IADC Drilling Manual, Volume 1 and 2 (12th Edition) PDF

IADC DRILLING MANUAL DM–3 DM 12TH EDITION IADC DRILLING MANUAL VOLUME 1 OF 2 IADC Drilling Manual Copyright © 2015 This is a volume of the IADC Drilling Manual, 12th edition, 1st printing. 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: 978-8-9915095-0-8 Printed in the United States of America. 1st printing. March 2015. IADC DRILLING MANUAL DM–5 ABOUT THE IADC DRILLING MANUAL, 12TH EDITION The 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. This is Volume 1 of the two-volume edition of the IADC Drilling Manual attempts to bring the best information on drilling technology and practices to rig crews, drilling engineers and rig management. The manual uses black-and-white and full-color images, videos, charts and tables to complement the text. Each of the 26 chapters of the IADC Drilling Manual is denoted by a two-letter code, “DS” for Drill String, for example. Pages, videos and illustrations are all described with this two-letter designation. For example, “Figure DS-3” indicates the third figure in the Drill String chapter. These codes are also listed on the tab dividers separating the chapters. The codes are defined in the table of contents for this manual. The IADC Drilling Manual will be an evergreen document. Should any reader see an opportunity to improve this manual, email your suggestions to [email protected]. For other IADC books, visit www.IADC.org/bookstore. Electronic versions of every chapter of the IADC Drilling Manual and other books are available at www.IADC.org/ebookstore. Or click the QR Codes below. www.IADC.org/bookstore www.IADC.org/ebookstore Important information 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. IADC Drilling Manual Copyright © 2015 IADC DRILLING MANUAL DM–7 VOLUME 1 OF 2 IADC DRILLING MANUAL Contents CHAPTER TAB Types of Drilling Rigs............................................... RT Automation................................................................ AU Bits............................................................................... BI Casing and Tubing.................................................... CT Casing While Drilling............................................... CD Cementing.................................................................. CE Chains and Sprockets.............................................. CH Directional Drilling................................................... DD Downhole Tools........................................................ DH Drill String................................................................... DS Drilling Fluid Processing.......................................... FP Drilling Fluids............................................................. FL Drilling Hydraulics.................................................... HY Drilling Practices....................................................... DP IADC Drilling Manual Copyright © 2015 Title: IADC Drilling Manual, Volume 1 and 2 (12th Edition) Table: Interactive Graphs x-axis y-axis graph title text graph digitizer Number of Cycles of Stress Stress (psi) Figure DS-8: S-N curve of mild steel shows number of cycles under stress to view text produce failure. Dogleg Angle (&#0176) for (kip) Tension (kip) Figure DS-10: Fatigue damage conditions in abrupt doglegs vs. tension for 3 view text ½-in., 13.3 lb/ft drill pipe. Dogleg Angle (&#0176) for Thousands of Tension - Thousands of feet of pipe Figure DS-10: Fatigue damage conditions in abrupt doglegs vs. tension for 3 view text feet of pipe ½-in., 13.3 lb/ft drill pipe. Dogleg Angle (&#0176) for (kip) Tension (kip) Figure DS-11: Fatigue damage conditions in abrupt doglegs vs. tension for 4 view text ½-in., 16.6 lb/ft drill pipe. Dogleg Angle (&#0176) for Thousands of Tension - Thousands of feet of pipe Figure DS-11: Fatigue damage conditions in abrupt doglegs vs. tension for 4 view text feet of pipe ½-in., 16.6 lb/ft drill pipe. Dogleg Angle (&#0176) for (kip) Tension (kip) Figure DS-12: Fatigue damage conditions in abrupt doglegs vs tension for 5- view text in., 19.5-lb/ft drill pipe. Dogleg Angle (&#0176) for Thousands of Tension - Thousands of feet of pipe Figure DS-12: Fatigue damage conditions in abrupt doglegs vs tension for 5- view text feet of pipe in., 19.5-lb/ft drill pipe. Percent Fatigue Life Expended in a 30-foot Length of Drill Pipe Below Dogleg Figure DS-13: Fatigue damage conditions in gradual doglegs vs tension in a view text Interval for (103 ft) (103 ft) non-corrosive environment. Percent Fatigue Life Expended in a 30-foot For Drill pipe 3-1/2 in. Tension in Figure DS-13: Fatigue damage conditions in gradual doglegs vs tension in a view text Interval for (kip) Drill Pipe in Dogleg (kip) non-corrosive environment. Percent Fatigue Life Expended in a 30-foot For Drill pipe 4-1/2 in. Tension in Figure DS-13: Fatigue damage conditions in gradual doglegs vs tension in a view text Interval for (kip) Drill Pipe in Dogleg (kip) non-corrosive environment. Percent Fatigue Life Expended in a 30-foot For Drill pipe 5 in. Tension in Drill Figure DS-13: Fatigue damage conditions in gradual doglegs vs tension in a view text Interval for (kip) Pipe in Dogleg (kip) non-corrosive environment. Percent Fatigue Life Expended in a 30-foot Length of Drill Pipe Below Dogleg Figure DS-14: Fatigue damage conditions in gradual doglegs vs tension in a view text Interval for (103 ft) (103 ft) corrosive environment. Percent Fatigue Life Expended in a 30-foot For Drill pipe 3-1/2 in. Tension in Figure DS-14: Fatigue damage conditions in gradual doglegs vs tension in a view text Interval for (kip) Drill Pipe in Dogleg (kip) corrosive environment. Percent Fatigue Life Expended in a 30-foot For Drill pipe 4-1/2 in. Tension in Figure DS-14: Fatigue damage conditions in gradual doglegs vs tension in a view text Interval for (kip) Drill Pipe in Dogleg (kip) corrosive environment. Percent Fatigue Life Expended in a 30-foot For Drill pipe 5 in. Tension in Drill Figure DS-14: Fatigue damage conditions in gradual doglegs vs tension in a view text Interval for (kip) Pipe in Dogleg (kip) corrosive environment. Yield Point lb/100 square ft Effective viscosity, K (cp) Figure FP-1: Effective viscosity vs Yield Point. view text IADC Drilling Manual, Volume 1 and 2 (12th Edition) © 2015 International Association of Drilling Contractors (IADC) 1 RT TYPES OF DRILLING RIGS IADC Drilling Manual 12th Edition IADC Drilling Manual Copyright © 2015 GAINING GROUND OFFSHORE CAMERON’S TOTAL RIG PACKAGE SOLUTIONS FLOW EQUIPMENT LEADERSHIP Cameron’s Topside Equipment Packages: Proven Solutions SMARTRACKER™ Highlights Cameron offers rig equipment solutions that include world-class products, technology, services Fully automated tripping and stand-building sequences and support. Demand for our topside packages is steadily growing around the globe. Since Cameron entered the complete package market in 2011, we have secured dozens of topside 3-1/2" to 14" tubulars with no head or die changes equipment package orders for jackup drilling rigs during this period. With innovative, high- Quiet, high-precision performing, cost-effective Total Rig Package Solutions, Cameron is the obvious alternative to AC motor technology the status quo and will continue making waves in the market. Overhead HSE focus built in Intuitive controls with integrated Learn more at: www.TheMomentumIsBuilding.com safety management AD01335DRL RAISING PERFORMANCE. TOGETHER™ TYPES OF DRILLING RIGS RT-i CHAPTER RT TYPES OF DRILLING RIGS he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with T 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 mainte- nance and repair. 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 ad- vance 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 war- rant 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 Mark Dreith, Dreith Working Interests LLC Shane Lalumandier Reviewers Alan Spackman, IADC Joe Hurt, IADC RT-ii TYPES OF DRILLING RIGS 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: 978-0-9909049-5-3 IADC Drilling Manual Copyright © 2015 TYPES OF DRILLING RIGS RT-iii CHAPTER RT TYPES OF DRILLING RIGS Contents Introduction......................................................................RT-1 Semisubmersibles RT-8 Land Rigs RT-1 Drillships RT-9 Fit-for-purpose rigs RT-1 Conclusion RT-10 Walking rigs RT-2 References RT-11 Offshore rigs RT-3 IADC Drilling Manual chapters RT-11 Platform rigs RT-3 IADC Deepwater Well Control Guidelines RT-13 MODU types RT-4 IADC Health, Safety and Environmental Posted barges and submersibles RT-6 Reference Guide RT-13 Jackups RT-7 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 TYPES OF DRILLING RIGS RT-1 Figure RT-2: At top is a mast being raised by the bull lines and drawworks (Courtesy Nabors Industries Ltd.). The photo below shows the mast being raised by hydraulic cylinders (Courtesy Precision Drilling Oilfield Services Corp.). Figure RT-1: With the advent of steel rig construction, derricks were replaced by masts. A mast has fewer pieces to assemble and a smaller footprint than a derrick. Importantly, it remains open on one side, allowing traveling equipment to run freely up and down and has fewer pieces to assembly. IADC image. Introduction This chapter will explain the various types of drilling rigs used today. It will try to touch on the unique features of each rig type and their relative advantages and drawbacks. This structure be abandoned at the well site. Now, rigs could be chapter is not meant to be an exhaustive narrative on each moved from site to site, a major advantage. To enhance rig rig type, but strives to provide the reader with an overview of mobility, the original, bulky derrick was replaced with masts. each. The one overriding theme that holds true, regardless A mast has fewer pieces to assemble and a smaller footprint of rig type, is that the drilling industry has made big changes than a derrick. Importantly, it remains open on one side, al- in the design and layouts of all rig types to improve safety lowing traveling equipment to run freely up and down and for the people working on these rigs, safeguard the envi- has fewer pieces to assembly. ronment, and improve the efficiency to minimize the time it Once on location, masts can be raised either by bull lines takes to construct the well. and the drawworks or by using cylinders. Cylinder-raised masts feature 2-3 fully constructed sections that pin togeth- Land rigs er before the hydraulic cylinders raise them or a two-section As mechanization made the hunt for hydrocarbons more ef- telescoping mast where the top section is telescoped up af- ficient, it had a direct effect on land rig design. The first land ter raising. rigs were permanent wooden structures and would be left in place after the well was drilled. Many were just tall poles or Fit-for-purpose rigs simple V-frame structures. As well depth increased, drilling Drilling rigs often go where few people wish to venture, required stronger structures and rig construction from steel such as burning deserts and frozen tundra. Because few became the norm. or no highways exist to transport rigs in deserts, industry designed fit-for-purpose rigs. To move these rigs across the Fabricating rigs from steel meant that no longer would the IADC Drilling Manual Copyright © 2015 RT-2 TYPES OF DRILLING RIGS Video RT-1: Views of modern Arctic rig. Courtesy Bentec. sands, the entire drilling structure is placed on wheels, many of which can reach 12 ft in height. The huge wheels allow the rig to be pulled to the next location by truck or tractor. Figure RT-3a: Winterized Arctic rigs are often modular in design and capable of skidding from Industry has adapted the “standard” drilling rig for other wellhead to wellhead. Courtesy Bentec. specialized environments. For example, Arctic rigs are win- terized, with heating and cooling systems for the rig floor, drillpipe and casing storage and other areas. Often modular for easier fabrication, Arctic rigs are often capable of skid- ding from wellhead to wellhead. With current mechanization, wells on land can be drilled in as little as 14 days, and drilling speed is now a rig design fac- tor. However, this rig complexity has increased the share of rig moving time, relative to total operating days. Drilling con- tractors today often seek designs that shorten rig-up times. Walking rigs Industry’s improved understanding of accessing tight-per- meability formations, especially shale rock, has also impact- ed rig design. In today’s shale operations, many wellsites are configured for multi-well drilling. The entire rig mast and substructure walks or “skids” short distances to the next lo- cation. As a consequence, rigs require additional structural reinforcement, adding weight and increasing design com- Figure RT-3b: Desert drilling rigs were purpose built to Figure RT-4: Trailer-mounted rig working on location. traverse the roadless sands of this tough environment. Courtesy Drillmec Drilling Technologies. Note the size of the tires relative to the people in the foreground. Courtesy Nabors Industries Ltd. IADC Drilling Manual Copyright © 2015 TYPES OF DRILLING RIGS RT-3 Figure RT-5: One of the latest trends is “walking” rigs, used in multi-well locations to access drill sites that might be 100 ft apart (left). Photo above shows a close up of a rig “foot”. Photo at left courtesy Entro Engineering. Photo above an IADC image. they were mounted at the end of piers protruding into the ocean. Platform rigs have come a long way since then, and other types of marine rigs evolved to meet varying water depths and other environmental demands offshore. Platform rigs As industry stepped out beyond the reach of land-based piers, platform rigs were installed on large steel “jackets”, the bottom-supported frames supporting the rig substruc- ture, derrick and, often, fluid-processing equipment for pro- duced oil or gas (Figure RT-6). Video RT-2: Example of walking rig. IADC video of Wisco Moran drilling rig. Platform drilling rigs themselves are essentially of the same type and construction as land based rigs, with BOPs on sur- plexity. However, the mud system does not move with the face verses subsea, and special considerations to minimize mast and substructure, as with desert rigs. Consequently, weight that needed to be supported by the platform. De- heavy and complex festoons and flowline systems are being pending on the size and capacity of the particular platform, added to allow the rig to “walk” 100 ft without rigging down. if it was not of sufficient size to support the complete drill- ing package, plus all of the equipment, materials, and liq- The search for the land rig design that accommodates all uids necessary for the drilling operation, the use of a tender the latest drilling equipment and can still move quickly from vessel was often required. The tender vessel, be it a barge, wellsite to wellsite continues. Today, the industry box-on- semisubmersible or ship, would maintain station alongside box substructures, telescopic substructures, as well as de- the platform, and all of the necessary manpower, electrical signs featuring cantilevered masts in which the mast and power, mud pumping capacity, equipment and materials rig floor are elevated in a single step. (This was originally stored/located on the tender is transferred to the platform introduced as the “Dreco Slingshot”). Rigs are being built to rig as required. handle single stands of drillpipe, as well as doubles and tri- ples. Many of the smaller single style rigs being mounted on With the advent of extended-reach and horizontal drilling, trailers for easy transport. enabled by steerable drilling technology, a significant number of wells (typically 8, 12, or 16) could be drilled from a single Offshore rigs platform, maximizing oil recovery. Platform drilling rigs were Explorers began finding and drilling for oil in the ocean early deployed onto these large platforms. in the 20th Century. The earliest offshore wells were drilled Eventually, drilling operations proceeded in water far too by equipment that differed little from land rigs, except that deep to ever land a bottom-supported steel jacket. Indus- IADC Drilling Manual Copyright © 2015 RT-4 TYPES OF DRILLING RIGS Figure RT-9: Example of tender-assist rig. Figure RT-6: Platform rig. try adopted different approaches, the most popular design being the tension-leg platform. A TLP uses a floating plat- form, much like a semisubmersible, permanently moored to the sea floor. Figure RT-8 shows Shell’s Olympus TLP, over the Mars field in about 3,000 ft of water in the US Gulf of Mexico. Tender-assist platform rigs Older versions of the tender-assist type platform rigs uti- lized a moored barge alongside the platform, with a ramp that led from the barge to the platform for dragging mate- rials (tubulars) onto the drill floor. This ramp was also used for personnel transfer to and from the platform. However, traversing the ramp in rough weather could result in person- nel injury. Figure RT-7: As industry stepped out into deeper water, On modern tender-assist vessels, the deployment of an platform rigs were installed on large steel “jackets”, the articulated/telescoping walkway is used to safely transfer bottom-supported frames supporting the rig substructure, personnel between the platform and the tender vessel. derrick and, often, fluid-processing equipment for produced oil or gas. This jacket was constructed for Shell’s MODU types Bullwinkle platform in the US Gulf of Mexico. The jacket Today’s MODUs fall primarily into four water-depth catego- was landed in 1988 in 1,360 ft of water, setting a world ries: record for deepest water for a production platform. Shallow water: Either sitting on bottom in water depths ranging from very shallow to 300-400 ft, or floating with a traditional mooring system in 400-1,000 ft; Mid-water: Primarily using a traditional mooring system attaching the hull/barge to the ocean floor with chain/wire/rope to maintain stationkeeping, in water depths ranging from 1,000-4,000 ft; Deepwater: Primarily using a dynamic position system to maintain the rig over the well center, with some specialized mooring systems in water depths from 4,000-7,500 ft; Ultra-deepwater: Exclusively dynamically positioned stationkeeping for water depths in Figure RT-8: The tension-leg platform can drill and excess of 7,500 ft. Current rig designs have a produce in deepwater. The Olympus TLP sits above 3,000 maximum water depth rating of 12,000 ft. ft of water in the US Gulf of Mexico. Courtesy Shell. IADC Drilling Manual Copyright © 2015 TYPES OF DRILLING RIGS RT-5 Figure RT-10: At left is a typical BOP for land operations (Courtesy Cameron). At right, a rendering of a subsea BOP stack. Courtesy Maersk Drilling. The move to deepwater locations required placing the blow- surface allows drilling fluids and wellbore cuttings to be re- out preventer (BOP) on the ocean floor. This “subsea” BOP turned to the surface for treatment and recirculation. This stack initially used a conventional method for controlling riser pipe is made from high-tensile steel, traditionally fabri- the BOP functions from the MODU. In shallow water and cated in 50-ft lengths. Wall thickness in the older riser sys- mid-water depths, this is accomplished using a straight hy- tems ranged between ½-⅝-in. wall thickness. More modern draulic system in which hydraulic fluid was pumped down deepwater risers come in lengths of 75 ft or longer, with wall the umbilical lines to the control pods located on the top of thicknesses of 1 in. or more. These changes were driven by the BOP stack. The subsea stack comprises the same con- the tremendous tensions required at the top, and the sig- ventional hydraulic rams and annular bags, without the add- nificant external pressures pushing in on the tube at deep- ed component of the lower marine riser package (LMRP). water depths. Typical top tensions pulled from the surface The LMRP allows the driller to pull the control pods to the rig range from 3,000-4,000 kips to keep the riser straight surface without removing the critical hydraulic rams from and vertical in the water column. Buoyancy modules are the wellhead on the ocean floor. (For a more complete dis- also attached to the riser to decrease the weight in water of cussion of LMRP, read the separate Floating Drilling Equip- these massive tubes. Drilling in deepwater and high currents ment and Operations Chapter of the IADC Drilling Manual, requires special considerations to eliminate vortex-induced 12th edition, or the IADC Deepwater Well Control Guide- vibrations (VIV), similar to the spiral cowlings found on the lines.) top of tall exhaust stacks on land. With the move to deepwater and ultra-deepwater depths, Today’s modern drilling techniques require more capacity, emergency hydraulic power is stored in subsea accumula- higher flow rates, and better cleaning abilities for the latest tors attached to the subsea BOP stack. Controls went from drilling fluids. It is not unusual to have two separate mud pure hydraulics to multiple electronic controls (“multiplex” systems on a modern deepwater rig, and even have the abil- or “MUX”) to account for the increased pressures in deep- ity to connect a completions fluid system into the circula- water. tion system onboard. While two mud pumps have sufficed in the past, most modern deepwater rigs are outfitted with A riser pipe running from the top of the LMRP to the rig on IADC Drilling Manual Copyright © 2015 RT-6 TYPES OF DRILLING RIGS A C B Figure RT-11: Marine riser pipe (A), marine riser pipe with buoyancy modules installed (B) and riser pipe with strakes designed to minimize vortex-induced vibrations (C). Images A and B courtesy GE Oil & Gas. Image C courtesy Balmoral Offshore Engineering. Figure RT-12: A posted barge is an elevated structure built above a submersible barge that is ballasted down at the drilling location and generally pinned to the bottom using piles at the corners which are driven into the seabed. Figure RT-13: A submersible is a purpose-built rig that either has a mat or large ring pontoon at the bottom, four and sometimes five mud pumps to increase redundanc- and columns that support the upper hull structure. The ey and provide additional fluid flow and for some of today’s vessel is floated out to the drilling location, and ballasted downhole steerable tools. For removing cuttings and clean- down so that mat or ring pontoon rests on the bottom. ing the drilling fluid (“mud”) that returns to the rig from the ed structure built above a submersible barge that is ballast- wellbore, today’s rigs feature 6- 8 modern shakers. This has ed down at the drilling location, and generally pinned to the led to larger and more capable rigs, as the methods to drill bottom using piles at the corners driven into the seabed. The today’s wells have evolved. elevated structure contains all the personnel accommoda- tion, power generation, liquid storage, mud pumps, equip- Posted barges and submersibles ment and material storage necessary to drill the well. The Both posted barges and submersibles are bottom-founded drilling package is generally located at one end of the barge, rigs that operate in relatively shallow water. Posted barges and is either cantilevered over the end, or a slot is built into can typically operate in 8-20 ft of water, while submersibles the barge to accommodate the well center. Much like the can operate in 10-70 ft of water. A posted barge is an elevat- land rigs, a surface BOP is used for well control. IADC Drilling Manual Copyright © 2015 TYPES OF DRILLING RIGS RT-7 A submersible is a purpose-built rig that either has a mat or large ring pontoon at the bottom, and columns that sup- port the upper hull structure. The vessel is floated out to the drilling location, and ballasted down so that a mat or ring pontoon rests on the bottom. As with the posted barges, submersibles are pinned to the ocean floor at the corners. The upper hull stays elevated above the environment and supports the drilling operation. Both posted barges and submersibles are primarily used in exploratory drilling, and only a single well can be drilled from each set-up location. Jackups Jackup drilling rigs are also supported by the ocean floor. Jackups can be supported either by legs that can be raised or lowered independently or by legs attached to a large mat resting on the ocean floor. Once on location, the hull of the entire rig is lifted out of the water by a jacking mechanism. This is most commonly accomplished by multiple pinion drives climbing up the rack, which is part of the leg struc- ture. An alternative is “single bite” hydraulic cylinders, which raise the hull, one 8-10-ft stroke at a time. The jackup’s hull is typically raised above the ocean until achieving an “air gap” of some 50-70 ft or more. (The air gap is the distance from the mean water level to the bottom of the jackup’s hull.) This puts the hull of the rig above any significant storm waves. When Hurricane Katrina moved through the jackup fleet offshore Louisiana in August 2005, the storm generated wave heights estimated at 70 ft. There is solid evidence that jackups with air gaps less than 70 ft were literally sheared off their legs, while jackups with larger air gaps sustained far less damage. Figure RT-14: At top (Figure RT-14a) is a mat-supported jackup, while the jackup on the bottom (Figure RT-14b) Mat-supported jackups are better suited to areas with soft features independent legs. Note also the air gap on the material on the ocean floor. They are far easier to “preload” mat-supported jackup. Courtesy Hercules Offshore Inc. than are the independent-leg jackups. When a jackup arrives on location and its legs or mat are jacked down to the ocean floor, a “preload sequence” is conducted in which seawater in brought onboard the vessel and placed into tanks. This additional weight is used to push the legs or mat into the seabed to establish a stable platform, prior to jacking up to the drilling air gap. The objective of the preload sequence is to simulate the maximum vertical loading that any single leg will see during the worst anticipated loading condition (in- cluding environmental loading), while the rig is on location. Once the required amount of seawater has been brought onboard, and no more leg settlement (penetration into the ocean floor) is experienced, the seawater is discharged back into the ocean, and the jackup is raised to its drilling air gap. Some of the earlier jackups were built with a slot in the aft Figure RT-15: Note the slot on the left of the rig on this slot-type jackup. The derrick had been removed from end of the hull, and the drill floor package was located above this rig, because it was converted to a non-drilling unit. this slot in a fixed position. This allowed for only a single well IADC Drilling Manual Copyright © 2015 RT-8 TYPES OF DRILLING RIGS to be drilled from each drilling location, which was acceptable in the early days of exploration. The limitations of this single well per location led to the installation of the cantilever-type drilling pack- age, in which the drilling package is located atop large beams that can be skidded or jacked aft. This allows greater flexibility and the ability to drill mul- tiple wells from a single location. These cantilever jackups also incorporated the ability to move the drilling package transversely atop these large can- tilever beams. The extended-reach cantilever jackups became the tool of choice for oil companies wishing to economi- cally recover hydrocarbons in a given field. After the initial hydrocarbon field discovery, the oil compa- ny would erect a smaller platform, with an 8-, 12-, or 16-well grid located at one end of the platform. With a jackup located next to the platform, the der- rick cantilevers out over the platform to drill and/or rework wells on the platform grid. Early cantilever envelopes made it feasible to reach wells that were located 10-50 ft aft of the transom, and 10 ft on ei- ther side of the rig’s centerline. This represents a 20 ft by 40 ft drilling envelope. Modern jackups have extended-reach capabilities of 75 ft and 15-20 ft of transverse capability. This extended the drilling en- velop to 40 ft by 65 ft. Figure RT-14a is an example of a cantilever jackup. As the search for hydrocarbons moved into ev- er-deeper waters, the capabilities of jackup drilling rigs moved deeper, as well. Typically, early jackups could drill in shallow waters in water depths up to 200-250 ft. In the 1980s, the upper limit in water depths was approximately 300 ft. Today’s modern jackups are designed to drill in water depths of 450- 500 ft. Semisubmersibles Semisubmersible MODUs come in all shapes and sizes. This rig type is characterized by a lower hull (either separate pontoons or a ring pontoon) with a number of vertical columns supporting a large up- per hull. In most cases, the lower pontoons contain liquid storage, while personnel accommodation, power generation, and equipment/material stor- age is in the upper hull. The drilling package on a semisubmersible can either be centered in the up- per hull or set to one end. Figure RT-16: Semisubmersibles are characterized by a lower hull of either separate pontoons or a single ring pontoon with Once the rig is on the drilling location, the lower numerous vertical columns supporting a large upper hull. Top photo pontoons are ballasted down (i.e., “submerged”) Courtesy Diamond Offshore Drilling Inc. Center photo courtesy Noble Corporation. Bottom and inset photos courtesy Seadrill. so that the vertical columns are sticking out of the IADC Drilling Manual Copyright © 2015 TYPES OF DRILLING RIGS RT-9 water, supporting the upper hull struc- ture. Because the semi is floating, it will ride up and down with the waves. Con- sequently, it does not require the same magnitude of air gap as jackups. The semi’s configuration minimizes the en- vironmental loading and resulting heave, pitch and roll of the rig, compared to a ship-shaped hull, providing a relatively stable platform for drilling operations. Semisubmersibles have historically been used in the mid-water depths (1,000- 4,000 ft), and traditionally were moored on the drilling location using a fixed 8-point mooring system; comprised of anchors, chains, and/or wires to main- tain station. Using a fixed mooring sys- Figure RT-17: The ultra-deepwater drillship shown above was tem does not allow the driller to turn the designed for operations in water depths to 12,000 ft, with a 40,000- ft well-depth capability. Courtesy Atwood Oceanics Inc. rig into the weather, and for this reason, the smaller water plane area of the ver- tical columns minimized vessel motions could visually see his position and manually maintain station when the variable storm directions hit the rig on the beam. over the well. This was the birth of dynamic positioning. Early semis were not equipped with thrusters, and the in- stallation of thrusters were first used for “mooring assist” to Over the next half-century, the size and sophistication of drive the rig into the weather, to decrease the mooring load drillships evolved dramatically. Most of the early drillships on the highest loaded moorings. used traditional 8-point mooring systems to maintain sta- tion. If the wind/wave direction were always taken directly As the search for hydrocarbons moved out into deep water, on the bow of the ship, vessel motions would be very good. the size and capacity of the semisubmersibles grew also. However, winds and waves rarely come from the optimum Variable deck load (VDL) is an important determinant for heading at all times. Because a drillship anchored by an water-depth capability. As a semi moves into deeper water, 8-point mooring pattern cannot turn into the weather, the it obviously must carry more riser and drillpipe to reach the vessel’s motions became excessive when the weather im- ocean floor. As a result, a deepwater rig must be able to car- pacts the ship from the beam. This was a major reason why ry more weight than one in shallower water. This means the the vessel motions of fixed-mooring semisubmersibles were deepwater rig must have higher VDL. For a rough compar- superior to fixed-mooring drillships. ison, a mid-water semi would typically have a VDL in the 3,000-4,000-long ton range, while the VDL of a deepwater Today’s drillships are nearly three times the size of the orig- semi typically ranges from 7,000- 8,000 long ton. inal CUSS 1. While conventional mooring is still feasible in the mid-water depths, dynamically positioned ships must Along with the move to deeper water, semis were being be used in deepwater. DP systems use a sophisticated ver- equipped with full dynamic-positioning systems, allowing sion of the now-ubiquitous Global Positioning System (GPS). the rig to stay on location without installing a multi-point This has been enhanced with modern acoustic systems that mooring system. hear “pingers” which are placed on the ocean floor. This ad- ditional redundancy, combined with modern software, allow Drillships the drillship to maintain station in up to 70-knot beam seas, The first purpose built “drillship” was the CUSS 1,which was within a offset of only a few feet. deployed and drilled her first well in 1956. In March 1961, when the scientific community was looking for confirmation Drillships were the original tool of choice for the drillers, as of the “Mohorovicic discontinuity” (the boundary between they have the largest deck load capacity (VDL) of any of the the earth’s crust and mantle), the MOHO Project was un- rig type designs. While the mid-water semi has a 3,000- dertaken by the CUSS 1 and successfully recovered a core 4,000-long ton VDL capacity, a mid-water drillship is on of the earth’s crust from 11,000 ft depth in 3,100 ft of water. the order of 8,000-10,000-long ton VDL capacity. When The drillship was fitted with four “steerable thrusters” and loading up all the materials to head out to location to drill used a set of submerged buoys and sonar so that the “pilot” a well, this much larger VDL capacity made the drillship the IADC Drilling Manual Copyright © 2015 RT-10 TYPES OF DRILLING RIGS obvious choice. The oil company operating the well, had to days. Some drillers have increased the heights of their der- make fewer trips with supply vessels to replenish the on- ricks to allow “quads” rather than “triples” of drillpipe to be board supplies. tripped in and out of the hole. This reduces the number of connections that must be made up and broken out by about Ultra-deepwater drillships 25%. The drive to increase efficiency and decrease NPT When the goal is to drill a well in more than 10,000 ft of wa- were among the key design features of modern ultra-deep- ter, the tool of choice is the ultra-deepwater drillship. water drillships. Being exclusively dynamically positioned, ultra-deepwater In most modern well construction, both water-based, and drillships can maintain station and rotate the ship over the non-aqueous fluids, such as oil-based or synthetic fluids, are well center to head the ship into prevailing weather, follow- used. When changing over from water-based to non-aque- ing shifts in wind or wave direction. This minimizes the pitch ous fluids, fluid storage pits must be cleaned, if limited to and roll motions of these large drillships. The number and one set of storage pits. Cleaning mud pits also means that size of the engines and thrusters help determine the ship’s personnel must enter enclosed spaces, which can be a safe- stationkeeping ability. ty hazard. It’s far more efficient to install two separate fluid storage systems, allowing fluid switchovers without entering Industry has learned from experience that a dynamically po- and cleaning the tanks. With the large VDLs and liquid-stor- sitioned vessel must be able to maintain station in the face of age capacities available on ultra-deepwater vessels, most a 61-knot beam wind. Howard Shatto, considered the father drilling contractors have designed their rigs to accommo- of dynamic positioning, developed a standard by which a dy- date dual mud systems, eliminating the need to clean tanks namic-positioning system is easily gauged. Using the ratio of between different sections of the well. Again, this decreases 80% of available thruster power (i.e., with one of five pow- the NPT and improves safety and efficiency. er-generating engines down) and dividing that by the force of a 61-knot beam wind pushing on the vessel results in a di- The drive into ever-deeper water combined with longer hor- mensionless ratio called the HSSC Number (Howard Shatto izontal and directional sections means that more drillpipe Sanity Check). “HSSC” is pronounced “his sick”. (The force must be used and handled by the rig, resulting in larger loads of the 61-knot beam wind depends on rig size and configura- for the derrick to handle. Correspondingly, derrick capacities tion.) This easily derived ratio provided industry with a quick to support these larger loads have sharply increased. The check on a dynamic-positioning system’s ability to maintain old standard of 1.5 million lb gross nominal capacity (GNC) station in real world events. A HSSC Number greater than was insufficient to support the weight of BOP and riser at or equal to 1.0 means that the dynamic positioning system ultra-deepwater locations. Derrick’s of today’s ultra-deep- should be able to maintain station. The consequences of be- water drillships boast lifting capacities of 2.5-3.0 million lb ing blown off location are high from both environmental and GNC or higher. Derrick configurations have also changed economic perspectives. Should an ultra-deepwater rig lose with the introduction of redundancy on the rig floor to allow location, whether due to weather or a DP-system malfunc- offline activities for increase efficiency and lower NPT. Der- tion, the driller must disconnect the riser from the subsea ricks capable of handling offline running of riser and casing BOP, thereby dispersing the riser’s contents along the ocean are becoming standard in today’s ultra-deepwater drill-floor floor. Clearly, avoiding such situations is critical. construction, using a second set of tubular handling equip- ment (drillpipe, casing, and riser), second drawworks, and These tanker-sized ships have very large VDLs to allow second rotary table. The increased efficiency from this du- for increased storage of equipment and materials to drill ality of equipment has clearly helped reduce the NPT during ultra-deepwater wells. One of the most significant design ultra-deepwater well construction. goals for this rig type was increased efficiency for all oper- ations. With the ocean floor nearly 2 miles below the ship’s As hookloads have increased, so has the rating of the trav- hull, standard operations had to become more efficient to eling equipment in the derricks that carry these loads. The minimize “non-productive time” (NPT). Relatively simple old standard of 750 short ton traveling equipment soon gave operations, such as running the BOP and riser to the ocean way to 1,000-ton equipment, and today is pushing toward floor, can take days, rather than hours on deepwater wells. capacities of 1,250-1,500 short ton. In addition, drillpipe capacity for use in ultra-deepwater wells has increased as As an example of reducing NPT, increasing the length of the well. The old standard 5-in. diameter drillpipe soon gave way individual riser joints from 50 ft to 75 ft or longer, decreased to 5 ½-in. and even 6 ⅝-in. diameter drillpipe. As drillpipe the number of time-consuming connections between the diameter increased, the length of the individual joints of riser joints by one-third or more. In addition, redundancy on drillpipe has generally remained as API Range 2 (27-30 ft), the drill floor allows drillers to run and retrieve the BOP and with some drillers using API Range 3 (38-45 ft) to further riser off the critical path of building the well, which can save decrease NPT. Handling this drillpipe and combining them IADC Drilling Manual Copyright © 2015 TYPES OF DRILLING RIGS RT-11 into “stands” of multiple pipes have become more efficient, as well. Offline stand building has replaced the old standard References For more detailed information on these and other aspects of pulling single joints up the V-door to add to the drill string. of drilling equipment, practices and technology, refer to ad- Some drillers have used both horizontal and vertical storage ditional chapters of the IADC Drilling Manual and to other of full drillpipe stands to increase efficiency and options for IADC references. Visit www.IADC.org/bookstore or www. tripping drillpipe into and out of the well. IADC.org/ebookstore. All IADC works are copyright IADC, In addition to the change from straight hydraulic control sys- all rights reserved. tems to multiplex (electronic) controls due to the increased hydrostatic pressure in the ultra-deepwater, the overall rat- IADC Drilling Manual chapters ing of BOPs has increased. In recent years, BOP capacity has Chapters of the IADC Drilling Manual, 12th edition, are avail- increased from a standard of 10,000 psi to 15,000 psi as able as ebooks and within the complete printed manual: Automation: Overview of automated drilling formation pressures increase. Many of the latest deepwater operations, impact on rig crew, control and monitoring, drillships under construction, are designed for 20,000-psi drilling network evolution and examples of automation. BOPs. As discussed earlier, running and retrieving BOPs in Bits: Discusses bit design, lubrication and pressure ultra-deepwater can be measured in days rather than hours. compensation, cutting structures, TSP cutters, nozzle A problem with the BOP or its control system will add days and plug installation and removal, mechanical specific of NPT, not to mention the time it takes to actually fix the energy (MSE), monitoring drill parameters, dull grading problem. For this reason, many current ultra-deepwater and evaluation, storage, repairs, calculations, safety, drillships being built are designed to accommodate two governing standards and guidelines, and more. complete BOPs on deck. This allows the spare or stand- Casing and Tubing: Covers casing and tubing handling by BOP to be completely tested and ready to be deployed, and storage on drilling rigs. The chapter covers pipe should a problem develop with the subsea BOP. types, OCTG materials, corrosion, API casing grades, OCTG marking, transportation, handling, storage and Early in the evolution of ultra-deepwater drillships, there running procedures and equipment. was a perceived need to store crude oil, generated from ex- Casing While Drilling: Covers the range of CwD technology and operations. Topics include both tended well testing, onboard the rig. Some of the early de- retrievable and non-retrievable CwD, as well as liner signs incorporated the ability to store 300,000-400,000 drilling and retrievable liner drilling. bbl, or more. However, this crude oil storage and offload- Cementing: Discusses types of and reasons for ing capability has very rarely been used on ultra-deepwater cementing; preparing the well for cementing; job wells, and current rigs are not being designed and built with design, pumping and displacing cement; waiting on this capability. cement and post-job rig operations; cementing strings and hardware, including casing running tools; cement However, ultra-deepwater drillships have also been tasked evaluation; and conducting safe cementing operations. with erecting, testing and deploying subsea Christmas trees. Chains and Sprockets: Covers chain construction and These installations are provided for the day when the oil specifications, applicable standards, roller-chain company returns to produce one of these deepwater wells. numbering and dimensions, sprockets, installation, lubrication and maintenance. Directional Drilling: Reviews the evolution of Conclusion directional drilling, from the earliest days to the present; The type of rig to be employed depends on location and ex- magnetic and gyroscopic sensors; essentials of pected well-construction requirements. Whether on land directional surveying, including anti-collision; defining or in extreme water depths around the world, the push for subsurface targets; surface considerations; trajectory increasing personnel safety, decreasing environmental im- design; well profiles; deviation control; bottomhole pact, and reducing time to drill and complete the well are the assemblies; deflection and measuring tools; bits; and ultimate factors driving design. more. Downhole Tools: Provides a sweeping discussion of numerous important downhole tools. Content includes details on borehole enlargement; circulating subs; downhole mud motors; air hammers; rotary steerable systems; vibration, torque and drag; measurement while drilling; logging while drilling; wireline logging; and jars. Drill String: Contains brand new sections on heavyweight drillpipe, safety valves and accessories, wired drillpipe and more. Color photographs clearly IADC Drilling Manual Copyright © 2015 RT-12 TYPES OF DRILLING RIGS identify common drillpipe problems. Included for the underbalanced and air/gas/mist/foam drilling. Covers first time are proprietary drillpipe tables from IADC- drivers and all variations of MPD, including constant member manufacturers. bottomhole pressure, pressurized mud cap drilling, Drilling Fluids: Provides general information on drilling continuous circulation devices, dual-gradient and fluids for rig workers and early career professionals. riserless drilling, deepwater applications of MPD, air Covers purpose and functions of drilling fluids; basic hammer drilling, and more. testing and properties; categories, systems and Pumps: Entirely rewritten to cover both mud pumps and additives; maintenance, contamination and related centrifugal pumps. Each section is split between the problems; calculations, units conversions and useful two types of pumps for easy reference.Provides field tables; safety and hazards, regulations, safety data descriptions and basic theory, safety and handling, sheets and labeling; and additional reference materials operations and applications, general maintenance, and for more in-depth studies. important calculations. Includes a glossary, references, Drilling Fluids Processing: A comprehensive guide to and new color illustrations and photos. reducing drilling-fluid and overall well costs through Power Generation and Distribution: Features the latest proper solids-control techniques. Covers dilution, information on emissions standards and regulations. A chemical and mechanical separation, equipment brand-new section discusses design, operation and arrangement,, weighted and unweighted drilling-fluid maintenance of variable-frequency drives.Covers processing, screen labeling, shakers, degassers, engines, generators and transmissions, fuels, hydrocyclones, desilters, desanders, mud cleaners, installation, operations, shutdown, maintenance, centrifuges, lost circulation, sizing mud systems and storage and safety. Power distribution covers DC/DC steel pits, and much more. and SCR systems, DC drilling motors, SCR (AC/DC) Drilling Hydraulics: Discusses what is covered by the VFD, and DC/DC, including operations, design, theory broad term “hydraulics”, as well as briefly describing and maintenance. hydraulic-related equipment. Hydraulic parameters, Rotating and Pipehandling Equipment: Written and such as density, viscosity, yield point, rheology models, compiled by 26 subject matter experts, the brand-new flow rate and fluid velocity are covered. Velocity and Rotating and Pipehandling Equipment chapter covers circulation rate determinations for both duplex and the full range of equipment, including operations and triplex pumps are discussed. Applications of hydraulics, maintenance. Topics include top drives, hoisting and including estimating bottomhole pressure and wellbore running in, pipehandling, make up/break out, racking, pressure management are covered, as is annular auto-handling, tubulars, drawworks, elevators, casing velocity. running tools, power catwalk, manual and power tongs, Drilling Practices: A straightforward explanation of the instrumentation, maintenance and inspection, and causes of troublesome drilling problems and how to more. avoid and overcome them. Covers bit and drilling Special Operations: This new addition to the IADC dysfunctions,reaming for hole conditioning, hole Drilling Manual covers tricky operations, including cleaning in directional and horizontal wells ,tripping drilling highly depleted sands, coalbed methane practices in horizontal and directional wells, wellbore formations, permafrost, and geothermal wells. Also stability, lost circulation and more. discusses solid expandable liner technology and covers Floating Drilling Equipment and Operations: Covers open-hole fishing operations in detail. The fishing equipment and procedures specific to floating drilling section includes job planning, stuck-pipe mechanisms, operations, with a focus on deepwater. Topics include estimating stuck point, string-stretch formula, and stationkeeping, power systems, tubular and marine much more, including a review of fishing tools and riser handling and tensioning, subsea well control, techniques. motion compensation, cargo operations, emergency Structures and Land Rig Mobilization: Describes types disconnects and more. of structures and provides detailed guidance on their High Pressure Drilling Hoses: Includes an overview of maintenance, inspection, storage and safety. A new, hose types, mechanical properties, care and dedicated section on land rig mobilization addresses maintenance, inspection and testing, and a special pre-move planning, rigging down, and rigging up. The section on flexible choke-and-kill hose and flexible section also includes a discussion on rig-walking well-test hose. systems. Lubrication: Discusses wear mechanisms and types of Well Control Equipment and Procedures: Covers the lubrication. Covers in detail lubrication formulation of gamut of well-control equipment and practice, from base oils and additives; lubricant properties, equipment to maintenance to procedures for land, applications, and lubrication programs and practices, bottom-supported rigs and subsea operations. Updated including fluid conditioning, management of change, with the latest information, this stand-alone chapter storage handling, used oil analysis, and more. covers blowout preventer stack equipment and Managed Pressure, Underbalanced and Air/Gas/ arrangements, BOP design, BOP testing, inside BOPs, Mist/Foam Drilling: A brilliant guide to the key chokes, diverters, control systems and more. The enabling technologies of managed-pressure, chapter’s section on well control procedures explains IADC Drilling Manual Copyright © 2015 TYPES OF DRILLING RIGS RT-13 calculations and more for well killing. As an added Six chapters tackle the following vital information, key to bonus, the chapter includes the latest IADC Killsheets maximizing safety and efficiency in subsea rig operations. for Driller’s Method, Wait and Weight (surface and Operational Risk Management and Well Integrity subsea) and Bullheading Method. Each killsheet (James Hebert, Diamond Offshore Drilling Inc, conveniently provided in US, metric and SI units. chairman): Barrier installation and maintenance for the Wire Rope: Details the key information needed by rig life of the well; personnel to properly use and maintain wire rope, with Well Planning and Rig Operations (Brian Tarr, Shell, emphasis on obtaining the maximum safe life from the chairman): Relevance of well planning and well design drilling line. Shows how to select the proper size and to well control; type line to meet requirements, maintain and care for Equipment (Peter Bennett, Pacific Drilling, chairman): the line to prevent damage, compute service in Typical well control equipment used on floating drilling Ton-Miles, and choose a cut-off program best suiting rigs; conditions. Includes numerous example calculations. Procedures (Earl Robinson, Murphy Oil Corp, appendix. chairman): Kick prevention, detection and mitigation to Appendix with Glossary: Fully updated to define maintain/regain control. today’s industry terms, the IADC Glossary glossary Training and Drills (Benny Mason, Rig QA provides guidance about common and not-so-common International, chairman): Planning, conducting and acronyms, abbreviations and terms. continuously improving deepwater well control training and drills; IADC Deepwater Well Control Guidelines Emergency Response (John Garner, Booths and Coots, The 2nd edition of the IADC Deepwater Well Control chairman): Activities and resources to manage a well Guidelines includes new content on operational risk man- control emergency. agement, sometimes called process safety, with additional The IADC Deepwater Guidelines also include an appendix new and refreshed content on well integrity, well planning, defining important acronyms and terms. rig operations, equipment, procedures, training and drills, and emergency response. The year-long project was led by Louis Romo, BP, Chairman of the Deepwater Well Control IADC Health, Safety and Environmental Guidelines Task Force, and Moe Plaisance, DODI, Executive Reference Guide Advisor, with support from nearly 100 top-level experts. The redesigned IADC Health, Safety and Environmental Reference Guide contains all the necessary guidelines for The aim of the guidelines is to facilitate safe and efficient establishing a sound safety program, and includes valu- deepwater drilling operations. This important publication able information on safe working practices. The redesigned provides guidance for maintaining primary well control, ap- IADC Health, Safety and Environmental Reference Guide is plying secondary well control methods and responding to an printed in full color with updated illustrations. emergency in the event of a blowout. Each chapter is intend- ed to facilitate the rig team’s primary task of maintaining and optimizing control of the well. IADC Drilling Manual Copyright © 2015 AU AUTOMATION IADC Drilling Manual 12th Edition IADC Drilling Manual Copyright © 2015 Get a grip on automated tripping MMC single handedly takes you there To drilling contractors and rig operators who value safety, efficient operation and minimized wear and tear on equipment, NOV Multi Machine Control is smartly integrated automation that optimizes tripping, stand building and connection processes. This is all done by one person, freeing up valuable resources to look further into daily safety and efficiency instead of focusing on machine control. MMC eliminates a big part of human errors in tripping operations MMC creates very consistent tripping speeds MMC extends equipment life with gentler operations www.nov.com/mmc AUTOMATION AU–i CHAPTER AU AUTOMATION, INSTRUMENTATION & MECHANIZATION he IADC Drilling Manual is a series of reference guides assembled by volunteer drilling-industry professionals with T 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. 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 advances 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 Fred Florence, National Oilwell Varco Gregers Kudsk, Maersk Drilling John Pedersen, Maersk Drilling REVIEWERS Clinton Chapman, Schlumberger Tom Geehan, MI SWACO Moray Laing, SAS John McPherson, Baker Hughes Mario Zamora, MI SWACO IADC Drilling Manual Copyright © 2015 AU–ii AUTOMATION 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: 978-0-9915095-5-3 Printed in the United States of America. IADC Drilling Manual Copyright © 2015 AUTOMATION AU-iii CHAPTER AU AUTOMATION Contents Overview of automated drilling operations........... AU-1 Impact on rig crew....................................................... AU-1 Automation systems.................................................... AU-1 Control and monitoring............................................... AU-3 Drilling network evolution..........................................AU-6 Examples of automation.............................................AU-6 Automated pipehandling..................................... AU-6 Standbuilding........................................................... AU-8 Tripping..................................................................... AU-8 Drilling ahead.......................................................... AU-8 Other automated procedures............................ AU-8 Operating automated equipment..................... AU-8 Restricted access zone (Red zone)........................AU-11 IADC Drilling Manual Copyright © 2015 IADC Bookstore Enhancing expertise for rig crews of today and tomorrow New from IADC Technical Resources! IADC DEEPWATER IADC DEEPWATER WELL WELL CONTROL CONTROL GUIDELINES GUIDELINES 2ND EDITION 2ND EDITION Available in print and eBook formats! Enhancing expertise for rig 182 pgs, 40 color images, 7 black & white images, 43 tables Copyright © 2015. International Association of Drilling Contractors. crews of today and tomorrow The 2nd edition of the ground-breaking “IADC Deepwater Well Control Guidelines” is available in print & electronic formats. The new deep-water guidelines include new content on operational risk management, sometimes called process safety, with additional new and refreshed content on well integrity, well planning, rig operations, equipment, procedures, training & drills, and emergency response. The yearlong project was led by Louis Romo, BP, Chairman of the Deepwater Well Control Guidelines Task Force, and Moe Plaisance, DODI, Executive Advisor, with support from nearly 100 top-level experts. Buy Book Buy eBook The IADC Deepwater Guidelines also includes an appendix defining important acronyms and terms. Print: $295 Member | $350 List eBook: $275 goo.gl/iocBL7 goo.gl/0uz4PP Telephone: +1 713 292 1945 Fax: +1 713 292 1946 Email: [email protected] www.iadc.org/bookstore | www.iadc.org/ebookstore Copyright © 2015 International Association of Drilling Contractors. AUTOMATION AU–1 Overview of automated drilling operations operated at a local panel, wired or wireless, and For decades, nearly all rig designs used the basic separately from the integrated control station(s). equipment of a drawworks, a rotary or top drive, and several mud pumps. Drill floor operations were manual: Impact on rig crew roughnecks handled tongs, slips and even spinning chains Automation is not intended to replace the driller, just like an by hand. In the derrick, the derrickman pulled pipe to the autopilot does not eliminate the pilot of an airplane. Instead, fingerboards with a piece of rope. Good crews did this automation can make the driller’s work easier and better. well, and in some places, with excellent results. In other The driller is needed to supervise the operation and inter- cases, however, injuries occurred, due to numerous factors, vene when there are tasks to perform that are not automat- including human impairment (fatigue, distraction, etc), ed, and when things just don’t seem right. poor judgment, inexperience, or well environment. Automation also can allow the directional driller to be lo- Rig owners and E&P companies asked for new tools and cated in a remote operating center, where he/she can su- work flows to make this part of the job safer. Spinning chains pervise multiple rigs and steer the drilling assembly using and tongs were replaced with pipe spinners and iron rough- remote controls, resulting in less travel to the rig site. Ser- necks. Power slips made the work less manual. The addition vice companies from remote sites will also be able to assist of these types of tools and machines is known as “mecha- with formation evaluation. nization.” The most important change resulting from introducing Mechanization occurs when machines are introduced into drilling automation is monitoring and controlling the drilling a process to allow people to do more with the machine than process with an overall picture of operations. Automation they could do with their muscles. By pulling a lever or push- simulators can look at the rig settings with respect to pres- ing and holding a button, the rig crew lets machines take sures, navigation, wellbore integrity, well productivity, time some or all of the physical work out of the job. and cost impact, and more, all at the same time, and help calculate the effect of changes to the drilling plan during the As control systems evolved, machines were modified to take construction of the well advantage of new measurements and control capabilities. A single control command could trigger an entire sequence of Automation systems steps programmed into the machine and its controls. The Most modern drilling equipment includes controllers such execution of multiple steps by a machine to achieve some as PLCs (programmable logic controllers) and PACs (pro- goal is an aspect of “automation,” which can more formal- grammable automation controllers) that collect sensor ly be defined as a system that, without direct control by an information and provide signals to actuators that allow operator, performs a set of actions using sensors and/or ac- machines to operate. Such systems are necessary for the tuators of a machine. machine to execute its basic functions and allow it to be ac- tivated from a remote location such as a driller’s station or Automation, when implemented and used properly, can im- chair. Controllers can be connected together to form a net- prove safety and drilling efficiency. When the machines can work that can communicate with one another and to HMIs do the routine, repetitive work, the driller can focus on crew (human machine interfaces. Using these remote HMI’s on a safety and downhole conditions. New automation systems mechanized rig, the driller monitors measurements and ex- can warn the driller of possible downhole problems and can ecutes commands to control the drilling operation. propose or change drilling parameters to avoid unwanted wellbore influxes, stuck pipe, damaging drillstring vibra- HMIs on mechanized rigs range from older control stations tions, and much more. with gauges, knobs, and buttons (see Figure AU-1) to new- er fully digital computer displays (see Figure AU-2). In the An automated system can be operated in different modes: case of the newer computer displays, most of these sys- Fully automated mode with no or tems have some sort of screen displays to make it easier to minimal operator interaction; perform specific process, which can be changed to suit the Semi-automated mode in which operation/ current operation making it so driller’s cabins have far fewer functions are performed in sequences buttons than those several decades old. However, the au- with operator acknowledgment; tomatic system is not only controlling individual machines, Manual mode by the operator from a chair, but also systems that monitor their interaction regarding po- controlling and monitoring equipment and systems sitioning, limits of operation, acceleration and braking, and in a step-by-step or direct-control mode; overall safety aspects. Local mode where the equipment or system is IADC Drilling Manual Copyright © 2015 AU–2 AUTOMATION Figure AU-1: Older driller’s control stations were cluttered with many buttons, switches and knobs. Courtesy Jan A. Tjemsland and the Norwegian Petroleum Museum. Figure AU-2: Newer control stations use displays configured for the current drilling operation to reduce congestion and confusion. IADC Drilling Manual Copyright © 2015 AUTOMATION AU–3 By integrating measurements and and pressure while drilling (PWD). control with algorithms in computer These tools monitor wellbore trajec- systems connected to the network of tory, rock properties, vibration, and controllers (or embedded within the downhole pressure, just to name a controllers themselves), automated few. Measurements can be used man- event detection, such as alarms, and ually by the drill crew to monitor the automated control begin to surface. drilling process or fed into mathemat- This allows control of individual ma- ical predictive models that compute chines on the rig, as well as systems what is expected in the near future. that monitor their interaction regard- One example would be to use the ing positioning, limits of operation, drilling engineer’s hydraulics model acceleration and braking and overall to estimate pressures in the wellbore safety systems which can account for and update this model while drilling rig operation objectives. using the PWD measurements. If the trend looks like the pressures are However, the automatic system is not building due to excess cuttings in the only controlling individual machines, annulus, the drill crew could take pre- but also systems that monitor their ventative measures, such as pumping interaction regarding positioning, a sweep to clean the wellbore before limits of operation, acceleration and the fracture pressure of the formation braking, and overall safety aspects. is exceeded. Predictive models do not By integrating measurements and replace the driller’s knowledge, but control with algorithms in computer they can help alert the driller to unex- systems connected to the network of pected situations. Figure AU-3: A local control panel is not controllers (or embedded within the integrated with other machines. controllers themselves), many types Once the monitoring is in place, of automated sequences are possible. someone or something should control One well known example is Zone Management, which is a the drilling machines to keep the drilling parameters within smart system where the machines work together to avoid boundaries that are both safe and efficient. The driller ad- collisions and dropped pipe, while moving at the maximum justs the throttles of the top drive and mud pumps and keeps safe operating speed. While most machine alarms are the right weight on bit (WOB). The autodriller was invented based on individual sensors, such as high temperature, over- to make this easier on the driller. After the driller sets the speed, or excessive torque, automated event detection can desired WOB, the autodriller adjusts the brake, so the driller alarm on operating conditions, such as potential downhole does not need to do this manually time after time. This is a problems like stuck pipe, pack offs or fluid influxes. Limiting single example of semi-automated control. tripping speeds and accelerations can also reduce a num- ber of downhole pressure related problems such as induced A fully automated system would determine t

IADC Drilling Manual, Volume 1 and 2 (12th Edition) PDF

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