U.S. gal/min) AP = area of piston (sq in.) Ar = area of rod cross-section (sq in.) S = stroke length (in.) SPM = strokes (or revolutions) per min 10)

IHP * = HHP / 0.90

GPM (for triplex pump) = AP X S X SPM / 77

AP = pi X Dp X Dp / 4



* Based on 90% mechanical efficiency and 100% volumetric efficiency

Where: AP = area of piston (sq in.) Pi = Mathematical constant that is the ratio of a circle’s circumference to its diameter (approx. = 3.14159265) Dp = diameter of fluid piston (in.)

5)

VPS (for triplex pump) = AP X S / 77

11)

Where: IHP = input horsepower (hp) HHP = hydraulic (output) horsepower (hp)

Where: VPS (for triplex pump) = volume per stroke (gal) AP = area of piston (sq in.) S = stroke length of each piston (in.)

6)

Ar (For Duplex Pump) = pi X Dr X Dr / 4

Where: Ar = area of rod cross-section (sq in.) Pi = Mathematical constant that is the ratio of a circle’s circumference to its diameter (approx. = 3.14159265) Dr = diameter of piston rod (in.)

VPS (for duplex pump) = [( 2 X AP ) - Ar ] X S / 115.5

Where: VPS (for duplex pump) = volume per stroke (gal)

IADC Drilling Manual

Centrifugal pumps 1)

Head = P X 2.31 / Sp. Gr.

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PUMPS

Where: Head = head in ft P = pressure at discharge point (psi) Sp. Gr. = specific gravity 2)

Sp. Gr. = PPG / 8.34

3)

F=PXA

Where: F = force (lb) P = pressure (psi) A = area (sq in.)

Where: Sp. Gr. = specific gravity Note: Specific gravity of water = 1.0 PPG = weight of fluid (lb/gal)

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PM–19

PM–20

PUMPS

GLOSSARY Casing: See the preferred term “Housing.” Cavitation: The localized formation of cavities (or bubbles) in a liquid that induce vibration and noise in a pump. Cavitation can cause centrifugal pump damage or failure.

Lift (in pumping): The vertical height the fluid is raised from the free height of suction fluid going to the pump to free height of outlet fluid or open end discharge Multiplex: A pump with four or more cylinders.

Centrifugal pump: A device for moving fluid by spinning the fluid with a revolving device (rotating impeller) in a casing with a central inlet and tangential outlet.

Net-positive suction head (NPSH): What a centrifugal pump needs from the suction piping at a minimum to prevent cavitation.

Double-acting: A pump that has pistons accomplishing work in both directions.

Quadraplex: A pump with four cylinders. Quintuplex: A pump with five cylinders.

Duplex pump: A pump with two cylinders. Normally a double-acting pump. Flow rate: The amount of volume that is displaced per unit of time. Head: The height in ft of a column of water measured above a point in a pipe or at a pump.

Reciprocating pump: A pump that uses a piston and/or plunger in a cylinder. Simplex: A pump with one cylinder. Slush pump: A mud pump (slang). Triplex pump: A pump with three cylinders.

Housing (as applies to centrifugal pump): The outer housing that surrounds the impeller on a centrifugal pump.

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PUMPS

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REFERENCES: EVALUATION, TESTING, INPSECTION Mud pumps

American Petroleum Institute (API) Specification 7K, Drilling and Well Servicing Equipment, current edition, covers piston mud pump components. Note: API 7K does not currently cover high-pressure mud pump assemblies. ISO 14693, Petroleum and natural gas industries - Drilling and well-servicing equipment, current edition, covers piston mud-pump components.

Centrifugal pumps

American Petroleum Institute (API) Standard 610, Centrifugal Pumps for Petroleum, Petrochemical and Natural Gas Industries, current edition, covers centrifugal pumps. ISO 5198, Centrifugal, mixed flow and axial pumps - Code for hydraulic performance tests - Precision class, current edition. ISO 5199, Technical specifications for centrifugal pumps Class II, current edition.

ISO 9905, Technical specifications for centrifugal pumps Class I, current edition. ISO 9908, Technical specifications for centrifugal pumps — Class III, current edition. ISO 13709, Centrifugal pumps for petroleum, petrochemical and natural gas industries, current edition. ISO 21049, Pumps - Shaft sealing systems for centrifugal and rotary pumps, current edition. American Institute of Chemical Engineering (AIChE) E-31, Centrifugal Pumps (Newtonian Liquids): A Guide to Performance Evaluation - Third Edition, current edition. ASME International (ASME) PTC 8.2, Centrifugal Pumps, current edition. Bureau of Indian Standards (BIS) IS 15657, Centrifugal pumps for petroleum, petrochemical and natural gas industries, current edition

ADDITIONAL REFERENCES Drilling Fluids Processing Handbook, ASME Shale Shaker Committee, Nov 2004

Mud pumps

Drilling Fluids Mud Pumps and Conditioning, Unit 1, Lesson 7 (Rotary Drilling Series), Kate Van Dyke, Petroleum Extension Service (Petex), March 1998 Mud Pump Handbook, S. L. Collier, Gulf Publishing Co, February 1983

Centrifugal pumps

Know and Understand Centrifugal Pumps, L. Bachus and A. Custodio, Elsevier Science, August 2003 Shale Shaker and Drilling Fluids Systems: Techniques and Technology for Improving Solids Control Management, American Assoc. of Drilling Engineers (Author), Gulf Professional Publishing, July 1999

Centrifugal Pumps: Design and Application, Second Edition, Val S. Lobanoff and Robert R. Ross, Gulf Professional Publishing, June 1992

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ROTATING AND PIPEHANDLING EQUIPMENT

IADC Drilling Manual 12th Edition IADC Drilling Manual • Copyright © 2015

Born in the U.S.A. TM

Since 1928, well servicing and drilling operations have been counting on quality American made Cavins tools and replacement parts to keep them up and running safely and dependably. Cavins tools and replacement parts are made in accordance with our original manufacturer designs, to original tolerances from materials selected and treated for optimum performance in each application. The result is longer life, trouble-free operation and minimal maintenance. Today, downtime is more costly than ever, so why take chances with counterfeit imitations manufactured to looser tolerances from inferior,

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often improperly treated materials? Count on Cavins for tools that are safer and built better so they always work dependably from the start, last longer in the field and require less maintenance. Call or visit our website today for our comprehensive catalog and your nearest Cavins distributor. Or Email us at [email protected] (562) 424.8564  Fax (562) 595.6174 www.cavins.com  email: [email protected]

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Spiders  Slips  Sand Pumps  Bailers  Cement Dumps  Blowout Preventers  Hose Connections  Bent Orienting Subs  Depthometers  Oil Savers  Junk Snatchers  Safety Clamps  Sucker Rods  Tubing Elevators  Power Tongs  Cement Dumps  Blowout Preventers and Rod Strippers  Rod and Crane Hooks  Elevator Links and Hooks Baash-Ross, Foster, Hillman-Kelly, KelCo and Web Wilson are licensed trademarks of National Oilwell Varco, LLC.

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ROTATING & PIPEHANDLING EQUIPMENT

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CHAPTER

RP

ROTATING AND PIPEHANDLING EQUIPMENT

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. CONTRIBUTORS Faisal Yousef, Canrig Drilling Technology Ltd. Richard Ackerman, Schramm Inc. Steven Ancelet, Loadmaster Derrick & Equipment, Inc. Troy Baronet, Canrig Drilling Technology Ltd. Travis Burns, American Block Company Eric Deutsch, Canrig Drilling Technology Ltd. Robert Dugal, Forum Energy Technologies Norman Dyer, D Cubed Services, Consultant for DNV Robert Goodwin, National Oilwell Varco Joel Heinen, National Oilwell Varco Kenneth Kondo, National Oilwell Varco

Anthony Mannering, TM Engineering, PLLC Nick Mawford, Tesco Corporation Drew McPhail, Tesco Corporation Paul Meade-Clift, PMC Technical Services Ltd. Randy Pyrch, Canrig Drilling Technology Ltd. Andrew Roskey, American Block Company Sumit Shah, American Block Company Casimir Sulima, Canrig Drilling Technology Ltd. Kurt Vandervort, Stress Engineering Services Leandro Oviedo, Weatherford

REVIEWERS Peter Cui, Schramm Inc. Beat Kuttel, Canrig Drilling Technology Ltd. Miles Gilbert-Morgan, Parker Hannifin Corporation

Larry Foley, Foley Engineering Tommy Scarborough, Canrig Drilling Technology Ltd.

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WELL CONTROL EQUIPMENT & PROCEDURES

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9915095-9-1

Printed in the United States of America.

IADC Drilling Manual

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ROTATING & PIPEHANDLING EQUIPMENT Contents CHAPTER RP

ROTATING & PIPEHANDLING EQUIPMENT

Introduction...................................................................... RP-1 Hoisting and running in......................................RP-1 Pipehandling.............................................................RP-2 Make up/break out................................................RP-2 Racking......................................................................RP-2 Auto-handling..........................................................RP-2 Tubulars.......................................................................RP-3 Hoisting Equipment....................................................... RP-3 Drawworks.................................................................RP-3 Hydraulic cylinders................................................ RP-6 Slips........................................................................... RP-9 Elevators..................................................................RP-13 Elevator links (bails).............................................RP-16 Crown block, hook and sheaves........................RP-17 Drill line...................................................................RP-18 Structures...............................................................RP-18 Rotary swivel.........................................................RP-20 Deadline anchor....................................................RP-21 Rotary Equipment........................................................ RP-23

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Contents Top drive................................................................. RP-23 Rotary table...........................................................RP-28 Pipehandling equipment............................................ RP-33 Casing running tools (CRTs)............................. RP-33 Power catwalk.......................................................RP-36 In-derrick handling systems..............................RP-38 Manual tong......................................................... RP-40 Pipe arm................................................................. RP-41 Power tongs...........................................................RP-42 Instrumentation........................................................... RP-44 Weight indicator................................................. RP-44 Pressure gauge.....................................................RP-45 Torque (top drive)................................................RP-45 Other common instrumentation.................... RP-46 Maintenance and inspection....................................RP-47 API standards and recommended practices.RP-47 Inspection frequency............................................RP-48 Maintenance...........................................................RP-48 Reference...................................................................... RP-49

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THE IADC LEXICON

D E F I N I N G T H E D R I L L I N G S PAC E ! IADC Lexicon puts critical definitions at your fingertips. Imagine thousands of the most pertinent definitions and terms relevant to drilling, all in a single convenient repository – the IADC Lexicon. The IADC Lexicon draws from the most critical legislation, regulations, standards and guidelines worldwide. The European Union requested that IADC, as the authority in the drilling space, create the Lexicon to aid in regulation and understanding our industry. Use the IADC Lexicon as a dictionary or to quickly and easily identify a relevant standard, guideline or regulation. Or, use it as a template to develop instructions for your own company.

www.iadclexicon.org

ROTATING & PIPEHANDLING EQUIPMENT

Introduction

The ability to move tools into the borehole and selectively withdraw them is central to the drilling process. Whether a particular depth objective can be reached or the required casing can be installed depends on hole conditions and the equipment being used.

Hoisting and running in

The ability to move tubulars and tools in and out of the hole requires equipment with sufficient capacity to overcome the loads imposed by the work being done. Generally the highest loads will be experienced when pulling the drilling assembly out at total depth or when running casing. Significant hoisting loads include the mass of the traveling equipment and anything suspended from the traveling equipment. Some examples include: •• Traveling blocks and line; •• Swivel or top drive; •• Casing running tools (CRT); ••Drillstring; •• Casing string; •• Riser string. Significant braking loads include the mass of traveling equipment and anything suspended from the traveling equipment, as well as rotating inertia. Some examples of rotating Inertia include: ••Drum; ••Flanges; •• Gear train; •• Motors, etc. In addition, when considering total loads, one must include system friction: •• Gear or chain losses; •• Bearing loss; •• Drilling line reeving efficiency; •• Resistance caused by friction between the drilling assembly and the wall of the hole. System capacity can be addressed through three elements: hoisting power, braking capacity (stopping) and component strength. Hoisting power is the ability to move a load at a particular speed. Braking capacity is the ability to stop a moving load, while component strength is the ability to withstand a load without failure. To differentiate between power and component strength, consider the example of a train pulling a line of cars. If an ‘engine’ with several thousand horsepower is attached to the cars with the steel couplers, the cars will move forward with the train. However, if the cars are attached to the same engine with soft line (fiber rope), it is quite likely that the soft line will part and the load will not move. So, even with sufficient power and traction, failure of an element in the system

IADC Drilling Manual

RP-1

can prevent task completion and potentially cause damage or injury. Conversely, attaching the cars with steel couplers to an engine with insufficient horsepower will not cause a failure, but the train will not move. In the case of a drilling rig, the system may be thought of as a chain, as there are many elements working together to hold the load. Further, if any one link lacks sufficient strength, the entire system will fail. In a conventional drilling rig, the system comprises: •• Drawworks structure; •• Drilling line; •• Crown block; •• Travelling block; ••Hook; •• Swivel or top drive; ••Tubulars; ••Mast; ••Substructure. Each element has a strength limitation, the load at which failure will occur. Under certain circumstances, the drawworks capacity and loads imposed by the drilling or casing operation may exceed the strength of a system component. The well planning process should include an examination of the expected loads, and provide for appropriate components to withstand expected loads. In addition, it is good practice for the drilling contractor (owner/operator of the equipment) to provide an easy reference chart detailing the maximum loads (pull) allowed for each component. The maximum pull should represent the physical limit of the component, reduced by some safety factor. The safety factor provides a margin for unknowns such as equipment wear, instrumentation inaccuracy, or sudden loads etc. The initial planning process should account for the known loads, such as planned tubulars at the expected total depth, but also estimate hole drag. Once drilling has begun, the driller, who is operating the equipment, must be aware of the lowest capacity element in the chain, and ensure that loads do not exceed that capacity. The driller primarily relies on the weight indicator to show the load on the system and must continually compare the actual load with the maximum allowed. Power available to the system determines whether the load can be moved and how fast. In a conventional drawworks rig, the drum rotates and reels in the drilling line to move the blocks. The power at the drum can be supplied by an electric motor, an internal combustion engine or hydraulics. However, in all cases internal friction in the drawworks and drive reduces available power. The available power at the hook is further reduced by losses in the cable reeving through the crown and traveling block. The load or weight on the blocks is a function of the single line pull (drawworks capability)

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RP-2

ROTATING & PIPEHANDLING EQUIPMENT

multiplied by the friction-adjusted mechanical advantage provided by the block and tackle system.

imum joint diameter in the fingers are usually calculated at the outset.

Pipehandling

Rig design limits pipe racking in the derrick in two ways. Space limitations on the rig floor are one consideration. The load (weight) limitation of the rig floor, which is supported by the substructure, is the second consideration. The load limitation for the racking area may be affected by loads carried in the rotary table, depending on the design. This information is available from the manufacturer’s rating. When the load rating of the rig floor is known, the number of joints or length of pipe that are safe to rack on the floor can be calculated by dividing the load rating by the linear mass of the tubulars or the weight per joint. The number of joints cannot exceed the physical space available for the pipe to stand or the manufacturer’s load rating.

The majority of drilling is performed with jointed pipe; that is, the pipe is provided in fixed lengths that must be connected together to allow drilling to proceed. Pipehandling is the process whereby the tubulars are moved from the storage racks to the drilling floor and then in and out of the hole. Handling pipe is one of the main causes of personnel injury at the rig site. Pipehandling includes moving and connecting tubulars for drilling; moving, disconnecting and reconnecting for bit trips; and moving, disconnecting and returning the tubulars to the storage racks.

Make up and break out

Jointed pipe typically used for drilling has male (“pin”) and female (“box”) threads that are screwed together to provide a mechanical connection to transmit the drilling torque and tension. This connection also provides a pressure tight path for the flow of drilling fluid. In order to make up or break out pipe, tools are required that have the appropriate size and strength to spin the threads together and achieve the torque required to create the connection. When connecting or disconnecting the pipe, the string must be suspended above and below the connection. The rotary table or bowl, which is supported by the substructure, suspends the lower part of the drillstring with slips gripping the pipe. Each of these components has load rating, and size that must be appropriate for the load and size of tool to be handled. The swivel, top drive or elevators will support the upper part of the connection to make up or break out. The final requirement to make and break a connection is a tool, or tools, which can apply torque to the joint and rotate the connection free. They must be chosen to match the size of tubular being handled, and have sufficient strength to withstand the torque required to complete the connection.

Racking

When it is necessary to replace the bit or modify drilling components, the drillstring must be pulled from the hole and stored, allowing the bit or bottomhole assembly to be changed. The pipe may be laid down or stood back in the mast (racked). Racking can be conducted by vertically raising one joint (singles), or multiple joints connected together (doubles or triples), reducing the number of connections required. The racked joints are stored between “fingers” that hold the pipe in place. The number of joints to be stood together (whether singles, doubles or triples) and the max-

IADC Drilling Manual

This calculation should be performed as part of the rig selection process to ensure that total depth can be reached safely with the planned tubulars. Pipe is often racked on the floor while casing is being run, so the combined load must be compared to the manufacturer’s allowable loads.

Auto-handling

Pipehandling is one of the most hazardous operations performed while drilling and completing a well. Even though the drawworks, assisted by other power devices, performs the hoisting, pipehandling is a physically demanding activity. Consequently, manufacturers offer devices to automate or mechanize some or all pipe-handling functions. When moving from well to well, the pipe is commonly transported on flatbed trucks, then loaded onto simple storage racks (pipe racks). Alternatively, pipe may be stored for transportation in ‘tubs’, or steel frame boxes, which constrain the pipe and make lifting and transportation easier. The tubs may be simple boxes which require some external method to lift the pipe out of the box, or it might have a builtin hydraulic system which moves one row of pipe up to the level of the catwalk on command. The pipe is then rolled to the catwalk where traditionally, a worker will attach a sling and cable winch to the joint to pull it up the catwalk and onto the floor. Presently, two mechanized systems exist to move the pipe from the catwalk to the floor. The pipe arm system is equipped with grippers that clamp onto the pipe so that as the pipe arm pivots up to the floor, the joint of pipe is carried with it. To allow drilling in the conventional ‘pin-down’ orientation, the pipe must be rolled onto the pipe-arm grippers with the pin pointing to the V-door. (The V-door is an opening at floor level in a side of a derrick or mast. It is typically opposite the drawworks and is used as an entry to bring in tubulars onto the rig floor).

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ROTATING & PIPEHANDLING EQUIPMENT Pipe arm systems currently work in ‘single’ mode; that is, only one joint is moved to the floor at one time. As well, pipe-arm equipped rigs generally do not rack pipe on the floor, but lay the pipe down during each trip. The second and most common mechanized method for moving pipe to the floor is the powered catwalk. These systems employ a moving carriage, which pushes the pipe up the V-door and delivers the box end to the floor, where it can be picked up with the elevators. Rotating the connections together and making up to recommended torque has been mechanized in some form from the development of rotary drilling. Originally the pipe would be rotated together with the aid of a spinning chain, then made up with the cathead-powered tongs (“manual tongs”). The addition of a permanently mounted “kelly spinner” and the use of cable-suspended pipe spinners improved safety statistics dramatically. Manufacturers moved the process forward by combining the pipe-spinning function with a mechanized wrench capable of making up connections to required torque specification. With this method, the spinning chain and the heavy and awkward manual tongs were replaced. Racking pipe involves: •• Disconnecting pipe to be racked from the pipe in the hole by floor hands; •• Drawworks operated by the driller; •• Manually moving pipe to the racking position by the derrickman and floor hands in concert. Although this process has been refined over time, and with experienced crews has become extraordinarily efficient and rapid, it is physically demanding and prone to incident. The development of fully automated pipe racking for land rigs has been delayed by space and budget limitations. These limitations are generally overcome on larger floating rigs. Two available systems can replace the derrickman function. The first is a complete system capable of picking up a stand after it is disconnected and placing it in the racking position without human effort. The second requires the stand’s pin end placed into the racking position conventionally, i.e., with floor hands and drawworks, but pivots the stand into the racking system.

top-drive system is used. The rotating table engages a kelly bushing through which a hexagonal or square Kelly bar is fitted. The Kelly bar makes up to the drillstring. When the table is rotated, the string rotates with it. The primary rotary table capacity is the weight of the string that can be supported in the slips while rotating or static. However, as torque is being transmitted through the table to the pipe while drilling, available horsepower and drive capacity limit rotating power. The rotary table has a significant limitation: it is not possible to rotate (forward or backwards) and also hoist the pipe. This limitation becomes particularly problematic in difficult hole conditions, and led to the development of top-drive systems, which can drive the string from the top. Top-drive capacity comprises (maximum string load, rotating torque, and internal pressure capacity. Because the top drive is capable of rotating the string in both directions while hoisting, it is necessary to evaluate the combined stress capacity of the tubulars (simultaneous tension and torsion), as well as limit activities to some fraction of the connection make-up torque to ensure the pipe does not unintentionally separate downhole.

Hoisting Equipment Drawworks

The drawworks is the primary hoisting machine on the drilling rig used to lower and raise the drill or casing strings. The drawworks converts the power source into a hoisting operation and provides braking capacity to stop and sustain the weights imposed when raising or lowering the drillstring. The drawworks is a machine with a power source, power transfer and speed reduction, large diameter drum, brakes and associated auxiliary devices. The drawworks is typically driven by DC or AC motors or diesel/gas engines that are coupled to the power transfer and speed reduction system.

Tubulars

Current drilling technology utilizes various types of rotary bits. (See separate chapter in the 12th edition of the IADC Drilling Manual on Bits.) The bit can be rotated by a surface device, a subsurface device (downhole motor or rotary seerable system), or a combination. (Downhole motors and RSS are discussed in the chapters on Downhole Tools and Directional Drilling.)

Figure RP-1: Typical drawworks. Courtesy Canrig.

To rotate the bit from the surface, either a rotating table or a

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RP-4

ROTATING & PIPEHANDLING EQUIPMENT

Figure RP-2: The drum shown here is smooth. However, drums can be grooved to allow the reeling of the drilling line. It converts the motor torque into the line pull required for hoisting, lowering and stopping the drilling tools. Courtesy Canrig.

Video RP-1: Animation shows various drawworks components. Courtesy Canrig.

Major components »» Drum

Figure RP-3: Power transmission is accomplished by roller chain or gear drives. Courtesy Canrig.

The drum is grooved to allow the reeling of the drilling line. It converts the motor torque into the single-line pull required for hoisting, lowering and stopping the drilling load. For drawworks with band brakes, the drum will have brake rims on each side where the brake bands are mounted. For drawworks with disk brakes, the drum is equipped with a brake disc on one or both sides of the drum where the brake calipers are mounted or by a group of discs at the end of the drum shaft. The drum shaft is supported by pedestals on each side, by a gear box and a pedestal, or by a support frame. Regardless of design, the drum shaft must be supported on both sides.

»» Power transmission

Power transmission is accomplished by roller chain or gear drives. All drives are arranged (enclosed) in oil tight housings. Roller chain drives consist of various shafts, sprockets, roller chain and clutches arranged for 2 to 8 output speeds. Gear drives consist of shafts, input, idler and output gears and in some cases a planetary gear assembly. Different designs provide one output speed or include clutches and provide two or three output speeds. The power transmission mounts to the drum shaft on one end and the other end is coupled to the power source such as an AC motor. Depending on the design, the power transmission may have several input shafts. Each coupled to a motor or engine.

»» Power source

Figure RP-4: The drawworks is typically driven by electric motors or diesel engines. Electric motors are directly coupled to the input shaft or shafts in the power transmission. Courtesy Canrig.

IADC Drilling Manual

The drawworks is typically driven by electric motors or diesel engines. Electric motors are directly coupled to the input shaft or shafts of the power transmission. A fluid coupling, such as a torque converter, is usually placed between an engine and the power transmission input shaft. The capacity of the power source determines performance, hoisting speed for any particular load, and in some cases the maximum load capability of the drawworks.

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ROTATING & PIPEHANDLING EQUIPMENT

RP-5

as the fast line. The drawworks reels the fast line in and out in a controlled fashion. The drilling line extends to the crown block and traveling assembly, creating a block and tackle arrangement. The fast line is reeled over the crown block and traveling block to gain mechanical advantage in the block and tackle. Reeling in the drilling line, or load raising, is powered by the power source, while reeling out, or load lowering, by gravity. The drilling line exits the last sheave on the crown block and extends downward toward the rig floor. This portion of the drilling line is called the dead line. The dead line is fastened to a mast/derrick leg or to the rig floor by the deadline anchor. In many cases the line leads from the deadline anchor to a storage spool for extra drilling line.

Capacity & Limitation

Drawworks capacity is one of the factors used to determine the rig’s depth rating, the depth of well that can be economically drilled and serviced. Drawworks are used on most onshore & offshore drilling and workover/service rigs. Offshore drilling rigs mounted on a floating vessel may include an active heave compensating feature. Drawworks in floating offshore operations require significant powerto accomplish the application. Figure RP-5: The drawworks is designed with a primary brake, an emergency brake and, in some cases, an auxiliary brake. Courtesy Canrig.

»» Brakes

The drawworks is designed with a primary brake, an emergency brake and, in some cases, an auxiliary brake. The primary brake is used to retard or stop motion or maintain the main drum in a fixed position during normal operating conditions. Disc or band brakes are used as primary brakes on drawworks with DC motors or diesel engines. The AC motors on AC drawworks may be used as the primary brake s in the regenerative state. The emergency brake is used to stop and maintain the drum in a fixed position in the event that the primary brake is not capable. The emergency brake may be used as a parking brake when no motion is required. Disk or band brakes may be used as emergency and parking brakes. The auxiliary brake is an ancillary brake used to assist the primary brake in absorbing the energy released as heavy loads are lowered. The auxiliary brake may use discs or eddy-current rotors to convert to heat the kinetic energy of a downward-moving load being stopped. Disk brakes are always power operated. Band brakes may have a power assist. Power may be supplied as hydraulic or air power.

Function & Operation

The primary function of a drawworks is to transform rotary power into hoisting ability and to provide braking capacity to stop and sustain the weights imposed when lowering and raising the drillstring. The portion of the drill line that extends from the drawworks to the crown block is referred to

IADC Drilling Manual

Drawworks can be rated by any of three metrics: by installed horsepower, fastline pull or traveling-block pull for a given number of lines to the block. The capacity of onshore mobile workover/service rigs ranges from 250-1,000 hp. For onshore drilling, capacities range from 750-4,000 hp. For offshore drilling, capacities range from 3,000-13,000 hp, with active heave drawworks occupying the upper portions of the range. (Discussion of capacities in terms of fastline or traveling-block pull is beyond the scope of this chapter.)

Inspection & Maintenance

The user/owner of the equipment and the manufacturer should jointly develop inspection, maintenance, repair and remanufacture procedures consistent with equipment application, loading, work environment, usage and operational conditions and update the procedures as changes are indicated due to new technology, product improvements and changes in original conditions. If the original manufacturer is not available, the owner/user should develop procedures consistent with accepted industry practices. Inspection criteria should be based on safety, time intervals, wear limits, relative load size and cycle count, external and/or internal damage, experience and regulatory requirements. Operating personnel should be trained to assess the condition of equipment prior to use and during usage. Qualified personnel should be used for more detailed inspection at extended intervals and to perform maintenance and repair as required.

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RP-6

ROTATING & PIPEHANDLING EQUIPMENT

Out stroke Pushes

Piston-bearing rings

Sealing washer

Piston seals

Rod Barrel

Piston seal

Rod bearing

Rod seal

Rod seals

O ring

Wiper ring

In stroke Pulls

Figure RP-6: Cylinder stroke. Top: Fluid (in red) flows into the bottom end of the cylinder, extending the rod at the opposite end. Bottom: During in stroke, fluid enters the rod end, causing the rod to retract. Courtesy Schramm Inc.

Hydraulic cylinders used as hoisting equipment

A hydraulic cylinder converts hydrostatic oil/fluid flow and pressure into linear force and motion. As shown in the top view ("out stroke") of Figure RP-6, fluid (shown red) flows into the bottom, butt or cap end of the cylinder, extending the rod at the opposite end of the cylinder. Upon in stroke (bottom) fluid flows into the rod end of the cylinder, causing the rod to retract. If both ends of the cylinder are connected to the hydraulic power source the cylinder is double acting (produces force in both directions). If only one end is connected to the power source the cylinder is single acting. The speed of rod movement is dependent on the flow rate of the fluid and the active piston face area. The force exerted by the rod is dependent on the pressure of the fluid and the active piston face area. The cylinder cap and gland are attached to opposite ends of the cylinder barrel. One or both parts are removable. The cap and gland each contain a connection into the chamber on that end of the cylinder. The piston is attached to the rod and slides inside the cylinder barrel as the rod extends or retracts. Seals are provided at each joint to prevent fluid leakage. Bearing rings are provided on the sliding surfaces to reduce friction and provide a replaceable wearing surface. A wiper ring in the gland removes most of the dirt on the rod as it enters the cylinder. The piston divides the inside of the cylinder into two chambers, the bottom chamber (cap end) and the piston rod side

IADC Drilling Manual

Figure RP-7: Cylinder components. Courtesy Schramm Inc.

chamber (rod end/head end). When fluid enters from cap end during extension stroke, and if the oil pressure in the rod end/head end is approximately zero, the force F on the piston rod equals the pressure P in the cylinder times the piston area A: Force = Fluid Pressure x Piston Area During the retraction stroke, oil is pumped into the head (or gland) at the rod end. The oil from the cap end flows back to the reservoir. Since the rod occupies a part of the piston area the extend force produced by any pressure will be greater than the retract force for that pressure. The fluid pressure in the rod end is (pull force) / (piston area - piston rod area):

P=

Fp Ap – Ar

Where P is the fluid pressure, Fp is the pulling force, Ap is the piston face area and Ar is the rod cross-section area. The cylinder just described is a single-stage cylinder. A multiple-stage cylinder may be used when the operating conditions dictate. The multiple stage cylinder adds one or more additional cylinder barrels of greater diameter outside the first cylinder barrel creating a telescopic effect. This creates

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ROTATING & PIPEHANDLING EQUIPMENT

RP-7

Hoist cylinder

Figure RP-8: Cylinders on a land rig. Courtesy Schramm Inc.

Figure RP-10: Cylinders on a land rig. Courtesy Schramm Inc.

readily variable pressure and volume control, which the cylinder converts to force and position. Cylinders have many applications on mobile heavy equipment. It is common to see hydraulic cylinders on oil/gas drilling rigs as shown in Figures RP-8 and RP-9.

Figure RP-9: Outrigger cylinders on a land rig. Courtesy Schramm Inc.

a cylinder with greater extended length for a specified retracted length. (provide picture of telescopic cylinder here)

Capacities

Hydraulic cylinders are designed for a particular application. The design ratings, qualification testing, and other parameters are determined by the manufacturer. The National Fluid Power Association and API provide industry standards which may be used to judge or compare hydraulic cylinders. Operators should take care to ensure they are familiar with the rated working load limits and do not exceed those limits.

Purpose/Use

Hydraulic cylinders are a compact means providing variable straight line force and movement. Hydraulic valves provide

IADC Drilling Manual

Hydraulic cylinders may also be used for drillstring hoisting on both land and offshore rigs, as shown in Figures RP-10 and RP-11.

Operation and safety

Hydraulic pressure in a cylinder should not be allowed to exceed the cylinder pressure rating. Lifting a load greater than the cylinder rating will cause excessive pressure. The cylinder hydraulic system may contain counterbalance vales on or very near the cylinder. These valves lock the hydraulic fluid in the cylinder and prevent movement when the system pressure is removed. Applying an overload to a cylinder with counterbalance valves will cause excessive pressure unless the counterbalance valve includes a pressure control section. The potential for pressure intensification exists during system operation. For example, on the rod end of a cylinder when the cylinder is extended with the rod end port blocked. Quick, intense over-pressure situations may

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RP-8

ROTATING & PIPEHANDLING EQUIPMENT

Figure RP-11: Drillstring hoist cylinders on an offshore rig. Courtesy Schramm Inc.

IADC Drilling Manual

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ROTATING & PIPEHANDLING EQUIPMENT

RP-9

occur if a telescopic cylinder raising a gravity load misstages during operation. The hydraulic control system usually contains pressure protective devices, but improper operation or adjustment can cause an over pressure situation. If an over-pressure situation occurs the cylinder and all piping connections should be inspected for damage before proceeding with normal operation.

Hydraulic fluid cleanliness is a major factor in the life of the cylinder and all parts of the hydraulic system. Regular replacement and/or cleaning of hydraulic filters are very important. The fluid reservoir should be checked regularly for water content. Time span between water content checks should be based on experience. A sample of the fluid should be checked for contamination on a monthly basis.

Maintenance

Slips

Cylinder maintenance is necessary since the rod and rod seals are exposed to environmental factors, such as moisture, dirt, or salt and the internal (piston) seals are exposed to any contamination in the hydraulic fluid. The cylinder supplier should provide recommended inspection activities and inspection frequency. Industry standards also provide inspection information. Due to the importance of rig operation (and to prevent costly downtime), cylinders in regular use should be visually inspected daily. Cylinders used occasionally should be inspected before each use. At a minimum, cylinder maintenance should occur every 10,000 hours. Daily inspection should include: 1.• Inspect the rod seal and all cylinder piping for evidence of leakage. Replace the seal and gland bushings and stop the piping leaks; 2.• Inspect the cylinder rod for scratches or nicks. Smooth any sharp edge that will catch on another sharp edge such as the side of a wooden pencil; 3.• Check the cylinder rod for evidence of uneven wear around the diameter or along the length. Determine the cause of uneven wear and make the necessary repairs. A bent rod or binding due to installation problems are probable causes; 4.• Inspect the cylinder barrel for dents or damage. Further investigation is required when dents or damage are found; 5.• If the cylinder includes longitudinal tension rods, the rods should be inspected for damage, bending or signs of uneven tension. Major repair is necessary when a tension rod problem is found; 6.• Review the cylinder installation area for problems: kinked or damaged hose or piping, litter or misplaced equipment that will prevent proper cylinder movement during operation. Replace damaged parts and remove obstructions; 7.• Check couplings, particularly quick-connect couplings, for proper connection. Clean, repair or replace as necessary to assure a proper connection. Major inspection includes the daily inspection plus complete disassembly, magnetic particle inspection of suspected cracks, inspection of all threaded joints and review for excessive wear. Replace all seals and wear bushings, repair or replace damaged or worn parts, and pressure test in accordance with the original manufacturer’s test procedure.

IADC Drilling Manual

A pipe slip is a general term applied to specialty equipment in the oilfield. Their chief purpose is to hold pipe stationary while it is in the vertical orientation. Slip assemblies range in size to accommodate very small diameters of pipe to very large casing diameters. Slips are used to hold the pipe steady at the rig floor while the hook, top drive, elevator, casing running tool or other implement assembles or disassembles the string. Once the lowering of the pipe has stopped, the slips are set or seated into a bowl. The traveling equipment is then lowered causing the slips to hold the weight of the pipe string as the die teeth engage with the pipe. Then the pipe is released from the hook or elevator and the hook moves up to pick up the next stand of pipe to assemble into the string or vise-versa, if tripping out of the hole. Slips typically conform to a “cone in cone” design where there is an internal cone and an external conic bowl. In the most commonly used, the split cone configuration, the drill pipe is centered in a segmented cone of wedges. Those conically shaped wedges are supported inside a conically shaped bowl, such that downward force “wedges” the cone segments between supporting bowl and the outside of the pipe. Once “wedged” into place, the segments transfer the load of the pipe into the supporting bowl and into the substructure. In the split bowl design, the conical bowl is segmented and the inner cone remains solid. The inner cone now pushes the segmented bowl sections outward against the inside of a pipe. Slips are intended to hold the pipe at the rig floor. The size and capacity of the slips must match the pipe being used but as the depth of the hole increases the weight to be held increases. Slips have not historically required a rating. Theyhave been and continue to be used very successfully on land rigs and in some shallow water applications. However, the load capacity of slips continues to increase as the depth of wells or the depth of the water for offshore drilling operations continues to increase. To enable the current ultra-deep water drilling and continued drilling as the wells get deeper and deeper, slips and related spider systems are now available at 1,000 tons and beyond, to 1,250 ton and even 1,500 ton.

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RP-10

ROTATING & PIPEHANDLING EQUIPMENT

Split Cone

Split Bowl

or ”teeth” that actually bite into the surface of the pipe to hold it in place. The die inserts can be easily removed and replaced as necessary due to wear or if the teeth break. The dies stack up on a shelf at the bottom or toe of the slip sections. The dies are an integral component of the slips performing the function of holding the pipe in place as an assembly. The dies typically conform to one of three shapes: ••Narrow; ••Square; ••V-shape. The narrow dies are probably the most common, about 1 1/8 in. by 2 ¾ in. long. The outside face is flat and smooth. The inside face is cylindrical to match the OD of the pipe. The slips with these particular dies contain columns of teeth that actually bite the surface of the pipe. Looking down on the top of the die the sides are dovetailed, fitting into dovetailed grooves in the front face of the slips. Usually these dies are placed in multiple columns with narrow sections of the slip body between them. An increasing number of columns are used as the OD of the pipe increases. The length of the columns increases with anticipated load.

Figure RP-12: Split-cone and split-bowl slips. Slips are intended to hold the pipe at the rig floor. The size and capacity of the slips must match the pipe being used but as the depth of the hole increases the weight to be held increases. Courtesy National Oilwell Varco.

Slip components

Slips generally consist of large wedge-shaped pieces, replaceable wear inserts (dies), along with some method of connecting the slips together so that they work as an assembly. Many slip assemblies are manually operated using handles for lifting the slips in and out of engagement at the conical bowl. Some slips are designed to operate hydraulically when lifting the slips in and out of engagement, and so will have fittings and linkages to facilitate attachment to the hydraulic cylinders and support assembly. Control of the hydraulic systems is often integrated into the driller’s control system so that the driller can seamlessly control the slips and the elevator to most efficiently coordinate the setting and releasing of the slips as the pipe is stopped from running in the hole or being pulled out of the hole. The number of wedge sections in the slip assembly is proportional to the diameter of the pipe and the length of the slip segments is often proportional to the expected load. The replaceable die inserts are machined with sharp ridges

IADC Drilling Manual

Near square dies are common and often wider by comparison to the narrow die configuration. They fit into a pocket in the face of the slip body. Along the center of the front face of the slips is a deeper dovetailed groove. Toward the sides of the slip, the edge of the slip body has been cut back to form the pocket. The side of the pocket is tapered similar to one side of a dovetailed groove. These dies are then laid in pairs, one die on each side of the central dovetail groove. There are typically four or five pairs of these dies per section of slips. A rod with cross section like a bow tie is pushed down between the two stacks of dies to hold them in place. These dies are cut from a tubular section. Teeth are milled into the inside face forming columns and are sized to match the OD of the pipe to be held. The outside face of the die is smooth and seats against the face of the pocket in the slip. “V” shaped dies have columns of teeth on the two inside faces that form the “V”. The outside face is typically either a male or female dovetail or may be any other similar locking method. These dies work by creating two wide lines of contact where the teeth imbed deeply at the point of contact between the OD of the pipe and the flats of the various “V”s of the slip system. “V” shaped dies are often used in slip systems that have a higher number of slip sections than three man slips. Along with the common slips intended for handling drill pipe, there are also slips designed for handling casing. These slips are typically a higher number of narrow sections. Usually each section is only as wide as a single column of dies

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ROTATING & PIPEHANDLING EQUIPMENT and the gripping device may be traditional dies or it may be a form of “button” die. Sections are added/removed as the OD of the casing to be handled changes. The assembly is arranged so the length comes as close as possible to reaching all the way around the casing without any attempt to overlap. The taper on casing slips has traditionally been 2in. per foot per side or 4 in. of diametrical taper per foot (approximately 9.47° of taper from the centerline of the tubular). For casing slips a large number of die sizes and bowl diameters are necessary to enable the proper and safe handling of all the casing sizes from 36 in. down to 7 in. In the modern era, especially offshore where the casing strings are very heavy and rig time is extremely expensive, casing slips have been replaced by automated spiders or mock rotary devices to allow the casing strings to be assembled more efficiently and safely.

A

RP-11

5-in. slips with 5-in. inserts has proper contour

Slip damage

Damage from inappropriate use or overload subjects slips to a variety of failures.. The most common of these is to “blow out the toes”; where the stack of dies is damaged in the vicinity of the support shelf for the dies. This damage ranges from shearing through to breaking the entire toe off. In either case, the event can lead to “fish” in the hole (die fragments), along with damage to the slips and the potential of dropping the pipe string. Both maintenance and proper use are critical to the long life and safe use of slips. The right size slips must always be used for the size pipe being handled. Figure RP-13 shows the effects of using the wrong size of rotary slips on the drill pipe. Slips that are smaller than the pipe will damage the pipe and the corners of slips as well as risk dropping a string of pipe. Slips that are too large will not contact the pipe all the way around. This risks dropping the pipe and destroys the center part of the slip’s gripping surface. In order to carry the load evenly over the entire length of engagement the inserts must all be the same thickness. Below is a depiction of what happens when this is not followed. New or “like-new” inserts carry a concentrated load and deeply penetrate the pipe. Re-sharpened inserts carry no load. Inserts that carry a concentrated load are forced into slip bodies resulting in permanent damage to slips. The downward motion of the drill pipe must be stopped with the drawworks brakes, not with the slips. The drawing shows the effects of stopping the motion of the pipe with slips. This can occur when the floor hands are not careful to set the slips at the proper time when the driller has stopped the pipe or if the person at the drillers console sets the automated slips too soon. In both cases the slips “catch” the pipe, bringing it to a very sudden stop creating very high forces on the toes of the slips and on the pipe.

IADC Drilling Manual

B

5-in. slip used on larger drill pipe, collars or tool joints

C

5-in. slips on 5-in. pipe – after slip has been used on larger pipe, slip will bend back and could possilby break and fall into the hole.

Excessive stress placed on slip segments

Ribs Cracked

Figure RP-13: "B" and "C" show effects of using rotary slips on wrong size pipe, compared to "A". IADC drawing.

Do not let the slips “ride” on the pipe while the pipe is being pulled out of the hole. This practice accelerates the wear on the dies. It also risks having the slip ejected from the master bushing bowl when a tool joint comes through and causing possible injury to personnel. Be careful not to catch the tool joint box in the slips when the driller slacks off. This often happens when coming out of the hole and the driller does not pick up high enough for the slips to fall around the pipe properly. This can ruin the slips, damage the tool joint box and damage the body of the pipe.

Slip care and maintenance

There are a number of documents that demonstrate various conditions of wear that lead to damage to the slips, the bowl,

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RP-12

ROTATING & PIPEHANDLING EQUIPMENT

New or like-new gripping elements carry concentrated load and deeply penetrate the pipe.

Dull or resharpened gripping elements carry no load. Gripping elements which carry concentrated load are forced into slip bodies resulting in permanent damage to slips.

Permanent deformation

Figure RP-14: Never use re-sharpened gripping elements. IADC drawing.

Figure RP-15: Stop the downward motion of drillpipe with the drawworks brakes, not with the slips. Using slips for this purpose can permanently deform the pipe. IADC drawing.

or the tubular being handled. Today, slips can reliably handle the very high string loads necessary for modern ultra-deep wells and wells drilled in ultra-deep water offshore. Despite FIGURE E2-7; Newer use resharpened gripping elements. the advancements that have been made to enable the slips, it is still necessary to sustain good operating and maintenance practices. To ensure safe sustained operations with slips it is essential to inspect the slips on a regular basis. Any cracks that may be present are possible locations of catastrophic failures while the slips are in use.

•• Place a straight edge on the backs of the slips and on the face of the slips. If the slips are bent or worn the straight edge will not make full surface contact with the Results from Stopping Pipe with Slips slips. The backs of the slips should be straight and smooth. Excessively worn slips should be replaced; •• Magnetic particle inspection or inspection by similar method should be made to detect fatigue cracking in the slip bodies, webs and toes of the slips. If cracks are detected, the slips should be removed from service and destroyed to prevent future use; •• Check the insert slots for damage or excessive wear. If there is 1/8 in. to 3/16 in. clearance between the back of the inserts and the insert slot, the slips should be replaced. With worn insert slots there is danger of losing the inserts down the hole.

Operationally these include but are not limited to: •• Visual inspection; •• Complete disassembly of the slips; •• Cleaning of the slips and bowl; •• Dimensional checks of the slips and bowls; •• Die penetrant or magnetic particle inspection; •• Regular inspection and replacement of the dies as they wear or as teeth break off; •• Lubrication of the slips in the bowl; •• Inspection of the toes and other critically loaded surfaces.

Inspection of drill pipe slips

The slips should be physically inspected before every trip. If the inserts are not secure, remove the slips from service until they can be repaired. If cracks are detected in the slip bodies, they should be removed from service and destroyed to prevent future use. The slips should be more thoroughly checked every three months:

IADC Drilling Manual

Slip tests should be performed every three months. This test is important to determine slip wear and/or master bushing wear. Spare parts are readily available to repair all slips of recent manufacture. Normally the inserts, dies or liners are the parts most frequently requiring replacement. Never intermix new inserts with worn or re- sharpened inserts. Section B4 of this manual provides additional information concerning re-sharpened inserts. To maintain fully functional slips, they must be kept clean, they must not be abused, the hinge pins must be well lubricated and the backs, before use, are fully coated with good quality anti-seize compound.

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ROTATING & PIPEHANDLING EQUIPMENT

RP-13

Routine care and maintenance will extend the service life of the drill pipe slips, protect the drill pipe and reduce the danger of sticking slip; Figure RP-16 indicates points of maintenance and lubrication.

API slip standards

Historically, slips and rotary spiders have had very limited specification control on them. Over several years leading up to 2013, a task group within API Subcommittee 8 has been updating the specifications for slips and spiders. This update is set to become a part of the standard in 2014. There are several noteworthy changes to API Specification 7K as a result of this update. In brief these are the following: •• The first piece/assembly for equipment designed for over 500 ton must have a Design Verification Test (DVT) to be eligible for an API monogram. •• Each future piece/assembly must have a Production Proof Test (PPT) to demonstrate ongoing integrity of the manufactured parts/assembly. •• Once tested for rating above 500 ton, a group of pieces assembled into a slip or spider must stay together as a group. If alternates are inserted or sections taken out then the new group must have a new PPT done. (This does not include the replacement of dies as they wear.) •• The taper of the slips and bowls is no longer specified by the standard. Instead the specification states that the taper of the slips and the bowl must be marked on the top surface so the users can read it and verify that the tapers match. •• The DVT is now a two part test, first, strength verification similar to that required in API 8C. This is followed by a “fitness for purpose test” on a tubular to demonstrate how the slips impart stresses on the tubular being handled.

Slip backs will bend

Figure RP-16: Setting slips on tool joint. IADC drawing.

Setting Slips on Tool Joint

Slips

Clean and lubricate lock assembly

Retaining pin

Lock Eccentric pin

Keep these surfaces clean and lubricated

To replace the drive pin bushing: Torch cut 2 places 180° apart and drive out from the drain hole

Bowl

Elevators

Dress surfaces of slips and bowls

Elevators attach to pipe for movement about the rig floor and pipe storage areas. Single Figure RP-17: Points of lubrication and maintenance for slips. IADC drawing. joint elevators are designed to transfer a single joint or single stand of drill pipe or casing. secure the tubular within the elevator, and to transfer the Higher capacity elevators usually work in an area on or adload to the elevator body. Most elevators have the ability to jacent to the well center line. Elevators are attached to the open and close around the pipe allowing the pipe to enter tubular by tool joint or collar interface, or by slip assemblies the elevator from the side (side door, center latch elevators, which grip the tubular. Elevators that interface with the tool split or gated). Solid body elevators do not open and must joint or collar utilize a load shoulder to transfer the load to be installed over the end of the tubular. Elevator Spiders are the elevator. Slip type elevators utilize a wedge concept to also installed over the end of the tubular, but incorporate a

IADC Drilling Manual

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RP-14

ROTATING & PIPEHANDLING EQUIPMENT













split arrangement, which allow them to be occasionally removed from the tubular being run without the requirement to lift and remove over the uppermost section of the tubular. Setting the slips can be performed manually or via pneumatic or hydraulic controls actuated either locally or remotely. They are attached to the main hoisting system via elevator links. •• Slip Type Elevators utilize a wedge concept to secure the tubular within the elevator body. They typically include a slip setting ring which contacts either the upset or the collar, manually setting the slips. They are also available in mechanized versions allowing the operator to actuate the slips locally or remotely. These are typically limited to use on smaller casing sizes, tubing and limited string weights. •• Solid Body Elevators consist of a single piece body design and may or may not incorporate slips. They are designed, and primarily intended, for single function applications. These elevators must be installed over the tubular. Because of their simple design, they can accommodate higher load ratings and usually facilitate horizontal applications such as riser running.

Operation  Figure RP-18:  Single Joint Elevator,  Bottleneck Elevator,  Square Shoulder Elevator,  Elevator/ Spider as Elevator,  Elevator/Spider as Spider,  Slip Type Elevator,  Solid Body Elevator. All courtesy Forum Energy Technologies.

split or gated design facilitating intermittent opening to install or remove pipe from the side. There are several types of elevators. Refer to Figure RP-18: •• Single Joint Elevators are designed to transport single joints of tubulars. They are usually attached to a winches or racking systems, while some are attached beneath the main elevator and hoisted by the drawworks. •• Bottleneck Elevators provide a tapered load shoulder that interfaces with the taper of the tool joint and transfers the load to the elevators. The load shoulder may be bored directly into the elevator body. Alternatively, some elevators include interchangeable bushings incorporating the load shoulder and facilitate extended capability. Bottleneck elevators are attached to the main hoisting system via elevator links. •• Square Shoulder Elevators provide a flat surface that interfaces with a collar or square shouldered tool joint. While some single joint elevators contain a square shoulder, the term typically applies to elevators that are designed to carry the full weight of the string. They are attached to the main hoisting system via elevator links. •• Elevator/ Spiders are designed to run casing and tubing. They incorporate a slip assembly device inside the frame, using a wedge concept to set the slips, thus transferring the load. They typically include a gate or

IADC Drilling Manual

Elevators may be operated manually or by power. Manual operation requires the assistance of personnel to latch and unlatch the elevators via latch handles on the elevator. Power operation allows, remote or local elevator operation by the driller or other assigned personnel via pneumatic or hydraulic power. Power operated elevators may be integrated into the rig control system. Elevators with hinged doors (center latch and side door) allow the pipe to be easily removed at each connection point. Slip type or gated type elevators are intended for occasional opening and are usually used for handling casing. Today’s elevators all contain at least one redundant safety system preventing the elevator from opening via a single command or when loaded. Bottleneck, square shoulder, single joint, and slip type elevators facilitate rapid removal and installation from each connection as they incorporate a hinged door design.

Capacities/Limitations

Each elevator carries a specific maximum load rating as prescribed by the manufacturer. Examples of load ratings on drill pipe include load ratings up to 1,500 short ton. However, drilling environment is rapidly becoming more demanding and we will likely see higher applicable load ratings as a result. In certain circumstances, available contact area at the interface point, may limit the elevator’s rating. For an idea of how bore and tool-joint diameters affect the load rating, see Figure RP-19. Special caution must be used when the tool joint or collar O.D. is minimally larger than the bore of the elevator. If there

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ROTATING & PIPEHANDLING EQUIPMENT is any doubt regarding the ratio of the O.D. to the elevator bore, contact the manufacturer for clarification on load ratings.

RP-15

Min. req’d tool joint diameter (in.) 8

Inspection and Maintenance 7

Maintenance

Practice safety at all times when servicing the equipment and use approved safety methods, material and tools. Always wear protective gear for eyes, head and hands.

6

An example of scope and frequency follows.

5

Lubricants: Lubricate the elevator regularly during the usage and storage to prevent corrosion. Use an extreme pressure, multi-purpose, lithium base grease of no. 1 or no. 2 consistency and multi-weight motor oil. When the elevator is in use, lubricate the elevator according to the following schedule:

»» Daily: •• •• •• •• ••

Grease hinge pin(s); Lubricate latch pin and latch lock pin; Grease underside of lifting ears; Grease bore and seating surface; Check link block bolt f/nut and cotter pin.

»» Weekly:

s ton tons 0 35 ns to 0 15 s ton

500

4 0

25

3

s

0 10

n to

2 3

2

4

5

6

Actual center bore (in.) Figure RP-19: Effect of bore and tool-joint diameter on load rating.

•• Brush grease on springs; •• Grease link retainer fasteners; •• Check link block bolts for nuts and cotter pins.

Inspection

To ensure optimum performance from elevators, the following checks should be performed once a week: •• Inspect hinge pins, latch pins, and latch lock pins and mating components to insure that they remain in accordance with the manufacturer’s maximum wear tolerance. These may hinder proper opening and closing of the door and latch and latch lock engagement; •• Check for proper latch and latch lock spring performance; •• Check for proper operation of latch stop mechanism; Latch should not stop against the body when engaged; •• Check springs for damage, deformation and lack of tension; •• Check link block bolts, nuts and cotter pins. API RP 8B provides a procedure for developing an inspection and maintenance procedure covering both extent and frequency requirements.

Safety

The design safety factor mandated for API monogramed elevators or elevators produced to a recognized standard, assures the user that the elevator was designed and test-

IADC Drilling Manual

ed for loads at rated load capacity. Manufacturers provide additional safety features as a standard part of the product. Optional safety and operating features may be available at the discretion of the manufacturer and the buyer. When using elevators, please be aware of the following: •• Elevators are manufactured to operate at rated capacity in a vertical direction. When used to pick or lay down a SINGLE JOINT of pipe in a non-vertical position, the operator MUST ensure that the latch, safety latch & latch springs are in good working order; •• Prior to hoisting with the elevator from any position, it is necessary to ensure that the elevator is completely installed around the pipe and that the latches are properly engaged. Failure to do this could result in serious injury; •• If there is any question as to the safe operation condition of an elevator, it must be removed from service until a review can be completed; •• Be sure to use the handles provided (when applicable) for operating the elevator. Keep hands and fingers clear of the elevator bore when installing the elevator on the tool joint; •• Oversized pipe could cause difficulties in latching or possibly result in the elevator latching partially or not at all; •• Undersized pipe could cause uneven stress distribution, inadequate load bearing area, or possibly allow the tool joint to slip through the elevator;

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ROTATING & PIPEHANDLING EQUIPMENT

•• Inspect the bore, latch, latch pin and hinge pin regularly for wear to be sure the tool joint does not slip down into the bore of the elevator under pressure, placing strain on the latch in an improper manner. Proper bore codes and dimensions are provided in current operations and maintenance manuals; •• Make sure link block bolts are retained w/ nuts and cotter pins.

should immediately be taken out of service and sent to the original equipment manufacturer for further inspection and/ or evaluation for potential repair. Likewise, if indications or cracks are found in ANY inspection, the links should immediately be taken out of service and sent to the original equipment manufacturer for further inspection and/ or evaluation for potential repair.

Elevator links (bails)

Using elevator links unsafely consititues a serious danger to the entire rig and crew. When installing links and/or attaching elevators, all retention methods supplied by the OEM must be fully engaged and secure. Failure to do so could result in serious injury or death.

Elevator links are used to connect the top drive or hook on a drilling rig, to the elevators and are used in pairs. In addition to serving as a direct connection providing hoisting capability to the elevators, they also provide the flexibility required to access tubular in various positions on the rig floor. Elevator links are typically made of forged material. Some elevator link components are welded together in a loop arrangement. These links are intended for lighter loads such as well servicing. Links intended for heavier loads and critical applications are typically forged from a single piece. The single piece forging consists of upper and lower eyes connected by a shaft or rod. The upper and lower eyes are usually having different size openings to facilitate connection to the top drive or drilling hook and the elevator. Elevator links are installed first onto either the top drive (solid body elevator) or hook which is connected directly to the travelling block. Once connected and secured, they can be hoisted to facilitate installation of the elevator onto the lower eye (or section). Elevator links are available in various sizes and lengths. They are available in short ton ratings from 50 ton to 1,380 ton and , in lengths from 30 ft to 55 ft (longer links are available upon request). API has established standardized dimensions and ratings for elevator links (API Specification 8C, Drilling and Production Hoisting Equipment). Although not always the case, the rated capacity is typically determined by the remaining cross sectional dimension of the lower eye at the interface point of the elevator. Special attention should be given to this area. The American Petroleum Institute recommends regular inspection and has established inspection categories (API Recommended Practice 8B, Recommended Practice for Procedures for Inspections, Maintenance, Repair and Remanufacture of Hoisting Equipment). Daily category I inspections, as prescribed in API Recommended Practice 8B, are therefore recommended. When in use, Category II inspections should occur weekly, Category III inspections should occur semi-annually and Category IV inspections to be conducted annually. In the event sufficient wear has occurred, reducing the cross sectional dimension of any section, to below that of the minimum value in API Specification 8C, the links

IADC Drilling Manual

Crown block, hook and sheaves

The hoisting system on a drilling rig comprises several components that work together to lift heavy lengths of drilling pipe and casing. Combined, these components create a block-and-tackle system that can lift loads as heavy as 2 million lb. The crown block is the piece of equipment at the very top of the mast or derrick. It consists of a system of sheaves that distribute the wireline, and its configuration varies from rig to rig depending on the placement of the equipment below the crown. Crown blocks are systems of sheave assemblies, so the concept of operation is very similar to that of traveling blocks. Sheaves are stacked between pedestals, and end caps are bolted against the shaft ends in order to squeeze the pedestals against each other and preload the sheave bearings. The pedestals are usually bolted to the crown, and the placement of them depends on where the deadline anchor and drawworks are located. Crown blocks vary considerably in layout; however, there are three components which are found in every crown block: a fastline, a cluster, and a deadline assembly. The wireline wraps around the deadline assembly at a very slow speed coming from the anchor, it then goes down to the traveling block and up to the cluster several times. The bigger the size of the rig the more sheaves are on the cluster assembly, as more lines give more lifting capacity/hookload capacity. The last line from the traveling block finally comes up to the fastline assembly and down to the drawworks at a high speed. The drawworks feeds or takes in the wireline as the traveling block moves up and down the mast.

Capacities and limitations

The crown block must hold a similar or equal load to the traveling block, which means crown blocks are typically rated anywhere between 100-1,000 tons. It is important to note that these load ratings are for static loading. Any additional forces due to dynamic loading or impact must be taken into account when specifying a safe hoisting load for the rig.

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Figure RP-20: Example system of sheaves that distribute the wireline, part of the crown/block/hook/sheave combination that act like a block and tackle to hoist loads as heavy as 2 million lb. Courtesy American Block.

Inspection and maintenance

Like all hoisting equipment, periodic inspection of the primary-load carrying components for cracks, damage or wear is vital for safety and the proper operation of the equipment. Scheduled maintenance should also be performed according to the OEM maintenance schedule and API 8B. Some of the commonly replaced or inspected items include: Bearings, seals, and sheaves.

Safety

All crown blocks used in the oil industry are designed and tested to stringent specifications such as API Spec 4F. It is important to not exceed the OEM-rated load during operation of the equipment. Control of dropped objects is vital to a safe working environment. Proper retention on all fasteners is critical.

Drill line

The drill line is a key part of the operating system. Drill line is made from steel wire rope (Independent Wire Rope Core or IWRC), typically from 7/8 in. to 2 in. diameter. The size of the drill line in the reaving system, along with the number of parts of drill line, determines allowable hookload (Figure RP-21). The drill line is used to lift the traveling block. On a mast or derrick, the drill line travels from the drawworks (with several dead wraps around the drum), directly to the fastline sheave. It’s common for the drill line then to travel from the fastline sheave to the traveling block. The path of the drill line then goes between the traveling block sheaves

IADC Drilling Manual

RP-17

Figure RP-21: Crown with fastline sheaves and cluster sheaves. Courtesy TM Engineering PLLC.

and crown cluster sheaves multiple times (Figures RP-22 and RP-23). Once the drill line has left the last cluster sheave located on the crown, the drill line goes back to the traveling block, then returns to the crown and over the deadline sheave. From the deadline sheave the drill line travels to the deadline anchor and is fastened at the deadline anchor, which is either attached to the mast or the drill floor. From the deadline anchor, the remainder of the drill line comes from the supply reel, typically stored off to the side of the rig. For further details on wire rope, see the Wire Rope chapter of the IADC Drilling Manual, 12th edition.

Structures

To provide context regarding placement and use of rotary and pipehandling equipment, this chapter contains a summary of drilling structures distilled from the separate Structures Chapter in the IADC Drilling Manual, 12th edition For a complete discussion of drilling structures, please refer to that complete chapter. Drilling structures are divided into several different categories. The primary purpose of the drill floor structure is to support the mast or derrick, rotary table, pipe setback, drawworks, driller’s cabin or console, and other important drilling related equipment. Major load carrying elements of the drill floor are the rotary beams, drawworks frame and setback frame. Other frames and supports are located on the drill floor as required to support various drilling equipment. The main purpose of the substructure is to support the drill floor and mast during operations or support a mast during mast raising. The primary loads applied to the sub-

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Figure RP-22: Traveling block. Courtesy TM Engineering PLLC.

Figure RP-23: Traveling block reeved to cluster sheaves. Courtesy TM Engineering PLLC.

structure are through the hookload located in the crown of the derrick or mast, rotary table, environmental, pipe setback, and drilling equipment. The substructure also commonly provides a means for the drill floor to skid or move in order to accommodate various well locations.

various equipment. They also support lights to illuminate the drill floor, illuminate the pipe rack, and provide aircraft warning and navigation markers. The main structural steel of a derrick can range from 147 ft-215 ft tall. The base dimensions typically range from 30 ft x 30 ft for a single derrick on a jackup to 40 ft x 80 ft for a dual derrick on a drillship. Derricks are typically used offshore, although there are a few onshore. A derrick is not very mobile; therefore few are used onshore today.

Derricks and Masts

Derricks are four-sided structures used to support the downhole drilling loads from tools, drill pipe, and casing. Masts are three-sided structures used to support the downhole drilling loads from tools, drill pipe, and casing. Derricks are typically offshore structures, uses on drillships, semisubmersibles, and jackups. Masts are found on both onshore and offshore rigs. Masts and derricks are typically connected to a drill floor structure, although common older mast designs connect to the basebox, directly supported by the ground.

»» Derricks

Derricks are four-sided tower like structures that support loads during oilfield drilling (Figure RP-24). The typical drilling loads are from the hookload (the support of loads in the wellbore comprising drill pipe, casing, traveling equipment or tools), pipe setback in the derrick, environmental loads (wind and vessel motion) and accessory equipment loads (pipehandling machines, casing-tabbing boards, etc.) Derricks allow access for personnel to inspect or operate

IADC Drilling Manual

The wellbore drilling loads are applied to the derrick through the crown. At the crown, several sheaves are engaged with wire rope that reeve to a traveling block. The ends of the wire rope terminate at the drawworks at one end and usually a deadline anchor at the other end. It is possible to have each end of the wire rope terminate at a drawworks. As the drawworks spools and unspools, load is applied to the crown and through the derrick to the drill floor and substructure. The origin of this load is what is suspended from the traveling equipment. This load could be several thousand ft of drill pipe or casing. Also, downhole tools for measuring well formations, removing foreign objects, or cutting casing or drill pipe apply loads to the derrick. Another major function of the derrick is to support drill pipe and/or casing that is not in the wellbore. During the process of drilling, drill pipe will be inserted into and out of the well-

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RP-19

Figure RP-25: Derrick racking board with drill pipe. Courtesy TM Engineering PLLC.

bore several times. As a time saver, stands of drill pipe are racked back in the derrick in a racking board (Figure RP-25). The pipe applies horizontal load to the derrick from pipe lean, wind on the pipe, and rig motion. Some derricks have a casing-setback area, which speeds casing running. The casing inputs similar loads into the derrick as drill pipe. Several other pieces of equipment are located in the derrick. This includes, but is not limited to pipehandling equipment, navigation equipment, traveling equipment controls, mud standpipes, cement standpipes, casing running equipment, maintenance platforms, maintenance access baskets, dead line anchors, degasser ventlines, and weather sensing devices.

»» Masts

Masts are three-sided tower-like structures that support loads during oilfield drilling, as shown in Figure RP-26. The typical drilling loads are from the hookload (the support of loads in the wellbore that consist of drill pipe, casing, traveling equipment, or tools), pipe setback in the mas environmental loads (wind and vessel motion, if applicable), and accessory equipment loads such as casing stabbing boards, etc. Masts have access for personnel to inspect or operate various drilling equipment. They also support lights to illuminate the drill floor, illuminate the pipe rack, provide aircraft warning, and navigation markers. The main structural steel of a mast can range from 105 ft tall to 185 ft tall. The base dimensions have a variety of range from 12 ft x 8 ft to 30 ft x 35 ft. Masts are primarily used onshore, although a number are used offshore, primarily on fixed platform rigs. A mast is typically very mobile; therefore, masts dominate the onshore drilling industry.

Figure RP-24: Drilling derrick. Courtesy Loadmaster Derrick & Equipment Inc.

IADC Drilling Manual

As with the derrick, wellbore drilling loads are applied to the mast through the crown. At the crown, several sheaves are engaged with wire rope that reeve to a traveling block. The ends of the wire rope terminate at a drawworks on one end

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RP-20

ROTATING & PIPEHANDLING EQUIPMENT and usually a deadline anchor on the other end. It is possible to have each end of the wire rope terminate at a separate drawworks, but not typical on a mast. As the drawworks spools and unspools, load is applied to the crown and through the mast to the drill floor and substructure. The origin of this load is what is suspended from the traveling equipment. This load could be several thousand feet of drill pipe or casing. Also, downhole tools for measuring well formations, removing foreign objects, or cutting casing or drill pipe apply loads to the mast. Another major function of the mast is to support drill pipe and/or casing that is not in the wellbore. During drilling, drill pipe will be run into and out of the wellbore several times. As a time saver, stands of drill pipe are racked externally to the mast in a racking board (Figure RP-27). The pipe applies horizontal load to the mast from pipe lean, wind on the pipe, and rig motion. In some cases, masts have a casing setback area which speeds up the process of running casing into the wellbore. Casing loads on the mast are similar to drill pipe. Several other pieces of equipment are located in the mast. These include, but are not limited to, pipehandling equipment, navigation equipment, traveling equipment controls, mud standpipes, cement standpipes, casing-running equipment, maintenance platforms, maintenance access baskets, dead line anchors, degasser ventlines, and weather sensing devices. The mast caps off the mobile drilling rig package.

Rotary swivel Figure RP-26: Drilling mast. Courtesy Loadmaster Derrick & Equipment Inc.

Figure RP-27: Mast racking board with drill pipe. Courtesy Loadmaster Derrick & Equipment Inc.

IADC Drilling Manual

The hoisting system on a drilling rig comprises several components that work together to lift heavy lengths of drill pipe and casing. Combined, all of these components create a block-and-tackle system that can lift loads as heavy as 2 million lb. The swivel is a piece that hangs directly beneath the traveling block and directly above the Kelly drive (Figure RP28). It constitutes the connection point between the rotating drillstring and the stationary traveling block. The swivel is also the point where mud is pumped into the drillstring. The swivel must hold the hoisting load and the pressure from the drilling fluid while the drillstring rotates in operation. Key components of the rotary swivel include: •• Gooseneck: This is the connection for the drilling fluid. It is rated to hold 5,000-7,500 psi of pressure and the typical hose connection provided is 3 in.-4 in. female line pipe thread; •• Thrust bearing: This bearing provides the point that the drillstring rotates about. API defines a swivel bearing load rating to quantify the dynamic load rating of the thrust bearing; •• Stem: This piece rotates along with the drillstring. It must be strong enough to support the hoisting load and the drilling fluid pressure. The connecting threads are API threads, which are tapered threads made with high precision to seal the drilling fluid from leaking;

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manageable levels. This allows the line to be clamped with a bronze insert in a clamp assembly secured with bolts that can be hand torqued.

•• Saver sub: This is an optional piece of equipment connected to the bottom of the swivel stem. It acts as a spare part between the stem and the Kelly drive. When the API threads wear out, the sub can be replaced without having to disassemble the stem from the swivel.

To measure loads using the load cell, the drum of the deadline anchor must be able to slightly rotate around a shaft due to the torque of the drilling line wrapped around it. The reaction to the wireline tension is counter-reacted by a compression-type hydraulic load cell mounted between base frame and the drum. The pressure developed in the load cell is measured and transmitted to driller’s control panel.

Capacities and limitations

Rotary swivels are typically rated anywhere from 100-1,000 ton. It is important to note that these load ratings are for static loading. Any additional forces due to dynamic loading or impact must be taken into account when specifying a safe hoisting load for the rig.

Load Cell

Inspection and maintenance

Like all hoisting equipment, periodic inspection of the primary-load carrying components for cracks, damage or wear is vital for safety and proper operation. Scheduled maintenance should also be performed according to the OEM maintenance schedule and API 8B. Some of the commonly replaced or inspected items include: Main thrust bearing, washpipe assembly, and sealing O-rings.

RP-21

Figure RP-28: The swivel hangs directly beneath the traveling block and directly above the Kelly drive. Courtesy American Block.

Safety

All swivels used in the oil industry are designed and tested to stringent specifications such as API 8C. It is important to not exceed the OEM-rated load during operation. Control of dropped objects is vital to a safe working environment. Proper retention on all fasteners is critical.

Deadline anchor

The hoisting system on a drilling rig consists of several components that work together to lift heavy lengths of drilling pipe and casing. Combined, these components create a block-and-tackle system, which traditionally includes a drawworks, traveling block, crown block, swivel, hook and the deadline anchor. Because the hoisting load for some of the biggest rigs can exceed 2 million lb, it is important to have an accurate measurement of the hookload.

The load cell is a simple hydraulic piston. It is filled with oil, and the force reacting against the rotation of the drum pressurizes the system. The standard compression and tension load cells have known surface areas of 50 sq in. and 36.7 sq in., respectively. By knowing the reaction force and surface area of the piston within the load cell, a pressure can be calculated for a given line tension. This is then converted to hookload, depending on how many lines are strung.

Unlike traveling blocks, deadline anchors vary widely in configuration. This is due to the huge variety of rig layouts. Some of the configurations include: floor-mounted tension; floor-mounted compression; mastor leg-mounted tension; mast- or leg-mounted compression (Figure RP-29, RP-30 and RP-31); rotating or non-rotating. Although many different types of load cells are used to measure the load, only two are commonly used: the compression (E551 style) and the tension (E-80 style).

The deadline anchor is designed to provide a practical method of securing the deadline and measuring line tension. The deadline anchor must hold the deadline and not let it slip during operation. This is accomplished by wrapping several (usually 3-4) wraps of wireline around the drum. This creates significant friction and reduces the line tension to

IADC Drilling Manual

Figure RP-29: Standard floor-mounted tensiontype anchor. Courtesy American Block.

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ROTATING & PIPEHANDLING EQUIPMENT

Figure RP-30: Leg-mounted compressiontype anchor. Courtesy American Block.

Figure RP-31: Rotating deadline anchor. Designed to decrease slip and cut times. Courtesy American Block.

Traditionally, the conversion from pressure to hookload is done within the weight indicator. The weight indicator is a calibrated pressure gauge that reads hookload instead of pressure. It does this by using a specially made Bourdon tube that is tailored to the application. Any change in configuration, number of lines strung or different type of anchor must result in a recalibration of the weight indicator. As technology advances, the weight indicator is becoming a redundant backup of a sophisticated electronic drilling control system. All of these calculations can then be performed and calibrated to a much higher precision through electrical pressure transducers.

ly rotate to pay drilling line in and out can drastically improve these times. This reduces the need for a worker to constantly handle the rope to ensure proper alignment. Because of this, the line can be pulled through much more quickly. Further, eliminating manual efforts reduces the risk of injury.

Operation and function

Deadline anchors not only measure line tension and hold the deadline in place. They are also an integral component used during routine rig maintenance. Slipping and cutting the drilling line is a common occurrence on a rig. When the wire rope reaches a certain ‘age,’ often measured in ton-miles, that entire strung-up section needs to be replaced. The anchor makes this possible by unclamping the deadline, pulling the required line through the system off of the supply spool, cutting the line at the drawworks and re-spooling. Ease of use and equipment familiarity is paramount for quick slip and cut times. To enhance efficiency, a key driver in today’s drilling operations, technical advances have decreased time spent on routine tasks, such as slipping and cutting line. Rotating deadline anchors featuring an unlockable drum able to free-

IADC Drilling Manual

Capacities and limitations

Typical deadline anchor installations depend on orientation, hookload and number of lines strung. The combination of these factors determines the anchor’s rating, which is usually defined in kilo-pounds, or kip. The load ratings can vary from 20 kip-200 kip. It is important to note that these rated loads are static values. It is essential that the rig designer take into account any dynamic loadings and ensure that they do not exceed the rated load of the equipment. The measured reading is very sensitive to external factors. Fleet angles can impact the accuracy of the load-cell reading. Friction caused by deflector sheaves, improperly maintained bearings, or any rubbing of the wireline can introduce error into the system. Drillstring movement can produce strange readings due to the friction of the sheaves. This friction produces different tension values on each line in the system while it is in motion. Only when the traveling equipment is stationary is the line tension in equilibrium.

Inspection and maintenance

As with all hoisting equipment, periodic inspection of the primary load-carrying components for cracks, damage, or wear is vital for safety and proper operation. Scheduled

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SPECIAL OPERATIONS

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practice advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. Contributors Dennis Moore, Marathon Oil Corp. (Chapter Lead and Faults) Chip Alvord, ConocoPhillips (Permafrost) Charles Bellinger, Smart Chemical Services (Geothermal) Jerry Fisher, Schlumberger (Fishing) John Jones, Marathon Oil Corp. (Depleted sands) Louis Godoy, Weatherford (Solid Expandables)

Moji Karimi, Weatherford (Solid Expandables) John Murphy, M-I SWACO, a Schlumberger company (Permafrost) Nathan Smith, Energen Resources (Coalbed Methane) Mike Winfree, ConocoPhillips contractor (Permafrost)

Reviewers Michael Davis, Drill Science Corp., (Faults) Mohamed Elshabrawy, Shell (Fishing) Buster Hamley, Weatherford (Fishing) Eric Moellendick, Schlumberger (Solid Expandables)

Allen Pere, BP (Depleted sands) Ron Sweatman, Baker Hughes (Geothermal) Monte Johnson, Weatherford (Fishing) Bobby Jarrett, Weatherford (Fishing)

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This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9909049-1-5

Printed in the United States of America.

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SO-iii

Contents

SPECIAL OPERATIONS

Drilling highly depleted sands...................................SO-1

Free-point indicator............................................ SO-8

Drilling coalbed methane formations.....................SO-1

Separating or backing off pipe in the

History.....................................................................SO-1

wellbore.............................................................. SO-8

Drilling CBM wells................................................SO-1

String-shot back off.................................... SO-8

Summary.................................................................SO-2

Chemical cutters......................................... SO-8

Drilling permafrost based on North Slope Alaska experiences.................................................................SO-2

Radial cutting torch..................................... SO-9

Well design considerations...............................SO-2

Severing tools............................................... SO-9

Common fluid systems used for Arctic drilling...................................................................SO-2

Washover operations......................................... SO-9

Spud mud........................................................SO-2

Pipe-size selection...................................... SO-9

Surface casing and cements.....................SO-3

Mud properties for fishing and

Jet cutters...................................................... SO-9

Rotary-shoe selection................................ SO-9

Geothermal wells..........................................................SO-3

washover.................................................... SO-9

Drilling faults................................................................. SO-4

Freeing stuck pipe with acid............................. SO-9

Solid expandable liner technology...........................SO-5

Jarring operations................................................ SO-9

Improve well architecture..................................SO-5

Fisher bumper sub...................................... SO-9

Mitigate hazards...................................................SO-5

Hydraulic fishing jars................................ SO-10

Components of solid expandable liners.........SO-5 Running sequence....................................... SO-6

Fishing accelerator/intensifier/slinger jar................................................................ SO-10

Open-hole fishing operations................................... SO-6

Surface jar................................................... SO-10

Job planning.......................................................... SO-6

Attachment tools for fishing parted pipe... SO-10

Stuck-pipe mechanisms......................................SO-7

Screw-in sub............................................... SO-11

Differential sticking......................................SO-7

Full-strength series 150 overshot......... SO-11

Sloughing shale.............................................SO-7

Casing/tubing spear................................. SO-11

Key seating.....................................................SO-7

Box and taper taps.................................... SO-12

Blowout sticking............................................SO-7

Fishing for junk................................................... SO-12

Undergauged hole sticking....................... SO-8

Fishing magnets................................................. SO-12

Lost-circulation sticking............................. SO-8

Junk mills..................................................... SO-12

Mechanical sticking.................................... SO-8

Globe-type junk baskets.......................... SO-13

Estimated stuck point......................................... SO-8

Reverse-circulating junk baskets.......... SO-13

String stretch formula......................................... SO-8

Open-hole logging tools.......................... SO-13

Electric-wireline pipe recovery........................ SO-8

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Drilling highly depleted sands

Drilling through highly depleted sands may pose significant challenges, depending on the pore pressures and fracture gradients of other exposed formations, and the minimum allowable mud weight to avoid an influx and maintain wellbore stability (prevent hole collapse). In most instances, fracture gradients in sands are reduced as a function of depletion. However, this is not a one to one relationship, as the reductions in minimum horizontal stress and fracture extension pressures are typically 30 to 60% of the reduction in pore pressure. Even so, in situations where initial drilling margins are low, such as in highly inclined wellbores in over-pressured environments, any reduction in the drilling margin may prove difficult to manage. Since the minimum allowable mud weight for any wellbore is generally fixed by the maximum pore pressure of any exposed permeable formations or the minimum mud weight to prevent hole collapse, strategies for successfully drilling through highly depleted sands generally focus on maintaining a quality filter cake, reducing equivalent circulating density (ECD) and maintaining pipe movement to avoid differential sticking. In some cases it may also be necessary to alter the wellbore trajectory in order to increase the drilling margin. In normally faulted environments, hoop stresses and fracture initiation pressures are reduced at high inclination angles, and industry wide wellbore strengthening efforts (e.g., stress caging) have often had mixed or negligible results. Maintaining a thin but tough filter cake, while establishing an optimal lost circulation material (LCM) concentration, is an important first step for ensuring that breakdown pressures in depleted sands are as high as possible, and that differential sticking is minimized. Too small a concentration of LCM will provide inadequate wellbore to formation isolation, while excessive LCM concentrations unnecessarily increase ECDs. Furthermore, for many formations drilled at high inclination angles, the mud weight required to ensure wellbore stability is often greater than for a vertical wellbore. Since high inclination angles are often unavoidable, particularly for centralized offshore platform development drilling, a number of ECD reducing techniques have been developed. Managed pressure drilling (MPD) techniques, including “constant bottomhole pressure” drilling, allow for lower mud weights to be utilized in a closed system, with a portion of the total required mud column equivalent pressure held by the surface equipment. When drilling fluid circulation is established, the surface pressure can be reduced to account for all or most of the annulus friction pressure, which generates ECD above the static mud weight.

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SO-1

Drilling coalbed methane formations

Coalbed methane, or CBM, formations are comprised of a series of coal stringers that range anywhere from 1 ft thick to as much as 30 ft thick. Depending on the environment in which the coal was deposited, the interval can contain from one or two to as many as five to seven stringers. Coalbeds are normally bound by sandstone and shale stringers within the formation that contains the coal. Coal formations are considered to be a porous and “friable” (easily crumbled) formation. Although fracture gradients can be as high as 23 ppg, lost circulation situations can still occur when drilling through this formation because of the nature of its porosity. Depending on the area, coalbeds can be either overpressured or underpressured and different grades are encountered ranging in appearance anywhere from a bright luster to a dull gray. CBM wells are considered a non-conventional formation and typically produce higher volumes of water initially.

History

In the past, as other deeper formations were being sought, the coal was seen as just a formation to get through. Early on many saw extremely high pressures while going through the coal requiring very high mud weights. Some early coal wells produced as much as 20 mmscf/day. The first coal wells drilled were completed using a slotted or perforated liner across the coal section and were allowed to free flow. The wells were typically vertical and later on the wells were either hydraulically fracture stimulated or completed by cavitation – pressuring up the formation with air and allowing it to surge back into a flow-back pit or tank causing the formation to crumble.

Drilling CBM wells

Today, CBM wells are drilled either vertically or horizontally and can be drilled with either roller cone or PDC type bits. Vertical drilling coal is in a practical sense no different than drilling any other vertical well. The main difference is that a drilling break will occur when the coal is encountered. The ROP will suddenly increase as the bit enters the coal with the same WOB as was applied through the shale and sandstone above it. Depending on the coal environment, it is possible to see minor gas kicks when drilling into the coal. Typically a standard low solids non-dispersed, or LSND, mud system can be used for drilling vertical wells. The other form of drilling CBM wells that has been most recently adopted, especially in the US, is by directional and horizontal drilling. When drilling these wells, the operating parameters are much the same as any other vertical well when drilling to the kick off point and when drilling and landing the curve section. In a situation where the coal is over-pressured, a natural (unstimulated) completion is used. A clear drilling

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SO-2

SPECIAL OPERATIONS

fluid is best used to drill the lateral in the coal when the well is to be completed naturally. It has proven to be a best practice to use weighted brine water using KCL, NaCl, or CaCl2 to achieve the required densities and simple starches to gain the viscosities needed for solids carrying. Mud weights range, while drilling over-pressured laterals in the coal, from 9.5 ppg to as high as 11.0 ppg. Even though fracture gradients can be high, as mentioned earlier, when drilling the coal it is as though it is “hydraulically mined” more than drilled. The jetting action caused by the bit and circulating rates that are too high can create excessively high ECDs and can wash out the wellbore causing larger than normal hole diameters. When the hole becomes enlarged, cuttings are often not properly carried to surface and it may require periodic clean outs by pulling the bit off bottom a predetermined distance, rotating the drillstring at a higher rpm while slightly increasing pump rates to clean out the additional cuttings. Drilling horizontal laterals in coal stringers is time sensitive. The typical allowable timeframe ranges from 5-7 days of being in the lateral including drilling, making bit trips, etc. So, if for any reason the lateral is not finished in that time, the wellbore may begin to exhibit signs of instability and sloughing that will eventually cause a stuck pipe problem, regardless of whether TD is reached. The longer the lateral, the more likely this event is to occur. Many times it is very beneficial to use PWD (pressure-while-drilling), equipment within the BHA, to help identify any problems that may be occurring. The completion method used after the lateral is drilled is to run a pre-perfed/slotted liner or a conventional liner and pinpoint perforated with coil tubing.

Summary

Coalbed Methane wells have proven to be a very good source of gas. It is considered to be a non-conventional formation, which means that some special considerations need to be addressed when drilling it. These are: • The structure of the coal itself can allow lost circulation to occur; • High pressures may cause minor gas kicks when entering the coalbed itself; • A drilling fluid should be used that will not damage the natural fractures of the coal for a natural completion; • There is an increasing risk of wellbore instability the longer the hole stays open. The maximum exposure time before serious instability occurs varies somewhat with location but is usually in the range of 5-7 days; • Hydraulics can be very important since the friable nature of coal can result in an enlarged borehole making hole cleaning difficult.

IADC Drilling Manual

Drilling permafrost based on North Slope Alaska experience Well design considerations

Well conductors are generally pre-set prior to the drilling rig’s arrival to a depth of 80 ft. Development drilling applications use a 16-in. or 20-in. conductor depending on the actual well & casing design. Long term development scenarios where close well spacing and thaw bulb development could result in possible melting permafrost should consider insulated conductors (30 in. x 16 in. or 34 in. x 20 in.) and thermosyphon to mitigate subsidence issues. The conductor hole is augured to a depth of 80 ft and the conductor is lowered in by crane. Cement is the pumped into the conductor x conductor hole annulus from the bottom up. This cement should be pumped in two stages after tacking the bottom to prevent u-tubing the conductor off depth. Well designs for development wells should consider the effects of permafrost melting over the life cycle of the well and the resultant subsidence effects developing severe compression loads when selecting surface casing weights, grades and connections. Permafrost intervals can range from sand to course gravel entrained within an ice matrix. The intervals are relatively soft and drill fast with standard 3-cone rock bit on mud motors. Directional drilling practices have advanced over the years where directional wells can routinely kick off at depths up to 250 ft TVD. Mud motors with bent housings using AKO setting from 0.5-2° depending on the required doglegs are standard for drilling surface hole intervals. Excessive circulation through mud motors can impart high heat losses to the wellbore and mud system accelerating melting of the permafrost and causing gravels entrained in the ice matrix to run. Efforts should be made to drill the interval as quickly as practical to minimize heat loss to the wellbore.

Common fluids systems used for Arctic drilling Spud mud

A freshwater, high-viscosity bentonite spud mud is typically used to drill the surface hole. This provides the needed viscosity for carrying capacity and solids suspension while drilling gravels and sands through the permafrost sections. The fluid consists of approximately 25-lb/bbl bentonite hydrated in cold fresh water. Just prior to drilling, the funnel viscosity is increased to 200-300 sec/qt by adding a small amount of polymeric bentonite extender. (For reference, fresh water has a funnel viscosity of 26 sec/qt). Problems encountered in the surface interval are usually poor hole cleaning due to running gravels / sands or sticky, balled up clay cuttings. Keeping the mud as cold as possible

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SO-3

with additions of cold water helps minimize thawing of the permafrost, which holds the gravel in place. Surfactants are used successfully to eliminate clay balling.

produce water at temperatures less than boiling and without artesian flow at the surface; however, some will be hotter or will flow.

Hydrates are sometimes drilled and can cause problems when they break out as methane gas at the surface. Once the drilled hydrates have been circulated out the problem usually stops. Additional mud weight, lecithin, and slow ROP have all been tried with varying degrees of success.

Blowout preventers and other safety equipment are not usually required by governing bodies; however, this does not mean that there are not significant safety considerations that should be addressed. Many of the wells have water above 140°F, and this will scald. Public and drilling crew safety must be ensured; therefore, normal well control equipment should be utilized during all drilling operations.

Recently, mixed metal oxide (MMO) and mixed metal silicate (MMS) drilling fluid systems have been used successfully to drill troublesome surface holes where thawing permafrost has caused increased instability in the gravel and sand sections. The unique rheological properties of these systems provides a highly shear thinning fluid with exceptional hole cleaning and cuttings suspension properties and also seems to reduce fluid loss in unconsolidated surface gravel.

Surface casing and cements

Arctic cementing presents some unique challenges. The first being the low temperatures of the permafrost, and the second being the unconsolidated nature of the permafrost. The fracture gradient across permafrost intervals on Alaska’s North Slope is generally taken to be 12.5 ppg. A lightweight lead cement is used in conjunction with a 15.8 ppg class G tail to keep ECDs down and lower the density of the fluid column. The lead slurry is generally mixed to approximately 11 ppg. For freeze protection, both lead and tail have salt in them. The fluid column is generally 500 ft of tail cement at the shoe with the rest of the fluid in the annulus being lead slurry. A proper spacer is pumped ahead of the lead slurry to help remove the mud filter cake. The permafrost has a tendency to melt very easily while drilling, and because it is unconsolidated, enormous washouts are common. Common practice on Alaska’s North Slope is to use 250% excess cement in the permafrost section (usually about 0-1,500 ft TVD) and 50% excess cement below the permafrost. This excess can increase even more if excessive circulation or other unforeseen circumstances occur. Conductors set and cemented in permafrost require a blend that is able to hydrate quickly at the low permafrost temperatures and can gain approximately 1,000 psi compressive strength in 5-8 hours. The blend may contain salt, which lowers the freezing point of water to below permafrost temperatures, ensuring that the water in the cement slurry will not freeze before the cement has a chance to hydrate.

Geothermal wells

Most geothermal wells can be drilled using conventional water well technology and equipment. Most of the wells will

IADC Drilling Manual

Lost circulation is the loss of drilling fluid from the borehole through cracks, crevices, or porous formations. It can be partial or complete, depending on the conditions. When circulation is lost, the drilling fluid is not performing one of its major functions, that of transporting the cuttings up the hole where they can be released in the mud tank or pit. If the cuttings are not removed from the hole, they will pack around the drillstring above the bit, resulting in stuck pipe and possible loss of the bit, collars, part of the string and perhaps, the hole. If the formation has large cracks or crevices, the fluid may carry the cuttings into the formation and away where they cannot pack around the drillstring, but there is no way of being assured that this is the case. Drilling without circulation is also known as drilling blind. Complete loss of circulation usually results in the fluid level dropping to considerably below the surface with the resultant complete or partial loss of fluid pressure stabilizing the hole walls. This can result in cave-ins, another cause of stuck pipe. Lost circulation is probably the most important problem encountered in drilling. It results in: (1) loss of expensive fluid components, (2) loss of drilling time, (3) use of potentially expensive lost circulation materials to keep the losses from plugging possible production zones, and (4) leads to cementing problems, in addition to possible loss of equipment in the hole, as noted above. Despite the severity of the problems, most experts agree that probably half the lost circulation problems can be avoided and that many are driller induced. Proper planning and rig operation are important. Some of the techniques involved in proper planning and operation are: • Insofar as possible, use nearby well logs and geologic information, and carefully plan the hole and the casing program; • Treat the wellbore gently. Raise and lower drillstrings and casing slowly. Do not spud or swab. Start fluid pumps at slow rates and increase slowly; Maintain fluid velocity in the annulus at the lowest rate to assure

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σ1 Normal Faulting σ1 = Vertical Stress SPECIAL = Maximum Horizontal Stress σSO-4 2 = Minimum Horizontal Stress σ Normal Faulting 3 σ2 ≥ σ σ σ11 =≥Vertical Stress 3 σ2 = Maximum Horizontal Stress Minimum Horizontal Stress σ3 =Normal Faulting σ1 ≥ σ 2 ≥ σ 3 σ1 = Vertical Stress σ2 = Maximum Horizontal Stress σ3 = Minimum Horizontal Stress

σ1 ≥ σ 2 ≥ σ 3

OPERATIONS

σ1 σ3

σ1 σ3

σ2

σ3

σ2

σ2

In the Gulf of Mexico it is often assumed that σ 2=σ3 Where σ 2=σ3 stability is not affected by wellbore azimuth Where σ 2=σ3 breakouts do not occur in vertical wellbores

The typical geothermal environment can have a BHT = 475°F with approximately 10 ppm H2S , 500 ppm CO2, and a producing water consists of 10,000 chlorides with about 26 ppm sulfate and 13 ppm bicarbonate. Laboratory simulations conducted at a chemical research and development centre indicate that drilling without the proper corrosion management program will result in excessive corrosion (> 11 lb/sq ft/yr) and severe pitting.

3 Figure SO-1: Normal faulting occursσwhen a block of rock moves down, relative to its surroundings.

Reverse (Thrust) Faulting σ3

σ1 = Maximum Horizontal Stress σ2 = Minimum Horizontal Stress Reverse (Thrust) Faulting = Vertical Stress σ 3

σ1

σ3

σ σ2 ≥ σ3 Horizontal Stress σ11 =≥Maximum σ2 = Minimum Horizontal Stress σ3 = Vertical Stress Reverse (Thrust) Faulting σ2 σ1 ≥ σ 2 ≥ σ 3 σ1 = Maximum Horizontal Stress σ2 = Minimum Horizontal Stress σ3 = Vertical Stress σ2 σ1 ≥ σ 2 ≥ σ 3

Corrosion is a major concern when drilling in a geothermal environment, especially when using compressed air. The combination of extreme temperatures, pressures, acid gases, and high oxygen content (from compressed air) can lead to severe corrosion and potential tubing/drillpipe failure without a proper corrosion management program.

σ1

σ1

Overburden represents the minimum principal stress

Figure SO-2: When aσ2block of rock has been forced up relative to its surroundings, it is referred to as “reverse” or “thrust” faulting.

By ensuring and implementing the proper corrosion chemistry, field results indicate lower corrosion rates, less metal loss, and no damage to downhole tubulars may be realized. Not only does this program lower drilling cost by protecting the downhole tubulars, but also more importantly, it provides a safer drilling environment for field personnel.

σ2

Drilling faults

Strike-Slip Faulting σ2

σ1 = Maximum Horizontal Stress σ2 = Vertical Stress = Minimum Horizontal Stress σ Strike-Slip Faulting 3

σ3

σ3 σ σ2 ≥ σ3 Horizontal Stress σ11 =≥Maximum σ1 σ2 σ2 = Vertical Stress Overburden represents the immediate principal stress σ3 = Minimum Horizontal Stress Strike-Slip Faulting σ3 σ1 ≥ σ 2 ≥ σ 3 σ1 σ1 = Maximum Horizontal Stress σ2 = Vertical Stress Figure SO-3: In “strike-slip” faulting, a block of rock will σ3 = Minimum Horizontal Stress

σ3 σ1 ≥ σ 2 ≥ σ 3

move laterally relative to the adjacent rocks. σ1

cuttings removal. Do not drill so fast as to overload the annulus with cuttings. • Make frequent measurements of mud properties to maintain minimum weight, viscosity, and filtration. Air drilling (aerated fluid) is a technique often used in drilling geothermal wells. This technique uses a compressible fluid to lighten the equivalent circulating density (ECD) of the drilling mud and allow fluid and cuttings to be transported to surface.

IADC Drilling Manual

σ3

σ3

Faults are breaks in the earth where a block of rock has moved relative to surrounding formations. If the block has moved down relative to its surroundings, it is called a “normal” fault. If it has been forced up relative to its surroundings, it is called a “reverse” or “thrust” fault. If it moved laterally relative to the adjacent rocks it is called a “strike-slip” fault. See Figures SO-1, -2 and -3.

Since faults are a result of the presence of stress in the rock, borehole stability is sometimes an issue in areas where faults are present. If the fault does not form a seal, loss of circulation can result, especially if a rubble zone results from the rocks moving against each other. If a seal is formed by a fault, the displacement of the rocks can result in formations that were originally deeper and containing higher pressure being lifted and encountered at a shallower depth. If encountered unexpectedly, crossing a fault can result in a well control issue. Crossing a sealing fault can also result in crossing into a zone of lower formation pressure, which may cause differential sticking or mud losses. Bed dips of-

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SPECIAL OPERATIONS

ten change dramatically as a fault is approached, and deviation from a planned trajectory can increase with proximity to the fault. The fault interface can also act as a whipstock and create a sudden change in wellbore orientation as a drill bit penetrates it. Crossing a fault might not cause any problems or give any indication that any has occurred. However, it can also have serious consequences. Therefore, it is very important to exercise caution when approaching a known fault and to alert the company man when it is suspected that a fault has been encountered, whether anticipated or not. Indications of encountering a fault can include: • Sudden erratic torque; • Sudden difficulty in maintaining tool face if directional drilling; • Changes in drilling parameters indicating change in formation type; • Mud losses; • Kicks. Drilling faults may have any result from absolutely no effect to serious wellbore stability or well control issues. The appropriate response may range from continuing to drill ahead with no action, to picking up off bottom, making sure the pipe is free, checking for flow, and circulating bottoms up to check samples and mud log shows. It is advisable to discuss with the company man ahead of time what the desired response will be if a fault is encountered.

Solid expandable liner technology

Expandable technology is used to maximize the passthrough ID of the final casing string by minimizing or eliminating the reduction in hole size that results from having a large number of casing strings in the well design. The process of swaging expands the casing used into a larger size. Solid expandable liners are enlarged using cone expansion. This is a cold working process in which a swage-like expansion cone is pumped and/or pulled through the casing, stretching it beyond its elastic limit, or yield point, but without exeeding the ultimate, or failure, limit. The process permanently deforms the pipe without breaking it, increases its yield strength, and decreases the ductility of the metal. Solid expandable liners allow the operator to run more strings of casing without losing as much hole size making it possible to run larger production casing at TD.

Improve well architecture

• Downsize the hole: Solid expandable systems can be used to downsize parts of the well, saving time and money; • Maximize production string size: By using smaller

IADC Drilling Manual

1

2

3

SO-5

1

2 1: Unexpanded pipe 2: Expansion cone 3: Expanded pipe

3

Figure SO-4: A solid expansion cone is the most widely used means to swage and expand pipe. Usually the cone is deployed in a launcher or cone housing at the bottom of the expandable liner. Once the expandable liner reaches the desired setting depth, the cone is pumped from the bottom up, expanding pipe as it travels.

casing to wellbore clearances, it is possible to increase hole size in the target reservoir and upsize the completion.

Mitigate hazards

Adding additional casing strings to overcome lost circulation zones can make it impossible to reach TD with a completion that is large enough to realize the well’s full potential. Expandable liners allows setting casing across the loss zone, but still allows the operator to reach TD with a larger casing size. Wellbore Instability is a common drilling problem that can result in significant non-productive time (NPT) or even loss of hole section. Expandable liners isolate the problem zone behind a solid steel barrier, keeping the formation from sloughing in. Over-pressured formations might require setting an extra casing string. The use of expandables sometimes makes it possible to do this and still preserve hole size.

Components of solid expandable liners

• Tubulars for solid expandable system are made from malleable grades of pipe made to tighter tolerances than normal casing with thicknesses allowing for expansion at reasonable forces; • Elastomers are primarily used to seal into host casing and provide zonal isolation in cased hole situations; • Lubrication is a critical part of expanding pipe. Without reducing friction, the cone could become stuck during

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SPECIAL OPERATIONS

Running sequence 1. 2. 3. 4. 5. 6.

Drill hole section and underream, if necessary; Make up expandable liner, and hang in rotary; Stab in work string and run to depth; Drop dart (if required) and pump cement; Drop second dart and pressure up to expand liner; Pull out work string as expansion cone moves up the hole; 7. Cone exits top of liner using rig overpull; finish pulling work string out of the hole; 8. Drill out shoe if required and continue rig operations.

Open-hole fishing operations

In fishing operations, an assessment of the problem and a plan for resolving the problem are paramount. A response is required as quickly and as efficiently as possible so that productive operations can resume. Precise planning, coordination, and execution of the fishing operations are the key to a successful operation.

Job planning

Figure SO-5: Key steps in running expandable casing.

 Drill and underream hole section.  Make up expandable liner, and hang in rotary.  Stab in work string and run to depth.  (Pump cement if required) Drop dart and pressure up to expand liner.

 Cone exits top of liner using rig overpull.

 Drill out shoe if required and continue rig operations. expansion or gall the inside of the liner. Expandable liners are coated with a lubricating material to reduce friction during the expansion process; • Connections are another critical component of solid expandable systems. They normally are the limiting factor of expanding tubulars. Expandable connections are required to hold pressure before and during the expansion process. After expansion, the threads are distorted, but the expandable must still hold pressure; • A solid Expansion Cone is the most accepted, utilized, and reliable method of swaging and expanding pipe. Typically the cone is deployed in a launcher or cone housing at the bottom of the expandable liner. Once the expandable liner reaches the desired setting depth, the cone is pumped from the bottom up, expanding pipe as it travels.

IADC Drilling Manual

Prior to commencement of fishing operations, gather information: • Casing details: »»Casing sizes and weights: Note any mixed casing weights; »»Depth of the casing shoe: Back-off of a stuck bottomhole assembly (BHA) close to the casing shoe could have disastrous results. • Hole details: »»Hole size; »»Angle; »»Depths: • Total depth; • Measured depth; • Doglegs; »»Washed-out sections; »»Low-pressure formations. • BHA and drilling/work string details: »»All tools should be calipered precisely; »»Outer diameter (OD); »»Inner diameter (ID); »»Fishing neck OD; »»•Length of fishing neck; »»All tensile and torsional strengths. • Drilling jar details: »»Are there jars in the hole and are they working; »»Where are the jars placed in the string; »»Do the jars operate mechanically or hydraulically; »»What is the maximum jarring load. • Mud details.Mud properties help determine why the pipe is stuck: »»Additives can reduce friction in the string;

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SPECIAL OPERATIONS »»Additives can help carry the cuttings to surface. • Operations in process at time of incident: »»Pipe motion prior to sticking will provide a good clue as to why the pipe is stuck; »»Tripping in-hole; »»Tripping out of hole; »»Reaming in-hole; »»Reaming out of hole; »»Circulation rates before and after incident; »»Jar on stuck pipe in the opposite direction from how the pipe was moving prior to sticking. • Fish details: »»OD, ID, length, and condition of fish; »»Make use of the composite catalogs, technical manuals, and manufacturers’ drawings; »»Have an exact replica of the fish on location, if possible; »»Always know where the top of the fish is; »»Never rotate the fish out of the hole.

Stuck-pipe mechanisms

The openhole environment presents a degree of uncertainty that carries a high risk of stuck pipe. Even with a large selection of tools, openhole fishing offers the challenge of an infinite number of formation variables. Because of the wide range of formations, local experience becomes very valuable in openhole fishing. In open-hole fishing, the primary problems encountered are related to the mud or the formation. The key to freeing stuck pipe successfully and with a minimum amount of time is to first ascertain where and how the pipe became stuck, and secondly, attempt to free it in a systematic and economical manner. In every situation, the cause of the sticking must be identified before taking any action, enabling the best fishing method to be determined and avoiding additional tools getting stuck in the hole.

Differential sticking

• Hydrostatic mud pressure in the wellbore is greater than the formation opposite the stuck pipe interval; • Formation opposite the stuck-point interval is usually porous and a permeable sand, limestone, or dolomite; • A thick, poor filter cake has built up across the formation; • Pipe is left stationary, creating a large contact area against the formation; • Pipe cannot be reciprocated or rotated, circulation at normal standpipe pressure is possible; • Possible mud loss prior to becoming stuck; • Freeing pipe from being differentially stuck: »»“U” tube technique; »»Spot diesel oil to reduce the hydrostatic pressure;

IADC Drilling Manual

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»»Drillstem test-tool technique (setting the packer, the hydrostatic pressure is lowered below the packer); »»Spot pipe-free solutions around stuck BHA; »»Run free-point and back-off from stuck pipe; »»Jar on stuck BHA; »»Washover BHA.

Sloughing shale

• Circulation is either greatly reduced or impossible; • Unable to engage the Kelly-drive bushing after picking up a new joint due to hole fill; • Cannot slack the bit off without the rotary and the pump; • Shale shaker shows that shale is being produced from the hole; • Pump-pressure increase or packing off; • Freeing pipe from being stuck by sloughing shale: »»Run free-point and back off from stuck pipe; »»Stabilize hole conditions; »»Trip bit to clean and stabilize hole conditionJar on stuck BHA; »»Washover BHA.

Key seating

• Pipe tube wears a groove in the hole wall at a dogleg; • BHA is larger so will not pass through when POOH; • Can go down and pipe will rotate freely but cannot pull up; • Have full circulation; • Freeing pipe from keyseat: »»Pull into the keyseat to hold the pipe; »»Run a free point and backoff above the keyseat; »»TIH with keyseat wiper one joint above screw in sub, jarring BHA, and screw into fish; »»Jar down to free fish and wipe out key seat with keyseat wiper; »»Consider running keyseat wiper on future trips above BHA to prevent a repeat of the problem.

Blowout sticking

• In a blowout sticking situation, there is typically bridging and more than one stuck interval. Sand and shale that has blown up the hole will settle out around the tool joints, stabilizers, and other large-OD tools; • A stuck-pipe log is usually run to determine the best fishing procedures: • Freeing pipe from being stuck as a result of blowout: »»Run free-point and back off from stuck pipe; »»Stabilize hole conditions (trip bit to clean and stabilize hole conditions); »»Jar on stuck BHA; »»Washover BHA.

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SPECIAL OPERATIONS

Undergauged hole sticking

• Running in-hole with a new bit at high speeds is the usual cause of being stuck in an under-gauged hole: • Freeing pipe stuck in an under-gauged hole: »»Run free-point and back off from stuck pipe; »»Jar on stuck BHA (If the stuck point is at the bit, initiate UP jarring operations only); »»Washover BHA.

Lost-circulation sticking

• Lost-circulation sticking occurs when the string sticks after losing returns, causing the hole to fall in; • Freeing stuck pipe from lost circulation: »»Run free-point and back off from stuck pipe; »»Stabilize hole conditions (trip bit to clean and stabilize hole conditions); »»Jar on stuck BHA; »»Washover BHA,

Mechanical sticking

Mechanical sticking occurs when there are: • Foreign objects in hole: »»Junk, such as bolts, slip dies, tong parts, hammers, chains, etc; • Crooked/corkscrewed drillpipe: »»If the drillstring is not able to be pulled, serious fishing problems can develop; • Freeing mechanically stuck pipe: »»Run free-point and back off from stuck pipe; »»Stabilize hole conditions (trip bit to clean and stabilize hole conditions); »»Jar on stuck BHA; »»Washover BHA.

Estimated stuck point

The estimated stuck point (ESP) is the point at which all pipe below is stuck and all pipe above is free. The stuck point is also referred to as the estimated free point (EFP). The formulas used to determine the stuck point will only give an approximation of the depth at which the pipe is stuck and only in a vertical hole, but a wireline free-point indicator will give you an exact depth of the stuck point.

String stretch formula

Feet of free pipe = 1,000,000 × inches of stretch K × pounds of overpull

For collared pipe: K = 1.4 ÷ weight of the pipe per foot For integral-joint tubing or drillpipe: K = 1.5 ÷ weight of the pipe per foot

IADC Drilling Manual

The example shown in Table SO-1 illustrates the stretch formula. A drilling string at a depth of 10,000 ft is stuck. The drillpipe that is stuck is 4 1/2-in. and 16.60 lb/ft, and the string weight is 166,000 lb. The maximum pull on the drillstring is 246,000 lb (80,000 lb of which is overpull). The stretch length is 49 in.

Table SO-1: Example calculation using stretch formula Step

Action

Example

1

Determine the value of the variable K

K = 1.5/16.6 = 0.0904

2

Multiply the inches of stretch by 1,000,000

49 in. × 1,000,000 = 49,000,000

3

Multiple the value of K by the number of pounds of overpull

0.0904 x 80,000 = 7,232

4

Divide the result of step 2 by the result of step 3. The result is the amount of free pipe

49,000,000/7,232 = 6,775 ft of free pipe

Electric-wireline pipe recovery

Electric-wireline pipe-recovery work has become a technical, scientific service that requires specialized, competent, and highly trained personnel. A free point and back off or cut is used to recover the portion of pipe that is free to allow fishing operations to proceed on the stuck portion of the pipe.

Free-point indicator

• Readings provide a measure of pipe movement due to surface-applied stretch and/or torque; • The readings provide a pipe-movement profile that can be interpreted to indicate the depth at which pipe can be effectively recovered; • A free-point tool will indicate only the uppermost free-point in a pipe string.

Separating or backing off pipe in the wellbore String-shot back off

• The connection to be backed off is selected with a collar location (CCL), left hand torque applied, and backing off is accomplished with the aid of a string-shot charge; • The string-shot charge consists of a job-specific quantity of detonating cord strung on a shot rod that is electrically detonated when positioned at the desired connection.

Chemical cutters

• The chemical cut is accomplished with controlled high-pressure radial dispersion of bromine trifluoride; • A chemical cutter is the preferred method for parting tubing, because it does not flare the top of the fish;

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• Chemical cutters leave no debris in the wellbore and will not damage adjacent casing strings; • Parting the pipe with a chemical cutter is successful in approximately 85% of uses; • It will not cut coated or chrome pipe.

Radial cutting torch

• A plasma cutting device that overcomes many of the disadvantage of other cutting tools: • A nonexplosive, flammable solid; • Can be transported without special requirements, including on passenger flights; • Does not flare the top of the fish; • Leaves no debris in the wellbore and will not damage adjacent casing strings; • Cuts alloy, plastic-lined, and scaled pipe; • Passes through restrictions cutting larger pipe below the restriction; • operable in high pressures and temperatures to 500°F .

Jet cutters

• Used when a back-off or chemical cutter is not an option or has been tried unsuccessfully; • Always a risk of adjacent string damage; • Available in sizes between 1.156- and 12-in. OD; • Able to cut tubulars in sizes between 1.660 in. and 13.375 in.

Severing tools

• The severing tool is used for drillpipe, Hevi-Wate drillpipe, and drill collars, and is only used in open holes to abandon the wellbore; • The severing tool will cut wall thicknesses that conventional cutters cannot sever and is able to go through small restrictions; • Sizes available range from 1 3/8-in. to 2 5/8-in. OD; • A 2 5/8-in. tool will sever up to 11-in. OD drill collars.

Washover operations

Washover operations are done in open holes to cut the formation or to mill a fishing neck, junk or any obstruction away from the outside of a fish to free the fish for recovery.

Rotary-shoe selection

• Tooth-type or scallop-bottom rotary shoes are best for all formations; • Flat-bottom or scallop-bottom rotary shoes are used to mill stabilizers, reamers, and tool joints; • Rotary shoe rough OD is normally 1/8 in. under bit size: • Rough OD for openhole, smooth OD for cased-hole; • Rotary shoe ID – dressed rough to cut clearance: • When milling over fish to create a fishing neck, the ID of

IADC Drilling Manual

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the rotary shoe must not be larger than the maximum catch of overshot to be run for recovery.

Pipe-size selection

• Minimum size to cover fish with adequate room for circulation: • Preferred ID clearance is 1/4 in. larger than fish OD; • Preferred OD clearance is 1/2 in. smaller than the hole size; • Length of washpipe to be used is determined by: • Hole conditions; • Clearances; • OD of fish; • Length of the fish.

Mud properties for fishing and washover

• • • • • • • • • •

Weight: Maintain well control; Stop shale sloughing. Viscosity: 4 times mud weight ; Yield point (YP) equal to mud weight if drilling; Must be 20 to wash over; Must be 30+ to mill. Water loss Hard formation = 10; Unconsolidated sand = 5 or below.

Freeing stuck pipe with acid

• If pipe gets stuck in a carbonate, HCL can be spotted around the stuck point and allowed to soak, dissolving the formation; • HCL should not be used in the presence of hydrocarbons to prevent the formation of flammable gas.

Jarring operations

Jarring is the process of transforming energy stored as stretch in a fishing string into kinetic energy. A correctly placed jarring assembly using a jarring program can free most stuck tool strings. Fishing jars are available in a wide range of sizes, and most are full opening to allow for fluid circulation and for wireline tools to pass through them without reducing fishing options.

Fishing bumper sub

• Mechanical or lubricated; • Used for jarring down: • Aids in the release of attachment tools (overshot or spears); • Jars down on a fish to free it; • Provides a means to move the work string with 18–in. of free movement: • Helps to get over the top of a fish; • Compensates for rig movement on floating rigs.

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Hydraulic fishing jars

• A straight pull-up jarring tool with no setting or adjustment required before going in the hole or after the fish is engaged: • Straight push/pull operation; • Hydraulic time delay with a mechanical triggering device; • Variable tripping loads; • Consistent time delay. • Controlling the jarring intensity: Varying the applied pull load controls the intensity of the jarring impact; • Frequency of blows: The operator can deliver a rapid series of blows when desired. The operator fully controls the frequency of successive blow.

Fishing accelerator/intensifier/slinger jar Figure SO-6: Screw-in sub.

• Provides the means to store the required energy immediately above the hydraulic fishing jar and drill collars; • Offsets the loss of stretch or drag on the fishing string, especially at shallow depths; • Prevents shock from being applied to the running string and surface equipment as the string rebounds after each jar stroke.

Surface jar

Figure SO-7: Full-strength 150 overshot.

• Designed to be installed in the drillstring at surface; • Delivers sharp, downward impact or jarring blows against the fish at its stuck point; • Surface jars can be adjusted to deliver light blows or very-high-impact blows; • Used to initiate abrupt jarring blows down the string to actuate bumper subs more efficiently; • Surface jarring operations are limited to depth and should not be used on a stuck work string deeper than 3,500 ft; • Severe damage may occur to stuck work string with prolonged downward jarring operations.

Attachment tools for fishing parted pipe

There are many opinions of how to fish parted pipe from a wellbore. The condition of the fish needs to be accurately assessed to determine the best attachment tool to use for the fishing of the parted pipe. The following fishing tools are listed in order from the most efficient to the least efficient to run for fishing parted pipe.

Screw-in sub

Figure SO-8: Casing/tubing spear.

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If there is a usable tool-joint connection looking up, the preferred method for engaging a fish is to screw into the fish with a screw-in sub, joint of drillpipe, or drill collar below the fishing jar assembly. This is the most reliable method of solid engagement (Figure SO-6).

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SPECIAL OPERATIONS

Advantages of screwing into the fish include: • The screw-in point has the sa me or higher mechanical strength th an the fish; • The ID is full-opening for full circulating capabilities and for wireline operations; • Full torque capabilities; • Full jarring capabilities.

Full-strength series 150 overshot

Whenever a fish needs to be externally engaged, the fullstrength series 150 overshot is the best tool for externally engaging the fish. At times it may be necessary to use variations such as a Short Catch, Extra Full strength, Semi Full Strength, Slim Hole or Extra Slim hole overshot (Figure SO6). Figure SO-9: Box tap.

Advantages and disadvantages of running an overshot to engage a fish: • ID large enough for wireline operations and circulation capabilities, with the circulation capabilities limited to the pressure rating of the overshot packoff; • Limited torque capabilities; • Full jarring capabilities; • Releasable with right-hand rotation; • Dressing off the top and engaging the fish in one run if a mill control is used.

Casing/tubing spear

The preferred tool to fish inside drillpipe, tubing, or casing is the releasing spear. The casing/tubing spear is designed to ensure positive internal engagement with a fish. Built to withstand severe jarring and pulling strains, the casing/tubing spear engages the fish over a large area without damage to or distortion of the fish (Figure SO-8).

Figure SO-10: Taper tap.

Advantages and disadvantages of running a casing/tubing spear to engage a fish: • Limited wireline operations – dependent on ID of spear; • Limited circulation capabilities; • Limited torque capabilities; • Full jarring capabilities (may need a spear stop to allow cocking the jars); • Most spears are releasable with right-hand rotation.

Box and taper taps

Box taps are attachment tools that screw onto the OD of a fish and the taper tap is an attachment tool that screws into the ID of a fish, Box taps have threads on the ID, which cut threads into the OD of the fish, externally engaging the pipe. Box taps are used to retrieve an irregularly sized fish or a fish with an unknown OD (Figure SO-9). Figure SO-11: Fishing magnet.

Taper taps have threads on the OD, which cut threads into

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SPECIAL OPERATIONS

the ID of the fish. They internally engage the fish, inhibiting circulation through the fish (Figure SO-10). Box and taper taps are not typically recommended because they are not releasable. For that reason, a safety joint should always be run immediately above a box or taper tap; Advantages and disadvantages of running a box or a taper tap to engage a fish include: • Box taps: »»ID large enough for wireline operations; »»Limited torque capabilities; »»Limited jarring capabilities; »»Limited circulation capabilities; »»Not releasable. • Taper taps: »»ID does not allow wireline tools to pass through; »»Brittle and may break in jarring operations; »»Not releasable; »»Limited torque capabilities; »»Limited jarring capabilities; »»Limited circulation capabilities.

Figure SO-12: Junk mill.

Fishing for junk

Any undesirable object that is stuck, accidentally dropped or left in a well bore is referred to as “junk.” Junk may include bit cones, tong dies, broken slips, reamer parts or debris created by a previous drilling, fishing or milling operation, or any other small debris that could impede normal drilling operations. A boot basket is often run in conjunction with a magnet, or other junk recovery tool.

Fishing magnets Figure SO-13: Globe-type junk baskets.

Fishing magnets are primarily used to pick up bit cones, but they can pick up all types of small objects with magnetic properties (Figure SO-11).

Junk mills

Junk mills mill up and break up large pieces of junk into smaller pieces that can be recovered in a boot basket. They provide the surest method for eliminating junk in the wellbore (Figure SO-12).

Globe-type junk baskets

Globe-type junk baskets are used to recover any small piece of junk that in the wellbore. The successful operation of the tool requires that a core be cut from the formation. Any junk will be recovered above the core. The globe-type junk basket is recommended when performing fishing operations in soft to medium formations (Figure SO-13).

Reverse-circulating junk baskets Figure SO-14: : Reverse-circulating junk baskets.

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A reverse-circulating junk basket uses the force of a vacuum created inside the tool to pull the junk up into the basket

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(Figure SO-14). A ball is dropped into the drillstring, thereby initiating the reverse-circulation process. The ball needs to be measured to make sure it will pass through the string to the basket. Pumping mud through the jets produces a vacuum inside the barrel, sucking mud up into the basket. Mud deficiency in the barrel will be replenished by mud entering from below, carrying any junk with it, which will be trapped above the finger catchers. Because cutting a core is not required to recover the junk when using the reverse-circulating junk basket, this type of basket is commonly used in hard formations.

1. 2.

Secure and cut the cable; Strip over it with an Overshot attached to the drillpipe while holding the wireline that is being stripped in maximum tension; 3. When the logging tool is reached, the overshot is lowered over the logging tool until the grapple is engaged; 4. Once this is completed and the tools pulled free with the drillpipe, the wireline is pulled out of the Logging Tool’s Rope Socket; 5. The cable is spooled onto the truck and the drillstring POOH with the logging tools.

Open-hole logging tools

The surest method of recovering stuck wireline tools is to strip over the line with an overshot:

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IADC Technical Resources

IADC TECHNICAL RESOURCES ENHANCES RIG CREW EXPERTISE

IADC brings the collective knowledge and experience of the global drilling industry to the workforce through industry-developed print, electronic and multimedia tools and resources accessible in one convenient location. From books to industry news to manuals and more—IADC is the definitive source. The Technical Resources Center contains a variety of items, including: • IADC Bookstore and e-Bookstore: textbooks, guidelines, checklists, model contracts and more. • Online Safety Toolbox: Safety Alerts, safety meeting topics, near hit/miss forms and safety posters. • Knowledge, Skill & Ability (KSA) Competencies Database: filter competencies based on various criteria and generate a unique set of KSAs for each type of position on a rig. • Industry news: quick access to Drilling Contractor magazine and IADC Drill Bits newsletter. • Reports: Onshore and Offshore US Federal Regulatory Summaries and the International Regulatory Summary provide easy to access updated information on industry regulation.

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STRUCTURES AND LAND RIG MOBILIZATION

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CHAPTER

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he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. PRINCIPAL AUTHORS Steven Ancelet, Loadmaster Derrick & Equipment, Inc. Elsa Atarod, National Oilwell Varco Marcus McCoo, National Oilwell Varco Christopher Haist, Integrated Drilling Equipment, Inc. Clint Harris, Comal Design Group Gilberto Gallo, Drillmec Drilling Technologies Josh Sprague, Drillmec Drilling Technologies

PRINCIPAL AUTHORS (APPENDIX: Land Rig Mobilization) Anthony Zacniewski, Bandera Drilling Co. Inc. Daniella Kramer, Columbia Enterprises LLC Rhett Winter, IADC REVIEWERS (APPENDIX: Land Rig Mobilization) Jared Blong, Octane Energy Thad Dunham, Flat Time Reduction, LLC

REVIEWERS Steve Ellis, Lee C. Moore Tom Wingarter, Lee C. Moore Charles Vora, Veristic Dave Brooks, 5J Oilfield Services, LLC Rhett Winter, IADC

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This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9906220-7-9

Printed in the United States of America.

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STRUCTURES AND LAND RIG MOBILIZATION Contents CHAPTER ST

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Contents

STRUCTURES AND LAND RIG MOBILIZATION

Introduction..................................................................ST-1 Rig nomenclature.......................................................ST-2 Drilling structures................................................ST-5 Substructures........................................................ST-6 Derricks and masts..............................................ST-8 Common characteristics.................................ST-9 Personnel.............................................................. ST-10 Maintenance.............................................................. ST-10 Objective.............................................................. ST-10 Maintenance instructions................................. ST-11 Safety summary.................................................. ST-11 Routine inspections for maintenance............ ST-11 Periodic maintenance schedule...................... ST-11 Monthly maintenance................................ ST-12 Yearly maintenance.................................... ST-12 5-Yearly maintenance................................ ST-12 Periodic maintenance................................. ST-12 Drilling structures................................ ST-12 Guide track system.............................. ST-12 Drilling rig accessories....................... ST-12 Bolts, bolted connections, and pins...................................................... ST-13 Hoisting equipment............................. ST-13 High-pressure and other pipes......... ST-13 Personnel support devices................. ST-13 Electrical equipment........................... ST-14 Wire rope/wireline, mast raising slings, hang-off lines................................... ST-14 Wind walls, other rig and drill floor equipment............................................. ST-14 Corrections and minor repairs.......... ST-14 Major repairs and modifications.................... ST-14 Maintenance not normally performed by user......................................... ST-14 Inspections................................................................. ST-14 Qualification of personnel performing inspections..................................................... ST-15

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Pre-inspection data review............................... ST-15 Inspection categories and limitations........... ST-15 Documentation requirements......................... ST-16 Position of masts and derricks during inspections............................................... ST-18 Weld inspection performance and acceptance criteria........................................................... ST-18 Inspection of repairs and modifications...... ST-20 Inspections and nondestructive examinations.................................................. ST-21 Inspection of pad eyes, lifting eyes and pin connections..................................... ST-21 Inspection of raising lines, guy lines and wire rope................................................. ST-21 Inspection of racking platforms.....................ST-22 Inspection of substructures............................ST-22 Report documentation and record requirements.................................................ST-22 Calibration requirements.................................ST-23 Useful tools and equipment........................... ST-24 Ethics and the inspector.................................. ST-25 Safety...........................................................................ST-25 Areas of concern............................................... ST-25 Common work areas................................ ST-26 Safety tie-off points................................. ST-26 Dropped objects....................................... ST-26 Storage of drilling structures................................ ST-26 Sheave assemblies............................................ST-27 Short-term storage............................................ST-27 Offshore masts and derricks..........................ST-27 Long-term storage.............................................ST-27 Racking boards and service platforms.........ST-27 Telescoping masts.............................................ST-27 Cantilever masts............................................... ST-28 References................................................................. ST-29 Appendix: Land Rig Mobilization.........................ST-A1

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THE IADC LEXICON

D E F I N I N G T H E D R I L L I N G S PAC E ! IADC Lexicon puts critical definitions at your fingertips. Imagine thousands of the most pertinent definitions and terms relevant to drilling, all in a single convenient repository – the IADC Lexicon. The IADC Lexicon draws from the most critical legislation, regulations, standards and guidelines worldwide. The European Union requested that IADC, as the authority in the drilling space, create the Lexicon to aid in regulation and understanding our industry. Use the IADC Lexicon as a dictionary or to quickly and easily identify a relevant standard, guideline or regulation. Or, use it as a template to develop instructions for your own company.

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STRUCTURES AND LAND RIG MOBILIZATION

Introduction

Drilling structures are a very important part of the drilling rig; however, these structures are often overlooked because of their static nature. Many activities take place on the drilling rig, with most of the activity being on the drill floor. The supports for all of this activity and working drilling load are the structures. The derricks and masts are the tower structures that are the characteristic images of drilling rigs.

It is very important that these structures be well maintained. Any damage due to wear, corrosion, incidental impact or other means can have detrimental effects on the operation of the drilling rig. This can be as simple as a short shutdown time for repair or a catastrophic failure resulting in equipment damage and personal injury. Regular inspection intervals with a pre-planned procedure are essential for keeping the structure in good working condition. Oftentimes drilling

Figure ST-1: Key areas on a typical drilling rig. See associated descriptions and definitions, pp ST-2 to ST-5. Copyright IADC..

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rigs are stored for long periods. This does not exclude them from regular inspection and maintenance, or they may not be in working condition when needed. The manufacturer of the structures will also provide guidance on maintenance and inspections. However, the industry-standard guidance provided in this chapter will ensure that the structures remain in working order. Safety on the drilling rig is of utmost importance. The drill floor is a dangerous place when the rig is operating. One must always be aware of the surroundings, activities, potential overhead risks and escape paths from their location. Awareness and proper personal protective equipment (PPE) for the situation are essential to preventing injuries. The intent of this chapter is to provide a broad working knowledge of drilling structures and their function. Operation, inspection, maintenance and storage are all critical and discussed in this chapter. This chapter is intended to be used as a ready reference to assist the drilling rig operator with the structures that are critical to the drilling operation.

Rig nomenclature

1. Crown or Crown Block: The fixed set of pulleys (called sheaves) located at the top of the derrick or mast, over which the drilling line is threaded 2. Mast: The structure used to support the crown block and the drill string. Masts are usually rectangular or trapezoidal in shape and offer a very good stiffness, important to land rigs whose mast is laid down when the rig is moved. However, masts are often heavier than conventional derricks. Consequently they are rarely found on offshore rigs, where weight is a greater concern than on land. 3. Catline Boom or Catline: A relatively thin cable used with other equipment to move small rig and drill string components and to provide tension on the tongs for tightening or loosening threaded connections. 4. Racking Board or Monkey Board or Racking Platform: The small platform that the derrickman stands on when tripping pipe. 5. Drill Line or drilling line: A wire rope hoisting line, reeved on sheaves of the crown block and traveling block (in effect, a block and tackle). Its primary purpose is to hoist or lower drill pipe or casing from or into a well. Also a wire rope used to support the drilling tools. 6. Traveling Block: The set of sheaves that move up and down in the derrick. The wire rope threaded through them is threaded (or “reeved”) back to the stationary crown blocks located on the top of the derrick. This pulley system gives

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great mechanical advantage to the action of the wire rope drilling line, enabling heavy loads (drill string, casing and liners) to be lifted out of or lowered into the wellbore. 7. Hook: The high-capacity J-shaped equipment used to hang various other equipment, particularly the swivel and kelly, the elevator bails or top-drive units. The hook is attached to the bottom of the traveling block and provides a way to pick up heavy loads with the traveling block. The hook is either locked (the normal condition) or free to rotate, so that it may be mated or decoupled with items positioned around the rig floor, not limited to a single direction. 8. Swivel: A mechanical device that suspends the weight of the drill string. It is designed to allow rotation of the drill string beneath it, conveying high volumes of high-pressure drilling mud between the rig’s circulation system and the drill string. 9. Rotary Hose: A large-diameter (3- to 5-in. inside diameter), high-pressure flexible line used to connect the standpipe to the swivel. This flexible piping arrangement permits the kelly (and, in turn, the drill string and bit) to be raised or lowered while drilling fluid is pumped through the drill string. The simultaneous lowering of the drill string while pumping fluid is critical to the drilling operation. 10. Standpipe: A rigid metal conduit that provides the high-pressure pathway for drilling mud to travel approximately one-third of the way up the derrick, where it connects to a flexible high-pressure hose (kelly hose). Many large rigs are fitted with dual standpipes so that downtime is kept to a minimum if one standpipe requires repair. 11. Drawworks: The machine on the rig consisting of a large-diameter steel spool, brakes, a power source and assorted auxiliary devices. The primary function of the drawworks is to reel out and reel in the drilling line, a large diameter wire rope, in a controlled fashion. The drilling line is reeled over the crown block and traveling block to gain mechanical advantage in a “block and tackle” or “pulley” fashion. This reeling out and in of the drilling line causes the traveling block, and whatever may be hanging underneath it, to be lowered into or raised out of the wellbore. The reeling out of the drilling line is powered by gravity and reeling in by an electric motor or diesel engine. 12. Driller’s Console: The control panel, located on the platform, where the driller controls drilling operations. 13. Pipe Setback: A location to place stands of drill pipe and drill collars in a vertical position to one side of the rotary table in the derrick or mast of a drilling or workover rig.

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STRUCTURES AND LAND RIG MOBILIZATION 14. Drill Floor: This is the heart of any drilling rig. It is the area where the drill string is drilled into the eary. Traditionally where joints of pipe are assembled, as well as the bottomhole assembly (BHA), drill bit and other tools. This is the primary work location for roughnecks and the driller. The drill floor is located directly beneath the derrick or mast. 15. Rotary Table: The revolving or spinning section of the drill floor that provides power to turn the drill string in a clockwise direction (as viewed from above). The rotary motion and power are transmitted through the kelly bushing and the kelly to the drill string. When the drill string is rotating, the drilling crew commonly describes the operation as simply, “rotating to the right,” “turning to the right” or “rotating on bottom.” Almost all rigs today have a rotary table, either as primary or backup system for rotating the drill string. Top-drive technology, which allows continuous rotation of the drill string, has replaced the rotary table in certain operations. A few rigs are being built today with top-wash-drive systems only, and lack the traditional kelly system. 16. Substructure: The foundation structure on which the derrick, rotary table, draw-works and other drilling equipment are supported. 17. Blowout Preventer Stack: A set of two or more BOPs used to ensure pressure control of a well. A typical stack might consist of one to six ram-type preventers and, optionally, one or two annular-type preventers. A typical stack configuration has the ram preventers on the bottom and the annular preventers at the top. The configuration of the stack preventers is optimized to provide maximum pressure integrity, safety and flexibility in the event of a well-control incident. For example, in a multiple ram configuration, one set of rams might be fitted to close on 5-in. diameter drill pipe, another set configured for 4 ½-in. drill pipe, a third fitted with blind rams to close on the open hole and a fourth fitted with a shear ram that can cut and hang-off the drill pipe as a last resort. It is common to have an annular preventer or two on the top of the stack since annulars can be closed over a wide range of tubular sizes and the open hole, but are typically not rated for pressures as high as ram preventers. The BOP stack also includes various spools, adapters and piping outlets to permit the circulation of wellbore fluids under pressure in the event of a well-control incident. 18. Dog House or Driller’s Cabin: The steel-sided room adjacent to the rig floor, usually having an access door close to the driller’s controls. This general-purpose shelter is a combination tool shed, office, communications center, coffee room, lunchroom and general meeting place for the driller and his crew. It is at the same elevation as the rig floor, usually cantilevered out from the main substructure supporting the rig.

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19. Choke Manifold: A set of high-pressure valves and associated piping that usually includes at least two adjustable chokes, arranged such that one adjustable choke may be isolated and taken out of service for repair and refurbishment while well flow is directed through the other one. 20. Gas Flare or Flare Stack: A gas combustion device used in industrial plants such as petroleum refineries, chemical plants, natural gas processing plants as well as at oil or gas production sites having oil wells, gas wells, offshore oil and gas rigs, and landfills. 21. Mud Gas Separator or Gas Buster or Poor Boy Degasser: A device that captures and separates a large volume of free gas within the drilling fluid. If there is a “kick” situation, this vessel separates the mud and the gas by allowing it to flow over baffle plates. The gas then is forced to flow through a line and vent it to a flare. A “KICK” situation happens when the annular hydrostatic pressure in a drilling well temporarily (and usually relatively suddenly) falls below that of the formation, or pore, pressure in a permeable section downhole and before control of the situation is lost. 22. Shale Shaker: The primary and probably most important device on the rig for removing drilled solids from the mud. This vibrating sieve is simple in concept, but a bit more complicated to use efficiently. A wire-cloth screen vibrates while the drilling fluid flows on top of it. The liquid phase of the mud and solids smaller than the wire mesh pass through the screen, while larger solids are retained on the screen and eventually fall off the back of the device and are discarded. Obviously, smaller openings in the screen clean more solids from the whole mud, but there is a corresponding decrease in flow rate per unit area of wire cloth. Hence, the drilling crew should seek to run the screens (as the wire cloth is called) as fine as possible without dumping whole mud off the back of the shaker. Where it was once common for drilling rigs to have only one or two shale shakers, modern high-efficiency rigs are often fitted with four or more shakers, thus giving more area of wire cloth to use and giving the crew the flexibility to run increasingly fine screens. 23. Degasser: A device that removes air or gases (methane, H2S, CO2 and others) from drilling liquids. There are two generic types that work by both expanding the size of the gas bubbles entrained in the mud (by pulling a vacuum on the mud) and by increasing the surface area available to the mud so that bubbles escape (through the use of various cascading baffle plates). If the gas content in the mud is high, a mud gas separator or “poor boy degasser” is used, because it has a higher capacity than standard degassers and routes the evolved gases away from the rig to a flaring area complete with an ignition source.

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24. Desander: A hydrocyclone device that removes large drill solids from the whole mud system. The desander should be located downstream of the shale shakers and degassers, but before the desilters or mud cleaners. A volume of mud is pumped into the wide upper section of the hydrocylone at an angle roughly tangent to its circumference. As the mud flows around and gradually down the inside of the cone shape, solids are separated from the liquid by centrifugal forces. The solids continue around and down until they exit the bottom of the hydrocyclone (along with small amounts of liquid) and are discarded. The cleaner and lighter density liquid mud travels up through a vortex in the center of the hydrocyclone, exits through piping at the top of the hydrocyclone and is then routed to the mud tanks and the next mud-cleaning device, usually a desilter. Various size desander and desilter cones are functionally identical, with the size of the cone determining the size of particles the device removes from the mud system. 25. Mud Cleaner: A desilter unit in which the underflow is further processed by a fine vibrating screen, mounted directly under the cones. The liquid underflow from the screens is fed back into the mud, thus conserving weighting agent and the liquid phase but at the same time returning many fine solids to the active system. Mud cleaners are used mainly with oil- and synthetic-based muds where the liquid discharge from the cone cannot be discharged, either for environmental or economic reasons. It may also be used with weighted water-based fluids to conserve barite and the liquid phase. 26. Mud Guns (Bottom Type): Devices that provide supplemental or primary mixing in mud tanks, depending on the number being used and the pit size. They are best used in tank corners to keep solids from settling. A mud agitator is placed in the tank center. The number of mud guns depends on the size of the tank. Usually a mud gun is installed with the mud line of the mud tank. The mud gun in the mud system can also be used to transfer mud from compartment to compartment (for example, for trip tank compartment). 27. Mud Agitators: A device used in surface mud systems to suspend solids and maintain homogeneous mixture throughout the system. A mechanical agitator is driven by an explosion-proof motor, coupled to a gear box that drives the impeller shaft. The impellers (turbines) transform mechanical power into fluid circulation or agitation. The objective is to obtain a uniform suspension of all solids. 28. Mud Tanks: Open-top containers, typically made of square steel tube and steel plate, to store drilling fluid on a drilling rig. They are also called mud pits, because they used to be nothing more than pits dug out of the earth.

29. Mud Sack Storage: A general location to store materials to make drilling mud. 30. Mud Mixing Hopper or Mud Hopper: A mud-flow device, also called a jet hopper, in which materials are put into the circulating mud system. The mud hopper is powered by a centrifugal pump that flows the mud at high velocity through a venturi nozzle (jet) below the conical-shaped hopper. Dry materials are added through the mud hopper to provide dispersion, rapid hydration and uniform mixing. Liquids are sometimes fed into the mud by a hose placed in the hopper. 31. Mud Mixing Pumps: Large pumps with mixing blades to keep the drilling mud from coagulating. 32. Mud Pumps: Large reciprocating pumps used to circulate the mud (drilling fluid) on a drilling rig. They are an important part of the oilwell drilling equipment. 33. Pulsation Dampeners: An accumulator with a set precharge that absorbs system shocks while minimizing pulsations, pipe vibration, water hammering and pressure fluctuations. By minimizing pulsation in the system, components like regulators, solenoids, sensors, pumps, etc., will see decreased wear and have longer life. Pulsation dampeners are tied directly onto the discharge manifold or plumbed immediately downstream of the pump. 34. Shock Hoses: Hoses in the high-pressure mud piping system that allow for flexibility and pressure spikes in the system. 35. Mud Discharge Lines: Lines into which the excess volume of fluid is displaced. 36. Brake Water Tank: A water tank apparatus that uses an air gap to stop reflux (backflow) into the system. 37. Mud Lab: The area where the drilling mud is tested and checked for density. 38. Mud Trip Tank: A small mud tank with a capacity of 10 to 15 bbl, usually with 1-bbl or H-bbl divisions, used to ascertain the amount of mud necessary to keep the wellbore full with the exact amount of mud that is displaced by drill pipe. When the bit comes out of the hole, a volume of mud equal to that which the drill pipe occupied while in the hole must be pumped into the hole to replace the pipe. When the bit goes back in the hole, the drill pipe displaces a certain amount of mud, and a trip tank can be used again to keep track of this volume. 39. Mud Return Lines: A trough or pipe placed between the

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STRUCTURES AND LAND RIG MOBILIZATION surface connections at the wellbore and the shale shaker. Drilling mud flows through it upon its return to the surface from the hole. 40. Drilling Water Tank: A tank used to store water that is used for mud mixing, cementing and rig cleaning. 41. SCR House: A silicon-controlled rectifier (or semiconductor-controlled rectifier) is a four-layer solid state current-controlling device. 42. Cable Tray: A cable tray system is used in the electrical wiring of buildings to support insulated electric cables used for power distribution and communication. 43. Cable Elevator (Grass Hopper): A large cable tray that provides a means for the cables at ground level to get up to the drill floor. 44. Engines & Generators: Devices that provide power for all of the systems required to drill a well. 45. Engines & Air Compressors: Devices that convert power (usually from an electric motor, diesel engine or gasoline engine) into kinetic energy by compressing and pressurizing air, which, on command, can be released in quick bursts. There are numerous methods of air compression, divided into either positive-displacement or negative-displacement types. 46. Parts Storage: General storage area for rig spare parts.

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side of the ramp is a stairway for personnel movement to the drill floor. 55. Catwalks: A long, rectangular platform about 3 ft (0.9 m) high, usually made of steel and located perpendicular to the vee-door at the bottom of the slide. This platform is used as a staging area for rig and drill string tools, components that are about to be picked up and run, or components that have been run and are being laid down. A catwalk is also the functionally similar staging area, especially on offshore drilling rigs, that may not be a separate or raised structure. 56. Drill Pipe: Tubular steel conduit fitted with special threaded ends called tool joints. The drill pipe connects the rig surface equipment with the bottomhole assembly and the bit, both to pump drilling fluid to the bit and to be able to raise, lower and rotate the bottomhole assembly and bit. 57. Pipe Rack: Onshore, two elevated truss-like structures having triangular cross-sections. The pipe rack supports drill pipe, drill collars or casing above the ground. These structures are used in pairs located about 20 ft (6 m) apart and keep the pipe above ground level and closer to the level of the catwalk. Pipe stored horizontally on the pipe racks can have its threads cleaned and inspected, and the rig crew may roll the pipe from one end of the pipe racks to the other with relative ease. The pipe racks are usually topped with a wooden board so as to not damage pipe, especially casing, as it is rolled back and forth along the racks. When large amounts of pipe are stored, wooden sills are placed between the layers of pipe to prevent damage.

47. BOP Closing Unit (BOP Control System): The assembly of pumps, valves, lines, accumulators, and other items necessary to open and close the BOP equipment.

58. Auxiliary Brake: Extra brake on the drawworks to assist in stopping the drill line if needed.

48. Work Shop: General work area for small repair work.

Drilling structures are divided into a few different categories. Derricks are four-sided structures that are used to support the downhole drilling loads from tools, drill pipe and casing. Masts are three-sided structures that are used to support the downhole drilling loads from tools, drill pipe and casing. Both of these structures are connected to a drill floor structure. The main purpose of the drill floor structure is to support the mast or derrick, rotary table, pipe setback, drawworks, driller’s cabin or console, and other important drilling-related equipment. Major load-carrying elements of the drill floor are the rotary beams, drawworks frame and setback frame. Other frames and supports are located on the drill floor as needed to support other equipment. The main purpose of the substructure is to support the drill floor and all of the loads that are imparted to it by the hook load through the derrick or mast, environmental, pipe setback, and drilling equipment. The substructure also commonly

49. Pump Parts Storage: General storage area for pump spare parts. 50. Fuel Tank: A safe container for flammable fluids in which the fuel is stored. 51. Junk Bin: Container for scrap and waste. 52. Personnel Elevator: Elevator for personnel to gain access to the drill floor from ground level. 53. Wire Line Stand: Extra spool of wire rope to be used for drilling activities. 54. Stairway with Pipe Ramp: A ramp for moving drill pipe from the pipe rack at ground level to the drill floor. On the

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Drilling Structures

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STRUCTURES AND LAND RIG MOBILIZATION

Figure ST-2: Box-on-box substructure.

Figure ST-3: Swing-up substructure in process of erecting.

provides a means for the drill floor to skid or move in order to accommodate various well locations.

Substructures

The substructure is the foundation of the drilling structure assembly. Various types of substructures are used for various situations. There are primarily four basic substructure styles: box-on-box, swing-up, truck-/trailer-mounted and rigid frame. The box-on-box substructure consists of fabricated truss frames that are welded into box shapes (Figure ST-2). One set of boxes is set for the foundation, and one or more sets are put on top. This creates the necessary height for the blowout preventer and other equipment that needs to have access below the drill floor. The drill floor is then lifted into place on top of the top box frame assembly, and the mast is lifted into place on the drill floor. After the mast is erected, other equipment is lifted on the drill floor, and the structure is secured, drilling can begin. This type of substructure is used mainly onshore and occasionally offshore on suitable rig locations. This type of substructure is not easily moveable and is therefore used when high mobility is not required. The swing-up substructure consists of foundation beams with pivotable legs that support the drill floor (Figure ST-3). Once the foundation beams are set in place, the pivotable legs, drill floor, some drilling equipment, and sometimes the mast are set on them. Then, by mechanical or hydraulic means, the drill floor is swung/lifted into position and locked into place. If the mast is set in place on the drill floor prior to the erection of the substructure, it is typically erected and in the operating position. Some styles of swing-up rigs have the mast connecting to the foundation beams. In this case, the drill floor and equipment are lifted into position separately from the mast. Usage of this type of substructure is

IADC Drilling Manual

Figure ST-4: Truck rig.

desirable when the rig is to be very mobile and rig-up/rigdown time is critical. Trailer- or truck-mounted substructures are similar in principle to the swing-up substructure but are mounted on a trailer towed behind a large truck, thus providing the mobility required by many customers (Figure ST-4). When the trailer reaches drilling location, bearing pads are set that

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Figure ST-5: Skid base structure.

support all loadings, and trailer wheels are lifted off ground. The mast is then erected. Trailer rigs are used where rigging up and rigging down has to be performed in the minimum amount of time. Rigid-frame substructures are usually a one piece weldment specially designed to transfer all rig loads to specified bulkheads on a jackup, submersible, semi-submersible, drill ship, or some other offshore floating type rig. It is usually welded in place; however, it can be bolted if required. The rigid frame absorbs all dynamic loadings due to wind, wave and sailing motion acting on the rig in addition to drilling and equipment loads. This substructure is typically built in a shipyard and inserted into the vessel, or it is built directly in the vessel. A substructure master skid or skid base can be used to support the substructure (Figure ST-5). Substructures used in conjunction with a master skid are usually of the rigid-frame type. The primary purpose of a skid base is to lift the substructure and allow controlled movement to position the structures above the skid base to desired locations to service several wells from the same platform. The lateral movement of the substructure on the skid base is usually provided by a hydraulic cylinder or gear and rack system. The skid base concept is used primarily on fixed offshore platforms where available deck space is very limited or when there is a need to service several wells from one platform. In summary, the substructures carry the maximum casing loads, setback loads, dead loads, drawworks weight, rotary table weight, drill pipe weight, doghouse weight and any other equipment specified by the customer. The shoe reactions from the mast or derrick may be supported by the substructure also. The base or bottom of the substructures will connect to a skid base, vessel structure or mat foundation on the ground. Substructures consist of many pinned con-

IADC Drilling Manual

Figure ST-6: Drilling derrick.

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Figure ST-7: Derrick racking board with drill pipe.

nected members and heavy welded members for the rotary beams, floor extensions, setback beams, doghouse support brackets, etc. The substructure is a critical item for a drilling rig, so care must be taken in the design, fabrication, erection and maintenance of this item.

Derricks and masts

Derricks are four-sided tower-like structures that support loads during oilfield drilling (Figure ST-6). The typical drilling loads are from hook load (the support of loads in the well bore that consist of drill pipe, casing, traveling equipment or tools), pipe setback in the derrick, environmental loads (wind and vessel motion), and accessory equipment loads (pipehandling machines, casing stabbing boards, etc.). Derricks have access for personnel to inspect or operate various equipment. They also support lights to illuminate the drill floor and the pipe rack, provide aircraft warning, and provide navigation markers. The main structural steel of a derrick can range from 147 ft tall to 215 ft tall. The base dimensions typically range from 30 ft by 30 ft to 50 ft by 60 ft. Derricks are typically used offshore, although there are a few onshore. A derrick is not very mobile; therefore, few are used onshore today. The wellbore drilling loads are applied to the derrick through the crown. At the crown, several sheaves are engaged with wire rope that reeves to a traveling block. The ends of the wire rope terminate at a drawworks at one end and usually a deadline anchor at the other end. It is possible to have each end of the wire rope terminate at a drawworks. As the drawworks spools and unspools, load is applied to the crown and through the derrick to the drill floor and substructure. The origin of this load is what is suspended from the traveling equipment. This load could be several thousand feet of drill pipe or casing. Also, downhole tools for measuring well formations, removing foreign objects, or cutting casing or drill pipe apply loads to the derrick.

IADC Drilling Manual

Figure ST-8: Drilling mast.

Another major function of the derrick is to support drill pipe and/or casing that is not in the wellbore. During the process of drilling, drill pipe will be inserted into and out of the wellbore several times. To save time, stands of drill pipe are racked back in the derrick in a racking board (Figure ST-7). The pipe applies horizontal load to the derrick from pipe lean, wind on the pipe and rig motion. Some derricks have a casing setback area that speeds up the process of running casing into the wellbore. The casing inputs similar loads into the derrick as drill pipe.Several other pieces of equipment are located in the derrick. This includes, but is not limited to, pipehandling equipment, navigation equipment, traveling equipment, controls, mud standpipes, cement standpipes, casing running equipment, maintenance platforms, maintenance access baskets, deadline anchors, degasser ventlines and weather-sensing devices. The derrick is the pinnacle of the drilling rig and is an icon for the drilling industry. Masts are three-sided tower-like structures that support loads during oilfield drilling (Figure ST-8). The typical drill-

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ST-9

ing loads are from hook load (the support of loads in the wellbore that consist of drill pipe, casing, traveling equipment or tools), pipe setback in the mast, environmental loads (wind and vessel motion), and accessory equipment loads such as casing stabbing boards, etc. Masts have access for personnel to inspect or operate various equipment. They also support lights to illuminate the drill floor and the pipe rack, provide aircraft warning, and provide navigation markers. The main structural steel of a mast can range from 105 ft tall to 185 ft tall. The base dimensions typically range from 20 ft by 20 ft to 30 ft by 35 ft. Masts are typically used onshore, although there are a few offshore, mainly on platform rigs. A mast is typically very mobile; therefore, many are used onshore today. The wellbore drilling loads are applied to the mast through the crown. At the crown, several sheaves are engaged with wire rope that reeves to a traveling block. The ends of the wire rope terminate at a drawworks on one end and usually a deadline anchor on the other end. It is possible to have each end of the wire rope terminate at a separate drawworks, but not typical on a mast. As the drawworks spools and unspools, load is applied to the crown and through the mast to the drill floor and substructure. The origin of this load is what is suspended from the traveling equipment. This load could be several thousand feet of drill pipe or casing. Also, downhole tools for measuring well formations, removing foreign objects, or cutting casing or drill pipe apply loads to the mast. Another major function of the mast is to support drill pipe and/or casing that is not in the wellbore. During the process of drilling, drill pipe will be inserted into and out of the wellbore numerous times. As a time saver, stands of drill pipe are racked back external to the mast in a racking board (Figure ST-9). The pipe applies horizontal load to the mast from pipe lean, wind on the pipe, and rig motion. In rare cases masts have a casing setback area that speeds up the process of running casing into the wellbore. The casing inputs similar loads into the mast as drill pipe. Several other pieces of equipment are located in the mast. This includes, but is not limited to pipehandling equipment, navigation equipment, traveling equipment controls, mud standpipes, cement standpipes, casing running equipment, maintenance platforms, maintenance access baskets, deadline anchors, degasser ventlines and weather sensing devices. The mast caps off the mobile drilling rig package.

Common characteristics

API 4F is a good place to start for a standard definition of derricks and masts. According to API 4F: • Derrick: Structural tower of square or rectangular

IADC Drilling Manual

Figure ST-9: Mast racking board with drill pipe.

cross-section, having members that are latticed or trussed on all four sides • Mast: Structural latticed tower of rectangular crosssection with an open face. Derricks are almost always located offshore and very rarely on a land rig. The reason for this is dynamics. The arrangement of structural steel members in a derrick is better equipped to handle dynamic motion due to waves. Derricks tend to have a larger footprint at the base and a larger cross-section than masts do. Because of this, drill pipe and other tubulars are racked inside a derrick. Derricks are sometimes assembled member by member once on the drilling rig or vessel. However, many times, the derrick for offshore is assembled before being moved to the drilling rig and then set into place by a crane, either in single or multiple crane lifts. While a derrick can be a more efficient design in terms of strength and ability to handle operating and environmental loads, they are at a disadvantage to masts when it comes to rig-up time. Longer rig-up time means drilling operations do not happen as quickly. Masts can be used both onshore and offshore, and they can be raised and lowered. This is typically done by means of hydraulic cylinders or with wire rope (drawworks or winches). Masts can also be scoped together. The most common types of masts are cantilever (starts in a horizontal position and raised 90° to vertical), bootstrap (sections of the mast are brought in and scoped to the operating position) and telescopic (may be two or three mast sections that transport within one another and are scoped “out” to the operating position). Masts will often be outfitted with a racking board on the open side of the cross-section, and this is where drill pipe and other tubulars will be racked/stored. The structural members of a mast are generally welded together. The vari-

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ST-10

STRUCTURES AND LAND RIG MOBILIZATION The Driller and Assistant Driller share job functions. On smaller rigs, an Assistant Driller is not necessary. On larger rigs, the Driller and Assistant Driller divide up the work load, usually by equipment location. The Driller may handle the mud pumps, traveling equipment and drawworks, and the Assistant Driller may handle the drill floor equipment such as the iron roughneck, mousehole, and pipehandling equipment. The Driller is the supervisor of the rig crew. The Driller and Assistant Driller need to be mindful of activities in the derrick/mast and drill floor. The equipment they operate can damage the structures and equipment or hurt members of the drill crew working on the drill floor or in the derrick or mast.

Figure ST-10: Masts can be used both onshore and offshore,

and can be raised and lowered. This is typically done by means of hydraulic cylinders or with wire rope.. ous sections of the mast are then connected together with a pin-and-plate assembly or with bolts. Masts usually do not take as long to rig up as derricks. Drilling rig structures, whether onshore or offshore, commonly have a mechanical system allowing the structure to move from well to well. These are typically referred to as “skidding” or “walking” systems. These systems are attached to the structure in a variety of configurations and styles. See Appendix for more on walking systems. Skidding systems allow the rig to move in forward and backward. Typical arrangements include a “jack and claw” where a “claw” grips slots in a beam or plate while a hydraulic cylinder pushes or pulls the structure. “Lift and roll” systems also utilize hydraulic cylinders to push and pull the rig. However, these systems have an additional hydraulic cylinder that lifts the rig, placing the full weight on rollers that move as the rig is pushed or pulled. Skidding systems can be used on both onshore and offshore drilling rig structures. Walking systems act much like a lift and roll system but tend to have more capabilities. Walking systems are typically designed to allow the rig to move in more than just one direction. In most cases, the walking system allows the rig to make complete turns, allowing access to multiple rows of wells. The application for walking systems is only on land rigs.

Personnel

There are four important job positions that pertain to drilling rig structures: Driller, Assistant Driller, Derrickman and Mechanic.

IADC Drilling Manual

Members of the drill crew that work in the derrick or mast at the racking board are the Derrickmen. The Derrickman handles drill pipe at the racking board when tripping into and out of the wellbore. This job requires coordination with the Driller who is operating the drawworks and top drive. A harness and safety attachment point on the derrick or mast structure is utilized by the Derrickman to prevent injury in case of a fall from the racking board. He also uses this safety line to enable him to lean out toward well center to handle the pipe transfer to and from the top drive. This is a very physically demanding and dangerous job. Some drilling rigs have automated pipehandling equipment that removes the need for the Derrickman. The Mechanic is responsible for ensuring that all parts requiring maintenance on the drilling rig are properly maintained and in good working order. For the drilling structures, this includes crown sheaves, fairleads and skidding systems. The Mechanic needs to access all points of the structure from the top to the bottom. Access ways and maintenance points are important for safety and reliability to the Mechanic.

Maintenance Objective

The objective of the maintenance section is to provide the owners and operators of the drilling equipment listed below with guidelines for maintenance and repair, establishing the necessary steps that may be utilized to maintain serviceability of the covered equipment, recommending practices and procedures for use in the safe operation and maintenance of the equipment, and promoting safe working conditions for personnel engaged in drilling operations and well servicing operations, including special services. Note: The maintenance guidelines mentioned within this section should in no way be intended to supersede the recommended instructions as given by the original equipment

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STRUCTURES AND LAND RIG MOBILIZATION manufacturer (OEM). The reader of this section shall refer to the OEM instructions and develop their maintenance schedule accordingly. This section is intended as a basic guideline that could be used to assist the reader in their maintenance program. This section covers the following drilling equipment: • Onshore/offshore drilling structures: masts, derricks, substructures and skidding systems; • Guide track system; • Drilling rig accessories: crown and other sheaves, snatch blocks, man rider, utility winches, bearings, bushings, fastline stabilizers, rollers/wheels; • Bolts, bolted connections, pins; • Hoisting equipment supported by the drilling rigs: bridge rackers, pipehandling systems, BOP trolley beams, stand building systems; • High-pressure pipes and others: cement standpipes, mud standpipe, vent lines, hydraulic systems; • Personnel support devices: drilling rig elevators, safe climbing equipment, fall arrest systems, ladders and cages, emergency evacuation systems; • Electrical equipment, junction boxes; • Wire rope/wireline, mast-raising slings, hang-off lines; • Wind walls, other rig equipment, and drill floor equipment.

Maintenance instructions

A Maintenance Log must be established for the equipment. All maintenance, abnormal observations and repairs should be logged. Upon request, the log should be made available to the owner and serviceman. The OEM should keep and maintain a modification and service database for the equipment supplied. It is of great importance that the user reports deficiencies, modifications and problems to the OEM. This information is essential for OEMs to identify critical items prone to excessive wear or problems, and it will highlight components that require a design review to improve safety and reliability. Areas of major concern shall without hesitancy be brought to the attention of OEMs. If important deficiencies appear after the equipment is taken into use, OEMs should issue Safety or Service Bulletins to users as deemed necessary. Maintenance and repair procedures should be carried out by personnel qualified by professional trade and verified by widely accepted or recognized standards covering the specific skills or knowledge required. See the Inspection and Safety sections of this chapter for more details.

• Information provided by the manufacturer, serial number, identification marking; • Inspection records, date and name of responsible person; • Maintenance records, date and name of responsible person; • Repair records; • Remanufacture records (if applicable).

Safety summary

The following points summarize the safety aspects related to maintenance: • Only qualified personnel should be allowed to carry out maintenance. • Only the prescribed maintenance to the user by the OEM should be carried out by the user. Anything else should be clarified with supplier’s/OEM’s service department before being carried out. • It is extremely important to do a thorough visual check and inspection of any equipment before and after implementing any procedure, to avoid or mitigate hazards to personnel in the event of a failure. • See the Safety section of this chapter for more details.

Routine inspections for maintenance

The inspection part of routine maintenance should be carried out regularly. A maintenance inspection schedule should be developed by the user. All abnormal observations should be reported to the maintenance supervisor at once and also recorded in the Maintenance Log. Due dates should also be logged. Ask the operator if any abnormalities have been observed. All such observations should be logged for follow-up.

Periodic maintenance schedule

• If the routine inspection revealed any abnormal conditions, these must be followed up by the operator/ owner of the equipment. • The inspection notes must be followed up by the operator/owner; • Inspect all assembly components for structural integrity, and ensure all bolts and nuts are in place and are made-up to appropriate minimum installation requirements for all fasteners; • Structures should be visually inspected for damage and deformation and reported immediately if any abnormality occurs; • Check if the Operation and Inspection Program is firmly in place and is being followed by the personnel and if it needs to be reviewed and updated; • See the Inspection section of this chapter for more details;

Maintenance records may include the following:

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Monthly maintenance

• Keep the equipment clean. • Check for structures’ (mast, derrick) level status. Correct if out of vertical as per OEM instructions. • If signs of abnormal wear are detected, repair accordingly and correct the situation immediately. • Carry out the monthly lubrication maintenance specified for each piece of equipment according to the equipment’s lubrication chart. • Check that the Emergency Evacuation System is working properly. • Review specific maintenance manuals for specific equipment. • See the Inspection section of this chapter for more details.

Yearly maintenance

• Structures such as derrick, masts, wind walls and crown blocks should be inspected for critical areas at least once a year. • Have the entire (lifting appliance) equipment inspected by a qualified person. See the inspection section of this chapter for more details. • A signed copy of the inspection report must be filed in the Maintenance Log, and the remarks must be followed up. • The annual inspection should include employing appropriate non-destructive examination (NDE) techniques at suspected critical areas that will reveal defects that would not otherwise be visible to the naked eye. • Wirelines such as mast and substructure raising wire ropes should be inspected after each use. If the wire rope does not pass inspection, it must then be replaced by a new wire of the original type. See the Wire Rope chapter of this manual for further details. • See the Inspection section of this chapter for further details and recommendations.

5-year maintenance

• • • •

• • •

• • • •

• •

as required by API Standards and local regulations as per the original equipment criteria. Levelling shims should be installed per OEM instructions if the structure is not level. Check for any operating interference with any of the derrick accessories or equipment. Check that the bumper blocks at crown level are in good shape. In the event of extreme load cases resulting from abnormal operations beyond the rated capacity of the equipment, check the connection points (welded, pinned or bolted) and primary load-carrying members. Check for cracks or signs of deformity. Repair according to approved methods. Note areas with rust or corrosion and repair immediately. Use approved method of repair. Check for missing or damaged name plates, tags, instruction plates or other equipment markings, and replace with duplicate as required by OEM; Look for items rubbing against paint, and repair to reduce amount of rubbing. If any equipment or structure needs to be modified or added to the mast or derrick, consult the OEM. Do not burn holes or weld unless without adhering to approved methods and consulting with the OEM. Always inspect the wirelines before raising or lowering a mast. Pay particular attention to areas near sockets or around sheaves. See the Wire Rope chapter of this manual. Follow inspections and maintenance schedules as described in previous sections of this chapter. See the Inspection and Safety sections of this chapter for further details.

»» Guide track system The Guide Track System should provide a level platform for the traveling equipment. When a tubular or pipe is hanging in the traveling equipment (in normal running mode), it should pass cleanly through the rotary. Otherwise the derrick or mast must be levelled.

Change all hydraulic hoses (see OEM’s instructions). Only original-type hoses must be used.

The guide track bracing may be adjusted vertically and horizontally in both directions with shims if needed.

Periodic maintenance

»» Drilling rig accessories

Follow supplier/OEM recommendations for each piece of equipment.

»» Drilling structures • Careful, periodic checking and maintenance of the structure will ensure the safe, dependable and economical service life of the rig. • The drilling structure should be operated and maintained

IADC Drilling Manual

• Periodic checks of the sheaves will help for longer wire rope service life. • Worn sheaves and drum grooves cause excessive wear on the wire rope. • All sheaves should be in proper alignment to avoid wear on the wire rope. • Guidelines on API RP 9B and API RP 8B should be followed. • Cap plates on all shafts and all wired bolts should be

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• •

•

•

• •

checked regularly to ensure that the bolts are tight and the retaining wires in place. See API RP 2D, Appendix G and Section G.5.1.4 for recommended methods of lubrication for wire rope. During replacement of the wire rope, the opportunity should be taken to examine the sheaves, checking for any signs of undue wear or damage. Follow API RP 9B or OEM recommendations for allowed sheave wear. Check that the safety “Hobble Lines” under the watertable/crown block are attached to the tugger or snatch blocks and are in good condition. Padeyes provided by the original OEM and stamped with a SWL (safe working load) should be used as the maximum load capacity for the padeye as noted by the SWL. No additional padeyes should be added to the structures without consulting with the OEM first. See the Wire Rope chapter of the IADC Drilling Manual, 12th edition, for more information.

»» Bolts, bolted connections, and pins • Bolts provide critical connections for the overall structural integrity. It is essential that they are installed with enough tension to secure and maintain the assembly components. • Improper bolt installation can be just as dangerous and subject to failure as bolts missing from the assembly. It is essential to follow the bolt installation method as given by the OEM. • If hole elongation occurs, it may be due to an abnormal load. The origin of the abnormal load must be determined and this operation discontinued. The lug or lugs require repair or replacement by approved method. • If wear on pin or pinhole allows for excess movement, then approved repair or replacement is required. • Contact the OEM before making any repairs. WARNING: Operating equipment with bolts and nuts which are improperly installed or missing can cause catastrophic equipment failure resulting in serious injury or death. See the Inspection and Safety sections of this chapter for further details.

»» Hoisting equipment • Use adequate hoisting equipment. Observe all safety precautions. Follow OEM guidelines for operation and maintenance. • The hoisting system should be in a serviceable condition and inspected before use. • Do not attempt to use the hoisting system if any of the components are damaged. • Keep clear of the hoisting system’s moving parts during

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test or operation by the local hydraulic controls. Only well-trained personnel should use these controls. • Make sure that unauthorized personnel do not have access to these systems.

»» High-pressure and other pipes • Follow all safety and inspection recommendations. • No welding of lugs, brackets, etc. should take place on the equipment. Contact the OEM for further guideance; • In the case of a fire, be aware that hydraulic oil is flammable. • Before any maintenance on the hydraulic system, make sure that the pressure is vented fully and that accidental starting is prevented. • Adjustable valves sealed by the supplier are not to be adjusted by user without approval and guidelines from the supplier. • Only original spare parts ordered through the OEM must be used. • A maintenance warning sign should be clearly placed when maintenance is being performed. • See OEM data for steps for venting hydraulic systems. • Repair of hydraulic cylinders should be always be performed by qualified personnel. • If a hydraulic hose, oil seal or gaskets become worn or damaged, the defective piece must be replaced by a new one of the original type following the manufacturer’s instructions. Note the date of replacement. • Avoid twisting of the hose during assembly. A twisted hose is subject to stress that eventually may work loose the connections. Warning: Do not unscrew hydraulic hoses before pressure is thoroughly vented!

»» Personnel support devices • All personnel support devices must be maintained in working order at all times. • All hooks used for support of personnel shall have an operable latch. • A crane hook that may be closed and locked, with a pinned or positive locking device, eliminating the hook throat opening, shall be used for any personnel lifts. • Additionally, a hook with a designed lifting eye integral to the hook may be used in conjunction with a shackle that may be pinned to prevent opening. These hooks are designed to prevent the personnel basket sling from coming off the hook accidentally • Check proper function of all safety gates at all levels. • Check that the mechanical spring mechanisms are all properly greased. • Check for no obstruction over the entire climbing height. • Check that both descending guide wires are correctly fitted and pre-tensioned.

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• Check that the guide bar in the emergency evacuation system can slide freely over the entire length. Follow OEM guidelines for testing. • See the Inspection and Safety sections of this chapter for further details.

»» Corrections and minor repairs

»» Electrical equipment

Major repairs and modifications

• Disconnect the electrical power supply when working on a system, and tag controls to prevent accidental operation. Use mechanical shutoff when available. • Some sensitive electrical equipment, such as control cabinets, must be protected at all times, and when stored it should be indoors in heated and humidity-controlled areas. • All housings made of stainless steel must be protected from spatter of welding and grinding. • Glass should be protected. • Junction Boxes must be protected from weld spatter and grinding spatter with suitable cloth.

»» Wire rope/wireline, mast raising slings, hang-off lines • API RP 9B covers Application, Care, and Use of Wire Rope for Oil Field Service. • API RP 2D, Appendix G covers recommendations for wire rope inspection. • All wire ropes, including slinglines, are well-lubricated when manufactured; however, the lubrication will not last throughout the entire service life of the rope. Periodically, therefore, the rope will need to be field-lubricated with a good rope lubricant and kept lubricated at all times. • Sudden, severe stresses and extreme loading are injurious to wire rope, and such applications should be reduced to a minimum and inspected afterwards. • Excessive speeds when running blocks under light load may damage wire rope. If the wire doesn’t pass the inspection, it must be changed as soon as possible. • The wire rope can be used until examination indicates that it no longer is suited for continued use. It must then be replaced by a new wire of the original type. • The examination should preferably occur during the yearly inspection of the hoist/raising system by authorized personnel. Between examinations, the wire must be greased as described in the lubrication chart. • During replacement of the wire, the opportunity should be taken to examine the sheaves, checking for any signs of undue wear or damage. • See the Inspection and Safety sections of this chapter for more details.

»» Wind walls, other rig and drill floor equipment Wind walls should be firmly attached to the drilling structure. See the OEM data sheet for maintenance for other equipment not listed in this section.

IADC Drilling Manual

User should contact the OEM’s service department to discuss any corrections and repairs. If authorized by the service department, work permits and procedures should be issued as required.

All major repairs and modifications must be discussed with and approved by OEM’s service department before the work can start. The service department should involve OEM’s design engineers as necessary, and a conclusive report and proposal should be issued.

Maintenance not normally performed by user

The repair/modification work listed below shall specifically not be carried out by user without approval and instructions from OEM’s Service Department. The list is not exhaustive, and the general rule is still that maintenance/repairs not described in the Maintenance Section require OEM’s approval before carried out. • If any equipment or structure needs to be modified or added to the mast or derrick, the OEM should to be consulted. • Do not burn holes or weld unless strictly adhering to approved methods and consulting with the OEM. • The OEM should be contacted prior to any repair, reinforcement or other modification to ensure the structural acceptability, proper engineering design and installation of the proposed modifications, and to ensure that adequate repair methods and procedures are followed so that the certification given by the OEM is not impaired. • Adjustments, repairs and replacements of parts belonging to the main hydraulic system. • Adjustments, repairs and replacements of mechanical or hydraulic components with load-carrying or safety functions. • Adjustments, repairs and replacements of components sealed by the supplier. • Dismantling hydraulic motors and gearboxes.

Inspections

While performing API RP4G Inspections, it should be noted that the standard itself is identified as a “recommended” practice only, and that in the absence of an established internal inspection program by a given manufacturer, the information and forms provided in this standard are intended for use as an aid and framework. The acceptance criteria and requirements in this procedure are based on manufacturing experience of global providers of drilling and well servicing structures and aspects of accepted domestic and international standards such as AWS D1.1 (American Welding Society), AISC (American Institute of Steel Construction),

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STRUCTURES AND LAND RIG MOBILIZATION

Table ST-1 : Frequency and required documentation for inspection categories12 Category

Frequency

Documentation

I

Daily

Optional

II

At Rig Up

Optional

III

Every 730 operating days

Equipment File

IV

Every 3650 operating days

Equipment File

One operating day equals 24 hours

ASTM (ASTM International), TC-1A, API 8B, API 9A, RP 9B and API 4F.

Qualification of personnel performing inspections

Personnel performing structural inspections shall be qualified in one or more of the following manners or disciplines:• • A registered professional engineer; • Possession of a recognized certificate of training based on a manufacturer’s documented inspection training program; • An AWS-certified welding inspector with additional documented subject matter training; • An AWS-certified associate welding inspector with additional documented subject matter training; • A person who by knowledge, training or experience has successfully demonstrated the ability to solve or resolve problems relating to the subject matter of metals fabrication and or inspection (verified resume).

Pre-inspection data review

Prior to the performance of any inspection, a request for a review of existing data should be made. The user/owner

should maintain and retain an equipment file containing pertinent information regarding the mast or substructure to be inspected. These records can be primarily used to establish the clear identification of the structure to be inspected (original manufacturer, serial number, rating, etc.) and any history which might include areas of concern to which additional focus might to be given. Documents which fall in to this category are, as applicable: • Assembly and critical-area drawings; • Internal procedures including acceptance criteria; • Documentation of repairs and or modifications; • Photos of repairs and or modifications; • Performance test records; • Records of category III and IV inspections; • Weld procedures; • Welders’ qualifications; • NDE methods and results; • NDE technician qualifications; • Material test reports (MTRs); • Guying requirements, if applicable, including recommended patterns; • Nameplate information (which should include the manufacturer, serial number, static hook load capacity and number of lines strung).

Inspection categories and limitations

• Category I and II inspections, as defined by the API RP4G standard, are generally performed by rig personnel designated by the owner or user and would not typically be performed by an inspector.; • Category III and IV inspections as defined by the API RP4G standard shall be limited in scope to the detection of defects such as cracks, mechanical damage, corrosion or wear on an existing engineered structure within the following frameworks; • Category III: A visual inspection of all load-bearing

Figure ST-11: Major areas substructure (side view).

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ST-16

STRUCTURES AND LAND RIG MOBILIZATION components and members to determine the condition of the mast/derrick or substructure; • Category IV: A 100% visual inspection of all welds, including the disassembly and cleaning of the structure to the extent necessary to conduct NDE of all defined critical areas including and when applicable, ultrasonic examination for all tubular-style or closed members. Defects reported during Category III and IV inspections shall be based upon acceptance criteria, as established in this procedure, unless otherwise instructed by the client. Inspections shall not include any determinations by the inspector as to the validation of the original design or structural capacity of any modifications made to an existing structure. Figure ST-12: Major areas substructure (top view).

Any damage found during the inspection shall be defined on the following basis: • Major: Significant geometrical distortion or structural damage to primary load-carrying components including raising assembly, main legs, hinge points, sheaves or sheave shaft, crown and pin connections. • Secondary: Damage or distortion to non-primary load-carrying components including gerts and diagonal bracing. • Minor: Damage or distortion to ancillary equipment, i.e., ladders, monkey board, walk arounds, tong hangers, etc.

Documentation requirements

Documentation requirements for Category III and IV inspections shall include the use of the appropriate visual inspection form as provided by the API RP4G standard. • Appendix A: Drilling Masts Visual Inspection Form; • Appendix B: Well Servicing Mast Visual Inspection (trailer-mounted); • Appendix C: Drilling Derrick Visual Inspection Form; • Appendix D: Substructure Visual Inspection Form. Documentation requirements for the inspections of modifications shall be reported.

Figure ST-13: Major areas mast.

IADC Drilling Manual

Category IV Inspections, in addition to the provided visual inspection form, shall also require the following documentation as applicable: • The appropriate Category III Visual Inspection Form; • Date and location repairs were made; • Photos or drawings denoting the location of significant defects reported; • Photos or drawings denoting the location and extent of repairs; • NDE methods and results, including those reports; • Verification of Level III certification of procedures; • Welders’ qualifications;

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STRUCTURES AND LAND RIG MOBILIZATION

Figure ST-14: Examples of cracks. Clockwise from top left, longitudinal wel metal-face crack, toe crack, toe crack, stress crack.

Figure ST-16: Stress crack.

Figure ST-15: Stress crack on backside of pad eye.

IADC Drilling Manual

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ST-18

STRUCTURES AND LAND RIG MOBILIZATION 2 10 13

2 5 13

13

9

3 11

12

6 13

3

3 6 7 13

1

4

2 5 8 13

1 Crater crack 2 Face crack 3 Heat-affected zone crack 4 Lamellar tear 5 Longitudinal crack 6 Root crack 7 Root surface crack 8 Throat crack 9 Toe crack 10 Transverse crack 11 Underbead crack 12 Weld interface crack 13 Weld metal crack

Figure ST-17: Any crack shall be unacceptable, regardless of size or location.

• Weld Procedure Specifications (WPS); • Calibration certification for equipment used ; • MTRs; • Date and name of the qualified inspector performing the inspection; • Any other documentation pertinent to the condition or status of the structure.

Position of masts and derricks during inspections

Weld inspection performance and acceptance criteria

Visual inspection of welds in all steels can begin immediately after completed welds have cooled to ambient temperature, except for steels falling under the ASTM A 514, A517, A709 Grade 100 and 100W steel, (high-yield-strength steels), which shall be visually inspected not less than 48 hours after the completion of the welds.

Category IV inspections may be performed on masts and derricks in the horizontal position in order to allow access to all welds and ancillary equipment. In addition, it is preferable that the mast or derrick be sandblasted and may be coated with a zinc-type coating to prevent surface corrosion during the exposure of unprotected metal.

Weld inspection criteria shall be based on the categories of discontinuities established by the AWS D1.1/D1.1M Visual Inspection Acceptance Criteria, Table 6.1, and shall include the following categories of discontinuities. • Cracks; • Weld/base metal fusion; • Crater cross-section; • Insufficient weld profiles; • Undercut; • Porosity.

Modifications, dependent on the location, may be inspected with the mast or derrick in the upright position but shall not be considered a Category III or IV inspection.

Thorough fusion shall exist between layers of weld metal and between weld metal and base metal. Incomplete fusion is a weld discontinuity in which fusion did not occur between

Category III inspections may be performed on masts and derricks in the horizontal position in order to allow access to welds and all load-bearing components.

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ST-19

Table ST-2: Weld table. Weld size (x) in. (mm) 1/16 (1.6)

.93k/in

1.31k/in

1.86k/in

.56k/in

1/8 (3.2)

1.86k/in

2.63k/in

3.71k/in

1.11k/in

3/16 (4.8)

2.78k/in

3.94k/in

5.57k/in

1.67k/in

1/4 (6.4)

3.71k/in

5.25k/in

7.43k/in

2.23k/in

5/16 (8.0)

4.64k/in

6.56k/in

9.28k/in

2.78k/in

3/8 (9.5)

5.57k/in

7.88k/in

11.14k/in

3.34k/in

7/16 (11.1)

6.50k/in

9.19k/in

12.99k/in

3.90k/in

1/2 (12.7)

7.43k/in

10.50k/in

14.85k/in

4.46k/in

9/16 (14.3)

8.35k/in

11.81k/in

16.70k/in

5.01k/in 5.57k/in

5/8 (16.0)

9.28k/in

13.13k/in

18.56k/in

11/16 (17.46)

10.21k/in

14.44k/in

20.42k/in

6.13k/in

3/4 (19.0)

11.14k/in

15.75k/in

22.27k/in

6.68k/in

13/16 (20.64)

12.07k/in

17.06k/in

24.13k/in

7.24k/in

7/8 (22.23)

12.99k/in

18.38k/in

25.99k/in

7.80k/in

15/16 (23.81)

13.92k/in

19.69k/in

27.84k/in

8.35k/in

1” (25.4)

14.85k/in

21.0k/in

29.70k/in

8.91k/in

Method to determin capacity

Capacity = .7071 (x) 21ksi

Capacity = (x) 21ksi

Capacity = (x+x) .7071 x 21ksi

weld metal and fusion faces or adjoining weld beads. It is usually the result of improper welding techniques, improper preparation of base metal or improper joint design, but it can include insufficient welding heat or lack of access to all fusion faces.

The capacity of a weld, while ultimately a final determination of the engineer, should be based on an accepted method to determine the capacity and should generally follow the criteria for weld dimensions in Table ST-2 and pin connections in Figure ST-18.

All craters shall be filled to provide the specified weld size, except for the ends of intermittent fillet welds outside of their effective length. Crater cracks occur at the end of a weld when the weld is improperly terminated and are found most frequently in materials with a high coefficient of thermal expansion, such as austenitic stainless steels.

Undercut for material less than 1 in. (25 mm) thick shall not exceed 1⁄32 in. (1 mm) for any accumulated length up to 2 in. in any 12-in. length of continuous weld.

Unless otherwise specified, all accessible contact surfaces are to be joined with a continuous 45° fillet weld, with weld sizes to be 1⁄16 in. smaller than the lighter member of the joint up to 5/16 in. thickness and 1⁄8 in. smaller than the lighter member of the joint up to 3⁄4 in. thickness.

For fillet welds, no porosity over 1⁄8 in. in diameter (3.2 mm) shall be allowed or the sum of all holes 1⁄32 in. (1 mm) diameter or greater shall not exceed 3⁄8 in. (10 mm) in any linear inch of weld and shall not exceed ¾ in. (20 mm) over any 12 in. (300 mm) length of weld.

For the purpose of the acceptance criteria only, the size of a fillet weld in any continuous portion of weld may not be less or more than 20% of the nominal size of the weld and shall not exceed 10% of the weld length.

Inspection of repairs and modifications

IADC Drilling Manual

Undercut for material equal to or greater than 1 in. (25.4 mm) shall not exceed 1⁄16 in. for any length of weld.

Inspection acceptance criteria for repairs and modifications shall be based on the following API RP4G Recommended Practice guidelines.

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STRUCTURES AND LAND RIG MOBILIZATION

Figure ST-18: Pin connection design for fixed connections.

Repair welding shall be performed using approved welding procedures by welders qualified to perform those specific welding procedures. Components displaying deviations as listed below shall be reported and considered for repair/replacement: • Legs: ¼ in. (6.4 mm) bow in 10 ft (3.048 m); • Braces: ½ in. (12.7 mm) bow in 10 ft (3.048 m); • Overall alignment on structure: ¾ in. (19.0 mm); • Pin diameters: 1⁄16 in. (1.6mm) undersize; • Pin hole diameters less than 3 in.: (76.2 mm) maximum oversize 3⁄16 in. (4.8 mm); • Pin hole diameters 3 in. or larger: ¼ in. (6.4 mm) maximum oversize; • Corrosion over 10% reduction in cross-sectional area; • Sharp kinks or bend in a local area; • Loose connections or fittings; • Missing bolts, pins or safety keys; • Missing members; • Sheaves or rollers which do not turn freely or have cracks; • Line cuts or groove cuts that exceed 1.75 times the line diameter; • Exposure to heat in excess of 500°F (260°C).

Inspections and nondestructive examinations

NDE, when performed, shall be performed using procedures which have been reviewed and approved by a Level III Exam-

IADC Drilling Manual

iner, as certified by the American Society for Nondestructive Testing (ASNT), or equivalent. Personnel performing NDE shall, at minimum, be certified as Level II Technicians. All critical welds shall be 100% visually examined. Twenty percent of critical welds shall be inspected using magnetic particle (MP) or liquid penetrant (LP) testing. The inspector shall be allowed to choose the areas for random inspection coverage. Areas examined shall include the weld area and the adjacent areas up to 3 in. (76mm) on both sides of the weld. The area shall be 100% scanned. Welds that are subject to magnetic-particle (MT) and penetrant testing (PT), in addition to visual inspection, shall be evaluated on the basis of the applicable requirements for visual inspection (AWS D1.1, Table 6.1). Welds subject to examination by ultrasonic testing (UT), in addition to visual inspection, shall be evaluated on the basis of the acceptance criteria as determined in the AWS D1.1, Table 6.2 Statically Loaded Non-tubular Connections. Welds subject to examination by X-ray (radiographic test-

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STRUCTURES AND LAND RIG MOBILIZATION

ST-21

Figure ST-19: Bent or bowed braces, ½ in. (12.7 mm).

Figure ST-21: Impact damage to pin connection.

Figure ST-20: Distorted pad eyes.

Figure ST-22: Distorted braces.

ing, RT), in addition to visual inspection, shall be evaluated on the basis of the acceptance criteria as determined in the AWS D1, Figure 6.1.

area shall be considered the maximum amount of reduction allowed before replacement.

When known, all full or partial penetration welds loaded in tension to 70% or greater of their allowable stress, as determined by design, shall be ultrasonic or radiographic inspected. Documentation requirements for NDE performed shall include a copy of the Level II certification for the technician performing the NDE and a signed MT, PT, UT or RT report that indicates the area inspected and makes a determination concerning the inspected areas pass or fail status. In corrosive environments (humidity, salt, H2S, etc.), the inspection activity should include an ultrasonic examination for the purpose of checking for internal corrosion on tubular-style members. A 10% reduction in a cross-sectional

IADC Drilling Manual

Inspection of pad eyes, lifting eyes and pin connections

Pad eyes should be identified with an SWL rating. Holes should be machined, and welds should be examined using a non-destructive testing (NDT) process. Surface contact of leg ends, at pin connections, for mast sections, should be maintained at a minimum 85%.

Inspection of raising lines, guy lines and wire rope

Wire rope used as guy lines, escape lines and pendant lines should be maintained in a well-lubricated condition and removed from service when any of the following conditions exist: • Three broken wires are found within one lay length; • Two broken wires are found at the end connection in the strand valley;

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ST-22

STRUCTURES AND LAND RIG MOBILIZATION • Marked corrosion or rust appears; • Corroded wires are observed at end connections; • End connections are corroded, cracked, bent, worn or improperly applied; • Evidence of kinking, crushing, cutting, cold working or bird caging is observed.

Inspection of racking platforms

Pipe racking fingers should be straight and secured with a safety device. The working platform should be made of a nonskid material. Racking platforms may be made of special high-strength steel; care should be taken to ensure that like materials are used in repair and replacement.

Inspection of substructures

It should be noted by the inspector that the critical areas of a substructure are the areas associated with the rotary table, rotary beams, pin connections, shoes and spreaders. These areas as well as the set-back support the majority of the load and are considered critical to the substructure.

Report documentation and record requirements

Documentation requirements shall consist of objective evidence substantiating any and all works performed, including, where applicable, qualifications for personnel performing such work and verification of the materials and procedures used in the modifications or repair of the structure in question.

Figure ST-23a (top) and ST-23b: Toe cracks on pad eyes.

Welding procedures that have been pre-qualified on the bases of conformance with all the applicable requirements of Section 3 of the AWS D1.1 Standard for Structural Welding Code, “Prequalification of WPS’s”, shall be exempt from qualification testing. WPSs that do not conform to the requirements of Section 3 shall be qualified by tests in conformance with Section 4, of the AWS D1.1 Standard, “Qualifications.” Welders shall submit documented evidence of qualification to the specific procedures used in the repair or modification of the structures in question. NDE, whether performed by third-party outside sources or in-house, shall be performed using procedures reviewed and approved by an ASNT-TC-1A Level III examiner or an examiner qualified to a standard recognized by ASNT. The procedures shall meet the requirements of the 4th edition of API 4F Standard, Section 11.4.4.2, regarding the area of examination:

Figure ST-24: Distorted connection plate.

IADC Drilling Manual

“The area of examination shall include the weld area and adjacent areas up to 3 in. (76.2 mm) from the weld. The area shall be 100% scanned.”

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STRUCTURES AND LAND RIG MOBILIZATION

Figure ST-25: 85% surface contact of leg ends at pin connections.

ST-23

Figure ST-27: Wires maintained in a well-lubricated condition.

Note Acute Angle

Figure ST-26: Wire crushed at connection.

Personnel performing NDE shall be required to submit a certification indicating a minimum of a Level II Technician. Nondestructive reports submitted shall indicate the nondestructive method used, the area inspected and a clear pass/ fail status. Material test reports indicating the identification, characteristics and heat number of materials and/or fasteners used for modifications or replacement shall also be considered relevant to the report. Any certifications of conformance for calibration, testing, ratings, coatings, etc. shall also be considered relevant to the final report. Drawings, photos, and finite-element analysis (FEA) reports

IADC Drilling Manual

Figure ST-28: : Guy lines per requirements.

that show repairs and modifications may also be included as relevant to the report, to the extent necessary.

Calibration requirements

Equipment used to inspect, test or examine material or other equipment shall be identified, controlled, calibrated and adjusted at specific intervals in accordance with the manu-

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STRUCTURES AND LAND RIG MOBILIZATION

Figure ST-29: Substructure critical areas.

facturer’s documented procedures or consistent with a recognized industry standard.

A calibrated tape measure is an essential tool and should always be included in an inspector’s equipment.

Useful tools and equipment

Because inspections are often performed by a single inspector, magnets and string can be a useful tool to allow an inspector to determine the bow of a beam over a given length without needing the assistance of another person.

Because inspections are often performed immediately after the sandblasting of a structure, a coarse-haired brush is a convenient tool to have available in order to brush away any excess debris to better visually inspect the entire weld. See Figure ST-29 for images of useful equipment. Bright-colored metal markers are useful for identifying discontinuities located and also serve as a way of indicating areas that will require further non-destructive examination. The use of a handheld telescopic mirror can be helpful for the inspection of welds that are difficult to access or are in areas that are hard to easily see.

IADC Drilling Manual

Because linear measurements are often referenced to the centerline of a given diameter or the centerline of the well, a plumb bob is a useful tool for establishing an extended reference point for intersecting lines of measurement. Fillet gages are used to determine the consistent profile of a weld over a given area. Calipers are used for exact measurements of deformation

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WELL CONTROL EQUIPMENT & PROCEDURES

IADC Drilling Manual 12th Edition IADC Drilling Manual • Copyright © 2015

Proven Leadership Then. Now. Always. Covering well control events of all magnitudes for the past 40 years, our experience and dedication to quality, timely execution of operations has positioned us as industry leaders. When the largest of the world’s oilfield disasters calls for a company that can take on the impossible, Wild Well is there. There then, here now, and always ready with innovative solutions. wildwell.com

WELL CONTROL EQUIPMENT & PROCEDURES

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CHAPTER

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WELL CONTROL EQUIPMENT & PROCEDURES

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. CONTRIBUTORS Fred Mueller, Chevron Lachelle Ahmed, GE Oil & Gas Richard Grayson, Nabors Offshore Drilling David Cormack, Auriga Training Limited Arash Haghshenas, Boots & Coots A Halliburton Service Bhavesh Ranka, Cudd Well Control Mel Whitby, Cameron Drilling Systems Darren Mourre, National Oilwell Varco REVIEWERS Jason Sasarak, BP

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WELL CONTROL EQUIPMENT & PROCEDURES

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9909049-4-6

Printed in the United States of America.

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WELL CONTROL EQUIPMENT & PROCEDURES Contents CHAPTER WC

WELL CONTROL EQUIPMENT & PROCEDURES

Introduction................................................................... WC-1 Blowout preventer stack equipment...................... WC-1 Typical stack arrangement........................................WC-5 BOP design considerations.......................................WC-5 BOP arrangement considerations...........................WC-6 BOP arrangements: surface stacks........................ WC-7 Testing surface stacks with one pipe size..........WC-11 BOP arrangements: subsea stacks.......................WC-15 Inside blowout preventers.......................................WC-17 Choke manifold..........................................................WC-19 Diverter systems........................................................WC-22

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WC-iii

Contents Typical diverter system for onshore and/or bottom-supported offshore installations............WC-26 Typical diverter system for floating installations............................................WC-27 Diverter system maintenance................................WC-27 BOP performance characteristics.........................WC-28 Blowout preventer control systems......................WC-29 Diverter types............................................................ WC-41 Well control procedures......................................... WC-47 Appendix 1: Glossary..............................................WC-A1 Appendix 2: IADC Kill sheets...............................WC-A3

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IADC Safety Toolbox Essential safety alerts and other tools for the crew on the rig floor

IADC SAFETY TOOLBOX

DESIGNED TO SHARPEN SAFET Y SKILL S Sharpen your safety skills with the new IADC Safety Toolbox. Available at no charge at www.IADC.org/safety-toolbox, the searchable IADC Safety Toolbox provides easy access to key IADC safety information, including safety alerts, safety meeting topics, near miss/hit forms, safety posters and more. The IADC Safety Toolbox is easy to use. Users can narrow their search by type of operation (rigging up, lifting, etc), incident classification (LTI, equipment damage, etc.), body part, location (rig type, etc.), incident type (slip, etc.) and equipment. The Online Safety Toolbox provides a practical, user-friendly resource that will seamlessly integrate into daily drilling operations. Contents include: • 700 IADC Safety Alerts; • 125 Safety Meeting Topics for JSAs or other meetings; • Near Miss/Hit Report forms for both drilling and well servicing/workover; • 60 IADC Safety Posters. The Online Safety Toolbox puts critical safety related tools and resources directly in the hands of the rig crew, and is one of several IADC initiatives aimed at enhancing safety in the industry. Access it today!

www.iadc.org/safety-toolbox

WELL CONTROL EQUIPMENT & PROCEDURES

WC-1

Introduction

Preventing and, when prevention is not sufficient, responding to potential uncontrolled releases of oil or gas ("blowout") is critical to safe drilling operations. A kick is an influx of formation fluids into the wellbore. A blowout is an uncontrolled kick exiting the well at surface. Well control is a process that begins with spudding the well and is not complete until the well is put on production and all drilling operations cease. This chapter will examine equipment commonly used in well control and processes used to control kicks of oil or gas.

Blowout preventer stack equipment Annular blowout preventer

The annular blowout preventer is installed at the top of the BOP stack (Figure WC-1) and has the capability of closing (sealing off) on anything in the bore or completely shutting off (CSO) the open hole by applying closing pressure. The sealing device of an annular blowout preventer is referred to as the “packing element”. It is basically a donut-shaped element made out of elastomeric material. To reinforce the elastomeric material, different shapes of metallic material are molded into the element. This keeps the elastomeric material from extruding when operating system pressure or wellbore pressure is applied to the bottom of the packing element. Since the packing element is exposed to different drilling environments (i.e., drilling fluid/mud, corrosive H2S gas and/or temperature of the drilling fluid), it is important to make sure that the proper packing element is installed in the annular preventer for the anticipated environment of the drilling operation. During normal wellbore operations, the preventer is kept fully open by applying hydraulic pressure to position the piston in the open (down) position. This position permits passage of drilling tools, casing, and other items which are equal to the full bore size of the BOP. The blowout preventer is maintained in the open position by relaxing all hydraulic control pressures to the closing chamber and applying hydraulic pressure to the opening chamber. Application of hydraulic pressure to the opening chamber ensures positive control of the piston.

Close preventer operation

In order for the annular BOP to close on anything in the bore or to perform a complete shut-off, CSO or open-hole closure, closing pressure must be applied. A CSO is typically limited to 50% of the annular rated working pressure, RWP. As the piston is moved to the closed position, the elastomer packer is squeezed inward to a sealing engagement with

IADC Drilling Manual

Figure WC-1: Schematic (top) and photo of annular blowout preventers. Photo courtesy GE Oil & Gas. Top image, IADC drawing.

anything in the bore or on the open hole. Compression of the elastomer throughout the sealing area assures a strong, durable seal off against almost any shape, even with a previously used or damaged packer. The piston is moved to the closed position by applying hydraulic pressure to the closing chamber. Guidelines for closing pressures are contained in the operational section for each manufacturer’s type of annular blowout preventer and in the Operator’s Manual. The correct closing pressure will ensure long life, whereas excessive or deficient closing pressures will reduce packer life. The pressure regulator valve of the hydraulic control unit should be adjusted to the manufacturer’s recommended closing pressure. As the packing element rubber deteriorates, higher closing pressures may be required to effect a seal. Subsea applications may require an adjustment of closing pressure due to effects of the hydrostatic head of the control fluid and of the drilling fluid column in the marine riser. Some manufactur-

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WC-2

WELL CONTROL EQUIPMENT & PROCEDURES

Figure WC-2: Schematic of ram-type BOP. IADC drawing.

Video WC-1: Animation shows internal BOP action. Courtesy National Oilwell Varco.

ers may also require limiting the closing pressure depending upon the diameter and wall thickness of casing or large diameter tubulars. The applicable operator’s manual will explain these requirements.

Stripping with an annular BOP

Drillpipe can be rotated and tool joints stripped through a closed packer while maintaining a full seal on the drillpipe. Longest packer life is obtained by adjusting the closing chamber pressure just low enough to maintain a seal on the drillpipe with a slight amount of drilling fluid leakage as the tool joint passes through the packer. The leakage indicates the lowest usable closing pressure for minimum packer wear and provides lubrication for the drillpipe motion through the packer. A pressure regulator valve should be set to maintain the proper closing pressure. For stripping purposes, the regulator valve is usually too small and cannot respond fast enough for effective control, so a surge bottle is connected as closely as possible to the BOP closing port (particularly for subsea installations). The surge bottle is pre-charged with nitrogen, and is installed in the BOP closing line in order to reduce the pressure surge which occurs each time a tool joint enters the closed packer during stripping. A properly installed surge bottle helps reduce packer wear when strip-

IADC Drilling Manual

Figure WC-3: Schematic (top) and photo of typical subsea BOP stack. Photo courtesy GE Oil & Gas. IADC drawing at top.

ping. Check manufacturer’s recommendations for proper nitrogen precharge pressure for your particular operating requirements. In subsea operations, it is advisable to add an accumulator to the opening chamber line to prevent undesirable pressure variations.

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WELL CONTROL EQUIPMENT & PROCEDURES

Figure WC-4: Blind rams. IADC drawing.

WC-3

Figure WC-6: Variable bore rams. IADC drawing.

Figure WC-5: Pipe rams. IADC drawing.

Ram-type blowout preventer

A ram-type blowout preventer is basically a large bore valve (Figure WC-2). The ram blowout preventer is designed to seal off the wellbore when pipe or tubing is in the well. In a BOP stack, ram preventers are located between the annular BOP and the wellhead. (See schematic of a typical subsea BOP stack in Figure WC-3.) The number of ram preventers in a BOP stack ranges from one to eight depending on application and water depth. Flanged or hubbed side outlets are located on one or both sides of the ram BOPs. These outlets are sometimes used to attach the valved choke and kill lines too. The outlets enter the wellbore of the ram preventer immediately under the ram cavity. Other than sealing off the wellbore, rams can be used to hang-off the drillstring. A pipe ram, closed around the drillpipe with the tool joint resting on the top of the ram, can hold up to 600,000 lb of drillstring. Several different types of rams are installed in the ram type BOP body. The five main types of rams are blind rams, pipe rams, variable bore rams, shearing blind rams, and casing shear rams. Following is a brief description of each type: ŸŸ Blind rams: Rubber sealing element is flat and can seal the wellbore when there is nothing in it, i.e., “open hole” (Figure WC-4); ŸŸ Pipe rams: Sealing element is shaped to fit around a variety of tubulars with a particular diameter, which

IADC Drilling Manual

Figure WC-7: Schematic (top) and photo of Upper and lower shearing blind rams. Photo courtesy GE Oil & Gas. IADC drawing at top.

include production tubing, drill pipe, drill collars, and casing that will seal off the wellbore around it (Figure WC-5); ŸŸ Variable bore rams: Sealing element is much more complex and allows for sealing around a particular range of pipe sizes (Figure WC-6); ŸŸ Shearing blind rams: Blade portion of the rams shears or cuts the drillpipe, and then a seal is obtained much like the blind ram (Figure WC-7); ŸŸ Casing shear rams: Casing shear rams are typically shearing rams only and will not seal. They are specifically designed to cut large diameter tubulars that are incapable of being sheared by blind shear rams. Note: Shear rams are also available that are capable of shearing multiple tubing strings and large diameter tubulars while maintaining a reliable wellbore pressure seal.

Operation and use of pipe rams

As described earlier, pipe rams are designed to fit around certain diameter tubulars to seal off the wellbore (annulus) in a blowout situation. Most pipe rams are designed with re-

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WC-4

WELL CONTROL EQUIPMENT & PROCEDURES

placeable elastomer packers and top seals. Besides sealing off the wellbore in an emergency situation, the pipe rams can be used for stripping. Use of two ram-type preventers would only be resorted to if the annular preventer was badly worn. However, stripping drillpipe through rams can be done with less string weight than if the annular preventer is used, since there is no closure around the larger diameter of the tool joints. One additional ram-type BOP must always remain available below any used for stripping, to allow the well to be closed in safely.

Stripping with ram-type BOPs

Stripping through ram-type BOPs requires at least three preventer ram cavities fitted with the proper size rams for the pipe to be stripped. If the pipe string is a tapered string, i.e., having more than one size pipe in the string, two preventer ram cavities will be required for each size of pipe in the string. A tapered pipe string can be stripped using only two preventer ram cavities provided variable (multiple) bore rams are used. Variable bore rams have a specified pipe size range and will seal off on any size pipe within the size range. The two preventer ram cavities used for stripping should be spaced sufficiently far apart so that closed rams in each preventer cavity will clear the length of a pipe connecting joint. This also includes any upset (increased pipe diameter) portions adjacent to the connection. The distance between the two preventer ram cavities should provide enough additional space so that positioning the pipe joint between the cavities does not require an excessive amount of precise positioning. When operations indicate that a considerable amount of stripping may be required, it is advisable to include a third preventer ram cavity fitted with pipe rams for added safety and to permit replacement of the ram packers in the stripping preventers. The pipe rams in the upper two preventer cavities would be considered the “stripping” rams while the pipe rams in the third preventer cavity would be “safety” rams. Stripping pipe through ram packers causes wear on the packers and packer replacement is sometimes required. The safety rams in the third preventer cavity will permit well pressure to be shut in below the stripping preventers when required. The preventer with safety rams is only closed on a stationary pipe string and therefore the rams do not receive much wear, thus always providing a reliable backup closure. Stripping requires no special equipment beyond what is normally available on a drilling rig; however, as the pipe string becomes insufficient to overcome the upward force of the well pressure acting on the pipe, provisions must be made for restraining the pipe string against upward movement. At this point, the stripping operation becomes a “snubbing” operation. Capability for pipe snubbing is also required when starting a pipe down into the wellbore against well pressure.

IADC Drilling Manual

Ram locking device

A ram locking device must be fitted to all ram blowout preventers. This device is used whenever it is necessary to remove hydraulic operating pressure from the “close” side of the ram operating system, but maintain the ram preventer in the close position. Ram locking devices are used when rams will be closed in for a long period of time as a contingency plan for a loss of hydraulic pressure scenario. On BOP stacks that are used in a surface application, the ram locking device is a threaded rod, referred to as a “lock screw”. This lock screw reacts between the operating piston in the ram operating system, and the housing of the lock screw. The locking device on a ram preventer that is used in a subsea application must be designed to be remotely actuated by either the BOP hydraulic control unit, or by the actual movement of the operating piston in the ram operating system.

Operation and use of shearing blind rams

Under normal operating conditions, shearing blind rams are used as blind rams. The large front packer in the upper shear ram seals against the front face of the lower shear ram, resulting in prolonged packer life similar to that of standard blind packers. If emergency conditions make it necessary to shear the drillpipe, the closing shearing blind rams will shear the pipe and seal the wellbore whether the fish (the lower section of sheared pipe) is suspended on the lower pipe rams or dropped. If the fish is not dropped, the lower shear ram will bend the sheared pipe over a shoulder and away from the front face of the lower shear ram which then seals against the packer in the upper shear ram. If different grades, weights, or large diameter pipe has to be sheared, each oil tool manufacturer has a variety of shear rams available to perform the shearing operation.

»» Recommended shearing procedures

1. Raise the bit off the bottom and position the pipe in the preventer so that the tool joint is positively NOT in the shear ram cavity. 2. To ensure proper alignment for shearing, a set of pipe rams may be closed before the shearing blind rams are closed. Also, if the fish is not to fall downhole after being sheared, a tool joint may be landed on closed and locked pipe rams at least 30 in below the shear rams. The tool joint and upset portion of the drillpipe must be below the lower edge of the shear ram cavity to ensure that the pipe is sheared successfully. 3. Close the shearing blind rams with 3,000 psi on the BOP operating system. The accumulator system should be sized such that the pressure does not fall below 2,700 psi during

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WELL CONTROL EQUIPMENT & PROCEDURES the shearing operation. The hoses for the open and close functions of the BOP are recommended to be at least one inch in diameter.

WC-5

Figure WC-8: Typical blowout preventer arrangement for 10,000-psi and 15,000-psi working pressure service surface installations. IADC drawing.

4. Lock the shearing blind rams in the closed position by actuating the manual lock or applying locking (closing) pressure to the appropriate locking mechanism as required. 5. If the lower fish is suspended in pipe rams below the shearing blind rams, killing mud may be circulated through a BOP outlet between the shearing blind rams and the pipe rams and into the lower fish in order to circulate a kick out of the hole in the conventional manner.

Care and maintenance of all blowout preventer stack equipment

Each manufacturer has individual care and maintenance manuals for each product of the blowout preventer stack. They should be contacted for detailed information regarding their specific recommendation on each piece of equipment. Proper care and maintenance is essential to keep the equipment working.

* Annular preventer A and rotating head G can have lower pressure ratings.

Typical stack arrangement and testing procedures for a surface stack The American Petroleum Institute has established standard nomenclature for describing BOP components and ratings, including the following information:

BOP component codes Code Component A Annular Rotating Head G R Single Ram Rd Double Ram Rt Triple Ram S Drilling Spool

Example API BOP stack

"5M - 13 5/8 in. SRRA" describes a 5,000-psi W.P., 13 5/8-in., 5M bore stack with components from bottom up, consisting of a drilling spool, two single rams and an annular BOP. For control of any well, blowout preventer stacks and associated kill/choke lines and valving must be arranged to provide a high degree of backup and flexibility. Figure WC-8 illustrates typical arrangements for BOP and choke/kill manifolds. However, this API standard deals with the subject only in a general way. The majority of this section will be devoted to analyzing several specific BOP stack arrangements. Before doing this, first consider certain general facts concerning BOP design and arrangements.

BOP design considerations

The principal BOP design considerations are to: ŸŸ Confine wellbore pressure; ŸŸ Provide for passage of tools.

Pressure code

M = 1,000-psi rating working pressure

Controlling bottomhole pressure while killing a well is the primary purpose of a BOP. In most cases, the BOP working

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WC-6

WELL CONTROL EQUIPMENT & PROCEDURES

pressure exceeds the limit of all other well control system elements. A BOP stack should be able to contain the maximum anticipated surface pressure, which is essentially the full bottomhole formation bore pressure.

Flexibility and safety

Obviously, the BOP bore must be large enough for passage of anticipated tool sizes. On occasion, underreamers must be used to open the hole because of BOP bore restrictions. Pilot holes are sometimes drilled to investigate formation pressure and the BOP is removed to open the hole and run casing. This practice could be disastrous. The BOP bore should be sufficient to provide protection during any drilling process.

Both arrangements consist of a singular annular and three rams. The advantages and disadvantages of these arrangements in terms of flexibility and safety will be discussed.

BOP arrangement considerations

Specific BOP arrangements are based on the following considerations: ŸŸ Governmental regulations; ŸŸ Company policy; ŸŸ Physical size and cost; ŸŸ Flexibility and safety.

Governmental regulations

Rules and regulations governing the operation of a BOP in the USA outer continental shelf areas are contained in the Bureau of Safety and Environmental Enforcement (BSEE) 30 code of Federal Regulations Part 250. These rules and regulations must be complied with. Likewise, in other areas of the world, governments will usually have local regulations governing the use and testing of BOP stacks.

Company policy

Both the Operator and the Contractor will usually have their own policies concerning BOP stack configuration and testing. The operator should be made aware of the contractor’s policies prior to the occurrence of any kick.

Physical size and cost

If physical size and cost is no consideration, the ideal situation would be to have only one BOP stack of sufficient bore, working pressure and backup components to drill the complete well. Such stacks are actually being built for deepwater subsea operations where such designs can be justified. Most non-floating rig BOPs are surface mounted. Two independent stack arrangements are normally used. A large-bore, relatively low-pressure stack consisting of an annular only, or an annular plus one or two rams, is used for well control until surface casing is set. This large bore stack sometimes is used as part of a diverter system. After setting surface casing, a small bore stack of higher working pressure is normally used to TD.

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The rest of this section will analyze two BOP stack arrangements used for maintaining control below surface casing on non-floating type rigs.

Also, included are recommendations for developing a safe, efficient BOP test procedure and the description of a specific test sequence for one of the subject stack arrangements. There can be no “best” standard stack arrangements, since each drilling environment and rig influences, to some degree, BOP equipment configuration. But a closer look at several good hookups highlights principles that will be helpful to anyone responsible for arranging or inspecting BOP stacks.

BOP arrangements: surface stacks

The drilling business is often a series of compromises, both in equipment and practices. This is certainly true with BOP stack arrangements.

Location of the shear/blind ram

Consider placement of blind rams in a 3-ram surface BOP stack. If blind (or shear) rams are placed at the bottom of the stack, with no flowlines below, then the BOP stack has the advantage of a “master valve” for open hole situations or a last resort valve if all else fails during a kick. But this placement also imposes limitations on stack use. For example, drillpipe cannot be hung off on pipe rams below the blind ram and the well killed by circulating through the drill stem. This arrangement may also force placement of pipe rams so close together that adequate space is not available for ram-to-ram stripping. On the other hand, if blind rams are placed at the top of the ram BOP stack, they can be replaced with pipe rams for ramto-ram stripping operations to either protect the lower pipe ram or in the event of a tapered string, to furnish the pipe ram size that will fit the size of drillpipe being stripped. But this arrangement also presents a problem because it prevents the utilization of the blind ram as a master valve in open hole situations, for repair of items above it or changing to casing rams. It also may force spacing of pipe rams so close that the ram-to-ram stripping is impossible. The question arises as to how to best maximize advantages of both of these placements and minimize disadvantages. The two compromise arrangements illustrated in this section (Figures WC-9 and WC-10) place blind rams on top for tapered string drilling and in the middle when one size drillpipe is being used. This allows hanging off pipe in the

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WELL CONTROL EQUIPMENT & PROCEDURES pipe rams and circulation through the drill stem when kill and choke lines are placed properly, adequate clearance for ram-to-ram stripping and partial utilization of the blind ram as a master valve for equipment out of hole repairs (top ram change to casing size obviously being safer with the blind ram in the middle).

To Test Manifold P

Figure WC-11 depicts a standard length API NC50 pin and box joint. An extra-long joint would probably not clear the shear ram in a standard 5,000-psi BOP. Each arrangement must be reviewed on a case-by-case basis.

Vent

P

To Shaker

Arrangement of a double and a single ram unit

A standard size 13 5/8-in., 5,000-psi flanged double ram should be mounted on top of a single ram unit. This provides sufficient space for shearing above a standard 5–in. API NC50 connection hung in the bottom pipe ram as illustrated in Figure WC-11. This is the best arrangement for use with a single drillpipe size.

WC-7

From Cement Unit

From Mud Pumps

5

P

Annular

Top Pipe Ram

Shear/ Blind Ram

1

2a Alternate location

Bottom Pipe Ram

4

2

3

Figure WC-9: BOP arrangement for one pipe size. IADC drawing.

Some contractors prefer to assemble the single on top so that the annular and the single can be separated from the double for purposes of easier handling. Trade-offs may be necessary in this matter. The primary aim here is not to debate each point, but to emphasize the importance of critically reviewing BOP arrangements.

To Test Manifold

Vent

P P

To Shaker

Activities possible: One pipe size

From Cement Unit

Refer to Figure WC-9:

1. Normal kill down drillpipe using either pipe ram; a. Choke flowlines 2 and 4 below each pipe ram. 2. Kill with blind or shear ram closed; a. Double ram unit must be on top of single ram to provide sufficient space for hang off and shear; b. Kill flowline 1 and choke flowline 4 must be arranged as shown. 3. Ram-to-ram stripping; a. Blind ram must be in middle to provide sufficient space; b. Kill flowline 1 to equalize pressure before opening bottom ram; c. Choke flowlines 2 and 4 to bleed fluid and monitor pressures below each ram during stripping; d. Kill flowline 3 to lubricate in fluid (volumetric method when bleeding gas) or kill below bottom ram; e. Could also strip between annular and either ram and do items 2, 3, or 4 above. 4. Location of blind ram in the middle. a. More room for ram-to-ram stripping as previously mentioned; b. Safe “out of hole” top ram change, annular element change or repairs to the single ram unit or annular.

From Mud Pumps

5

P

Annular

Blind Ram

1

Small Pipe Ram

Large Pipe Ram

4 2

3

Figure WC-10: BOP arrangement for two pipe sizes. IADC drawing.

Must Shear Above Upset

Annular

Pipe Upset

Top Pipe Ram

Pin Shear Ram

25”

14.56”

Bottom Pipe Ram

25.56”

Box

Pipe Ram CIW 13 5/8” 5000 psi Type-U Double and Single

Set on Ram

5” XH Tool Joint (standard)

Figure WC-11: Clearance for shearing. One pipe size. IADC drawing. K1-4C Clearance for Shearing

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WC-8

WELL CONTROL EQUIPMENT & PROCEDURES NOTE: Location of primary choke flowline 2 at alternate location 2a will allow all previously mentioned activities but is somewhat more exposed to mechanical damage. Double ram units can be special ordered with enough room between rams to hang-off and shear. This special “long neck” double ram unit could be put on bottom, best satisfying both single and tapered string application. This discussion considers standard height double and single BOP units only, with no spool or special stacks, so the most practical compromise is to place the double ram unit on top.

Activities possible: Two pipe sizes Refer to Figure WC-10:

Figure WC-12: Normal kill down drill pipe using ram. One pipe size. IADC drawing.

Figure WC-13: Kill with blind or shear ram closed. One pipe size. IADC drawing.

1. Normal kill down drill pipe using either pipe ram; a. Choke flowlines 2 and 4 below each pipe ram. 2. Kill with blind or shear ram closed; b. Can hang off in large pipe (bottom) rams, shear, and kill; c. Can hang off in small pipe (top) rams but cannot shear due to small space so must back off before closing blind rams; d. Kill flowline 1 and choke flowlines 2 and 4 must be arranged as shown. 3. Ram-to-ram stripping; a. Could change blind ram to large pipe size and strip ram-to-ram but the arrangement shown provides insufficient space to strip small pipe ram-to-ram; b. Kill flowline 1 to equalize pressure before opening bottom rams; c. Choke flowlines 2 and 4 to bleed fluid and monitor pressures below each ram during stripping; d. Kill flowline 3 to lubricate in fluid (volumetric method when bleeding gas) or kill below bottom ram; e. Could also strip between annular and either small or large ram and do items 2, 3 and 4 above. NOTE: Relocation of kill flowline 1 required to accomplish kill procedures mentioned in items 2c and 3b; 4. Location of blind rams on top: a. Can accomplish kill with either size pipe hung off; b. Can change to large pipe size for ram-to-ram stripping; c. Can change to either pipe size thereby minimizing wear on lower pipe rams, which inevitably occurs when pipe is worked with rams closed; d. A disadvantage is open-hole exposure while installing casing rams while out of hole.

Figure WC-14: Ram-to-ram stripping. One pipe size. IADC drawing.

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NOTE: If the single ram unit were arranged on top of the double unit or there was enough space between the top and the middle ram provided some other way, then small pipe ram-to-ram stripping might be possible.

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WELL CONTROL EQUIPMENT & PROCEDURES NOTE: Refer to items 2b and 3a for Figure WC-10: Arrangement for tapered strings indicates that space between the blind rams and small pipe rams limits certain activities. For tapered string application, this space problem could be eased by stacking the single ram unit on top of the double ram unit. Figure WC-3 shows the double on top, another compromise. In field use it is not practical to rearrange the BOP stack just before picking up a smaller drillpipe string. Double ram units can be special ordered with enough room between rams to hang-off and shear. This special “long neck” double ram unit could be put on bottom, best satisfying both single and tapered string applications. This discussion considers standard height double and single BOP units only, with no spool or special stacks, so the most practical compromise is to place the double ram unit on top.

Choke and kill flowlines

Annular Blind Ram

1

2

Small Pipe Ram Large Pipe Ram

Check (non-return) valves, are located in each “kill” wing valve assembly for the following reasons: ŸŸ To stop backflow in case the kill flowline ruptures while pumping into the well at high pressure; ŸŸ Other kill flowline gate valves between the check valve and BOP can be left open during kicks for pumping into the well whenever desired without personnel having to open them. Kill lines should not be used as fill-up lines. Constant use could result in erosion of lines and valves which would result in an unsuitable kill flowline. A separate line from the mud standpipe (independent of all choke and kill flowlines) is desirable for filling the hole during trips. Inboard valves adjacent the BOP stack on all flowlines are manual operated “master” valves to be used only for emergency. Outboard valves should be used for normal killing operations. Hydraulic operators are generally installed on the primary (flowlines 1 and 2 in Figures WC-9 and WC-10) choke and kill flowline outboard valves. This allows remote control during killing operations. Choke/kill flowlines are generally not connected to the casing wellhead outlets but valves and unions are provided there as:

Flow with annular or small ram closed 4

Flow with large ram closed

3

Figure Kill down pipeeither usingram. either FIGUREWC-15: K1-8C Kill down drill drill pipe using ram. Two pipe sizes. IADC drawing.

Arranging rams is important, but choke and kill flowline (wing valves) placement is equally important to fully utilize the BOP. Again, compromises are made between the most conservative position of having no flowlines below the bottom ram and a middle road position of arranging the flowline for maximum BOP usage. Figures WC-9 and WC-10 illustrate two BOP and wing valve arrangements. Activities possible with each of these two arrangements are summarized near the figures and further illustrated in Figures WC-12 through WC-17.

WC-9

Annular Blind Ram

1

2

Small Pipe Ram Large Pipe Ram 4

3

FIGURE K1-9C Kill blink or shear ram closed.

Figure WC-16: Kill blind or shear ram closed. Two pipe sizes. IADC drawing.

Annular Large Pipe Ram

1

2

Small Pipe Ram Large Pipe Ram 4

3

Figure WC-17: Ram-to-ram stripping. Two pipe sizes. IADC drawing. FIGURE K1-10C Ram to ram stripping

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K1-10C

WELL CONTROL EQUIPMENT & PROCEDURES

WC-10 Alternate

P

P

P

P

Lift Drill Pipe

From Cement Unit Test Pressue From Cement Pump

From Mud Pumps

Annular

P

From Cement Unit

From Mud Pumps

P Annular Top Ram Pipe

Top Ram Pipe

Blind Ram

Blind Ram

Bottom Pipe Ram

Bottom Pipe Ram Casing Head

Figure WC-18: Testing entire casing string and casing head valves. IADC drawing.

Figure WC-19: Testing upper casing joints FIGURE K1-12C Testing Upper Casing Joints after Drilling Shoe after drilling shoe. IADC drawing.

ŸŸ Reserve outlets for emergency use only; ŸŸ Relief openings to prevent pressurizing of casing and open hole should a casing head plug tester leak during BOP testing.

4. All connections in choke, kill and relief lines, and the choke manifold should have a pressure rating at least equal to the rating of the BOP stack;

Flowing through a casing head outlet should be avoided. Should this connection be ruptured or cut out, there is no control. Therefore, primary and secondary choke and kill flowlines should all be connected to heavy duty BOP outlets (or spool outlets) with wellhead outlets used only in an emergency.

5. Choke and kill wing valves are subjected to severe mechanical and vibrational stresses during drilling operations and when handling or controlling a “kick”. Where practical, all overhanging valves, piping and connections should be supported.

Suggestions for rigging up surface stacks

The following practices and principles should be considered: 1. All ring grooves should be cleaned of heavy grease. A ring will not seal properly if the ring groove is full of grease or “puddled” oil. A “light” film of oil only should be applied to ring grooves before nippling up. Avoid using a wire brush which would damage seal surfaces; 2. To achieve proper make-up torque on flange, clamp or BOP bonnets, a power torque wrench is useful. Bonnet bolt makeup torque is high and, if not properly tightened, could vibrate loose during drilling. Makeup torque tables are available from BOP manufacturers. Most tables give required torque using either API 5A thread lube or Moly-lube. Torque requirements using Moly-lube are much less so always be aware of the relationship between the lubricant and the torque requirement; 3. Plug all BOP control lines not in use to prevent accidental loss of accumulator fluid. Do not couple unused open and close control lines together. Plug them!

NOTE: When operating wing valves that have pressure on them, proper manufacturer procedures should be observed to prevent explosive decompression of the elastomer. 6. Swivel joint pipe sections in flowlines are necessary for ease of rig-up, but where practical, “choke” flowlines from BOPs to manifold should be straight or curved (hoses). Sharp turns should be minimized, and where practical, targeted tees with lead-filled bull plugs should be used to minimize flow stream erosion. Using swivel joint pipe in kill flowlines is not as bad, because of less severe vibrations and fluid conditions. 7. Choke flowlines conduct well fluid under pressure from the well to the choke manifold. Flow velocities are sometimes greater than through the kill line by virtue of the expansion of gas in the annulus, so small lines may create high pressure drops and erosion. By sizing the primary choke line to a larger size (minimum 3–in. I.D. instead of 2–in.), the line will have greater strength, less frictional pressure loss and be subjected to less wear. All lines should be properly secured. 8. Where applicable, all connections, piping and valves in flowlines should be protected from freezing by draining, heating or keeping the line filled with non-freezing fluid.

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WELL CONTROL EQUIPMENT & PROCEDURES

P

From Cement Test Unit Pressure From from Mud Cement Pumps Pump

P

P

Annular

From Cement Unit

P

From Mud Pumps

WC-11

Test Pressure Through Drill Pipe

P

Annular

P Top Ram Pipe

Top Ram Pipe Blind Ram

Blind Ram

Remove Checks When Testing Kill Wing Valves

Bottom Pipe Ram

Open Casing Head

Open Casing Head

Keep Open

Bottom Pipe Ram

Keep Open

Casing Head Plug Tester Casing Head Test Plug with Port

Stand of Drill Collars FIGURE K1-13C Testing Blind Ram

Figure WC-20: Testing blind ram. IADC drawing.

K1-13C

9. The gas/mud separator (gas box), vessel diameter, gas vent exhaust and mud seal at the discharge should be designed to separate the maximum expected influx and not allow gas to exit the mud discharge or mud to exit the gas vent.

Testing surface stacks with one pipe size

This section contains a typical BOP test procedure using the Figure WC-9 (one pipe size) arrangement. Figures WC-18 through WC-21 illustrate each test step. The objective of this test example is to focus on principles that could apply for testing any BOP systems.

Test frequency, pressures and fluids

BOP test pressure and frequency requirements vary among governmental regulators, operators and contractors. The following are general recommendations.

Frequency

ŸŸ After initial installation; ŸŸ After each casing setting operation; ŸŸ Before drilling into any known or suspected highpressure zones; ŸŸ Routine test no less than once each seven days of operation; ŸŸ After a ram change, maintenance or BOP repair, test the component that was affected; ŸŸ Prior to a production test.

Test pressures

The rams and annulars should betested in two stage, at a low pressure test of 200-300 psi and then at maximum test pressure. Both pressure holding periods should not be less than three minutes. A 5 or 10 min holding period is common.

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FIGURE K1-14C Testing pipe rams, annular, all choke and kill manifolds, flow lines, and BOP wing valves.

Figure WC-21: Testing pipe rams, annular and all choke and kill manifolds, flow lines, and BOP wing valves. IADC drawing.

Rams and choke manifold should be tested to full working pressure upon: ŸŸ Initial installation of BOP on wellhead; ŸŸ Maintenance or repair. Only test the affected component(s). Routine ram and choke manifold maximum test pressure should be limited to the lesser of: ŸŸ 70% of rated working pressure; ŸŸ Wellhead rated working pressure; ŸŸ 70% of casing minimum internal yield strength. However, in no case should these or subsequent test pressures be less than the maximum anticipated surface pressure. The annular BOP maximum test pressure should not exceed 70% of rated working pressure or 70% of casing minimum burst strength, whichever is less. If governmental regulations or the operator does not stipulate annular BOP test pressures, do not exceed 50% of working pressure. All well control system components should be tested in the direction normally felt by wellbore pressure during a kick.

Test fluids

ŸŸ For water-based muds, use water. ŸŸ For oil-based muds, use diesel or acceptable alternative.

General testing procedures

ŸŸ All choke manifold and choke and kill flowlines should be flushed out before each test and clean water be inside all systems being tested when pressure is applied. Drilling mud is a good sealant, which makes it an unsuitable test fluid. ŸŸ Pipe-rams should be closed only when there is pipe in the hole. Closing rams on the wrong size pipe or ON

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WC-12

WELL CONTROL EQUIPMENT & PROCEDURES a swab and must have the proper OD to fit upper size and weight casing joints. This test should be performed regularly. However, actual test interval depends upon regulations and company policy. The appropriate cup tester is made up on drill pipe and lowered approximately 90 ft (two casing joints) below the casing head. Some operators require that the cup tester be run into the casing to a point below cement on the outside. After filling the stack with clean water, the top pipe rams or annular is closed. Pressure is built up by either pumping down the flowlines or by hoisting the drill string slowly (as shown in Figure WC-19) to provide desired pressure. Hoisting the drillstring is preferred over pumping, because there is less chance of accidentally exceeding casing yield or drillpipe strength. Pressure applied to the cup tester directly imposes a load on the drillpipe test string which could cause drillpipe failure, particularly with Grade E. The usual problem is collapsed pipe due to a combination of outside crushing forces and pull.

A safe approach is to use Grade S135 or heavy wall Figure WC-22: Cup-type Figure WC-23: Test plug. IADC drawing. drillpipe for all casing tests. Another technique is to run a casing head plug tester in combination with a tester. IADC drawing. cup tester. The casing head plug would be spaced OPEN HOLE could result in ram front packer damage. out 90 ft above the cup with heavy wall pipe. After This fact is often overlooked. landing the casing head plug, test pressure would be applied ŸŸ To prevent collapsed pipe, vent the annulus when through the casing head outlets. This allows the cup-inclosing a pipe ram. If a ram is forced into a closed BOP duced forces to be supported by the casing head. bore, the trapped fluid pressure will rise rapidly as the operating cylinder rod enters the BOP cavity.

A BOP test sequence

Figures WC-18 through WC-21 provide schematics for testing BOP stacks and casings. Explanations and reasoning behind the different schematics and procedures are discussed briefly in this section.

Entire casing string and casing head valves Figure WC-18 shows the schematic for testing the BOP and casing. There is no cup tester in the BOP stack. To avoid exerting external pressure to the formation, this test is performed after cementing the casing and when the bumped cement plugs are sealing. Some operators prefer to apply casing test pressure when the cement plug bumps. The reasoning is that micro-cracks in the cement may occur if test pressure is applied after cement has set up.

Upper casing joints after drilling the shoe

See Figure WC-19. After drilling the casing shoe, all future tests of casing and casing head requires use of a casing cup tester (Figure WC-22). The cup tester is nothing more than

IADC Drilling Manual

Regardless of the approach, remember that all cup testers are swabbing devices. To prevent swabbing, pull the cup slowly and never run a test string that is not fully open to atmosphere. In other words, the underside of the cup must always be open through the test string bore. 1. Before drilling out any casing shoe, test entire casing to operator’s specifications, but never exceed 70% of rated casing burst pressure; 2. Flush all lines and fill BOP with test fluid. (Test fluid might be water or diesel, depending on the type of fluid, as discussed on page WC-11 ["Test fluid"].) Close blind ram. Pressure up using cementing pump through kill manifold or a special test pump through (alt.) point. This tests entire casing string plus casing head valves. NOTE: Casing tests are the only tests where casing head valves are closed. These valves should always be open for other tests to prevent casing or formation rupture should casing head plug tester leak.

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WELL CONTROL EQUIPMENT & PROCEDURES

Wellbore test pressure, psi 5,000

5,0 00 ps

,00

1. Ensure that casing head valves are always open when a casing head plug tester is in use. This allows detection of a plug tester seal leak and prevents over pressuring of casing or open hole; 2. Casing head plug testers come in many shapes and sizes. Figure WC-23 illustrates a test plug. Some have special features such as integral ports. Some have open bore with bull plugs provided for testing the blind rams while others are solid bore. Some function as combination plug testers and wear bushing retrievers.

IADC Drilling Manual

/4”

Several precautionary notes are necessary for test steps illustrated in Figures WC-20 and WC-21.

0 1,500

1-1

Because the BOP bore is being pressured through the drillpipe, all valves can be tested in the normal well kick direction. By sequencing valves, open and closed in proper order, a minimum of repressuring will be necessary. Always leave downstream valves open and remove the spring loaded check in the check valve (when applicable) to ensure a valid test on each kill valve. It is important that all manifolds and flowlines be flushed out before this test so that all are clear and full of water.

02

See Figure WC-21. Some casing head plug testers are manufactured with an integral port which allows the BOP bore cavity to be pressured by pumping down the drillpipe test string. If the plug tester is not equipped with an integral port, a perforated sub could be used with the test plug. Be sure the casing head outlet is open to prevent pressuring casing and open hole.

1,000

psi

0 psi

P2 MS

Most kill and choke manifold valves, flowlines, and BOP wing valves could be pressured during the Figure WC-20 test. However, the test string arrangement in Figure WC-21 (pressuring down the drillpipe which simulates a well kick) is best suited for this purpose because all valves can be tested in the direction that the pressure is applied during a kick. Therefore, Figure WC-20 test is designed primarily to test the blind ram only by pressuring down a kill flowline.

GL 16-3/4”,

i

2,000

Testing BOP stack

GL 13-5/8”, 5,000

4”

3/ 6-

3,000

18-3/4” 5,00

,1 8”

5/ 3-

4,000

4. Build up test pressure to operator’s specifications by lifting drilling pipe, being careful not to exceed 70% of rated casing burst pressure or tensile strength of drill pipe being used.

Limit to min. 50 psi during actual kic k

1 GK

3. Run appropriate size and weight casing cup tester on drillpipe to approximately 90 ft below casing head. Fill annulus with water and close top ram;

WC-13

1000 500 Opening pressure

0

500 1,000 Closing pressure

P

MS

500

”

1/2

29-

1,500

Opening pressure, psi * Operating pressure may vary with individual packing elements (bags). Adjust operating pressures accordingly, but do not exceed maximum closing pressure of 1,500 psi except on CIW Type-D annulars. ** During actual kick situations, for safety’s sake, operating pressure should not be applied to the OPENING chamber of wellbore pressure.

Figure WC-24: Annular operating characteristics with 5-in. drillpipe.* (Actual values may vary.) IADC drawing.

Failure to select the proper size and style test plug can cause problems. Casing head hanger contours vary. For example, a CIW Type “F” 5,000-psi tubing head has tapered contours, while the Type DCB head is straight contoured. Insert a Type “F” plug tester in a Type DCB head, pressure K1-18C K1-18C: Annular operating characteristics with Always up,Figure and 5-inch the two will become almost inseparable. drill pipe (Actual values may vary). consult with the casing head manufacturer to ensure that the appropriate plug tester is being used. The rams, annular, and hydraulic operated valves should be tested in two stages. API Standard 53 (4th edition, section 6.5.3.2) recommends a low pressure test of 250-350 psi held for at least 5 minutes before pressuring up to full test pressure. There are several reasons for this. Many preventers are designed such that the wellbore pressure (test pressure) causes a closing force, so the BOP may be more likely to leak at low pressure than at full test pressure. Because actual well kicks are normally closer to 300 psi than full working pressure, the low pressure test is significant. Also, mud solids sometimes plug a potential leak hole. A low pressure test will come closer to uncovering this hole than the full test pressure. Some annular preventers will hold maximum test pressure with no more than 700-1,000 psi operating pressure. Because of special design features, operating pressure (from accumulator) should be reduced on Hydril GK and 21 1/4–in.

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WELL CONTROL EQUIPMENT & PROCEDURES

WC-14

Table WC-1: Schedule of operating vs. test pressure Psi-regulated Psi pressure

Operating pressure closing test side

Opening side

0

700*

N/A

1,000

300

N/A

1,500

50

N/A

2,000

N/A

50**

2,500

N/A

300

3,000

N/A

500

3,500

N/A

700

MSP annulars as the test (wellbore) pressure increases. This greatly reduces element stress. For example, on a GK 16 3/4– in. 5,000-psi annular, if operating pressure is held at 700 psi (closing chamber), the compression force on the element increases from approximately 380,000 lb at zero test pressure to about 780,000 lb at 3,500-psi test pressure. On the other hand, if operating pressure is reduced according to Figure WC-24, compression force on the element will actually reduce to about 180,000 lb. If an annular BOP of this type is tested, use an operating pressure versus test pressure chart to minimize element stress. Alway consult the operating manual and/or the manufacturer for testing procedure and operating recommendations. From Figure WC-24, the schedule for test pressure vs operating pressure shown in Table WC-1 was developed for a 13 5/8–in. or 16 3/4–in. GK 5,000-psi annular on 5–in. drillpipe. Notice that at test pressures higher than about 2,000 psi, regulated operating pressure is applied to the OPENING chamber instead of the closing chamber.

»» Low-pressure test 1. All equipment in this test should be tested to 200-300 psi; 2. Install one stand drill collars below appropriate casing head plug tester. Land plug tester and back off running joint. NOTE: Open bore-type plug testers can be provided with a plug to test blind rams with drillstring removed. Fill BOP with water and close blind rams; 3. Open casing head valves to prevent casing rupture or formation break-down should the plug tester leak; 4. Apply test pressure as illustrated. Although test pressure is applied to a number of flowlines and valves, the primary purpose of this test is to evaluate blind rams and certain BOP connections as indicated by the arrows.

IADC Drilling Manual

»» High-pressure test 1. All equipment in this test should be tested to rated working pressure of the weakest member; 2. From previous test, open blind rams, install appropriate test string and screw into plug tester. Fill BOP with water and close top pipe ram. 3. Apply test pressure down drill pipe and through perforated sub or plug tester if it has an integral port. 4. Bottom ram can be tested in similar manner. Test string must fit ram size. 5. Annular preventer can also be tested similarly, but do not test to more than 70% of rated working pressure in the U.S. Gulf or 50% of rated working pressure where regulations do not specify. NOTE: Most annular preventers will hold maximum test pressure with no more than about 700-psi regulated accumulator operating pressure. Reducing accumulator operating pressure as the test pressure increases is recommended for some annular preventers. This can greatly reduce element stress. Where applicable, use an operating pressure versus test pressure chart during testing. 1. All equipment in this test should be tested to rated working pressure of the weakest member. 2. Pick up kelly, install full open safety valve on bottom of lower kelly valve. Using an adapter, connect to an independent test pump or cement pump. 3. Open appropriate standpipe valves and all kelly valves. Fill system with water and close standpipe and kelly. By alternatively closing upstream and opening downstream valves, all kelly valves could be tested without pressuring up again, although it may not be possible to operate the upper kelly valve under pressure. 4. Although not shown, the inside BOP (float-type) can be tested similarly by installing below the safety valve and opening all valves through the standpipe. Remember that each make, size and model annular preventer may have unique characteristics. For example, most annulars require increasing, not decreasing, closing pressure to prevent leaks as test pressure increases. Using incorrect procedures could cause damage or be unsafe. Always consult the manufacturer for testing recommendations. Casing sizes larger than 7 in. might be collapsed by annular element forces if the operating pressure is too high. Recom-

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Flex Joint

Alternate

Mud Standpipe P

From Cement Unit

Swivel Lower Kelly Valve

P

Upper Kelly Valve

Annular Preventer

Full Open Safety Valve

Hydraulic Connector

Pressure From Test Pump From Mud Pumps

P

Kill / Choke Line

Riser Adaptor

Rotary Hose

WC-15

Kill / Choke Line

WELL CONTROL EQUIPMENT & PROCEDURES

Annular Preventer

Ram-type Preventer Pipe Rams

Annular Ram-type Preventer

Top Ram Pipe

Blind Ram

Blind/Shear Rams

Ram-type Preventer Pipe Rams

Ram-type Preventer Pipe Rams

Bottom Pipe Ram

Hydraulic Connector

Figure WC-26: Typical subsea BOP arrangement. IADC drawing.

Figure WC-25: Testing inside BOPs, kelly valves, swivel and rotary hoses. IADC drawing.

Figure K1-21C: Typical Subsea BOP Arrangement

FIGURE K1-17C Testing inside BOPs, kelly Valves, Swivel and Rotary Hose.

mended maximum operating pressures for closing on various manufactures size casing can be obtained from most annular preventer manufacturers.

Testing inside BOPs, kelly valves, swivel sand rotary hoses Refer to Figure WC-25. Although only one mud standpipe and rotary hose test is shown, the other side should be tested before being put into service. Instead of using an adaptor sub as illustrated, an alternative method for testing this equipment would be to move directly from the test illustrated to Figure WC-21. Pick up the kelly, if it was not already connected, and apply test pressure down a kill flowline with the cement pump or special test pump (at an alternate inlet location). The perforated test sub or plug tester ingetral port will allow the test string to be pressured in the direction normally felt during an actual kick.

BOP arrangements: subsea stacks

Figure WC-26 illustrates a typical subsea BOP arrangement. Figure WC-27 shows only a portion of a 20,000-psi subsea BOP. Note how it towers over the attendants.Some of the differences when compared to surface stacks are: ŸŸ More backup units needed because of the difficulty of retrieving and deploying a subsea BOP; ŸŸ Upper annular(s) can be recovered with the riser for repairs without removing the “big” stack; ŸŸ Do not normally pull BOP for casing ram change so two annulars are needed for back-up; ŸŸ Variable bore rams usually installed in one of the ram cavities to provide redundancy when tapered strings are used or when running production casing;

IADC Drilling Manual

Figure WC-27: Deepwater BOP stacks are built in two, sometimes three, sections to facilitate transport. Here, the top half of a 20,000- psi BOP stack is loaded onto a trailer for transit to port. Courtesy GE Oil & Gas.

ŸŸ Blind shear rams are generally set high in the stack to provide more pipe hang-off options below. With the blind shear rams closed over hung-off pipe, the well can be monitored or circulated in pipe or annulus; ŸŸ Choke and kill lines are dual purpose, i.e., either can be used to kill (pump in) or choke (direct to choke manifold); ŸŸ Two fail-safe valves for each choke and kill BOP outlet that are fail-safe in the closed position; ŸŸ Two hydraulic or electro hydraulic control PODs each with 100% redundancy; ŸŸ All rams equipped with remote operated ram locks.

Testing subsea BOP stack

Test pressures and test frequency are similar to surface stacks with the following notable exception. All subsea BOP stack rams and valves are generally tested at surface (on a test stump) to their rated working pressure.

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WELL CONTROL EQUIPMENT & PROCEDURES

WC-16

Table WC-2: 'Inside' BOPs—Rigs with Kelly drive Inside BOP name

Normal location

Common type

Figure Illustration

Upper kelly valve or upper kelly cock

Between swivel and kelly

Flapper or full open ball

Figure WC-28

Lower kelly valve or upper kelly cock

Between kelly and kelly saver sub

Full open ball

Figure WC-29

Safety valve

In front of drawworks

Full open ball

Figure WC-29

Table WC-3: 'Inside' BOPs—Rigs with top drive Inside BOP name

Normal location

Common type

Figure Illustration

Upper remote safety valve

Between main shaft and lower valve

Full open ball

Figures WC-30 & -31

Lower safety valve

Below upper safety valve

Full open ball

Figures WC-30 & -31

Table WC-4: 'Inside' BOPs—Kelly drive or top drive rigs Inside BOP name

Normal location

Common type

Figure Illustration

Inside BOP

In front of drawworks

Poppet check

Figure WC-32

Drop-in check valve

Top of BHA

Ball check

Figure WC-33

Bit float

Installed in bit sub

Flapper or poppet check

Figure WC-34

The annular is generally tested to 70% of rated working pressure. The subsea stack, once deployed and connected to the conductor casing wellhead is not disconnected until the well is complete. Therefore, a higher stump test pressure is required than is normal for surface stacks.

Testing procedure for subsea BOPs Tests before lowering the BOP stack

All subsea BOP stack components should be installed, checked, and pressure tested to their rated working pressure and to a low pressure of 250 psi while the stack is mounted on the test stump. After the surface tests, all clamp connections and all studded connections should be checked for tightness. The complete BOP operating unit should be tested in accordance with manufacturer’s recommendations and pressure tested to its rated working pressure. The test should include at least the following: ŸŸ Test every BOP control; ŸŸ Check that each function is properly connected; ŸŸ Activate the functions which are indicated from both control pods; ŸŸ Check and record test volumes and response times for each function.

IADC Drilling Manual

The choke manifold, valves, kill and choke lines and fail-safe valves should be pressure tested with water to the rated working pressure of the ram type preventers, or the rated working pressure of the manifold, whichever is the lower. The kelly or top drive and kelly stopcocks should be pressure tested to their rated working pressure with a test sub. Tests during lowering and after connecting the BOP stack, kill and choke lines, marine riser and operating hoses. When running the BOP stack on riser joints, the kill and choke lines should be pressure tested at least when the stack is below the splash zone and both before and after landing. More frequent testing may be stipulated, i.e., each 5 or 10 riser joints. After the BOP stack is connected to the wellhead, a full function test on both pods and a low pressure test should be conducted. The pressure test upon initial and any subsequent mating of the BOP and wellhead should be performed with sea water to the maximum anticipated pressure at TD of the well to confirm connector/wellhead integrity. This pressure is only required against one pipe ram if the stack has been completely stump-tested prior to running. For routine tests, the BOP will be tested with the fluid in the hole at the time of the test. In deep water, a serious well control problem could develop due to loss of hydrostatic head, with the choke and kill line full of water. Therefore, after initial and subsequent mating of the BOP on the wellhead, the choke and kill lines will be kept full of in-hole drilling fluid. All lines should be flushed daily to ensure they are not blocked. In shallow water (less than 1,500 ft), operators may prefer to keep the choke/kill lines filled with sea water to prevent solids from settling out. Blind shear rams are normally tested against casing prior to drilling out, first at low pressure and again at a higher pressure, as indicated on the actual drilling prognosis. The blind shear rams are generally not retested during the normal test intervals as is done with the other BOP components unless the seal integrity is in question, but will be retested prior to drilling out of subsequent casing strings.

Routine tests

The opening/closing times and the volumes of hydraulic operating fluid required for the operation of the various underwater stack components (i.e., rams, kill and choke line valves, annular preventers, hydraulic connectors, etc.) shall be recorded during testing of the stack underwater. These results shall be compared with the normal opening/closing times and volumes required of the hydraulic system. Any

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WELL CONTROL EQUIPMENT & PROCEDURES

WC-17

major differences are an indication that the system is not operating “normally” and shall require further investigation and possible repair. Pressures of the wellhead or preventers should be to the anticipated wellhead pressure with a maximum limit for the annular preventer of 70% of its working pressure. It should also be pressure tested at low pressure, as described earlier.

"Inside" blowout preventers

There are several pieces of equipment in addition to the primary blowout prevention equipment that are sometimes necessary to control a kick. The equipment which furnishes closure inside the drill string is called an “inside” blowout preventer. A number of devices serve this purpose. The “names” of these devices are often confusing. Tables WC-2 through WC-4 classify inside BOPs to eliminate this confusion.

Upper Kelly valve

The upper kelly valve, or kelly cock (Figure WC-28), is installed between the kelly and the swivel and normally has left hand threads. Because it is installed above the kelly, it is always available. The basic purpose of this valve is to isolate the fluid in the drillstring from the swivel, rotary hose or standpipe and to prevent leaks or rupture under well conditions. If the drillpipe pressure exceeds the rating of the rotary hose, closing the valve allows a safe change to higher pressure connections. It also permits removal of the swivel so that wire lines or tools may be run into a pressurized drillstring.

IADC Drilling Manual

The most common design has a flapper as shown in Figure WC-28. The other design is a full open ball similar to the lower kelly valve. The upper kelly valve should have a WP rating equal to or greater than that of the blowout preventer assembly being used, and should have an inside opening equal to that of the

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WC-18

WELL CONTROL EQUIPMENT & PROCEDURES kelly. To operate this valve, a special wrench is required, and should be kept in an accessible place on the rig floor.

Lower Kelly valve

A lower kelly valve (Figure WC-29), sometimes called a lower kelly cock. It is installed on the lower end of the kelly, and is used when the upper kelly valve is damaged or not easily accessible. If the kill pressures approach the rotary hose ratings, this valve is closed, the kelly broken out and set back and the cement standpipe hose is connected via a circulating head to the lower kelly valve.

Safety valve

During trips on rigs with kelly drive, the kelly and both upper and lower kelly valves are stored in the rat hole. For this reason, another valve, identical to the lower kelly valve, is stored close by so it can be quickly installed on the drillpipe during a trip should a kick occur. When used in this manner, it is called a safety valve. If a tapered drillstring is being used, then a safety valve for each size pipe and crossovers to drill collar connections must be available on the rig floor.

Figure WC-30: Safety valves installed in top drive system. IADC drawing.

All of these kelly and safety valves should be operated at the beginning of each tour. They should be tested when the BOP is tested and the pressure should be applied in the direction pressure would be felt should the well be closed.

Upper remote safety valve and lower safety valve

The upper and lower safety valves on top drive systems are connected together. They are a ball type design. Both are very likely to be inaccessible should a kick occur during drilling operations, so the upper valve is remote operated as shown in Figure WC-30. The body on this particular design is splined to accommodate the pipe handler system. Some top drive units use a different kind of torquing mechanism which does not require a special OD profile on the upper safety valve. In these cases, the upper and lower safety valves may be identical except that the upper is fitted with a remote actuator crank and the lower is plain manual operated. Figure WC-30 illustrates the two valves installed in the top drive assembly. Figure WC31 show these two valves separated. During trips with the top drive system, the swivel and safety valves are not set back but rather are hoisted with the drillstring. Should a kick occur during the trip, the safety valves are immediately connected to the drillstring, and the upper valve remotely closed. There is no need to have another safety valve on standby as with kelly drive operations. Figure WC-31: Splined and plain topdrive safety valve. IADC drawing.

IADC Drilling Manual

Should a top drive require repairs, it's recommended to stab a safety valve atop the drillpipe, should there be a need to close the drillpipe.

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WELL CONTROL EQUIPMENT & PROCEDURES

Figure WC-32: Inside BOP. IADC drawing.

Inside BOP

Although all valves that secure the drillstring bore are “inside” BOPs, the check valves discussed in the following paragraphs are — confusingly — the only ones commonly called “inside BOPs” (Figure WC-32). They are normally used for stripping in the hole under pressure when a kick occurs off bottom during a trip. By utilizing a special tool, the inside BOP or check valve may be kept open to permit stabbing into the drillstring when the well is kicking. Once made up in the drillstring, the tool is released and the check valve closes. The inside BOP on the rig floor should be kept in open position, as a guard against a kick or flow through the drillpipe. However, check valves are more difficult to stab against drill pipe flow than are full open ball valves. Therefore, the full open safety valve should be installed first and then the “inside” BOP (check valve) installed if it is necessary to strip back in the hole.

Figure WC-33: Wireline retrieval and dropin check valve. IADC drawing.

sembly of the drillstring. These inside BOPs are often used in stripping operations and particularly stripping “out” operations. Some are wireline retrievable. Figure WC-33 shows one type of drop-in check valve.

Bit float

A bit float (Figure WC-34) may be considered an “inside” preventer. It is basically a flapper or poppet-type check valve that is installed in the bit sub to prevent backflow during connections; however, it is subjected to severe wear by the drilling mud and may not function when needed. A common practice is to use a slotted flapper. This reduces backflow to a minimum, yet allows stabilized closed-in pipe pressure to be easily read should the well kick. Most operators discontinue the use of bit floats after setting surface casing. Kicks are more likely to occur below surface casing and the bit float might interfere with a good stabilized closed-in drillpipe pressure reading. Bit floats are most useful in top-hole drilling where backflow during connections is more likely due to imbalanced annular fluid density.

Drop-in check valve

Another type inside BOP is the pump down or drop-in type which requires a special sub near or in the bottomhole as-

IADC Drilling Manual

WC-19

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WC-20

WELL CONTROL EQUIPMENT & PROCEDURES

Choke manifold

If the hydrostatic head of the drilling fluid is insufficient to control subsurface pressure, formation fluids will flow into the well. To maintain well control, back pressure is applied by routing the returns through adjustable chokes until the well flow condition is corrected. The chokes are connected to the blowout preventer stack through an arrangement of valves, fittings and lines which provide alternative flow routes or permit the flow to be halted entirely. This equipment assemblage is designated the “choke manifold.”

Design Considerations

Choke manifold design should consider such factors as anticipated formation and surface pressures, method of well control to be employed, surrounding environment, corrosivity, volume, toxicity, and abrasiveness of fluids.

Installation guidelines

Figure WC-34: Clockwise from top left: Bit float, poppettype, flapper-type and plunger type. IADC drawing.

Recommended practices for planning and installation of choke manifolds for surface installations include: ŸŸ Manifold equipment subject to well and/or pump pressure (normally upstream of and including the chokes) should have a working pressure equal to the rated working pressure of the blowout preventers in use. This equipment should be tested when installed to pressures equal to the rated working pressure of the blowout preventer stack in use. ŸŸ Components should comply with applicable specifications to accommodate anticipated pressure, temperature and corrosivity of the formation fluids and drilling fluids. ŸŸ For working pressures of 3,000 psi and above, flanged, welded or clamped connections should be employed on components subjected to well pressure. ŸŸ The choke manifold should be placed in a readily accessible location, preferably outside of the rig substructure.

Figure WC-35: Typical 2,000-psi (13.8 MP) manifold. IADC drawing.

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WELL CONTROL EQUIPMENT & PROCEDURES

Figure WC-36: Typical 5,000-psi (34.5 MPs) manifold. IADC drawing.

Figure WC-37: Typical 10,000-20,000-psi (69.0-138.0 MP) manifold. IADC drawing.

IADC Drilling Manual

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WC-21

WC-22

WELL CONTROL EQUIPMENT & PROCEDURES

Packing unit/ Packing element/ Sealing element Piston

Vent outlet

Lower piston seal seat

Figure WC-38: Diverter with annular packing element. IADC drawing.

Figure WC-39: Diverter with insert-type packing element. IADC drawing.

ŸŸ The choke line (which connects the blowout preventer stack to the choke manifold) and lines downstream of the choke should: ŸŸ Be as straight as practicable; turns, if required, should be targeted; ŸŸ Be firmly anchored to prevent excessive whip or vibration; ŸŸ Have a bore of sufficient size to prevent excessive erosion or fluid friction. ŸŸ Minimum recommended size for choke lines is 3-in. nominal diameter (2-in. nominal diameter is acceptable for Class 2M installations). ŸŸ Minimum recommended size for vent lines downstream of the chokes is 3-in. nominal diameter. ŸŸ For high volumes and air or gas drilling operations, 4-in nominal diameter lines are recommended. ŸŸ Alternate flow and flare routes downstream of the choke line should be provided so that eroded, plugged or malfunctioning parts can be isolated for repair without interrupting flow control. ŸŸ Consideration should be given to the low temperature properties of the materials used in installations to be exposed to unusually low temperatures. ŸŸ The bleed line (the vent line which bypasses the chokes) should be at least equal in diameter to the choke line. This line allows circulation of the well with the preventers closed while maintaining a minimum of back pressure. It also permits high-volume bleed-off of well fluids to relieve casing pressure with the preventers closed. ŸŸ Although not shown in the typical equipment illustrations, buffer tanks are sometimes installed downstream of the choke assemblies for the purpose of manifolding the bleed lines together. It also provides a large chamber for gas expansion and reduction in gas velocity. When buffer tanks are employed, provisions should be made to isolate a failure or malfunction without interrupting flow control. ŸŸ Pressure gauges suitable for drilling fluid service should be installed so that drillpipe and annulus pressures may be accurately monitored and readily observed at the station where well control operations are to be conducted.

ŸŸ All choke manifold valves subject to erosion from well flow should be full-opening and designed to operate in high pressure gas and drilling fluid service. Double, full-opening valves between the blowout preventer stack and the choke line are recommended for installations with rated working pressures of 3M and above. ŸŸ For installations with rated working pressures of 5,000 psi and above the following are recommended: ŸŸ One of the valves should be remotely actuated. ŸŸ Double valves should be installed immediately upstream of each choke. ŸŸ At least one remotely operated choke should be installed. If prolonged use of this choke is anticipated, a second remotely operated choke should be used. ŸŸ A valve should be installed downstream of the choke to provide isolation from the buffer tank when changing wear items while circulating through the second choke. ŸŸ Downstream of the choke, a decrease of one pressure rating, i.e., 5,000 psi down to 3,000 psi, 10,000 psi down to 5,000 psi, etc., may be considered for the valves and buffer tank. ŸŸ Spare parts for equipment subject to wear or damage should be readily available. ŸŸ Testing, inspection, and general maintenance of choke manifold components should be performed on the same schedule as employed for the blowout preventer stack in use. ŸŸ All components of the choke manifold system should be protected from freezing by heating, draining or filling with proper fluid. ŸŸ Figures WC-38 through WC-40 illustrate typical choke manifolds for various working pressure service. Refinements or modifications such as additional hydraulic valves and choke runs, wear nipples downstream of chokes, redundant pressure gauges and/or manifolding of vent lines will be dictated by the conditions anticipated for a particular well and the degree of protection desired. The guidelines discussed and illustrated represent typical industry practice.

IADC Drilling Manual

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WELL CONTROL EQUIPMENT & PROCEDURES

Side View

WC-23

Flow Line Fill-Up Line

Bell Nipple 30” - 1,000 psi W.P. Annular Preventer

A-A Hydraulic-Operated Ball Valve

Diverter Vent Line

Diverter Vent Line

30” Conductor Pipe with 30” - 1,000 psi W.P. Welded on Top

View A-A

Overboard Vent

Overboard Vent

Hydraulic Operated Ball Valve

30” - 1,000 psi W.P. Drilling Spool/Mud Cross

Figure WC-41: Typical diverter system with control- K1-4F sequenced flow system. IADC drawing. FIGURE K1-4F: Typical Diverter System with Control Sequenced Flow System

Packing unit/ Packing element/ Sealing element Piston

Two-Position Target Plug

Diverter Exhaust K1-3F

Figure WC-40: Switchable 3-way target valve. IADC drawing. Figure K1-3F: Switchable 3-Way Target Valve

For economic reasons, it may be desirable at the beginning of a drilling operation to install a manifold with a pressure rating equivalent to that of the highest pressure rated system which will be used on that well. This will preclude the necessity of always matching manifolds with BOP stack ratings, minimizing time lost changing choke manifolds and reduce the number of manifolds held in inventory. Screwed connections are optional for only the 2,000-psi manifold; all others shall be welded or flanged. Suggested configurations are shown in Figures WC-38, WC-39 and WC-40 as 2,000-psi and 3,000-psi, 5,000-psi, 10,000psi, and 15,000-psi manifolds.

Diverter systems

The function of a diverter system is to provide a low pressure well flow control system to direct controlled or uncontrolled wellbore fluids or gas away from the immediate drilling area for the safety of personnel and equipment involved in the drilling operation. The diverter system is not designed to shut in or halt well flow. Diverter system equipment that can be exposed to a hydrogen sulfide environment should comply with NACE MR-0175: Material Requirements Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment, latest edition. A diverter system comprises the following components:

IADC Drilling Manual

Vent outlet

Lower piston seal seat

Figure WC-42: Example of purpose-designed diverter with built-in vent valving. IADC drawing.

Annular sealing device

The annular sealing device is available in three different designs.

Annular packing element

Figure WC-41 is an example of an annular sealing device that utilizes an annular packing element as the sealing mechanism. The annular packing element can effect a seal on any pipe or kelly size in the wellbore, or can effect a seal on open hole where no pipe is present. This is often times referred to as “complete shut-off” (CSO).

Insert-type packing element

Figure WC-42 is an example of an annular sealing device that utilizes an insert-type packing element as the sealing mechanism. An insert-type packing diverter element uses a group of inserts. The inserts are placed one inside the other. Each insert in the group is designed to close and seal on different ranges of pipe diameters. A hydraulic or mechanical func-

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WELL CONTROL EQUIPMENT & PROCEDURES

tion serves to latch each insert in place. The correct size insert should be in place for the pipe size in use. In order to pass large bottomhole assemblies, it is necessary to remove some or all of the inserts. An insert-type packing element cannot CSO.

Rotating head

A rotating head can be used as a diverter to complement a blowout preventer system. The stripper rubber is energized by the wellbore pressure to seal the rotating head element against the drillpipe, kelly or other pipe to facilitate diverting return wellbore media and can be used to permit pipe movement.

Vent outlet(s)

Vent outlet(s) for the diverter system are located below the annular sealing element. One or more vent outlets can be used in a system. Vent outlet(s) may either be incorporated in the housing of the annular sealing device, or may be an integral part of a separate drilling spool/mud cross that is assembled using a flange or clamp type connection just below the annular sealing device. Design considerations for the connection between the vent outlet(s) and the vent line(s) should include ease of installation, leak-free construction and freedom from solids accumulation. Regarding the size of the vent outlet(s), different regulator bodies have different requirements, depending on the area of operation. For example, the requirements for drilling operations that utilize a surface wellhead configuration in areas regulated by the U.S. Minerals Management Service (reference CFR 30, Chapter II, 7-1-88 Edition, paragraph 250.59) require that no spool outlet or diverter line shall have an internal diameter less than 10 in.; except in the case where dual outlets are provided, in which case the minimum internal diameter of each vent outlet is 8 in. For drilling operations where a floating or semi-submersible type drilling vessel is used, the vent outlet internal diameter shall not be less than 12 in. For drilling activity outside the United States, the drilling contractor is advised to become familiar with the regulations for that particular area of operation.

Drilling spool/mud cross

If a drilling spool/mud cross is utilized under the annular scaling device, the through-bore diameter of the drilling spool/mud cross should be equal to the through-bore diameter of the annular sealing device. The design working pressure rating of the drilling spool/mud cross should be equal to the design working pressure rating of the annular sealing device.

Valves

full-opening, have at least the same through-bore opening as the vent outlet that it is attached to, and should be capable of opening with maximum anticipated pressure across the valve sealing mechanism. Several types of full-opening valves which can be used in this application are gate valves (various types), ball valves, knife valves, switchable 3-way targeted valves (Figure WC-40), and valves that are integral to the annular sealing device. Any valve used in a diverter system application should be fitted with remote actuators capable of operation from the rig floor. The actuators can be operated either with hydraulics or pneumatics. The actuator should be sized to open the valve with the maximum system rated working pressure across the closed valve sealing mechanism, with hydraulic or pneumatic pressure that is available from the diverter system remote control unit. The trim of the internal components of the valve actuator should be suitable for the media that is going to be used to operate the actuator. If a water-based fluid is the media, the actuator trim should be suitable for water service, corrosive. Excessive resistance due to drilled solids in the valve should be kept in mind, especially if using a pneumatic system where variations in rig air pressure are common.

Vent line piping

There are various considerations that need to be investigated for the vent line piping in a diverter system. These considerations are as follows:

Sizing

The vent line piping in a diverter system should be sized to minimize back pressure on the wellbore while diverting wellbore media. The vent line should be run as straight as possible, keeping in mind that bends, tees and elbows not only create higher back pressure than straight pipe, but are more susceptible to erosion during a diverting operation than straight piping. Just as with the vent outlet(s) discussed in the above paragraph, government regulatory bodies have minimum requirements for the internal diameter of the vent line piping. The drilling contractor should be familiar with the requirements for the area where the drilling operation is going to take place.

Flexible lines

Flexible lines with integral end couplings can be employed in a diverter vent line piping system. If used, the flexible lines should have the same or larger internal diameter as the vent outlet and valve, they should be resistant to fire and erosion, have end couplings that are compatible with those utilized in the hard piped section(s) of the vent line piping system, and supported adequately.

Valves used in a diverter vent line(s), or in the flow line to the shale shaker in a floating drilling operation, should be

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WELL CONTROL EQUIPMENT & PROCEDURES

Routing

The vent line(s) used in a diverter system should be routed so that at all times, one line can vent wellbore media to the downwind side of the rig. Routing changes should be as gradual as possible. Long radius bends are preferred over short radius bends. In the case of a 90° bend, it is preferred to use a targeted tunning tee equipped with a blind flange or plug to minimize effects of erosion. If the vent line is required to change direction two times in one location, it is preferred to use a “y-type” branch over a tee. The vent line (s) should be sloped along their entire run in order to eliminate low spots which may accumulate drilling media and debris.

Support

The vent lines should be firmly secured. The dynamic effects of high-volume fluid/gas flow and the impact of drilling solids are to be considered in the vent line(s) support. Supports located at points where piping direction changes must be capable of restaining pipe deflection. Special attention should be given to the supports located at the end sections of the vent line(s). This area will tend to whip and vibrate during a diverting operation.

Cleanouts

Provisions for cleaning and flushing any accumulated debris from the vent line(s) should be made. Cleanouts should be placed upstream of all valves and sharp direction changes, with flushing jets located to aid removal of sharp debris and drilling solids. Cleanouts and flushing ports should be adequately sealed to prevent the escape of any wellbore media when the diverter is in use. The cleanout should have the same rated working pressure as the piping into which they are installed. Well-monitoring devices (flow indicators, etc.), gumbo busters, etc., which are exposed to diverting media should be able to withstand the anticipated back pressure without leaking or failing.

Fill-up lines

If a fill-up line is positioned below the annular sealing device, it should be valved. The valve can be either a remote-operated gate, ball or knife-type valve, or a check valve. The pressure rating of the valve should be equivalent to the pressure rating of the rest of the diverter system valve components.

Control system

The diverter control system is usually hydraulic or pneumatic, or a combination of both. The system should be capable of being controlled from two or more remote units. All units should be available for ready access by operating personnel. The diverter control system may be a completely self-contained system, or it may be an integral part of the blowout preventer control system. In some cases, the blowout preventer control system can double as the diverter control system. This is dependent on the type/configuration of diverter system used.

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Volumetric capacity

As a minimum, the volumetric capacity of the diverter controls system accumulators should be sufficient to provide the usable fluid volume (with pumps inoperative) required to close and open all functions in the diverter system and still retain a 50% reserve. Usable fluid volume is defined as the fluid recoverable from an accumulator between maximum operating pressure of the system (the pressure at which the pumps automatically shut off) and 200 psi above the gas pre-charge pressure. The API RP-16E, Recommended Practices for Design of Control Systems for Drilling Well Control Equipment, latest edition, should be used to assist in determining the accumulator volume required. For a control system that incorporates an integral diverter system with the blowout preventer control system, the accumulators required for the diverter system should have their supply isolated from the accumulators required for the blowout preventer system by a check valve. On systems utilizing pneumatically-operated valves, an independent power source should be provided to supply the necessary air/gas required in the event of reduction or loss of rig air pressure.

Response time

The diverter control system should be capable of operating the vent line valve(s) and the flow line valve (if so equipped), and closing the annular sealing device packing element on pipe in use within 30 seconds if the packing element of the annular sealing device has a nominal open bore of 20 inches or less. For annular sealing devices that have a packing element nominal open bore greater than 20 inches, the diverter control system should be capable of operating the vent line valve(s) and flow line valve (if so equipped), and closing the annular sealing device packing element on pipe in use within 45 seconds.

Pump requirements

The pump(s) used in a diverter control system should be capable of recharging the diverter control system accumulator system to full system operating pressure within 5 minutes after one complete divert mode operation of the diverter control system. The discharge pressure rating of the pump(s) should be equal to the rated working pressure of the diverter control system. Power supply to the pumps should be available to the diverter control system at all times, such that the pump(s) will automatically start when the system supply pressure in tile accumulator(s) decreases to less than 90% of the accumulator operating pressure. The pump(s) should automatically stop when the full design operating pressure is reached. An over-pressure protection device (i.e., relief valve) should be set to function at no more than 110% of the design operating pressure. The overpressure protection device should be designed to automatically shut off and reset within 25% decrease of the design operating pressure.

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WELL CONTROL EQUIPMENT & PROCEDURES

Back-up system

An alternate means, or back-up system, should be employed to permit operation of the diverter system should the primary control system become inoperative. This can be accomplished by use of an alternative pump source, separate isolated accumulator capacity, bottled nitrogen, or other means. The back-up system need not be automatic, but should be available if the need arises.

Valves, fittings, lines, and manifolds

All valves, fittings, lines and manifolds should have the same rated working pressure as the pump(s). Sizing of valves, fittings, lines and manifolds should be adequate enough to supply the diverter system components volume enough to satisfy the response time required. Pressure-regulating valves should be provided for the annular sealing device, and for all other components in the diverter system. Accurate pressure gauges should be incorporated to indicate critical system pressures. Pressure regulating valves utilized in the system should have the capability to be manually operated within their rated operating pressure range should the remote control capability fail.

Fluid reservoir capacity

The reservoir capacity of the diverter control system should be equal to at least 2 times the usable fluid capacity of the diverter control system accumulator system.

Fluid recommendation

A suitable hydraulic fluid (nonflammable petroleum or water-based) should be used as the operating fluid. In cold ambient environments, sufficient volume of glycol should be added to the operating fluid in order to keep the fluid from freezing. Use of diesel oil, motor oil, chain oil or any other similar fluid is not recommended due to the possibility of explosion or resilient seal damage.

Control sequencing

The diverter control system should have the capability to be operated such that the well can never be shut in with the diverter system. For installations where the annular sealing device is located below the flow line, the control sequencing should be that the vent line valve(s) always open before the annular sealing device is closed. If more than one vent valve is installed, both valves should remain open during the initial closing of the annular sealing device, and then allow for closure (either automatic or manual) of the upwind vent line valve, if so desired. On installations where the flow line is below the annular sealing device, the desired vent valve(s) should be opened (if not already open) while simultaneously closing the shale shaker/flow line valve and annular sealing device. If possible, the design of the control system and/or the vent line piping system should allow that the vent(s) fail to the open position. Although desired, this is sometimes

IADC Drilling Manual

not practical. The complexity of the control sequencing system is dependent on the design of the diverter system and the components selected to be used in the diverter system.

Control system location

The main pump/accumulator/control manifold unit should be located in a safe place which is easily accessible to rig personnel in an emergency. It should also be located such that maintenance to the components on the system can be done in an easy manner. The distance of the main unit from the diverter system components will determine the sizing of the control lines between the two, keeping in mind the response time requirement for operating the annular sealing device and vent line valve(s). In addition to the main pump/ accumulator/control manifold unit, remote control units should also be incorporated. These too should be located in a position that is readily accessible by the rig personnel in an emergency. At least one of these remote control units should be located a safe distance from the rig floor. The design of all components utilized in the diverter control system should comply with the area classifications found in API RP 500B, Recommended Practice for Classification of Locations for Electrical Installations on Drilling Rigs and Production Facilities on Land and Marine Fixed and Mobile Platforms, latest edition.

Mounting of diverter

An important consideration for diverters is to structurally secure the mounting, since the device receives the full force of diverted wellbore media. If the diverter is mounted utilizing API or MSS/ANSI type flanges, refer to the appropriate standards for these flanges to determine the proper bolting material and method of making up the flange. If the diverter is attached to the rig floor structure (e.g., rotary table beams), the connection should be designed so that the upward force is directed back into the structure.

Typical diverter system for onshore and/or bottom-supported offshore installations

When diverter systems are deemed necessary, they should be installed on the drive or conductor pipe.

System arrangement

There are various arrangements of diverter systems for onshore and/or bottom-supported offshore installations. The most common of these consists of an annular sealing device attached to a drilling spool/mud cross (Figure WC-41). The drilling spool/mud cross generally has one or two vent outlets. The annular sealing device often times used is an annular type blowout preventer. The typical sizes of annular preventers used are: ŸŸ 29 1/2-in. - 500-psi W.P. ŸŸ 30-in. - 1,000-psi W.P.

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ŸŸ 20 3/4-in. - 3,000-psi W.P. ŸŸ 21 1/4-in. - 2,000-psi W.P. There are insert-type preventers that are available for this application. The typical size for this type of diverter is a 30in., - 2,000-psi W.P. Also available for onshore and bottom-supported off- shore installations are annular preventers purpose designed for a diverter application, in that the vent valving has been designed into annular preventer (Figure WC-42). Additionally, substructure mounted diverter systems are also available for onshore and/or bottom-supported offshore installations (Figure WC-43). These are similar in design to the diverters that are designed for floating drilling rigs. One of the major advantages of this design system is that it allows the diverter, overshot spool and overshot packer assembly to be pulled or run without having to connect or disconnect flow line, fill-up line and diverter vent lines. Hydraulic-actuated seals are used to isolate the flow line, diverter vent lines and fill-up lines by providing a reliable, positive seal between the diverter and the support housing. The diverter assembly is mechanically locked into the support housing with a right-hand “J” which also positively aligns the outlets of the diverter with the outlets in the support housing. The overshot packer, which is used to connect the diverter to the conductor pipe, is a stab-over and seal mechanism, thereby eliminating the need for welding and/ or making up flanges each time different size casing is run. The overshot packers and spools are connected utilizing a stab-type casing connector. Tools are available that allow testing the diverter assembly seals, insert packer(s), and all flow line and diverter vent valving. These types of diverter systems are available for use with 37 1/2-in. and 49 1/2-in. rotary tables. This diameter is not the internal diameter of the diverter, but the minimum internal diameter of the support housing. These types of diverters are available with either an annular packing element (Figure WC-38 and WC-44) or insert-type packing elements (Figure WC-39). Compare Figures WC-42 and WC-44 to see diverter vent connections for two different systems.

Typical diverter system for floating rigs

Floating drilling operations include operations from drillships and semi-submersibles that drill in the floating mode. These vessels are distinguished from other types of drilling units by the use of subsea blowout preventer stacks. The subsea blowout preventer stack and associated equipment are connected to the drilling vessel via the marine drilling riser system.

IADC Drilling Manual

Figure WC-43: Substructure-mounted diverter system for onshore or bottom-supported offshore installations. IADC drawing.

Figure WC-44: Substructure mounted diverter with annular packing element. IADC drawing.

Installation

Diverter systems on floating drilling rigs are typically mounted to the drill floor substructure (rotary support beams). The diverter system is the upper end of the marine drilling riser system. A floating drilling operation requires equipment that allows for relative motion between the subsea blowout preventer stand and the drilling vessel. A flex/ball joint is usually located above the blowout preventer stack (at the bottom of the marine drilling riser system) to allow for this motion. An additional flex/ball joint may be located at the top of the marine drilling riser package as well in order to reduce bending stresses caused by vessel offset, vessel surge and sway motions, and environmental forces. This flex/ball joint is usually located between the bottom of the diverter and the top of the telescopic joint.

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Packing Unit

Flow Line

Ported Valve Sleeve

Vent Line Side Seal Piston

Figure WC-45: Diverter for floater installations with builtFIGURE K1-8F: DIVERTER FOR FLOATER INSTALLATIONS in flow line and vent line valving. IADC drawing. WITH BUILT-IN FLOW LINE AND VENT LINE VALVING

System arrangement

K1-8F

Diverter systems used on floaters are similar in design to the substructure mounted systems used on bottom-supported offshore installations. In fact, the idea for the substructure mounted diverter systems used on bottom-supported offshore installations came from the floating installation design. Because of the large diameter of the marine drilling riser that is used today, the most common size of diverter system is one that is designed to work with a 49 1/2-in. rotary table. This diameter is not the internal diameter of the diverter, but the minimum internal diameter of the support housing. This large diameter allows conductor casing and marine drilling riser to be pulled or run without having to connect or disconnect flow line, fill-up line and diverter vent lines. Hydraulic actuated seals are used to isolate the flow line, diverter vent lines, and fill-up lines by providing a reliable, positive seal between the diverter and the support housing. The diverter assembly is hydraulically locked into the support housing with hydraulic operated dogs. When properly installed and locked in place, the diverter outlets are positively aligned with the outlets in the support housing. Tools are available that allow testing the diverter assembly seals, insert packer(s) and all flow line and diverter vent valving. Diverters for floating installations are available with either an annular packing element (Figure WC-44) or insert-type packing elements (Figure WC-39). Additionally available for floaters are diverters that incorporate automatic valving for the flow line and diverter vent line. A single hydraulic function is used to close the diverter and at the same time close off the flow line to the shale shakers and open the diverter vent line. Figure WC-45 shows an example of this component. The figure does not show the support housing that the diverter fits into. This housing is similar in design to the substructure mounted insert-type diverter.

IADC Drilling Manual

Diverter system maintenance

A schedule for routine check-out and maintenance of diverter systems equipment should be implemented and kept by the rig operating personnel. Specific guidelines for each diverter component or subsystem should be based on maintenance manuals and recommendations provided by the equipment manufacturer. Visually inspect the rubber components of the system after each test to verify that they are in good working condition. Packer components should be replaced when their proper functioning is questionable due to damage, wear, and/or age. The diverter system should be function tested on a periodic basis. During diverter function tests, observe all components of the diverter system including the diverter, valves, valve actuators, valve actuator piping, and control panel to verify that there are no leaks in the system. In the event a leak is discovered, it should be repaired immediately. If the diverter system utilizes a separate control system from the blowout preventer control system, the unit requires periodic maintenance including such items as checking various fluid levels, cleaning air strainers, cleaning pump strainers and cleaning filter elements. Tightening of packing and lubrication of power actuating cylinders should be performed. The nitrogen precharge in the system accumulator bottles should be checked as well. Control hoses, tubing, vent line piping support brackets, targeted fittings, valves, fittings, etc., should be visually inspected on a routine basis. Due to the difficulty in hydrostatically pressure testing of the vent line(s) of a diverter system, it is recommended that the wall thickness of these lines and their associated fittings be checked using ultrasonic inspection devices. These lines are not only highly susceptible to erosion due to high velocity flows, but they are highly susceptible to material loss due to corrosion. Control system pressure gauges should be calibrated and tagged at intervals not to exceed 12 months.

BOP performance characteristics

Blowout preventers are valves which can close off the annulus space between the BOP bore and drillpipe, or as in the case of blind rams and annular blowout preventers, close off the well when the hole is open. As with any valve, a pressure differential can exist across the valve that opposes its opening or closing. This differential was not formerly considered a factor to reckon with when BOPs were only rated at 5,000psi MWP (maximum working pressure). The design of the BOP, depending on manufacture, generally ranged from a 4.5:1 to a 6.8:1 closing ratio. With the high closing ratio and low MWP rating of the BOP, and the advent of the 3,000-psi

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Next Page WELL CONTROL EQUIPMENT & PROCEDURES closing units in 1953, there was always sufficient pressure to close the BOP against its full rated working pressure. The closing ratio is a product of the area on the ram side which is exposed to wellbore pressure versus the area of the operator piston exposed to operating pressure. BOP manufacturers calculate and publish the opening and closing ratios. Since pressure in psi times area in inches equals force in pounds, it is easy to recognize that wellbore pressure versus operator pressure oppose each other. For example, if the difference in area exposed to operator pressure produces seven times greater force than the area exposed to wellbore pressure, the ratio is said to be 7:1. This means operator pressure produces seven times the force to close as the wellbore side produces to resist closing. Another factor that affects closing force is inherent friction; however, this is considered minimal and is not normally figured into the closing characteristics of the BOP. Simple calculations divide the BOP maximum working pressure by the opening or closing ratios to determine the minimum operator pressure required to open or close the BOP against full wellbore pressure. With the advent of 10,000-psi and higher maximum working pressure BOPs, the closing ratio does become a factor to reckon with if the BOP must be closed against high wellbore pressure. The following examples show the effect of closing against full rated wellbore pressure assuming closing ratios of 4.5:1 and 6.8:1

4.5:1 Closing ratio

MWP (psi) Operator Pressure Req’d (psi) 5,000 1,111 10,000 2,222 15,000 3,333

6.8:1 Closing ratio

MWP (psi) Operator Pressure Req’d (psi) 5,000 735 10,000 1,470 15,000 2,205 It must be noted that the BOP also has an opening ratio. The opening ratio is less than the closing ratio since the ram face is sealed off against the drill pipe or the other blind ram block, and is not exposed to wellbore pressure until this seal is broken. Prior to opening then, the ram block area is not exposed to wellbore pressure, thus the pressure in the ram cavity actually assists in maintaining the ram in the closed position. This means the operator pressure must be increased to open against wellbore pressure. In some cases, this is a moot point since the components for ram block retraction are not designed to pull the block open under pressure and damage to the BOP would result if it were attempted.

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Prior to consideration of 10,000 psi and higher maximum working pressure BOPs, the accumulators on the BOP closing unit were precharged and the minimum working pressure of the accumulator calculated to optimize the fluid capacity of the accumulator system, and simplify the calculations using Boyles Law. The minimum pressure was established at 1,200 psi (200 psi above precharge). The precharge pressure was established at 1,000 psi. When the accumulator was charged with hydraulic pressure to 3,000 psi, 50% of the accumulator fluid volume could be discharged down to the pressure at which the poppet valve in the accumulator closed and shut off flow. This would be between 1,200 psi and 1,000 psi. The minimum working pressure (1,200 psi) was used in calculations to ensure a margin of safety. The recommended practice for design of control systems for drilling well control equipment API RP16E, 1st edition, October 1, 1990, recognized the operating characteristics of the BOP. The applicable reference today is API Spec 16D, 2013. Opening or closing the ram BOPs at maximum rated wellbore pressure is not recommended. However, operators should be aware of the operating characteristics and limitations of the well control equipment so that surprises can be avoided when encountering well control problems. Users should contact the manufacturers for any information not contained in the equipment users manual. To prepare for emergency operations, should the accumulator pumps be out of service and wellbore pressure increases, operators should isolate the pumps and, using the accumulators only, create a table to show actual performance of the system. This can be accomplished during initial installation by checking the accumulator precharge then charging them to full design pressure. Then isolate the pumps and chart the finishing pressure each time a ram BOP is closed (exclude shear rams). The resulting table will show what the final pressure will be after certain numbers of ram closures based on the resulting decrease in accumulator pressure as volume is expelled. With the known closing ratio of the BOP, the operator can divide specific wellbore pressures by the BOP closing ratio and know before attempting to do so if there will be sufficient accumulator pressure to effect closing and seal off against whatever elevated wellbore pressure is in the hole. Most BOP closing units are equipped with a manifold pressure reducing and regulating valve that supplies the hydraulic pressure to operate the ram BOPs, kill and choke valves. This device normally limits pressure to a maximum of 1,500 psi and may often be regulated lower than that. There is also a manifold regulator bypass valve. When this valve is in the “high” pressure position, the ram control valves receive full accumulator pressure for operation. The bypass valve can be placed in the “high” position anytime wellbore pressure

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WIRE ROPE

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CHAPTER

WR

WIRE ROPE

he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with expertise spanning a broad range of topics. These volunteers contributed their time, energy and knowledge in developing the IADC Drilling Manual, 12th edition, to help facilitate safe and efficient drilling operations, training, and equipment maintenance and repair.

T

The contents of this manual should not replace or take precedence over manufacturer, operator or individual drilling company recommendations, policies or procedures. In jurisdictions where the contents of the IADC Drilling Manual may conflict with regional, state or national statute or regulation, IADC strongly advises adhering to local rules. While IADC believes the information presented is accurate as of the date of publication, each reader is responsible for his own reliance, reasonable or otherwise, on the information presented. Readers should be aware that technology and practices advance quickly, and the subject matter discussed herein may quickly become surpassed. If professional engineering expertise is required, the services of a competent individual or firm should be sought. Neither IADC nor the contributors to this chapter warrant or guarantee that application of any theory, concept, method or action described in this book will lead to the result desired by the reader. Authors Brent Dein, WireCo WorldGroup Dennis Fetter, WireCo WorldGroup

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WIRE ROPE

This is a chapter of the IADC Drilling Manual, 12th edition. Copyright © 2015 International Association of Drilling Contractors (IADC), Houston, Texas. All rights reserved. No part of this publication may be reproduced or transmitted in any form without the prior written permission of the publisher. International Association of Drilling Contractors 10370 Richmond Avenue, Suite 760 Houston, Texas 77042 USA ISBN: 978-0-9915095-7-7

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Contents

WIRE ROPE

Preface & acknowledgements....................................WR-i Introduction................................................................... WR-1 Definition........................................................................ WR-1 Wire rope nomenclature........................................... WR-1 Sizes and construction diameter............................. WR-1 Basic strand consideration........................................ WR-2 Single layer...............................................................WR-2 Filler wire...................................................................WR-2 Seale.......................................................................... WR-3 Warrington.............................................................. WR-3 Combined patterns............................................... WR-3 Preforming............................................................... WR-3 Lay.............................................................................. WR-3 Grades............................................................................. WR-4 Cores............................................................................... WR-4 Care and handling........................................................ WR-4 Field care and use of wire rope......................... WR-6 Handling on reel...........................................WR-6 Proper steps in stringing line....................WR-6 Care of wire rope in service...................... WR-7

IADC Drilling Manual

Socketing of wire rope.............................................. WR-11 Attachment of wire rope clips to wire rope....... WR-11 Wire rope clips........................................................... WR-11 How to apply clips..................................................... WR-11 Fist grip clips...............................................................WR-12 Casing line and reeving line practice...................WR-12 Methods of reeving............................................. WR-12 Function of reeving system.............................. WR-14 Factors affecting service..........................................WR-15 Ton-mile calculations................................................ WR-18 Introduction........................................................... WR-18 Examples of ton-mile calculations................. WR-18 Ton-miles per foot cut.......................................WR-29 Ton-mile calculations—drilling ton-miles for top drive (drilling with stands).............WR-30 Cut-off program.........................................................WR-30 Suggestions for cut-off practice......................WR-30 Design factor.............................................................. WR-48 Index..............................................................................WR-73 Appendix.....................................................................WR-A1

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IADC Technical Resources

IADC TECHNICAL RESOURCES ENHANCES RIG CREW EXPERTISE

IADC brings the collective knowledge and experience of the global drilling industry to the workforce through industry-developed print, electronic and multimedia tools and resources accessible in one convenient location. From books to industry news to manuals and more—IADC is the definitive source. The Technical Resources Center contains a variety of items, including: • IADC Bookstore and e-Bookstore: textbooks, guidelines, checklists, model contracts and more. • Online Safety Toolbox: Safety Alerts, safety meeting topics, near hit/miss forms and safety posters. • Knowledge, Skill & Ability (KSA) Competencies Database: filter competencies based on various criteria and generate a unique set of KSAs for each type of position on a rig. • Industry news: quick access to Drilling Contractor magazine and IADC Drill Bits newsletter. • Reports: Onshore and Offshore US Federal Regulatory Summaries and the International Regulatory Summary provide easy to access updated information on industry regulation.

www.IADC.org/technical-resources

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Introduction

Definition

The drilling line is a machine. It is an assembly of precision parts, each can move independently, requires lubrication, is static until an external force is applied and it transmits energy.

Drilling lines and wire lines are known as and are used interchangeably with the term “wire rope”. Reference to all three of these terms will be prevalent throughout this manual.

The information that follows will guide you in the selection, care and use of drilling lines. Instructions are included for attaching wire rope clips, socketing wire rope, seizing wire rope, etc.

Wire rope is an intricate network of close tolerance, precision made steel wires, much on the order of a machine, where each part has a job to do. Each part must work in a perfect relationship with the other part for the rope to properly function. Proper care and handling is mandatory to receive the highest service at the highest level of safety.

To keep the wire line costs at a minimum, the rig crews and all levels of operations management should know how to obtain maximum safe life from the drilling line. The following is basic to that objective. A. Select the proper size and type line to meet the requirements. B. Care for the line to prevent damage. C. Compute the service obtained from the line in Ton-Miles. D. Choose a cut-off program that best suits your conditions and follow it carefully. This will greatly increase the service obtained from the line. When a new line is received, the reel number, make and description of the line should be recorded on the daily drilling report. The ton-mile service should be computed daily and a record kept so cut-offs can be made after a proper interval of service.

Wire

Strand

Nomenclature Wire rope comprises just three parts—core, strand and wire (Figure WR-1). Become familiar with each part; it is surprising how many times a “wire” is reported to be a “strand”. Each of the components are detailed later in this manual. Wire rope is described and identified with numerals and abbreviations. It is important to understand these terms and to relate them to the wire rope specified within our industry. The following is an example description of a rotary drilling line; the identifying terms are translated and explained individually. 5,000 ft × 1 in. 6×19 S-IWRC EIP SZ (RR) PRF 5,000 ft = Length of wire rope, ft 1 in. = Nominal diameter of wire rope, in. 6 = Number of outer strands per wire rope 19 = Number of wires per outer strand S = Seale outer strand wire pattern IWRC = Independent wire rope core EIP = Extra improved plow steel SZ (RR) = Right regular lay PRF = Preformed strands

Core

Rope

This translates to a 5,000 ft length of 1 in. diameter, 6-strand rope with 19 wires in each strand laid in a Seale pattern (S). The strands of the rope are laid around an Independent Wire Rope Core. The strength grade of the rope is Extra Improved Plow Steel (EIP). The strands are laid in a Right Regular Lay (SZ or RR) pattern and are preformed (PRF) in a helical shape prior to closing the rope.

Sizes and constructions diameter Diameter measurements are correct only when made across the “crowns” of the rope strands so that the true diameter is the widest diameter of the rope. Always rotate the caliper on the rope—or rotate the rope inside the caliper to take the measurement. Figure WR-1: Anatomy of wire rope, showing core, strand and wire, which comprise the rope.

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Always measure the diameter of any rope at its widest point by turning the caliper on the rope. Measurements for

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WIRE ROPE

1

Table WR-2: The number of strands and number of wires per strand determine a rope's classification.

2

Correct

1

Wires per strand

6×7

6

7

6×19

6

16 through 26

6×36

6

27 through 49

8×19

8

16 through 26

Within each classification there are specific rope constructions. For example, in the 6×19 class, some of the rope constructions are 6×25 FW (filler wire), 6×119 S (Seale) and 6×26 WS (Warrington Seale).

Figure WR-2: Wire diameter measurement.

diameter shall be taken on a straight portion of the rope at two positions spaced at least three feet apart. Two diameters shall be measured at each position at right angles from each other. The average of these four measurements shall be the reported diameter. Most ropes are manufactured larger than the nominal diameter. When first placed in operation, strands of new unused rope will “seat in” and “pull down” from its original diameter. Therefore, measurements recorded for future reference and comparison should be taken after the rope has been in service for a short period of time. See Table WR-1 for rope diameter vs. tolerances.

Table WR-1: Rope diameter vs. tolerance. Steel wire ropes with IWRC

Number of strands

Wire rope differs in the number of strands and the number and pattern of wires per strand. Most common wire rope constructions are grouped into four standard classifications based on the number of strands and wires per strand, as shown in Table WR-2.

2

Incorrect

Rope Diameter Inches

Classification

Steel wire ropes with fiber core

Tolerance (percent) Tolerance (percent)

Characteristics, such as fatigue resistance and resistance to abrasion, are directly affected by the design of strands. As a general rule, a strand made up of a few large wires will be more abrasion-resistant and less fatigue-resistant than a strand of the same size made up of many smaller wires.

Basic strand constructions Single layer

Figure WR-3: Example of a single-layer strand.

The “Single Layer Principle” is the basis of this strand construction. The most common example is a single wire center with six wires laid around it. It is called a 7-wire (1–6) strand (Figure WR-3).

UNDER

OVER

UNDER

OVER

d < 3/16

0

8

0

9

Filler wire

3/16 ≤ d < 1/4

0

7

0

9

¼ ≤ d < 3/8

0

6

0

8

3/8 and larger

0

5

0

7

This construction has two layers of the same-sized wires around a center wire, with the inner layer having half the number of wires as the outer layer. Small filler wires, equal in number to the inner layer, are laid in the valleys of the inner layer.

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Combined patterns When a strand is formed in a single operation using two or more of the foregoing constructions, it is referred to as a “combined pattern”. Beginning from the center wire, the first two layers constitute a Seale pattern. The third layer, with two different wire sizes is a Warrington pattern. The fourth layer of the same diameter wires forms a Seale pattern.

Figure WR-4: Filler wire has two layers of the same-sized wires around a center wire. This is a 25 filler wire (1-6-6f-12) strand.

Seale The Seale construction has two layers of wires around a center wire with the same number of wires in each layer. All wires in each layer are the same diameter and the strand is designed so that the larger outer wires rest in the valleys between the smaller inner wires.

Figure WR-7: Strands formed in a single operations using two or more of the foregoing constructions is called a “combined pattern.” Above is 49 Seal Warrington Seale (1-8-8-(8+8)-16) strand.

Preforming Preforming is a process by which strands are helically formed into the shape they will assume in the finished rope. Preforming improves fatigue resistance, ease of handling, and resistance to kinking in a rope by equalizing the load among the strands and among the individual wires of strands.

Figure WR-5: Seale construction features two layers of wires around a center wire, with the same number of wires in each layer. This example is 19 Seale (1-9-9) strand.

Warrington The Warrington construction has 2 layers of wires. The inner layer is a single size of wire and the outer layer has two diameters of wire, alternating large and small. The larger outer-layer wires rest in the valleys and the smaller ones on the crowns of the inner layer.

When a preformed rope is cut, the end does not unlay. If strands are unlayed from the rope, they retain their helical shape. When a non-performed rope is cut, it will open up or "broom" unless the end has been secured (seized) before cutting. The superior qualities of preformed ropes result from wires and strands being “at rest” in the rope which minimizes internal stresses within the rope. Because wires and strands are free to move and slide in relation to each other when the rope bends, the rope can adjust more easily while operating on sheaves or drums. Unless otherwise indicated in the rope description, ropes are preformed.

Figure WR-8: Right lay, regular lay.

Lay Figure WR-6: Warrington construction features two layers of wires. The inner is a single size wire, and the outer has two wire diameters, alternating large and small. Drawing is of 19 Warrington (1-6-(6+6) strand.

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The first element in describing Lay is the DIRECTION of strands lay in the rope—Right or Left. When you look along a rope, strands of a Right Lay rope spiral to the right. Left Lay rope spirals to the left.

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WIRE ROPE

The second element in describing lay is the relationship between the direction the strands lay in the rope and direction the wires lay in the strands. In Regular Lay, wires are laid opposite the direction the strands lay in the rope. In appearance, the wires in Regular Lay are parallel to the axis of the rope. The second element in describing lay is the relationship between the direction the strands lay in the rope and direction the wires lay in the strands. In Regular Lay, wires are laid opposite the direction the strands lay in the rope. In appearance, the wires in Regular Lay are parallel to the axis of the rope.

Figure WR-9: Left lay, regular lay.

The grade of rope refers to the strength of a new unused wire rope. Standard 6 strand EEIP ropes within the same classification and having an IWRC have a nominal strength about 10% higher than EIP ropes. Galvanized ropes are those in which the individual wires have had a zinc coating applied to their surface to provide increased corrosion resistance. The proper grade of rope to use depends on the specific characteristics of the application.

Cores The primary purpose of a core in wire rope is to provide a foundation or support for the strands. Approximately 7 ½% of the nominal strength of a 6-strand IWRC rope is attributed to the core. Wire rope cores are usually one of three types (Figure WR12). The first, fiber core (top) is either of natural fiber, such as sisal or man-made fiber, such as polypropylene. The second, independent wire rope core (center) is literally an independent wire rope called IWRC. Finally, strand core (bottom) is a strand composed of wires.

In Lang Lay, wires are laid the same direction as the strands lay in the rope and the wires appear to cross the rope axis at an angle.

Figure WR-10: Right lay, lang lay.

The third element in describing lay is that one rope lay is the length along the rope axis which one strand uses to make one complete helix around the core. Figure WR-12: Examples of rope cores (from top)—fiber core (FC); independent wire rope core, center; strand core, bottom.

Table WR-3: Lay designations. One Rope Lay Figure WR-11: One rope lay.

Grades Today the greatest portion of all wire rope is made in two grades: Extra Improved Plow Steel (EIP) and Extra Extra Improved Plow Steel (EEIP)

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Lay type

Preferred designations

Other designations

Right hand ordinary lay Left hand ordinary lay Right hand langs lay Left hand langs lay Right hand alternate lay Left hand alternate lay

RR, sZ LL, zS RL, zZ LL, sS RA, aZ LA, aS

RHOL, RRL LHOL, LRL RHLL, RLL LHLL, LLL RHAL, RAL LHAL, LAL

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Table WR-4: Typical sizes and constructions of wire rope for oilfield service. Service and well depth

Wire rope inches

Wire rope description

Shallow

1/2 to 3/4 incl.

6×26 WS or 6×31 WS

Intermediate

3/4, 7/8

RRL or LRL IPS,EIP or EEIP, IWRC

Deep

7/8 to 11/8 incl.

Rod & Tubing Pull Lines

Rod Hanger Lines

1/4

6×19, RRL, IPS, FC

Sand Lines Shallow

1/4 to 1/2 incl.

Intermediate

1/2, 9/16

Deep

9/16, 5/8

6×7 or 5×7 or 5×7 Swaged Bright or Galv.2, RRL IPS, FC

Drilling Lines—Cable Tool (Drilling & Cleanout) Shallow

5/8, 3/4

Intermediate

3/4, 7/8

Deep

7/8, 1

6×21 FW, RRL or LRL, PS or IPS, FC

Casing Lines—Cable Tool Shallow

3/4, 7/8

Intermediate

7/8, 1

6×25 FW, RRL, IPS, FC or IWRC

Deep

1, 1 1/8

6x25 FW, RRL, IPS or ElP, IWRC

Shallow

7/8, 1

6×26 WS, RRL, IPS or EIP, IWRC

Intermediate

1, 1 1/8

6×19 S or 6×26 WS, RRL, EIP or EEIP, IWRC May have compacted strands or be plastic impregnated.

Shallow

1, 1 1/8

6×19 S or 6×21 S or 6×26WS, RRL, EIP or EEIP, IWRC. May have compacted strands or be plastic impregnated

Deep

1 1/4 to 2 incl.

Drilling Line—Coring and Slim-Hole Rotary Rigs

Drilling Lines—Large Rotary Rigs

5/8 to 7/8 incl.

6×26 WS or 6×31 WS, RRL, IPS EIP or EEIP, IWRC

7/8 to 1 1/8 incl.

6×36 WS, PF, RRL, IPS EIP or EEIP, IWRC

Shallow

1/2 to 1 1/8 incl.4

6×19 Class or 6×36 Class or 19×7, IPS, FC or IWRC

Intermediate

5/8 to 1 1/8 incl.3

6×19 Class or 6×36 Class, IPS, FC or IWRC

7/8 to 2 3/4 incl.

6×19 Class, Bright or GaIv., RRL, ElP or EEIP, IWRC

Offshore Anchorage Lines

1 3/8 to 4 3/4 incl.

6×36 Class, Bright or GaIv., RRL, ElP or EEIP, IWRC

3 3/4 to 4 3/4 incl.

6×61 Class, Bright or GaIv., RRL, ElP or EEIP, IWRC

Mast Raising Lines5

1 3/8 and smaller

6×19 Class, RRL, EIP or EEIP, IWRC

1 1/2 and larger

6×36 Class, RRL, EIP or EEIP, IWRC

3/4

6×25 FW, RRL, IPS or EIP, IWRC

Winch Lines—Heavy Duty Horsehead Pumping—Unit Lines

Guideline Tensioner Line

6×36 WS or 6×41 WS or 6×41 SFW or Riser Tensioner Lines

1 1/2 and larger

6×49 SWS, RRL, IPS or EIP, IWRC or 8×36 class RL IWRC May have compacted strands and/or be plastic impregnated.

Abbreviations WS

Warrington Seale

IPS

Improved Plow Steel

RRL

Right Lay

S

Seale

ElPS

Extra Improved Plow Steel

LRL

Left Lay

FW

Filler-Wire

PRF

Preformed

FC

Fiber Core

PS

Plow Steel

NPF

Non-preformed

IWRC

Independent Wire Rope Core

Bright wire sand lines are regularly finished; galvanized finish is sometimes required.  pplies to pumping units having one piece of wire rope looped over an ear on the horsehead and both ends fastened to a A polished rod yoke. 4 Applies to pumping units having two vertical lines (parallel) with sockets at both ends of each line. 5 See API Spec. 4E – Specification for Drilling and Well Servicing Structures. 2 3

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WIRE ROPE

Care and handling

4. Braking reels: Brake the reel flanges so that the rope does not become loose on the reel while being unwound and so an even tension is applied on the rope between the blocks; do not apply the brake on the rope itself.

Field care and use of wire rope A. Handling on reel 1. U  se of binding or lifting chain: When handling wire rope on a reel with a binding or lifting chain, wooden blocks should always be used between the rope and the sling in order to prevent damage to the wire or distortion of the strands in the rope. 2. U  se of bars: Bars for moving the reel should be used against the reel flange and not against the rope. 3. S harp objects: The reel should not be rolled over or dropped on any hard, sharp object in such a manner that the rope will be bruised or nicked. 4. Dropping: The reel should not be dropped from a truck or platform. This may cause damage to the rope as well as break the reel. 5. Mud, dirt, or cinders: Rolling the reel in or allowing it to stand in any medium harmful to steel such as mud, dirt, or cinders should be avoided. Planking or cribbing will be of assistance in handling the reel as well as in protecting the rope against damage. 6. Corrosion: To minimize the effects of corrosion on wire rope, care should be taken to store and lubricate the wire rope properly. Corrosion may be particularly severe in environments containing high concentrations of salt or acid. Corrosion reduces a wire rope’s strength, resistance to fatigue, and service life. 7. Welding and flame cutting: Never use wire rope in an arc welding circuit. The grounding clamp can arc or the individual wires can arc and damage the line. If using a torch near the wire rope, always protect the rope from the flame and sparks. B. Proper steps in stringing line 1. Preliminary work: Attach the traveling block to the hang line, or otherwise support in a vertical position. The best position is where the elevators are in pick-up position near the rotary table. 2. Position of the reel: Provide a permanent location for the reel of drilling line. This should be as close as practical to the dead-line anchor. The reel should be firmly supported on its horizontal axis with the line unwinding from beneath the reel drum (not from the top of the drum). 3. Stringing of blocks: When leading the line from the reel to the first crown sheave use snatch blocks with large diameter sheaves to guide the line and keep it from rubbing on derrick members or other obstructions.

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5. Tension on rope: Keep the line in tension to make sure that it is tightly wound on the drum. Insufficient tension during installation and after slip-and-cuts can cause improper spooling. 6. Tight spooling: The rope should be spooled under a sufficient load to ensure tight spooling. 7. Swivel-type stringing grip: To start stringing the rope, remove the old rope from the dead line anchor and fasten it to the new rope with a swivel grip. The grip becomes tighter as the load increases. This will prevent transferring the twist from one piece of rope to the other. Care should be taken to see that the grip is properly applied. 8. Winding old rope: Wind all the old rope on the drawworks drum and slip enough of the new rope into the system to permit attaching to the drum. Never pull rope through a loosened clamp. Keep as much back tension in the rope as possible because slackness can cause loops and/or kinks to form. 9. Fastening new line: Fasten the new line so that it will not run back through the blocks. Remove the swivel grip. Then take the old line off the drum and transfer it to a storage reel. Attach the new line to the drawworks drum and provide enough wraps so that the proper number will be on the drum at the pick-up point. 10. Number of wraps on drawworks drum: When the traveling block is at the lower pick-up point, 6–9 wraps should be on the drum (if grooved). Plain faced drums must have a full layer of line plus 4–6 wraps on the second layer as needed. 11. Deadline anchor: Hold-down sheaves are the best way to anchor the line when cut-off practices are to be employed. Such sheaves should be of sufficient diameter to prevent dog-legging the line and should be at least 15 times the rope diameter. The line should go around the hold-down sheaves in the same direction as it comes over the deadline sheave and from the storage reel. Never anchor the dead end of the line to a wooden or steel joist if you plan to utilize a cut-off procedure. Such practices will put severe dog-legs in line which will cause premature damage when this section is later moved into service. Exercise great care so that the deadline clamps do not kink, flatten, or otherwise crush or distort the rope. 12.  Completing string-up: After anchoring the dead-line end, raise the traveling block and take off the supporting line. The block, hook and elevators may then be lowered through the V-door far enough to unreel the line on the drum so that it can be re-reeled tightly.

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13. Break-in period: Whenever possible, a new rope should be run under a light load for a short period after it has been installed. This will help to adjust the rope to working conditions. It is suggested that 15 cycles with 3 joints of pipe would be sufficient break-in. 14. New coring or swabbing line: If a new coring or swabbing line is excessively wavy when first installed, two to four sinker bars may be added on the first few trips to straighten the line. C. Care of wire rope in service 1. Handling: The recommendations or handling as given under A and B inclusive, should be observed at all times during the life of the rope. 2. Design factor: The design factor should be determined by the following formula: B Design Factor = W Wherein: B = Nominal catalog strength of the wire Rope - in pounds W = Fast line load - in pounds a. When a wire rope is operated close to its minimum design factor, care should be taken that the rope and related equipment are in good operating condition. At all times, the operating personnel should use diligent care to minimize shock, impact, and acceleration or deceleration of loads. b. Successful field operations indicate that the following design factors should be regarded as minimum.

Table WR-5: Wire rope life varies with design factor. Longer rope life generally results from maintaining high design factors. Cable-tool line Sand line Rotary drilling line Rotary drilling line when setting casing Pulling on stuck pipe and similar infrequent operations Mast raising and lowering line

Minimum design factor 3 3 3 2 2 2.5

c. Wire rope life varies with the design factor. Therefore, longer rope life can generally be expected when relatively high design factors are maintained. 3. Application of loads: Sudden, severe stresses are injurious to wire rope and such applications should be reduced to a minimum. A jerk line may be rigged and

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WR–7

clamped to the drilling line when it is necessary to do considerable jarring in one place. 4. O  perating speed: Experience has indicated that wear increases with speed; economy results from moderately increasing the load and diminishing the speed. 5. Maximum rope speed: Excessive speeds when blocks are running up light may injure wire rope. For most drums, a maximum rope speed of 4,000 ft of rope travel per min for hoisting or lowering is recommended. 6. Line fatigue: Fast line fatigue is also caused by line whip and natural vibrations, therefore, a wire line stabilizer must be employed. Reverse bending at the deadline anchor or too small a diameter of the deadline sheave (crown block) may produce a set in the line which will cause excessive wear when a cut-off procedure is utilized. 7. Sheave maintenance: Vibration causes drilling line fatigue and shortens line life. Failure due to vibration is most serious at the deadline (crown block) sheave. This all the excess energy caused by line whip and vibration. Make certain the reeving system minimizes vibration. Considerable line whip results from fast line movement in the spooling process unless wire line stabilizers are used. As the line goes through sheaves, its momentum tends to throw it outward, much as a car rounding a curve on the highway. It is prevented from doing this, however, by the tension on the line. This sudden angular acceleration and deceleration will produce vibrations, which in a long, unsupported, fast moving, flexible line, can result in severe whipping, if a stabilizer is not used. Wobbly sheaves can produce shimmying, which will induce vibration in the drilling line. This may lead to whipping. The wobble may also cause the line to receive abnormal wear from the sides of the sheaves, which further reduces rope life. 8. Sheave alignment: All sheaves should be in proper alignment. The last sheave should line up with the center of the hoisting drum. 9. Sheave grooves: On all sheaves, the arc of the bottom of the groove should be smooth and concentric with the bore or shaft of the sheave. The centerline of the groove should be in a plane perpendicular to the axis of the bore or shaft of the sheave. Sheave grooves that have been altered by prior ropes are bound to shorten the life of new rope. From the standpoint of wire rope life, the condition and contour of sheave grooves are of material importance. Sheave grooves should be checked periodically with the gauge for worn sheaves and dimensions in Table WR-6. The sheave grooves should have a diameter of not less than that of the gauge; otherwise the reduction in rope life can be expected. Recondi

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WIRE ROPE

Table WR-6: Worn, new and maximum groove radii for wire rope. Nominal wire rope diameter

Groove radius minimum worn

Groove radius minimum new

Groove radius maximum

In.

Mm

In.

Mm

In.

Mm

In.

Mm

0.250

6.5

0.128

3.25

0.134

3.40

0.138

3.51

0.313

8.0

0.160

4.06

0.167

4.24

0.172

4.37

0.375

9.5

0.192

4.88

0.199

5.05

0.206

5.23

0.438

11.0

0.224

5.69

0.232

5.89

0.241

6.12

0.500

13.0

0.256

6.50

0.265

6.73

0.275

6.99

0.563

14.5

0.288

7.32

0.298

7.57

0.309

7.85

0.625

16.0

0.320

8.13

0.331

8.41

0.344

8.74

0.750

19.0

0.384

9.75

0.398

10.11

0.413

10.49

0.875

22.0

0.448

11.38

0.464

11.79

0.481

12.22

1.000

26.0

0.513

13.03

0.530

13.46

0.550

13.97

1.125

29.0

0.577

4.66

0.596

15.14

0.619

15.72

1.250

32.0

0.641

16.28

0.663

16.84

0.688

17.48

1.375

35.0

0.705

17.91

0.729

18.52

0.756

19.20

1.500

38.0

0.769

19.53

0.795

20.19

0.825

20.96

1.625

42.0

0.833

21.16

0.861

21.87

0.894

22.71

1.750

45.0

0.897

22.78

0.928

23.57

0.963

1.875

48.0

0.961

24.41

0.994

25.25

2.000

52.0

1.025

26.04

10.060

2.125

54.0

1.089

27.66

1.126

2.250

58.0

1.153

29.29

2.375

60.0

1.217

2.500

64.0

2.625 2.750

tioned sheave grooves should conform to the recommended radii for new and reconditioned sheaves as given in Table WR-6. Each operator should establish the most economical point at which sheaves should be re-grooved by considering the loss in rope life which results from worn sheaves as compared to the cost involved in re-grooving. 10. Corrugated sheaves: If rope is operated very long with heavy loads, or if the metal is too soft, scouring or corrugation of drums and sheaves will occur. When radial pressure causes corrugation in grooves, there is a filing action during every stop and start. When new rope is installed after such corrugations form, its lay will not fit the imprints left by previous ropes and very rapid wear will take place.

Table WR-7: Tangents of fleet angles. Ratio of “A” to “B” Tangent of “W” degrees

Fleet angle, degrees

0.009

1/2

0.013

3/4

24.46

0.017

1

1.031

26.19

0.022

1 1/4

26.92

1.100

27.94

0.026

1 1/2

28.60

1.169

29.69

0.031

1 3/4

1.193

30.30

1.238

31.45

0.035

2

30.91

1.259

31.98

1.306

33.17

1.281

32.54

1.325

33.66

1.375

34.93

67.0

1.345

34.16

1.391

35.33

1.444

36.68

71.0

1.409

35.79

1.458

37.03

1.513

38.43

2.875

74.0

1.473

37.41

1.524

38.71

1.581

40.16

3.000

77.0

1.537

39.04

1.590

40.39

1.650

41.91

3.125

80.0

1.602

40.69

1.656

42.06

1.719

13.66

3.250

83.0

1.666

42.32

1.723

43.76

1.788

15.42

3.375

86.0

1.730

43.94

1.789

45.44

1.856

17.14

3.500

90.0

1.794

45.57

1.855

47.12

1.925

48.89

3.750

96.0

1.922

48.82

1.988

50.50

2.063

52.40

4.000

103.

2.050

52.07

2.120

53.85

2.200

55.88

4.250

109.0

2.178

55.32

2.253

57.23

2.338

59.39

4.500

115.0

2.306

58.57

2.385

60.58

2.475

62.87

4.750

112.0

2.434

61.82

2.518

63.96

2.613

66.37

5.000

128.0

2.563

65.10

2.650

67.31

2.750

69.85

5.250

135.0

2.691

68.35

2.783

70.69

2.888

73.36

5.500

141.0

2.819

71.60

2.915

74.04

3.025

76.84

5.750

148.0

2.947

74.85

3.048

77.42

3.163

80.34

6.000

154.0

3.075

78.11

3.180

80.77

3.300

83.82

Minimum worn groove radius = nominal rope radius + 2 1/2% Minimum new groove radius = nominal rope radius + 6% Maximum groove radius = nominal rope radius + 10%

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When these danger signs are found, it is economical to have the grooves turned smooth. In most cases, the sheaves should be replaced. In replacing the sheaves, make sure the metal is sufficiently hard to take the expected loading. Cast steel can stand only about 900 psi of pressure, but other alloy steels will take up to 2,000 psi and will stand wear much longer. If corrugations are occurring even with the best steel, chances are that the rope diameter is too small for the work load or not enough lines are being used between the blocks, or the sheave diameter is too small. 11.  Rope inspection: Equipment that is not maintained properly not only deteriorates itself, but also aids in destroying wire rope ervice life in the process. Frequent inspection of the equipment to determine its operating condition and replacement of worn or broken parts is good economics when operating a rig. This is preventative maintenance versus remedial maintenance. 12. Fleet angle: When a wire rope is led from the drum onto the last sheave, it is parallel to the sheave groove only when at one point on the drum, usually the center. As the rope departs from this point either way, an angle is created which starts wear on the side of the rope. This angle is called the fleet angle.

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WIRE ROPE

The fleet angle, although necessary, should be held to a minimum. Experience indicates that it should be held to less than 1 1/2 degrees for smooth faced drums and to less than 2 degrees for grooved drums. Any greater angle creates needless wear on the sides of the rope. This holds true for either grooved or smooth drums. Poor fleet angles cannot only cause excessive abrasive wear, but also build-up excessive torque in a rope. To check the fleet angle, Figure WR-13 can be used. The fleet angle is the included angle between a line representing travel of the rope across the drum and a line drawn through the center line of the lead sheave perpendicular to the axis of the drum. Fleet angles for several ratios of “A” & “B” are shown in Table WR-7.

Figure WR-13: Use in conjunction with Table WR-8 to check fleet angle.

13. Lubrication of sheaves: In order to ensure a minimum turning effort, all sheaves should be kept properly lubricated. 14. Worn drums: Roughly worn drums may cause excessive wear on the rope. Corrugations cause cutting of ropes. 15. Drum spooling: Heavy wear to a rotary line occurs while spooling on the drum. Each succeeding layer causes cross-over points and change of layer points. At the cross-over points and change of layer points where the rope climbs from one layer to the next, wear is usually severe. In the portion of the line that spools last and when the blocks are raised and loaded, terrific cribbing and wear occur when the load of the drill string is suddenly lifted. In a portion of the line that lies next to the drum, which must withstand the loading of all the other layers, crushing is considerable. 16. Proper spooling: Smooth faced drums are sometimes encountered and the biggest problem is to get the line to spool evenly and snugly. Unless the rope is started correctly, the wraps in the first layer may tend to spread apart. This can accelerate “cutting-in” of subsequent layers and result in flattened, distorted or crushed rope and a loss of thread lay.

IADC Drilling Manual

WR–9

Table WR-8: Clip attachment. Courtesy the Crosby Group

Rope diameter Minimum no. Amt of rope to Torque (in.) of clips turn back (in.) (ft-lb) 1/8

2

3 1/4

4.5

3/16

2

3 3/4

7.5

1/4

2

4 3/4

15

5/16

2

5 1/4

30

3/8

2

6 1/2

45

7/16

2

7

65

12/2

3

11 1/2

65

9/16

3

12

95

5/8

3

12

95

3/4

4

18

130

7/8

4

19

225

1

5

26

225

1 1/8

6

34

225

1 1/4

7

44

360

1 3/8

7

44

360

1 1/2

8

54

360

1 5/8

8

58

430

1 3/4

8

61

590

2

8

71

750

2 1/4

8

73

750

2 1/2

9

84

750

2 3/4

10

100

750

3

10

106

1,200

3 1/2

12

149

1,200

On smooth face drums, where ropes operate on and off the first layer, right lay and left lay ropes are not interchangeable. The proper direction of rope lay is based on the location of the drum attachment and whether or not the spooling is under-wind or over-wind. The advantage of using the proper lay rope on a smooth drum is that rotation of the rope as it spools on the drum under tension will cause it to hug the preceding wrap. If the improper lay is used, the rope will try to open spool. Care must be exercised to prevent over-run in paying out rope to avoid slack rope on the drum which causes excess abrasion on drum and rope at take-up. Slack rope

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WR–10

WIRE ROPE

has a tendency to slide across groove dividers which cuts the rope severely when loads are applied. Rope can be parted or severed with a quick take-up of slack. Drum grooves should be checked with a sheave gauge for proper contour before installing a new rope. 17. Poor spooling: Poor spooling can sometimes be traced to the way the line leaves the dead end side of a smooth faced drum. If it leaves the flange at too great an angle, it maintains this angle all across the drums so that it leaves a big gap at the opposite flange. Thus successive layers of line cross over that initial layer sharply and will tend to cut at the gaps—line crushing and shorter life result. It is most important to get the first drum layer full and tight without overcrowding so that it will support the succeeding layers. That is to say the first layer acts as a “grooving” for the following layers. One way to assist proper drum winding is by means of a riser strip or wedge on the dead end side. These strips are as high as the rope diameter and taper from 0 to the diameter of the rope in width. The starter strip travels flush around the dead end flange. It keeps the first wrap straight and tends to eliminate the gap at the other flange. Piling up of wraps at the flange is prevented by turn-back rollers or kick plates. 18. Grooved drums: Wear due to cross-over points cannot be completely avoided. It can be reduced by controlled spooling, which is provided by grooved drums. In any type of spooling there must necessarily be two crossover points with each wrap. As a lower layer proceeds in one direction across the spool, the next layer must proceed in the other direction. Along most of the turn, the upper wrap rides in a groove between two wraps of the lower layer. The rope must leave this groove in order to cross to the next groove and in doing so, crosses over a wrap of the line in the lower layer. Two ropes are crossed over in each drum revolution. With smooth faced drums, and where wire line slipping is employed, new rope is spooled onto worn rope. The worn rope has a smaller diameter and when it is wound tight, the new line will not track. The new line instead will jump a wrap and leave a gap into which the line of the next layer will cut. Therefore, we suggest that slipping is only helping to temporarily relieve a wearing condition in the drilling line between blocks. 19. Pyramid spooling: Utilizing grooving allows an upper layer of line to track a lower, despite the fact that the lower layers may be worn. In this manner, cutting in is reduced. However, it is necessary that the grooving includes filler plates at each end so that when the second and following layers start, they start smoothly and leave no gap for cutting in.

IADC Drilling Manual

An improvement in spooling methods is the controlled cross-over system. This is a grooving system where the cross-over points are controlled thereby reducing wear and vibration. Instead of being a helical shape like a coiled spring, most of the grooves are parallel to the drum flanges. Normally at the cross-over points, pitch changes rapidly where the line is crossed from one groove to the next. In controlled spooling, the change in pitch is less severe. In controlled pyramid spooling, wear and cutting-in is parallel and there is no tendency for the line to slip over. 20. Counter-balanced pyramid spooling: Considerable vibration of the spooling drum and wire line at high speed results from the eccentricity of spooled line on the drum when one cross-over point is present. This makes the center of gravity slightly off center of the drum. Counter-balanced spooling was developed to overcome this problem.  Counter-balanced spooling consists of 2 cross-over points on opposite sides of the drum. This is achieved by making the pitch at each cross-over point only half that of the single cross-over drum. The grooves are still parallel, but those on one side of the drum are displaced half a groove width from those on the other side. This along with special pitch control bars at the flanges cause a line to move only 1/2 of the rope diameter at a time. 21. Block and hook weight: Slack line causes severe wear because of cutting and scrubbing of one layer of line against the next. This condition is most likely to occur when going back in the hole, where the traveling block is brought up fast with no load other than the weight of the block and hook to hold the line in tension. When the full load of the drill string is picked up from this position, the top layer from the drum may cut into the loosely spooled layers. To keep this line tight and to minimize the spooling damage to the line, it is important to use a heavy traveling block and hook. See Table WR-9 for theoretical weights of blocks, hooks, links and elevators. 22. Seizing of wire rope: Before cutting, a wire rope should be securely seized on each side of the cut by serving with soft wire ties. For socketing, at least two additional seizings should be placed at a distance from the end equal to the length of the basket of the socket. For large ropes, the seizing should be several inches long and securely wrapped. This is very important as it prevents the rope untwisting and helps maintain equal tension in the strands when the load is applied. 23. Procedure for seizing wire rope: a. The seizing wire should be wound on the rope by hand. The coils should be kept together and considerable tension maintained on the wire.

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WIRE ROPE

WR–11

b. After the seizing wire has been wound on the rope, the ends of the wire should be twisted together by hand in a counterclockwise direction so that the twisted portion of the wires is near the middle of the seizing. c. Using “Carew” cullers, the twist should be tightened just enough to take up the slack. Tightening the seizing by twisting should not be attempted

Correct method of attaching clips to wire rope.

Correct Method of Attaching Clips to Wire Rope Correct Method of Attaching Clips to Wire Rope

Incorrect methods of attaching clips to wire rope.

Incorrect Methods of Attaching Clips to Wire Rope Figure WR-15: Correct and incorrect methods of seizing wire rope. Incorrect Methods of Attaching Clips to Wire Rope

Socketing of wire rope Zinc spelter and resin poured sockets are a common end termination that can be expected to reach 100% efficiency when poured and prepared properly. ISO 17558 should be referenced when pouring sockets.

Attachment of wire rope clips to wire rope A. Wire rope clips Wire rope clips are widely used for making end terminations. Clips are available in two basic designs; the U-bolt and fist grip. The efficiency of both types is the same. When using U-bolt clips, extreme care must be exercised to make certain that they are attached correctly, i.e., the U-bolt must be applied so that the “U” section is in contact with the dead end of the rope (Figure WR-15). Also, the tightening and retightening of the nuts must be accomplished as required. B. How to apply clips See U-Bolt Clips (Figure WR-15). Recommended method of applying U-bolt clips to get maximum holding power of the clip:

Figure WR-14: The figure shows the relationship between the two critical dimensions used in calculating fleet angle.

IADC Drilling Manual

1. Turn back the specified amount of rope from the thimble. Apply the first clip one base width from the dead end of the wire rope (U-bolt over dead end - live end rests in clip saddle). Tighten nuts evenly to recommended torque.

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WR–12

WIRE ROPE

2. Apply the next clip as near the loop as possible. Turn on nuts firm but do not tighten.

5. U  se of half hitch: Do not use a half hitch, either with or without clips.

3. Space additional clips, if required, equally between the first two. Turn on nuts - take up rope slack - tighten all nuts evenly on all clips to recommended torque.

Casing line and reeving line practice A. Methods of reeving

4.  NOTICE ! Apply the initial load and retighten nuts to the recommended torque. Rope will stretch and be reduced in diameter when loads are applied. Inspect periodically and retighten to recommended torque.

Vee Side of Derrick Deadline Anchor (G) (for Left-Hand Receiving)

A termination made in accordance with the above instructions and using the number of clips shown has an approximate 80% efficiency rating. This rating is based upon the nominal strength of wire rope. If a pulley is used in place of a thimble for turning back the rope add one additional clip.

6

5

4

3

2

E

D

C

B

IMPORTANT : Failure to make a termination in accordance with aforementioned instructions, or failure to periodically check and retighten to the recommended torque, will cause a reduction in efficiency rating. C. Fist grip clips Recommended method of applying fist grip clips: 1. Turn back the specified amount of rope from the thimble. Apply the first clip one base width from the dead end of the wire rope. Tighten nuts evenly to recommended torque. 2. Apply the next clip as near the loop as possible. Turn on nuts firmly but do not tighten.

A

Monkey Board

Ladder Side of Derrick

F

The number of clips shown also applies to right regular lay wire rope, 8×19 class, fiber core, IPS, sizes 1 1/2-in. and smaller; and right regular lay wire rope, 18×7 class, fiber core, IPS or EIP, sizes 1 3/4-in. and smaller. For other classes of wire rope not mentioned above, it may be necessary to add additional clips to the number shown. If a greater number of clips are used than shown in the table, the amount of rope turnback should be increased proportionately. Above based on use of clips on new rope.

1 Drill Pipe Fingers

Pump Side of Derrick

The number of clips shown is based upon using right regular or lang lay wire rope, 6×19 class or 6×36 class fiber core or IWRC, IPS or EIP. If Seale construction or similar large outer wire type construction in the 6×19 class is to be used for sizes 1 inch and larger, add one additional clip.

T

Deadline Anchor (H) (for Right-Hand Receiving)

Drawworks Drum

Driller Side of Derrick

Figure WR-16: Illustrates the generally acceptable methods of reeving inline crown and traveling blocks.

Figure WR-16 illustrates in a simplified form the generally accepted methods of reeving (stringing up) inline crown and traveling blocks, along with the location of the drawworks drum, monkey board, drill pipe fingers, and deadline anchor in relation to the various sides of the derrick. Ordinarily, the only two variables in reeving systems, as illustrated, are the number of sheaves in the crown and traveling blocks or the number required for handling the load, and the location of the deadline anchor. Figure WR-16 shows a typical reeving diagram for a 12-line string-up with 7-shear crown block and 6-sheave traveling block (left-hand reeving). See arrangement 1 in Table WR-9.

3. Space additional clips if required equally between the first two. Turn on nuts-take up rope slack-tighten all nuts evenly on all clips to recommended torque.

Table WR-9 gives the various possible arrangements of reeving patterns for 12-10-8 and 6-line string-ups using 7-sheave crown blocks with 6-sheave traveling blocks and 6-sheave crown blocks with 5-sheave traveling blocks.

4.  NOTICE ! Apply the initial load and retighten nuts to the recommended torque. Rope will stretch and be reduced in diameter when loads are applied. Inspect periodically and retighten to recommended torque.

The most used practice is to use left-hand reeving and locate the deadline anchor to the left of the derrick vee. In selecting the best of the various possible methods for reeving casing or drilling lines, the following basic factors should be considered.

IADC Drilling Manual

Copyright © 2015

Table WR-9: Recommended reeving arrangmentes for 12, 10, 8 and 6-line string-ups using 7-sheave crown blocks with 6-sheave traveling blocks and 6-sheave crown blocks with 5-sheave traveling blocks.

No. of Sheaves Arrangement Crown Trav. No. Block Block 1 2 IADC Drilling Manual

3 4 5

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6 7 8 9 10

12 13

7 7 6 6 6 6 6 6 6 6 6 6

6 6 6 5 5 5 5 5 5 5 5 5 5

Lft Hand

12

Rt Hand Lft Hand Rt Hand Lft Hand Rt Hand Lft Hand Rt Hand Lft Hand Rt Hand Lft Hand Rt Hand Lft Hand Rt Hand

12 10 10 10 10 8 8 8 8 6 6 6 6

Reeving Sequence (Read from Left to Right Starting with Crown Block and Going Alternately from Crown to Traveling to Crown) Crn Blk Trav Blk

1

Crn Blk Trav Blk

7

Crn Blk Trav Blk

1

Crn Blk Trav Blk

7

Crn Blk Trav Blk

1

Crn Blk Trav Blk

6

Crn Blk Trav Blk

1

Crn Blk Trav Blk

6

Crn Blk Trav Blk

1

Crn Blk Trav Blk

6

2 A

3 B

6 F

5 E

2 A

D

4 D

2

C

2 5 E

4 D

Crn Blk Trav Blk

2

Crn Blk Trav Blk

5

4 C

H 5 G 2

B

H

4 C

4 E

G

D 3

3

6 E

3 C

H

2

4

C

A

A

B

C 4

G 1

5

3

3

D

6

D

C

B

H

E 2

3 B

G

A

B

H

1

5

4

G 1

6

2

D

7

A

E

B

D

A

6

3

H

F 2

5

3

5

6

B

D

B

E

Crn Blk Trav Blk

4 C

G 1

A

E 3

3

5

2

5

C

7 F

B

D

B

A

3

5

2

6 E

C

E

E

1

4

3

6

A

5 D

B

F

Crn Blk Trav Blk

4 C

Dead Line Anchor

G 1

A

H

WR–13

14

7

6

No. of Lines to

WIRE ROPE

11

7

Type of StringUp

WR–14

WIRE ROPE

1. Minimum fleet angle from the drawworks drum to the first sheave of the crown block and from the crown block sheaves to the traveling block sheaves. 2. Proper balancing of crown and traveling blocks. 3. Convenience in changing from smaller to larger number of lines, or from larger to smaller number of lines. 4. Locating of deadline on monkey board side for convenience and safety of derrickman. 5. Location of deadline anchor and its influence upon the maximum rated static hook load of derrick.

4. Determining maximum pull: The fast line during hoisting has a load greater than the total weight being lifted divided by the number of parts of line. The load is increased by the friction of the sheave bearings and the bending of the line around the sheaves. Starting at the deadline sheave, each successive line has, during hoisting, an extra load on it caused by the “sum” of the frictional loads from all previous rotating sheaves. 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. The fast line load can be calculated by the following formula:

B. Function of reeving system 1. General: A hoisting system is a way of lifting heavy loads with lighter lead line pulling loads. As with a simple pulley system, the line strung through the blocks allows you a mechanical lifting advantage. This mechanical advantage is equal to the number of lines strung between the crown and the traveling block, taking into consideration accumulated friction. Thus for a 6-line system, without friction you could lift a weight by pulling with a force of only 1/6 of the weight. With an 8-line system, the pull will be only 1/8 of the weight; with 10 lines, 1/10, and so forth. The reason for this mechanical advantage is that the lines emerging from the traveling block divide the load equally among themselves by pulling down on the line as it leaves the traveling block. This is the load divided by the number of lines strung. 2. Work encountered in reeving system: By utilizing mechanical advantage of the pulley you are not decreasing the work done. Work done is the load multiplied by the distance moved. When the load is hoisted, each of the lines shortens by the distance of the hoist, however, the last line or fast line, coming onto the drum, must take up all the extra line. This is, of course, the distance the load moves times the number of lines strung. Inasmuch as the load on this line is the weight lifted divided by the number of lines, then the work done by the hoist is the same as the work required to raise the load. 3. Line speed: Since the movement of the drilling line being wound or unwound on the drum is greater than the movement of the traveling block, the speed with which it moves is also greater. Thus if the traveling block is being lowered at the rate of 10 ft/sec in a 6-line system, the line is paying off the drum at 60 ft/sec or 3,600 ft/min. Maximum recommended speed for movement of wire ropes through the sheaves is 4,000 ft/min. If the block of an 8-line system were moving at 10 ft/sec, the line speed would exceed the recommended rate.

IADC Drilling Manual

L = W × K s (K−1)

Kn− 1

Where: L = W = K = = n = *s =

fast line load, lb total weight lifted, lb friction coefficient roller bearing sheaves 1.04 number of parts of line number of rotating sheaves

*NOTE: Deadline crown sheave does not rotate during hoisting so for most rotary rigs s = n. EXAMPLE 500,000 lb load 10-line string up 1 1/2 in. EIPS drilling line friction coefficient = 1.04 What is the lead line load and design factor? A.

n = 10 s = 10 W = 500,000 L = 500,000 × (1.04)10 (1.04 −1) (1.04)10 − 1

K = 1.04

What is the lead line load and design? = 500,000×0.123 Lead line load = 61,500 lb B.

Nominal Strength 1 1/2 in. EIPS = 114 Tons = 228,000 lb Design Factor = 228,000 = 3.7 to 1 61,500

WARNING: The fhahaoregoing ignores acceleration forces and shock loadings. These may greatly increase the load on the rope and lead to permanent deformation and increased rate of deterioration.

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WIRE ROPE

5. Fast line loads and design factors: Fast line loads and design factors for various hook loads with 6, 8, 10, and 12 parts of line are shown in Table WR-10. This table is based on the Extra Improved Plow and Improved Plow with independent wire rope cores.

Factors affecting service Here are some critical factors that directly affect rotary drilling line service. When these elemental factors are considered, it is then apparent why rotary line service programs must be tailored each individual rig. 1. Mast or derrick height: Varies from approximately 65 ft to 185 ft or more. Governs the total amount of rotary line in the string-up and determines whether “doubles”, “triples” or “quadruples” of drill pipe will be handled during trips. 2. Crown blocks sheaves: Sheave diameters should be large enough to minimize the bending fatigue that occurs on a rotary line. Worn grooves will not properly support the rotary line and worn bearings set up undue wear on both the sheaves and the line. 3. Traveling block sheaves: The same conditions concerning the sheaves apply here as with the Crown Block. In addition, the traveling block must be of sufficient weight to give tight spooling on the drum as the block assembly is being raised or lowered when going into and coming out of the hole. 4. Draw works drum: The diameter and length of the drum is important. A drum of small diameter and length requires more drum wraps to raise the blocks. This leads to more layers of rope on the drum and therefore more “cross-over” wear points. A grooved drum increases wire line service by supporting the rotary line and giving a tighter wrap. The condition of the drum clutch and brake greatly affects line life. If these are not properly adjusted the resulting jerking and shock loads must be borne by the rotary line. 5. Types of string-up—6, 8, 10 or 12 lines: Governs the load each part of the line must carry, determines the total line in the String-Up, and also determines the length of time that wear points must remain in the system. 6. Dead line anchor or clamp: The size, type and condition of the anchor has a direct effect on the rotary line. If it is too small or otherwise distorts the line, it may form a “dog-leg” in the line which will set up a stress point. This stress point will result in undue wear and early fatigue, necessitating a long cut to get it out of the system. 7. Wire line stabilizer and turn-back rollers: These two pieces of equipment help extend wire line life. The wire line stabilizer relieves vibration or “whip” on the “fast” line. The turn-back rollers help relieve shock at the “cross-

IADC Drilling Manual

WR–15

over” points on the drum and prevent line piling up at the drum flanges. Weight box type stabilizers are considered far superior as far as drum spooling is concerned. Deadline stabilizers reduce vibration in the deadline adjacent to the deadline anchor and deadline sheave. 8. Experience of crew: Affects wire line life in the manner in which they handle the rotary line. For example, how they un-spool the reel, how they reeve the string-up, steps taken to keep the line out of mud and dirt, method used to spool new line on the drum and how the driller starts and stops the drum when making a “round trip.” Remember, 6 inches of slack line jerked out on the load, doubles the load on the line. 9. Depth of well: Governs total weight of drill pipe and drill collars, the number of connections required, the number of bits and the number of round trips required. 10. Drilling conditions: Certain types of earth strata cause bit “chatter” or vibration, which is passed through the drill pipe and traveling blocks to the rotary line. The intermittent shock loads must be absorbed by the drilling line and are a source of undue wear, particularly at the dead line sheave. Also, certain strata cause crooked hole drilling, which results in considerable excess strain on the drilling line when coming out of the hole during a round trip. 11. Size of drill pipe: Determines the total load when figuring the ton-mile service per round trip and in making connections. 12. Size and number of drill collars: Is one of the variable factors in determining the total excess weight when figuring ton-mile service per round trip. 13. Drill stem tests: Means extra round trips over and above those necessary to change bits. 14. Coring: Also means extra round trips and more line wear. 15. Stuck pipe: Jarring and manipulation to un-stick drill pipe causes extreme strain and wear on rotary line. No ton-mile method of service wear can determine the damage here! Careful visual inspection should be made, and damaged line removed from the system regardless of the length of cut required. 16. “Twist offs” and “fishing” jobs: Often mean several extra round trips to completely remove the “fish” or obstruction before normal drilling can be resumed. 17. Setting casing: Length and size will vary, but it still means additional trips, connections, and line wear. 18. Fleet angle: Taken into consideration with the proper wire line stabilizer can be the basis for solving many of the reasons for poor spooling on a rig. Therefore, the proper fleet angle should be of paramount importance when determining the excess laps.

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WR–16

WIRE ROPE Table WR-10 (continued on page WR-17) Grade

Hookload 000 lb

200

250

300

350

400

450

500

600

700

800

900

1,000

1,250

1,500

Parts of Line

Fast Line Factors

IPS

1 in. EIP EEIP

IPS

MBF (Short Tons)

44.9 51.7 56.9 56.5

MBF (lb)

89,800

103,400

113,800

113,000

1 1/8-in. EIP EEIP 65 130,000

IPS

1 1/4-in. EIP EEIP

IPS

1 3/8-in. EIP EEIP

71.5 69.4 79.9 87.9 83.5 143,000

138,800

159,800

175,800

167,000

96 192,000

IPS

1 1/2-in. EIP EEIP

106 98.9 114 212,000

197,800

228,000

IPS

1 5/8-in. EIP EEIP

125

115

132

146

250,000

230,000

264,000

292,000

Fast Line Load lb

6

0.191

38,200

2.35

2.71

2.98

2.96

3.40

3.74

3.63

4.18

4.60

8

0.148

29,600

3.03

3.49

3.84

3.82

4.39

4.83

4.69

5.40

5.94

10

0.123

24,600

3.65

4.20

4.63

4.59

5.28

5.81

5.64

6.50

7.15

6

0.191

47,750

1.88

2.17

2.38

2.37

2.72

2.99

2.91

3.35

3.68

3.50

4.02

4.44

8

0.148

37,000

2.43

2.79

3.08

3.05

3.51

3.86

3.75

4.32

4.75

4.51

5.19

5.73

10

0.123

30,750

2.92

3.36

3.70

3.67

4.23

4.65

4.51

5.20

5.72

5.43

6.24

6.89

12

0.107

26,750

3.36

3.87

4.25

4.22

4.86

5.35

5.19

5.97

6.57

6.24

7.18

7.93

6

0.191

57,300

1.57

1.80

1.99

1.97

2.27

2.50

2.42

2.79

3.07

2.91

3.35

3.70

3.45

3.98

4.36

8

0.148

44,400

2.02

2.33

2.56

2.55

2.93

3.22

3.13

3.60

3.96

3.76

4.32

4.77

4.45

5.14

5.63

10

0.123

36,900

2.43

2.80

3.08

3.06

3.52

3.88

3.76

4.33

4.76

4.53

5.20

5.75

5.36

6.18

6.78

12

0.106

31,800

2.82

3.25

3.58

3.55

4.09

4.50

4.36

5.03

5.53

5.25

6.04

6.67

6.22

7.17

7.86

1.69

1.94

2.14

2.08

2.39

2.63

2.50

2.87

3.17

2.96

3.41

3.74

3.44

3.95

4.37

1.73

2.00

2.20

2.18

2.51

2.76

2.68

3.08

3.39

3.22

3.71

4.09

3.82

4.40

4.83

4.44

5.10

5.64

6

0.191

66,850

8

0.148

51,800

10

0.123

43,050

2.09

2.40

2.64

2.62

3.02

3.32

3.22

3.71

4.08

3.88

4.46

4.92

4.59

5.30

5.81

5.34

6.13

6.78

12

0.106

37,100

2.42

2.79

3.07

3.05

3.50

3.85

3.74

4.31

4.74

4.50

5.18

5.71

5.33

6.15

6.74

6.20

7.12

7.87

1.91

2.20

2.42

2.34

2.70

2.97

2.82

3.24

3.58

3.34

3.85

4.22

3.89

4.46

4.93

2.30

2.64

2.91

2.82

3.25

3.57

3.39

3.90

4.31

4.02

4.63

5.08

4.67

5.37

5.93 6.89

8

0.148

59,200

10

0.123

49,200

1.83

2.10

2.31

2.12

2.44

2.68

12

0.106

42,400

8

0.148

66,600

10

0.123

55,350

1.62

1.87

1.88

2.17

12

0.106

47,700

8

0.148

74,000

2.67

3.07

3.37

3.27

3.77

4.15

3.94

4.53

5.00

4.67

5.38

5.90

5.42

6.23

1.70

1.95

2.15

2.08

2.40

2.64

2.51

2.88

3.18

2.97

3.42

3.75

3.45

3.96

4.38

2.06

2.04

2.35

2.58

2.51

2.89

3.18

3.02

3.47

3.83

3.57

4.12

4.52

4.16

4.77

5.28

2.39

2.37

2.73

3.00

2.91

3.35

3.69

3.50

4.03

4.44

4.15

4.78

5.24

4.82

5.53

6.12

1.88

2.16

2.38

2.26

2.59

2.86

2.67

3.08

3.38

3.11

3.57

3.95

10

0.123

61,500

1.84

2.11

2.33

2.26

2.60

2.86

2.72

3.12

3.45

3.22

3.71

4.07

3.74

4.29

4.75

12

0.106

53,000

1.69

1.95

2.15

2.13

2.45

2.70

2.62

3.02

3.32

3.15

3.62

4.00

3.73

4.30

4.72

4.34

4.98

5.51

1.89

2.18

2.40

2.38

2.74

3.01

2.92

3.36

3.70

14

0.095

47,500

8

0.148

88,800

10

0.123

73,800

12

0.106

63,600

14

0.095

57,000

8

0.148

103,600

1.58

1.81

2.00

3.52

4.04

4.46

4.16

4.80

5.26

4.84

5.56

6.15

1.88

2.16

2.39

2.23

2.57

2.82

2.59

2.97

3.29

1.88

2.17

2.38

2.26

2.60

2.87

2.68

3.09

3.39

3.12

3.58

3.96

1.78

2.04

2.25

2.18

2.51

2.76

2.63

3.02

3.33

3.11

3.58

3.93

3.62

4.15

4.59

1.98

2.28

2.51

2.44

2.80

3.08

2.93

3.37

3.72

3.47

4.00

4.39

4.04

4.63

5.12

1.61

1.85

2.05

1.91

2.20

2.41

2.22

2.55

2.82

10

0.123

86,100

1.61

1.86

2.04

1.94

2.23

2.46

2.30

2.65

2.90

2.67

3.07

3.39

12

0.106

74,200

1.87

2.15

2.37

2.25

2.59

2.86

2.67

3.07

3.37

3.10

3.56

3.94

2.09

2.40

2.64

2.51

2.89

3.19

14

0.095

66,500

8

0.148

118,400

1.70

1.95

2.15

2.97

3.43

3.76

3.46

3.97

4.39

1.67

1.93

2.11

1.94

2.23

2.47

10

0.123

98,400

1.70

1.95

2.15

2.01

2.32

2.54

2.34

2.68

2.97

12

0.106

84,800

1.64

1.88

2.07

1.97

2.26

2.50

2.33

2.69

2.95

2.71

3.11

3.44

1.83

2.10

2.31

2.20

2.53

2.79

2.60

3.00

3.29

14

0.095

76,000

8

0.148

133,200

10

0.123

110,700

12

0.106

95,400

14

0.095

85,500

10

0.123

123,000

1.62

1.87

2.06

1.75

2.01

2.22

1.95

2.25

2.48

3.03

3.47

3.84

1.73

1.98

2.19

1.79

2.06

2.26

2.08

2.38

2.64

2.07

2.39

2.62

2.41

2.77

3.06

2.31

2.67

2.92

2.69

3.09

3.42

1.61

1.85

2.03

1.87

2.15

2.37

12

0.106

106,000

1.58

1.81

2.00

1.87

2.15

2.36

2.17

2.49

2.75

14

0.095

95,000

1.76

2.02

2.23

2.08

2.40

2.63

2.42

2.78

3.07

16

0.086

86,000

1.94

2.23

2.47

2.30

2.65

2.91

2.67

3.07

3.40

12

0.106

132,500

1.74

1.99

2.20

1.61

1.86

2.04

14

0.095

118,750

1.67

1.92

2.11

1.94

2.22

2.46

16

0.086

107,500

1.84

2.12

2.33

2.14

2.46

2.72

12

0.106

159,000

14

0.095

142,500

1.61

1.85

2.05

16

0.086

129,000

1.78

2.05

2.26

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–17

Table WR-10 (continued from page WR-16) 1-3/4 in.

Hookload 000 lb

500

600

700

800

900

1,000

1,250

1,500

1,750

2,000

2,250

2,500

1-7/8 in.

2 in.

2-1/8-in.

2-1/4 in.

Grade

IPS

EIP

EEIP

IPS

EIP

EEIP

IPS

EIP

EEIP

IPS

EIP

EEIP

IPS

EIP

MBF (Short Tons)

133

153

169

152

174

192

172

198

217

192

221

244

215

247

272

MBF (lb)

266,000

306,000

338,000

304,000

348,000

384,000

344,000

396,000

434,000

384,000

442,000

488,000

430,000

494,000

544,000

4.08

Parts of Line

Fast Line Factors

8

0.148

74,000

3.59

4.14

4.57

10

0.123

61,500

4.33

4.98

5.50 6.38

EEIP

Fast Line Load lb

12

0.106

53,000

5.02

5.77

14

0.095

47,500

5.60

6.44

7.12

8

0.148

88,800

3.00

3.45

3.81

3.42

3.92

4.32

10

0.123

73,800

3.60

4.15

4.58

4.12

4.72

5.20

12

0.106

63,600

4.18

4.81

5.31

4.78

5.47

6.04

14

0.095

57,000

4.67

5.37

5.93

5.33

6.11

6.74

8

0.148

103,600

2.57

2.95

3.26

2.93

3.36

3.71

3.32

3.82

4.19

10

0.123

86,100

3.09

3.55

3.93

3.53

4.04

4.46

4.00

4.60

5.04

12

0.106

74,200

3.58

4.12

4.56

4.10

4.69

5.18

4.64

5.34

5.85

14

0.095

66,500

4.00

4.60

5.08

4.57

5.23

5.77

5.17

5.95

6.53

8

0.148

118,400

2.25

2.58

2.85

2.57

2.94

3.24

2.91

3.34

3.67

3.24

3.73

4.12

10

0.123

98,400

2.70

3.11

3.43

3.09

3.54

3.90

3.50

4.02

4.41

3.90

4.49

4.96

12

0.106

84,800

3.14

3.61

3.99

3.58

4.10

4.53

4.06

4.67

5.12

4.53

5.21

5.75

14

0.095

76,000

3.50

4.03

4.45

4.00

4.58

5.05

4.53

5.21

5.71

5.05

5.82

6.42

8

0.148

133,200

2.00

2.30

2.54

2.28

2.61

2.88

2.58

2.97

3.26

2.88

3.32

3.66

3.23

3.71

10

0.123

110,700

2.40

2.76

3.05

2.75

3.14

3.47

3.11

3.58

3.92

3.47

3.99

4.41

3.88

4.46

4.91

12

0.106

95,400

2.79

3.21

3.54

3.19

3.65

4.03

3.61

4.15

4.55

4.03

4.63

5.12

4.51

5.18

5.70

14

0.095

85,500

3.11

3.58

3.95

3.56

4.07

4.49

4.02

4.63

5.08

4.49

5.17

5.71

5.03

5.78

6.36

10

0.123

123,000

2.16

2.49

2.75

2.47

2.83

3.12

2.80

3.22

3.53

3.12

3.59

3.97

3.50

4.02

4.42

12

0.106

106,000

2.51

2.89

3.19

2.87

3.28

3.62

3.25

3.74

4.09

3.62

4.17

4.60

4.06

4.66

5.13

14

0.095

95,000

2.80

3.22

3.56

3.20

3.66

4.04

3.62

4.17

4.57

4.04

4.65

5.14

4.53

5.20

5.73

16

0.086

86,000

3.09

3.56

3.93

3.53

4.05

4.47

4.00

4.60

5.05

4.47

5.14

5.67

5.00

5.74

6.33

12

0.106

132,500

2.01

2.31

2.55

2.29

2.63

2.90

2.60

2.99

3.28

2.90

3.34

3.68

3.25

3.73

4.11

14

0.095

118,750

2.24

2.58

2.85

2.56

2.93

3.23

2.90

3.33

3.65

3.23

3.72

4.11

3.62

4.16

4.58

16

0.086

107,500

2.47

2.85

3.14

2.83

3.24

3.57

3.20

3.68

4.04

3.57

4.11

4.54

4.00

4.60

5.06

12

0.106

159,000

1.67

1.92

2.13

1.91

2.19

2.42

2.16

2.49

2.73

2.42

2.78

3.07

2.70

3.11

3.42

14

0.095

142,500

1.87

2.15

2.37

2.13

2.44

2.69

2.41

2.78

3.05

2.69

3.10

3.42

3.02

3.47

3.82

16

0.086

129,000

2.06

2.37

2.62

2.36

2.70

2.98

2.67

3.07

3.36

2.98

3.43

3.78

3.33

3.83

4.22

12

0.106

185,500

1.64

1.88

2.07

1.85

2.13

2.34

2.07

2.38

2.63

2.32

2.66

2.93

14

0.095

166,250

1.60

1.84

2.03

1.83

2.09

2.31

2.07

2.38

2.61

2.31

2.66

2.94

2.59

2.97

3.27

16

0.086

150,500

1.77

2.03

2.25

2.02

2.31

2.55

2.29

2.63

2.88

2.55

2.94

3.24

2.86

3.28

3.61

12

0.106

212,000

1.62

1.87

2.05

1.81

2.08

2.30

2.03

2.33

2.57

14

0.095

190,000

1.60

1.83

2.02

1.81

2.08

2.28

2.02

2.33

2.57

2.26

2.60

2.86

16

0.086

172,000

1.77

2.02

2.23

2.00

2.30

2.52

2.23

2.57

2.84

2.50

2.87

3.16

18

0.079

158,000

1.68

1.94

2.14

1.92

2.20

2.43

2.18

2.51

2.75

2.43

2.80

3.09

2.72

3.13

3.44

20

0.074

148,000

1.80

2.07

2.28

2.05

2.35

2.59

2.32

2.68

2.93

2.59

2.99

3.30

2.91

3.34

3.68

14

0.095

213,750

1.61

1.85

2.03

1.80

2.07

2.28

2.01

2.31

2.55

16

0.086

193,500

1.78

2.05

2.24

1.98

2.28

2.52

2.22

2.55

2.81

18

0.079

177,750

2.44

2.16

2.49

2.75

2.42

2.78

3.06

20

0.074

166,500

16

0.086

215,000

18

0.079

197,500

20

0.074

185,000

1.60

1.84

2.03

1.71

1.96

2.16

1.94

2.23

1.83

2.09

2.31

2.07

2.38

2.61

2.31

2.65

2.93

2.58

2.97

3.27

1.60

1.84

2.02

1.79

2.06

2.27

2.00

2.30

2.53

1.74

2.01

2.20

1.94

2.24

2.47

2.18

2.50

2.75

1.86

2.14

2.35

2.08

2.39

2.64

2.32

2.67

2.94

1.64

1.88

2.08

IADC Drilling Manual

Copyright © 2015

WR–18

WIRE ROPE Table WR-11: E indicator—drill collar weight factor, drill collar dimensions (in.)

# of Drill Collars

4 1/8 × 2

4 3/4 × 2 1/4

5 3/4 × 2 13/16

5 3/4 × 2 1/4 6 × 2 13/16

6 × 2 1/4 6 1/4 × 2 13/16

6 1/4 × 2 1/4 6 1/2 × 2 13/16

1

1

400

600

700

800

900

2

2

700

1,300

1,500

1,700

1,900

3

3

1,100

1,900

2,200

2,500

2,800

4

4

1,500

2,600

2,900

3,300

3,800

5

5

1,900

3,200

3,700

4,200

4,700

6

6

2,200

3,800

4,000

5,000

5,600

7

7

2,600

4,500

5,100

5,800

6,600

8

8

3,000

5,100

5,900

6,700

7,500

9

9

3,400

5,700

6,600

7,500

8,500

10

10

3,700

6,400

7,300

8,300

9,400

11

11

4,100

7,000

8,100

9,200

10,300

12

12

4,500

7,700

8,800

10,000

11,300

13

13

4,900

8,300

9,500

10,800

12,200

14

14

5,200

8,900

10,200

11,700

13,200

15

15

5,600

9,600

11,000

12,500

14,100

16

16

6,000

10,200

11,700

13,300

15,000

17

17

6,300

10,800

12,400

14,200

16,000

18

18

6,700

11,500

13,200

15,000

16,900

19

19

7,100

12,100

13,900

15,800

17,900

20

20

7,500

12,800

14,600

16,700

18,800

21

21

7,800

13,400

15,400

17,500

19,800

22

22

8,200

14,000

16,100

18,300

20,700

23

23

8,600

14,700

16,800

19,200

21,600

24

24

9,000

15,300

17,600

20,000

22,600

25

25

9,300

15,900

18,300

20,900

23,500

26

26

9,700

16,600

19,000

21,700

24,500

27

27

10,100

17,200

19,800

22,500

25,400

28

28

10,500

17,900

20,500

23,400

26,300

29

29

10,800

18,500

21,200

24,200

27,300

30

30

11,200

19,100

22,000

25,000

28,200

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–19

Table WR-11 (continued): E indicator—drill collar weight factor, drill collar dimensions (in.) # of Drill Collars

6 × 2 1/4 63/4 × 2 13/16

6 3/4 × 2 1/4 7 × 2 13/16

7 1/4 × 2 13/16

7 3/4 × 3 7 3/4 × 2 13/16

8×3 8 × 2 13/16

9×3

1

1,000

1,200

1,300

1,500

1,700

2,200

2

2,100

2,300

2,600

3,100

3,300

4,400

3

3,100

3,500

3,900

4,600

5,000

6,500

4

4,200

4,600

5,200

6,100

6,700

8,700

5

5,200

5,800

6,500

7,700

8,300

10,900

6

6,300

7,000

7,800

9,200

10,000

13,100

7

7,300

8,100

9,100

10,700

11,700

15,300

8

8,400

9,300

10,400

12,300

13,300

17,400

9

9,400

10,400

11,700

13,800

15,000

19,600

10

10,500

11,600

13,000

15,300

16,700

21,800

11

11,500

12,800

14,300

16,900

18,300

24,000

12

12,600

13,900

15,600

18,400

20,000

26,200

13

13,600

15,100

16,900

19,900

21,700

28,300

14

14,700

16,200

18,200

21,500

23,300

30,500

15

15,700

17,400

19,500

23,000

25,000

32,700

16

16,800

18,600

20,800

24,600

26,700

34,900

17

17,800

19,700

22,100

26,100

28,300

37,100

18

18,900

20,900

23,400

27,600

30,000

39,200

19

19,900

22,000

24,700

29,200

31,700

41,400

20

21,000

23,200

26,000

30,700

33,300

43,600

21

22,000

24,300

27,200

32,200

35,000

45,800

22

23,100

25,500

28,500

33,800

36,700

48,000

23

24,100

26,700

29,800

35,300

38,300

50,100

24

25,200

27,800

31,100

36,800

40,000

52,300

25

26,200

29,000

32,400

38,400

41,700

54,500

26

27,300

30,100

33,700

39,900

43,300

56,700

27

28,300

31,300

35,000

41,400

45,000

58,900

28

29,400

32,500

36,300

43,000

46,700

61,000

29

30,400

33,600

37,600

44,500

48,300

63,200

30

31,500

34,800

38,900

46,000

50,000

65,400

IADC Drilling Manual

Copyright © 2015

WR–20

WIRE ROPE

Ton-mile calculations A. Introduction In the early 1940s, a drilling contractor would have purchased only enough rotary drilling line to string-up the reeving system. Depending upon the height of the derrick and the number of parts of line to be used, lengths would vary from 650 ft to 1,750 ft. In working the line, heavy wear would occur in a few localized sections: where the rope makes contact with the traveling block sheaves, and where the rope makes contact with the crown block sheaves when the slips are pulled going in or coming out of the hole, and on the drum where each wrap of rope crosses over the rope on the layer below. Broken wires at these points of critical wear would result in the retirement of the entire string up, even though the remainder of the rope was in good condition. For these reasons, it is important that the drilling line be cut off at the proper rate. The purpose of this Simplified Cut-Off Practice is to give the drilling contractor a method for keeping track of the amount of work done by the drilling line and a systematic procedure for making cuts of the appropriate length at the appropriate time. The objective is to obtain maximum rope service without jeopardizing the safety of the rig operation. In conjunction with the record keeping required for the cut-off procedure, daily visual inspection of the drilling line should be made for broken wires and any other rope damage. It must be remembered that in all cases, visual inspection of the wire rope by the drilling contractor must take precedence over any predetermined calculations. The only complicated part of a cut-off procedure is the determination of how much work has been done by the wire rope. Methods such as counting the number of wells drilled or keeping track of days between cuts are not accurate because the loads change with depth and with different drilling conditions. The various operations performed (drilling, coring, fishing, setting casing, etc.) subject the rope to different amounts of wear. For an accurate record of the amount of work done by a drilling line, it is necessary to calculate the weight being lifted and the distance it is raised and lowered. In engineering terms, work is measured in foot-pounds. On a drilling rig the loads and distances are so great that we use “ton-miles.” One ton-mile equals 10,560,000 ft-lb and is equivalent to lifting 2,000 lb a distance of 5,280 ft.

are available for any type or size of drill pipe in both mud and air drilling. Contact a UNION WIRE ROPE representative for the Indicator(s) you require. B. Examples of ton-mile calculations EXAMPLE 1 Round trip ton-miles Situation: At a depth of 11,000 ft, a round trip is made to change the bit. Drill Pipe = 4 1/- in. (l6.6 lb/ft) Drill Collars = ten, 7-1/4 in. (119.2 lb/ft) Traveling block assembly weight (hook, elevators, traveling block) = 27,000 lb Drilling Fluid = mud Solution: 1) Determine weight factor due to collars: On Table WR-11, locate proper drill collar number and read weight factor due to collars in appropriate column. Weight factor due to collars = 13,000 lb 2) Determine total weight factor: Add together Weight Factor due to Collars and weight of Traveling Block assembly. Traveling Block Assembly Weight = 27,000 lb + Weight Factor due to Collars = 13,000 lb Total Weight Factor = 40,000 lb 3) Determine Ton-Miles Per Round Trip: On Table WR-10, locate depth and read round trip ton-miles in appropriate column. Round Trip Ton-Miles = 337 T-M Note: For laying down drill pipe at the end of well, figure one-half of round trip ton-miles for drill string in question.

To simplify the calculation of ton-miles, a Ton-Mile Indicator has been developed. The following pages provide examples of how this Indicator is used to determine the number of tonmiles of work done by the drilling line for various operations on the rig. Please refer to Tables WR-9 and WR-10 as you go through the examples. These tables are taken from the TonMile Indicator developed by UNION WIRE ROPE. Indicators

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–21

Table WR-12: Wire rope indicator Ton-Mile per round trip 4 ½ in., 16.6 lb/ft drill pipe in mud—total weight factor Depth

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

1,000

5

9

13

17

20

24

28

32

36

39

1,200

7

11

16

20

25

29

34

39

43

48

1,400

8

14

19

24

29

35

40

45

51

56

1,600

10

16

22

28

34

40

46

52

58

64

1,800

12

18

25

32

39

46

52

59

66

73

2,000

13

21

29

36

44

51

59

66

74

82

2,200

15

24

32

40

49

57

65

74

82

90

2,400

17

27

36

45

54

63

72

81

90

99

2,600

20

29

39

49

59

69

79

89

98

108

2,800

22

33

43

54

64

75

86

96

107

117

3,000

24

36

47

58

70

81

92

104

115

127

3,200

27

39

51

63

75

87

100

112

124

136

3,400

29

42

55

68

81

94

107

120

132

145

3,600

32

46

59

73

87

100

114

128

141

155

3,800

35

49

64

78

93

107

121

136

150

165

4,000

38

53

68

83

99

114

129

144

159

174

4,200

41

57

73

89

105

121

137

152

168

184

4,400

44

61

78

94

111

128

144

161

178

194

4,600

48

65

82

100

117

135

152

169

187

204

4,800

51

69

87

105

124

142

160

178

196

215

5,000

54

73

92

111

130

149

168

187

206

225

5,200

58

78

97

117

137

157

176

196

216

235

5,400

62

82

103

123

144

164

185

205

225

246

5,600

66

87

108

129

150

172

193

214

235

257

5,800

70

92

114

136

157

179

201

223

245

267

6,000

74

96

119

142

165

187

210

233

255

278

6,200

78

101

125

148

172

195

219

242

266

289

6,400

82

106

131

155

179

203

228

252

276

300

6,600

87

112

137

162

187

212

237

262

287

312

6,800

91

117

143

168

194

220

246

271

297

323

7,000

96

122

149

175

202

228

255

281

308

334

IADC Drilling Manual

Copyright © 2015

WR–22

WIRE ROPE Table WR-13: Design factors 2 in. extra extra improved plow rotary drill line, 434,000 lb nominal strength*

Weight Indicator Reading (1000's Lbs.) 12 Lines

14 Lines

16 Lines

Weight Indicator Reading (1000's Lbs.) Design Factor

12 Lines

14 Lines

16 Lines

Design Factor

411

463

511

9.9

690

778

857

5.9

416

468

516

9.8

702

791

872

5.8

420

473

521

9.7

715

805

887

5.7

424

478

527

9.6

727

819

903

5.6

429

483

532

9.5

740

834

919

5.5

433

488

538

9.4

754

850

936

5.4

438

493

544

9.3

768

866

954

5.3

443

499

549

9.2

783

882

972

5.2

448

504

556

9.1

799

899

991

5.1

453

510

562

9

815

917

1011

5

458

515

568

8.9

831

936

1032

4.9

463

521

574

8.8

848

956

1053

4.8

468

527

581

8.7

867

976

1076

4.7

474

533

588

8.6

885

997

1099

4.6

479

540

595

8.5

905

1019

1123

4.5

485

546

602

8.4

926

1043

1149

4.4

491

553

609

8.3

947

1067

1176

4.3

497

559

616

8.2

970

1092

1204

4.2

503

566

624

8.1

993

1119

1233

4.1

509

573

632

8

1018

1147

1264

4

516

581

640

7.9

1044

1176

1296

3.9

522

588

648

7.8

1072

1207

1330

3.8

529

596

657

7.7

1101

1240

1366

3.7

536

604

665

7.6

1131

1274

1404

3.6

543

612

674

7.5

1164

1311

1444

3.5

550

620

683

7.4

1198

1349

1487

3.4 3.3

558

628

692

7.3

1234

1390

1532

566

637

702

7.2

1273

1434

1580

3.2

574

646

712

7.1

1314

1480

1631

3.1

582

655

722

7

1358

1529

1685

3

590

665

733

6.9

1404

1582

1743

2.9

599

675

743

6.8

1455

1638

1805

2.8

608

685

755

6.7

1508

1699

1872

2.7

617

695

766

6.6

1566

1764

1944

2.6

627

706

778

6.5

1629

1835

2022

2.5

636

717

790

6.4

1697

1911

2106

2.4 2.3

646

728

802

6.3

1771

1995

2198

657

740

815

6.2

1851

2085

2298

2.2

668

752

829

6.1

1939

2184

2407

2.1

679

765

843

6

2036

2294

2528

2

*The design factors were calculated using Case A from the API 9B formula with 4% sheave loss. They do not include shock loads or acceleration stresses.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–23

Table WR-14: Design factors 2 in. extra extra improved plow rotary drill line, 113,800 lb nominal strength* Weight Indicator Reading (1000's Lbs.) 6 Lines

8 Lines

10 Lines

Weight Indicator Reading (1000's Lbs.) Design Factor

6 Lines

8 Lines

10 Lines

Design Factor

60

77

93

9.9

101

130

156

5.9

61

78

94

9.8

103

132

159

5.8

62

79

95

9.7

105

134

162

5.7

62

80

96

9.6

107

137

165

5.6

63

81

97

9.5

109

139

168

5.5

63

82

98

9.4

111

142

171

5.4

64

82

99

9.3

113

145

174

5.3

65

83

100

9.2

115

147

177

5.2

66

84

101

9.1

117

150

181

5.1

66

85

103

9

119

153

185

5

67

86

104

8.9

122

156

188

4.9

68

87

105

8.8

124

160

192

4.8

69

88

106

8.7

127

163

196

4.7

69

89

107

8.6

130

167

201

4.6

70

90

109

8.5

133

170

205

4.5

71

91

110

8.4

136

174

210

4.4

72

92

111

8.3

139

178

215

4.3

73

93

113

8.2

142

183

220

4.2

74

95

114

8.1

146

187

225

4.1

75

96

115

8

149

192

231

4

76

97

117

7.9

153

197

237

3.9

77

98

118

7.8

157

202

243

3.8

78

100

120

7.7

161

207

249

3.7

79

101

121

7.6

166

213

256

3.6

80

102

123

7.5

171

219

264

3.5

81

104

125

7.4

176

225

271

3.4 3.3

82

105

126

7.3

181

232

280

83

106

128

7.2

186

240

288

3.2

84

108

130

7.1

193

247

298

3.1

85

110

132

7

199

256

308

3

86

111

134

6.9

206

264

318

2.9

88

113

136

6.8

213

274

330

2.8

89

114

138

6.7

221

284

342

2.7

90

116

140

6.6

230

295

355

2.6

92

118

142

6.5

239

307

369

2.5

93

120

144

6.4

249

319

385

2.4

95

122

146

6.3

259

333

401

2.3

96

124

149

6.2

271

348

420

2.2

98

126

151

6.1

284

365

439

2.1

99

128

154

6

298

383

461

2

*The design factors were calculated using Case A from the API 9B formula with 4% sheave loss. They do not include shock loads or acceleration stresses.

IADC Drilling Manual

Copyright © 2015

WR–24

WIRE ROPE Table WR-15: Design factors 2 in. extra extra improved plow rotary drill line, 434,000 lb nominal strength*

Weight Indicator Reading (1000's lbs.) 10 Lines

12 Lines

14 Lines

Weight Indicator Reading (1000's Lbs.) Design Factor

10 Lines

12 Lines

14 Lines

Design Factor

205

237

267

9.9

344

398

448

5.9

207

239

270

9.8

350

404

456

5.8

209

242

272

9.7

356

412

464

5.7

211

244

275

9.6

362

419

472

5.6

213

247

278

9.5

369

427

480

5.5

216

250

281

9.4

375

434

489

5.4

218

252

284

9.3

383

443

499

5.3

220

255

287

9.2

390

451

508

5.2

223

258

290

9.1

398

460

518

5.1

225

261

294

9

406

469

529

5

228

264

297

8.9

414

479

539

4.9

230

267

300

8.8

422

489

551

4.8

233

270

304

8.7

431

499

562

4.7

236

273

307

8.6

441

510

574

4.6

239

276

311

8.5

451

521

587

4.5

241

279

315

8.4

461

533

601

4.4

244

283

318

8.3

472

546

615

4.3

247

286

322

8.2

483

559

629

4.2

250

290

326

8.1

495

572

645

4.1

253

293

330

8

507

587

661

4

257

297

334

7.9

520

602

678

3.9

260

301

339

7.8

534

617

695

3.8

263

305

343

7.7

548

634

714

3.7

267

309

348

7.6

563

652

734

3.6

270

313

352

7.5

579

670

755

3.5

274

317

357

7.4

596

690

777

3.4 3.3

278

321

362

7.3

614

711

801

282

326

367

7.2

634

733

826

3.2

286

330

372

7.1

654

757

852

3.1

290

335

378

7

676

782

881

3

294

340

383

6.9

699

809

911

2.9

298

345

389

6.8

724

838

944

2.8

303

350

394

6.7

751

869

979

2.7

307

355

400

6.6

780

902

1016

2.6

312

361

407

6.5

811

938

1057

2.5

317

367

413

6.4

845

978

1101

2.4

322

372

419

6.3

882

1020

1149

2.3

327

378

426

6.2

922

1066

1201

2.2

332

385

433

6.1

965

1117

1258

2.1

338

391

440

6

1014

1173

1321

2

*The design factors were calculated using Case A from the API 9B formula with 4% sheave loss. They do not include shock loads or acceleration stresses.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–25

Table WR-16: Design factors 1 5/8 in. extra, extra improved plow rotary drill line, 143,000 lb nominal strength* Weight Indicator Reading (1000's Lbs.) 6 Lines

6 Lines

10 Lines

Weight Indicator Reading (1000's Lbs.) Design Factor

6 Lines

6 Lines

10 Lines

Design Factor

76

97

117

9.9

127

163

197

5.9

77

98

118

9.8

129

166

200

5.8

77

99

120

9.7

132

169

203

5.7

78

100

121

9.6

134

172

207

5.6

79

101

122

9.5

136

175

211

5.5

80

102

123

9.4

139

178

215

5.4

81

104

125

9.3

141

182

219

5.3

82

105

126

9.2

144

185

223

5.2

82

106

127

9.1

147

189

227

5.1

83

107

129

9

150

193

232

5

84

108

130

8.9

153

197

237

4.9

85

109

132

8.8

156

201

242

4.8

86

111

133

8.7

160

205

247

4.7

87

112

135

8.6

163

209

252

4.6

88

113

136

8.5

167

214

258

4.5

89

115

138

8.4

170

219

264

4.4

90

116

140

8.3

174

224

270

4.3

91

117

141

8.2

179

229

276

4.2

93

119

143

8.1

183

235

283

4.1

94

120

145

8

187

241

290

4

95

122

147

7.9

192

247

297

3.9

96

123

149

7.8

197

253

305

3.8

97

125

151

7.7

203

260

313

3.7

99

127

153

7.6

208

268

322

3.6

100

128

155

7.5

214

275

331

3.5

101

130

157

7.4

221

283

341

3.4

103

132

159

7.3

227

292

351

3.3

104

134

161

7.2

234

301

362

3.2

106

136

163

7.1

242

311

374

3.1

107

138

166

7

250

321

387

3

109

140

168

6.9

259

332

400

2.9

110

142

171

6.8

268

344

414

2.8

112

144

173

6.7

278

357

430

2.7 2.6

114

146

176

6.6

288

370

446

115

148

178

6.5

300

385

464

2.5

117

151

181

6.4

312

401

483

2.4

119

153

184

6.3

326

419

504

2.3

121

155

187

6.2

341

438

527

2.2

123

158

190

6.1

357

459

552

2.1

125

161

193

6

375

482

580

2

*The design factors were calculated using Case A from the API 9B formula with 4% sheave loss. They do not include shock loads or acceleration stresses.

IADC Drilling Manual

Copyright © 2015

WR–26

WIRE ROPE Table WR-17: Design factors 1 3/8 in. extra-extra improved plow rotary drill line, 212,000 lb nominal strength*

Weight Indicator Reading (1000's Lbs.) 10 Lines

12 Lines

14 Lines

Weight Indicator Reading (1000's Lbs.) Design Factor

10 Lines

12 Lines

14 Lines

Design Factor

174

201

226

9.9

291

337

380

5.9

175

203

229

9.8

296

343

386

5.8

177

205

231

9.7

302

349

393

5.7

179

207

233

9.6

307

355

400

5.6

181

209

236

9.5

313

362

407

5.5

183

212

238

9.4

318

368

415

5.4

185

214

241

9.3

324

375

423

5.3

187

216

244

9.2

331

383

431

5.2

189

219

246

9.1

337

390

439

5.1

191

221

249

9

344

398

448

5

193

224

252

8.9

351

406

457

4.9

195

226

255

8.8

358

414

467

4.8

198

229

258

8.7

366

423

477

4.7

200

231

261

8.6

374

432

487

4.6

202

234

264

8.5

382

442

498

4.5

205

237

267

8.4

391

452

509

4.4

207

240

270

8.3

400

463

521

4.3

210

243

273

8.2

409

474

534

4.2

212

246

277

8.1

419

485

547

4.1

215

249

280

8

430

497

560

4

218

252

284

7.9

441

510

575

3.9

220

255

287

7.8

452

524

590

3.8

223

258

291

7.7

465

538

606

3.7

226

262

295

7.6

478

553

622

3.6

229

265

299

7.5

491

568

640

3.5

232

269

303

7.4

506

585

659

3.4 3.3

236

273

307

7.3

521

603

679

239

276

311

7.2

537

622

700

3.2

242

280

316

7.1

555

642

723

3.1

246

284

320

7

573

663

747

3

249

288

325

6.9

593

686

773

2.9

253

293

330

6.8

614

711

800

2.8

257

297

334

6.7

637

737

830

2.7

261

301

340

6.6

661

765

862

2.6

265

306

345

6.5

688

796

896

2.5

269

311

350

6.4

716

829

934

2.4

273

316

356

6.3

748

865

974

2.3

277

321

361

6.2

782

904

1019

2.2

282

326

367

6.1

819

947

1067

2.1

287

332

373

6

860

995

1120

2

*The design factors were calculated using Case A from the API 9B formula with 4% sheave loss. They do not include shock loads or acceleration stresses.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–27

Table WR-18: Design Factors 1 3/8 in. extra-extra improved plow rotary drill line, 212,000 lb nominal strength* Weight Indicator Reading (1000's Lbs.) 12 Lines

14 Lines

16 Lines

Weight Indicator Reading (1000's Lbs.) Design Factor

12 Lines

14 Lines

16 Lines

Design Factor

277

312

344

9.9

464

523

576

5.9

280

315

347

9.8

472

532

586

5.8

282

318

351

9.7

481

541

597

5.7

285

322

354

9.6

489

551

607

5.6

288

325

358

9.5

498

561

618

5.5

292

328

362

9.4

507

572

630

5.4

295

332

366

9.3

517

582

642

5.3

298

335

370

9.2

527

594

654

5.2

301

339

374

9.1

537

605

667

5.1

304

343

378

9

548

617

680

5

308

347

382

8.9

559

630

694

4.9

311

351

387

8.8

571

643

709

4.8

315

355

391

8.7

583

657

724

4.7

319

359

395

8.6

596

671

739

4.6

322

363

400

8.5

609

686

756

4.5

326

367

405

8.4

623

701

773

4.4

330

372

410

8.3

637

718

791

4.3

334

376

415

8.2

652

735

810

4.2

338

381

420

8.1

668

753

830

4.1

343

386

425

8

685

772

850

4

347

391

431

7.9

703

791

872

3.9

351

396

436

7.8

721

812

895

3.8

356

401

442

7.7

741

834

919

3.7

361

406

448

7.6

761

857

945

3.6

365

412

453

7.5

783

882

972

3.5

370

417

460

7.4

806

908

1000

3.4 3.3

375

423

466

7.3

830

935

1031

381

429

472

7.2

856

965

1063

3.2

386

435

479

7.1

884

996

1097

3.1

391

441

486

7

913

1029

1134

3

397

447

493

6.9

945

1064

1173

2.9

403

454

500

6.8

979

1102

1215

2.8

409

461

508

6.7

1015

1143

1260

2.7

415

468

515

6.6

1054

1187

1308

2.6

422

475

523

6.5

1096

1235

1360

2.5

428

482

531

6.4

1142

1286

1417

2.4

435

490

540

6.3

1191

1342

1479

2.3

442

498

549

6.2

1246

1403

1546

2.2

449

506

558

6.1

1305

1470

1620

2.1

457

514

567

6

1370

1543

1701

2

*The design factors were calculated using Case A from the API 9B formula with 4% sheave loss. They do not include shock loads or acceleration stresses.

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WR–28

WIRE ROPE

EXAMPLE 2

Drilling ton-miles Situation: Drilling continues from a depth of 11,000 ft to 12,000 ft. Drill Pipe = 4 1/2 in. (l6.6 lb/ft) Drill collars = ten, 7 1/4 in. (l19.2 lb/ft) Traveling block assembly weight = 27,000 lb Drilling fluid = mud Top Drive Solution: Ton-Miles for drilling from one depth to another when using a top drive are equal to the difference in round trip ton-miles for the two depths. 1) Determine ton-miles for a round trip where drilling stopped: Locate depth of 12,000 ft Read under 40,000 lb column Ton-Miles = 384 T-M

40.5 lb/ft = 2.44 16.6 lb/ft 16.6 lb/ft 2) Determine ton-miles for making a round trip with pipe: Locate depth of 3,600 ft Read under 20,000 lb column (No drill collars are used, therefore, the Total Weight Factor is equal to the traveling block assembly weight only.) 3) Determine ton-miles for making a round trip with casing: Multiply by the weight ratio:

2.44×46 = 122 T-M

Round trip ton-miles for casing = 112 T-M. 4) Determine ton-miles for setting casing: Divide by 2, since the casing is only set down and not pulled out.

2) Determine ton-miles for a round trip where drilling started: Locate depth of 11,000 ft Read under 40,000 lb column Ton-Miles = 337 T-M

112 divided by 2 = 56 T-M Ton-miles for setting casing = 56 T-M. EXAMPLE 4

3) Calculate difference in round trip ton-miles:

Ton-miles for a short trip Situation: Having drilled to 13,000 ft, a short trip is made back to 9,000 ft to condition the hole.

384 T-M –337 T-M 47 T-M Ton-Miles for Drilling with a top drive from 11,000 ft to 12,000 ft = 47 T-M. * The ton-miles for drilling when using a convential drilling rig without a top drive are equal to the difference in the round trip ton miles for the two depths multiplied by three. (47 T-M * 3 = 141 T-M)

Drill Pipe = 4 1/2 in. (16.6 lb/ft) Drill Collars = Twenty, 7 3/4 in. (138 lb/ft) Traveling Block Assembly Weight = 20,000 lb Drilling Fluid = Mud Solution: The ton-miles of work done in making a short trip is equal to the round trip ton-miles at the deeper depth minus the round trip ton-miles at the shallower depth. 1) Determine ton-miles for a round trip at 13,000 ft: Locate depth of 13,000 ft Read under 50,000 lb column Round trip ton-miles at 9,000 ft = 483 T-M

EXAMPLE 3 Ton-miles for setting casing Situation: Setting 10 3/4 in. (40.5 lb/ft) casing from surface to 3,600 ft Traveling Block Assembly Weight = 20,000 lb Solution: The ton-miles of work done in setting casing would be one-half the ton-miles done in making a round trip if the weight of the casing were the same as the weight of the drill pipe. 1) Determine the ratio of casing weight to drill pipe weight:

IADC Drilling Manual

2) Determine ton-miles for a round trip at 9,000 ft: Locate depth of 9,000 ft Read under 50,000 lb column Round trip ton-miles at 9,000 ft = 284 T-M 3) Determine ton-miles for the short trip 483 T-M −284 T-M 199 T-M Ton-miles for the short trip = 199 T-M

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EXAMPLE 5 Ton-miles for round trip of mixed drill string Situation: Having drilled to 13,000 ft with the drill string shown on the left, a round trip is to be made: Drilling Fluid = Mud Traveling Block Assembly Weight = 27,000 lb Solution: 1) Weight factor due to collars

=

23,000 lb

2) Total weight factor = 23,000 lb + 27,000 lb 50,000 lb 3) Ton-miles for round trips: 4 1/2 in.−13,000 ft = 483 T-M 5 in.− 9,000 ft = + 303 T-M 786 T-M 4 1/2 in.− 9,000 ft

= − 284 T-M 502 T-M

Ton-miles for a round trip with the mixed drill string = 502 T-M.

Total excess weight = (25.4) × (900 ft)

=

22,860 lb

Buoyed excess weight = (22,860) × (.85)

=

19,431 lb

1/2 Buoyed excess weight = (19,431) % (2)

=

9,716 lb

Weight factor due to heavyweight pipe

=

9,716 lb

Traveling block assembly weight = Weight factor due to collars =

30,000 lb 30,700 lb

3) Determine total weight factor:

Weight factor due to heavyweight pipe Total weight factor

=

9,716 lb

=

70,416 lb

4) Determine ton-miles per round trip: Locate depth of 12,000 ft. Read under 70,000 lb column Round trip ton-miles = 520 T-M C. Ton-miles per foot cut

EXAMPLE 6 Ton-miles for round trip with heavy-wall drill pipe Situation: Having drilled to 12,000 ft with the drill string shown on the left, a round trip is to be made. Drilling Fluid = mud Traveling Block Assembly Weight = 30,000 lb Solution: Instead of trying to calculate the heavy-weight pipe as in a mixed drill string, treat it as additional drill collars. Use the drill collar window on the back of the Ton-Mile Indicator which is closest to the heavy weight pipe weight or do the calculations by hand. 1) Determine weight factor due to collars: On Table WR-11 locate proper drill collar number and read weight due to collars under appropriate column. 2) Determine weight factor due to heavy-wall drill pipe: Figure heavyweight pipe like drill collars. On Table WR-11 locate proper heavy-weight pipe number and read weight due to heavyweight pipe from the window with the closest drill collar weight is 46.7 lb/ft. An accurate value for Weight Factor due to heavy-weight pipe can also be figured longhand as follows (more accurate): Excess weight per foot = 42.0−16.6

WR–29

=

25.4

IADC Drilling Manual

The purpose of calculating the amount of work done by the drilling line is to give an accurate method for determining when and how much drilling line to slip through and cut off. The objective of spreading the rope wear along the length of the line can be accomplished best by cutting lengths proportional to the ton-miles of work accumulated. All that is necessary to maintain a consistent number of ton-miles per foot of rope cut. For a given rope size, any particular rig can get only so many ton-miles of service. The key to a successful cutoff procedure is to spread these ton-miles uniformly by using the optimum ton-mile per foot cut goal. A rig which has been able to get about 66,000 T-M out of a 1 3/8 in.×5,000 ft drilling line may have a string-up of 1,700 ft for 10 parts. The remaining 3,300 ft available to be cut off should be cut at a rate of one foot for every 20.0 ton-miles. (66,000 T-M %3,300 ft = 20.0 T-M/ft) The ton-mile goal would be 20.0. The ton-mile goal for any rig with good past performance records can be calculated in the same manner. If the rig is new, or if the records are unavailable, a ton-mile goal can be selected from Table WR-20. You will note that only the drilling line size and the drum diameter are needed to determine a ton-mile goal. These are by far the most important factors that influence ton-mile service on a drilling rig.

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WIRE ROPE

D. Ton-mile calculations—drilling ton-miles for top drive (drilling with stands) Ton-mile calculations for other operations tend to be unaffected by the addition of the top drive with the exception of the additional traveling equipment weight. Definition of terms: WDS = Buoyant weight of drill string (drill pipe and BHA) M

= Weight of traveling equipment

LS

= Length of a stand Drilling Operation Cycle: 1. Drill down length of stand (LS) 2. Raise stand and ream back down full length 3. Set slips and break out at pipe handler 4. Raise traveling equipment: pick up next stand and make-up 5. Pick-up off slips and begin again Ton-Miles Generated Per Cycle Segment: 1. ((WDS + M) × LS)/(2000 × 5280) 2. (2 × (WDS + M) × LS)/(2000 × 5280) 3. N/A 4. (M × LS)/(2000 × 5280) 5. N/A If one cares to combine steps 1 through 5, the following will apply: Ton-Miles Per Stand Drilled = (LS × (3 WDS + 4 M)) / (2000 × 5280)

Table WR-20 Ton-mile per foot cut goal for rigs having no past performance records Drum diameter (in.) 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36

Rope diameter (in.) 1

1 1/8

6.0 6.0 7.0 7.0 7.0 8.0 8.0 8.0 9.0 9.0

9.0 9.0 9.0 10.0 10.0 10.0 11.0 11.0 11.0 12.0 12.0 12.0 13.0

1 1/4

13.0 13.0 14.0 14.0 15.0 15.0 15.0 16.0 16.0 17.0 17.0 18.0

1 /8

1 1/2

1 5/8

17.0 17.0 17.0 18.0 18.0 18.0 19.0 19.0 20.0 20.0 21.0 21.0 22.0

24.0 25.0 25.0

28.0

B. Suggestions for cut-off practice

Cut-off program A. Cut-off program Assuming that 1 3/8 in. drilling line is used on a NATIONAL 130 (30 in. drum) rig with no past performance records, Table WR-20 gives a suggested ton-mile goal of 19.0. Table WR-21 is the UNION WIRE ROPE Cut-Off Program for a 19.0 ton-mile goal. Other programs are available for the specific goal required for your rig. You will note the program is summarized by the statement: Length to Cut = T-M Since Last Cut ÷ 19.0 So long as the maximum ton-mile accumulation shown on the program is not exceeded, a cut may be made whenever it is convenient. It is only necessary to total the tonmiles accumulated since the last cut and divide by 19.0 to determine what length to cut. This way the ton-miles per foot cut will always be exactly 19.0 and the wear on the drilling line will be uniformly spread along its length. For convenience, the calculations have been made for a number of ton-mile accumulations and are presented in tabular form on the program.

IADC Drilling Manual

Whatever program is being used, it should be followed throughout the life of one entire drilling line. If no long cuts are required and it is believed that more service can be had from a line, the goal can be raised one ton-mile per foot cut. This procedure should be followed until the optimum goal is found. Avoid accumulating more ton-miles between cuts than the maximum shown on the program for your rig even on the first cut of a new line. It is best not to run up to the maximum permitted ton-miles each time before making a cut, as some problem on the rig could prevent a cut being made at the proper time and lead to a ton-mile overrun. A better approach is to bounce around on your program, cutting with a low ton-mile accumulation sometimes and alternating with medium or higher ton-mile accumulations. This practice does not waste rope because you are always cutting lengths in proportion to the work accumulated. Accurate measurement of the length to cut is very important. A steel tape should be used when making this measurement. When stringing back from 12 to 10 lines or from 10 to 8 lines, make a cut of the appropriate length based upon

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Table WR-21 (example only) UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line Goal is 19.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 19.0 T-M Since Last Cut 1150 1200 1250 1300 1350 1400 1450 1500 1550 1600 1650 1700 1750 1800 1850 1900

Length To Cut 61 63 66 68 71 74 76 79 82 84 87 89 92 95 97 100

T-M Since Last Cut 1950 2000 2050 2100 2150 2200 2250 2300

Length To Cut 103 105 108 111 113 116 118 121

the ton-mile accumulation at that time. This procedure will shift the critical wear points on the rope following heavy operations such as setting casing. Keep your wire rope History Sheets current, accurate and complete. Calculate ton-miles for drilling after each round trip. Failure to record drilling ton-miles is probably the most common mistake made in cut-off practice. The best cut-off program is the one with the most consistent ton-mile per foot cut values. By staying as close as possible to the ton-mile goal you will avoid long cuts and maintain the safest most economical use of your rotary drilling line.

UNION WIRE ROPE cut-off program for 1 in. rotary drilling line Goal is 6.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 6.0 T-M Since Last Cut 25 50 75 100

Length To Cut 4 8 13 17

T-M Since Last Cut 425 450 475 500

Length To Cut 71 75 79 83

125 150 175 200

21 25 29 33

525 550 575 600

88 92 96 100

225 250 275 300

38 42 46 50

625 650 675 700

104 108 113 117

325 350 375 400

54 58 63 67

725

121

1. Do not accumulate more than 725 ton-miles between Cuts—even on the first cut of a new line. 2. So long as less than 725 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 6.0). 3. This program is based upon a goal of 6.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

Daily visual inspection of the drilling line should be made for broken wires and any other rope damage. It must be remembered that in all cases visual inspection of the wire rope by the drilling contractor must take precedence over any predetermined calculations.

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WR–31

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WR–32

WIRE ROPE

UNION WIRE ROPE cut-off program for 1 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 in. rotary drilling line

Goal is 7.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 7.0

Goal is 8.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 8.0

T-M Since Last Cut 225 250 275 300

Length To Cut 32 36 39 43

T-M Since Last Cut 625 650 675 700

Length To Cut 89 93 96 100

T-M Since Last Cut 325 350 375 400

Length To Cut 41 44 47 50

T-M Since Last Cut 725 750 775 800

Length To Cut 91 94 97 100

325 350 375 400

46 50 54 57

725 750 775 800

104 107 111 114

425 450 475 500

53 56 59 63

825 850 875 900

103 106 109 113

425 450 475 500

61 64 68 71

825 850

118 121

525 550 575 600

66 69 72 75

925 950

116 119

525 550 575 600

75 79 82 86

625 650 675 700

78 81 84 88

1. Do not accumulate more than 850 ton-miles between Cuts—even on the first cut of a new line.

1. Do not accumulate more than 950 ton-miles between Cuts—even on the first cut of a new line.

2. So long as less than 850 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot” is constant (length to cut = T-M since last cut ÷ 7.0).

2. So long as less than 950 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 8.0).

3. This program is based upon a goal of 7.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 8.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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WR–33

UNION WIRE ROPE cut-off program for 1 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 1/8 in. rotary drilling line

Goal is 9.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 9.0

Goal is 9.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 9.0

T-M Since Last Cut 425 450 475 500

Length To Cut 47 50 53 56

T-M Since Last Cut 825 850 875 900

525 550 575 600

58 61 64 67

625 650 675 700

69 72 75 78

725 750 775 800

81 83 86 89

Length To Cut 92 94 97 100

T-M Since Last Cut 525 550 575 600

Length To Cut 58 61 65 67

T-M Since Last Cut 925 950 975 1000

Length To Cut 103 106 108 111

925 950 975 1000

103 106 108 111

625 650 675 700

69 72 75 78

1025 1050 1075 1100

114 117 119 122

1025 1050 1075 1100

114 117 119 122

725 750 775 800

81 83 86 89

825 850 875 900

92 94 97 100

1. Do not accumulate more than 1100 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 1100 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 1100 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 9.0).

2. So long as less than 1100 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 9.0).

3. This program is based upon a goal of 9.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 9.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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WR–34

WIRE ROPE

UNION WIRE ROPE cut-off program for 1 1/8 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 1/8 in. rotary drilling line

Goal is 10.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷10.0

Goal is 11.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 11.0

T-M Since Last Cut 625 650 675 700

Length To Cut 63 65 68 70

T-M Since Last Cut 1025 1050 1075 1100

Length To Cut 103 105 108 110

T-M Since Last Cut 50 100 150 200

Length To Cut 5 9 14 18

T-M Since Last Cut 850 900 950 1000

Length To Cut 77 82 86 91

725 750 775 800

73 75 78 80

1125 1150 1175 1200

113 115 118 120

250 300 350 400

23 27 32 36

1050 1100 1150 1200

95 100 105 109

825 850 875 900

83 85 88 90

450 500 550 600

41 45 50 55

1250 1300

114 118

925 950 975 1000

93 95 98 100

650 700 750 800

59 64 68 73

1. Do not accumulate more than 1200 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 1300 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 1200 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 10.0).

2. So long as less than 1300 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 11.0).

3. This program is based upon a goal of 10.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 11.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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WR–35

UNION WIRE ROPE cut-off program for 1 1/8 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

Goal is 12.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 12.0

Goal is 13.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 13.0

T-M Since Last Cut 100 150 200 250

Length To Cut 8 13 17 21

T-M Since Last Cut 900 950 1000 1050

Length To Cut 75 79 83 88

T-M Since Last Cut 200 250 300 350

Length To Cut 15 19 23 27

T-M Since Last Cut 1000 1050 1100 1150

Length To Cut 77 81 85 88

300 350 400 450

25 29 33 38

1100 1150 1200 1250

92 96 100 104

400 450 500 550

31 35 38 42

1200 1250 1300 1350

92 96 100 104

500 550 600 650

42 46 50 54

1300 1350 1400 1450

108 113 117 121

600 650 700 750

46 50 54 58

1400 1450 1500 1550

108 112 115 119

700 750 800 850

58 63 67 71

800 850 900 950

62 65 69 73

1. Do not accumulate more than 1450 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 1550 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 1450 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 12.0).

2. So long as less than 1550 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 13.0).

3. This program is based upon a goal of 12.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 13.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

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WR–36

WIRE ROPE

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

Goal is 12.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 12.0

Goal is 13.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 13.0

T-M Since Last Cut 250 300 350 400

Length To Cut 21 25 29 33

T-M Since Last Cut 1050 1100 1150 1200

Length To Cut 88 92 96 100

T-M Since Last Cut 350 400 450 500

Length To Cut 27 31 35 38

T-M Since Last Cut 1150 1200 1250 1300

Length To Cut 88 92 96 100

450 500 550 600

38 42 46 50

1250 1300 1350 1400

104 108 113 117

550 600 650 700

42 46 50 54

1350 1400 1450 1500

104 108 112 115

650 700 750 800

54 58 63 67

1450

121

750 800 850 900

58 62 65 69

1550

119

850 900 950 1000

71 75 79 83

950 1000 1050 1100

73 77 81 85

1. Do not accumulate more than 1450 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 1550 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 1450 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 12.0).

2. So long as less than 1550 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 13.0).

3. This program is based upon a goal of 12.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 13.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–37

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

Goal is 14.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 14.0

Goal is 15.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 15.0

T-M Since Last Cut 450 500 550 600

Length To Cut 32 36 39 43

T-M Since Last Cut 1250 1300 1350 1400

Length To Cut 89 93 96 100

T-M Since Last Cut 550 600 650 700

Length To Cut 37 40 43 47

T-M Since Last Cut 1350 1400 1450 1500

Length To Cut 90 93 97 100

650 700 750 800

46 50 54 57

1450 1500 1550 1600

104 107 111 114

750 800 850 900

50 53 57 60

1550 1600 1650 1700

103 107 110 113

850 900 950 1000

61 64 68 71

1650 1700

118 121

950 1000 1050 1100

63 67 70 73

1750 1800

117 120

1050 1100 1150 1200

75 79 82 86

1150 1200 1250 1300

77 80 83 87

1. Do not accumulate more than 1700 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 1800 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 1700 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 14.0).

2. So long as less than 1800 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 15.0).

3. This program is based upon a goal of 14.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 15.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WR–38

WIRE ROPE

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

Goal is 16.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 16.0

Goal is 17.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 17.0

T-M Since Last Cut 650 700 750 800

Length To Cut 41 44 47 50

T-M Since Last Cut 1450 1500 1550 1600

Length To Cut 91 94 97 100

T-M Since Last Cut 750 800 850 900

Length To Cut 44 47 50 53

T-M Since Last Cut 1550 1600 1650 1700

Length To Cut 91 94 97 100

850 900 950 1000

53 56 59 63

1650 1700 1750 1800

103 106 109 113

950 1000 1050 1100

56 59 62 65

1750 1800 1850 1900

103 106 109 112

1050 1100 1150 1200

66 69 72 75

1850 1900

116 119

1150 1200 1250 1300

68 71 74 76

1950 2000 2050

115 118 121

1250 1300 1350 1400

78 81 84 88

1350 1400 1450 1500

79 82 85 88

1. Do not accumulate more than 1900 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 2050 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 1900 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 16.0).

2. So long as less than 2050 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 17.0).

3. This program is based upon a goal of 16.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 17.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–39

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

Goal is 18.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 18.0

Goal is 17.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 17.0

T-M Since Last Cut 850 900 950 1000

Length To Cut 47 50 53 56

T-M Since Last Cut 1650 1700 1750 1800

Length To Cut 92 94 97 100

T-M Since Last Cut 850 900 950 1000

Length To Cut 50 53 56 59

T-M Since Last Cut 1650 1700 1750 1800

Length To Cut 97 100 103 106

1050 1100 1150 1200

58 61 64 67

1850 1900 1950 2000

103 106 108 111

1050 1100 1150 1200

62 65 68 71

1850 1900 1950 2000

109 112 115 118

1250 1300 1350 1400

69 72 75 78

2050 2100 2150

114 117 119

1250 1300 1350 1400

74 76 79 82

2050

121

1450 1500 1550 1600

81 83 86 89

1450 1500 1550 1600

85 88 91 94

1. Do not accumulate more than 2150 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 2050 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 2150 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is const

2. So long as less than 2050 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 17.0).

3. This program is based upon a goal of 18.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program

IADC Drilling Manual

3. This program is based upon a goal of 17.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

Copyright © 2015

WR–40

WIRE ROPE

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

Goal is 18.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 18.0

Goal is 19.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 19.0

T-M Since Last Cut 1050 1100 1150 1200

Length To Cut 58 61 64 67

T-M Since Last Cut 1850 1900 1950 2000

Length To Cut 103 106 108 111

T-M Since Last Cut 1150 1200 1250 1300

Length To Cut 61 63 66 68

T-M Since Last Cut 1950 2000 2050 2100

Length To Cut 103 105 108 111

1250 1300 1350 1400

69 72 75 78

2050 2100 2150

114 117 119

1350 1400 1450 1500

71 74 76 79

2150 2200 2250 2300

113 116 118 121

1450 1500 1550 1600

81 83 86 89

1550 1600 1650 1700

82 84 87 89

1650 1700 1750 1800

92 94 97 100

1750 1800 1850 1900

92 95 97 100

1. Do not accumulate more than 2150 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 2300 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 2150 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 18.0).

2. So long as less than 2300 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 19.0).

3. This program is based upon a goal of 18.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 19.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–41

UNION WIRE ROPE cut-off program for 1 1/4 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

Goal is 18.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 18.0

Goal is 21.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 21.0

T-M Since Last Cut 1250 1300 1350 1400

Length To Cut 63 65 68 70

T-M Since Last Cut 2050 2100 2150 2200

Length To Cut 103 105 108 110

T-M Since Last Cut 1350 1400 1450 1500

Length To Cut 64 67 69 71

T-M Since Last Cut 2150 2200 2250 2300

Length To Cut 102 105 107 110

1450 1500 1550 1600

73 75 78 80

2250 2300 2350 2400

113 115 118 120

1550 1600 1650 1700

74 76 79 81

2350 2400 2450 2500

112 114 117 119

1650 1700 1750 1800

83 85 88 90

1750 1800 1850 1900

83 86 88 90

2550

121

1850 1900 1950 2000

93 95 98 100

1950 2000 2050 2100

93 95 98 100

1. Do not accumulate more than 2400 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 2550 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 2400 ton-miles have been accumu- lated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 20.0).

2. So long as less than 2550 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 21.0).

3. This program is based upon a goal of 20.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 21.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WR–42

WIRE ROPE

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

Goal is 22.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 22.0

Goal is 23.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 23.0

T-M Since Last Cut 100 200 300 400

Length To Cut 5 9 14 18

T-M Since Last Cut 1700 1800 1900 2000

Length To Cut 77 81 86 91

T-M Since Last Cut 100 200 300 400

Length To Cut 4 9 13 17

T-M Since Last Cut 1700 1800 1900 2000

Length To Cut 74 78 83 87

500 600 700 800

23 27 32 36

2100 2200 2300 2400

96 100 105 109

500 600 700 800

22 26 30 35

2100 2200 2300 2400

91 96 100 104

900 1000 1100 1200

41 45 50 55

2500 2600

114 118

900 1000 1100 1200

39 43 48 52

2500 2600 2700 2800

109 113 117 122

1300 1400 1500 1600

59 64 68 72

1300 1400 1500 1600

56 61 65 70

1. Do not accumulate more than 2600 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 2800 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 2600 ton-miles have been accumu- lated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 22.0).

2. So long as less than 2800 ton-miles have been accumu- lated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 23.0).

3. This program is based upon a goal of 22.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 23.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–43

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 1/2 in. rotary drilling line

Goal is 24.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 24.0

Goal is 23.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 23.0

T-M Since Last Cut 100 200 300 400

Length To Cut 4 8 13 17

T-M Since Last Cut 1700 1800 1900 2000

Length To Cut 71 75 79 83

T-M Since Last Cut 300 400 500 600

Length To Cut 13 17 22 26

T-M Since Last Cut 1900 2000 2100 2200

Length To Cut 83 87 91 96

500 600 700 800

21 25 29 33

2100 2200 2300 2400

88 92 96 100

700 800 900 1000

30 35 39 43

2300 2400 2500 2600

100 104 109 113

900 1000 1100 1200

38 42 46 50

2500 2600 2700 2800

104 108 113 117

1100 1200 1300 1400

48 52 56 61

2700 2800

117 122

1300 1400 1500 1600

54 58 63 67

2900

121

1500 1600 1700 1800

65 70 74 78

1. Do not accumulate more than 2900 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 2800 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 2900 ton-miles have been accumu lated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 24.0).

2. So long as less than 2800 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 23.0).

3. This program is based upon a goal of 24.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 23.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WR–44

WIRE ROPE

UNION WIRE ROPE cut-off program for 1 1/2 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

Goal is 24.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 24.0

Goal is 25.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 25.0

T-M Since Last Cut 500 600 700 800

Length To Cut 21 25 29 33

T-M Since Last Cut 2100 2200 2300 2400

Length To Cut 88 92 96 100

T-M Since Last Cut 600 700 800 900

Length To Cut 24 28 32 36

T-M Since Last Cut 2200 2300 2400 2500

Length To Cut 88 92 96 100

900 1000 1100 1200

38 42 46 50

2500 2600 2700 2800

104 108 113 117

1000 1100 1200 1300

40 44 48 52

2600 2700 2800 2900

104 108 112 116

1300 1400 1500 1600

54 58 63 67

2900

121

1400 1500 1600 1700

56 60 64 68

3000

120

1700 1800 1900 2000

71 75 79 83

1800 1900 2000 2100

72 76 80 84

1. Do not accumulate more than 2900 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 3000 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 2900 ton-miles have been accumu- lated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 24.0).

2. So long as less than 3000 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 25.0).

3. This program is based upon a goal of 24.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 25.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–45

UNION WIRE ROPE cut-off program for 1 3/8 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 1/2 in. rotary drilling line

Goal is 26.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 26.0

Goal is 27.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 27.0

T-M Since Last Cut 700 800 900 1000

Length To Cut 27 31 35 39

T-M Since Last Cut 2300 2400 2500 2600

Length To Cut 89 92 96 100

T-M Since Last Cut 800 900 1000 1100

Length To Cut 30 33 37 41

T-M Since Last Cut 2400 2500 2600 2700

Length To Cut 89 93 96 100

1100 1200 1300 1400

42 46 50 54

2700 2800 2900 3000

104 108 112 115

1200 1300 1400 1500

44 48 52 56

2800 2900 3000 3100

104 107 111 115

1500 1600 1700 1800

58 62 65 69

3100

119

1600 1700 1800 1900

59 63 67 70

3200

119

1900 2000 2100 2200

73 77 81 85

2000 2100 2200 2300

74 78 82 85

1. Do not accumulate more than 3100 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 3200 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 3100 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 26.0).

2. So long as less than 3200 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 27.0).

3. This program is based upon a goal of 26.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 27.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WR–46

WIRE ROPE

UNION WIRE ROPE cut-off program for 1 1/2 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 5/8 in. rotary drilling line

Goal is 28.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 28.0

Goal is 28.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 28.0

T-M Since Last Cut 900 1000 1100 1200

Length To Cut 32 36 39 43

T-M Since Last Cut 2500 2600 2700 2800

Length To Cut 89 93 96 100

T-M Since Last Cut 900 1000 1100 1200

Length To Cut 32 36 39 43

T-M Since Last Cut 2500 2600 2700 2800

Length To Cut 89 93 96 100

1300 1400 1500 1600

46 50 54 57

2900 3000 3100 3200

104 107 111 114

1300 1400 1500 1600

46 50 54 57

2900 3000 3100 3200

104 107 111 114

1700 1800 1900 2000

61 64 68 71

3300 3400

118 121

1700 1800 1900 2000

61 64 68 71

3300 3400

118 121

2100 2200 2300 2400

75 79 82 86

2100 2200 2300 2400

75 79 82 86

1. Do not accumulate more than 3400 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 3400 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 3400 ton-miles have been accumu- lated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 28.0).

2. So long as less than 3400 ton-miles have been accumu- lated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 28.0).

3. This program is based upon a goal of 28.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 28.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–47

UNION WIRE ROPE cut-off program for 1 3/4 in. rotary drilling line

UNION WIRE ROPE cut-off program for 1 3/4 in. rotary drilling line

Goal is 31.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 31.0

Goal is 32.0 ton-miles per foot cut Length to cut = ton-miles since last cut ÷ 32.0

T-M Since Last Cut 900 1000 1100 1200

Length To Cut 29 32 35 39

T-M Since Last Cut 2500 2600 2700 2800

Length To Cut 81 84 87 90

T-M Since Last Cut 900 1000 1100 1200

Length To Cut 28 31 34 38

T-M Since Last Cut 2500 2600 2700 2800

Length To Cut 78 81 84 88

1300 1400 1500 1600

42 45 48 52

2900 3000 3100 3200

94 97 100 103

1300 1400 1500 1600

41 44 47 50

2900 3000 3100 3200

91 94 97 100

1700 1800 1900 2000

55 58 61 65

3300 3400 3500 3600

106 110 113 116

1700 1800 1900 2000

53 56 59 63

3300 3400 3500 3600

103 106 109 113

2100 2200 2300 2400

68 71 74 77

3700

119

2100 2200 2300 2400

66 69 72 75

3700 3800

116 119

1. Do not accumulate more than 3700 ton-miles between cuts—even on the first cut of a new line.

1. Do not accumulate more than 3800 ton-miles between cuts—even on the first cut of a new line.

2. So long as less than 3700 ton-miles have been accumulated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 31.0).

2. So long as less than 3800 ton-miles have been accumu- lated, a cut may be made anytime it is convenient. To determine the length to cut, refer to the above table or calculate so that your “ton-miles per foot cut” is constant (length to cut = T-M since last cut ÷ 32.0).

3. This program is based upon a goal of 31.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

3. This program is based upon a goal of 32.0. Any attempt to improve rope service by increasing the ton-mile goal should not be made until one entire drilling line (requiring no long cuts) has been used following this particular program.

IADC Drilling Manual

Copyright © 2015

WR–48

WIRE ROPE

A. Design Factor Design factor is defined as the ratio of nominal wire line rope breaking strength to the wire rope tension. The maximum rope tension occurs in the fast line or “lead line” because of friction losses due to rope stiffness and bearing inefficiencies throughout the system. Consequently, the lead line tension is greater than the weight of the load divided by the number of parts of line. To calculate the design factor, it is necessary to compute the lead line tension using the following equations and table of lead line constants. Design Factor

=

Nominal Rope Strength Lead Line Tension

Lead Line Tension =

Weight of Load × Constant



No. of parts of lineC

Lead Line Tension = Lead Line Tension = Lead Line Tension = Design Factor

Weight of Load × Constant 304,000 lb × .1224 37,210 lb

=

Nominal Rope Strength Lead Line Tension

Lead Line Tension =

Weight of Load × Constant



Design Factor

=

167,000 lb ÷ 37,210 lb

Design Factor

=

4.5

For convenience, the design factors have been calculated for various sizes and grades of drilling line as shown in Table WR-22. A similar table is available for your specific requirements.

onstant

Table WR-22: Lead line constants. Figure WR-17: 10-part string-up.

Independent wire rope core Nominal diameter

Improved plow steel

Extra improved plow steel

Table WR-23: Nominal rope strength.

For example, if the weight indicator reads 304,000 lb with 10 parts of 1 3/8 in. improved plow drilling line, the design factor may be calculated as follows:

API-Recommended Practice 9B and most wire rope manufacturers suggest a minimum design factor of 3.0 for drilling and tripping. If heavier loads are used so that the design factor drops below 3.0, the ton-mile service falls off sharply. Below a design factor of about 2.0, wire rope is permanently and irreversibly damaged. Consequently, 3.0 would seem to be a realistic minimum for safe operation, giving some margin for stuck pipe and similar emergencies. Rigs running with loads so light that their design factor is above 7.0 for extended periods of time will not be able to get expected ton-mile service. Laboratory tests and actual field experience confirm that with light loads, the ton-miles add up so slowly that the wire rope will wear out in fatigue due to the higher number of bending cycles required to accumulate each ton-mile. These high design factors are especially common on workover rigs. When this is the case, it is a good idea to make cuts more frequently than normal, perhaps every few round trips. Another problem is that a high design factor means that too many parts of line are strung. An excessive number of parts of string-up puts extra rope on the drum where crossover and wear take their toll on the life of the rope. The excessive length in the string-up takes more cuts to work through the

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

reeving system and consequently any section of rope is in the system longer than necessary before it is finally cut off. Following is an illustrated example of using the fewest possible parts of string up while maintaining a safe rig operation and reasonable design factors:

A 12-part string-up would be required for setting casing having a total buoyed weight of more than 480,000 lb. B. Design Factor Charts See Tables WR-23 through WR-40.

1 3/8 in. EIP Rotary Line Constant Weight T.B.A. Wt. = 40,000 lb + Drill Collar Excess Wt. = 92,871 lb (30−138 lb/ft) = 132,871 lb. (Total) Maximum Indicated Load 132,871 lb Constant Weight 296,310 lb Drill Pipe Weight 4 1/2 in. (l6.6 lb/ft) (Design Factor = 3.0)

Surface

Maximum Indicated Load 132,871 lb Constant Weight 388,025 lb Drill Pipe Weight 4 1/2 in. (l6.6 lb/ft) (Design Factor = 3.0)

8-Part String-Up

21,000 Feet

429,181 lbs.

10-Part String-Up

T.D. or 27,500 Feet

520,896 lbs. Figure WR-18

IADC Drilling Manual

WR–49

Copyright © 2015

WR–50

WIRE ROPE

Table WR-24 Design factors (example only for this size and grade line) 1 3/8 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb) 8 Lines

10 Lines

12 Lines

Weight indicator reading (1,000s lb) Design Factor

8 Lines

10 Lines

12 Lines

Design Factor

115

138

159

9.9

193

231

267

5.9

116

139

160

9.8

196

235

271

5.8

117

141

162

9.7

199

239

276

5.7

118

142

164

9.6

203

244

281

5.6

120

144

166

9.5

207

248

286

5.5

121

145

167

9.4

211

253

291

5.4

122

147

169

9.3

214

257

297

5.3

124

148

171

9.2

219

262

302

5.2

125

150

173

9.1

223

268

308

5.1

126

152

175

9.0

227

273

315

5.0

128

153

177

8.9

232

278

321

4.9

129

155

179

8.8

237

284

328

4.8

131

157

181

8.7

242

290

335

4.7

132

159

183

8.6

247

297

342

4.6

134

161

185

8.5

253

303

349

4.5

135

162

187

8.4

258

310

357

4.4

137

164

189

8.3

264

317

366

4.3

139

166

192

8.2

271

325

374

4.2

140

168

194

8.1

277

333

384

4.1

142

171

197

8.0

284

341

393

4.0

144

173

199

7.9

291

350

403

3.9

146

175

202

7.8

299

359

414

3.8

148

177

204

7.7

307

369

425

3.7

150

180

207

7.6

316

379

437

3.6

152

182

210

7.5

325

390

449

3.5

154

184

213

7.4

334

401

463

3.4

156

187

215

7.3

344

413

477

3.3

158

189

218

7.2

355

426

491

3.2

160

192

221

7.1

367

440

507

3.1

162

195

225

7.0

379

455

524

3.0

165

198

228

6.9

392

470

542

2.9

167

201

231

6.8

406

487

562

2.8

170

204

235

6.7

421

505

582

2.7

172

207

238

6.6

437

525

605

2.6

175

210

242

6.5

455

546

629

2.5

178

213

246

6.4

474

568

655

2.4

180

217

250

6.3

494

593

684

2.3

183

220

254

6.2

517

620

715

2.2

186

224

258

6.0

541

650

749

2.1

189

227

262

6.1

568

682

786

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–51

Table WR-25 Design factors 1 3/8 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

6 Lines

8 Lines

10 Lines

12 Lines

Design Factor

6 Lines

8 Lines

10 Lines

12 Lines

Design Factor

48

62

74

85

9.9

81

104

124

143

5.9

49

62

75

86

9.8

82

105

126

146

5.8

49

63

76

87

9.7

84

107

129

148

5.7

50

64

76

88

9.6

85

109

131

151

5.6

50

64

77

89

9.5

87

111

133

154

5.5

51

65

78

90

9.4

88

113

136

157

5.4

51

66

79

91

9.3

90

115

138

160

5.3

52

66

80

92

9.2

92

118

141

163

5.2

52

67

81

93

9.1

94

120

144

166

5.1

53

68

82

94

9.0

95

122

147

169

5.0

97 99 102 104 106 108 111 114 116 119

125 127 130 133 136 139 142 146 149 153

150 153 156 159 163 167 171 175 179 183

173 176 180 184 188 192 197 201 206 211

4.9 4.8 4.7 4.6 4.5 4.4 4.3 4.2 4.1 4.0

157 161 165 170 175 180 185 191 197 204

188 193 198 204 210 216 222 229 237 245

217 223 229 235 242 249 256 264 273 282

3.9 3.8 3.7 3.6 3.5 3.4 3.3 3.2 3.1 3.0

54

69

82

95

8.9

54

69

83

96

8.8

55

70

84

97

8.7

55

71

85

98

8.6

56

72

86

99

8.5

57

73

87

101

8.4

57

74

88

102

8.3

58

75

89

103

8.2

59

75

91

104

8.1

60

76

92

106

8.0

60

77

93

107

7.9

61

78

94

108

7.8

62

79

95

110

7.7

63

80

97

111

7.6

64

82

98

113

7.5

64

83

99

114

7.4

65

84

101

116

7.3

66

85

102

117

7.2

67

86

103

119

7.1

68

87

105

121

7.0

122 126 129 133 136 140 145 149 154 159

69

89

106

123

6.9

165

211

253

292

2.9

70

90

108

124

6.8

170

218

262

302

2.8

71

91

110

126

6.7

177

226

272

313

2.7

72

93

111

128

6.6

184

235

282

325

2.6

73

94

113

130

6.5

191

245

293

338

2.5

75

95

115

132

6.4

199

255

306

352

2.4

76

97

116

134

6.3

207

266

319

368

2.3

77

99

118

136

6.2

217

278

333

384

2.2

78

100

120

139

6.1

227

291

349

403

2.1

80

102

122

141

6.0

239

306

367

423

2.0

IADC Drilling Manual

Copyright © 2015

WR–52

WIRE ROPE

Table WR-26 Design factors 1 in. extra improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb) 8 Lines

10 Lines

12 Lines

Weight indicator reading (1,000s lb) Design Factor

8 Lines

10 Lines

12 Lines

Design Factor

71

85

98

9.9

119

143

165

5.9

72

86

99

9.8

121

146

168

5.8

73

87

100

9.7

123

148

171

5.7

73

88

101

9.6

126

151

174

5.6

74

89

102

9.5

128

154

177

5.5

75

90

104

9.4

130

156

180

5.4

76

91

105

9.3

133

159

184

5.3

77

92

106

9.2

135

162

187

5.2

77

93

107

9.1

138

166

191

5.1

78

94

108

9.0

141

169

195

5.0

79

95

109

8.9

80

96

111

8.8

81

97

112

8.7

82

98

113

8.6

83

99

115

8.5

84

101

116

8.4

85

102

117

8.3

86

103

119

8.2

87

104

120

8.1

88

106

122

8.0

144 147 150 153 156 160 164 168 172 176

172 176 180 184 188 192 196 201 206 211

199 203 207 212 216 221 226 232 237 243

4.9 4.8 4.7 4.6 4.5 4.4 4.3 4.2 4.1 4.0

89

107

123

7.9

90

108

125

7.8

91

110

126

7.7

93

111

128

7.6

94

113

130

7.5

95

114

132

7.4

96

116

133

7.3

98

117

135

7.2

99

119

137

7.1

101

121

139

7.0

180 185 190 196 201 207 213 220 227 235

217 222 228 235 241 248 256 264 273 282

250 256 263 270 278 286 295 304 314 325

3.9 3.8 3.7 3.6 3.5 3.4 3.3 3.2 3.1 3.0

102

122

141

6.9

243

291

336

2.9

104

124

143

6.8

251

302

348

2.8

105

126

145

6.7

261

313

361

2.7

107

128

148

6.6

271

325

374

2.6

108

130

150

6.5

282

338

389

2.5

110

132

152

6.4

293

352

406

2.4

112

134

155

6.3

306

367

423

2.3

114

136

157

6.2

320

384

443

2.2

115

138

160

6.1

335

402

464

2.1

117

141

162

6.0

352

422

487

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–53

Table WR-27 Design factors 1 1/8 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

8 Lines

10 Lines

12 Lines

Design Factor

8 Lines

10 Lines

12 Lines

Design Factor

78

93

107

9.9

130

156

180

5.9

78

94

109

9.8

133

159

183

5.8

79

95

110

9.7

135

162

187

5.7

80

96

111

9.6

137

165

190

5.6

81

97

112

9.5

140

168

193

5.5

82

98

113

9.4

142

171

197

5.4

83

99

114

9.3

145

174

201

5.3

84

100

116

9.2

148

178

205

5.2

85

101

117

9.1

151

181

209

5.1

85

103

118

9.0

154

185

213

5.0

86

104

120

8.9

157

188

217

4.9

87

105

121

8.8

160

192

222

4.8

88

106

122

8.7

164

196

226

4.7

89

107

124

8.6

167

201

231

4.6

90

109

125

8.5

171

205

236

4.5

92

110

127

8.4

175

210

242

4.4

93

111

128

8.3

179

215

247

4.3

94

113

130

8.2

183

220

253

4.2

95

114

131

8.1

188

225

260

4.1

96

115

133

8.0

192

231

266

4.0

97

117

135

7.9

197

237

273

3.9

99

118

136

7.8

202

243

280

3.8

100

120

138

7.7

208

250

288

3.7

101

121

140

7.6

214

256

296

3.6

103

123

142

7.5

220

264

304

3.5

104

125

144

7.4

226

272

313

3.4

105

126

146

7.3

233

280

322

3.3

107

128

148

7.2

240

289

333

3.2

108

130

150

7.1

248

298

343

3.1

110

132

152

7.0

256

308

355

3.0

111

134

154

6.9

265

318

367

2.9

113

136

156

6.8

275

330

380

2.8

115

138

159

6.7

285

342

394

2.7

117

140

161

6.6

296

355

409

2.6

118

142

164

6.5

308

369

426

2.5

120

144

166

6.4

321

385

443

2.4

122

147

169

6.3

334

401

463

2.3

124

149

172

6.2

350

420

484

2.2

126

151

174

6.1

366

440

507

2.1

128

154

177

6.0

385

462

532

2.0

IADC Drilling Manual

Copyright © 2015

WR–54

WIRE ROPE Table WR-28 Design factors 1 1/8 in extra improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

6 Lines

8 Lines

10 Lines

12 Lines

Design Factor

6 Lines

8 Lines

10 Lines

12 Lines

Design Factor

70

89

107

124

9.9

117

150

180

207

5.9

70

90

108

125

9.8

119

153

183

211

5.8

71

91

109

126

9.7

121

155

186

215

5.7

72

92

111

128

9.6

123

158

190

219

5.6

73

93

112

129

9.5

126

161

193

223

5.5

73

94

113

130

9.4

128

164

197

227

5.4

74

95

114

132

9.3

130

167

200

231

5.3

75

96

115

133

9.2

133

170

204

235

5.2

76

97

117

135

9.1

135

174

208

240

5.1

77

98

118

136

9.0

138

177

212

245

5.0

78

99

119

138

8.9

141

181

217

250

4.9

78

101

121

139

8.8

144

184

221

255

4.8

79

102

122

141

8.7

147

188

226

260

4.7

80

103

123

142

8.6

150

192

231

266

4.6

81

104

125

144

8.5

154

197

236

272

4.5

82

105

126

146

8.4

157

201

241

278

4.4

83

107

128

147

8.3

161

206

247

285

4.3

84

108

130

149

8.2

164

211

253

291

4.2

85

109

131

151

8.1

168

216

259

299

4.1

86

111

133

153

8.0

173

221

266

306

4.0

87

112

134

155

7.9

177

227

272

314

3.9

89

113

136

157

7.8

182

233

279

322

3.8

90

115

138

159

7.7

187

239

287

331

3.7

91

116

140

161

7.6

192

246

295

340

3.6

92

118

142

163

7.5

197

253

303

350

3.5

93

120

144

165

7.4

203

260

312

360

3.4

95

121

145

168

7.3

209

268

322

371

3.3

96

123

148

170

7.2

216

277

332

383

3.2

97

125

150

172

7.1

223

285

343

395

3.1

99

126

152

175

7.0

230

295

354

408

3.0

100

128

154

177

6.9

238

305

366

422

2.9

102

130

156

180

6.8

247

316

379

437

2.8

103

132

159

183

6.7

256

328

393

453

2.7

105

134

161

185

6.6

266

340

408

471

2.6

106

136

163

188

6.5

276

354

425

490

2.5

108

138

166

191

6.4

288

369

443

510

2.4

110

140

169

194

6.3

300

385

462

532

2.3

111

143

171

197

6.2

314

402

483

556

2.2

113

145

174

201

6.1

329

421

506

583

2.1

115

147

177

204

6.0

345

442

531

612

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–55

Table WR-29 Design factors 1 1/4 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

6 Lines

8 Lines

10 Lines

12 Lines

Design Factor

6 Lines

8 Lines

10 Lines

12 Lines

Design Factor

74

95

115

132

9.9

125

160

192

222

5.9

75

96

116

133

9.8

127

163

196

225

5.8

76

97

117

135

9.7

130

166

199

229

5.7

77

98

118

136

9.6

132

169

202

233

5.6

78

99

119

138

9.5

134

172

206

238

5.5

78

101

121

139

9.4

137

175

210

242

5.4

79

102

122

141

9.3

140

178

214

247

5.3

80

103

123

142

9.2

142

182

218

251

5.2

81

104

125

144

9.1

145

185

222

256

5.1

82

105

126

145

9.0

148

189

227

261

5.0

83

106

127

147

8.9

151

193

231

267

4.9

84

107

129

149

8.8

154

197

236

272

4.8

85

109

130

150

8.7

157

201

241

278

4.7

86

110

132

152

8.6

160

205

247

284

4.6

87

111

133

154

8.5

164

210

252

290

4.5

88

112

135

156

8.4

168

215

258

297

4.4

89

114

137

157

8.3

172

220

264

304

4.3

90

115

138

159

8.2

176

225

270

311

4.2

91

117

140

161

8.1

180

230

277

319

4.1

92

118

142

163

8.0

184

236

283

327

4.0

93

120

144

165

7.9

189

242

291

335

3.9

95

121

145

168

7.8

194

249

298

344

3.8

96

123

147

170

7.7

199

255

306

353

3.7

97

124

149

172

7.6

205

262

315

363

3.6

98

126

151

174

7.5

211

270

324

373

3.5

100

128

153

177

7.4

217

278

334

384

3.4

101

129

155

179

7.3

223

286

344

396

3.3

102

131

157

182

7.2

230

295

354

408

3.2

104

133

160

184

7.1

238

305

366

422

3.1

105

135

162

187

7.0

246

315

378

436

3.0

107

137

164

189

6.9

254

326

391

451

2.9

108

139

167

192

6.8

263

337

405

467

2.8

110

141

169

195

6.7

273

350

420

484

2.7

112

143

172

198

6.6

284

363

436

503

2.6

113

145

174

201

6.5

295

378

454

523

2.5

115

148

177

204

6.4

308

394

472

545

2.4

117

150

180

207

6.3

321

411

493

568

2.3

119

152

183

211

6.2

335

429

515

594

2.2

121

155

186

214

6.1

351

450

540

622

2.1

123

157

189

218

6.0

369

472

567

653

2.0

IADC Drilling Manual

Copyright © 2015

WR–56

WIRE ROPE Table WR-30 Design factors 1 1/4 in. extra improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

8 Lines

10 Lines

12 Lines

Design Factor

8 Lines

10 Lines

12 Lines

Design Factor

110

132

152

9.9

184

221

255

5.9

111

133

154

9.8

188

225

259

5.8

112

135

155

9.7

191

229

264

5.7

113

136

157

9.6

194

233

269

5.6

115

137

158

9.5

198

237

274

5.5

116

139

160

9.4

201

242

279

5.4

117

140

162

9.3

205

246

284

5.3

118

142

164

9.2

209

251

289

5.2

120

143

165

9.1

213

256

295

5.1

121

145

167

9.0

218

261

301

5.0

122

147

169

8.9

222

266

307

4.9

124

148

171

8.8

227

272

313

4.8

125

150

173

8.7

231

278

320

4.7

126

152

175

8.6

236

284

327

4.6

128

154

177

8.5

242

290

334

4.5

130

155

179

8.4

247

297

342

4.4

131

157

181

8.3

253

304

350

4.3

133

159

184

8.2

259

311

358

4.2

134

161

186

8.1

265

318

367

4.1

136

163

188

8.0

272

326

376

4.0

138

165

190

7.9

279

335

386

3.9

139

167

193

7.8

286

344

396

3.8

141

170

195

7.7

294

353

407

3.7

143

172

198

7.6

302

363

418

3.6

145

174

201

7.5

311

373

430

3.5

147

176

203

7.4

320

384

443

3.4

149

179

206

7.3

330

396

456

3.3

151

181

209

7.2

340

408

470

3.2

153

184

212

7.1

351

421

485

3.1

155

187

215

7.0

363

435

502

3.0

158

189

218

6.9

375

450

519

2.9

160

192

221

6.8

389

466

537

2.8

162

195

225

6.7

403

484

557

2.7

165

198

228

6.6

418

502

579

2.6

167

201

231

6.5

435

522

602

2.5

170

204

235

6.4

453

544

627

2.4

173

207

239

6.3

473

568

654

2.3

175

211

243

6.2

494

593

684

2.2

178

214

247

6.1

518

622

717

2.1

181

218

251

6.0

544

653

752

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–57

Table WR-31 Design factors 1 3/8 in. improved plow rotary line UNION WIRE ROPE

Weight Indicator Reading (1,000s Lb)

Weight Indicator Reading (1,000s Lb)

8 Lines

10 Lines

12 Lines

14 Lines

Design Factor

8 Lines

10 Lines

12 Lines

14 Lines

Design Factor

115

138

159

178

9.9

193

231

267

299

5.9

116

139

160

180

9.8

196

235

271

304

5.8

117

141

162

182

9.7

199

239

276

309

5.7

118

142

164

184

9.6

203

244

281

315

5.6

120

144

166

185

9.5

207

248

286

320

5.5

121

145

167

187

9.4

211

253

291

326

5.4

122

147

169

189

9.3

214

257

297

332

5.3

124

148

171

191

9.2

219

262

302

339

5.2

125

150

173

194

9.1

223

268

308

345

5.1

126

152

175

196

9.0

227

273

315

352

5.0

128

153

177

198

8.9

232

278

321

360

4.9

129

155

179

200

8.8

237

284

328

367

4.8

131

157

181

202

8.7

242

290

335

375

4.7

132

159

183

205

8.6

247

297

342

383

4.6

134

161

185

207

8.5

253

303

349

391

4.5

135

162

187

210

8.4

258

310

357

400

4.4

137

164

189

212

8.3

264

317

366

410

4.3

139

166

192

215

8.2

271

325

374

419

4.2

140

168

194

217

8.1

277

333

384

430

4.1

142

171

197

220

8.0

284

341

393

440

4.0

144

173

199

223

7.9

291

350

403

452

3.9

146

175

202

226

7.8

299

359

414

464

3.8

148

177

204

229

7.7

307

369

425

476

3.7

150

180

207

232

7.6

316

379

437

489

3.6

152

182

210

235

7.5

325

390

449

503

3.5

154

184

213

238

7.4

334

401

463

518

3.4

156

187

215

241

7.3

344

413

477

534

3.3

158

189

218

245

7.2

355

426

491

551

3.2

160

192

221

248

7.1

367

440

507

568

3.1

162

195

225

252

7.0

379

455

524

587

3.0

165

198

228

255

6.9

392

470

542

607

2.9

167

201

231

259

6.8

406

487

562

629

2.8

170

204

235

263

6.7

421

505

582

652

2.7

172

207

238

267

6.6

437

525

605

678

2.6

175

210

242

271

6.5

455

546

629

705

2.5

178

213

246

275

6.4

474

568

655

734

2.4

180

217

250

280

6.3

494

593

684

766

2.3

183

220

254

284

6.2

517

620

715

801

2.2

186

224

258

289

6.1

541

650

749

839

2.1

189

227

262

294

6.0

568

682

786

881

2.0

IADC Drilling Manual

Copyright © 2015

WR–58

WIRE ROPE Table WR-32 Design factors 1 3/8 in. extra improved plow rotary line UNION WIRE ROPE

Weight Indicator Reading (1,000s Lb)

Weight Indicator Reading (1,000s Lb)

8 Lines

10 Lines

12 Lines

14 Lines

Design Factor

8 Lines

10 Lines

12 Lines

14 Lines

Design Factor

132

158

183

205

9.9

222

266

306

343

5.9

133

160

184

207

9.8

225

270

312

349

5.8

135

162

186

209

9.7

229

275

317

355

5.7

136

163

188

211

9.6

233

280

323

362

5.6

138

165

190

213

9.5

238

285

329

368

5.5

139

167

192

215

9.4

242

290

335

375

5.4

141

169

194

218

9.3

247

296

341

382

5.3

142

171

197

220

9.2

251

302

348

389

5.2

144

172

199

223

9.1

256

308

354

397

5.1

145

174

201

225

9.0

261

314

362

405

5.0

147

176

203

228

8.9

267

320

369

413

4.9

149

178

205

230

8.8

272

327

377

422

4.8

150

180

208

233

8.7

278

334

385

431

4.7

152

182

210

236

8.6

284

341

393

440

4.6

154

185

213

238

8.5

290

349

402

450

4.5

156

187

215

241

8.4

297

357

411

460

4.4

157

189

218

244

8.3

304

365

420

471

4.3

159

191

220

247

8.2

311

373

430

482

4.2

161

194

223

250

8.1

319

383

441

494

4.1

163

196

226

253

8.0

327

392

452

506

4.0

165

199

229

256

7.9

335

402

464

519

3.9

168

201

232

260

7.8

344

413

476

533

3.8

170

204

235

263

7.7

353

424

489

547

3.7

172

206

238

266

7.6

363

436

502

563

3.6

174

209

241

270

7.5

373

448

517

579

3.5

177

212

244

274

7.4

384

461

532

596

3.4

179

215

248

277

7.3

396

475

548

614

3.3

182

218

251

281

7.2

408

490

565

633

3.2

184

221

255

285

7.1

422

506

583

653

3.1

187

224

258

289

7.0

436

523

603

675

3.0

189

227

262

294

6.9

451

541

623

698

2.9

192

231

266

298

6.8

467

560

646

723

2.8

195

234

270

302

6.7

484

581

670

750

2.7

198

238

274

307

6.6

503

603

695

779

2.6

201

241

278

312

6.5

523

627

723

810

2.5

204

245

282

316

6.4

545

654

753

844

2.4

207

249

287

321

6.3

568

682

786

881

2.3

211

253

292

327

6.2

594

713

822

921

2.2

214

257

296

332

6.1

622

747

861

964

2.1

218

261

301

338

6.0

654

784

904

1013

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–59

Table WR-33 Design factors 1 1/2 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb) 8 Lines

10 Lines

12 Lines

Weight indicator reading (1,000s lb) Design Factor

8 Lines

10 Lines

12 Lines

Design Factor

136

163

188

9.9

228

274

316

5.9

137

165

190

9.8

232

279

321

5.8

139

167

192

9.7

236

284

327

5.7

140

168

194

9.6

240

289

333

5.6

142

170

196

9.5

245

294

339

5.5

143

172

198

9.4

249

299

345

5.4

145

174

200

9.3

254

305

351

5.3

146

176

202

9.2

259

311

358

5.2

148

178

205

9.1

264

317

365

5.1

150

180

207

9.0

269

323

373

5.0

151

182

209

8.9

275

330

380

4.9

153

184

212

8.8

281

337

388

4.8

155

186

214

8.7

286

344

396

4.7

157

188

217

8.6

293

351

405

4.6

158

190

219

8.5

299

359

414

4.5

160

192

222

8.4

306

367

423

4.4

162

195

224

8.3

313

376

433

4.3

164

197

227

8.2

321

385

443

4.2

166

200

230

8.1

328

394

454

4.1

168

202

233

8.0

337

404

466

4.0

170

205

236

7.9

345

414

478

3.9

173

207

239

7.8

354

425

490

3.8

175

210

242

7.7

364

437

503

3.7

177

213

245

7.6

374

449

517

3.6

180

215

248

7.5

385

462

532

3.5

182

218

252

7.4

396

475

548

3.4

184

221

255

7.3

408

490

564

3.3

187

224

259

7.2

421

505

582

3.2

190

228

262

7.1

434

521

601

3.1

192

231

266

7.0

449

539

621

3.0

195

234

270

6.9

464

557

642

2.9

198

238

274

6.8

481

577

665

2.8

201

241

278

6.7

499

599

690

2.7

204

245

282

6.6

518

622

716

2.6

207

249

287

6.5

539

646

745

2.5

210

253

291

6.4

561

673

776

2.4

214

257

296

6.3

585

703

810

2.3

217

261

300

6.2

612

735

847

2.2

221

265

305

6.1

641

770

887

2.1

224

269

310

6.0

673

808

931

2.0

IADC Drilling Manual

Copyright © 2015

WR–60

WIRE ROPE Table WR-34 Design factors 1 1/2 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb) 10 Lines

12 Lines

14 Lines

Weight indicator reading (1,000s lb) Design Factor

10 Lines

12 Lines

14 Lines

Design Factor

163

188

211

9.9

274

316

354

5.9

165

190

213

9.8

279

321

360

5.8

167

192

215

9.7

284

327

366

5.7

168

194

217

9.6

289

333

373

5.6

170

196

220

9.5

294

339

379

5.5

172

198

222

9.4

299

345

386

5.4

174

200

224

9.3

305

351

394

5.3

176

202

227

9.2

311

358

401

5.2

178

205

229

9.1

317

365

409

5.1

180

207

232

9.0

323

373

417

5.0

182

209

234

8.9

330

380

426

4.9

184

212

237

8.8

337

388

435

4.8

186

214

240

8.7

344

396

444

4.7

188

217

243

8.6

351

405

454

4.6

190

219

245

8.5

359

414

464

4.5

192

222

248

8.4

367

423

474

4.4

195

224

251

8.3

376

433

485

4.3

197

227

254

8.2

385

443

497

4.2

200

230

258

8.1

394

454

509

4.1

202

233

261

8.0

404

466

522

4.0

205

236

264

7.9

414

478

535

3.9

207

239

267

7.8

425

490

549

3.8

210

242

271

7.7

437

503

564

3.7

213

245

275

7.6

449

517

580

3.6

215

248

278

7.5

462

532

596

3.5

218

252

282

7.4

475

548

614

3.4

221

255

286

7.3

490

564

632

3.3

224

259

290

7.2

505

582

652

3.2

228

262

294

7.1

521

601

673

3.1

231

266

298

7.0

539

621

695

3.0

234

270

302

6.9

557

642

719

2.9

238

274

307

6.8

577

665

745

2.8

241

278

311

6.7

599

690

773

2.7

245

282

316

6.6

622

716

802

2.6

249

287

321

6.5

646

745

835

2.5

253

291

326

6.4

673

776

869

2.4

257

296

331

6.3

703

810

907

2.3

261

300

337

6.2

735

847

948

2.2

265

305

342

6.1

770

887

994

2.1

269

310

348

6.0

808

931

1043

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–61

Table WR-35 Design factors 1 1/2 in. extra improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb) 8 Lines

10 Lines

12 Lines

Weight indicator reading (1,000s lb) Design Factor

8 Lines

10 Lines

12 Lines

Design Factor

157

188

217

9.9

263

316

364

5.9

158

190

219

9.8

268

321

370

5.8

160

192

221

9.7

272

327

377

5.7

162

194

224

9.6

277

333

383

5.6

163

196

226

9.5

282

339

390

5.5

165

198

228

9.4

287

345

398

5.4

167

200

231

9.3

293

351

405

5.3

169

202

233

9.2

298

358

413

5.2

171

205

236

9.1

304

365

421

5.1

172

207

239

9.0

310

373

429

5.0

174

209

241

8.9

317

380

438

4.9

176

212

244

8.8

323

388

447

4.8

178

214

247

8.7

330

396

457

4.7

180

217

250

8.6

337

405

467

4.6

183

219

253

8.5

345

414

477

4.5

185

222

256

8.4

353

423

488

4.4

187

224

259

8.3

361

433

499

4.3

189

227

262

8.2

370

444

511

4.2

192

230

265

8.1

379

454

524

4.1

194

233

268

8.0

388

466

537

4.0

196

236

272

7.9

398

478

550

3.9

199

239

275

7.8

408

490

565

3.8

202

242

279

7.7

419

503

580

3.7

204

245

282

7.6

431

517

596

3.6

207

248

286

7.5

443

532

613

3.5

210

252

290

7.4

456

548

631

3.4

213

255

294

7.3

470

564

651

3.3

216

259

298

7.2

485

582

671

3.2

219

262

302

7.1

501

601

693

3.1

222

266

307

7.0

517

621

716

3.0

225

270

311

6.9

535

642

740

2.9

228

274

316

6.8

554

665

767

2.8

232

278

320

6.7

575

690

795

2.7

235

282

325

6.6

597

716

826

2.6

239

287

330

6.5

621

745

859

2.5

243

291

335

6.4

647

776

895

2.4

246

296

341

6.3

675

810

933

2.3

250

300

346

6.2

705

847

976

2.2

254

305

352

6.1

739

887

1022

2.1

259

310

358

6.0

776

931

1073

2.0

IADC Drilling Manual

Copyright © 2015

WR–62

WIRE ROPE Table WR-36 Design factors 1 1/2 in. extra improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

10 Lines

12 Lines

14 Lines

16 Lines

Design Factor

10 Lines

12 Lines

14 Lines

16 Lines

Design Factor

188

217

243

267

9.9

316

364

408

447

5.9

190

219

245

269

9.8

321

370

415

455

5.8

192

221

248

272

9.7

327

377

422

463

5.7

194

224

251

275

9.6

333

383

429

471

5.6

196

226

253

278

9.5

339

390

437

480

5.5

198

228

256

281

9.4

345

398

445

489

5.4

200

231

259

284

9.3

351

405

454

498

5.3

202

233

261

287

9.2

358

413

463

507

5.2

205

236

264

290

9.1

365

421

472

517

5.1

207

239

267

293

9.0

373

429

481

528

5.0

209

241

270

297

8.9

380

438

491

539

4.9

212

244

273

300

8.8

388

447

501

550

4.8

214

247

276

303

8.7

396

457

512

561

4.7

217

250

280

307

8.6

405

467

523

574

4.6

219

253

283

310

8.5

414

477

534

586

4.5

222

256

286

314

8.4

423

488

547

600

4.4

224

259

290

318

8.3

433

499

559

614

4.3

227

262

293

322

8.2

444

511

573

628

4.2

230

265

297

326

8.1

454

524

587

644

4.1

233

268

301

330

8.0

466

537

601

660

4.0

236

272

304

334

7.9

478

550

617

677

3.9

239

275

308

338

7.8

490

565

633

694

3.8

242

279

312

343

7.7

503

580

650

713

3.7

245

282

316

347

7.6

517

596

668

733

3.6

248

286

321

352

7.5

532

613

687

754

3.5

252

290

325

357

7.4

548

631

707

776

3.4

255

294

329

361

7.3

564

651

729

800

3.3

259

298

334

367

7.2

582

671

752

825

3.2

262

302

339

372

7.1

601

693

776

851

3.1

266

307

344

377

7.0

621

716

802

880

3.0

270

311

349

382

6.9

642

740

829

910

2.9

274

316

354

388

6.8

665

767

859

942

2.8

278

320

359

394

6.7

690

795

891

977

2.7

282

325

364

400

6.6

716

826

925

1015

2.6

287

330

370

406

6.5

745

859

962

1056

2.5

291

335

376

412

6.4

776

895

1002

1100

2.4

296

341

382

419

6.3

810

933

1046

1147

2.3

300

346

388

426

6.2

847

976

1093

1199

2.2

305

352

394

433

6.1

887

1022

1145

1257

2.1

310

358

401

440

6.0

931

1073

1203

1319

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–63

Table WR-37 Design factors 1 5/8 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb) 8 Lines

10 Lines

12 Lines

Weight indicator reading (1,000s lb) Design Factor

8 Lines

10 Lines

12 Lines

Design Factor

158

190

219

9.9

265

318

367

5.9

160

192

221

9.8

270

324

373

5.8

161

194

223

9.7

275

330

380

5.7

163

196

226

9.6

280

336

387

5.6

165

198

228

9.5

285

342

394

5.5

167

200

230

9.4

290

348

401

5.4

168

202

233

9.3

295

355

409

5.3

170

204

235

9.2

301

361

416

5.2

172

206

238

9.1

307

368

425

5.1

174

209

241

9.0

313

376

433

5.0

176

211

243

8.9

320

383

442

4.9

178

214

246

8.8

326

391

451

4.8

180

216

249

8.7

333

400

461

4.7

182

218

252

8.6

340

408

471

4.6

184

221

255

8.5

348

418

481

4.5

186

224

258

8.4

356

427

492

4.4

189

226

261

8.3

364

437

504

4.3

191

229

264

8.2

373

447

516

4.2

193

232

267

8.1

382

458

528

4.1

196

235

271

8.0

391

470

541

4.0

198

238

274

7.9

401

482

555

3.9

201

241

278

7.8

412

494

570

3.8

203

244

281

7.7

423

508

585

3.7

206

247

285

7.6

435

522

602

3.6

209

251

289

7.5

447

537

619

3.5

212

254

293

7.4

460

553

637

3.4

214

257

297

7.3

474

569

656

3.3

217

261

301

7.2

489

587

677

3.2

221

265

305

7.1

505

606

699

3.1

224

268

309

7.0

522

626

722

3.0

227

272

314

6.9

540

648

747

2.9

230

276

318

6.8

559

671

773

2.8

234

280

323

6.7

580

696

802

2.7

237

285

328

6.6

602

723

833

2.6

241

289

333

6.5

626

752

866

2.5

245

294

338

6.4

652

783

902

2.4

249

298

344

6.3

681

817

942

2.3

253

303

349

6.2

712

854

984

2.2

257

308

355

6.1

746

895

1031

2.1

261

313

361

6.0

783

940

1083

2.0

IADC Drilling Manual

Copyright © 2015

WR–64

WIRE ROPE Table WR-38 Design factors 1 5/8 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb) 10 Lines

12 Lines

14 Lines

Weight indicator reading (1,000s lb) Design Factor

10 Lines

12 Lines

14 Lines

Design Factor

190

219

245

9.9

318

367

411

5.9

192

221

248

9.8

324

373

418

5.8

194

223

250

9.7

330

380

426

5.7

196

226

253

9.6

336

387

433

5.6

198

228

255

9.5

342

394

441

5.5

200

230

258

9.4

348

401

449

5.4

202

233

261

9.3

355

409

458

5.3

204

235

264

9.2

361

416

467

5.2

206

238

267

9.1

368

425

476

5.1

209

241

270

9.0

376

433

485

5.0

211

243

273

8.9

383

442

495

4.9

214

246

276

8.8

391

451

505

4.8

216

249

279

8.7

400

461

516

4.7

218

252

282

8.6

408

471

527

4.6

221

255

285

8.5

418

481

539

4.5

224

258

289

8.4

427

492

551

4.4

226

261

292

8.3

437

504

567

4.3

229

264

296

8.2

447

516

578

4.2

232

267

300

8.1

458

528

592

4.1

235

271

303

8.0

470

541

607

4.0

238

274

307

7.9

482

555

622

3.9

241

278

311

7.8

494

570

638

3.8

244

281

315

7.7

508

585

656

3.7

247

285

319

7.6

522

602

674

3.6

251

289

323

7.5

537

619

693

3.5

254

293

328

7.4

553

637

714

3.4

257

297

332

7.3

569

656

735

3.3

261

301

337

7.2

587

677

758

3.2

265

305

342

7.1

606

699

783

3.1

268

309

347

7.0

626

722

809

3.0

272

314

352

6.9

648

747

837

2.9

276

318

357

6.8

671

773

866

2.8

280

323

362

6.7

696

802

899

2.7

285

328

368

6.6

723

833

933

2.6

289

333

373

6.5

752

866

970

2.5

294

338

379

6.4

783

902

1011

2.4

298

344

385

6.3

817

942

1055

2.3

303

349

391

6.2

854

984

1103

2.2

308

355

398

6.1

895

1031

1155

2.1

313

361

404

6.0

940

1083

1213

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–65

Table WR-39 Design Factors 1 5/8 in. improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb) 8 Lines

10 Lines

12 Lines

Weight indicator reading (1,000s lb) Design Factor

8 Lines

10 Lines

12 Lines

Design Factor

182

218

251

9.9

305

366

421

5.9

183

220

254

9.8

310

372

429

5.8

185

222

256

9.7

315

378

436

5.7

187

225

259

9.6

321

385

444

5.6

189

227

262

9.5

327

392

452

5.5

191

229

264

9.4

333

399

460

5.1

193

232

267

9.3

339

407

469

5.3

195

234

270

9.2

346

415

478

5.2

197

237

273

9.1

352

423

487

5.1

200

240

276

9.0

359

431

497

5.0

202

242

279

8.9

367

440

507

4.9

204

245

282

8.8

374

449

518

4.8

207

248

286

8.7

382

459

529

4.7

209

251

289

8.6

391

469

540

4.6

211

254

292

8.5

399

479

552

4.5

214

257

296

8.4

408

490

565

4.4

217

260

300

8.3

418

502

578

4.3

219

263

303

8.2

428

514

592

4.2

222

266

307

8.1

438

526

606

4.1

225

270

311

8.0

449

539

621

4.0

227

273

315

7.9

461

553

637

3.9

230

277

319

7.8

473

568

654

3.8

233

280

323

7.7

486

583

672

3.7

236

284

327

7.6

499

599

691

3.6

240

288

331

7.5

513

616

710

3.5

243

291

336

7.4

529

634

731

3.4

246

295

341

7.3

545

654

753

3.3

250

300

345

7.2

562

674

777

3.2

253

304

350

7.1

580

696

802

3.1

257

308

355

7.0

599

719

829

3.0

260

313

360

6.9

620

744

857

2.9

264

317

366

6.8

642

770

888

2.8

268

322

371

6.7

666

799

921

2.7

272

327

377

6.6

691

830

956

2.6

276

332

382

6.5

719

863

994

2.5

281

337

388

6.4

749

899

1036

2.4

285

342

395

6.3

781

938

1081

2.3

290

348

401

6.2

817

980

1130

2.2

295

354

408

6.1

856

1027

1184

2.1

300

359

414

6.0

899

1078

1243

2.0

IADC Drilling Manual

Copyright © 2015

WR–66

WIRE ROPE Table WR-40 Design Factors 1 5/8 in. extra improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

10 Lines

12 Lines

14 Lines

16 Lines

Design Factor

10 Lines

12 Lines

14 Lines

16 Lines

Design Factor

218

251

281

309

9.9

366

421

472

518

5.9

220

254

284

312

9.8

372

429

480

527

5.8

222

256

287

315

9.7

378

436

489

536

5.7

225

259

290

318

9.6

385

444

497

546

5.6

227

262

293

322

9.5

392

452

506

556

5.5

229

264

296

325

9.4

399

460

516

566

5.4

232

267

299

329

9.3

407

469

525

577

5.3

234

270

303

332

9.2

415

478

536

588

5.2

237

273

306

336

9.1

423

487

546

599

5.1

240

276

309

340

9.0

431

497

557

611

5.0

242

279

313

343

8.9

440

507

568

624

4.9

245

282

316

347

8.8

449

518

580

637

4.8

248

286

320

351

8.7

459

529

593

650

4.7

251

289

324

355

8.6

469

540

605

664

4.6

254

292

328

359

8.5

479

552

619

679

4.5

257

296

332

364

8.4

490

565

633

694

4.4

260

300

336

368

8.3

502

578

648

711

4.3

263

303

340

373

8.2

514

592

663

728

4.2

266

307

344

377

8.1

526

606

679

745

4.1

270

311

348

382

8.0

539

621

696

764

4.0

273

315

353

387

7.9

553

637

714

783

3.9

277

319

357

392

7.8

568

654

733

804

3.8

280

323

362

397

7.7

583

672

753

826

3.7

284

327

366

402

7.6

599

691

774

849

3.6

288

331

371

407

7.5

616

710

796

873

3.5

291

336

376

413

7.4

634

731

819

899

3.4

295

341

381

419

7.3

654

753

844

926

3.3

300

345

387

424

7.2

674

777

870

955

3.2

304

350

392

430

7.1

696

802

898

986

3.1

308

355

398

437

7.0

719

829

928

1019

3.0

313

360

404

443

6.9

744

857

960

1054

2.9

317

366

410

449

6.8

770

888

995

1091

2.8

322

371

416

456

6.7

799

921

1031

1132

2.7

327

377

422

463

6.6

830

956

1071

1175

2.6

332

382

428

470

6.5

863

994

1114

1222

2.5

337

388

435

477

6.4

899

1036

1160

1273

2.4

342

395

442

485

6.3

938

1081

1211

1329

2.3

348

401

449

493

6.2

980

1130

1266

1389

2.2

354

408

457

501

6.1

1027

1184

1326

1455

2.1

359

414

464

509

6.0

1078

1243

1392

1528

2.0

IADC Drilling Manual

Copyright © 2015

WIRE ROPE

WR–67

TableWR-41 Design factors 1 3/4 in. extra improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

12 Lines

14 Lines

16 Lines

18 Lines

Design Factor

12 Lines

14 Lines

16 Lines

18 Lines

Design Factor

326

374

420

463

9.9

548

628

705

778

5.9

330

378

424

468

9.8

558

639

717

792

5.8

334

382

428

473

9.7

568

650

729

805

5.7

337

386

433

478

9.6

578

662

742

819

5.6

341

390

438

483

9.5

588

674

756

834

5.5

344

394

442

488

9.4

599

686

770

850

5.4

348

398

447

493

9.3

610

699

784

866

5.3

352

403

452

499

9.2

622

713

799

882

5.2

355

407

457

504

9.1

634

727

815

900

5.1

359

412

462

510

9.0

647

741

831

918

5.0

363

416

467

516

8.9

660

756

848

936

4.9

367

421

472

521

8.8

674

772

867

956

4.8

372

426

478

527

8.7

688

788

884

976

4.7

376

431

483

534

8.6

703

806

904

997

4.6

381

436

489

540

8.5

719

823

924

1020

4.5

385

441

495

546

8.4

735

842

945

1043

4.4

390

446

501

553

8.3

752

862

967

1067

4.3

395

452

507

560

8.2

770

882

990

1092

4.2

399

457

513

566

8.1

789

904

1014

1119

4.1

404

463

520

574

8.0

809

926

1039

1147

4.0

409

469

526

581

7.9

829

950

1066

1176

3.9

415

475

533

588

7.8

851

975

1094

1207

3.8

420

481

540

596

7.7

874

1002

1123

1240

3.7

426

488

547

604

7.6

899

1029

1155

1274

3.6

431

494

554

612

7.5

924

1059

1188

1311

3.5

437

501

562

620

7.4

951

1090

1223

1349

3.4

443

508

569

629

7.3

980

1123

1260

1390

3.3

449

515

577

637

7.2

1011

1158

1299

1434

3.2

456

522

585

646

7.1

1044

1195

1341

1480

3.1

462

529

594

655

7.0

1078

1235

1386

1529

3.0

469

537

602

665

6.9

1116

1278

1433

1582

2.9

476

545

611

675

6.8

1155

1323

1485

1639

2.8

483

553

620

685

6.7

1198

1372

1540

1699

2.7

490

561

630

695

6.6

1244

1425

1599

1765

2.6

498

570

639

706

6.5

1294

1482

1663

1835

2.5

505

579

649

717

6.4

1348

1544

1732

1912

2.4

513

588

660

728

6.3

1407

1611

1807

1995

2.3

522

598

670

740

6.2

1470

1684

1889

2086

2.2

530

607

681

752

6.1

1540

1765

1979

2185

2.1

539

618

693

765

6.0

1618

1853

2078

2294

2.0

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Copyright © 2015

WR–68

WIRE ROPE Table WR-42 Design factors 2 in. extra improved plow rotary line UNION WIRE ROPE

Weight indicator reading (1,000s lb)

Weight indicator reading (1,000s lb)

10 Lines

12 Lines

14 Lines

16 Lines

Design Factor

10 Lines

12 Lines

14 Lines

16 Lines

Design Factor

359

423

484

543

9.9

603

710

813

912

5.9

363

427

489

549

9.8

613

722

827

927

5.8

367

432

494

555

9.7

624

734

841

944

5.7

370

436

500

560

9.6

635

748

856

961

5.6

374

441

505

566

9.5

647

761

872

978

5.5

378

445

510

572

9.4

659

775

888

996

5.4

382

450

516

578

9.3

671

790

905

1015

5.3

387

455

521

585

9.2

684

805

922

1034

5.2

391

460

527

591

9.1

697

821

940

1055

5.1

395

465

533

598

9.0

711

837

959

1076

5.0

400

470

539

604

8.9

726

854

979

1098

4.9

404

476

545

611

8.8

741

872

999

1121

4.8

409

481

551

618

8.7

757

891

1020

1145

4.7

413

487

557

625

8.6

773

910

1043

1169

4.6

418

493

564

633

8.5

790

930

1066

1195

4.5

423

498

571

640

8.4

808

951

1090

1223

4.4

428

504

578

648

8.3

827

974

1115

1251

4.3

434

511

585

656

8.2

847

997

1142

1281

4.2

439

517

592

664

8.1

867

1021

1170

1312

4.1

445

523

599

672

8.0

889

1047

1199

1345

4.0

450

530

607

681

7.9

912

1073

1230

1379

3.9

456

537

615

690

7.8

936

1102

1262

1416

3.8

462

544

623

699

7.7

961

1131

1296

1454

3.7

468

551

631

708

7.6

988

1163

1332

1494

3.6

474

558

639

717

7.5

1016

1196

1370

1537

3.5

481

566

648

727

7.4

1046

1231

1410

1582

3.4

487

573

657

737

7.3

1078

1269

1453

1630

3.3

494

581

666

747

7.2

1111

1308

1499

1681

3.2

501

590

675

757

7.1

1147

1350

1547

1735

3.1

508

598

685

768

7.0

1185

1396

1599

1793

3.0

515

607

695

780

6.9

1226

1444

1654

1855

2.9

523

616

705

791

6.8

1270

1495

1713

1921

2.8

531

625

716

803

6.7

1317

1551

1776

1992

2.7

539

634

727

815

6.6

1368

1610

1844

2069

2.6

547

644

738

828

6.5

1422

1675

1918

2152

2.5

556

654

749

841

6.4

1482

1744

1998

2241

2.4

564

665

761

854

6.3

1546

1820

2085

2339

2.3

574

675

773

868

6.2

1616

1903

2180

2445

2.2

583

686

786

882

6.1

1693

1994

2284

2562

2.1

593

698

799

897

6.0

1778

2093

2398

2690

2.0

* These values were calculated using 2% sheave loss and the API Fomula. They do not include shock loads or acceleration stresses.

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Copyright © 2015

WIRE ROPE

WR–69

Table WR-43 Ton-miles for jarring down (Bumper jars) Chart is for one pull* (Pull is from zero load to pipe weight plus 5 ft stroke and back)

Drill Pipe Size (in.) and Weight (lb/ft) Clear Length (ft) 1,000 2,000 3,000 4,000 5,000

2 3/8 in. 6.650

2 7/8 in. 10.400

3 1/2 in. 13.300

3 1/2 in. 15.500

4 in. 14.000

4 1/2 in. 16.600

4 1/2 in. 20.000

5 in. 19.500

5 1/2 in. 21.900

5 1/2 in. 24.700

6 5/8 in. 25.200

0.032 0.037 0.043 0.052 0.064

0.033 0.040 0.049 0.061 0.076

0.034 0.042 0.053 0.067 0.085

0.035 0.044 0.056 0.071 0.091

0.035 0.043 0.054 0.069 0.087

0.036 0.045 0.058 0.075 0.096

0.037 0.048 0.063 0.081 0.105

0.037 0.048 0.062 0.081 0.104

0.038 0.050 0.066 0.086 0.112

0.039 0.053 0.070 0.092 0.121

0.039 0.053 0.071 0.094 0.124

6,000 7,000 8,000 9,000 10,000

0.078 0.096 0.117 0.143 0.172

0.095 0.118 0.147 0.181 0.221

0.107 0.135 0.169 0.210 0.258

0.116 0.147 0.184 0.229 0.283

0.111 0.140 0.175 0.218 0.268

0.123 0.156 0.197 0.247 0.305

0.136 0.173 0.219 0.275 0.341

0.134 0.172 0.218 0.273 0.339

0.146 0.187 0.238 0.300 0.373

0.157 0.203 0.259 0.326 0.407

0.162 0.210 0.268 0.339 0.424

11,000 12,000 13,000 14,000 15,000

0.206 0.245 0.289 0.339 0.395

0.267 0.321 0.382 0.452 0.530

0.315 0.380 0.455 0.540 0.635

0.345 0.417 0.501 0.595 0.702

0.327 0.395 0.473 0.561 0.662

0.374 0.454 0.545 0.649 0.767

0.419 0.509 0.612 0.731 0.864

0.416 0.505 0.609 0.726 0.859

0.459 0.560 0.675 0.807 0.956

0.502 0.612 0.739 0.885 1.050

0.523 0.639 0.773 0.926 1.100

16,000 17,000 18,000 19,000 20,000

0.458 0.526 0.602 0.685 0.776

0.618 0.715 0.823 0.941 1.070

0.743 0.863 0.995 1.140 1.300

0.822 0.956 1.100 1.270 1.450

0.774 0.898 1.040 1.190 1.360

0.900 1.050 1.210 1.390 1.590

1.020 1.180 1.370 1.580 1.800

1.010 1.180 1.360 1.570 1.790

1.120 1.310 1.520 1.750 2.010

1.240 1.440 1.670 1.930 2.210

1.290 1.510 1.760 2.030 2.320

21,000 22,000 23,000 24,000 25,000

0.875 0.982 1.100 1.220 1.360

1.210 1.370 1.540 1.720 1.910

1.480 1.670 1.880 2.100 2.350

1.640 1.860 2.090 2.350 2.620

1.540 1.750 1.960 2.200 2.450

1.810 2.050 2.310 2.590 2.890

2.050 2.330 2.620 2.940 3.290

2.040 2.310 2.610 2.920 3.270

2.290 2.590 2.920 3.280 3.670

2.520 2.860 3.230 3.630 4.060

2.650 3.010 3.390 3.810 4.270

26,000 27,000 28,000 29,000 30,000

1.500 1.660 1.820 2.000 2.180

2.120 2.350 2.590 2.840 3.120

2.610 2.890 3.190 3.510 3.850

2.910 3.230 3.570 3.930 4.310

2.730 3.020 3.340 3.680 4.040

3.220 3.570 3.940 4.340 4.770

3.660 4.060 4.500 4.960 5.450

3.640 4.040 4.470 4.930 5.410

4.090 4.540 5.030 5.540 6.100

4.520 5.020 5.560 6.130 6.750

4.760 5.290 5.850 6.460 7.110

"* Example 1: If approximately 25 pulls are made on 12,000 ft of clear 5 in. (19.5 lb) pipe, the ton-miles accumulated are: 0.505×25 = 13 ton-miles. "* Example 2: If approximately 100 pulls are made on 20,000 ft of clear 4 1/2 in. (16.6 lb) pipe, the ton-miles accumulated are: 1.59×100 = 159 ton-miles.

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WR–70

WIRE ROPE Table WR-44 Ton-miles for jarring down (Bumper jars) Chart is for one pull* (Pull is from 20,000 lb under pipe weight to 70,000 lb over pipe weight and back) plus 5 ft stroke and back)

Drill Pipe Size (in.) and Weight (lb/ft) Clear Length (ft) 1,000 2,000 3,000 4,000 5,000

2 3/8 in. 6.650

2 7/8 in. 10.400

3 1/2 in. 13.300

3 1/2 in. 15.500

4 in. 14.000

4 1/2 in. 16.600

4 1/2 in. 20.000

5 in. 19.500

5 1/2 in. 21.900

5 1/2 in. 24.700

6 in. 25.200

0.034 0.074 0.121 0.174 0.233

0.023 0.052 0.088 0.130 0.179

0.019 0.044 0.076 0.144 0.158

0.016 0.039 0.068 0.103 0.145

0.018 0.043 0.074 0.111 0.155

0.016 0.039 0.068 0.104 0.146

0.013 0.033 0.059 0.092 0.131

0.014 0.034 0.061 0.095 0.135

0.013 0.033 0.059 0.091 0.131

0.012 0.030 0.055 0.086 0.124

0.012 0.031 0.056 0.089 0.128

6,000 7,000 8,000 9,000 10,000

0.298 0.370 0.448 0.533 0.623

0.234 0.295 0.363 0.437 0.518

0.209 0.267 0.331 0.401 0.478

0.192 0.247 0.307 0.374 0.447

0.205 0.262 0.325 0.395 0.471

0.195 0.251 0.313 0.382 0.457

0.176 0.228 0.286 0.350 0.421

0.181 0.234 0.293 0.359 0.431

0.176 0.229 0.288 0.353 0.425

0.168 0.219 0.277 0.341 0.411

0.173 0.226 0.285 0.351 0.424

11,000 12,000 13,000 14,000 15,000

0.721 0.824 0.934 1.050 1.170

0.604 0.698 0.797 0.903 1.020

0.561 0.650 0.746 0.848 0.957

0.526 0.612 0.704 0.802 0.906

0.554 0.642 0.738 0.840 0.948

0.539 0.628 0.723 0.825 0.933

0.498 0.581 0.671 0.767 0.870

0.510 0.595 0.686 0.784 0.889

0.504 0.589 0.681 0.780 0.885

0.488 0.571 0.661 0.758 0.861

0.504 0.590 0.683 0.783 0.889

16,000 17,000 18,000 19,000 20,000

1.300 1.440 1.580 1.720 1.880

1.130 1.260 1.390 1.530 1.670

1.070 1.190 1.320 1.460 1.600

1.020 1.130 1.260 1.390 1.520

1.060 1.180 1.310 1.450 1.590

1.050 1.170 1.300 1.430 1.570

0.978 1.090 1.220 1.340 1.480

1.000 1.120 1.240 1.370 1.510

0.996 1.110 1.240 1.370 1.510

0.970 1.090 1.210 1.340 1.470

1.000 1.120 1.250 1.380 1.520

21,000 22,000 23,000 24,000 25,000

2.040 2.210 2.380 2.560 2.740

1.820 1.980 2.140 2.310 2.490

1.740 1.900 2.060 2.230 2.400

1.670 1.810 1.970 2.130 2.300

1.730 1.890 2.050 2.210 2.390

1.720 1.880 2.040 2.200 2.380

1.620 1.770 1.920 2.080 2.240

1.650 1.800 1.960 2.120 2.290

1.650 1.800 1.960 2.120 2.300

1.620 1.760 1.920 2.080 2.250

1.670 1.820 1.980 2.150 2.330

26,000 27,000 28,000 29,000 30,000

2.940 3.130 3.340 3.550 3.770

2.670 2.860 3.060 3.260 3.470

2.580 2.760 2.960 3.150 3.360

2.470 2.650 2.840 3.030 3.230

2.560 2.750 2.940 3.140 3.350

2.560 2.750 2.940 3.140 3.350

2.420 2.600 2.780 2.970 3.170

2.470 2.650 2.840 3.030 3.320

2.470 2.660 2.850 3.040 3.250

2.420 2.600 2.790 2.990 3.190

2.510 2.690 2.890 3.090 3.300

* Example 1: If approximately 25 pulls are made on 12,000 ft of clear 5 in. (19.5 lb) pipe, the ton-miles accumulated are: 0.595×25 = 15 ton-miles. * Example 2: If approximately 100 pulls are made on 20,000 ft of clear 4 1/2 in. (16.6 lb) pipe, the ton-miles accumulated are: 1.57×100 = 157 ton-miles.

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WIRE ROPE

WR–71

Table WR-45 Ton-miles for working casing (Based on 30 travel) Chart is for one pull* (Pull is from 20,000 lb under pipe weight to 70,000 lb over pipe weight and back)

Number of Cycles

Weight Indicator Reading (1,000 of lb)

10 20

100 6 12

200 12 24

300 18 36

400 24 48

500 30 60

600 36 72

700 42 84

800 48 96

30 40 50

18 24 30

36 48 60

54 72 90

72 96 120

90 120 150

108 144 180

126 168 210

144 192 240

60 70 80 90 100

36 42 48 54 60

72 84 96 108 120

108 126 144 162 180

144 168 192 216 240

180 210 240 70 300

216 252 288 324 360

252 294 336 378 420

288 336 384 432 480

*30 ft travel means 30 ft up and 30 ft down (this is one cycle)

Table WR-46 Approximate traveling block assembly weights (hook, block, elevator, and links) Weight-Pounds 6,300 7,400 12,900 16,700 26,500 34,000 46,000

Capacity-Tons 100 150 250 350 500 650 750

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WIRE ROPE, Index

WR–73

Table WR-47 Drill Collar Weights Pounds Per Foot Chart is for one pull* (Pull is from zero load to pipe weight pluse 5 ft stroke and back)

Bore of collar Collar O.D. 3 3/8 3 1/2 3 3/4 3 7/8 4 4 1/8 4 1/4 4 1/2 4  3/4 5 5 1/4 5 1/2 5 3/4 6 6 1/4 6 1/2 6 3/4 7 7 1/4 7 1/2 7 3/4 8 8 1/4 8 1/2 8 3/4 9 9 1/2 10 10 1/2 11

1 1/2

1 3/4

24.4 26.7 31.5 34 36.7 39.4 42.2 48 60.1 54.2 67.5 74.7 82.1 89.9 98.1 106.6 115.5 124.6 134.1 143.9 154.1 164.6 175.4 186.6 198.1

22.2 24.5 29.3 31.9 34.5 37.2 40 45.8 52 58.5 65.3 72.5 79.9 87.8 95.9 104.5 113.3 122.5 131.9 141.7 151.9 162.5 173.3 184.4 195.9 207.8 232.4

2

2 1/4

29.4 32 34.7 37.5 43.3 49.5 55.9 62.8 69.9 77.5 85.3 93.5 101.9 110.8 119.9 129.5 139.3 149.5 159.9 170.8 181.9 193.9 205.3 229.9 255.9 283.3

26.5 29.2 31.9 34.7 40.5 46.7 53.1 59.9 67.2 74.6 82.5 90.6 99.1 107.9 117.1 126.6 136.5 146.6 157.1 167.9 179.1 190.6 202.4 227.1 253.1 280.4

2 1/2

2 13/16

3

3 1/4

3 1/2

3 3/4

4

43.5 49.9 56.8 63.9 71.5 79.3 87.5 95.9 104.8 113.9 123.5 133.3 143.5 153.9 164.8 175.9 187.4 199.3 223.9 249.9 277.3 305.9

53.3 60.5 67.9 75.8 83.9 92.5 101.3 110.5 119.9 129.8 139.9 150.5 161.3 168.6 183.9 195.8 220.4 246.4 273.8 302.4

56.7 64.1 71.9 80.1 88.6 97.5 106.6 116.1 125.9 136.1 146.6 157.5 172.5 180.1 191.9 216.6 242.6 269.9 298.6

67.8 75.9 84.5 93.3 102.5 111.9 121.8 131.9 142.5 153.3 164.5 175.9 187.8 212.4 238.4 265.8 294.4

63.3 71.5 79.9 88.8 97.9 107.5 117.3 127.5 137.9 148.8 159.9 171.4 183.3 207.9 233.9 261.3 289.9

93.1 102.6 112.5 122.6 133.1 143.9 155.1 166.6 178.5 203.1 229.1 256.4 285.1

87.9 97.5 107.3 117.5 127.9 138.8 149.9 161.5 173.3 197.9 223.9 251.3 279.9

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WIRE ROPE

WR–A1

Appendix Ton-mile formulas The locking assembly must facilitate several requirements in order for the remainder of the assembly to effectively drill with casing. The assembly must allow: The ton-mile tables in this manual are designated to include the most common operating situations; however, they are not exhaustive. Variations in pipe weight (drill pipe, tubing, etc.), excess weight, and fluid weight (mud, gas, air, foam, etc.) make an exhaustive set of ton-mile tables impractical for this manual. Where the ton-mile tables can not be used, the following ton-mile formula (from which the tables are derived) may be applied. A. Round-trip operations Most of the work done by a drilling line is that performed in making round trips (or half-trips) involving running the string of drill pipe into the hole and pulling the string out of the hole. The amount of work performed per round trip can be determined by use of the following formula:

Tr =

(4.1)

D (Ls + D) Wm + D (M + 1/2 C) 10,560,000 2,640,000



D

= ton-miles (weight in tons times distance moved in miles) = depth of hole, ft

Ls

= length of drill-pipe stand, ft



= number of stands of drill-pipe

N

Analysis of the cycle of operations shows that for any one hole, the sum of all operations 1 and 2 is equal to one round trip; the sum of all operations 3 and 4 is equal to another round trip; the sum of all operations 7 is equal to one-half a round trip; and the sum of all operations 5, 6, and 8 may, and in this case does, equal another one-half round trip, thereby making the work of drilling the hole equivalent to three round trips to bottom, which relation- ship can be expressed as follows: Td = 3 (T2−T 1 )

(4.2)

Wherein: Td = ton-miles drilling

Wherein: Tr

1. Drill ahead length of the kelly. 2. Pull up length of the kelly. 3. Ream ahead length of the kelly. 4. Pull up length of the kelly to add single or double. 5. Put kelly in rat hole. 6. Pick up single or double. 7. Lower drill stem in hole. 8. Pick up kelly.

T 1 = ton-miles for one round trip at depth D1 (depth where drilling started after going in hole, ft) T2 = ton-miles for one round trip at depth D2 (depth where drilling stopped before coming out of hole, ft) If operations 3 and 4 are omitted, then formula 4.2 becomes:

Wm = effective weight per foot of drill-pipe, lb

Td = 2 (T2−T 1 )



M = total weight of traveling block-elevator assembly, lb

If a top-drive is used, then formula 4.2 becomes



C

= effective weight of drill-collar assembly minus the effective weight of the same length of drill-pipe, lb

B. Drilling operations

Td = (T2−T 1 ) If reaming is to be done while using a top drive, then formula 4.2 becomes Td = 2 (T2−T 1 )

The ton-miles of work performed in drilling operations is expressed in terms of work performed in making round trips, since there is a direct relationship as illustrated in the following cycle of drilling operation.

IADC Drilling Manual

C. Coring operations The ton-miles of work performed in coring operations, as for drilling operations, is expressed in terms of work performed in making round trips, since there is a direct relationship that is illustrated in the following cycle of coring operations.

Copyright © 2015

WR-A2 1. 2. 3. 4. 5. 6.

WIRE ROPE

Core ahead length of core barrel. Pull up length of kelly. Put kelly in rat hole. Pick up single. Lower drill stem in hole. Pick up kelly.

Since no excess weight for drill collars need be considered, this formula becomes:



Ts =

Analysis of the cycle of operation shows that for any one hole the sum of all operations 1 and 2 is equal to one round trip; the sum of all operations 5 is equal to onehalf a round trip; and the sum of all operations 3, 4, and 6 may, and in this case does, equal another one-half round trip, thereby making the work of drilling the hole equivalent to two round trips to bottom, which relationship can be expressed as follows: Tc

(4.3)

= 2 (T4−T 3 )

Tc = ton-miles coring T 3 = ton-miles for one round trip at depth D3 (depth where coring started after going in hole, ft) T4 = ton-miles for one round trip at depth D4 (depth where coring stopped before coming out of hole, ft) NOTE: Extended coring operations are ordinarily not encountered. D. Setting casing operations The calculation of the ton-miles for the operation of setting casing should be determined as in Paragraph 1, as for drill pipe, but with the effective weight of the casing being used, and with the result being multiplied by onehalf, since setting casing is a onewa (1/2 round-trip) operation. Ton-miles for setting casing can be determined from the following formula:



D (Lcs + D) (Wcm) D (M + 1/2 C) Ts = × 1/2 + 10,560,000 2,640,000

DM + 10,560,000 2,640,000



× 1/2

Ts

= ton-miles setting casing, ft

Lcs = length of joint of casing, ft Wcm = effective weight per foot of easing, lb’ May be estimated from data given on Table WR-11 for drill pipe or calculated as follows: W = W ( 1 − 0.015B)

Wherein:

W = weight per foot of casing in air, lb



B

= weight of drilling fluid, lb/gal from Table WR-11 or Table WR-12

E. Short trip operations The ton-miles of work performed in short trip operations, as for drilling and coring operations is also expressed in terms of round trips. Analysis shows that the ton-miles of work done in making a short trip is equal to the difference in round trip ton-miles for the two depths in question. This can be expressed as follows:

T

= T5 − T6

Wherein:

T

= ton-miles for short trip

T5 = ton-miles for one round trip at depth D5 (shallower depth) (4.4)

IADC Drilling Manual

(4.4)

Wherein:



Wherein:

D (Lcs + D) (Wcm)

T6 = ton-miles for one round trip at depth D6 (deeper depth)

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