Types of Drilling Rigs (RT) – Stand-alone Chapter of the IADC Drilling Manual [1, 12 ed.] 9780990904953

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TYPES OF DRILLING RIGS

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

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TYPES OF DRILLING RIGS

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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.

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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 Mark Dreith, Dreith Working Interests LLC Shane Lalumandier Reviewers Alan Spackman, IADC Joe Hurt, 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: 978-0-9909049-5-3

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Introduction......................................................................RT-1 Land Rigs���������������������������������������������������������������������������RT-1

Fit-for-purpose rigs��������������������������������������������������������������� RT-1 Walking rigs����������������������������������������������������������������������������RT-2

Offshore rigs������������������������������������������������������������������� RT-3

Platform rigs���������������������������������������������������������������������������RT-3 MODU types��������������������������������������������������������������������������RT-4 Posted barges and submersibles�������������������������������������RT-6 Jackups�������������������������������������������������������������������������������������RT-7

Contents Semisubmersibles�����������������������������������������������������������������RT-8 Drillships����������������������������������������������������������������������������������RT-9

Conclusion��������������������������������������������������������������������� RT-10 References��������������������������������������������������������������������� RT-11 IADC Drilling Manual chapters��������������������������������������RT-11 IADC Deepwater Well Control Guidelines���������������� RT-13 IADC Health, Safety and Environmental Reference Guide������������������������������������������������������������ RT-13

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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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 chapter is not meant to be an exhaustive narrative on each rig type, but strives to provide the reader with an overview of each. The one overriding theme that holds true, regardless of rig type, is that the drilling industry has made big changes in the design and layouts of all rig types to improve safety for the people working on these rigs, safeguard the environment, and improve the efficiency to minimize the time it takes to construct the well.

Land rigs

As mechanization made the hunt for hydrocarbons more efficient, it had a direct effect on land rig design. The first land rigs were permanent wooden structures and would be left in place after the well was drilled. Many were just tall poles or simple V-frame structures. As well depth increased, drilling required stronger structures and rig construction from steel became the norm. Fabricating rigs from steel meant that no longer would the

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structure be abandoned at the well site. Now, rigs could be moved from site to site, a major advantage. To enhance rig mobility, the original, bulky derrick was replaced with 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. Once on location, masts can be raised either by bull lines and the drawworks or by using cylinders. Cylinder-raised masts feature 2-3 fully constructed sections that pin together before the hydraulic cylinders raise them or a two-section telescoping mast where the top section is telescoped up after raising.

Fit-for-purpose rigs

Drilling rigs often go where few people wish to venture, such as burning deserts and frozen tundra. Because few or no highways exist to transport rigs in deserts, industry designed fit-for-purpose rigs. To move these rigs across the

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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 wellhead to wellhead. Courtesy Bentec.

Industry has adapted the “standard” drilling rig for other specialized environments. For example, Arctic rigs are winterized, 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 skidding 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 factor. However, this rig complexity has increased the share of rig moving time, relative to total operating days. Drilling contractors today often seek designs that shorten rig-up times.

Walking rigs

Industry’s improved understanding of accessing tight-permeability formations, especially shale rock, has also impacted 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 location. As a consequence, rigs require additional structural reinforcement, adding weight and increasing design com-

Figure RT-3b: Desert drilling rigs were purpose built to traverse the roadless sands of this tough environment. Note the size of the tires relative to the people in the foreground. Courtesy Nabors Industries Ltd.

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Figure RT-4: Trailer-mounted rig working on location. Courtesy Drillmec Drilling Technologies.

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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 substructure, derrick and, often, fluid-processing equipment for produced oil or gas (Figure RT-6). Video RT-2: Example of walking rig. IADC video of Wisco Moran drilling rig. plexity. However, the mud system does not move with the mast and substructure, as with desert rigs. Consequently, heavy and complex festoons and flowline systems are being added to allow the rig to “walk” 100 ft without rigging down. The search for the land rig design that accommodates all the latest drilling equipment and can still move quickly from wellsite to wellsite continues. Today, the industry box-onbox substructures, telescopic substructures, as well as designs featuring cantilevered masts in which the mast and rig floor are elevated in a single step. (This was originally introduced as the “Dreco Slingshot”). Rigs are being built to handle single stands of drillpipe, as well as doubles and triples. Many of the smaller single style rigs being mounted on trailers for easy transport.

Offshore rigs

Explorers began finding and drilling for oil in the ocean early in the 20th Century. The earliest offshore wells were drilled by equipment that differed little from land rigs, except that

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Platform drilling rigs themselves are essentially of the same type and construction as land based rigs, with BOPs on surface verses subsea, and special considerations to minimize weight that needed to be supported by the platform. Depending on the size and capacity of the particular platform, if it was not of sufficient size to support the complete drilling package, plus all of the equipment, materials, and liquids necessary for the drilling operation, the use of a tender vessel was often required. The tender vessel, be it a barge, semisubmersible or ship, would maintain station alongside the platform, and all of the necessary manpower, electrical power, mud pumping capacity, equipment and materials stored/located on the tender is transferred to the platform rig as required. With the advent of extended-reach and horizontal drilling, enabled by steerable drilling technology, a significant number of wells (typically 8, 12, or 16) could be drilled from a single platform, maximizing oil recovery. Platform drilling rigs were deployed onto these large platforms. Eventually, drilling operations proceeded in water far too deep to ever land a bottom-supported steel jacket. Indus-

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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 platform, 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 utilized a moored barge alongside the platform, with a ramp that led from the barge to the platform for dragging materials (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 personnel injury. Figure RT-7: As industry stepped out into deeper water, platform rigs were installed on large steel “jackets”, the bottom-supported frames supporting the rig substructure, derrick and, often, fluid-processing equipment for produced oil or gas. This jacket was constructed for Shell’s Bullwinkle platform in the US Gulf of Mexico. The jacket was landed in 1988 in 1,360 ft of water, setting a world record for deepest water for a production platform.

Figure RT-8: The tension-leg platform can drill and produce in deepwater. The Olympus TLP sits above 3,000 ft of water in the US Gulf of Mexico. Courtesy Shell.

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On modern tender-assist vessels, the deployment of an articulated/telescoping walkway is used to safely transfer personnel between the platform and the tender vessel.

MODU types

Today’s MODUs fall primarily into four water-depth categories: • 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 excess of 7,500 ft. Current rig designs have a maximum water depth rating of 12,000 ft.

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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 blowout preventer (BOP) on the ocean floor. This “subsea” BOP stack initially used a conventional method for controlling the BOP functions from the MODU. In shallow water and mid-water depths, this is accomplished using a straight hydraulic system in which hydraulic fluid was pumped down the umbilical lines to the control pods located on the top of the BOP stack. The subsea stack comprises the same conventional hydraulic rams and annular bags, without the added component of the lower marine riser package (LMRP). The LMRP allows the driller to pull the control pods to the surface without removing the critical hydraulic rams from the wellhead on the ocean floor. (For a more complete discussion of LMRP, read the separate Floating Drilling Equipment and Operations Chapter of the IADC Drilling Manual, 12th edition, or the IADC Deepwater Well Control Guidelines.)

surface allows drilling fluids and wellbore cuttings to be returned to the surface for treatment and recirculation. This riser pipe is made from high-tensile steel, traditionally fabricated in 50-ft lengths. Wall thickness in the older riser systems ranged between ½-⅝-in. wall thickness. More modern deepwater risers come in lengths of 75 ft or longer, with wall thicknesses of 1 in. or more. These changes were driven by the tremendous tensions required at the top, and the significant external pressures pushing in on the tube at deepwater depths. Typical top tensions pulled from the surface rig range from 3,000-4,000 kips to keep the riser straight and vertical in the water column. Buoyancy modules are also attached to the riser to decrease the weight in water of these massive tubes. Drilling in deepwater and high currents requires special considerations to eliminate vortex-induced vibrations (VIV), similar to the spiral cowlings found on the top of tall exhaust stacks on land.

With the move to deepwater and ultra-deepwater depths, emergency hydraulic power is stored in subsea accumulators attached to the subsea BOP stack. Controls went from pure hydraulics to multiple electronic controls (“multiplex” or “MUX”) to account for the increased pressures in deepwater.

Today’s modern drilling techniques require more capacity, higher flow rates, and better cleaning abilities for the latest drilling fluids. It is not unusual to have two separate mud systems on a modern deepwater rig, and even have the ability to connect a completions fluid system into the circulation 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

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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. four and sometimes five mud pumps to increase redundancey and provide additional fluid flow and for some of today’s downhole steerable tools . For removing cuttings and cleaning the drilling fluid (“mud”) that returns to the rig from the wellbore, today’s rigs feature 6- 8 modern shakers. This has led to larger and more capable rigs, as the methods to drill today’s wells have evolved.

Posted barges and submersibles

Both posted barges and submersibles are bottom-founded rigs that operate in relatively shallow water. Posted barges can typically operate in 8-20 ft of water, while submersibles can operate in 10-70 ft of water. A posted barge is an elevat-

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Figure RT-13: A submersible is a purpose-built rig that either has a mat or large ring pontoon at the bottom, and columns that support the upper hull structure. The vessel is floated out to the drilling location, and ballasted down so that mat or ring pontoon rests on the bottom. ed 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 driven into the seabed. The elevated structure contains all the personnel accommodation, power generation, liquid storage, mud pumps, equipment and material storage necessary to drill the well. The drilling package is generally located at one end of the barge, and is either cantilevered over the end, or a slot is built into the barge to accommodate the well center. Much like the land rigs, a surface BOP is used for well control.

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A submersible is a purpose-built rig that either has a mat or large ring pontoon at the bottom, and columns that support 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 structure. 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. Mat-supported jackups are better suited to areas with soft material on the ocean floor. They are far easier to “preload” 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 (including 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 end of the hull, and the drill floor package was located above this slot in a fixed position. This allowed for only a single well

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Figure RT-14: At top (Figure RT-14a) is a mat-supported jackup, while the jackup on the bottom (Figure RT-14b) features independent legs. Note also the air gap on the mat-supported jackup. Courtesy Hercules Offshore Inc.

Figure RT-15: Note the slot on the left of the rig on this slot-type jackup. The derrick had been removed from this rig, because it was converted to a non-drilling unit.

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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 package, 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 multiple wells from a single location. These cantilever jackups also incorporated the ability to move the drilling package transversely atop these large cantilever beams. The extended-reach cantilever jackups became the tool of choice for oil companies wishing to economically recover hydrocarbons in a given field. After the initial hydrocarbon field discovery, the oil company 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 derrick 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 either 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 envelop to 40 ft by 65 ft. Figure RT-14a is an example of a cantilever jackup. As the search for hydrocarbons moved into ever-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 450500 ft.

Semisubmersibles

Figure RT-16: Semisubmersibles are characterized by a lower hull of either separate pontoons or a single ring pontoon with numerous vertical columns supporting a large upper hull. Top photo Courtesy Diamond Offshore Drilling Inc. Center photo courtesy Noble Corporation. Bottom and inset photos courtesy Seadrill.

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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 upper hull. In most cases, the lower pontoons contain liquid storage, while personnel accommodation, power generation, and equipment/material storage is in the upper hull. The drilling package on a semisubmersible can either be centered in the upper hull or set to one end. Once the rig is on the drilling location, the lower pontoons are ballasted down (i.e., “submerged”) so that the vertical columns are sticking out of the

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water, supporting the upper hull structure. Because the semi is floating, it will ride up and down with the waves. Consequently, it does not require the same magnitude of air gap as jackups. The semi’s configuration minimizes the environmental 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 (1,0004,000 ft), and traditionally were moored on the drilling location using a fixed 8-point mooring system; comprised of anchors, chains, and/or wires to mainFigure RT-17: The ultra-deepwater drillship shown above was tain station. Using a fixed mooring sysdesigned for operations in water depths to 12,000 ft, with a 40,000tem does not allow the driller to turn the ft well-depth capability. Courtesy Atwood Oceanics Inc. rig into the weather, and for this reason, the smaller water plane area of the vercould visually see his position and manually maintain station tical columns minimized vessel motions over the well. This was the birth of dynamic positioning. when the variable storm directions hit the rig on the beam. Early semis were not equipped with thrusters, and the inOver the next half-century, the size and sophistication of stallation of thrusters were first used for “mooring assist” to drillships evolved dramatically. Most of the early drillships drive the rig into the weather, to decrease the mooring load used traditional 8-point mooring systems to maintain staon the highest loaded moorings. tion. If the wind/wave direction were always taken directly on the bow of the ship, vessel motions would be very good. As the search for hydrocarbons moved out into deep water, However, winds and waves rarely come from the optimum the size and capacity of the semisubmersibles grew also. heading at all times. Because a drillship anchored by an Variable deck load (VDL) is an important determinant for 8-point mooring pattern cannot turn into the weather, the water-depth capability. As a semi moves into deeper water, vessel’s motions became excessive when the weather imit obviously must carry more riser and drillpipe to reach the pacts the ship from the beam. This was a major reason why ocean floor. As a result, a deepwater rig must be able to carthe vessel motions of fixed-mooring semisubmersibles were ry more weight than one in shallower water. This means the superior to fixed-mooring drillships. deepwater rig must have higher VDL. For a rough comparison, a mid-water semi would typically have a VDL in the Today’s drillships are nearly three times the size of the orig3,000-4,000-long ton range, while the VDL of a deepwater inal CUSS 1. While conventional mooring is still feasible in semi typically ranges from 7,000- 8,000 long ton. the mid-water depths, dynamically positioned ships must be used in deepwater. DP systems use a sophisticated verAlong with the move to deeper water, semis were being sion of the now-ubiquitous Global Positioning System (GPS). equipped with full dynamic-positioning systems, allowing This has been enhanced with modern acoustic systems that the rig to stay on location without installing a multi-point hear “pingers” which are placed on the ocean floor. This admooring system. ditional redundancy, combined with modern software, allow the drillship to maintain station in up to 70-knot beam seas, Drillships within a offset of only a few feet. The first purpose built “drillship” was the CUSS 1,which was deployed and drilled her first well in 1956. In March 1961, Drillships were the original tool of choice for the drillers, as when the scientific community was looking for confirmation they have the largest deck load capacity (VDL) of any of the of the “Mohorovicic discontinuity” (the boundary between rig type designs. While the mid-water semi has a 3,000the earth’s crust and mantle), the MOHO Project was un4,000-long ton VDL capacity, a mid-water drillship is on dertaken by the CUSS 1 and successfully recovered a core the order of 8,000-10,000-long ton VDL capacity. When of the earth’s crust from 11,000 ft depth in 3,100 ft of water. loading up all the materials to head out to location to drill The drillship was fitted with four “steerable thrusters” and a well, this much larger VDL capacity made the drillship the used a set of submerged buoys and sonar so that the “pilot”

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obvious choice. The oil company operating the well, had to make fewer trips with supply vessels to replenish the onboard supplies.

Ultra-deepwater drillships

When the goal is to drill a well in more than 10,000 ft of water, the tool of choice is the ultra-deepwater drillship. Being exclusively dynamically positioned, ultra-deepwater drillships can maintain station and rotate the ship over the well center to head the ship into prevailing weather, following shifts in wind or wave direction. This minimizes the pitch and roll motions of these large drillships. The number and size of the engines and thrusters help determine the ship’s stationkeeping ability. Industry has learned from experience that a dynamically positioned vessel must be able to maintain station in the face of a 61-knot beam wind. Howard Shatto, considered the father of dynamic positioning, developed a standard by which a dynamic-positioning system is easily gauged. Using the ratio of 80% of available thruster power (i.e., with one of five power-generating engines down) and dividing that by the force of a 61-knot beam wind pushing on the vessel results in a dimensionless ratio called the HSSC Number (Howard Shatto Sanity Check). “HSSC” is pronounced “his sick”. (The force of the 61-knot beam wind depends on rig size and configuration.) This easily derived ratio provided industry with a quick check on a dynamic-positioning system’s ability to maintain station in real world events. A HSSC Number greater than or equal to 1.0 means that the dynamic positioning system should be able to maintain station. The consequences of being blown off location are high from both environmental and economic perspectives. Should an ultra-deepwater rig lose location, whether due to weather or a DP-system malfunction, the driller must disconnect the riser from the subsea BOP, thereby dispersing the riser’s contents along the ocean floor. Clearly, avoiding such situations is critical. These tanker-sized ships have very large VDLs to allow for increased storage of equipment and materials to drill ultra-deepwater wells. One of the most significant design goals for this rig type was increased efficiency for all operations. With the ocean floor nearly 2 miles below the ship’s hull, standard operations had to become more efficient to minimize “non-productive time” (NPT). Relatively simple operations, such as running the BOP and riser to the ocean floor, can take days, rather than hours on deepwater wells. As an example of reducing NPT, increasing the length of the individual riser joints from 50 ft to 75 ft or longer, decreased the number of time-consuming connections between the riser joints by one-third or more. In addition, redundancy on the drill floor allows drillers to run and retrieve the BOP and riser off the critical path of building the well, which can save

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days. Some drillers have increased the heights of their derricks to allow “quads” rather than “triples” of drillpipe to be tripped in and out of the hole. This reduces the number of connections that must be made up and broken out by about 25%. The drive to increase efficiency and decrease NPT were among the key design features of modern ultra-deepwater drillships. In most modern well construction, both water-based, and non-aqueous fluids, such as oil-based or synthetic fluids, are used. When changing over from water-based to non-aqueous fluids, fluid storage pits must be cleaned, if limited to one set of storage pits. Cleaning mud pits also means that personnel must enter enclosed spaces, which can be a safety hazard. It’s far more efficient to install two separate fluid storage systems, allowing fluid switchovers without entering and cleaning the tanks. With the large VDLs and liquid-storage capacities available on ultra-deepwater vessels, most drilling contractors have designed their rigs to accommodate dual mud systems, eliminating the need to clean tanks between different sections of the well. Again, this decreases the NPT and improves safety and efficiency. The drive into ever-deeper water combined with longer horizontal and directional sections means that more drillpipe must be used and handled by the rig, resulting in larger loads for the derrick to handle. Correspondingly, derrick capacities to support these larger loads have sharply increased. The old standard of 1.5 million lb gross nominal capacity (GNC) was insufficient to support the weight of BOP and riser at ultra-deepwater locations. Derrick’s of today’s ultra-deepwater drillships boast lifting capacities of 2.5-3.0 million lb GNC or higher. Derrick configurations have also changed with the introduction of redundancy on the rig floor to allow offline activities for increase efficiency and lower NPT. Derricks capable of handling offline running of riser and casing are becoming standard in today’s ultra-deepwater drill-floor construction, using a second set of tubular handling equipment (drillpipe, casing, and riser), second drawworks, and second rotary table. The increased efficiency from this duality of equipment has clearly helped reduce the NPT during ultra-deepwater well construction. As hookloads have increased, so has the rating of the traveling equipment in the derricks that carry these loads. The old standard of 750 short ton traveling equipment soon gave way to 1,000-ton equipment, and today is pushing toward capacities of 1,250-1,500 short ton. In addition, drillpipe capacity for use in ultra-deepwater wells has increased as well. The old standard 5-in. diameter drillpipe soon gave way to 5 ½-in. and even 6 ⅝-in. diameter drillpipe. As drillpipe diameter increased, the length of the individual joints of drillpipe has generally remained as API Range 2 (27-30 ft), with some drillers using API Range 3 (38-45 ft) to further decrease NPT. Handling this drillpipe and combining them

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TYPES OF DRILLING RIGS into “stands” of multiple pipes have become more efficient, as well. Offline stand building has replaced the old standard of pulling single joints up the V-door to add to the drill string. Some drillers have used both horizontal and vertical storage of full drillpipe stands to increase efficiency and options for tripping drillpipe into and out of the well. In addition to the change from straight hydraulic control systems to multiplex (electronic) controls due to the increased hydrostatic pressure in the ultra-deepwater, the overall rating of BOPs has increased. In recent years, BOP capacity has increased from a standard of 10,000 psi to 15,000 psi as formation pressures increase. Many of the latest deepwater drillships under construction, are designed for 20,000-psi BOPs. As discussed earlier, running and retrieving BOPs in ultra-deepwater can be measured in days rather than hours. A problem with the BOP or its control system will add days of NPT, not to mention the time it takes to actually fix the problem. For this reason, many current ultra-deepwater drillships being built are designed to accommodate two complete BOPs on deck. This allows the spare or standby BOP to be completely tested and ready to be deployed, should a problem develop with the subsea BOP. Early in the evolution of ultra-deepwater drillships, there was a perceived need to store crude oil, generated from extended well testing, onboard the rig. Some of the early designs incorporated the ability to store 300,000-400,000 bbl, or more. However, this crude oil storage and offloading capability has very rarely been used on ultra-deepwater wells, and current rigs are not being designed and built with this capability. However, ultra-deepwater drillships have also been tasked with erecting, testing and deploying subsea Christmas trees. These installations are provided for the day when the oil company returns to produce one of these deepwater wells.

Conclusion

The type of rig to be employed depends on location and expected well-construction requirements. Whether on land or in extreme water depths around the world, the push for increasing personnel safety, decreasing environmental impact, and reducing time to drill and complete the well are the ultimate factors driving design.

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References

For more detailed information on these and other aspects of drilling equipment, practices and technology, refer to additional chapters of the IADC Drilling Manual and to other IADC references. Visit www.IADC.org/bookstore or www. IADC.org/ebookstore. All IADC works are copyright IADC, all rights reserved.

IADC Drilling Manual chapters

Chapters of the IADC Drilling Manual, 12th edition, are available as ebooks and within the complete printed manual: ŸŸ Automation: Overview of automated drilling operations, impact on rig crew, control and monitoring, drilling network evolution and examples of automation. ŸŸ Bits: Discusses bit design, lubrication and pressure compensation, cutting structures, TSP cutters, nozzle and plug installation and removal, mechanical specific energy (MSE), monitoring drill parameters, dull grading and evaluation, storage, repairs, calculations, safety, governing standards and guidelines, and more. ŸŸ Casing and Tubing: Covers casing and tubing handling and storage on drilling rigs. The chapter covers pipe types, OCTG materials, corrosion, API casing grades, OCTG marking, transportation, handling, storage and running procedures and equipment. ŸŸ Casing While Drilling: Covers the range of CwD technology and operations. Topics include both retrievable and non-retrievable CwD, as well as liner drilling and retrievable liner drilling. ŸŸ Cementing: Discusses types of and reasons for cementing; preparing the well for cementing; job design, pumping and displacing cement; waiting on cement and post-job rig operations; cementing strings and hardware, including casing running tools; cement evaluation; and conducting safe cementing operations. ŸŸ Chains and Sprockets: Covers chain construction and specifications, applicable standards, roller-chain numbering and dimensions, sprockets, installation, lubrication and maintenance. ŸŸ Directional Drilling: Reviews the evolution of directional drilling, from the earliest days to the present; magnetic and gyroscopic sensors; essentials of directional surveying, including anti-collision; defining subsurface targets; surface considerations; trajectory design; well profiles; deviation control; bottomhole assemblies; deflection and measuring tools; bits; and more. ŸŸ 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. ŸŸ Drill String: Contains brand new sections on heavyweight drillpipe, safety valves and accessories, wired drillpipe and more. Color photographs clearly

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ŸŸ

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TYPES OF DRILLING RIGS

identify common drillpipe problems. Included for the first time are proprietary drillpipe tables from IADCmember manufacturers. Drilling Fluids: Provides general information on drilling fluids for rig workers and early career professionals. Covers purpose and functions of drilling fluids; basic testing and properties; categories, systems and additives; maintenance, contamination and related problems; calculations, units conversions and useful field tables; safety and hazards, regulations, safety data sheets and labeling; and additional reference materials for more in-depth studies. Drilling Fluids Processing: A comprehensive guide to reducing drilling-fluid and overall well costs through proper solids-control techniques. Covers dilution, chemical and mechanical separation, equipment arrangement,, weighted and unweighted drilling-fluid processing, screen labeling, shakers, degassers, hydrocyclones, desilters, desanders, mud cleaners, centrifuges, lost circulation, sizing mud systems and steel pits, and much more. Drilling Hydraulics: Discusses what is covered by the broad term “hydraulics”, as well as briefly describing hydraulic-related equipment. Hydraulic parameters, such as density, viscosity, yield point, rheology models, flow rate and fluid velocity are covered. Velocity and circulation rate determinations for both duplex and triplex pumps are discussed. Applications of hydraulics, including estimating bottomhole pressure and wellbore pressure management are covered, as is annular velocity. Drilling Practices: A straightforward explanation of the causes of troublesome drilling problems and how to avoid and overcome them. Covers bit and drilling dysfunctions,reaming for hole conditioning, hole cleaning in directional and horizontal wells ,tripping practices in horizontal and directional wells, wellbore stability, lost circulation and more. Floating Drilling Equipment and Operations: Covers equipment and procedures specific to floating drilling operations, with a focus on deepwater. Topics include stationkeeping, power systems, tubular and marine riser handling and tensioning, subsea well control, motion compensation, cargo operations, emergency disconnects and more. High Pressure Drilling Hoses: Includes an overview of hose types, mechanical properties, care and maintenance, inspection and testing, and a special section on flexible choke-and-kill hose and flexible well-test hose. Lubrication: Discusses wear mechanisms and types of lubrication. Covers in detail lubrication formulation of base oils and additives; lubricant properties, applications, and lubrication programs and practices, including fluid conditioning, management of change, storage handling, used oil analysis, and more. Managed Pressure, Underbalanced and Air/Gas/ Mist/Foam Drilling: A brilliant guide to the key enabling technologies of managed-pressure,

IADC Drilling Manual

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ŸŸ

ŸŸ

underbalanced and air/gas/mist/foam drilling. Covers drivers and all variations of MPD, including constant bottomhole pressure, pressurized mud cap drilling, continuous circulation devices, dual-gradient and riserless drilling, deepwater applications of MPD, air hammer drilling, and more. Pumps: Entirely rewritten to cover both mud pumps and centrifugal pumps. Each section is split between the two types of pumps for easy reference.Provides descriptions and basic theory, safety and handling, operations and applications, general maintenance, and important calculations. Includes a glossary, references, and new color illustrations and photos. Power Generation and Distribution: Features the latest information on emissions standards and regulations. A brand-new section discusses design, operation and maintenance of variable-frequency drives.Covers engines, generators and transmissions, fuels, installation, operations, shutdown, maintenance, storage and safety. Power distribution covers DC/DC and SCR systems, DC drilling motors, SCR (AC/DC) VFD, and DC/DC, including operations, design, theory and maintenance. Rotating and Pipehandling Equipment: Written and compiled by 26 subject matter experts, the brand-new Rotating and Pipehandling Equipment chapter covers the full range of equipment, including operations and maintenance. Topics include top drives, hoisting and running in, pipehandling, make up/break out, racking, auto-handling, tubulars, drawworks, elevators, casing running tools, power catwalk, manual and power tongs, instrumentation, maintenance and inspection, and more. Special Operations: This new addition to the IADC Drilling Manual covers tricky operations, including drilling highly depleted sands, coalbed methane formations, permafrost, and geothermal wells. Also discusses solid expandable liner technology and covers open-hole fishing operations in detail. The fishing section includes job planning, stuck-pipe mechanisms, estimating stuck point, string-stretch formula, and much more, including a review of fishing tools and techniques. Structures and Land Rig Mobilization: Describes types of structures and provides detailed guidance on their maintenance, inspection, storage and safety. A new, dedicated section on land rig mobilization addresses pre-move planning, rigging down, and rigging up. The section also includes a discussion on rig-walking systems. Well Control Equipment and Procedures: Covers the gamut of well-control equipment and practice, from equipment to maintenance to procedures for land, bottom-supported rigs and subsea operations. Updated with the latest information, this stand-alone chapter covers blowout preventer stack equipment and arrangements, BOP design, BOP testing, inside BOPs, chokes, diverters, control systems and more. The chapter’s section on well control procedures explains

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TYPES OF DRILLING RIGS calculations and more for well killing. As an added bonus, the chapter includes the latest IADC Killsheets for Driller’s Method, Wait and Weight (surface and subsea) and Bullheading Method. Each killsheet conveniently provided in US, metric and SI units. ŸŸ Wire Rope: Details the key information needed by rig personnel to properly use and maintain wire rope, with emphasis on obtaining the maximum safe life from the drilling line. Shows how to select the proper size and type line to meet requirements, maintain and care for the line to prevent damage, compute service in Ton-Miles, and choose a cut-off program best suiting conditions. Includes numerous example calculations. appendix. ŸŸ Appendix with Glossary: Fully updated to define today’s industry terms, the IADC Glossary glossary provides guidance about common and not-so-common acronyms, abbreviations and terms.

IADC Deepwater Well Control Guidelines

The 2nd edition of the IADC Deepwater Well Control Guidelines includes 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 and drills, and emergency response. The year-long 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. The aim of the guidelines is to facilitate safe and efficient deepwater drilling operations. This important publication provides guidance for maintaining primary well control, applying secondary well control methods and responding to an emergency in the event of a blowout. Each chapter is intended to facilitate the rig team’s primary task of maintaining and optimizing control of the well.

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Six chapters tackle the following vital information, key to maximizing safety and efficiency in subsea rig operations. ŸŸ Operational Risk Management and Well Integrity (James Hebert, Diamond Offshore Drilling Inc, chairman): Barrier installation and maintenance for the life of the well; ŸŸ Well Planning and Rig Operations (Brian Tarr, Shell, chairman): Relevance of well planning and well design to well control; ŸŸ Equipment (Peter Bennett, Pacific Drilling, chairman): Typical well control equipment used on floating drilling rigs; ŸŸ Procedures (Earl Robinson, Murphy Oil Corp, chairman): Kick prevention, detection and mitigation to maintain/regain control. ŸŸ Training and Drills (Benny Mason, Rig QA International, chairman): Planning, conducting and continuously improving deepwater well control training and drills; ŸŸ Emergency Response (John Garner, Booths and Coots, chairman): Activities and resources to manage a well control emergency. The IADC Deepwater Guidelines also include an appendix defining important acronyms and terms.

IADC Health, Safety and Environmental Reference Guide

The redesigned IADC Health, Safety and Environmental Reference Guide contains all the necessary guidelines for establishing a sound safety program, and includes valuable information on safe working practices. The redesigned IADC Health, Safety and Environmental Reference Guide is printed in full color with updated illustrations.

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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

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CHAPTER

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AUTOMATION, INSTRUMENTATION & MECHANIZATION

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 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

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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

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AUTOMATION CHAPTER AU

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Contents

AUTOMATION

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

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IADC Bookstore Enhancing expertise for rig crews of today and tomorrow

New from IADC Technical Resources!

IADC DEEPWATER WELL CONTROL GUIDELINES 2ND EDITION

Available in print and eBook formats! 182 pgs, 40 color images, 7 black & white images, 43 tables

IADC DEEPWATER WELL CONTROL GUIDELINES 2ND EDITION

Copyright © 2015. International Association of Drilling Contractors.

Enhancing expertise for rig 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. The IADC Deepwater Guidelines also includes an appendix defining important acronyms and terms. Print: $295 Member | $350 List eBook: $275

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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

Overview of automated drilling operations

For decades, nearly all rig designs used the basic equipment of a drawworks, a rotary or top drive, and several mud pumps. Drill floor operations were manual: roughnecks handled tongs, slips and even spinning chains by hand. In the derrick, the derrickman pulled pipe to the fingerboards with a piece of rope. Good crews did this well, and in some places, with excellent results. In other cases, however, injuries occurred, due to numerous factors, including human impairment (fatigue, distraction, etc), poor judgment, inexperience, or well environment. Rig owners and E&P companies asked for new tools and work flows to make this part of the job safer. Spinning chains and tongs were replaced with pipe spinners and iron roughnecks. Power slips made the work less manual. The addition of these types of tools and machines is known as “mechanization.” Mechanization occurs when machines are introduced into a process to allow people to do more with the machine than they could do with their muscles. By pulling a lever or pushing and holding a button, the rig crew lets machines take some or all of the physical work out of the job. As control systems evolved, machines were modified to take advantage of new measurements and control capabilities. A single control command could trigger an entire sequence of steps programmed into the machine and its controls. The execution of multiple steps by a machine to achieve some goal is an aspect of “automation,” which can more formally be defined as a system that, without direct control by an operator, performs a set of actions using sensors and/or actuators of a machine. Automation, when implemented and used properly, can improve safety and drilling efficiency. When the machines can do the routine, repetitive work, the driller can focus on crew safety and downhole conditions. New automation systems can warn the driller of possible downhole problems and can propose or change drilling parameters to avoid unwanted wellbore influxes, stuck pipe, damaging drillstring vibrations, and much more. An automated system can be operated in different modes: • Fully automated mode with no or minimal operator interaction; • Semi-automated mode in which operation/ functions are performed in sequences with operator acknowledgment; • Manual mode by the operator from a chair, controlling and monitoring equipment and systems in a step-by-step or direct-control mode; • Local mode where the equipment or system is

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operated at a local panel, wired or wireless, and separately from the integrated control station(s).

Impact on rig crew

Automation is not intended to replace the driller, just like an autopilot does not eliminate the pilot of an airplane. Instead, automation can make the driller’s work easier and better. The driller is needed to supervise the operation and intervene when there are tasks to perform that are not automated, and when things just don’t seem right. Automation also can allow the directional driller to be located in a remote operating center, where he/she can supervise multiple rigs and steer the drilling assembly using remote controls, resulting in less travel to the rig site. Service companies from remote sites will also be able to assist with formation evaluation. The most important change resulting from introducing drilling automation is monitoring and controlling the drilling process with an overall picture of operations. Automation simulators can look at the rig settings with respect to pressures, navigation, wellbore integrity, well productivity, time and cost impact, and more, all at the same time, and help calculate the effect of changes to the drilling plan during the construction of the well

Automation systems

Most modern drilling equipment includes controllers such as PLCs (programmable logic controllers) and PACs (programmable automation controllers) that collect sensor information and provide signals to actuators that allow machines to operate. Such systems are necessary for the machine to execute its basic functions and allow it to be activated from a remote location such as a driller’s station or chair. Controllers can be connected together to form a network that can communicate with one another and to HMIs (human machine interfaces. Using these remote HMI’s on a mechanized rig, the driller monitors measurements and executes commands to control the drilling operation. HMIs on mechanized rigs range from older control stations with gauges, knobs, and buttons (see Figure AU-1) to newer fully digital computer displays (see Figure AU-2). In the case of the newer computer displays, most of these systems have some sort of screen displays to make it easier to perform specific process, which can be changed to suit the current operation making it so driller’s cabins have far fewer buttons than those several decades old. However, the automatic system is not only controlling individual machines, but also systems that monitor their interaction regarding positioning, limits of operation, acceleration and braking, and overall safety aspects.

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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.

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and pressure while drilling (PWD). These tools monitor wellbore trajectory, rock properties, vibration, and downhole pressure, just to name a few. Measurements can be used manually by the drill crew to monitor the drilling process or fed into mathematical predictive models that compute what is expected in the near future. One example would be to use the drilling engineer’s hydraulics model to estimate pressures in the wellbore and update this model while drilling using the PWD measurements. If the trend looks like the pressures are building due to excess cuttings in the annulus, the drill crew could take preventative measures, such as pumping a sweep to clean the wellbore before the fracture pressure of the formation is exceeded. Predictive models do not replace the driller’s knowledge, but they can help alert the driller to unexpected situations.

By integrating measurements and control with algorithms in computer systems connected to the network of controllers (or embedded within the controllers themselves), automated event detection, such as alarms, and automated control begin to surface. This allows control of individual machines on the rig, as well as systems that monitor their interaction regarding positioning, limits of operation, acceleration and braking and overall safety systems which can account for rig operation objectives.

However, the automatic system is not only controlling individual machines, but also systems that monitor their interaction regarding positioning, limits of operation, acceleration and braking, and overall safety aspects. By integrating measurements and control with algorithms in computer systems connected to the network of Figure AU-3: A local control panel is not controllers (or embedded within the integrated with other machines. Once the monitoring is in place, controllers themselves), many types someone or something should control of automated sequences are possible. the drilling machines to keep the drilling parameters within One well known example is Zone Management, which is a boundaries that are both safe and efficient. The driller adsmart system where the machines work together to avoid justs the throttles of the top drive and mud pumps and keeps collisions and dropped pipe, while moving at the maximum the right weight on bit (WOB). The autodriller was invented safe operating speed. While most machine alarms are to make this easier on the driller. After the driller sets the based on individual sensors, such as high temperature, overdesired WOB, the autodriller adjusts the brake, so the driller speed, or excessive torque, automated event detection can does not need to do this manually time after time. This is a alarm on operating conditions, such as potential downhole single example of semi-automated control. problems like stuck pipe, pack offs or fluid influxes. Limiting tripping speeds and accelerations can also reduce a numA fully automated system would determine the optimum ber of downhole pressure related problems such as induced WOB and control and coordinate the individual machines in fractures. As the system is expanded further to integrate such a way that the entire process can be conducted withwith downhole measurements and actuation with downout human intervention, except of course, when something hole automation systems, such as rotary steerable systems, unusual occurs. The driller chooses the operation; the auautomation of the full well-construction objective will have tomation system does the required tasks to complete the been achieved operation safely and properly. The driller carefully monitors the actions.

Control and monitoring

Automation systems have two basic components: control and monitoring. Monitoring systems need sensors and/or manual inputs to understand whether the process is going according to plan. Sensors include the familiar surface measurements of hookload, block position, flow, density, pressure and others. Sometimes downhole sensors are deployed, such as measurement while drilling (MWD), logging while drilling (LWD)

IADC Drilling Manual

Monitoring and control can be categorized as: • Simple monitoring and manual/local control: Operations on the drill floor are performed more or less by using gauges or analog and digital instrumentation to inform the driller. All control and equipment handling is executed in a manual and local mode by the driller and crew on the drill floor; •

Advanced monitoring and manual/local control:

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Figure AU-4: Illustrates a first-generation DCN with two chairs and few PLCs, hardwired communication, PROFIBUS DP (decentralized peripherals) and Ethernet. Courtesy of Aker Solutions.

drill floor operational modes. Closed circuit television (CCTV) allows the driller to visually monitor steps in the process at a remote location, such as checking the position of fingerboard latches or watching the top drive engage with the top of the drillpipe while making a connection. Operations can be performed in a semi-automatic mode where tripping in/out is more or less performed automatically and the driller’s only instructions are to confirm that actions have occurred at critical steps in the process, and to choose the speed of operation by adjusting the joystick on the chair. All equipment on the drill floor must be upgraded hydraulically, pneumatically, electrically and mechanically for these semi-automated modes;

Some rigs introduced “advanced drilling instrumentation” using networks set up with displays located in the driller’s cabin and in the toolpusher´s office. The displays help visualize the data on the rig, and sometimes data is shared with off-site centers where everyone can see the same information at the same time. The driller still controls the process in a manual and local mode; •

•

Advanced monitoring and integrated manual control: Some rigs have “operator’s chairs” where most of the monitoring and control is implemented in the chair-shaped control station using networked and computer-based solutions. This allows implementation of automated hydraulic, pneumatic and advanced mechanical solutions involving machines and equipment used for drilling operations. It streamlines the hand-off of control from the driller to the assistant driller and eliminates the “local” control and operation to ensure a safer and more reliable drilling operation; Advanced monitoring and semi-auto control: Today’s existing solutions for drillfloor operations typically implement advanced monitoring with sufficient redundancy of control and monitoring systems for all

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•

Advanced monitoring and full auto control: The evolving “new generation” of drillfloor monitoring and control will be enabled for full automation, using surface and downhole sensors, mathematical models and real-time simulation plus machines purpose-built for automation. This will reduce drilling related problems, improve drilling efficiency and increase the safety and reliability of drill floor and downhole operations.

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Figure AU-5 & AU-6 (above and below) show an advanced DCN network for two well centers with four chairs, where CCTV is implemented with fully automated functionality of machinery on drill floor. Figure AU-5 courtesy Aker Solutions. Figure AU-6 is courtesy National Oilwell Varco.

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AUTOMATION Table AU-1: Key elements to monitor from within the Drilling Control Network (DCN). Hook Load

WOB

TD RPM

TD Tq

Hook Pos

Bit Depth

Total Depth

Stand no

Flow in GPM (coriolis)

Flow out GPM (coriolis)

Flow Out (meter)

Drilling Conventionally

X

X

X

X

X

X

X

X

X

X

X

Drilling with MPD

X

X

X

X

X

X

X

X

X

X

X

X

X

X

Tripping

X

X

X

Run/Retrieve BOP

X

X

X

Flow Check

X

X

X

X

X

Well Control

X

X

X

X

X

Logging

X

x

Coriolis position

Choke back pressure

MP SPM X

X

X

X

X

X

X

x

MP Disch. Pres.

Active Vol. (header, pond, gutter)

Active Gain/ loss

Res. Vol.

Comp. Pos.

Stroke counters (3-4)

Indicator for IBOP, Elev, Slips

Hook Speed

Trip Tank 1

Trip Tank 2

Total Trip tank volume

Drilling Conventionally

X

X

X

X

X

X

X

X

X

X

X

Drilling with MPD

X

X

X

X

X

X

X

X

X

X

Tripping

X

X

X

X

X

Run/Retrieve BOP

X

X

X

Flow Check

X

X

X

X

X

Well Control

X

X

X

X

X

X

X

Logging

X

x

Trip Tank Discrep.

Trip Tank return flow

X

X

X

X

x

Table AU-1: Key elements to monitor from within the Drilling Control Network (DCN) include hookload. Courtesy Maersk Drilling.

Drilling network evolution

Rig controls have improved from manual levers and motor control rheostats to computerized networks of machine control devices like PLCs and touch screen monitors, often referred to as a drilling control network (DCN). Over time, the development of the DCN has expanded from a simple network with approximately 1,000 input/output (I/O) points, to today where a dual-well center control network with interface to other systems will typically have between 25,000 to 30,000 I/O (hardwired and serial). Figure AU-4 illustrates a first-generation DCN with two chairs and few PLCs, hardwired communication, PROFIBUS DP (decentralized peripherals) and Ethernet. Figures AU-5 and AU-6 show an advanced DCN network for two well centers with four chairs, where closed circuit television (CCTV) is implemented with fully automated functionality of machinery on drill floor. There are established interfaces with the BOP control system for monitoring, choke and kill for monitoring, DP system, mud mixing and mud treatment system, etc. The operator normally has access to two screens/monitors in front of him where all essential information is shown, as

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well as additional monitors for CCTV, third party equipment as MWD, etc. Alarm handling is essential to ensure that the operator only gets alarms that are essential for safe operation. Unnecessary alarms from auxiliaries as seawater systems, freshwater systems, generator systems, etc., should be avoided, and these alarms should be directly transferred to the maintenance department onboard. HMI and alarm handling are still an ongoing development process to ensure improvement of safe operation for drill floor.

Examples of automation Automated pipehandling

The most commonly known automated system involves handling of drillpipe, because the system can remove crewmembers from harm’s way and mitigate issues related to tripping pipe. Various drill floor and pipe deck machines have integrated controls so that they all work together to move tubulars, assemble them into stands, rack them in the

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AU–7

Table AU-2: Key elements to monitor from the closed circuit television (CCTV).

Flow Line

TD Conn

Wash pipe/ IBOP (will be various heights

Drilling Conventionally

X

X

X

X

X

X

X

Drilling with MPD

X

X

X

X

X

X

X

X

X

X

X

X

Tripping Run/Retrieve BOP Flow Check

X

X

Well Control

X

X

CMC

Hoisting Sheaves (crown block)

Drawworks/ hoisting cylinders

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

TD elevators

Shakers

Mud Pumps

Manifolds

Rotary table

Pit Room

X X

Logging

X

X

X

X

X

Drill pipe fingerboards

Drill pipe VPC

Drilling Conventionally

X

X

X

X

Drilling with MPD

X

X

X

X

X

Tripping

X

X

X

X

X

X

X

Run/Retrieve BOP

Riser finger board

X

Riser gantry crane

X

Riser gantry shuffle

X

Riser finger boards

Wire line Sheave in Derrick/ mast

Drill pipe setback

X

RPS/ TFM

Capstan Unit

Wireline Unit

Moon pool

Flow Check Well Control Logging

X

X

X

Table AU-2: Key elements to monitor from the closed circuit television (CCTV). Courtesy Maersk Drilling.

derrick, and run them in or out of the hole. Automated pipe handling puts the pieces together and lowers them into the wellbore with a minimum of commands from the drill crew. The drill crew can even set a speed limit, so that the lowering does not create excessive surge pressure on the formations. The pipe handling systems have different capabilities depending on the rig type and the type of wells for which they were designed. Automation on a land rig is very different from that on a deepwater semisubmersible or drillship. Advanced pipehandling systems normally include the following mechanized machines: • Hoisting system, with either a drawworks with disk brakes and /or AC motor brakes or a hydraulic cylinder or rack-and-pinion system. Some rigs even use a two-drawworks solution: a topdrive with pipehandler; • Rotary with power slips; • Iron roughneck with a mudbucket system; • Pipehandling machine, like a column racker, a bridge-crane system or a cartridgestyle that often works as a system; • Remote-operated racking boards; • Pipe-doping system;

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Video AU-1: Currently, pipehandling is the best-known drilling-automation application. The advanced pipehandler shown can build and rack drillpipe, HWDP and casing, including fully automated standbuilding and tripping. No people are on the rig floor. Courtesy Maersk Drilling.

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AUTOMATION

Pipe-deck system; • Pipe deck crane, or; • Pipe handler on the pipe deck, and; • Conveyor belt or catwalk machine (or similar) to transport the pipe to the drillfloor. Possibly a V-door machine; Chutes from a low setback area may be installed; CCTV system, with cameras located on equipment or positioned in the drilling tower, mast or derrick; Tailing arm to secure and position the lower end of the tubulars as they move from the V-door to well center.

Standbuilding

Stands of drillpipe and bottomhole assemblies (BHAs) are often assembled in a separate location called an auxiliary mousehole. Stand building may also have an optional use in preparing and racking back stands of casing. On some rigs, this can be done offline to reduce trip times.

Tripping

With the stands already racked in the setback area, the pipehandling machines and the rig’s hoisting system are integrated to trip pipe in or out of the well in an automated fashion. The driller can set a maximum speed, but this still requires rigorous monitoring of the downhole conditions to avoid excessive surge and swab pressures, tracking pick up and slack off weights, and watching for possible ledges and other conditions critical when tripping manually. Future systems will use hydraulic models that calculate downhole pressures in real time and automatically adjust the trip speed limits depending on mud properties and downhole conditions. The models will issue alerts when abnormal conditions are suspected. The driller will still be at the center of the process, but perhaps not physically located near the hazardous location on the rig floor.

Drilling ahead

Automated drilling today uses a brake controller to limit the payout of the drill line. When the calculated WOB is below a threshold, more line is released until the WOB reaches the set point. Some autodrillers use multiple parameter control, but they still do just one thing: they limit the payout of the drill line. When drilling a horizontal well, the normal way we calculate WOB is no longer valid. Drillers normally measure the standpipe pressure off bottom and again when they start drilling. The pressure will change due to the forces of the bit and formation and the torque from a downhole drilling motor. This differential pressure is called “delta P.” When drilling off differential pressure, if delta P is below a certain threshold, the autodriller pays out more line until delta P reaches

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the desired value. The autodriller does not control both WOB and delta P. It controls line payout, and it stops paying out line when one of the boundary conditions, either WOB or delta P, is too high. If the autodriller has more than two parameters, it stops paying out line when any one of the parameters exceeds the set points. In the future, automated drilling will do much more than control the brake. Pipe movement (up and down) and pipe rotation will be adjusted as needed. Mud pump flow rates, managed pressure systems and drilling chokes will be included. Harmful drillstring vibrations will be avoided. Surface and downhole measurements will feed drilling models that will adjust the setpoints on the drilling machinery and downhole tools. It may be something similar to a continual automated drill-off test or adjusting parameters to minimize downhole vibrations measured at the bit.

Other automated procedures

There are few, if any, automated procedures in use today, other than the piperacking systems and the autodriller. Look for running and retrieving the riser and BOP to be automated in the future. BOP and choke manifold testing will not be far off. There are obviously many more processes that can be safely automated over the next few years.

Operating automated equipment

As operator of an advanced or simple drilling operation today, there are several parameters that should be taken into consideration and monitored while these operations/ functionalities are performed. As “operator,” when located in the chair, you are responsible for a safe operation. Tables AU-1 through AU-7 offer simple guidelines for “what to monitor“ when located in the “chair” on the drilling control network (DCN), including CCTV, BOP, choke and kill panel (C&K), logging system, MWD, and fire and gas systems. This information is sourced both from rig owners and third parties. Be aware that third-party information might not be available to view. These tables present guidelines and are not exhaustive. Further, rig type and layout can impact information availability or applicability. Therefore, a similar setup should be generated for the specific vessel and drill floor layout of any given operation. It is recommended that the Driller not focus on the dynamic-positioning (DP) system. Instead, the Driller should rely the DP Operator to confirm that operations are following approved procedures and for feedback regarding watch circles/times.

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Table AU-3: Key elements to monitor from the BOP panel. BOP line up

Well head pressure

Well head Temp

BOP Acc system pressure

Flow count for functions (calculated and actual)

Alarms

Drilling Conventionally

X

X

X

X

X

X

Drilling with MPD

X

X

X

X

X

X

Tripping

X

X

Run/Retrieve BOP

X

Flow Check

X

Well Control

X

X

X

X

Logging

X

X

X

X

X X

X

X X

Table AU-3: Shows key elements to monitor from the BOP panel. Courtesy Maersk Drilling.

Table AU-4: Key elements to monitor from the choke panel. Manifold line up Drilling Conventionally

X

Drilling with MPD

X

Tripping

X

Manifold Pressures

MGS liquid seal

MGS differential

MGS temperature

MGS pressure

Choke Pressure

Choke Temp

X

X

X

X

X

X

X

Run/Retrieve BOP Flow Check

X

Well Control

X

Logging

X

Table AU-4: Shows key elements to monitor from the choke panel. Courtesy Maersk Drilling.

Table AU-5: Key elements to monitor from logging systems. Background gas

Table AU-5: Shows key elements to monitor from logging systems. Courtesy Maersk Drilling.

Drilling Conventionally

X

Drilling with MPD

X

Tripping Run/Retrieve BOP Flow Check

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Well Control

X

Logging

X

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Table AU-6: Key elements to monitor from MWD and directional drilling tools. Stick Slip

Lateral vibration

Whirl

Actual WOB

Actual Bit RPM

Actual Bit Torque

Well Trajectory

Drilling Conventionally

X

X

X

X

X

X

X

Drilling with MPD

X

X

X

X

X

X

X

Tripping Run/Retrieve BOP Flow Check Well Control Logging

Table AU-6: Shows key elements to monitor from MWD and directional drilling tools. Courtesy Maersk Drilling.

Table AU-7: Key elements to monitor from fire and gas systems. Fire Type

Fire Location

Gas Type

Gas Location

Drilling Conventionally

X

X

X

X

Drilling with MPD

X

X

X

X

Tripping

X

X

X

X

Run/Retrieve BOP

X

X

X

X

Flow Check

X

X

X

X

Well Control

X

X

X

X

Logging

X

X

X

X

IADC Drilling Manual

Table AU-7: Shows key elements to monitor from fire and gas systems. Courtesy Maersk Drilling.

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AUTOMATION Pending the system setup, there will be common or several monitors and systems from which the operator gets all of the information, and the operator should be familiarized with these systems before going into operation. Whether dual-well centers with four or five chairs or one well center with two or three chairs, it should be clearly specified what to monitor during operation when located in one of these chairs.

Restricted access zone (red zone)

Rig crews identify and mark off areas that should be restricted to essential personnel only. Indication of this “red zone” provides a simple and uniform procedure for identifying and/or differentiating between the areas deemed hazardous and less hazardous on the drill floor, pipe deck, riser storage, moonpool and adjacent areas, and identifying hazards in connection with handling operations. On the drill floor, the restricted access zone is defined as the drill floor and the area that can be impacted by equipment remotely operated from the rig floor. This includes adjacent walkways. With the range of automatic and remotely operated pipe and riser handling equipment in the restricted access zones, as well as rotating machinery and high-pressure circulating manifolds, the area can be deemed hazardous.

The restricted access zones in connection with general lifting operations are typically the areas of the deck or structure below any crane or where the load of a crane can be expected to land. The general philosophy of the restricted access zone is to establish a visual indication of an area where there is a high potential for a hazardous event to occur if someone enters without authorization. The restricted access zone could and should be treated in a similar way to that of a safety barrier taped-off area, extensively used throughout the industry to control and prevent unaware individuals from entering an area with potentially hazardous conditions or events. The intention is to identify the restricted access zone areas for both drilling- and lifting-related operations and describe the control measures to be implemented to minimize the risks associated when working within the red zone. Access to restricted zones in connection with lifting operations is normally not needed, but due to the large area a crane or lifting device is able to cover, personnel can enter the lifting zone without being aware of the potential hazards from the overhead work. The restricted access zones are established in order to avoid any personnel movement within the work zones of a lifting appliance.

The red zone also provides a clearly defined and controlled working environment for all drill floor activities and lifting operations across the rig.

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BITS

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

BITS

BI–i

CHAPTER

BI

BITS

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 Tyler Cobb, Baker Hughes Dan Scott, Baker Hughes Ron Dirksen, Halliburton Alfazazi Dourfaye, Varel International Craig Fleming, Schlumberger Richard Rivera, National Oilwell Varco Jorge Silveus, Ulterra

REVIEWERS Bob Radtke, Technology International, Inc. Ernesto Medialdia, Drilling Consultant

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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: 978-0-9909049-0-8

Printed in the United States of America.

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BITS CHAPTER BI

BI-iii

Contents

BITS Introduction......................................................................BI-1 Roller cone development.........................................BI-1 Early diamond bit development.............................BI-2 PDC arrives..................................................................BI-2 Dual/dueling bit evolution......................................BI-2 Directional drilling considerations........................BI-3 Motor roller cone................................................BI-3 Steerable PDC......................................................BI-3 King diamond.......................................................BI-4 Emerging technology.........................................BI-4 Drill bit basics....................................................................BI-5 History..........................................................................BI-5 Drilling bits classification....................................... BI-6 Design basics............................................................. BI-6 Roller-cone bits....................................................BI-6 Offset......................................................................BI-6 Journal (bearing pin) angle.............................. BI-7 Soft formations: low journal angle................ BI-7 Hard formations: high journal angle............. BI-7 Design factors summary........................................ BI-8 Lubrication and pressure compensation system....BI-8 Roller cone.................................................................. BI-8 Diamond bits...............................................................BI-9 Bit profile...............................................................BI-9 Bit profile types....................................................... BI-11 Blade geometry: straight or spiral..................... BI-11 Specialized roller-cone bits.................................. BI-12 Air bits..................................................................BI-12 Jet deflection bits..............................................BI-12 Specialized fixed-cutter bits..........................BI-12 Sidetrack bits......................................................BI-12 Impregnated bits...............................................BI-12 Surface-set diamond bits/natural diamond bits.......................................................BI-13 Core bits..............................................................BI-13 Hybrid bits (PDC and roller cone)...............BI-13

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Hole openers.................................................... BI- 14 Hammer bits.......................................................BI-15 Casing-while-drilling bits................................BI-15 Two-cone bits....................................................BI-15 Impreg and PDC hybrid bit............................BI-15 Cutting structures..........................................................BI-16 Roller cone.................................................................BI-16 Steel tooth...........................................................BI-16 Tunsgten carbide inserts................................BI-16 Diamond bits.............................................................BI-16 PDC cutter technology....................................BI-16 PDC types...........................................................BI-17 Diamond table...................................................BI-17 Cutter shape.......................................................BI-17 Thermally stable polycrystalline cutters.................BI-18 Leaching..................................................................... BI-18 TSP application........................................................ BI-18 Cutter design............................................................ BI-18 Finite-element analysis......................................... BI-18 Impact test................................................................ BI-18 Abrasion test.............................................................BI-19 Thermal stability......................................................BI-19 Substrate interface..................................................BI-19 Related equipment.........................................................BI-19 Additional bit accessories.....................................BI-19 Installation................................................................ BI-20 Nozzle and plug installation and removal.............. BI-20 PDC nozzle installation......................................... BI-20 PDC ports, plug removal...................................... BI-21 PDC nozzle installation and removal tools...... BI-21 Roller cone, nozzle installation........................... BI-21 Snap ring........................................................... BI-21 Retaining pin.................................................... BI-21 Large diamenter bits – center jets and ports................................................................... BI-21 Roller cone, nozzle removal................................. BI-21

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Roller cone nozzle installation and removal tools................................................... BI-21 Bit make-up procedure.......................................... BI-21 Bits run on special BHA tools............................. BI-22 Suggested operating recommendations.......... BI-22 Optimizing parameter overview......................... BI-23 Mechanical specific energy....................................... BI-23 Importance in drilling operations....................... BI-23 Definition................................................................... BI-23 Application................................................................ BI-23 Monitoring drilling parameter procedures.............BI-24 Data sources............................................................ BI-24 General overview of monitoring......................... BI-24 Rotary speed............................................................ BI-24 Torque........................................................................ BI-24 Weight on bit........................................................... BI-24 Flow rate.................................................................... BI-24 When to pull the drill bit...................................... BI-25 Pull the bit for ROP.......................................... BI-25 Pull the bit for mechanical damage............ BI-25 PDC bits..................................................... BI-25 Roller-cone bits........................................ BI-25 Factors in premature bearing failure:........ BI-25 Pull the bit for bit balling............................... BI-25 Pull the bit for nozzle problem..................... BI-25 Lost nozzle................................................. BI-25 Plugged nozzle......................................... BI-27 Dull grading and forensics.......................................... BI-27 System enhancements.......................................... BI-27 Evaluating “cutting structure”............................. BI-28 Inner/ourter rows: spaces 1 and 2............ BI-28 Dull characteristics: space 3....................... BI-28 Location: space 4............................................ BI-28 Other evaluation criteria....................................... BI-28 Bearing: space 5.............................................. BI-28 Gauge: space 6................................................ BI-28 Other dull characteristics: space 7........... BI-28 Reason pulled: space 8 ................................ BI-29

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Impact on other stages of drilling, completion and production....................................................................... BI-29 Proper storage considerations............................ BI-29 Tricone bit storage.................................................. BI-29 Sealed tricone bits.................................................. BI-29 Non-sealed tricone bits........................................ BI-30 Storage method 1: greasing the cones..... BI-30 Storage method 2: submersed in oil......... BI-30 Prior to use............................................................... BI-30 Locked cone.............................................................. BI-30 Fixed cutters bit storage....................................... BI-30 Drill bit repairs................................................................ BI-30 PDC............................................................................. BI-30 Post-run evaluation........................................ BI-30 PDC cutting elements and secondary components replacement and reclaim..... BI-31 Drill bit body and gauge.............................. BI-31 Pin connections and upper sections (matrix bits)..................................................................... BI-31 Miscellaneous modifications....................... BI-31 Roller cone................................................................ BI-31 Re-tipping.......................................................... BI-31 Post-repair documentation and inspections............................................... BI-31 Important calculations................................................. BI-32 Drilling hydraulics........................................... BI-32 Pressure drop................................................... BI-32 Hydraulic horsepower................................... BI-32 Hydraulic horsepower/square inch........... BI-32 Jet velocity........................................................ BI-33 Jet impact force.............................................. BI-33 Drilling economics.......................................... BI-33 Cost per foot.................................................... BI-33 Break-even line................................................ BI-33 Proper handling............................................... BI-34 Safety and handling...................................................... BI-35 Governing standards & guidelines/references.... BI-36

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BI–1

Table BI-1: Alternate names, acronyms & slang

Introduction

Rotary rigs drilling for oil in the early 1900s used a dragtype fishtail bit that made hole by scraping and shearing the bottom of the wellbore (Figure BI-2a and 2b). Although this was an improvement over percussion-style cable-tool rigs, the fishtail bit limited rotary drilling to soft, plastic formations because they were not durable enough to penetrate hard and abrasive formations. In 1909 a two-cone rolling cutter bit conceived by Howard Hughes, Sr. was introduced at Spindletop field near Beaumont, Texas.1 The cutting structure was created by milling circumferential and axial grooves into a steel conical rolling cone, producing a series of sharp teeth. The rolling cones, combined with the sharp cutting structure, created a unique crushing action. The roller-cone bit revolutionized oilfield drilling by enabling operators to use rotary rigs to efficiently penetrate hard and abrasive formations to gain access to the reservoir without hole deviation issues and costly delays associated with previous methods.

Roller cone development

During the following years, several major enhancements driven by Floyd Scott and his team increased the roller-cone bit’s footage and rate of penetration (ROP) capabilities. In 1925 engineers devised a method for welding tungsten carbide hard facing to the milled-tooth cutting structure, increasing durability. In 1933, a three-cone version was produced by perfecting offsetting cone geometry to accommodate the third cone. In 1951, precision machine tools allowed manufacturers to force-press tungsten carbide inserts (TCI) into pre-drilled holes in the cone steel, creating the TCI roller-cone bit. This focused effort was once again driven by the need to further enhance a bit’s ability to efficiently drill hard and abrasive formations. The “Jet” bit, employing the predecessor of today’s nozzles, was introduced to help deal with the bottomhole cleaning. The underlying problem of low ROP was caused by a phenomena known as bottomhole balling that becomes progressively worse with increased depths and mudweights. 2 Also, cutter tracking and off-center running further exacerbate the problems. In 1959, the first functional sealed bearing roller-cone bit was introduced, offering extended life by allowing the bearing to operate in a clean grease environment. 3 In 1969, an O-ring sealed friction-bearing design revolutionized bit life by distributing bearing loads over larger surfaces, reducing stress levels in critical areas and leading to runs of three to four times the prior life.4 However, limitations in drilling shale and other soft formations remained to be solved. To further address the low ROP issues, research and development (R&D) focused on the rolling action and how the cutting structure engages the formation. Engineers experimented with different cone angles and made modifications to the cutting structure teeth shape, projection, orientation,

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Bit type/subtype

Alternate names

Drill bits

Earth-boring bits

Fixed cutter bits

Diamond bits, drag bits

Polycrystalline diamond compact (PDC) bits

PDC bits, diamond bits, drag bits, fixed-blade bits, matrix bits, steel body bits

Impregnated bits

Impregs

Natural diamond bits

Surface set

Eccentric bits

Bi-center bits

Thermally stable polycrystalline (TSP)

--

Roller-cone bits

Tricone bits, rolling cone bits

Tooth bits

Steel tooth (st), mill-tooth, rock bits

Insert bits

Tungsten carbide, tci bits, insert bits, button bits, Hugheset® bits

One-cone bits

Uni-cones, single-cone bits

Two-cone bits

Bi-cone bits

Three-cone bits

Tricone bits, roller-cone bits

Air bits Hole opener tools

Hole enlargement tools, expandable borehole tool

Fixed reamers

--

Expandable reamers

Concentric reamers

Roller-cone reamers

--

Eccentric reamers

Bi-center bit

Specialty bits

--

Hybrid – impreg and PDC

--

Hybrid – PDC and roller-cone

Hyb

Casing-while-drilling

CwD

Core bits

--

Hammer bits

Percussion bits

Mills

Diamond mills, speed mills, junk mills

Coil-tubing

--

Junk bits

Junk mills

Casing-exit bits

--

etc. The knowledge gained led to updated roller cone cutting structure designs with bearing pin angles, optimized skew angles and cone profiles that featured innovative TCI shapes and recent hardfacing materials that dramatically improved steel tooth bits. 5-9 Due to their innovative design and unique

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crushing action, roller-cone bits accounted for approximately 96% of the total oilfield footage drilled worldwide between the years 1909-1986.

Early diamond bit development

During the time roller cone reigned supreme, different manufactures were experimenting with natural diamond bits, and in 1946 a diamond coring bit was successfully run in Rangely Field, Colorado In 1952, the first non-coring surface set natural diamond bit developed by Christiansen was successfully run in an oilfield application. This design utilized an erosion-resistant carbide matrix and a new powder metallurgical process for mounting natural diamonds in the bit crown. In 1960, an impregnated diamond bit was introduced that featured sintered cutting segments composed of sharp, grit-size diamonds mixed with tungsten carbide and a metallic binder. The resulting grinding action enabled an impregnated bit to drill the hardest, most abrasive formations but at a much lower ROP compared to alternative bit types. Other similar bits had the diamond grit dispersed in the carbide matrix and infiltrated with a copper-based binder, and others chose to make the bit crown and bit face as a unit, casting the new impregnated segments into the bits.

PDC arrives

In 1976, after four years of development and isolated bit runs by General Electric Superabrasives, the first commercial synthetic PDC bits specifically designed for oilfield applications were manufactured and field-tested. The work by the innovative leaders proved the capability of stud-mounted synthetic diamond drill blanks, which would evolve into today’s PDC cutters, to efficiently shear soft formations10,11 In 1982, the first cylindrical PDC cutters were introduced using new materials and bonding techniques to attach the synthetic diamond cutters to the bit body. PDC bit development continued during the early 1980s with the introduction of a parabolic face profile that increased cutter density in the gauge area to improve durability when drilling with a motor at high RPM. In 1986-87 the price of crude oil plummeted to $9/bbl, causing a dramatic decline in drilling activity and bit development. In spite of the downturn, the industry produced an application-specific three-bladed PDC bit with dedicated hydraulics specifically designed to drill soft and sticky shale.12 The combination of technologies alleviated bit balling issues drilling soft formations in water-based mud and served as the basis for next generation soft formation PDC. Drilling research work led to the discovery of bit whirl and the effects of this dynamic dysfunction on cutter durability. The proposed solution from a team at Amoco produced a much more robust cutting structure, and a step change in life was noticed. Competition from new suppliers entering the market aided the development of improved PDC cutters.

IADC Drilling Manual

Dual/dueling bit evolution

Increased drilling activity in the 1990s rejuvenated demand, and both types of bits continued to evolve with R&D efforts focused on increasing service life of roller-cone bits and expanding the PDC application envelope into harder and more abrasive formations while attempting to maximize penetration rates of both types of bits. During this time span, the bits were generally applied as follows: 1) roller cone was utilized in hard/abrasive and interbedded formations and for complex directional work, and 2) PDC was applied in mostly soft to medium formations and for less demanding directional applications. However, the drive to advance bit technology intensified when global engineering studies quantified the large impact improvements in bit design have on overall drilling efficiency and its vast potential for lowering project costs.13,14 Manufacturers responded with a series of systematic advancements in bit technology that improved performance in both product lines in the world’s most demanding drilling theaters.13,14 In 1987, a diamond-enhanced insert improved roller cone gauge-holding capabilities on TCI bits and increased borehole quality.15-22 During this same time, design and application engineers experimented with PDC blade count and cutter configurations. The industry also focused attention on modeling cutter loading and analyzing drilling mechanics to quantify and mitigate downhole vibrations. 23-24 As operators continued to explore the outer boundaries of the PDC application envelope, the industry began to describe the damaging effects that downhole vibrations have on PDC bits and cutters. 25-30 The inefficiencies drove the industry to explore new manufacturing methods to develop cutter technology that could withstand with a punishing downhole environment and develop bit bodies that would remain dynamically stable in targeted applications. 31-36 Non-planer interfaces, application-specific PDC cutters, low-friction polished cutters, improved edge geometries and ultra-thick high-toughness PDC cutters were introduced. The next major step involved producing cutter technology using a deep leaching process25, and that led to a new process that involves a two-step high-temperature/high-pressure procedure that produces a cutter capable of maintaining a sharp, efficient cutting edge. 37,38 In 2013, a fully rotating cutter was introduced that effectively utilizes the entire 360° diamond cutting edge to reduce frictional heat/wear while increasing drilling efficiency and bit life, and a cutter with a non-planer cutting face that was documented to stay cooler was introduced39,40, 41 ( SPE-168000).

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Diamond vs Roller Cone: Footage drilled, historical trend 100% 80% 60%

Gold Series

40%

Genesis

Anti-whirl

20% 0% 1985

1990 Tricone Footage (%)

1995

2000

2004

Diamond Footage (%)

Figure BI-1: Industry philosophy of continuous improvement led to the rapid advancement of PDC technology to solve application challenges. Courtesy Baker Hughes Inc.

Directional drilling considerations

Another key driver influencing bit development is the ever-increasing requirement for directional drilling. The industry requires complex wellbore trajectories and multilaterals to economically develop offshore oil and gas reserves and in difficult-to-reach reservoirs in land applications. The evolution in motor- and rotary-steerable tools has played a vital role in drill bit development. Properly matching the bit to the formations to be drilled and other bottomhole assembly (BHA) components is critical to project success, and a number of bit technologies have been incorporated into roller cone and PDC bits to accomplish these objectives.

Motor roller cone

The high rotational speed of motor drilling was one of the primary drivers in the accelerated advancement of seal and bearing technology. A unique twin elastomer sealing system was developed to protect the bearing from corrosive drilling and formation fluids in hot/high-pressure formations.42,43 An innovative metal-sealed bearing has also been incorporated into a wide range of bits to accomplish the same objectives with the added ability to operate reliably at high rotary speeds.44,45 Improved cutting structure configurations in the gauge and heel rows were developed for TCI, and enhanced hard-facing materials and application techniques were perfected on the milled tooth bits. Manufacturers have also increased tungsten carbide hard-facing on the shirttail and up the leading edge of the leg for additional protection in directional applications. Although roller cone provides drillers with good directional control, its slower ROP and limited run life relative to the latest PDC bits led to significant research into steerable PDC bits.

scribing problems while steering with PDC bits. They determined that controlling PDC torque response to weighton-bit changes in motor steerable applications is critical to maximize ROP while rotating without compromising directional control when sliding. The issues of toolface control with PDC bits has been discussed in the literature, and a number of approaches have been used to improve performance, including increased cutter back rake, higher blade counts, small cutters, wear knots, large chamfers and most recently a patented depth of cut (DOC) feature that has a bearing surface to limit reactive torque. The objective of each of these design changes is to reduce bit aggressiveness with increased weight on bit (WOB). However, the consequence of this approach can lower drilling efficiency and ROP in hard formations to gain steerability in soft rock if not properly applied. At times the bits are too aggressive to drill soft formations at high angles.46-51

Steerable PDC

With PDC bits continually encroaching on traditional roller cone applications, engineers began experiencing and de-

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Figure BI-2a & 2b: Fish tail bit and percussion bits.

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BITS

Figure BI-3: Howard R. Hughes was granted US Patent 930759 on August 10, 1909, for two-cone bits. Courtesy Baker Hughes Inc.

damage to the brittle synthetic diamond cutters. The stable bit allowed the bit companies and cutter suppliers to more reliably evaluate improvements in materials and processes. The result has been a dramatic improvement in cutter technology and bit performance. If the cutters remain intact, the bit can continue to drill at an acceptable ROP. This gives PDC bits a distinct advantage over roller cone and other bit types in the majority of today’s applications, with an increasing number of shoe-to-shoe runs being the norm in many applications.

Emerging technology

Today we are seeing a combination of PDC and roller-cone components to produce a hybrid bit. 52 It employs the crushing action of a roller cone combined with the scrapping action of PDC. It performs well in interbedded formations

Figure BI-4: Howard R. Hughes was granted US Patent 959540 on May 31, 1910, for a threecone roller bit. Courtesy Baker Hughes Inc.

King diamond

In today’s drilling environment, PDC bits are the industry’s workhorse accounting for approximately 75% of total footage drilled in worldwide oilfield applications. The shift to majority PDC drilling took only 28 years to achieve and occurred in 2004 when footage drilled by PDC increased to 54% (see Figure BI-1). The dramatic swing was made possible by stabilizing the bit body with various techniques to significantly reduce downhole vibration and mitigate impact

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Figure BI-5: : Synthetic diamond (grit).

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Figure BI-6: Development paths for today’s drill bits.

handling the transitions without the vibrations of a PDC, and in those where the PDC is not consistent enough to make the required interval reliably. An adjustable DOC control feature is being introduced which will alleviate some of the concerns mentioned with earlier technologies. Further, new cutter technology is emerging with cutters which are free to rotate in a PDC bit, and others have innovative chamfers or a contoured face to control chip flow and temperature. A resurgence in the science of the HTHP apparatus for making PDC cutters has led to substantial improvements in the base underlying cutter technology.

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Drill bit basics

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The drilling bit industry is changing rapidly in the areas of manufacturing technology and the use of new materials. Computers have also caused dramatic changes in the drilling bit manufacture process, as today the use of bottomhole simulation software in order to have a new bit design “virtually tested” before it gets manufactured is a very common practice in this industry.

History

The drill bit history timeline actually stars about 5,000 years ago in ancient China. There is some historical evidence indicating that water wells were drilled using cable drilling technology with percussion bits. More recently: • 1845: Pierre Pascal Fauvelle invented the rotary drilling system. It was used in the early years of the oil industry

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• • • • • • • • • • •

in some of the oil-producing countries in Europe. Fish tail-type bits were used (Figure BI-2a); 1859: Edwing Laurentine Drake drilled the first oil commercial well in Titusville, Pennsylvania. Percussiontype bits were used (Figure BI-2b); 1900: The rotary drilling system was in general use in Texas; 1901: On January 10 a well at the Spindle Top oilfield, a salt-dome structure located in south Beaumont, Texas, was drilled, marking the birthdate of the modern petroleum industry; 1909: Howard R. Hughes granted US Patent 930759 on August 10 for two cone bits (Figure BI-3); 1910: Howard R. Hughes granted US. Patent 959540 on May 31 for a three-cone roller bit (Figure BI-4); 1925: Cutting structures with intermesh were invented; 1928: Use of tungsten carbide hard-facing first used in the drilling industry; 1939: “Offset” criteria was introduced to roller-cone bit design; 1940: Natural diamond bits introduced to the market; 1951: TCI first used in roller-cone bits; 1953: General Electric Company created synthetic diamond crystals (Figure BI-5); 1963: Sealed bearing roller-cone bits first used; 1969: O-ring sealed journal bearing introduced; 1976: The PDC cutter was introduced by General Electric; 1986: Diamond-enhanced inserts (DEI) introduced on roller-cone bits by MegaDiamond; 1994: PDC technology introduced the non-planar interface (NPI) between tungsten carbide substrate and

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BITS

Figure BI-7: The bit cone’s “offset” is the horizontal distance between the bit axis and a vertical plane through the axis of the journal. Soft formations usually experience a high offset, while hard formations usually have a low offset. Courtesy Schlumberger.

• 2013: Rotating PDC cutter and a PDC cutter with a contoured face to improve chip flow and run cooler.

Drilling bits classification

There are two big groups of drilling bits, including its respective divisions and sub-divisions, as follows: The PDC bits can be sub-classified as: • Matrix-body PDC; • Steel-body PDC. The same type of sub-classification applies to bi-center bits: • Matrix-body bi-center; • Steel-body bi-center. Also, impregnated bits can be sub-classified as: • Conventional impregnated matrix; • Impregnated inserts or segments. Note: Matrix is manufactured from a tungsten carbide powder and metallic binder.

Design basics

Based on the drilling mechanics differences between roller cone bits and diamond bits, different design concepts apply for each group of bits.

Roller-cone bits

There are three basic design factors for roller-cone bits: • Cone offset; • Journal (bearing pin) angle; • Cone profile. Figure BI-8: The top image shows a low offset, while the lower drawing shows a high offset. Notice the difference between the centerline and the offset on each cone. Courtesy Schlumberger.

diamond table. Diamond table thickness was increased to maximize wear resistance and cutter life; • 1995: Polished cutters, stress engineered cutter placement and application-specific cutters introduced commercially; • 2003: Surface-leached PDC cutters commercialized; • 2003: Depth of cut control for steerable PDC introduced;

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Offset

The bit cone’s “offset” is defined as the horizontal distance between the axis of the bit and a vertical plane through the axis of the journal. Offset is established by moving the centerline of a cone away from the centerline of the bit in such a way that a vertical plane through the cone centerline is parallel to the vertical centerline of the bit.

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Figure BI-9 (above): The journal angle is formed by a line perpendicular to the bit axis and the journal axis. Courtesy Schlumberger. Figure BI-10 (top and center right): Usually bits with smaller journal angles (30°-33) are best for drilling softer formations requiring lower WOB. Conversely, larger journal angles are better for harder formations requiring higher WOB. Courtesy Schlumberger.

Soft formations usually experience a high offset (3⁄8 in.), while hard formations usually have a low offset (1⁄32 in.). Soft formation bits use high offsets values to increase this cutting action and thus increase ROP, while harder bits use lower offsets values to reduce cutter wear induced by the sliding action.

• • • • •

Gauge contact and length; Cone diameter; Cone shell thickness; Bearing space availability; Leg strength.

These images show a low offset (up) and a high offset (down). Notice the difference between the centerline and the offset on each cone.

It also affects the relationship between scraping and crushing actions produced by the cutting elements of the bit.

Basic cone geometry directly affects increases or decreases in either journal or offset angles and a change in one of them requires a compensating change in the other.

Generally, bits with relatively small journal angles, 30°-33°, are best suited for drilling in softer formations that require lower weight on bit (WOB). These formations require gouging and scraping actions.

Journal (bearing pin) angle

The journal angle is the angle formed by a line perpendicular to the axis of the bit and the axis of the journal. Journal angle influences the design of many key bit features, including: • Intermesh depth; • Insert projection and milled tooth depth; • Heel surface length and angle;

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Soft formations: low journal angle

Hard formations: high journal angle

Larger journal angles, 34°-39°, are better when drilling in harder formations that require higher WOB amounts. Hard formations require a chipping and crushing action.

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BITS

Figure BI-11: The basic design factors associated with designing bits for particular formation types. In a very soft formation, for instance, the bit teeth are spaced farther apart, are longer and gouge and scrape more than chip or crush. Courtesy Schlumberger.

Figure BI-12: Roller-cone bits boast one of the highest unit loads for any bearing and require specialized grease.

Design factors summary

Figure BI-11 identifies the basic design factors associated with designing a bit for a particular type of formation. For example, in a very soft formation, the teeth of the bit are spaced further apart, longer in length and provide more gouging-scraping action; the journal angle is lower, while the offset is higher.

Figure BI-13: Seals contribute significantly to the effectiveness of the lubrication and pressure compensation system by preventing drilling contaminants from entering the bearings. Non-sealed bearing designs allow mud to enter the bearing to cool and lubricate, but suffer shorter bearing life than sealed bearings.

Lubrication and pressure compensation system Roller cone

The lubrication and pressure compensation system equalizes pressure across the seal and provides lubricant to optimize temperature and load pressure within the bearing system. Roller-cone bits have one of the highest unit loads of any bearing and require specialized grease. Each drill bit manufacturer has developed custom-engineered roller cone bearing grease compatibility with all bearing components. The grease has been designed to have higher heat capacity, greater resistance to oxidation, and higher load capacity

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than conventional bearing greases. Collectively these characteristics minimize wear and friction and extend the life of the bearing system. The pressure compensation system serves to accommodate grease expansion, cone movement and annulus pressure and maintain a stable environment for the bearing system. The seal contributes significantly to the effectiveness of the lubrication and pressure compensation system as its dynamic properties keep drilling contaminants from entering the bearings.

Figure BI-14: The apex is the geometric center of a diamond bit. The cone can have a deep or shallow profile. Courtesy Schlumberger.

The pressure compensation system has a diaphragm that moves inwards to equalize internal pressure with the outside pressure from the annulus or changes in volume from cone movement. The diaphragm moves outward to increase the internal volume from grease expansion and cone movement to equalize with external pressure. In doing so, grease can vent through the diaphragm into the annulus to equalize the pressure. Some bearing designs incorporate solid lubrication components such as thrustwasher or hardmetal inlays; others incorporate a silver-plated bearing surface. These components serve to form a dissimilar material system that mitigates adhesive wear when carrying the thrust component of the bearing load. These run against Stellite® inlays, in many cases, which also provide a dissimilar material system that mitigates adhesive wear. The inlays have higher wear resistance properties than steel so as to reduce bearing letdown. Not all roller cone drill bits have sealed bearings. Non-sealed bearing designs allow mud to enter the bearing for cooling and lubrication. Non-sealed designs have a shorter bearing life than sealed bearings as mud contains particles that can cause excessive wear to the bearings therefore shortening the bearing in comparison to sealed designs.

Diamond bits

Figure BI-15: A bit’s nose is described by the radius (R) of it’s curvature and the horizontal distance (L) from the bit centerline where the curvature begins. Courtesy Schlumberger.

Figure BI-16a & 16b: The bit above features a nose location close to the apex. This means higher cutter density on the shoulder. Therefore, there is more diamond volume, creating a bit suitable for abrasive formations. Courtesy Schlumberger.

Bit profile

The first factor is the bit profile, which is a vertical cross-section of the bit head. The profile has a direct influence on stability, steerability, cutter density, durability, ROP, cleaning efficiency and cutter cooling. The profile is divided as follows: The apex is the geometrical center of the bit. The cone area can be: • Deep cone profile;

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Figure BI-17a & 17b: When the nose moves further from the apex, higher cutter density exists along the cone. This increases cone durability, suitable for drilling strong formations, such as dolomite and limestone, as well as transitional drilling. Courtesy Schlumberger.

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BITS • Shallow cone profile. A deep cone profile has a cone angle of 90°. Due to the deep profile, the cone area has substantial lateral support, which makes it more stable. The lateral support also makes a bit with a deep cone profile harder to steer. A deep cone profile allows for higher cutter density and increases durability. The additional cutters increase the number of cuttings, and the depth of the cone means that the cuttings need to travel further to evacuate from the bottom of the hole.

Figure BI-18: In addition to the nose location, nose radius affects bit aggressiveness. A large radius increases surface area for better load distribution in hard and transitional drilling. A smaller radius provides higher point loading on the cutters, which is more suitable for soft, homogeneous formations. Courtesy Schlumberger.

A shallow cone profile has a cone angle of approximately 150°. Unlike a deep cone, the shallow cone offers less lateral support, making it much easier to steer. This makes a shallow cone profile suitable for downhole motors, rotary steerable system (RSS) and any directional application. It is less stable than a deep cone bit. Cutting evacuation is much more efficient with a shallow cone bit. The cuttings have less distance to travel to evacuate the bottomhole. The more shallow the cone profile, the fewer cutters on the bit. Fewer cutters results in a higher point load on each cutter, making a shallow cone more aggressive. A bit’s nose is described by the radius (R) of its curvature and the horizontal distance, or location (L), from the bit centerline where the curvature begins. The location of the bit nose and the sharpness of the radius curvature influences the bit’s aggressiveness and durability.

Figure BI-19: The bit shoulder stretches from the outside nose tangent to the start of the outside diameter radius (ODR). Courtesy Schlumberger.

A nose location closer to the apex permits more surface area on the shoulder. In turn, this means higher cutter density on the shoulder. The increase in the number of cutters means the point-load for each cutter is less than ideal for drilling in homogeneous soft formations. Because of a higher cutter density, there is more diamond volume, thus making the bit suitable for more abrasive formations. In a bit where the nose is moved further away from the apex, there is a higher cutter density along the cone. The increased number of cutters results in an increase in cone durability suitable for drilling strong formations, such as dolomite and limestone, as well as transitional drilling.

Figure BI-20: The outside diameter radius (ODR) is the transition between bit shoulder and gauge areas. Courtesy Schlumberger.

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Along with the nose location, the radius of the nose affects bit aggressiveness. A large radius increases the surface area for better load distribution in hard and transitional drilling. A smaller radius provides higher point loading on the cutters, which is more suitable for soft, homogeneous formations.

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Figure BI-22a & 22b: Straight blades stay on the same vertical plane form the apex to the gauge. Spiral blades are curved, which increases the overall blade length. That in turn provides room for more cutters. Courtesy Schlumberger. Figure BI-21: Nose locations are shown by the vertical lines intersecting the curves of each of four main profile types. The nose location changes with each profile type. Long parabolic profiles are considered the most aggressive, while flat profiles are the least. Courtesy Schlumberger.

The bit shoulder is from the outside nose tangent to the start of the outside diameter radius (ODR). The ODR is the transition between bit shoulder and gauge areas. The gauge is the outward-most part of the bit and helps to stabilize the bit and maintain an in-gauge wellbore. Undergauge holes impede or prevent entry and removal of tools. Bit gauge features can also provide stabilization to the bit and help prevent undesirable operating problems such as bit whirl. Various gauge types and lengths are available to achieve maximum drilling efficiency.

Bit profile types

Figure BI-23 graphically summarizes the four main profile types. Note how the nose location changes with the various profile types, from long parabolic to flat. In general, long parabolic profiles are considered the most aggressive, while flat profiles are considered the least aggressive. Long parabolic profiles work best in soft, abrasive formations such as shales, clays and mudstones. They are typically used in high-speed positive-displacement motors (PDMs) and turbine applications. Medium parabolic bit profiles are less aggressive and work best in medium-to-hard abrasive formations such as sandstone, limestone and hard shales. Medium parabolic bits are used in rotary, PDM, RSS and turbine applications. Short parabolic bit profiles are most effective in hard formations with medium abrasion such as sandstone, limestone and some cherts. This bit profile has the sharpest nose of the three parabolic profiles. The short parabolic is most likely the most versatile; it provides an effective compromise between ROP, wear and cleaning. Short parabolic bits are used in rotary, downhole motor and turbine applications.

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A flat bit profile drills best in harder, less abrasive formations such as limestone and dolomites. It is easy to predict the direction and behavior of a flat profile bit in a given formation. These bits are most often found in sidetracking applications. The number of blades on a bit affects bit performance. A matrix body bit can support from 3 to 20 blades, whiles a steel-bodied bit is generally limited to between 3 and 8 blades. The majority of PDC applications require between 4 and 9 blades. Each blade has PDC cutters brazed into it; collectively, these are called the cutting structure. Bits are considered symmetrical when the angles between successive blades are equal. If one or more angles are unequal, the blade arrangement is considered asymmetrical. Symmetrical bits are prone to vibration, and asymmetrical bits are less prone to this damaging behavior.

Blade Geometry: Straight or Spiral

Blade geometry and layout influence bit vibration. There are two types of geometries, straight or spiral. A straight blade is one where the blade stays on the same vertical plane from the apex to the gauge. The cutter radial forces are summed together as a whole on the gauge. Straight blades are more hydraulically efficient because of the straight geometry; the flow exiting the nozzles can sweep efficiently along the blade. A spiral blade introduces a curve on the blades and increases the overall blade length. This provides room for more cutters, and the circumferential contact area on the gauge is increased. Only the perpendicular component to the gauge of each radial force is used, and the net effect on gauge is less than that of straight blades. Spiral blades are not as hydraulically efficient as straight blades; including an extra nozzle in the bit design improves cutter cleaning.

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BITS In addition to standard roller cone and fixed cutter bits, many manufacturers custom-produce bits with features suited for a particular purpose.

Specialized roller-cone bits Air bits

Air bits use air or gas as the drilling fluid in underbalanced drilling (UBD). Air bits might have screens over the bearings to protect them from clogging with cuttings. They can also have thicker hardfacing on the shirttail to protect them from the abrasive, high-velocity air or gas drilling fluid.

Jet deflection bits Figure BI-23: A jet deflection bit.

On directional drilling operations, jet deflection bits are sometimes used in soft formations. Jet deflection bits have an oversized jet nozzle. Without rotating, the bit is run to bottom and the oversized nozzle is pointed (oriented) in the direction required to start the deflected hole. Then the mud pump is started. Because the bit is not rotating, the oversized nozzle washes out the formation and forms a pocket in the wall of the hole. This pocket helps start the directional drilling (Figure BI-23).

Specialized fixed-cutter bits

Unlike most fixed cutter bits, some specialty bits are designed and manufactured for very specific drilling needs.

Sidetrack bits

Figure BI-24: Sidetracking bit.

Sidetracking bits, when made up on a downhole motor, are used to drill around broken drillpipe or casing that is permanently stuck in the hole. Drilling around non-removable objects requires a form of directional drilling. These bits have a flat profile and a short gauge length (Figure BI-24). Some have large fluid outlets so that a high volume of drilling mud can circulate without losing pressure across the face of the bit.

Impregnated bits

Figure BI-25: Impregnated bit. Courtesy Baker Hughes Inc.

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Impregnated drill bits are drilling bits where the cutting elements contain diamond grit throughout. The elements might be sintered segments containing diamond grit (synthetic or natural) compacted in a matrix of tungsten carbide. The impregnated parts, where the segments are pre-sintered, are generally incorporated into the body of the bit when being processed through the furnace, as with diamond-set bits. It is also possible to fix the impregnated segments in place by brazing, although this technique is less used at present. In other styles the diamond grit is mixed with the bit matrix, forming an integral cutting structure. Like surface-set diamond bits, impregnated bits are used when none of the PDC and roller-cone bits are suited to economically drill a very hard and abrasive rock (Figure BI-25).

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Surface-set diamond bits/natural diamond bits

The use of a single layer of surface-set diamonds in the petroleum industry began in the 1940s by Franck Christensen. The diamonds were hammered in steel bit alveolus, or cavities, and filled with a thin layer of copper. Enhancement in the manufacture of fixed cutter diamond drill bits was made by setting the diamonds into a metal blend called a matrix. The matrix combined grains of tungsten carbide in an alloy of copper and nickel. This new technology allowed for the development of increasingly economical and custom-shaped bits (Figure BI-26).

Core bits

Core bits are shaped like a ring (Figure BI-27). The ring drills the formation on both its inside and outside circumference, so it has two gauge surfaces. The center hole surrounds a solid cylinder of rock (the core) that the driller recovers later. Once the core is retrieved, the operating company sends it to a laboratory for formation analysis.

Figure BI-26 Surface-set diamond bit. Courtesy Varel International.

Hybrid bits (PDC and roller cone)

The PDC and roller-cone hybrid bit combines the two traditional cutting structure types into one tool (Figure BI-28). This drill bit uses the crushing action of the rolling cutting structure to fail the rock and the shearing action of the PDC cutter to clean the bottom and accelerate the ROP. The rolling, pre-fracturing action decreases the common PDC tendency for high torque fluctuations, establishing a smoother, more efficient drilling response. Lower torque magnitudes mean reduced stick-slip and downhole vibration. The resulting drilling dynamics create smooth transitions between interbedded formations of varying strength and reduce overall vibrations for more reliable operation of downhole tool components. The more consistent torque responses also improve toolface control, and the hybrid bit is capable of achieving high buildup rates on push-the-bit, point-the-bit, bent-housing motors and other directional systems.

Figure BI-27: Core bits—PDC and natural diamond. Courtesy Corpro (a company of ALS Oil & Gas)

Hybrid bit technology tends to generate less torque than a PDC with a lower WOB requirement than roller-cones, which can be beneficial in drilling environments where these parameters are limiting factors with traditional bit solutions. The conventional bit breaker for the manufacturer’s PDC should be used. The nozzles are interchangeable with the manufacturer’s PDC bits and are installed the same way. Hybrid bits might be repaired and rerun, much like any PDC bit. Care, handling and storage instructions for both the roller cone and PDC bits should be followed. Figure BI-28a & 28b: PDC and roller-cone hybrid bits. Courtesy Baker Hughes Inc.

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BITS Table BI-2: Representative pass-through and hole size for eccentric tools. Figure BI-29a shows a bi-center bit, and Figure BI-29b shows an eccentric reamer.

Figure BI-29a & 29b: Bi-center bit (left) and eccentric reamer. Figure BI-29a courtesy Varel International. Figure BI-29b courtesy Baker Hughes Inc.

Representative applications, operational parameters and performance of the hybrid bit can be found in SPE literature. 52,53,54,55

Hole openers

The past twenty years have seen the birth and tremendous growth of hole openers in the oil and gas drilling business. Reasons for utilizing these more expensive BHAs have included drilling of difficult formation, preventing stuck BHA due to swelling formations, simplifying completions and allowing better cement jobs, which will be more and more critical in the future. First to come into the market were bi-center bits, followed by eccentric reamers. They are designed to pass through a given diameter of hole, and when rotated on bottom will drill a larger diameter hole by having the gauge cutting blades on one side only. See Table BI-2 for representative passthrough and hole sizes for eccentric products. Contact your supplier to verify the actual dimensions for the brand and style you might be running, as these are custom-made and vary by application and the customer requirements. In the 1990s, bicenter bits came into use on Gulf of Mexico deepwater wells. Here they solved several problems unique to deepwater GOM. These wells encounter drilling problems, including plastic flow of salt formations, sloughing and swelling of shale formations, and inflows and outflows of fluids. Compounding these difficulties is the depth of water. Drill-out bicenter is a special design developed because the casing tends to be damaged by the gauge cutting elements mounted on the bicenter drill bit when drilling the plug. When the bit is inside the casing, the pilot section of the bit tends to rotate about the center of the drillstring, causing the reamer gauge cutters to engage the casing. This damages the casing and the cutters on the bit.

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Drill diameter (in.)

Pass-through diameter (in.)

3.000

2.700

3.250

2.740

4.125

3.750

5.000

4.125

5.750

4.750

7.000

6.000

7.500

6.500

8.500

7.500

9.500

8.500

9.875

8.375

10.500

9.750

12.250

10.625

13.500

12.250

14.500

12.200

14.750

12.250

16.000

14.750

17.500

14.500

19.500

16.500

20.000

17.000

22.000

18.000

These are still available for the foreseeable future. They are relatively low-priced and have the reliability advantage of no moving parts or seals. Just go to bottom and turn to the right, and the hole is drilled and enlarged. In the case of many eccentric reamers, the pilot bit diameter is stabilized before the eccentric blades enlarge the hole. Maintaining the pilot hole size allows the creation of the proper-sized enlarged hole. A larger pilot hole allows an undersized reamed hole. Concentric reamers followed eccentric bits and reamers into the industry, first as near-bit flow-activated reamers, and later placed above the measuring tools. Ball-drop activated reamers displaced flow-activated reamers due to ease of use and reliability. This accounts for the majority of the market today. Upon introduction into the industry, many suppliers provided reamers properly balanced to their pilot bits56, 57. Without properly balanced relative aggressiveness, unacceptable levels of BHA vibration can restrict ROP to unacceptable levels and damage the BHA components. Vibration control continues to be a focus area.

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BITS Ultra-deep wells have successfully implemented ball-drop concentric reamers, probably the deepest being documented in SPE 14525958. This particular tool is not susceptible to hydrostatic pressure problems and completed the well to 31,400 ft (9,571 m). Flow-activated on-off reamers have made a resurgence. They can be difficult to operate, but they offer the advantage of being able to be placed below the measurement string as a rathole reamer, immediately above the pilot bit. This allows the operator to drill with flow-activated reamer closed until TD and then activate it and ream the rathole without a dedicated cleanout run, saving a trip. Other reamers are being developed that are activated or de-activated by RFID, or by electronic signal in the case of a wired pipe operation. A mud-pulse-activated tool is now available in two sizes on a limited basis 59 and is expected to grow in popularity given its compatibility with many existing rig systems. In hole openers and stabilizers with movable blades, care must be taken in handling to not damage the moving parts, which could result in an inoperable tool on bottom, or worse, one which opens but does not close.

Hammer bits

Hammer bits are a unique style of bit that designed for use on a downhole percussion hammer. They feature a solid head bit with either tungsten carbide or diamond-enhanced carbide inserts. The typical application is situations where it is not possible to put sufficient weight on bit on a standard bit to efficiently drill, such as very hard rock at the surface.

Casing-while-drilling bits

The unique bits are growing in popularity where the operator desires to drill with casing to the chosen TD for that interval and leave it in the hole as opposed to pulling the bit and drillstring. There are two styles of bits. One is run on a retrieval tool and is removed after reaching the casing point. The more common bit is designed to be drillable and is left on the end of the casing, cemented in and drilled out with the following bit. Typical application are in areas with heavy lost circulation, where the formations are easily PDC-drillable and the opportunity to save a trip and NPT, where heavy back reaming to get out of the hole was encountered on offsets, through depleted sands, shallow water flows and many others. For a detailed discussion of casing while drilling, refer to the dedicated chapter of the IADC Drilling Manual, 12th editon, on CwD.

Two-cone bits

Two-cone bits are a specialized roller-cone bit with all of the

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premium bearing, seal and insert technology of the threecone. They are sometimes used in very soft drilling applications.

Impreg and PDC hybrid bit

This is a unique style of bit employing both PDC cutters and impregnated inserts as backups, as the substrate behind the PDC table or in the matrix behind the PDC cutter. In isolated applications, the bit might have PDC cutters and impreg materials both as the primary cutting structure in different areas on the bit.

Cutting structures Roller cone Steel tooth

A steel-tooth cutting structure is valuable for various applications, especially soft formations. These bits are normally hardfaced with tungsten carbide pellets in a hardened steel matrix. The size and shape of the teeth and location of the hardfacing varies by the intended application and the design criteria amongst the manufacturers of the bits. A modification of this uses a composite cone made by powder metallurgy, which has the hardfacing integrally molded into the cone during the manufacturing process. Tungsten carbide hardfacing on steel tooth cones is necessary to provide wear resistance.

Tungsten carbide inserts

Tungsten-carbide inserts (TCI) are manufactured in a variety of shapes, sizes and lengths with specialized grades of carbide designed for specific applications and formations. The size of the bit and the type of formation it is designed for has a direct effect on the insert needed. The physical appearance of cutting structures designed for soft, medium and hard formations can readily be recognized by the shape, length and geometric arrangement of the inserts. Bits with large inserts with large projections and generally chisel-shaped inserts are designed for softer formations. Those for hard formations contain smaller ball-nose-shaped inserts with an increased number of inserts. A bit designed for medium-strength formations typically has a conical or a blunt stubby chisel insert with moderate projection (see Figure BI-30). The inserts are composed of cemented tungsten carbide, which is a mixture of tungsten grains in a metallic binder, usually cobalt. The carbide grain size and cobalt content are adjusted to produce the desired combination of wear resistance and toughness required for the particular application. This mixture is pressed to shape, sintered at a high tempera-

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Figure BI-30: Tungsten carbide inserts (TCI) can be designed for soft, medium and hard formations. The TCI bit above was designed for medium-strength formations, and features a conical or a blunt stubby chisel insert with moderate projection. Courtesy Schlumberger.

ture in a furnace and finished to the final shape. They are then press-fit into precision holes in the cones. This material has the combination of wear resistance and toughness to perform well in the TCI bits. One specialized form of a TCI bit uses a diamond-enhanced insert (DEI) for added wear resistance of the cutting structure in extremely abrasive applications. These insets employ a specialized layer of polycrystalline diamond over a TCI. They are typically used in medium-to-hard and very abrasive applications and in directional drilling applications where wear and rounding of the gauge and heel area would have a negative impact on the bit performance. These bits have been documented to have longer life and improved bearing and seal reliability. There are other downhole benefits. One is a reduction in the amount of reaming needed by maintaining a full gauge hole. Another benefit is the prevention of heat checking on the heel and gauge row inserts, more commonly seen with downhole motors and high rotary speeds. Operating parameters are the same as for a conventional TCI bit. Another specialized feature on rolling cone bits is a mechanical or metal-faced seal, as opposed to the more common elastomer seal. The distinguishing feature from the external examination of a bit is the very easy rotation of the cones. Care should be taken in handling to prevent pinching of a hand or finger between cones when handling the bits. Typical applications are high rotary speeds and large-diameter bits where the heat generated from the friction of the tightly squeezed elastomer seal leads to high heat and damage to the seal.

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Diamond bits PDC cutter technology

A PDC is the cutting element on a PDC bit. It is composed of very fine diamond crystals sintered under extreme pressure and high temperature to a tungsten carbide carrier known as a substrate. Diamond is the hardest known substance and is also the best-known conductor of heat. It also has a very low coefficient of friction against rock. This combination of unique properties was the driving force in the development of the PDC cutter in the 1970s. In other words, diamond is the best material in resistance to abrasion, has the ability to withstand and transmit compressive forces, removes heat from the cutting tip efficiently, and generates less heat from friction than other materials. To manufacturer the PDC cutter, the provider utilizes specially designed high-pressure, high-temperature equipment known as HPHT apparatuses or diamond presses. There are a variety of different system designs. These systems are known as the cubic press, the belt press and the piston-cylinder press. All three press systems are capable of generating the ultra-high pressures (800,000-1,000,000 psi or more) and high temperatures (2,700°F) required to sinter the polycrystalline diamond (PCD) used in the bit. (Note: Polycrystalline diamond, or PCD, is a term used by materials scientists working on synthetic diamond. But, somewhat confusingly, the cutter on the bit is typically called PDC.) Each of these press designs are used commercially, and each has its own particular advantages relating to sintering characteristics and properties imparted to the product.

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Figure BI-31: Types of grain. Courtesy Schlumberger.

The application for the PDC cutter is determined by the grade of diamond used in the manufacturing process. Diamond grit size, distribution and density have an effect on the final cutter properties. If the initial diamond grit is fine (1-6 microns), the cutter has high abrasion resistance but lower impact resistance. Medium-grain grit (7-15 microns) cutters display moderate abrasion and medium impact resistance. Coarse-grain grit (16+ microns) cutters have low abrasion resistance and better impact resistance. Most PDC cutters employ a multi-modal mixture of grain sizes in which the mixture of fine-medium-coarse grains is chosen to impart a particular balance of wear resistance, impact resistance and diamond density for the intended application. Some PDC cutters used in the industry have a unique layered structure that utilizes the wear-resistant fine-grained diamond on the face and the coarser and tougher diamond feed backing it up to provide a combination of excellent abrasion resistance supported by a tough and durable underlayer between it and the carbide substrate.

Figure BI-32: Two primary PDC designs exist, the cylinder and the stud. Cylinder cutters can achieve greater cutting densities and are the most common today. Stud cutters offer greater flexibility to achieve a particular cutter exposure. Courtesy Schlumberger.

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PDC types

There are two primary PDC designs: the cylinder and the stud. Cylinder cutters are able to achieve greater cutting densities on a given bit profile and are the most common used on today’s bits. Stud cutters have greater flexibility to achieve a particular cutter exposure. Although cylinders are more common, both types of cutters are used by leading bit manufacturers.

Diamond table

A key element with both types of cutters is the diamond table. The thickness of the diamond table is typically 2-4 mm thick. The thickness is a variable utilized by the fabricators to provide cutters that have properties and behaviors tailored to the specific application of the bit.

Cutter shape

PDC cutters are manufactured in a cylindrical wafer shape. Round cutters are the most common shape used on PDC bits. PDC cutters can be precisely cut to shape using a laser or electrical discharge machine. Other shaped PDC cutters are made directly to their shape in the diamond press.

Figure BI-33: The diamond table is typically 2-4 mm thick. Courtesy Schlumberger.

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Figure BI-34: PDC cutters are manufactured in a cylindrical wafer shape. The cutters can be cut precisely to shape with a laser or electrical discharge machine. Courtesy Schlumberger.

Thermally stable polycrystalline cutters

First developed in the 1980s as an alternative cutting element, today thermally stable polycrystalline (TSP) cutters are primarily used in the gauge of a matrix PDC bit. There are a limited number of bits still made for unique applications that use the TSP as a primary cutting element. They might be a fully leached PDC element where the cobalt catalyst is removed by an extensive acid treatment, or they might be a diamond matrix with a silicon carbide material disposed within the area between the diamonds. After the leaching process, TSPs are cut into the desired shape based on application. Unfortunately, TSPs are not wettable, which limits their application.

Leaching

TSP cutters are PDC cutters that have gone through the leaching process. The patented leaching process is used to remove the cobalt and increase the thermal coefficient of the cutter.

TSP application

TSP cutting elements can be used in a variety of applications. Ideally, these cutters were designed to drill harder and more abrasive formations such as sandstone, limestone and granite. A higher tolerance to abrasion is required, which is accomplished with the significantly stronger diamond-to-diamond bond and removal of the cobalt catalyst The variety of shapes and sizes that are most commonly in used include triangles, rectangles and cylinders. Matrix-bodied bits provide an excellent medium for TSP cutters. When the cutter is set in the bit face with a matrix backing, very aggressive exposures can be achieved. Self-sharpening characteristics can then be utilized, with the cutting element

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exposing new diamond as it is worn. The tungsten carbide matrix, with its lower abrasion resistance, wears away sooner, exposing more cutter and maintaining a positive angle between the cutter wear flat and the formation.

Cutter design

Now that the manufacturing process has been explained, let us examine cutter design characteristics. The various design characteristics greatly affect the overall cutter performance. The characteristics that directly influence performance include impact, abrasion, shear strength and thermal stability.

Finite-element analysis

Finite-element analysis (FEA) is a mathematical process used by engineers to design cutting structures that are used in all types of formations for analyzing a geometrical shape and calculating the effectiveness of the interfaces. The models produced reflect the stress state and magnitude. They also serve to predict high-stress areas that could be prone to failure and allows mitigation through selective modification of the interfaces and other parameters. This valuable process is used in the design of cutters, inserts and nearly every component and bit style in use today.

Impact test

Impact damage is the mechanical failure that occurs when the forces from the formation are able to overcome the bond of the diamond table to the substrate or the bond in the diamond table. In conjunction with FEA analysis, the industry is continually mechanically testing PDC cutters for impact resistance using a specially designed testing apparatus. This is a way of experimentally validating and comparing cutters before field testing commences. The drop tower test is performed to

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BITS test impact. During the test, an up-sharp cutter is fastened onto a steel bar with material properties and surface finishes that are carefully controlled. Tests are performed at several energy levels using multiple cutters per level. Cutters are then ranked according to the degree of failure by percent of spalling, number of hits to failure defined as whenever spalling area is over 30% of the diamond table surface area, and failure mode. The final number is a relative number that gives a general indication of impact resistance. Most suppliers have some form of impact test, although there is no industry standard.

Abrasion test

Abrasive wear occurs on a microscopic level through a process of impact shock and fatigue on the individual diamond grains. On impact with rock particles, some diamond grains experience crushing in which the edge of the diamond grain is gradually removed. Other grains might experience cleavage fracturing across the entire plane of the diamond grain. During an abrasion test, an up-sharp cutter is rotated against a granite block until failure. At the end of the test, the volume of rock removed until the point of failure is measured, and results for each cutter type are ranked. There is also a granite mill test, which tests abrasion as well as impact fatigue. Most suppliers also conduct additional abrasion testing run on large vertical turret lathes on large blocks of stone. As for impact testing, however, there is no industry standard.

Thermal stability

Thermal stability is the ability of a cutter to maintain its integrity at higher temperatures. PDCs used at temperatures below 1,380°F are primarily worn down by impact. Unfavorable stress conditions increase in PDCs at temperatures over 660°F. At this temperature, micro-chipping intensifies due to degradation of the bond between individual diamond grains. The hardness of the diamond table decreases linearly as the temperature approaches 1,290°F. At temperatures over 1,380°F, the wear changes from microscopic chipping of diamond grains to macroscopic loss of entire grains. Wear rates resulting from high temperatures are elevated and unpredictable. PDC cutters have no practical life under those conditions. TSP cutters might be necessary in applications where there are excessive temperatures. An abrasion/thermal wear test is conducted to evaluate PDC cutter wear and depth of cut when the cutter is rotated on a rock sample.

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Substrate interface

Substrate geometry at the interface area seeks to enhance bonding with the diamond table. Generally, geometries that increase interface surface area improve bonding. Geometries also attempt to hold stresses at the bond to the lowest possible level. Geometrically, the shape of a diamond table seeks to include the highest possible diamond content. Geometric features of the interface between the diamond table and the substrate can significantly improve the ability of a diamond table to withstand impact. For this reason, the interface between the diamond table and substrate is geometric rather than planar in premium cutters used in sever applications. Different types of interfaces are used based on the type of application and the location of the cutter on the bit. Depending on the type of application, the interface on the substrate is either planar or non-planar. High-temperature cutters have optimized diamond table thickness through the use of NPI in conjunction with FEA. Different interface geometries were developed by PDC cutter suppliers to minimize residual stresses concentrated in the diamond table during the manufacturing process.

Related equipment Additional bit accessories

Several items support bits being used at the rig site. Examples are listed below. • Nozzle kit: This kit includes the items needed to change out the nozzles safely at the rig site if some hydraulic modifications are needed from the initial requirements. This kit likely varies among the various drill bit manufacturers. Never assume the nozzles from one manufacturer fit another despite visually similar appearances; • Lifting straps: Appropriate lifting straps must be used depending on the weight of the bit being lifted. Refer to the appropriate bit handling procedures for more information on how to handle bits; • Lifting bail and cap: These are used to help move the bit around the rig. They are screwed to the end of the shank threads. There are both pin and box thread types available, depending on what type of upper connection is on the tool (see Figure BI-35); • Bit breakers: The appropriate bit breaker needs to be available at the rig site to make up and breakout the bit. Refer to the bit make-up and breakout procedures for the specific drill bit in question. Use the bit breaker from the manufacturer of the bit. Do not attempt to use a breaker

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Figure BI-35: Lifting bail for pin. Lifting bails are used to help move the bit around the rig. They are screwed to the shank threads. Both pin and box thread types are available. Courtesy Baker Hughes Inc.

from another supplier as it could result in damage to the bit or could be damaged and cause an injury; • Thread protectors: These help protect the thread on the bit shank so the threads (usually made of plastic) do not get damaged. They must always be used when the thread is not screwed into a BHA component, lifting bail or cap. One could use a pin or box type depending on what type of connection the tool has (Figure BI-36); • Ring gauge: The appropriate ring gauge should be available to verify bit gauge. The gauge of the bit must be verified prior to the bit run. (See API Spec 7-1 Specification for Rotary Drill Stem Elements.) Drill bit vendor employees or rig site crew personnel can perform this task. Dull grading gauge measurements must be taken once the bit has been run (Figure BI-37). Note: Be sure the ring gauges being used are for the appropriate bit type. Due to the API specifications, the manufacturing tolerances on a roller-cone and PDC are different enough to require separate gauge rings for the two products.

Installation

When installing drill bits, or making-up, it is traditionally accomplished via attaching it securely to the end of the drill stem by using a bit breaker. Not all bits of the same size or type or from the same vendor might use the same bit breaker. Roller-cone bit breakers often have a bottom-plate versus the gate-style prevalent with the fixed cutter bits. It is best to check with the vendor to ensure the proper bit breaker is used with the bit to prevent lost time or injury while trying to make up the bit with the incorrect breaker.

Nozzle and plug installation and removal Figure BI-36: Connections with and without thread protectors Thread protectors must always be used when the thread is not screwed into a BHA component, lifting bail or cap. Courtesy Baker Hughes Inc.

Figure BI-37: Ensure that the correct ring gauge is being used for the appropriate bit type. Manufacturing tolerances on roller cones and PDCs differ enough to require separate gauge rings. Courtesy Baker Hughes Inc.

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PDC nozzle installation

1. Determine the nozzle requirements; 2. Gauge the nozzle orifice to ensure proper nozzle size. Nozzle gauges might be obtained from the vendors and should be readily available on the rig; 3. Inspect the nozzle threads or nozzle retainer threads and the nozzle socket threads. Remove all debris with a small brush and environmentally safe solvent if needed; 4. Inspect the O-ring. Ensure that the O-ring is properly seated and is not cracked or damaged. If the O-ring is damaged, it should be replaced; 5. Apply anti-seize to both the threads of the nozzle socket and the nozzle. If there is a problem or history of nozzles backing out in an area or application, then do not use any anti-seize and apply approximately three drops of Loctite 242 to the threads of the nozzle; 6. Carefully thread the nozzles into the nozzle sockets; 7. Using the wrench provided, slowly turn the nozzle or nozzle retainer clockwise until resistance is felt. Then

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back the nozzle out ½ turn counter-clockwise and continue rotating clockwise until a firm resistance is felt to finish seating the nozzle against the O-ring; 8. Tighten all nozzles by hand or using a torque wrench to 35 ft-lb.

8. Rotate the snap ring with the snap ring pliers to ensure that the snap ring is seated; 9. For applications in corrosive environments, coat exposed snap ring with water-repelling grease.

PDC ports, plug removal

1. Retaining pin type installation follows steps 1-6 of snap ring installation; 2. Choose the retaining pin length that correlates to the nozzle and then insert the pin into the retaining pin hole. Tap it with a hammer until the head is flush with the bit body. A properly installed pin could be slightly loosefitting.

1. Use provided hex wrench to remove the two plugs; 2. Keep removed plugs and O-rings in a cool, dry place, in case the reinstallation is necessary. PDC ports, plug installation 1. Inspect and clean ports using the same method used for nozzles; 2. Remember that plugs are sized specifically for the given port size; 3. Use anti-seize on the threads of the plug; 4. Fit the first plug and hand-tighten it, using the provided hex wrench; 5. Install a clean, undamaged O-ring on top of the first plug; 6. Thread and hand-tighten a second plug on top of the O-ring and first plug.

PDC nozzle installation and removal tools • Nozzle extractor; • Nozzle wrench.

Roller cone, nozzle installation

Depending on the manufacturer, roller-cone nozzles might be installed using threads or snap rings to hold in place. For threaded nozzles, use similar process to the PDC nozzle installation described previously.

Snap ring

1. Determine the nozzle requirements; 2. Select and clean and inspect the nozzles for any damage. Do not use cracked or chipped nozzles; 3. Gauge the nozzle orifice to ensure proper nozzle size; 4. Place the bit on its pin with the cones facing up; 5. Lubricate the nozzle socket and O-ring with light grease or lubricating oil. Make sure that the O-ring is not damaged and is properly seated in the O-ring groove; 6. Insert a nozzle into the nozzle socket with the smaller opening of the nozzle facing out. Push the nozzle with both thumbs until it passes the O-ring and seats with the top of the nozzle below the snap ring groove. Never hammer the nozzle into place. This can chip or crack the nozzle and damage the O-ring. Protective eye wear should be worn, since tungsten carbide nozzles can chip easily from any impact; 7. Place the tips of the snap ring pliers into the holes of the snap ring with the flat side facing up and compress the snap ring until it fits into the nozzle socket. Insert until snap ring aligns with groove and release the snap ring until it seats in the groove;

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Retaining pin

Large diameter bits - center jets and ports

Each drill bit company and third-party nozzle provider provides specific installation procedures for center jets and ports located in the throat of the roller cone.

Roller cone, nozzle removal

1. It is easiest to remove the nozzles immediately after the bit is pulled out of the well; 2. Clean the nozzle and nozzle sockets of mud and cuttings; 3. Place the bit on its pin end with the cones facing up; 4. If the nozzles are not being removed immediately after running, apply water or penetrating oil to the nozzle sockets. Wait several minutes to allow the water or penetrating oil to work before proceeding; 5. Orient the snap ring so the ears are toward the outside of the bit; 6. Insert snap ring pliers in the holes of the snap ring, compress and remove the snap ring from the nozzle socket; 7. Insert the nozzle puller into the nozzle and pull up with a twisting motion to remove the nozzle.

Roller cone nozzle installation and removal tools • • • •

Nozzle gauge; Snap ring pliers; Nozzle extractor; Nozzle hammer.

Bit make-up procedure

1. Proper lifting techniques and equipment must be used to bring the tools to the rig floor. Drill bit in the bit box/ container and appropriate bit breaker (where applicable) should be brought up to the drilling rig floor; 2. When picking up a bit, take all the precautions normally taken while lifting and handling a bit, along with the following additional precautions; 3. When removing the bit from its box, handle it carefully. Do not roll it out on the rig floor and let the cutting structure get damaged, which will reduce the life and performance of the bit. PDC bits must be placed on a

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BITS should be locked so as to not allow rotation, where applicable; 12. Use the tongs system or appropriate wrench system to apply the torque to the connection. API Recommended Practices 7G lists the torque requirements for the tool connection type. The unique bit specification sheet will also have the torque requirements.

Bits run on special BHA tools

Note: Make all personnel aware of the correct bit lifting procedures in the pre-tour safety talk or drill floor tool box talk.

Figure BI-38: Bit breaker and breaker box in rotary table with BHA tool above bit. Courtesy Baker Hughes Inc.

wood or rubber mat to ensure that the diamond cutters are not damaged; 4. Perform a visual inspection of the interior (center waterway) of the bit to ensure that no debris is left inside prior to making up the bit to the drillstring. Rags, gloves and other debris can plug a nozzle and result in hydraulic back pressure problems on the rig equipment and improper fluid flow across the bit, resulting in poor cleaning and cooling of the cutting elements and leading to bit balling or damage to the cutting structure; 5. Ensure that appropriate nozzles are installed for the application; NOTE: Some smaller bit sizes (less than 5 in.) might not require a bit breaker. These small bits generally weigh less than 50 lb (22 kg) and can be lifted by a person, unless there are personal limitations. 6. Install the appropriate bit breaker that is designed for the bit as required; NOTE: The bit breaker should be visually inspected to verify that there is no possible way for the bit breaker to malfunction. The system of bit, bit breaker and master bushing should match up for proper fit. 7. Place the bit and bit breaker assembly into the rotary table. Do not allow any junk to go down into the borehole while setting the assembly in the rotary table; 8. Prior to applying the thread compound, inspect the pin/ box threads; 9. Apply the threads compound to the bit threads and/or the next tool above the bit; 10. Carefully bring the bit thread and tool above bit together to engage the threads. One or the other (bit or tool above bit) should be rotated to engage the threads; 11. When the bit and tool are engaged, the rotary table

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Some BHA components might require special considerations. One example would be that some rotary steerable directional drilling tools might require a breaker box to lift the bit off the rotary table to allow the bit to be made-up or broken out of the BHA tool, just above the bit (Figure BI-38). The bit has to be lifted up off the table to help get the tongs on the tool above the bit to allow the bit to be made up or broken out.

Suggested operating recommendations

It has been said by some industry experts that more damage is caused getting to bottom and in the first 10 minutes of a bit’s life than in the rest of the run. “Tagging” bottom can damage the cutting structure and, in extreme cases, the bearings and seals. Care should also be taken when running to bottom not to hit a ledge from a prior run. Forcing a bit to bottom in an undergauge hole results in a pinched bit and can result in premature bearing and seal failure, and/or cutting structure interference and damage. PDC bits might suffer premature damage to the shoulder and gauge. Rotating a PDC bit on a motor and adjustable kick-off (AKO) motor in the casing can result in damage to the casing and also broken shoulder and gauge cutters on the bit. Optimizing drilling performance through operating parameter optimization is frequently interpreted as maximizing the ROP, but this is not always appropriate and might cause poor overall performance. In some applications, drilling performance is optimized by maximizing the bit run length, thus reducing the number of trips. In these cases, the goal is to protect the cutting structure, so it might be necessary to reduce penetration rates to gain increased durability of the cutting structure and save more time with reduced trips than the upside potential of short-term ROP gains. In some applications, drilling performance is optimized by minimizing reactive torque, thus reducing the occurrence of vibrations. This can be achieved by running the drill bit with reduced parameters: for example, with low WOB. In other applications, best life is obtained by using higher WOB and

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BITS lower rotary speed. Contact your bit representative for specific recommendations for the BHA design and formations being drilled. In some applications, borehole quality for logging purpose or casing running issues might need the application of reduced parameters and a decrease of the ROP.

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• •

Operating parameters optimization strategy should be guided by: • Understanding what the primary aim of the application is; • Understanding the challenge of the environment being drilled; • Understanding the constraints on performance associated with the drilling equipment you are working with.

Optimizing parameter overview

• A diligent driller that performs frequent drill-off tests for drilling parameter optimization always drills further and faster than the driller who “sets and forgets;” • Be on the rig floor (physically or virtually) at all crew changes. This is critical to ensure optimum drilling parameters are maintained and to update the new driller of the current drilling/rig issues and any drilling parameter testing in progress; • If running a motor, try setting the automatic driller to run off motor differential pressure rather than WOB. This generally corrects the weight faster; consequently, the weight is applied more consistently and better performance is achieved; • Conduct a series of drill-off tests to find the optimum drilling parameters to achieve satisfactory penetration rate or to minimize bit/BHA damage; • Formation changes can result in a penetration rate change; if the ROP reduces and reasonable torque is still generated, the formation is likely to be harder so the rotary speed should be reduced and weight increased. If this generates too much torque, weight should be reduced and RPM increased; • Monitor mudweight. As mudweight increases, ROP generally decreases. When closer to balanced drilling (where the mud pressure equals the formation pore pressure), ROP generally increases; • Maintaining good notes is very important for optimizing drilling performance over an entire run. It also aids understanding/problem solving if the drilling becomes problematic; real-time visualization of the drilling parameters makes it easier for you to see trends over time; • Parameter readings are more accurate if read directly from the gauges (Martin Decker for WOB, the stand pipe gauge for pressure, etc.) than those displayed on the rig

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floor monitor. The rig floor monitor can be inaccurate unless data are frequently recalibrated as hole is drilled; There are no rotary speed limitations for a PDC bit in rotary and motor applications. Rotary speed constraints are established by rig and downhole motor capabilities; Critical drillstring RPM (destructive drillstring harmonics initiated) should be avoided; Use the RPM that gives the best performance, avoiding critical drillstring harmonics; It should not be necessary to use the maximum WOB value for the bit—exceeding this significantly increases the risk of catastrophic failure.

For more on vibration mitigation in bits, as well as other guidelines for running bits efficiently, please refer to the separate Drilling Practices chapter of the IADC Drilling Manual, 12th edition. The Drilling Practices chapter also includes physics-based guidance on connection practices, reaming to condition holes, hole cleaning, tripping, wellbore stability management and lost circulation.

Mechanical specific energy Importance in drilling operations

Fundamental to any drilling optimization program is knowing what the energy balance is downhole. Is the energy being input into the system being used efficiently in the drilling of the rock? • Where energy is not being used efficiently, that energy is invariably used in phenomena that are detrimental to the bit and BHA: for example, vibrations that can lead onto cutter damage; • Due to this, it is important in all drilling operations to be aware of the energy usage in the subsurface, and one of the ways of doing this is by monitoring mechanical specific energy (MSE) values.

Definition

MSE is the amount of energy consumed to remove a unit volume of rock and expressed in lb/sq in. (psi). • MSE values are best measured (if possible) at multiple points along the BHA, as that way you get a better idea of the energy distribution and its application; • For the best understanding of what energy is available for the bit, you need to get MSE values from as close to the bit as possible; • These downhole MSE values are provided by specialist downhole drilling dynamic measuring tools. If they are not being recorded and transmitted, then you are generally limited to surface MSE alone.

Application

If drilling were taking place with 100% efficiency, the energy

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being input into the system would match the rock’s confined compressive strength (CCS expressed in psi). • In reality, there is never 100% efficiency, but what should be seen in efficient drilling is a trend for MSE values to be approaching the rock’s compressive strength; • When analyzing MSE values, do not fixate on the absolute values—the best way of using MSE is as a trend indicator; • For example, an observed increase in MSE value with no corresponding change in lithology type and strength indicates that a drilling inefficiency is appearing (for example, cutter dulling, bit balling, vibration, etc.). Interpreting what the drilling inefficiency is, and what is causing it, can be a complex task, so appropriate training is needed to use MSE analysis proactively. As mentioned, the best MSE analysis is done where you can access values from various positions in the BHA.

Monitoring drilling parameter procedures Data sources

• Fully understand the source of the data, as the source influences how much credence is given to it during decision making; • If several measurements of the same parameter exist, analyze those drilling parameter values measured as close to the bit as possible; • Surface data need to be treated more circumspectly, especially if you have the likes of a motor present in the BHA; in that scenario, the values should be used more qualitatively as trend indicators than quantitatively in the likes of MSE analysis; • In the best-case scenario, you should be monitoring both surface and downhole measurements simultaneously. Doing so delivers the most accurate representation of what is happening in the wellbore.

General overview of monitoring

Closely monitor the following parameters: • ROP; • Rotary speed; • Torque; • WOB; • Flow rate; • Standpipe pressure; • Pump stroke rate. Undertake this while reaming as well as when drilling a new formation. Ensure that the mud logging unit (or rig data system if ap-

IADC Drilling Manual

propriate) records all relevant parameters when drilling and when reaming. Continuously compare the observed drilling performance (ROP, torque, standpipe pressure) and cuttings interpretation with the prognosis for the well. Any discrepancies between the observed and anticipated performance should be evaluated and explained. Compute the MSE (if not already being generated by any of the rig data systems being used). Compare this with the prognosis unconfined compressive strength (UCS) for the formation being drilled to get an idea of the overall drilling efficiency. In the ideal world, with 100% energy efficiency, the MSE value should be coming close to the UCS value.

Rotary speed

Total bit RPM is equal to the surface RPM plus the downhole motor/turbine rotary speed. • High rotary speed should be avoided in abrasive formations to prevent rapid thermal abrasive wear; • High rotary speed should be avoided if the drill bit starts whirl; • Some rotary speeds can initiate drillstring resonance and should be avoided. This can be done by determining critical RPMs; • High RPM in hard formations might reduce ROP, as the cutters are unable to dig in the formation; • Rotary speed might be limited due to drillpipe or drive limitations.

Torque

Rotary torque is an indicator of what is happening at the drill bit. In soft formation, torque might indicate the bit is on bottom before the WOB does. The torque could be considered high when it starts to slow down surface rotary speed and stalls the motor, rotary table or top-drive. Interbedded formations produce torque changes as the bit moves in and out of formation beds that have different rock strength and drillability, while homogeneous formations produce smooth constant torque signals. If downhole torque measurements are available, they can be used in combination with surface measurements for greater accuracy.

Weight on bit

As the bit wears, more WOB is required to achieve the same ROP in a homogeneous formation. In general WOB should be applied before excessive RPM so that the cutting structure maintains a significant depth of cut to stabilize the bit and prevent whirl.

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Flow rate

Generally, high flow rate provides better hole cleaning than low flow rate, as it removes the cuttings more efficiently due the resulting high velocity and high hp/sq in. (HSI). However, excessive HSI might result in poor borehole quality due to washout. Flow rate must match with junk slot area (JSA) to prevent bit erosion, particularly in the case of rock bits and steel body PDC bits.

When to pull the drill bit

There are many reasons why an operator might desire to or need to pull a drill bit. Below is a detailed list of some of the most common reasons and guidelines for when they might be applicable.

Pull the bit for ROP

The decision to pull the bit because of low ROP should be based on a review of the observed ROP, drilling efficiency, cuttings interpretation and their comparison to expectations. • Be aware of offset performance in all the relevant formations; • ROP could be poor because of a transition into a hard formation and not necessarily because of a damaged bit; • If no relevant offsets exist, it is crucial to focus on the drill bit response to parameter changes before deciding to pull the drill bit. 1. Estimate the ROP to section TD with the current bit and compare it to the ROP of a new bit; 2. Could the bit currently in the hole be able to drill to the next planned trip, to section TD or to the next change of BHA? If not, pull the bit; 3. Compare the cost of leaving the current bit in the hole longer, with the cost of tripping the bit and replacing it with a new bit. Would the time saved by the higher penetration rate of a new bit be sufficient to compensate for the time spent on the trip and the cost of the new bit; 4. Do not leave a bit on bottom once it is determined that the bit should be pulled. Grinding away on bottom destroys the dull characteristics that could reveal the cause of the bit’s loss of performance or damage. It could also leave junk in the hole, such as a cone from a roller-cone bit or nozzles from a fixed-cutter bit.

Pull the bit for mechanical damage

The evaluation of possible mechanical damage to the bit differs between bit types.

»» PDC bits • A worn cutting structure tends to require more WOB to achieve comparable ROP compared to a bit with sharp cutters. The bit becomes less aggressive, which means the reactive bit torque generally decreases for a sustained WOB;

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• With a worn bit, torque tends to gradually decrease as the consequence of ROP drop, while the MSE tends to increase; • Sudden PDC cutter damage causes an instantaneous reduction in penetration rate, as opposed to a progressive reduction; • A fixed cutter bit should be pulled as soon as it is believed to have suffered major mechanical damage such as a “ring-out” or a broken blade; o Ring-out and broken blades can occur when the cutting structure is damaged by a high impact event, i.e., lateral vibration. The high lateral vibration can damage a set of cutters, which subsequently requires the remaining cutters to increase their work rate, which ultimately accelerates the wear rate on the remaining cutters; o Ring-out and broken blades can occur during period of high stick-slip. During the stick phase, the cutters and blades are loaded the greatest amount.

»» Roller-cone bits • The most frequent mode of failure for a roller-cone bit is bearings failure. A roller cone bit should be pulled as soon as there are good reasons to believe that a bearing has failed. The threat of leaving junk in the hole is very serious and could lead to very costly fishing jobs for the customer; • With correct operating parameters and procedures, a sealed roller cone bearing can operate for hundreds of thousands of bit revolutions before it wears to the point of a failure; • Open bearings have a much shorter operating life and should not normally be used in applications that require runs much in excess of 24 hours; • Bearing failures can occur sooner than the target life span. If a bearing failure is not detected rapidly, there is a real prospect of a cone becoming detached from the bit and left downhole.

Factors involved in premature bearing failure: • • • • • •

Incorrect operating parameters; Unsuitable cutting structure; Severe gauge wear; Incorrect reaming practices; Unsuitable BHA; Axial and torsional drilling string vibrations.

Pull the bit for bit balling

1. First, try to remove the balling before deciding to trip the drill bit; 2. If attempts to remove the balling are unsuccessful, perform the cost/ft analysis to assess the cost of the trip.

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Figure BI-39: Format of IADC dull grading chart.

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Pull the bit for nozzle problem »» Lost nozzle The primary symptom of a lost nozzle is a sudden decrease in pump pressure due to an increase in the total flow area (TFA). • If ROP isn’t affected significantly, the drilling operation could continue. The lost nozzle in the hole could damage the drill bit’s cutting structure; • Drilling with a missing nozzle could increase the risk of eroding the drill bits nozzle ports. Monitor the pump pressure; if the ports are eroding, the pump pressure would gradually decrease; • A lost nozzle could increase the risk of bit balling due to the reduction in HSI.

»» Plugged nozzle The primary symptom of a plugged nozzle is an increase in the standpipe pressure due to the blockage in the flow area. The symptoms are the opposite of what is seen in the case of lost nozzle. There are various factors that could clog up a nozzle, ranging from swollen or sticky formation cuttings to loose mud motor stator chunking (junk inside bit).

Dull grading and forensics

Paper SPE/IADC 23939, developed under the auspices of IADC and presented the 1992 IADC/SPE Drilling Conference held in New Orleans, Louisiana, February 18-21, 1992, outlines the dull-grading procedure for fixed-cutter bits. Figure BI-40 shows examples of dull characteristics. The IADC Fixed-Cutter Work Group during 1991 audited the 1987 Fixed-Cutter Dull Grading System and determined that some minor refinement was necessary. As was the case with introduction of the fixed cutter dull grading system in 1987, the objective of this revision was to facilitate creation of a “mental picture” of a worn bits physical condition through a standardized evaluation of certain bit characteristics.1 Because the system provides an industry-wide standard for recording the physical condition of the worn bit for future reference, the meaning of a dull grade should be subject to as little misinterpretation as possible. Therefore, committee discussions focused on two specific areas: improving the definition of “usable cutter height” as it relates to evaluation of PDC cutter wear, and making minor enhancements to the wear characteristic codes.

System enhancements

shows eight factors to record. The first four spaces describe the extent and location of wear of the “Cutting Structure”. The next two spaces address other criteria for bit evaluation, with the fifth space reserved for grading “Bearing” wear of roller cone bits. This space is always marked with an “X” when fixed cutter bits are graded. The sixth space indicates “Gauge Measurement.” The last two positions allow for “Remarks” which provide additional information concerning the dull bit, including “Other (or

The format of the dull grading chart, shown in Figure BI-39,

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Inner Area 2/3 Radius

Outer Area 1/3 Radius GAGE CONE

TAPER

NOSE

1 0

2

GAGE

SHOULDER CONE

NOSE

SHOULDER TAPER

3 4

GAGE

5

SHOULDER

6

GAGE CONE

SHOULDER NOSE

TAPER CONE

7

NOSE

A1-4

Figure BI-42: Location designations. Figure A1-4 Location Designation

Figure BI-41: Location designations.

Secondary) Dull Characteristics” and “Reason Pulled,” respectively. The system grades all PDC cutters based on condition of the visible diamond table of the cutter, regardless of cutter shape or exposure. This differs from the former practice of grading PDC cutters based on “usable cutter height” remaining. It was determined that the definition of “usable cutter height” for PDC bits was subject to misinterpretation, given the initial positioning of some PDC cutters “within” the bit blade on some designs. Additional enhancements include addition of a dull characteristic code, “BF”, to distinguish “bond failure” between the cutter and its support backing from “LT”, loss of a cut- ter. In addition, the optional designations “RR” or “NR” were added to allow for indication of whether a bit is “re-runnable” or not. Application of these minor revisions will further “standardize” the meaning of a dull grade. Examples of dull characteristics are shown in Figure BI-40.

Evaluating “cutting structure” Inner/outer rows: spaces 1 and 2

Refer to Figures BI-41 and B-42. Using a linear scale from 0 to 8, as before, a value is given to cutter wear in both the inner and outer rows of cutters. Grading numbers increase with amount of wear, with 0 representing no wear, and 8 meaning no usable cutters left. A grade of 4 indicates 50% wear. For surface-set bits, the scale of cutter wear is determined by comparing the initial cutter height with the amount of usable cutter height remaining.

IADC Drilling Manual

Rather than evaluating “usable cutter height”, PDC cutter wear is now measured across the diamond table, regardless of the cutter shape, size, type or exposure. This eliminates the difficulty in determining the initial cutter height on a bit in which PDC cutters are designed with less-than-full exposure. For both surface-set and PDC bits, the average amount of wear for each area is recorded, with two-thirds of the radius representing the “inner rows” and the remainder representing the “outer rows” (Figure BI-41). Average wear is calculated by simply averaging the individual grades for each cutter in the area.

Dull characteristics: space 3

The most prominent or “primary” physical change from new condition of a cutter is recorded in the third space. “Other” dull characteristics of the bit are noted in the seventh space the difference being that space 3 describes cutter wear, while space 7 may concern other wear characteristics of the bit as a whole. Codes for dull characteristics of both categories are listed in Figure BI-39.

Location: space 4

The fourth space is used to indicate the location of the primary dull characteristic noted in the third space. Locations are designated in the diagrams of Figure BI-53. One or more of these codes may be used to indicate the location of the characteristic(s) noted. They include: C-cone, N-nose (row), T-taper, S-shoulder, G-gauge, A-all areas, M-middle row and H-heel row.

Other evaluation criteria Bearing: space 5

This space is used only for roller cone bits. It will always be marked “X” for fixed-cutter bits.

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Gauge: space 6

The sixth space is used to record the condition of the bit gauge. “I” is used if the bit is still in gauge. Otherwise, the amount the bit is under-gauge is recorded to the nearest 1/16 in.

Other dull characteristics: space 7

In the seventh space, secondary evidence of bit wear is noted. Such evidence may relate specifically to cut- ting structure wear, as recorded in the third space, or may note identifiable wear of the bit as a whole, such as “erosion”. Many times, this “secondary” dull grade identifies the cause of the dull characteristic noted in the third space. Codes for grading both “primary” and “secondary” dull characteristics are listed in the table shown in Figure BI-50. The designations “RR” and “NR” have been included as options for noting whether the bit is re- runnable or not.

Reason pulled: space 8

The eighth space is used to record the reason the bit was pulled. A list of codes is shown in Figure BI-50.

Impact on other stages of drilling, completion and production The drilling process itself always starts with a careful design and engineering analysis, where the objectives for this specific and unique drilling case must be approached, considering the overall situation, even under well-known offset conditions and mature drilling developments, or with risky wildcats. Factors to be taken into account might be driven by some questions. Equipment could be affected by the following: • Risk analysis: How fast in terms of drilling time and directional work one desires to work. The analysis should include critical factors such as drillability, steerability and available technologies for operations with remote or difficult logistics. Considering items such as pore pressure and kicks probability, equivalent circulating density (ECD) will help drill under controlled, near-balance environment; • Drilling mud: Borehole interaction in terms of reactiveness and well aging; • Geological objectives: The target’s trail when we found more than one , scale, and the necessary type of well to reach the target; • Well profile and trajectory: The selected path to be followed to hit the targets impacts the necessary bit selection, cutting structure, stability and aggressiveness in terms of the formations to be

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drilled. The path might include geological obstacles, high dip, salt dome, igneous rocks, unconsolidated formations, non-desired high-pressure zones; • Marketing plan: This factor is more related to economic and strategic models, and is the proper time to show drilling capacity and time reduction. Sometimes large drilling projects depend on the result of the small ones, and bit selection plays a key role on the marketing plans for drilling; • Equipment availability: What types of drilling systems are used or planned to be used under the umbrella of the project feasibility, and what technology is available? Some of the equipment indirectly affected by the bit selection can be directly affected by vibrations, like drilling line (hesitation and pendular vibration), conventional rigs, hydraulic pistons at the super singles, or rack-and-pinion rigs, and of course all of the downhole tools, like mud motors, RSS systems, etc; • Other effects: Drilling an oversized hole results in increased cost in the completions and cementing operations. A tortuous hole or one with ledges might result in difficulty with getting casing to bottom, further increasing time and cost to the complete the well. These effects can be minimized or are generally preventable with good drilling practices.

Proper storage considerations

The storage procedures differ depending on the bit type to be stored. Not all bits are manufactured or maintained the same. Below are general recommendations, but always consult the appropriate drill bit representative and documentation for best practices.

Tricone bit storage

Tricone bits have bearings that are either sealed or nonsealed. The sealed bits must have component parts (like elastomers) protected from the environment. Extreme temperatures also degrade the elastomeric properties, which could diminish the performance of the bit.

Sealed tricone bits

• Sealed bearing rolling cone drill bits must be stored properly to protect them from damaging environmental conditions. Store sealed bearing rock bits in a bit box; • When stored properly, sealed bearing drill bits should retain their full performance potential for a period of five years from the date of manufacture. Bits over five years old might experience a slow degradation in performance, due to the elastomer (rubber) components in the bit; • Elastomer components, such as bearing seals and pressure compensator parts, continue to age with time. Aging causes the parts to harden and become less

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BITS ed until grease appears at the outer edge of the cones between the cone backface and the leg. The rock bit can now be stored safely.

Storage method 2: submersed in oil

Another acceptable practice is to store an unsealed bit in a drum of oil. The oil should completely cover the cones. After sitting in oil for two or three days, the cones should be turned and the bit returned to the oil bath until needed.

Prior to use

Prior to use, clean and install new nozzle o-rings and nozzles. Re-grease each cone bearing through the weep hole; try to fill the entire bearing cavity by rotating the cones several times until plenty of grease comes out the backface. Clean the shank and shoulder area as well and apply pipe grease (dope) to these areas. Figure BI-43: Location of grease holes in non-sealed bits.

resilient. The deterioration of elastomer components can be aggravated or accelerated by improper storage conditions, which result in decreased seal life in demanding drilling applications; • Do not store bits in a place where they could be exposed to dampness, harmful vapors, radiation or temperatures in excess of 120°F (49°C) or lower than 30°F (-1°C). Do not place close to a heater, because the elastomer components will be damaged; NOTE: Do not rotate the cones on a bit that is cold (below 30°F or -1°C) to avoid damaging the bearing seals; warm the bit up before rotating the cones. • Sealed bearing rock bits must be stored at least six ft away from ozone-producing equipment, such as electric motors.

Non-sealed tricone bits

There are two methods to servicing and storing non-sealed rock bits between runs. Prior to storage, the non-sealed rock bit must be cleaned thoroughly by washing with a high-pressure hose. Wash down the bit, and rotate the cones to flush out cuttings through the weep holes. Make sure all the cones can be rotated freely.

Storage method 1: greasing the cones

The first method is to grease each cone individually with a grease gun. Cones can be greased through the pre-cast holes, as shown in Figure BI-43. Several pumps of grease should be forced into the grease holes. During this process, the cone should be rotated fully in order to spread the grease inside the roller bearing. This procedure should be repeat-

IADC Drilling Manual

Locked cone

If an unsealed bit has a locked cone, submerge it in a diesel tank for a day, then try again to rotate the cone. If the bit was submerged for a couple of days or more and the cone still does not break free, then consider scrapping the bit.

Fixed cutters bit storage

• Fixed cutter bits (PDC, casing and impregs) need to be stored in the bit box they arrived at the wellsite in; • The PDC cutters on the bit need to be protected from sustaining damage in any manner; • Steel bits should be placed in an environment where there is minimal chance of corrosion on the bit body, i.e., away from wet/damp/humid conditions.

Drill bit repairs PDC

In the current market and under current operating parameters and limits of the BHA and drillstring components, PDC drill bits typically can be run multiple times after minimal repairs. Repairing PDC drill bits is a common practice amongst the larger drill bit manufacturers, and each manufacturer has a specific set of acceptance criteria or standards for a repairable bit. The drill bits are repaired to specific manufacturing tolerances, and non-destructive examinations (NDE) are performed to satisfy manufacturer quality management procedures. These standards provide product reliability in line with customer expectations and standard operating parameters and are requirements per ISO 9001 standards.

Post-run evaluation

After a drill bit is run, the dull bit is cleaned and evaluated for reparability. The procedure for reparability inspection involves a visual inspection that classifies drill bits with ob-

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BITS vious non-repairable damage as damaged beyond repair (DBR), and the bit is subsequently scrapped. PDC cutting elements and components are visually inspected for wear and damage. Dye penetration inspection is used to further evaluate the dull drill bit to determine reparability at the repair or manufacturing facility. The dye penetration can be used to indicate the need for replacing secondary components on the drill bits that have passed visual inspection, e.g., TCI or posts. The pin connection might be magnetic-particle tested based on manufacturing standards. Drill bits designated for offshore use might be required by the customer to be DS-1 Category 5 tested before and after repairs.

PDC cutting elements and secondary components replacement and reclaim

PDC cutting elements are brazed in during the original manufacturing process and can be replaced after running. Each PDC cutting element is inspected for wear or damage and classified for scrap or reuse. The wear to the diamond table and the tungsten carbide substrate is evaluated. If acceptable for reuse, the cutting element is reclaimed and in future use be rotated to use an edge that has not engaged formation. In some areas there is no reclaim process, and all cutting elements are replaced. The PDC cutting element replacement and reclaim process involves complete removal of the cutting elements, braze material and corrosion/oxidation products through a heating cycle and blasting/grinding. The bit is allowed to cool, and the cutting element pockets are then shot blast, chemically cleaned and preheated for re-braze. The reclaimed cutting elements are also cleaned for re-braze. Whenever heat is being used, thermocouples are required to monitor heat magnitude and cycles. Caution is taken during repairs due to the inherent risks associated with heat cycles. Detailed procedures are specified for drill bit repairs outlining preheat, heating and brazing temperatures and various other critical steps in the repair process. For welding and brazing, specific settings are outlined, and thermocouples are used to monitor temperatures. Upreaming PDC cutting elements and secondary components are replaced in the same manner as the primary cutting structure PDC cutting elements. Various other types of tools, such as reamers, variable-gauge stabilizers and bi-center bits that use PDC cutting elements are repaired using similar procedures.

Drill bit body and gauge

Wear to the drill bit body and gauge can be either cosmetic or functional, each requiring a specific procedure for repair. Cosmetic body and gauge repairs are typically performed immediately after cutter replacement brazing to prevent unnecessary heat cycles. The body is prepared by shot blast and cleaned of all foreign material. Graphite plugs are used to protect cutting element pockets. Using approved mate-

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rials and an oxy-acetylene torch, worn areas of crown and all the joints between cutters and pockets are covered and repaired. For functional wear repairs, drill bits are repaired using a flame spray method. The difference between cosmetic and functional might differ between drill bit manufacturers. The functional gauge wear has limitations, and bits that exceed the functional repair limits are classified as scrap. After hardfacing is applied, the bit is visually inspected, and wheel brushing or grinding is used to clean-up or remove any overspray or cosmetic imperfections. The gauge is ground radially to nominal specified diameter. Other components that might be affected by the temperatures involved in these repairs should be replaced.

Pin connections and upper sections (matrix bits)

Pin connections and certain upper sections can be removed and replaced. The drill bit is cleaned by pressure washing and shot blast. The pin or upper section is removed by machining the weld groove or the entire pin connection down to the original blank make-up threads. Care must be taken to leave the original blank make-up threads intact to enable the threading make-up of the replacement pin connection. Threads shall be properly de-burred. The weld groove shall also be cleaned out as necessary by machining to provide for a suitable weld groove for the replacement upper section. The replacement pin connection shall be made up, welded, inspected and completed in accordance with appropriate requirements.

Miscellaneous modifications

Drill bit gauge modifications can be made by grinding both in diameter and length. These modifications have limitations and are outlined by manufacturing and engineering policies. Ports can also be closed using welding methods.

Roller cone Re-tipping

Re-tipping of the teeth of steel-tooth roller cones is not a common practice for standard drilling environments. However, numerous third-party re-tippers will provide this service for non-challenging or special applications. Re-tippers have developed a procedure for cosmetic repair of tooth gauge, face, flank and crest. The procedure involves the building-up the teeth of the drill bit by welding steel and hard metal to the surface of the teeth. Smaller cosmetic discrepancies are repaired using “liquid steel” or equivalent product to the voids. These repaired areas are filled slightly above flush with the base material and sanded to create a blended, uninterrupted surface.

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Table BI-3: Approximate weight of roller-cone bits (boxed).

Post-repair documentation and inspections

Drill bit manufacturers are required keep detailed records regarding serialized components. These records detail postrun inspections, repair comments, temperature logs, NDE results and tolerances compliance. Various stages in the repair process require meticulous inspection and quality assurance checks: • ASME SEC V: Non-Destructive Examination; • ASTM E709: Standard Practice for Magnetic Particle Examination; • ASTME 1316: Standard Terminology for Non-Destructive Examinations; • Standard DS-1: Drillstring manufacture, design, inspection and specialty tools.

Important calculations Drilling hydraulics

Good hydraulics is essential in ensuring the economic success of a drill bit. The drilling fluid must at the same time clean the cutting elements, avoid clogging (balling up), cool and lubricate the cutters. To ensure and fulfill these objectives is therefore mandatory to design the hydraulic power to meet the bit performance target. For a given flow rate, the choice of a greater TFA reduces the fluid velocity at the exit of the nozzles. The jet impact is the force with which the fluid leaving the nozzles hits the hole bottom. This impact force, mainly a function of the fluid speed and mudweight, is at its maximum when the pressure drop at the bit is 49% of the pump pressure.

Pressure drop

The pressure drop across a bit is defined as the difference between the pressure of the mud exiting the nozzles and the pressure of the mud within the drillstring immediately prior to entering the bit.

and mudweight, the fluid exiting the nozzles has a correspondingly high velocity. A lower-pressure drop, on the other hand, under the same conditions of flow and mudweight, results in fluid exiting the nozzles with lower velocity. Pressure drop is dependent on flow rate, mudweight and the bit TFA.

Units system: • • • • •

Pressure drop (psi); Flow rate (gal/min); Mud weight (lb/gal) TFA (sq in.); 10,856 is a unit conversion factor.

Hydraulic horsepower

The total hydraulic hp developed at the bit (HHP) is a function of flow rate (gal/min) and pressure drop (PD) according to the formula in U.S. units:

Hydraulic horsepower/square inch

Hydraulic HSI provides a measure of the hydraulic power consumed at the bit per hole section and is a function of flow rate and bit pressure drop, as well as hole diameter, and therefore increases as the flow rate is increased. However, as flow rate becomes higher, the TFA eventually needs to be increased to maintain a suitable pressure drop, in which case the HSI once again falls.

If the bit pressure drop is extremely high for a given flow rate

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BITS HSI is at maximum when the pressure drop across the bit is 65 % of the standpipe pressure, which registers the pressure of the mud entering the top of the drillstring.

Units system: • • • •

Flow rate (gal/min); Bit pressure drop (psi); Hole area (sq in.) = π/4 * (hole diameter)2; 1,714 is a unit conversion factor.

Jet velocity

Jet velocity The jet velocity is defined as the average speed of mud exiting the nozzles. It is a function of flow rate and TFA. If the flow rate is extremely high, for a given mudweight, the fluid exiting the nozzles has a correspondingly high velocity. A lower flow rate, on the other hand, under the same conditions of mudweight, results in fluid exiting the nozzles with lower velocity. If the TFA is high, for a given flow rate and mudweight, the fluid exiting the nozzles has low velocity. The converse is also true.

bit diameter, a proportional relationship is used to define the necessary energy: the power per wellbore area. The hydraulic power at the bit is at its maximum when the pressure drop at the bit is 64% of the pump pressure. The hydraulic power requirements vary with local practices. In soft formation, it is preferable to increase mud flow rather than pressure drop; two to three HSI is common. With oil-based mud or when drilling in some shales, the level is generally lower. For surface set bits, the level is between one and three HSI. In harder rocks and with water-based mud and when a high jet effect is wanted, a level from three to five HSI is usually applied.

Drilling economics

Drill bit selection is key in the achievement of decent drilling performance and the reduction of overall drilling costs. Values of optimization might include various benefits such as reduced number of trips, lower rig mobilization and better safe operating conditions, which result in a great economic benefit. To help drilling engineers in this task, there are some basic cost calculations to perform. The most used formula is the cost/ft that measures the overall operating cost to drill one foot of well with a given drill bit.

Cost per foot

The cost/ft is the bit performance measurement used to evaluate the choice. When a downhole motor (measurement while drilling [MWD], motor or rotary steerable system) is used, its rental cost must be added to the hourly cost of the rig and the fixed cost of the bit. However, the economics of a bit only depends on its penetration rate and its life expectancy in terms of time and/or m drilled. One must endeavor to optimize these two elements. One can use the following formula to calculate the cost/ft drilled:

Units system:

• Flow rate (gal/min); • TFA (sq in.); • 0.32086 is unit conversion factor.

Jet impact force

The jet impact force (JIF) is the force that is exerted on the bottom of the hole by the fluid exiting the nozzles when the bit is on bottom. It is a function of jet velocity, mudweight and flow rate. JIF is maximized when the pressure drop across the bit is 49% of the standpipe pressure.

Where CPT

= Cost/m drilled ($/m or $/ft)



CRig

= Cost/hr for the rig ($/hr)



CBit

= Bit cost ($)

CMotor = Motor cost

Units system: • • • •

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Flow rate (gal/min); Mud weight (lb/gal); TFA (sq in.); 1,932 is unit conversion factor.

t

= Drilling time (hour)

T

= Trip time (hour)

M

= footage drilled (m or ft)

Given the fact that the required hydraulic hp varies with the

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BITS the best bit selection for the planned profile, BHA, formations and operating conditions.

Break-even line

Bit life and ROP are the best criteria used to define the impact of the drill bit on the overall drilling cost. Bit life is measured as the footage drilled per bit, whereas the ROP is ft drilled per rotating hour. Bit life affects the number of trips that is required to change the bit, while ROP influences the number of drilling hours needed to complete a given hole section. Proper planning for the well prognosis and working with your operator and bit specialist will you help to choose

IADC Drilling Manual

Proper handling

Always refer to the original equipment manufacturer (OEM) manualas applicable, before undertaking procedures at the current work site.

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SAFETY AND HANDLING General handling hazards

• Ensure all lifting straps are correctly rated for the load and are secured when moving drill bits; • Use proper lifting practices when handling drill bits; • Be aware of other material movements being undertaken when working on the drill floor; • Any general wellsite bit handling hazards should be covered and discussed with the relevant third-party personnel in the general safety meeting or pre-run/ pre-tour Toolbox talk; • Use correct PPE when handling drill bits (gloves) and/or drill bit accessories; • Make crew aware of any potential hand safety issues (e.g., pinch points) when handling, moving and lifting bits at the wellsite; • Placement of the bit box and make-up equipment should not constitute an obstruction or trip hazard on the drill floor.

IADC Drilling Manual

Operation-specific hazards

• Ensure correct tools are being used for any nozzle replacement procedures; • Do not place fingers below the bit cutting face when the bit is being manually handled, especially when it is being placed upon a flat surface; • Do not manipulate a heavy bit at height if it is not adequately supported or if there is any possibility of it falling; • Ensure the base of the bit box is supported if a bit is lifted within its packaging, if there is any possibility the bit could fall through the base of the box; • Never place fingers on a drill bit that has packed debris on its body until it is cleaned off, especially if casing has been drilled, as sharp edges might be packed in the material.

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GOVERNING STANDARDS & GUIDELINES / REFERENCES Governing standards & guidelines

• ANSI/API Specification 7-1 Specification for Rotary Drill Stem Elements; • API Recommended Practice 7G Recommended Practice for Drill Stem Design and Operating Limits; • ISO 9001 Quality Management Systems - Requirements - Fourth Edition; • IADC/SPE 23937 The IADC Roller-cone bit Classification System; • SPE/IADC 16145 Application of the New IADC Dull Grading System for Fixed Cutter Bits; • SPE/IADC 16142 The 1987 IADC Fixed Cutter Bit Classification System; • SPE/IADC 23939, First Revision to the IADC Fixedcutter Dull Grading System;

References

1. Hughes, H.: “A Modern Rotary Drill” Transactions of the American Institute of Mining Engineers, Volume LI., February 1915. 2. Murray, A.S., Cunningham, R.D.: “Effect of Mud Column Pressure on Drilling Rates” paper TP4166 presented at the Petroleum Branch Fall Meeting, New Orleans, Louisiana 2-5 October 1955. 3. Cook, J., McElya, F.: “Development and Application of Journal Bearing Bits” paper presented at the Rotary Drilling Conference, March 2, 1973. 4. Newman, E.F.: “Design and Application of Softer Formation Tungsten Carbide Rock Bits” paper IADC/SPE 11386 presented at the IADC/SPE Drilling Conference, New Orleans, Louisiana, 20-23 February 1983. 5. Byrd, C, Scott, D.E., Kirkland, R.: “New Rolling Cutter Bit Design Reduced Gage Wear in Geothermal Applications,” 1991, Trans., Geothermal Resources Council, pp. 365-69. 6. Scott, D.E., Zahradnik, A.F, Schmidt, S.R.: “Enhanced Gauge Improves Rolling Cutter Bit Performance in Abrasive North Sea Sands,” 1991, OTC 6738, presented at the 1991 Offshore Technology Conference, Houston, Texas, May 6-9, 1991. 7. Grimes, R.E., Felderhoff, F.C., Brown, L.A.: “New Cutting Structure Designs Extend Rock Bit Life in Hard Permian Basin Formations,” 1992, PED-Vol. 40, Drilling Technology, ASME, pp. 43-50. 8. Watson, P.A., Welch, R.M., Scott, D.E.: “New Hard Formation Roller-cone bit Technology Improves Economics of Abrasive Travis Peak, Cotton Valley Wells,” 1996, IADC/SPE 35114, presented at the 1996 IADC/SPE Drilling Conference, New Orleans, Louisiana, March 12-15.

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9. Meiners, M.J., Jacobsen, J., Kunning, J.: “Understanding Downhole Dynamics While Reaming Enhances Gauge Protection,” presented at the ASME Energy Sources Technology Conference and Exhibition, Houston, Texas Feb 1999. 10. Feenstra, R., Juergens, R., Walker, B.H.: “New Generation of Oilfield Bits - Laboratory and Field Results” paper SPE 6712 presented at the Annual Fall Technical Conference and Exhibition SPE/AIME, Denver, Colorado, 9-12 October 1977. 11. Zijsling, D.H.: “Single Cutter Testing - A Key for PDC Bit Development” paper SPE 16529 presented at Offshore Europe, Aberdeen, Scotland UK, 8-11 September 1987. 12. Zijsling, D.H., Illerhaus, R.: “Eggbeater PDC Drillbit Design Eliminates Balling in Water-Based Drilling Fluids” paper SPE 21933 presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, March 11-14 1991. 13. Shepherd, W.L., Klingensmith, D.L.: “Improvements in Rock Bit Performance presented at the ASME Energy Resources Technology Conference, New Orleans, Louisiana, February 1990. 14. Turner, E.C.: “Field Specific Analysis Reinforces Role of Bit Technology in Improving Overall Drilling Economics” paper SPE/IADC 37642 presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 4-6 March 1997. 15. Salesky, W.J., Payne, B.R.: “Preliminary Field Test Results of Diamond-Enhanced Inserts for Three-Cone Rock Bits” paper SPE/IADC 16115 presented at the SPE/ IADC Drilling Conference, New Orleans, Louisiana, 15-18 March 1987. 16. Salesky, W.J., Swinson, J.R., Watson, A.O.: “Offshore Tests of Diamond-Enhanced Rock Bits” paper SPE 18039 presented at the 63rd Annual Technical Conference and Exhibition, Houston, Texas, 2-5 October, 1988. 17. Eckstrom, D.: “Bits with Diamond Inserts Reduce Gauge Problems,” 1991, Oil & Gas Journal, June 17, pg. 41. 18. Scott, D.E.: “Development of Roller-cone bits with Active PDC Shear Cutting Elements Improves GaugeHolding Ability,” 1993, IADC/SPE 25736, presented at the IADC/SPE Drilling Conference, Amsterdam, The Netherlands, February 23-25 1993. 19. Keshavan, M.K., Siracki, M.A., Russell, M.E.: “ Diamond-Enhanced Insert: New Compositions and Shapes for Drilling Soft-to-Hard Formations” paper SPE/ IADC 25737 presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 23-25 February 1993. 20. Pessier, R., Grimes, R., Isbell, M., Scott, D.: “Rolling Cone Bits with Novel Gauge Cutting Structure Drill Faster, More Efficiently” paper SPE 30473 presented at

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BITS the SPE Annual Technical Conference and Exhibition, Dallas, Texas 22-25 October 1995. 21. Salleh, S., Eckstrom, D.: “Reducing Well Costs by Optimizing Drilling Including Hard/Abrasive Igneous Rock Section Offshore Vietnam, paper IADC/SPE 62777 presented at the IADC/SPE Asia Pacific Drilling Technology, Kuala Lumpur, Malaysia 11-13 September 2000. 22. Martin, D., Jacobsen, J.: “New Hard Rock Roller-cone bit Technology /Operational Excellence Improves Economics in Mature East Texas Gas Fields” paper IADC/SPE 74527 presented at the IADC/SPE Drilling Conference, Dallas, Texas, 26-28 February 2002. 23. Glowka, D.A.: “Use of Single-Cutter Data in the Analysis of PDC Bit Designs: Development of a PDC Cutting Force Model” paper SPE 15619 presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 5-8 October 1986. 24. Warren, T.M., Sinor, L.A.: “Drag-Bit Performance Modeling” SPE paper 15618 presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 5-8 October 1986. 25. Behr, S.M., Warren, T.M., Sinor, L.A. Brett, J.F.: “3D PDC Bit Model Predicts Higher Cutter Loads” paper SPE 21928 presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 11-14 March 1991. 26. Brett, J.F., Warren, T.M., Behr, S.M.: “Bit Whirl - A New Theory of PDC Bit Failure” paper SPE 19571 presented at the SPE 64th Annual Technical Conference and Exhibition, San Antonio, Texas, 8-11 October 1989. 27. Warren, T.M., Brett, J.F., Sinor, L.A.: “Development of a Whirl-Resistant Bit” paper SPE 19572 presented at the SPE 64th Annual Technical Conference and Exhibition, San Antonio, Texas, 8-11 October 1989. 28. Sinor, L.A. Brett, J.F., Warren, T.M., Behr, S.M.: “Field Testing of Low-Friction-Gauge PDC Bits” paper SPE 20416 presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 23-26 September 1990. 29. Pastusek, P.E., Cooley, C.H., Sinor, L.A., Anderson, M.: “Directional and Stability Characteristics of Anti-Whirl Bits With Non-Axisymmetric Loading” paper SPE 24614 presented at the SPE 67th Annual Technical Conference, Washington DC, 4-7 October, 1992. 30. Warren, T.M., Sinor, L.A.: “PDC Bits: What’s Needed To Meet Tomorrow’s Challenge” paper SPE 27978 presented at the University of Tulsa Centennial Petroleum Engineering Symposium, Tulsa, Oklahoma, 29-31 August 1994. 31. Ortega, A., Glowka, D.A.: “Frictional Heating and Convective Cooling of Polycrystalline Diamond Drag Tools During Rock Cutting,” paper SPE 11061presented at the SPE Annual Technical Conference and Exhibition held in New Orleans September, 26-29 1982.

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32. Tomlinson, P. N., Pipkin, N. J., Lammer, A., Burnand, R. P., 1985, “High Performance Drilling-Syndax3 Shows Versatility,” Industrial Diamond Review, Vol. 6 pp. 299-305. 33. Eko, A., Ohashi, T., Tajima, I.: “Precision Machining with Fine-Grained Carbonate Binder PCD” Diamond Tooling Journal, February 2010, pp. 48-51. 34. Radtke, R.P.: “New High Strength and Faster Drilling Thermally Stable Polycrystalline Diamond Cutters for Drill Bit” paper SPE 74515 presented at the IADC/SPE Drilling Conference, Dallas, Texas, 26-28 February 2002. 35. Wood, J. 1984, “Thermally Stable Cutters Extend Application of Synthetic diamond Bits to Hard Formations” Oil and Gas Journal, pp. 133-138. 36. Schell, E.J., Phillippi, D., Fabian, R.T., “New Stable PDC Technology Significantly Reduces Hard Rock Cost per Foot” paper SPE/IADC 79797 presented at the SPE/ IADC Drilling Conference, Amsterdam, Netherlands, February 19-21 2003. 37. Baker, R., Shen, Y., Zhang, J., Robertson, S.: “New Cutter Technology Redefining PDC Durability Standards for Directional Control: North Texas/Barnett Shale” paper IADC/SPE 128486 presented at the IADC/SPE Drilling Conference and Exhibition, New Orleans, Louisiana, 2-4 February 2010. 38. Plemons, B., Douglas, C., Shen, Y., Zhan, G., Zhang, Y.: “New Cutter Technology for Faster Drilling in Hard/ Abrasive Formations” paper SPE 132143 presented at the CPS/SPE International Oil and Gas Conference and Exhibition in China, Beijing, China, 8-10 June 2010. 39. Zhang, Y., Baker, R., Burhan, Y., Shi, J., Chen, C., Tammineni, S., Durairajan, B., Self, J., Segal, S.: “Innovative Rolling PDC Cutter Increases Drilling Efficiency Improving Bit Performance in Challenging Applications” paper SPE/IADC 163536 presented at the SPE/IADC Drilling Conference and Exhibition, Amsterdam, The Netherlands, 5-7 March 2013. 40. Zhang, Y., Burhan, Y., Chen C., Tammineni, S., Durairajan, B., Mathanagopalan, S., Ford, R.: “Fully Rotating PDC Cutter Gaining Momentum: Conquering Frictional Heat in Hard/Abrasive Formations Improves Drilling Efficiency” paper SPE 166465 presented at the SPE Annual Technical Conference and Exhibition New Orleans, Louisiana, USA, 30 September–2 October 2013. 41. DiGiovanni, Anthony. Stockey, David. Fuselier, Danielle. Gavia, David. Zolnowsky, Matt. Phillips, Russell. Ridgeway, Derek. “Innovative non-planer Face PDC Cutters Demonstrate 21% Drilling Efficiency Improvement in Interbeded Shale and Sand” Paper 168000 presented at the SPE Annual Technical Conference and Exhibition New Orleans, Louisiana, USA, 30 September–2 October 2013. 42. Cariveau, P., Slaughter, R.H., Didericksen, R., Cawthorne, C.E., Portwood, G.R.: “Sealed Bearing Drill Bit with Dual-Seal Configuration” United States Patent

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6,033,117, March 7, 2000. 43. Al-Farei, I.,A., Al-Sukaiti, A.H., Al-Lawati, A., Portwood, G., Krishnamurthy, R., Gatell J.: “Two Years of Progress: Field Driven Rollercone Design Iterations Cut Conglomerate Formation Drilling Costs by 40% in Oman” paper SPE/IADC 147958 presented at the SPE/ IADC Middle East Drilling Technology Conference and Exhibition Muscat, Oman, 24–26 October 2011. 44. Schmidt S. R., Wittry A. E., Burr B. H., Kelly J. L.: “Metal-Bearing Seal Technology Improves Drilling Efficiency of Rolling Cutter Bits in High-RPM North Sea Applications”: SPE paper 21934 presented at the SPE/ IADC Drilling Conference, Amsterdam, March 11-14, 1991 45. McLeod, S.A., O’Grady, T.T., Sullivan, E.C., Mason, J.S., Lin, C.: “Application of Metal-Bearing Seal Roller-Cone Bit Reduces Rig Time/Drilling Costs in Green Canyon, Deep Water Gulf of Mexico” paper IADC/SPE 59109 presented at the IADC/SPE Drilling Conference, New Orleans, Louisiana, 23–25 February 2000. 46. Norris, J.A., Dykstra, M.W., Beuershausen, C.C., Fincher, R.W. and Ohanian, M.P.: “Development and Successful Application of Unique Steerable PDC Bits,” paper IADC/SPE 39308 presented at the IADC/SPE Drilling Conference, Dallas, Texas, 3-6 March 1998. 47. Sinor, L.A., Powers, J.R., Warren, T.M.: “The Effect of PDC Cutter Density, Back Rake, Size, and Speed on Performance” paper SPE 39306 presented at the IADC/ SPE Drilling Conference, Dallas, Texas, 3-6 March 1998. 48. Mensa-Wilmot, G., Krepp, T. and Stephen, I.: “Dual Torque Concept Enhances PDC Bit Efficiency in Directional and Horizontal Drilling Programs,” paper SPE/IADC 52879 presented at the SPE/IADC Drilling Conference, Amsterdam, Netherlands, 9-11 March 1999. 49. Sinor, L.A., Hansen, W.R., Dykstra, M.W., Cooley, C.H., Tibbits, G.A.: “Drill Bits with Controlled Cutter Loading and Depth of Cut,” US Patent 6,298,930, October 9, 2001. 50. Dykstra, M.W., Heuser, W., Doster, M.L., Zaleski, T.E., Oldham, J.T., Watts, T.D., Ruff, D.E., Walzel, R.B., Beuershausen, C.C.: “Drill bits with reduced exposure of cutters,” US Patent 6,460,631, October 8, 2002. 51. Al-Suwaidi, A.S., Soliman, A.A., Klink, Z., Isbell, M., Dykstra, M., Jones, C.: “New PDC Design Process Solves Challenging Directional Application in Abu Dhabi Onshore Fields paper SPE/IADC 79796 presented at the SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 19-21 February 2003. 52. Pessier, Rudolf. Damschen, Michael. “Hybrid Bits Offer Distinct Advantages in Selected Roller-Cone and PDC-Bit Applications” SPE 128741, 2010. 53. Dolezal, Tisha, Felderhoff, Floyd Carl, Holliday, Alan D., Baker Hughes Inc. Bruton, Greg A., Chesapeake Operating Inc.: “Expansion of Field Testing and Application of New Hybrid Drill Bit”, SPE 146737, 2011. 54. Bradford, John F., Ferrari, Louis Anthony, Rickabaugh, IADC Drilling Manual

Caleb, Rothe, Mitchell A., Tipton, Brent Jackson, Chesapeake Energy: “Hybrid Drill Bit Combining Fixed-Cutter And Roller-Cone Elements Improves Drilling Performance In Marcellus Shale Surface Interval”, SPE 154831, 2012. 55. Di Pasquale, M., Calvaresi, E., Baker Hughes, Pecantet, S., NV Turske Perenco, “ A Breakthrough Performance for an Inland Application with a Hybrid Bit Technology”, SPE 163436. 2012. 56. Thomson, Ian James, Radford, Steven Ralph, Powers, Jim R., Shale, Leslie T., Jenkins, Mark, Baker Hughes Inc. “A Systematic Approach to a Better Understanding of the Concentric Hole-Opening Process Utilizing Drilling Mechanics and Drilling Dynamics Measurements Recorded Above and Below the Reamer”, SPE 112647, 2008. 57. Meyer-Heye, Bernhard, Technische Universitat Braunschweig, Reckmann, Hanno, Baker Hughes Inc. Ostermeyer, Georg-Peter, Technische Universitat Braunschweig, “ Weight Distribution in Reaming While Drilling BHAs” SPE 127094 SPE Conference Paper , 2010. 58. Ubaru, Charles C., Thomson, Ian James, Radford, Steven Ralph, Baker Hughes Drilling and Under-Reaming in the GOM” “Deepwater Ultradeep Lower Tertiary: History of a Record Run in the World” SPE 145259 SPE Conference Paper, 2011. 59. Pragt, Jos, Herberg, Wolfgang, Meister, Matthias, Clemmensen, Carl Christian, BAKER HUGHES Inteq GmbH, Grindhaug, Gaute, Hanken, Knut Johan, Statoil ASA Oil “Reaming on Demand - Selective Activation of an Integrated Under Reamer at the Grane Field in the North Sea”.146501-MS SPE Conference Paper – 2012. 60. Ulvedal, Lydia, Statoil, Enterline, James Dean, Hughes Christensen, Scott, Dan Eugene, Shale, Les, Radford, Steven Ralph, Baker Hughes Inc. Clinkscales, Douglas Jay, Hughes Christensen, Croxton, Mike, Hughes Christensen. “ Operator’s Recommendation for a Uniform Dull Grading System for Fixed Cutter Hole Enlargement Tools”, SPE139870-SPE ATCE, Amsterdam, - 2011. 61. Pessier, R.C., Hughes Tool Co., Fear, M.J., BP Exploration, “Quantifying Common Drilling Problems With Mechanical Specific Energy and a Bit-Specific Coefficient of Sliding Friction”, SPE 24584 SPE Conference, Dallas TX – 1992 62. Pessier, Rudolf Carl, Hughes Christens, Wallace, Stephen Nicholas, Baker Hughes Oasis, Oueslati, Hatem, Baker Hughes, “Drilling Performance is a Function of Power at the Bit and Drilling Efficiency”, SPE 151389-MS SPE Conference San Diego, CA – 2012. 63. Clark, D. A., et al, Application of the New IADC Dull Grading System for Fixed Cutter Bits, paper SPE/IADC 16145, presented at the 1987 SPE/IADC Drilling Conference, New Orleans, La., March 15-18, 1987. 64. Brandon, B.D., et al, First Revision to the IADC Fixed Cutter Dull Grading System, SPE/IADC 23939, 1992.

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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.

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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 and REVIEWERS Dan Postler, Sierra Hamilton Dusty Sonnier, McCoy Global Inc. Fred Dupriest, Texas A&M University Stewart Barker, Albany Technical Services Alistair Brodie, VAM Oilfield Service Antoine Caillard, Vallourec Dan Dall’Acqua, Volant Products Inc. Malcolm Gray-Stephens, Frank's International W.H. “Buster” Hamley, Weatherford Neil Kimbler, Besco Tubular Bob Moe, Viking Engineering Kevin Robertson, EMAS Energy Services Ltd. Allen Sinnot, Weatherford Matthew Allen, Volant Products Inc.

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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: 978-0-9909049-2-2

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CASING AND TUBING CHAPTER CT

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Contents

CASING AND TUBING

Introduction..................................................................... CT-1 Types of casing and tubing......................................... CT-1 Drive, structural and conductor casing........... CT-1 Surface casing........................................................ CT-1 Intermediate casing.............................................. CT-1 Drilling liners........................................................... CT-2 Production casing and tiebacks......................... CT-2 Tubing....................................................................... CT-2 OCTG materials............................................................. CT-2 Manufacturing methods...................................... CT-2 OCTG labels............................................................CT-4 OCTG specifications.............................................CT-4 Corrosion..........................................................................CT-9 Sour service corrosion (SSC).............................CT-9

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Summary of API casing grades...............................CT-10 OCTG marking..............................................................CT-10 Transportation and handling....................................CT-12 Transport and offloading...................................CT-12 Handling.................................................................CT-12 Tubular storage.............................................................CT-13 Pipe racks���������������������������������������������������������������CT-13 Storage coatings and compounds..................CT-13 Thread protectors................................................CT-13 Running procedure......................................................CT-14 Running tools and equipment..........................CT-15 Pick-up and lay-down tools..............................CT-22 References.....................................................................CT-24

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Introduction

Tubulars are selected for the specific conditions anticipated in a given well. The anticipated production flow rates and economics of the well determine tubing size, which then determines the necessary size of each previous hole and tubular. Once the tubular size and setting depths are determined, the wall thickness and grade of material are then chosen by the well designer to ensure the strength is adequate for the expected loads. Material grade is also selected to ensure it is appropriate for the fluids the tubular will encounter; corrosion resistant alloys (CRA) may be required in some environments such as CO2 or H2S. Finally, tubular connections are selected based on dimensional needs, load capacity, and gas-vs-liquid sealability. This chapter discusses types of casing and tubing; OCTG manufacturing, labeling and specifications; corrosion; API casing grades; transportation and handling; storage; and running procedures.

Pipe types

There are two basic types of pipes used in oil and gas exploration and production and standardized by the American Petroleum Institute (API) and the International Standards Organization (ISO). For in-well services (i.e., below the wellhead oil country tubular goods [OCTG]): • • Casing: API 5CT/ISO 11960 with API 5B/ISO 10422 for threads; • • Tubing: API 5CT/ISO 11960 with API 5B/ISO 10422 for threads. Per API, the specification differences between casing and tubing are: • • Length of the drift mandrel: 6 in. or 12 in. for casing and 42 in. for tubing; • • Joint strength calculation method: Minimum tensile strength for casing, and minimum yield strength for tubing. This chapter specifically covers casing and tubing. For information on drill pipe, heavyweight drill pipe and drill collars, please refer to the separate chapter Drillstring of the IADC Drilling Manual, 12th edition. For additional advice on drillpipe practices, refer to the separate chapter on Drilling Practices.

Types of casing and tubing Drive, structural and conductor casing

The main purpose of this first string of pipe is to protect unconsolidated shallow formations from erosion by drilling fluids. Additional functions of the first casing string include:

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•• Allows for installation of a full mud circulation system, when formations are sufficiently stable; •• Guides the drill string and subsequent casing into the hole; •• Can form a part of the piling system offshore for a wellhead jacket or piled platform. In subsea wells the conductor may form an integral part of the structural support for the wellhead system; •• Provide centralization for the inner casing strings, which limits potential buckling of subsequent casing strings; •• Minimize shallow lost returns; •• Provides a mount in onshore applications for a diverter system that would be used in the event of an unexpected shallow influx. Conductor casings can be driven or jetted to depth or, alternatively, run into a predrilled or jetted hole and cemented.

Surface casing

Surface casing is installed to: •• Prevent poorly consolidated shallow formations from sloughing into the hole; •• Enable full mud circulation; •• Protect fresh water sands from contamination by drilling mud; •• Provide protection against hydrocarbons found at shallow depths; •• Provide initial support for the blowout preventers; •• Provide kick resistance for deeper drilling; •• Support the wellhead system and all subsequent casing strings. The surface casing string is typically cemented to the surface or seabed. it is usually the first casing on which blowout preventers are installed. The amount of protection provided against internal pressure will only be as effective as the formation strength at the casing shoe.

Intermediate casing

Intermediate casing is used to ensure there is adequate blowout protection for deeper drilling and to isolate formations that could cause drilling problems. The first intermediate string is typically the first casing providing full blowout protection. An intermediate casing string is nearly always set in the transition zone associated with the onset of significant overpressures. If the well could encounter severe lost circulation zone(s), intermediate casing would normally be set in a competent formation below the loss zone. Intermediate casing can also be used to case off any known hydrocarbon-bearing intervals as a contingency against the possibility of encountering lost circulation, with attendant well control problems. An intermediate string may also be set simply to reduce the overall cost of drilling and completing the well by isolating intervals that have caused me-

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chanical problems in the past. Intermediate casing may be required to isolate: •• Swelling clays and shale that can result in tight hole and key seats; •• Brittle caving shale or weak zones prone to washout and creation of persistent on bottom fill; •• Salt intervals; •• Chemically active formations that can upset mud chemistry; •• Over-pressured permeable formations; •• Hole sections that are used to deviate the wellbore; •• High permeability sand(s); •• Partly-depleted reservoirs that could cause differential sticking. A good well designer should plan to combine as many of these objectives as possible when selecting a single casing point. A liner may be used instead of a full intermediate casing string and difficult wells may actually contain several intermediate casings and/or liners.

Drilling liners

A drilling liner is essentially a string of intermediate casing that does not extend all the way to surface. It is hung off in or above the previous casing shoe and is usually cemented over its entire length to ensure it seals within the previous casing string. In many subsea well designs, the liner is partially cemented around the shoe, and a liner lap packer is used to seal the liner top. This is necessary when the fracture gradient cannot withstand the equivalent circulating density resulting from the pressure drops associated with cementing the entire liner. Drilling liners may be installed to: •• Increase shoe strength to allow further mud density increases; •• Isolate troublesome zones; •• Satisfy rig tension load limitations; •• Minimize the length of reduced hole diameter to overcome possible adverse effects on drilling hydraulics and the size of drill pipe that can be used; •• Save money compared to running a full string. There are a number of disadvantages to installing liners: •• Difficulty obtaining a quality cement job; •• Risk of liner running equipment being cemented in the hole; •• The liner lap represents a potential source of influx and typically must be isolated by a retrievable bridge plug if it is necessary to remove the blowout preventer stack; •• The lap must be tested with both positive and negative pressure and remedial action taken if it fails to perform.

Production casing and tiebacks

Production casing is the conduit through which the well will

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be completed, produced and controlled throughout its life. On exploration wells, this life may amount to only a very short testing period, but on most development wells it will span many years, during which multiple repairs and recompletions might be performed. Production casing should be designed to retain its integrity throughout its life. In most cases, production casing must provide full pressure redundancy to the tubing, isolate the productive intervals, facilitate proper reservoir maintenance and/or prevent the influx of undesired fluids. The size of the production casing is selected to accommodate the optimum method of completion and production, along with: •• Well flow potential, i.e., tubing size; •• Possibility of a multiple tubing string completion; •• Space required for downhole equipment, such as safety valves, artificial lift equipment, etc.; •• Potential well servicing and recompletion requirements; •• Adequate annular clearances to permit circulation at reasonable rates and pressures. It is also possible that the production casing itself could be used as production tubing to maximize well deliverability (casing flow), to minimize the pressure losses during fracture stimulations, for continuous or batch chemical injection or for lift gas.

Tubing

The pipe centered in the annulus of an oil and/or gas well through which the hydrocarbons flow to the surface from the formation is called tubing. It is important to size tubing properly. If too small, production will be restricted, limiting the profitability of the well. However, tubing that is too large can reduce fluid velocity and allow for build up of produced water that can kill the well. Large tubing will also affect the economics of the project, adding to the cost of the overall well design.

OCTG materials

For OCTG, material “type” describes the composition of the steel used in manufacturing of the pipe, which impacts resistance to various types of corrosion. The type of material for OCTG must be appropriate for the corrosiveness of the operating environment. The six material types for OCTG are shown in Table CT-1.

Manufacturing methods

OCTG pipe is manufactured by either a welded or seamless process. •• Welded tubulars are generally large diameter with relatively thin walls, suitable for structural pipe, conductors, surface casing, and marine risers. Welded

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Table CT-1: The six materials used for OCTG manufacture Material Name

Governing specification

Application

Carbon steels

API 5CT/ ISO 11960

Non-corrosive wells Sour service without CO2

13% Cr Martensitic

API 5CT/ ISO 11960

Sweet corrosion (CO2)

Super 13 Martensitic

API 5CRA/ ISO13680 Group1

Sweet corrosion (CO2) and temperature

22% Cr or 25% duplex or super duplex

API 5CRA/ ISO13680 Group 2

Sour service + CO2

28% Cr Austenitic (Fe base alloys)

API 5CRA/ ISO13680 Group 3

Highly corrosive: Fit for purpose testing

Alloy 825, G3, C276. Nickel base alloys

API 5CRA/ ISO13680 Group 4

Extremely corrosive: Fit-for-purpose testing

pipe is sometimes used for other applications such as intermediate casing, production casing, and tubing, though these applications are less common, especially in the smaller diameters. Welded pipes have generally good dimensional properties and are generally less expensive but have limitations: s s Prohibited for API 5CRA tubulars; s s Not suitable to 13 Cr; s s Not suitable to sour service. Only accepted for L80, forbidden when higher strength properties are required; s s Prohibited for couplings and accessories, per API 5CT; s s Limited wall thickness because of weld limitation in wall. •• Seamless pipe is suitable for all types of material and grades, and is preferred when well conditions are severe. Per API 5CRA, all CRA tubulars are seamless. Because of manufacturing limitations, seamless pipe is generally only available in diameters of 18 in. or less.

Seamless tube manufacturing

There are multiple seamless steel-tube manufacturing processes that originated at the end of the 19th century. These include: •• Continuous mandrel rolling process and push bench process: 21-178 mm (0.8-7.0 in.); s s Continuous mandrel rolling process: 7 to 9 tandem rolling stands continuously mill and elongate the hollow shell of the tube over a floating mandrel bar to produce a final tube. Starting material is generally round rolled billets. First the material is heated, then pierced to produce a hallow shell. At this point the piece is elongated anywhere from 2 to 4 times its initial length. Finally the shell is rolled out in the

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continuous rolling mill to produce a continuous tube; s s Push Bench: First billets are heated to rolling temperature, and then moved through the cylindrical dies of a piercing press, where they become thick-walled pierced billets (a.k.a., "hollow") closed at one end. Later the hollows are stretched using a 3-roll elongator, thereby leveling the wall thickness. Once elongated the hollow is moved to a push bench, where a mandrel is inserted and it passes through a series of rollers. The hollow passes roller to roller, resulting in smaller wall thicknesses. Finally a hot saw removes the closed end from the hollow. •• Multi-stand plug mill (MPM) with controlled floating mandrel and plug mill: 140-406 mm (51/2-16 in.); s s MPMs and Plug Mills: In Plug mills a solid round (billet) is used. It is uniformly heated in the rotary hearth heating furnace and then pierced by a piercer. The pierced billet or hollow shell is roll-reduced in outside diameter and wall thickness. The rolled tube simultaneously burnished inside and outside by a reeling machine. The reeled tube is then sized by a sizing mill to the specified dimensions. From this step the tube goes through a straightener. This process completes the hot working of the tube. The tube (referred to as a mother tube) becomes a finished product after finishing and inspection. •• Cross-roll Piercing and Pilger rolling process: 250-660 mm (10-26.0 in.); s s Cross-roll Piercing and Pilgering Stand: Piercing a solid billet with two or three profiled working rolls rotating in the same direction is the basis of the cross –roll pilgering process. Once it is completed the thick-walled hollow shell is rolled through a pilgering process to produce the finished pipe.

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CASING AND TUBING

CT-4

Table CT-2: Casing and tubing tolerances OD < 4 ½ in.

OD ≥ 4 ½ in.

+/- 0.031 in. +/- 0.79 mm

-0.5% / +1%

The pilgering stand generally has two rolls, with a tapered pass around the circumference. The rolls rotate in the opposite direction from the material.

OCTG Labels

Casing and tubing are generally described with four labels: ••Size; ••Weight; ••Grade; •• End finish and thread. For example, casing bearing the label “9-5/8 47 P-110 BTC” has a 9.625-in. diameter, 47-lb/ft nominal weight, P-110 grade, and Buttress (BTC) threads. Size and weight labels are referred to as the designation in the API specifications. API Spec 5CT/ISO 11960 lists the various size and weight designations and the standardized grade and available end finishes for API casing and tubing, respectively. Knowledge of dimensional characteristics and performance properties of OCTG tubing or casing strings is essential for all who work on oil and gas wells.

OCTG Specifications Outer diameter (OD)

This size designation establishes the outside diameter in inches (in.) or millimeters (mm), as shown in Table CT-2.

Wall Thickness

For a particular size, the weight designation determines the nominal pipe body wall thickness in inches or mm (Table CT-3). Although wall thickness tolerance is normally a nominal value, buyers can request a specific measurement of wall thickness. Tolerances may also be changed by agreement between the purchaser and supplier.

Drift diameter

OCTG users must be assured that the pipe will have sufficient clearance to allow a bottomhole assembly (BHA) or other drilling or completion tool to pass through it. The internal clearance of an OCTG is proven by the ability to pass a mandrel of specified diameter and length through the pipe’s full length. This mandrel is called a drift mandrel. Drift should not be confused with internal diameter (ID), as any given ID is only a nominal value. The size and weight designation determines the drift diameter of the pipe body

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Table CT-3: Wall thickness tolerance* Per API 5CT

Per API 5CRA QT and SA**

Per API 5CRA CH***

Min, %

Min, %

Min, %

-12.5

-12.5

-10

*Max tolerance is driven by actual weight for all ** For quenched and tempered or solution-annealed products *** For cold-hardened products

and through the threaded and coupled (T&C) connections in inches or mm. API defines three types of drift dimensions: standard, alternate, and special. Standard drift dimensions are given in the Tables CT-4 and CT-5.

»» Alternate drift

Alternate drift is used when the standard drift does not meet the user’s operational requirements. API has defined some alternate drift sizes that are outside the standard drift formula, but which can be achieved within normal manufacturing tolerances. For example, 9 5/8-in., 53.5-lb/ft pipe has a standard API drift of 8.379 in., but can be offered with an alternate drift of 8.5 in. Alternate drift must be specified by the user at the time of purchase.

»» Special drift

Special drift is a specific drift diameter agreed between supplier and purchaser. The “special drift” option can have an impact on the OD of the tubular as it is often necessary to shift the OD tolerances above maximum. In this case, the pipe would be considered “oversized”, and no longer compliant with API.

Inside diameter (ID)

The size/weight designation defines the inside diameter of the pipe body in inches (or mm). There are no specified tolerances for the inside diameter of the pipe body; it is governed by the outside diameter and weight tolerances. Extreme line casing and integral joint tubing have special inside diameter drift requirements.

Weight

The size/weight designation determines the mass (i.e., the nominal plain end unit weight) of the pipe body. Although generally expressed in pounds per foot (lb/ft), the nominal weight given by API and manufacturer literature is actually dimensionless and is only a nominal value. The dimensionless weight designation is an adequate approximation of the mass of the pipe in lb/ft (x 1.4895 for kg/m). Actual weight depends on wall thickness tolerances, OD tolerances, and connection weight. When nominal weight is unknown, a tubular can be specified with only the nominal outside diameter and nominal wall thickness.

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CASING AND TUBING Table CT-4: Standard drift dimensions for API 5CT tubulars OD range, in.

Drift Length, in. (mm)

OD ≤ 2 ⅞ Tubing

2 ⅞ < OD ≤ 8 ⅝ 8 ⅝ < OD < 10 ¾ 4 ½ ≤ OD < 9 ⅝

Casing

9 ⅝ ≤ OD ≤ 13 ⅝ OD > 13 ⅜

Table CT-5: Standard drift dimensions for API 5CRA tubulars

Drift Diameter*, in. (mm):

OD range, in.

d-3/32 (2.38) 42 (1,067)

d-⅛ (3.18)

Tubing

d-5/32 (3.97) d-⅛ (d-3.18)

6 (152) 12 (305)

d-5/32 (d-3.97) d-3/16 (d-4.76)

* d = nominal OD - 2x nominal wall thickness

Weight tolerances are: •• Single lengths: +6.5%, -3.5%; •• Carload lots (40,000 lb or 18,140 kg minimum): -1.75%, with no + tolerance.

Grade

For API OCTG, material “grade” is a letter and/or number combination that signifies the composition and mechanical strength of the tubular. The grade of steel sets the mechanical properties and corrosion resistance of the product. Certain grades also carry restrictions on the process of manufacture and heat treatment.

»» Grade naming for API 5CT (non-CRA)

The names of the API 5CT grades are a combination of one prefix letter and one number. Past practice associated the prefix letter with quality, with early letters in the alphabet indicating poorer performance: the closer to “A”, the worse the performance. However, this is no longer true and can be confusing. Currently, the prefix letter has no particular significance with three exceptions, two of which indicate suitability for sour service, while the third indicates ultimate strength difference: •• L and N 80 (L grade suitable for sour service); •• R and T 95 (T grade suitable for sour service); •• J and K 55 (K grade has higher ultimate strength). Grade number corresponds to the specified minimum yield strength (SMYS) of the material in thousands of psi (ksi). For example, material grade C90 has minimum yield strength of 90 ksi (90,000 psi).

»» Grade naming for API 5CRA

The names of the API 5CRA grades are a combination of four numbers separated by dashes. The first 3 numbers represent the material composition in chromium, nickel and molybdenum, while the fourth corresponds to the SMYS of the material in ksi. For example, 27-31-4-110 CRA material contains 27% chromium, 31% nickel, and 4% molybdenum, with a SMYS of 110 ksi.

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CT-5

Casing

OD ≤ 2 7/8 OD > 2 7/8

Drift Length, in. (mm)

4 (1067)

Drift Diameter*, in. (mm): d – 3/32 (d-2.38) d – 1/8 (d – 3.18)

OD ≤ 8 5/8

6 (152)

d – 1/8 (d-3.18)

OD > 8 5/8

12 (305)

d - 5/32 (d – 3.97)

* d = nominal OD - 2x nominal wall thickness

External clearance

The OD of an OCTG tube body is generally NOT the largest diameter of the joint of pipe, because the connections are often larger than the tube body. Users need to know the external clearance between the tubular and the hole or outer tubular in which it is installed. The largest outside diameter measured across the full length of the casing or tubing is the coupling OD for T&C pipes or the OD at the box end level for integral semi-flush connections. API specifications define the coupling OD for API connections. For proprietary connections, the coupling diameter is obtained by machining. The values should be provided by the supplier.

Casing and tubing lengths

The Range length and tolerances are listed in API RP 5CT/ IS011960 and in API RP 5CRA/ISO 13680. Due to the various manufacturing processes used to make pipe, pipe lengths can vary considerably from one mill to another for the same product and within the same product from the same mill. Conversely, pipe lengths can be very consistent. By agreement between purchaser and supplier, special ranges may be defined due to rig constraints, transportation in closed containers, etc. For operational purposes, all tubulars should be individually measured. At the mill and in the pipe yard, the lengths of pipe are measured from the end of the coupling, or box connection, to the end of the pin. For the running (rig or driller's) tally, the lengths of pipe are measured, "less threads" (i.e., from the end of the coupling, or box connection, to the position on the pin that will be flush with the end of the box connection made up fully on the prior run joint).

Casing and tubing strength

Please refer to API 5C3/ISO 10400 for detailed calculations: •• Pipe body yield strength (PBYS) is the maximum tensile load that can be applied to the pipe body without yielding the steel (in the absence of internal and

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CT-6

Table CT-6: API 5CT grades, YS range and tensile strengths Yield Strength ksi Grade

Group 1

Type

Tensile strength

min.

max.

ksi

H40

40

80

60

J55

55

80

75

K55

55

80

95

N80

1

80

110

100

N80

Q

80

110

100

R95

95

110

105

M65

65

85

85

L80

1

80

95

95

L80

9Cr

80

95

95

L80

13Cr

80

95

95

C90

1

90

105

100

T95

1

95

110

105

C110

110

120

115

Group 3

P110

110

140

125

Group 4

Q125

125

150

135

Group 2

1

Table CT- 7: Range length for API RP 5CT tubulars

Casing*

Tubing**

Integral joint tubing

Range 1

Range 2

Range 3

Min

18 ft (4.88 m)

28 ft (7.62 m)

36 ft (10.36 m)

Max

25 ft (7.62 m)

34 ft (10.36 m)

48 ft (14.63 m)

Variation

6 ft (1.83 m))

5 ft (1.52 m)

6 ft (1.83 m))

Min

20 ft (6.10 m)

28 ft (8.53 m)

38 ft (11.58 m)

Max

24 ft (7.31 m)

32 ft (9.75 m)

42 ft (12.80 m)

Variation

2 ft (0.61 m)

2 ft (0.61 m)

2 ft (0.61 m)

Min

20 ft (6.10 m)

28 ft (8.53 m)

38 ft (11.58 m)

Max

26 ft (7.92 m)

34 ft (10.36 m)

45 ft (13.72 m)

Variation

2 ft (0.61 m)

2 ft (0.61 m)

2 ft (0.61 m)

* 95% of the order shall meet the values shown in the table above for casing. The last 5% minimum values may be smaller and variation on lengths may be more scattered (see API 5CT). ** Range 3 Tubing can be increased to 45 ft max by agreement between Purchaser and manufacturer.

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CT-7

Table CT-8: Range length for API 5 CRA Tubulars

Casing or tubing

Range 1

Range 2

Range 3

Min

16 ft (4.88 m)

25 ft (7.62 m)

34 ft (10.36 m)

Max

25 ft (7.62 m)

34 ft (10.36 m)

48 ft (14.63 m)

Variation

5 ft (1.83 m)

5 ft (1.52 m)

5 ft (1.83 m)

Table CT-9: Pup joint length tolerance + / - 3 in. (+ /- 76 mm)

external pressure, bending and torsion). It is defined as the product of the cross-sectional area and the specified minimum yield strength for the particular grade of pipe ; •• Internal yield pressure (often referred to as burst pressure) is the internal pressure that is guaranteed before risk of pipe yielding; Per API 5C3, it is based on specified minimum yield strength for the particular grade of pipe, outside diameter, and minimum wall thickness; •• External pressure resistance is often referred to as collapse pressure. Collapse is an unstable failure mode leading to a sudden deformation of the pipe body. It cannot be calculated from a single simple formula. API 5C3/ISO 10400 recognizes four collapse equations based primarily on the outside diameter / thickness (D/t) ratio.

OCTG connections

Lengths of casing and tubing are joined together with threaded connections. Besides joining the pipe together, connections must withstand all expected wellbore loads for the life of the well (e.g., tension and compression, collapse and burst pressures, and bending). In addition to wellbore loads, connections often must meet other requirements that may include OD/ID clearance, makeup characteristics, and hostile-service environments.

mended practices, and specifications describing minimum requirements for the manufacture and physical performance of API connections. The specifications most commonly used are: •• API Specification 5CT/ISO 11960, “Specification for Casing and Tubing”; •• API Specification 5B, “Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe Threads”. API connections have been in use for decades and have proven to perform well in many applications. However, the increased structural, dimensional, and sealability demands placed on tubulars, particularly in hostile well environments, have led to the development of a number of proprietary (non-API) connection designs. Both API and proprietary connections can have different end finishes. They may be: •• Threaded and coupled (T&C); •• Integral joint (IJ); •• Flush joint (FJ).

Threaded and coupled connections

Threaded and coupled connections (T&C) are the most common connection in use (Figure CT-1). They consist of two externally threaded ends of pipe (called pin ends) joined together by a shorter internally threaded section of pipe stock (called a coupling or collar). The OD of the coupling is larger than the OD of the pipe body. Note that the ID of the API connection is not flush. It therefore creates turbulence in fluid returns. This, in turn, can cause washout in the turbulent zone, pushing API dope out and creating a leak path in the API connection.

Although connections represent less than 3% of the length of the pipe run in a well, they deserve special care and handling. The integrity of the entire wellbore can depend on them, and, further, more than 90% of pipe string failures occur in the connection. Casing and tubing connections are commonly categorized as either API connections or Proprietary connections. The API has published a number of standards, recom-

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Figure CT-1: Threaded & coupled connection.

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CT-8

CASING AND TUBING • Some proprietary connections have leak resistance and higher pressure capabilities that are superior to API connections; • Proprietary connections are frequently the best solution for small annular clearance applications; • Proprietary connections may also be chosen because of superior makeup characteristics. A connection’s resistance to galling, mishandling, or cross threading can greatly affect its performance. Proprietary connections generally have less thread interference than API connections and as a result usually have greater resistance to galling.

Figure CT-2: Integral-joint (IJ) connection.

ERW pipe

Figure CT-3: Flush-joint (FJ) connection.

»» Integral-joint connections

Integral-joint (IJ) connections were developed to provide a strong, leak-tight connection with an OD that was smaller than a T&C connection while reducing problems with downhole makeup or tight clearances. IJ connections do not use couplings, but instead require some form of pipe expansion to achieve the desired tensile strength. An IJ connection consists of two joints of pipe, joined together by an internally threaded box end and an externally threaded pin end, and has only half as many potential leak paths as a T&C connection. Figure CT-2 shows a schematic of an IJ connection. The integral-joint connection shown in Figure CT-2 has had both the pin and box upset for improved tensile load carrying capacity. Many IJ connections are used for liner applications or for contingency casing strings where clearances are particularly tight.

»» Flush-joint connections

Flush-joint (FJ) connections are a special class of IJ connections developed to provide high-pressure integrity in applications with small annular clearance. A true flush-joint connection has OD and ID dimensions equal to that of the pipe body itself. The thread is cut directly onto the pipe wall with no upsetting and no coupling. Therefore, the connection tensile strength is relatively low as compared to IJ, and especially as compared to T&C connections. Figure CT-3 shows a flush-joint connection.

»» Proprietary connections

Proprietary connections are used when API connections cannot meet one or more of the requirements for the well. For example:

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In calculating performance properties, API/ISO specifications treat casing and tubing manufactured by the electric resistance weld (ERW) process the same as casing and tubing manufactured by the seamless process. However, this is not the case in specifying which of the two manufacturing processes are suitable for sour service. API 5CT stipulates that sour service grades of casing and tubing, L80, C90 and T95, must be manufactured using the seamless process. This was done because of concerns about maintaining acceptable sour service metallurgical properties across the weld area. There are other API requirements particular to ERW tubular products: •• There are special chemistry requirements for ERW P-110; •• There are special heat treating requirements for ERW P-110 and Q-125; •• Any pipe component with an API threaded box (female thread) must be made of seamless material. Some of the benefits of ERW pipe are: •• Since the pipe starts out as a flat plate, tight control of the wall thickness is easily achieved; •• The inside surface finish condition can also be controlled to some extent while the pipe is still in the plate configuration; •• ERW pipe is available in much larger diameters than seamless. ERW pipe introduces additional quality control measures associated with the process used to produce the weld seam: •• The pressure welding process used to join the seam requires very tight quality control;

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CASING AND TUBING •• Heat treatment and ultrasonic inspection of the weld seam must also be tightly controlled and documented. ERW manufactured pipe is currently used in many drilling and completion applications by a broad cross section of operators, with the exception of those applications excluded by API Specifications and mentioned above. It is worth noting that many of the expanded tubular applications utilize ERW casing because of its consistent wall thickness. Uniform wall thickness is critical to achieving a uniform expansion and this implies at least one reason why ERW pipe is widely used for this application.

Corrosion

Corrosion can have a major detrimental effect on the mechanical integrity of tubing and casing systems and must be considered in the design. Corrosion can attack the pipe in two ways: 1.• Metal loss will reduce the wall thickness of the casing and lead to a corresponding reduction in its load resistance. This is typical of CO2 corrosion;

CT-9

SSC characteristics

•• SSC is a hydrogen-induced phenomenon that can be nearly instantaneous; •• As temperature increases, a material’s tolerance for H2S increases; •• As yield strength increases, the material’s tolerance to H2S decreases; •• CO2 has no direct effect on SSC, but it can lower the pH of the environment, which will encourage cracking.

SSC resistance

The resistance of steel to SSC is a function of chemical, metallurgical and mechanical properties of the steel, and is also affected by: •• Hydrogen ion concentration (pH) of the environment; •• H2S concentration and total pressure; ••Stress; ••Temperature; ••Time. Alloying elements can lead to a significant improvement in the SSC resistance.

2.• The pipe material can be damaged to an extent that it can no longer withstand operating loads. The most severe forms of this type of corrosion are corrosion fatigue, sulfide or chloride stress-corrosion cracking, and hydrogen damage. These can lead to sudden and often catastrophic failure of the material. The corrosion resistance of a particular material is affected by complex interactions of many factors, including:

Hardness

•• The material under corrosive attack,

The vast majority of oilfield applications utilize low-alloy carbon steel for tubular, wellhead, and other pressure-containing purposes. Generally, more expensive corrosion resistant alloys (CRA) may be appropriate for one or more of the following reasons. •• Weight loss and pitting corrosion resistance; •• Velocity Enhancement; •• Higher Strength.

•• The composition and concentration of the corrosive agents such as CO2, H2S, Salts (NaCI, CaCl2, MgCl2), elemental Sulfur (S), and Oxygen (O2), •• Temperature, pressure, and a host of other factors that must be considered by the well designer but are beyond the scope of this chapter.

Sour service corrosion (SSC) Sour environments and sour service

An environment can contain H2S without being considered a sour environment or necessitating sour-service OCTG. The National Association of Corrosion Engineers (NACE) MR0175 defines a sour environment according to the partial pressures of H2S in the well; environments that contain H2S concentrations lower than those specified by NACE are not considered sour and design for H2S is not necessary.

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In addition to the chemistry, one of the most significant mechanical properties affecting SSC resistance is steel hardness, which reflects steel strength. Since higher-strength, higher-hardness steel has less SSC resistance, maximum hardness values are specified for the various steels.

Corrosion resistant alloys (CRA)

Sour service conclusion

Many environmental factors influence the suitability of any given material in a given medium. Foremost among these are partial pressures of H2S, CO2, concentration of chlorides, and temperature. Other influencing parameters include pH, and carbonate (HCO3) concentration, produced water concentration, and a myriad of produced formation minerals. When planning casing for an H2S application, the casing designer should select materials with care and within the guidelines of NACE MRO175. A qualified metallurgist should always be involved in assessing the severity of a corrosive environment and in recommending appropriate tubulars and/or corrosion monitoring and mitigation measures.

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CT-10

CASING AND TUBING

Summary of API casing grades

The following is a summary overview of API casing grades, with comments regarding suitability for sour service. This is not intended to be a definitive classification and a qualified metallurgist should be involved in the selection of any materials for sour service. ••H-40 s s Used for non-critical, shallow wells; s s Do not use for sour service applications. ••J-55 s s Fit for H2S service at all temperatures; s s Often used for shallow tubing strings. ••K-55 s s Fit for H2S service at all temperatures; s s Often used for large diameter surface casing strings, although line pipe grades X-52 and X-56 are becoming a popular replacement. ••M-65 s s Fit for H2S service at all temperatures. ••L-80 s s Fit for H2S service at all temperatures; s s Has a maximum hardness requirement; s s Often used for sour service production casing, production liners, and tubing. ••N-80 s s Fit for H2S service at temperatures greater than 150 °F for quenched and tempered (Q&T); s s Fit for H2S service at temperatures greater than 175 °F if not Q&T. ••C-90 s s Type 1 grade fit for H2S service at all temperatures; s s Has a maximum hardness requirement; s s An SSC test is required to demonstrate a minimum threshold stress of 80% of YP; s s This grade is becoming obsolete in favor of T-95. May be used for sour service production casing and production liners when L-80 does not have enough strength for the desired wall thickness. ••R-95 s s R-95 is not a sour service grade; s s Fit for H2S service at temperatures greater than 150°F; s s Used for intermediate casing strings that may be exposed to H2S during a gas kick. ••T-95 s s Type 1 grade fit for H2S service at all temperatures; s s Has a maximum hardness requirement; s s An SSC test is required to demonstrate a minimum threshold stress of 80% of YP; s s Often used for HPHT sour gas production casing strings when L-80 and C-90 do not have enough strength for the desired wall thickness;

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s s Relatively expensive. ••P-110 s s Fit for H2S service at temperatures greater than 175°F; s s Minimal chemistry requirements. ••C-110 s s A proprietary sour service grade that may or may not be fit for H2S service at all temperatures. Suitability depends on a number of factors including: the manufacturer, the pH of the produced fluids, and the partial pressure of H2S; s s Relatively expensive. ••Q-125 s s Type 1 is fit for H2S service at temperatures greater than 225°F; s s Often used for critical service wells. ••S-135 s s Not suitable for sour service at any temperature. ••U-140 s s Not suitable for sour service at any temperature; s s May be very brittle and generally discouraged for OCTG service. ••V-150 s s Not suitable for sour service at any temperature; s s May be very brittle and generally discouraged for OCTG service. If an electric weld (EW) product is used, use only products with a full body anneal as opposed to a seam-annealed product.

OCTG Marking

Characteristics of API tubulars are identified by die stampings or stencil markings. The markings, which assist in visually inspecting and verifying the pipe, provide all key elements: manufacturer’s name or mark, size, weight, grade, length, manufacturing process, hydrostatic pressure test and thread type. API Spec 5CT/ISO 11960 requires API tubulars to be identified with paint stencil markings (or die stampings) to aid in the process of visual inspection and verification. The markings give the manufacturer’s name or mark, size, weight, grade, length, process of manufacture, hydrostatic pressure test, and the type of thread. Table CT-10 summarizes the tubular paint stencil information requirements of API Spec 5CT/ISO 11960, and Figure CT-4 shows the locations for the markings on the pipe. Figure CT-4 indicates the pipe was rolled by XYZ manufacturing company and produced to API Spec 5CT/ISO 11960. (Use of “API” is optional.) The “41” indicates the date of manufacture, with the “4” denoting 2014 (or any year ending in “4” such as 2024) and the “1” the quarter of the year.

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CT-11

Table CT-10: Tubular paint stencil requirementsa,b Marking Sequence

Grade

Manufacturer’s name or mark

All Grades

ISO 11960 with date of manufacture. Inclusion of “API” is optional.

All Grades

Unthreaded pipe or special end finishc

All Grades

Size

All Grades

Weight per ft

All Grades

Grade

All Grades

Heat treatmentc

Grades J55, K55, M65

Manufacturing process

All Grades

Supplementary requirementsb

All Grades

Hydrostatic test pressure

All Grades

Type of threadc

All Grades

Full Length driftc

All Grades

Serialization of products

Grades C-90, T-95, Q-125

Notes: a Source: API Spec 5CT, ISO 11960. b A die stamp may be substituted for the paint stencil by mutual agreement of the manufacturer and the purchaser. c If applicable.

“UF” indicates the pipe was shipped with unfinished ends (threading to be done by another party). The pipe is 7 ⅝ in., 39 lb/ft and grade Q125 Type 1. “S” indicates the pipe was manufactured by the seamless process, and “P10000” means that it was hydrostatic pressure tested to 10,000 psi. Finally, “D” indicates the pipe was drifted along its full length with an API standard drift. API couplings are also required to have specific markings. However, because of space limitations on the coupling, this information is generally die stamped rather than paint stenciled. In general, the markings on the coupling include the manufacturer’s name or symbol, ISO 11960 with manufacture date, thread type, and the grade.

2 ft

2 ft Paint stencil marking in this area

XYZ ISO 11960 41 UF 7-5/8 39.00 Q1 S P10000 D

Paint band Coupling paint

API Spec 5CT/ISO 11960 also require that pipe and couplings be identified by color-coded paint bands to indicate the grade. The paint bands are applied by one or more of the following methods:

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42.23 ft

Figure CT-4: Location of paint stencil marking and paint bands. See text for a discussion of the markings.

•• A paint band encircling the pipe at a distance not greater than 2 feet from the coupling or box end; •• Paint entire outside surface of coupling;

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CT-12

Table CT-11: ISO pipe paint color code identification J55 Tubing

One bright green

C90 Type 2

One purple, one yellow

J55 Casing

One bright green

T95 Type 1

One silver

K55

Two bright green

T95 Type 2

One silver, one yellow

M65

One bright green, one blue

C95

One brown

N80 Type 1

One red

P110

One white

N80 Q

One red, one bright green

Q125 Type 1

One orange

L80 Type 1

One red, one brown

Q125 Type 2

One orange, one yellow

L80 9Cr

One red, one brown, one yellow

Q125 Type 3

One orange, one green

L80 13Cr

One red, one brown, two yellow

Q125 Type 4

One orange, one brown

C90 Type 1

One purple

•• For pup joints shorter than 6 ft in length, the entire surface is painted, except the threads.

a few miles, and at regular intervals thereafter during the journey.

The ISO pipe paint color code identification is summarized in Table CT-11.

The stowage and transportation of tubulars by marine craft is the sole responsibility of the Master of the marine vessel. Handling of tubulars to and from the vessel should be governed by the same guidelines indicated for land transport. In preparation for handling offshore, casing and tubing should be bundled with slings and secured with a bulldog grip and a plastic tie-wrap to prevent loosening of the bundle.

Other paint codes that indicate the results or types of inspections performed at the pipe yard may also be present on the pipe. Inspection paint-code bands are red for rejected pipe and white for accepted pipe. These bands will be placed as close as possible to the coupling without conflicting with pipe grade paint bands.

Transportation and handling

Tubular-handling practices are described in API Recommended Practice 5C1, “Recommended Practices for Care and Use of Casing and Tubing”. Additional industry rigging courses are available to teach standards and practices for working with forklift trucks and cranes. Personnel who should receive training for handling of tubulars may include roustabouts, floor hands, deck hands (offshore), riggers, crane operators, drillers, deckhands, thread representatives, casing hands, drivers and dock hands.

Transport and offloading

The forces applied to a load when a vehicle brakes, accelerates, or changes directions may be sufficient to cause the load to slide or shift Approved restraining devices should be sufficient to withstand a force equal to the total weight of the load acting in a forward direction when braking and half the weight of the load acting backwards or sideways. Anchor points must be designed to resist twice the weight of the load in any direction. Tensioning devices/lashings points should be checked prior to moving the loaded vehicle, after

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The use of metallic supports and slings is acceptable for carbon and low-alloy steel, but corrosion-resistant alloys should be placed on non-metallic supports, and forks of the forklift should be protected with wood or plastic. Textile or plastic-coated slings should be used for handling any CRA material. For safety reasons, use of hooks is not recommended for handling any type of tubular because of the possibility of accidental release. Instead of hooks, it is recommended to handle tubulars with slings and/or cables. Slings and cables must be stored out of the weather and inspected prior to storage. Damaged slings or cables must be handled according to instructions for repair or destruction. Regardless of material, a sufficient number of supports are required to accommodate the weight and quantity of the tubular. To prevent bending, space the supports evenly but no farther than 10 ft apart.

Handling

Racking practices should allow protectors to be removed, connections inspected, and threads cleaned and doped. Provide a space equal to twice the circumference of one pipe between tube bodies on each layer.

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CASING AND TUBING Unless a crane is available, pipes must be rolled to the catwalk. If pipes are higher than the catwalk, use planks of wood to create a very slight slope. When rolling CRAs, use a rope to control rolling speed. To pick up and position a joint in the V-door, use a “single joint elevator” rather than a rope or a chain to lift the pipe, or use a pick up/laydown machine or hydraulic catwalk.

Impact of low temperatures

Low temperature reduces the impact resistance of steel. Pipes that are dropped, bent or deeply scratched should be inspected. Take care to avoid scratching surfaces when separating frozen tubes, and do not hammer thread protectors to remove. Use a stabbing guide to avoid damage while making up connections, and ensure pin and box are similar temperatures to ensure proper torque response. Use Arctic-grade thread lubricant when appropriate.

Tubular storage

At the rig-site, tubulars are typically stored above ground or deck level on pipe racks. Tubulars stored for long periods in wet climates should be separated, using a plastic wedge or T-piece to allow drainage and the rack should be tilted towards the pin-end to enhance self-drainage. For storing tubulars, use open-ended thread protectors to allow evaporation.

Pipe racks

Practices for the design of pipe racks are provided in API RP 5C1, Section 6.3. The design depends on local conditions, such as the required load-bearing capacity and degree of permanency. Racks should be spaced at about 6.5 ft (2 m), which allows 20-ft (6.1-m) joints to be stored on two racks, and 40-ft (12.2-m) joints on four racks. Timbers are often used for temporary stringers. Dimensions depend on soil-bearing capacities, but 10 ft length x 10 in. diameter generally suffices. Layers must be separated and the separators must be aligned vertically to avoid bending the pipe. Timbers of approximately 5-in. (7.5-cm) diameter are commonly used as separators, with a wedge secured to the timber at each end. Green timber should not be used, because their moisture content may cause corrosion. Stack height should not exceed 10 ft (3 m), including the pipe rack. The length of each pipe rack should accommodate Range 3 tubulars. (Refer to Table CT-7 for lengths of Range 1-3 tubulars and to Table CT-8 for CRA tubulars.) The width should not exceed 40 ft (12 m) nor be less than 20 ft (6 m). For transport and handling operations, allow a lane of not less than 20 ft (6 m) wide on each side of the racks and a space of approximately 5 ft (1.5 m) between racks. For small quantities, reduce the stacking height and increase the stacking

IADC Drilling Manual

CT-13

width in proportion. As a rough guide, the height of tubulars in a stack should not exceed the base width; therefore, when planning pipe racks, allowance must be made for small quantities that require more space than the table indicates.

Storage coatings and compounds

The choice of preservative or coatings that may be applied to protect stored tubulars depends on the corrosiveness of the environment and cost. Casing manufactured in accordance with API RP 5CT will have a mill coating to protect it during transit. If casing is to remain in storage for a long period, the mill coating can be supplemented, or completely removed and new coating applied. Internal and external surfaces of production tubulars may be grit-blasted to achieve this and thread protectors are fitted to prevent contamination. Particular care is need with notch-sensitive casing, such as C95 and P110. (Notch-sensitive metals suffer significant strength loss from notches.) If storage for more than three months is expected, assess whether the mill coating is adequate, and the pipe should be cleaned and coated internally and externally, if needed. Evidence suggests that coatings may affect acoustic cement evaluation logs and the seal itself. In critical applications the external coating can be removed. Compounds are available that are specifically designed for the tube body, or the connection threads. In addition, hybrid compounds are available. Ensure the proper compound is used for the intended service. Storage compounds should also not be confused with thread compounds. Many compounds contain elements such as lead, copper, zinc, arsenic, antimony and molybdenum disulphide that may be harmful to the environment. These should be used in accordance with the manufacturer's recommendations. Further, properties of storage compounds differ from those of running compounds. Consequently, using a storage compound to make up a connection could result in a result in a reject make up and even a damaged connection, due to the friction factor & mating tolerances. Ensure that any compound being spread on the connection is clean and debris-free. The compound should be covered at all times by protectors to prevent contamination from foreign materials. (Sand & grit can score the seal of a connection, rendering the connection unusable.)

Thread protectors

Thread protectors are used for shipping and are not adequate for running operations. Air-operated thread protectors (Figure CT-7) used to prevent impact damage have an inner diameter that can be made reduced by clamps or an air bladder to enable the protector to grip the pin. These protectors will also have a shoulder of an even smaller diameter for the end of the pin to rest on and to align the protector when being placed. They are applied at the pipe deck and

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CASING AND TUBING

CT-14

Block or top drive

Link (bails) Engage elevators to pick casing up off slips, and disengage slips

D rings

Sling

Power tongs

Single joint elevator

Power slips or casing tongs

V door

Disengage slips, then lower casing

Figure CT-5: Procedure for running casing or tubing. From left, pick up a joint positioned in the V-door. Next, make up a new joint to the tubular hanging in the slips. Then engage elevators, release the slips and run the tubular into the hole.

removed just prior to stabbing the pipe. Heavier-capacity versions can also be used to rack stands of pipe.

Running procedure

Casing and tubing may be run by either rig crews or specialty service companies that provide and operate running equipment, or a combination of both. The general procedure and equipment utilized are illustrated in Figure CT-5. Procedures will vary with the type of elevators, spiders, make-up equipment, and other factors. When using bails, it is important to use a specified length to ensure proper equipment spacing. General descriptions of each individual component of a casing running system are provided in this chapter. The crew should refer to the equipment manufacturer’s detailed procedures for rig-up, inspection, and operations for the specific equipment used to run the casing. 1.• Clean all compounds from connections and drift full length. Drifting can also be performed in the v-door to allow drift to free fall from box to pin end. Take care when removing the pin end protector to ensure the drift does not fall out;

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2.• Pick up casing joint and position the upper box end in the V-Door with tugger line, crane, or mechanical pick-up machine; 3.• Latch single joint elevator below box. If casing does not have a square shoulder box, pick up on pre-installed lift subs made up in box;. 4.• Raise block or top drive to pull casing through V-Door and continue upward until the pin end is above the floor. Remove the pin protector. Continue raising joint until the casing pin is hanging vertically above the joint in the spider or slips; 5.• Apply thread dope to pin and/or box, as directed by operator's representative; 6.• Lower joint and guide pin by hand into the box of the previous joint, ensuring that workers’ fingers are clear of mating parts and pinch points; 7.• If a stabbing guide has been used on the box of the casing joint in the slips, remove it; 8.• Swing power casing tongs into position 1-2 ft above the pin and close the side door;

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CASING AND TUBING

Figure CT-6: Stabbing guide.

9.• Make up the connection to the appropriate torque, and/ or thread position. See separate discussion of make-up procedure. Be sure to pull power tong back to a safe area; 10.•Slowly lift elevators and check to ensure string load has been transferred; 11.• Open spider or lift slips when approved by the driller; 12.• Lower the casing string at the planned speed, which may vary with hole conditions or the ability of the hole to withstand surge pressures. Initiate movement slowly; 13.• While the joint is lowered, the single joint elevator hanging from the slings will be caught by the floor hands and swung out and latched below the box of the next joint in the V-Door;. 14.•Continue lowering the string to position the box at the planned working height above the spider and rig floor. 15.• Set the spider slip assembly or manual slips and slack off the string weight. 16.•Disengage the elevators and pick up to position them a short distance above the floor so that they are in position to reach the next joint with the single joint elevator. 17.• Install clamp-on thread protector or stabbing guide on box in the spider, if one is to be used. Fill up casing joint with drilling fluid. 18.•Repeat the process beginning with Step 1.

Running tools and equipment Stabbing boards

The stabbing board is a temporary work platform installed approximately 30 ft above the rig floor for the stabber to stand on while aligning the pipe for make up. The platform can usually be adjusted up and down as much as 10 ft to allow for different lengths of pipe. Running pipe with a stab-

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CT-15

Figure CT-7: Inflatable and made of rubber, Air-operated thread protectors are quick to install, and protect tubular pin end threads from damage en route to the drill floor.

bing board requires good communications and constant awareness of the location of the top drive.

Stabbing guides

Stabbing is the action of guiding the pin end of the pipe into the box end of the previous joint in the spider. A stabbing guide (Figure CT-6) is often used to assist in guiding the pin into the box and to protect the threads of the box and pin. Stabbing guides are generally funnel-shaped and wrap around the box and extend above it. As the pin enters the upper section of the guide it is centered and its lateral movement is limited. This prevents damage to the pin threads, which do not make contact with the box until just prior to engaging the threads. Guides should be considered for use with premium connections in which the pin end or step shoulders provide a seal surface that must be protected from damage.

Air-operated thread protector

An inflatable rubber protector is quick and easy to install and remove. They protect the tubular pin end threads from damage en route to the drill floor (Figure CT-7).

Single-joint elevators

Single-joint elevators (SJE) are used to pick up a single joint of casing through the V-door and position it above the rotary table (Figure CT-8). They are typically rated for 5 tons and feature a center hinge design to latch the elevator around the casing below the collar. An SJE is used when a casing pickup machine is unavailable. With the SJE, a wire tugger line moves the casing to the rig Figure CT-8: Single joint elevator. floor.

Full-string elevators

Full string elevators are used to lift the entire casing or tubing string. These are designed to either pick up against a square

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CT-16

CASING AND TUBING A

B

C

Figure CT-9a, b and c: From left to right, side-door elevator with a load shoulder for square shoulder connections; center latch elevator with slips to grip external casing surface. These may also be designed with a load shoulder for square shoulder connections. Combination elevator spider with powered slips to grip the external casing surface.

connection shoulder if one exists, or they hold the outside of the casing with gripping elements (i.e., slips) if the casing connection is flush or has a tapered upset. Three types of elevators are shown in Figure CT-9. The center latch type may be designed to use either a load shoulder or slips. Lift subs may also be screwed into flush joint or tapered boxes to create a lifting shoulder. There are two types of lift subs: those for lifting single joints of pipe from the V-door, and those for lifting and running a full string. Typically, 3-5 lift subs are supplied to run a string of pipe so they can be removed and recycled on the pipe deck without interrupting operations. Elevator operating controls can be manual or have pneumatic or hydraulic assistance. In either case, a crewmember is normally located in the derrick on a stabbing board to position the elevators and operate the power controls. With power-assisted systems, remote controls may be located on the floor. If these A are used, it is good practice to have visual flags, cameras, or pneumatic/hydraulic/electric indicators to ensure the pipe is engaged. Interlock systems will ensure a further level of security against dropped pipe.

•• Ensure load-bearing rings in elevators are not deformed. Recheck regularly; •• Tools might require greasing of slip backs. See the OEM manual for instructions. Do not alter the type of grease and do not use pipe dope or thread compound on slips or elevators. Using the wrong grease can be as detrimental as using no grease at all.

Casing running tools

The casing running tool (CRT) is essentially a type of elevator that connects directly to the top drive through a drill string sub, rather than being suspended from bails. This enables fill-up and makeup using the top drive’s circulation, rotation, and torque capabilities (Figure CT-10a). The connection to the top drive also allows casing to be rotated as it is run and circulated for conditioning and cementing.

B

C

Pre-job checks

•• Secondary latch mechanisms should be present, checked before lifting, and visually verifiable; •• Ensure inserts of slip-type tools are clean. Recheck during job;

Figure CT-10a, b and c: From left to right, CRT with link tilt for picking up and presenting a single joint for make up (Figure CT-10a); CRT with internal gripping system (Figure CT-10b); CRT with external gripping system (Figure CT-10c). Figure CT-10a courtesy Weatherford. Figures CT-10b and -10c courtesy Volant Products Inc.

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CASING AND TUBING

A

B

CT-17

C

Figure CT-11a, b and c: From left, Floor mounted casing bowl with manual hand slips, casing bowl with mechanical assist for removal and insertion of slips, and near-flush mounted spider (FMS) with power slips.

The casing is suspended from the CRT by either internal or external gripping systems, and torque is transferred through the same device. Internal grippers that extend into the top few feet of the casing (Figure CT-10b) are used over a wide range of casing sizes, from 4.5 in. to as large as 30 in. Internal grippers also include an elastomer sealing element to allow circulation. External gripping systems are available for smaller casing (Figure CT-10c) and are well suited for lifting very heavy casing strings, a key advantage of external grips. While they grip the exterior of the pipe, they must still have an extension that passes inside to seal against the interior to allow circulation. CRTs may be may be part of a casing running system or standalone elevators. Since the casing is run and made up with the rig’s top drive when a CRT is used, the driller will play a larger role in the casing installation than with conventional tongs. Rig-up and operating practices are specific to each casing running system, and suppliers should provide training for the rig crew and qualified service personnel.

Insert bushings can be used with some bowls to reduce to a smaller size, e.g., a 20-in. by 16-in. reducer bushing can be fitted to a 20-in. bowl so that 16-in. and smaller pipe can be handled. Systems are available with mechanical assist devices to lower or lift the slips in and out of the bowl (Figure CT-11b). They are designed to be removed from the pipe by splitting or removing a section. These are commonly used with tubing and smaller casing sizes. Flush-mounted spiders (FMS) are available with power slips that mount within the rotary and project above it by only a few inches (Figure CT-11c). These are typically equipped with casing slips within the body of the spider that support the pipe, but they are also available with load shoulders for square shoulder connections if needed. Some hydraulically operated systems will be able to resist makeup torque when loaded with only the first joint, but other systems require backup tongs to be used to resist makeup torque until the string weight on the slips is sufficient. Spiders typically have

Casing slips and spiders

Manual casing slips or spiders are used to hold the vertical casing load as each connection is made. Historically, hand slips were placed into bowls inside the rotary table, and backup casing tongs were used to prevent rotation of the casing in the slips during makeup (Figure CT-11a). For larger diameters and tonnage combinations, independent bowls may be placed on the rig floor above the rotary table. These may require additional support plates to properly transfer the load to the drilling rig structure. Independent bowls can use the same hand slips as used in the rotary if they have the normal 4 in./ft taper, but some independent bowls have a 3 in./ft taper and would require matching slips. The bowl’s normal maximum sizes are 3 ½ in., 4 ½ in., 5 ½ in., 8 5/8 in., 10 ¾ in., 13 3/8 in., 16 in., 20 in., 30 in., 36 in., and 42 in. with ratings from 100-500 ton.

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Figure CT-12: Combination spider/elevators.

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CASING AND TUBING

CT-18

A

Figure CT-13a, b and c: Clockwise from left, Manual casing tongs used for makeup or backup, power casing tongs, combination tongs. Figures CT13b and -13c courtesy McCoy Global.

B

top and bottom guides that are changed for different pipe sizes. Check to ensure centralizers, cable clamps, side pocket mandrels, and other larger diameter elements will pass through the guides and power slips. Combination spider/elevators can be dressed as either an elevator, or the lift eyes may be removed for them to be used on the rig floor as a spider (Figure CT-12). These are generally external slip type elevators. When used as a spider, the load is transferred to the rotary table through the bottom surface of the elevator (sometimes requiring C plates or adapter plates). When dressed as an elevator, the tool will have a bell-shaped guide and bottom guides to guide it over the top of the pipe. When dressed as a spider, there will be no bottom guide or bell guide but top guides will be fitted.

C

Tongs

Tongs are used to apply torque to make up and break threaded connections. They may be manual tongs, power tongs, or combination tongs (Figure CT-13). The manual tong (belt tong, rig tong) is essentially a wrench used to make and break casing and tubing connections (Figure CT-13a). This tong is typically suspended by a cable from the mast and hangs near the rotary. The tong is latched around the casing and torque is applied by pulling tension on a cable attached to the tong arm. The tong operator, who can be either a service company employee or a rig crewmember, increases cable tension on the arm until reching the required makeup torque. The torque in the connection is calculated by the pull on the cable and the length of the tong arm. It is important to position the cable at 90° from the arm of the tong at max torque for an accurate. calculation When manual tongs are used for make up a second manual tong is often used below the connection to hold back-up torque to resist the makeup torque. This tong is generally fixed to a structural element of the rig via a chain or cable and remains stationary. The tong's position and suspension

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points should be arranged according to OEM installation instructions. Failure to do so could result in an unsafe, uncontrolled load movement on the rig floor and increased work for the crew. For hydraulic power tongs, the torque is applied by hydraulics within the body of the tool, rather than by pulling on an external tension cable (Figure CT-13b). A static snub line is attached to the rig to prevent the tong from rotating about the pipe during makeup. Alternatively, combination power tongs may be used that have an assembly that also grips the casing below the connection and the torque reaction is held within the system (Figure CT-13c).

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CASING AND TUBING

CT-19

Figure CT-14: Two examples of tong positioning systems. Courtesy McCoy Global.

Power tongs are installed with a means to account for thread makeup loss. This is typically a spring in series on the hanging line that will allow the tong to travel up/down as the thread engages on the connection; this is commonly known as makeup loss/gain. Hydraulic pressure is supplied to the power tong by an independent hydraulic power unit or the rig’s hydraulic systems. Power tongs are typically capable of generating high speed as well as excessive torque that far exceed the recommended limits of the connection being made up. The desired RPM, torque, and clamping/crushing limits should be considered when selecting the appropriate tong for the application. For proper handling for safety, the operator of the power tong must be competent in the safe use of the equipment. Some operational risks are noted below: •• Because power tongs are capable of generating extreme torque, a snub line should be used, even with integral backups; •• Pinch points should be guarded and indicated on the tong system. Hand placement practices should be discussed prior to each job. It’s important that only the tong operator place his hands on the tong; •• As with manual tongs, power tongs should be suspended and positioned according to manufacturer’s

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instruction. Safe work positioning and motion paths should be discussed prior to each job. Do not assume each member has previous training; •• Ensure open throat tongs include a safety system to prevent rotation when the door is not fully closed. Pre-job testing and regular inspection of the systems should be scheduled and should follow the OEM instructions. Follow manufacturer’s lubrication instructions.

Tong positioning systems

The purpose of a tong positioning system is to present the tong to the pipe in the rotary for makeup and breakout operations without manual handling (Figure CT-14). A tong positioning system allows for a single operator to control the position of the tong and reduces the number of personnel on the rig floor. As the capability, mass and size of tongs has increased, the need for tong positioning systems has increased accordingly. The many models and styles of tong positioning systems range from a simple cylinder that pushes and retracts a suspended tong to fully rigid power tongs on the floor or attached to the rig structure. These systems must be installed according to manufacturer’s instruction. Because each functions somewhat differently, it is essential that training be provided, and that the competency of crewmembers be confirmed prior to each job.

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CT-20

CASING AND TUBING

Figure CT-15: Torque turn monitoring systems are primarily data acquisition and control systems with the ability to measure and display connection data acquired tubular during makeup and breakout. Courtesy McCoy Global.

Torque turn monitoring systems

Torque turn monitoring systems are primarily data acquisition and control systems with the ability to measure and display connection data acquired during the makeup and break out of tubular products (Figure CT-15). These systems integrate with power tongs and bucking units and have a primary function to stop torque actions at a predetermined torque or turns (or combination of) limit as specified by the parameters set at the start of the job. These systems vary in complexity and features but are fundamentally based around torque vs. turns as a means to predict appropriate make up. This data is collected and graphed on a display for the operator to evaluate in order to determine if the connection was made up to acceptable criteria. The graph is shown where turns are represented on the X-Axis and torque is represented on the Y-Axis. Initial thread engagement, shoulder point of primary seal, and change in torque from shoulder to peak is displayed. The proper parameters for the makeup are given by the thread OEM for the connections being used. These systems are used on most OCTG connections, but are almost always required when running premium connections. Interpretation of the graph and data should only be attempted by a trained and competent person that has knowledge of the connections being serviced. Figure CT-16 is a typical torque-turn graph showing the amount of torque supplied to the casing as the connections is screwed together. The lower horizontal axis indicates the turns in the pipe, the left vertical axis indicates the corresponding torque supplied to the casing and the right hand axis indicates the RPM while the connection is made up. The line between the upper and lower limits is the optimum torque for the connection and is typically specified by the OEM. The torque monitoring system is activated as soon as the connection is started. In the beginning of the connection

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make up, the torque supplied to the casing is fairly low and remains low until the casing is screwed in for seven full turns. At this point the tapered threads on the casing starts to bind with the threads on the coupling and torque begins to increase until the casing end meets the shoulder in the coupling. The connection has “shouldered”. When this point is reached, the torque will increase rapidly, as it takes only one-tenth of a turn to apply the final makeup torque. The casing will not screw in deeper into the coupling but any rotation supplied to the casing will increase the pressure on the shoulder. The compression of the casing end and shoulder provide the seal and the structural strength of the connection. As soon as the optimum torque is reached (peak torque), the rotation of the casing is stopped and the torque reduced to zero. The connection must be made up to a specific torque to provide a proper seal and structural strength. If the torque is below the lower torque limit, the connection might not seal properly or achieve the required structural strength. If the connection is torqued higher than the upper limit, the seal faces might be damaged and the structural strength compromised. The equipment used to make up the connection has inertia and cannot be stopped immediately. Since it takes only one-tenth of a turn to apply the delta torque, the make-up speed of the connection must be slow enough to enable the equipment to stop within a tenth of a turn. It is important to specify an RPM that will allow the equipment to be stopped in time, preventing the torque from overshooting the upper torque limit and thereby damaging the connection. On the other hand, if the RPM is too low, make up will proceed too slowly. Figure CT-16 shows make up at a speed of approximately 11 rpm for most of the connection. Once the shouldering point was reached, however, RPM dropped rapidly to zero.

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CASING AND TUBING

CT-21

Torque (ft lb)

RPM

22,000 21,000 20,000 19,000 18,000 17,000 16,000

40 38 36 34 32 30

Lower torque limit

28

15,000 14,000 13,000 12,000 11,000 10,000 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0

Peak torque

Upper torque limit

26 24

Delta torque

22 20 18 16

RPM graph

14 12 10 8

The connection is shouldering

0

1

2

3

4

5

6

7

Turns

8

9

10

11

12

13

14

6 4

15

2 0

Figure CT-16: Typical torque-turn graph showing the amount of torque supplied to the casing as the connection is screwed together. The lower horizontal axis indicates the turns in the pipe, the left vertical axis indicates the corresponding torque supplied to the casing and the right hand axis indicates the RPM while the connection were made up. The line between the upper and lower limit are the optimum torque for the connection and is typically specified by the OEM. Courtesy Tesco Corp.

Fully remote tong systems

The purpose of a remote tong system is to remove the tong operator from the area of moving equipment. This differs from tong-positioning systems that still require an operator to function hydraulically or pneumatically assisted controls at the tong unit. The most common functions of a remote tong system include make/break, backup clamp/unclamp, door open/close, gear selection, reversing pin location, and, in some cases, tong position. (See preceding section on tong positioning systems.) These remote systems vary from tethered control panels where the operator is positioned away from the tong to wireless control stations that may, in some cases, be integrated into the driller’s chair controls.

Fill-up and circulation tools

Fill-up tools are stingers that are run into the top of each joint and through which mud is pumped to fill the empty joint. This enables the casing to be filled as it is run to eliminate fill-up time, and it allows for circulation of the casing if an obstruction is encountered downhole. The stinger may be made up directly to a top drive or suspended below a hook with a a high pressure mud line attached for circulation. Whether it is run below a top drive or hook, it is long enough to extend down through the center of the elevators so that the sealing element on the end enters the top of the casing as the elevators are lowered. The sealing element is

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Figure CT-17: Safety clamp.

then expanded to effect a seal on the inside of the pipe and fluid is pumped as the casing joint is being lowered.

Safety clamps

Safety clamps (Figure CT-17) are used with slip-type spiders and hand slips until sufficient casing weight is run to ensure the slips will seat reliably (typically about 20,000 lb). Safety clamps are not lifting devices and are positioned far enough above the slips so that they do not make contact with the slips when the slips are set. They are installed after the string is set in the slips and removed after the string weight is returned to the elevators. Manufacturing specifications are provided in API Spec 7K and maintenance in API Spec 7B.

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CT-22

CASING AND TUBING

Interlocks, zone and elevator management

Interlocks prevent the opening of the elevator before the spider or slips have closed to secure the string and they prevent the spider or slips from being opened before the elevator has closed. Interlocks can be part of an integrated drill floor system or supplied by a service company along with hoisting tools.

Figure CT-18: Example dies. Courtesy McCoy Global.

Dies, inserts, jaws

The purpose of dies, inserts, and jaws is to allow a tool (elevator, spider, slips, tongs, etc.) to grip a tubular. The majority of dies work with teeth that penetrate or deform the surface of the tubular and operate in shear. This die penetration varies by tooth design, which allows different style dies to penetrate deeper into the OD of the pipe and provide higher load carrying capacity based on depth of penetration and clamping force (Figure CT-18). Other dies work by using pressure and surface contact and have lower load ratings than toothed dies. The manufacturer of the tool that uses dies determines the dimensions of the dies. There are no standardized sizes, so dies from one tool should not be assumed to be interchangeable with those from another tool. Instructions on installation and removal of dies are given in operating manuals for their respective tools. Some key points: •• Use of the manufacturer’s recommended lubricant for the back of dies is critical as this changes with OEM tools and will affect safe working load (SWL) of the tool; •• When removing stuck dies with impact, wear appropriate PPE as they may shatter; •• Overloaded dies that fail may be fragmented. Inspect them regularly; •• Dies are not repairable; •• Store dies in a manner to avoid impact damage and corrosion.

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Installation of interlocks must be done according to instructions provided by manufacturers of the equipment. While interlocks are often assumed to be fail-safe, operation of interlock systems should be supported by sound practical procedures that use human observation to the greatest extent possible. All interlock systems have some form of override to allow for testing, rig-up, etc. The use of the interlock override should be strictly controlled, ideally via the permit-towork system at the worksite. Pre-job testing and regular inspection of the systems should be scheduled. Often several systems are in use at one time on a rig site, and these systems do not necessarily exchange information. This should be addressed and shared knowledge on the rig floor during use.

Pick-up/lay-down tools

There are numerous systems for picking up or laying down casing. On land rigs, these systems are typically rigged up temporarily for the casing running operation. Pick-up / laydown systems are more likely to be an integral and permanent element in offshore pipe handling systems, or on some large land rigs. Pick-up/lay-down system designs generally fall into one of two major categories. In cable systems, a wire is run from a winch unit located at the end of the catwalk to an anchor point above the floor. Casing is then picked up by arms that place it in a trough suspended from a wire rope, and the trough and casing are pulled up the wire to the rig floor. In the second type, casing is also picked up onto a horizontal trough positioned on the catwalk, but the trough is supported by hydraulically powered arms that tilt and move it to position the upper end of the casing at the rig floor. The casing is solidly supported by the catwalk throughout the process, rather than suspended in air by wire. The hydraulic system is considered more reliable and it is also preferred for larger and heavier casing. New offshore rigs and large land rigs might be equipped with permanent pick-up systems used for both drill pipe and casing. These vary from hydraulically supported troughs to

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Figure CT-19: Horizontal makeup system. Courtesy McCoy Global.

more complex armatures or trolleys. The manufacturer’s instructions should be followed for installation and processes in place to ensure the rig crew is trained in maintenance, operations, and potential pinch points and handling risks.

Horizontal make-up systems

Horizontal make-up systems are also referred to as bucking units, make/break machines, and offline makeup units. These may be used to make or break connections offline, outside of the critical path of activity on the rig (Figure CT19). These machines can be used for a range of operations such as stand-building, pre-assembly of completions, installation of couplings, etc. Bucking units are generally provided in one of two versions. One version is commonly referred to as a ‘make/break’ unit. This system functions similar to a power tong, in which pre-turns are applied via spinners, with final torque then applied in incremental bite/turn of the head. The alternate version has a continuous rotating head and functions similar to a hydraulic power tong, where the makeup is continuous from initial pre-turns to final torque.

move pipe to and from the catwalk and a pickup/laydown machine that then moves it to the V-door.

Vertical alignment systems

Alignment systems are used to ensure that the pin on the joint being positioned vertically for make up or breakout is aligned with the box to prevent damage to the threads, and to ensure a good make up or break out. There are two basic types of mechanical alignment systems: those that are capable of returning a joint that has moved out of alignment back to the correct position and those that simply hold the joint in the correct position. The standard location on a rig site for stationary equipment is normally the derrick or the top drive assembly. Follow the installation and operating instructions provided by the manufacturer. Alignment systems operate in the same path as the travelling block assembly and procedures or interlock systems should be utilized to prevent collisions. The system should be tested prior to the job and inspected regularly as specified by the manufacturer.

Horizontal pipe handling

Offshore rigs and large land rigs may be equipped with horizontal pipe handling systems. These are typically a combination of an overhead gantry crane that can pick up and

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CASING AND TUBING

References

1.• API Spec 8C: Drilling and Production Hoisting Equipment.This has replaced API Spec 8A. 2.• API RP 8B/ ISO 13534: Inspections, Maintenance, Repair and Remanufacture of Hoisting Equipment. 3.• API Spec 8C/ISO 13535: Specification for Drilling and Production Hoisting Equipment.

5. API Spec 5CRA/ISO 13680: Specification for Corrosion Resistant Alloy Seamless Tubes for Use as Casing, Tubing and Coupling Stock. 6. API TR 5C3/ISO 10400: Formulae and calculations for casing, tubing, drill pipe and line pipe properties. 7. API Spec 5B: Specification for Threading, Gauging and Thread Inspection of Casing, Tubing, and Line Pipe Threads.

4. API Spec 5CT/ISO 11960: Specification for Casing and Tubing.

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Enhancing operational integrity by ensuring a competent workforce

Accreditation & Credentialing

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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 Moji Karimi, Weatherford International Eric Moellendick, Schlumberger REVIEWERS Kyle Graves, Apache Don Hannegan, Weatherford International Calvin Holt, Chevron Dietmar Neidhardt, Tubefuse Technologies Bill Rehm, Consultant

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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: 978-0-9906220-6-2

Printed in the United States of America.

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Contents

CASING WHILE DRILLING

Introduction....................................................................CD-1 Non-retrievable casing while drilling........................CD-1 Enhanced rig equipment - surface drive systems........................................................ CD-4 CwD centralizers.................................................. CD-4 CwD connections, torque rings and wear bands/sleeves.................................... CD-4 Plastering effect.................................................... CD-5 Operations............................................................. CD-5 Why drill with a non-retrievable CwD system?........................................................ CD-5 Typical non-retrievable CwD problems......... CD-6 Retrievable casing while drilling.............................. CD-6 Locking assembly................................................. CD-6 Internal duplex stabilizer.................................... CD-6 Underreamer......................................................... CD-7 Operations............................................................. CD-8

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Why drill with a retrievable CwD system?... CD-8 Typical retrievable CwD problems.................. CD-8 Liner drilling................................................................... CD-9 Non-retrievable liner drilling............................. CD-9 Non-retrievable liner drilling and setting sequence................................................................ CD-9 Why drill with a non-retrievable liner drilling system?................................................................. CD-11 Typical problems with a non-retrievable liner drilling system..................................................... CD-11 Retrievable liner drilling........................................... CD-11 Why drill with a retrievable liner drilling system?................................................... CD-12 Typical problems with retrievable liner drilling systems................................................................. CD-12 Safety and the environment................................... CD-13 Conclusion................................................................... CD-13

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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!

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Introduction

Casing while drilling (CwD) technology uses the casing string as a drillstring so that casing is landed on bottom during the drilling process, rather than later in a separate installation process. The technology is typically applied for purposes of increasing drilling performance, putting trouble zones behind CwD, and enhancing the integrity/quality of the wellbore from the resulting plastering effect. CwD can be performed using two kinds of systems: non-retrievable and retrievable. The non-retrievable system’s assembly comprises a drillable casing bit attached to the bottom of the first joint of casing. A float collar is usually run between the first and second joints. Drilling torque is transferred from the top drive to the casing string and drill bit via the casing-running tool. The casing-running tool can be a crossover, a CwD spear or a premium top-drive CwD system. Once the targeted depth is reached, there is no drill bit to recover through the casing. Since the float collar is also run in the casing string, cementing can begin immediately. After the cement is set, the next bottomhole assembly (BHA) drills out the shoe track and the casing drill bit. With the retrievable system, an underreamer and pilot bit assembly is latched below the casing by means of a retrievable locking assembly. As the assembly drills ahead, the casing is run in the hole, either in a sliding or rotating mode. Upon reaching TD, the BHA is unlatched and recovered with a special retrieval tool on drillpipe. Cementing plugs can then be pumped downhole into a landing profile to complete the cementing process. In this chapter, CwD systems are discussed first, and then liner drilling is covered. The components of non-retrievable and retrievable systems and their functions are explained in each section.

Non-retrievable casing while drilling

With non-retrievable CwD, the drillable casing bit is attached to the first joint of casing to eliminate the drillpipe and hence the need for tripping to recover the bit (see Figure CD-1). This process also eliminates the need for conventional casing running. CwD faced so much resistance initially since it was thought to create problematic situations such as stuck pipe and higher equivalent circulating density (ECD) due to narrow annulus. However, once the technology was implemented, it was observed that these situations were not arising. In addition, there were unexpected advantages due to the special geometry of CwD and the interaction of the large-diameter pipe with wellbore wall. This interaction is commonly referred to as the plastering effect.

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Figure CD-1: Non-retrievable casing while drilling. Courtesy Weatherford.

The main component of non-retrievable CwD is the drillable casing bit. Figure CD-2 shows drillable casing bits. The installation of a separate float collar in the casing string allows the cementation operation to begin immediately once TD has been reached and to be completed as normal. After waiting on cement, the next drill bit is run and drills through the shoe track and casing bit before entering new formation. Alternatively, it may be possible to drill out the shoe track with another casing bit on the next casing string. The drillable bit ought to reach the objective depth in one run; therefore, rock strength and abrasiveness should be studied before deciding the footage the drillable bit can drill. Figure CD-3 and Table CD-1 provide some general guidelines on typical rock types (hardness) drillable with non-retrievable casing drill bits. For applications outside the acceptable zone, the required footage to be drilled must be analyzed further. Of course, for applications with softer rocks, simpler designs can be used. It is worth mentioning that in cases where the CwD is the last section of the well (no drill-out required), conventional bits can be used.

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Figure CD-2: Drillable casing bits. Courtesy Weatherford & Schlumberger.

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Table CD-1: Lithology and rock strength for non-retrievable CwD

Figure CD-3: Application range for casing drillable bits. Device used for CwD

Very low strength

< 4,000 psi

Gumbo, shales, soft shales, claystones, unconsolidated (very soft sands)

Low strength

4,000 8,000 psi

chalk, shaley and clayey sandstones, claystones, shales, (soft) evaporites, soft silicones

Medium strength

8,000 16,000 psi

Conglomerates, sandy and chalky limestones, marls, medium-medium hard sandstones, hard shales

High strength

16,000 32,000 psi

Hard stringers, hard dolomites, crystalline limestones, brittle (hard) shales, hard sandstones

Very high

> 32,000 psi

Very fine, tight sandstones, chert, quartzite, igneous and metamorphic rocks, hard siltstones

Description

Application

Waterbushing Crossover

It is simply a sub with a drillpipe connection (box) up and a casing connection (pin) down that is positioned between the top drive and the casing string.

• Short casing strings (less than 500 ft); • Very large casing string, i.e., 20 in. or larger; • Jobs where reducing flat time is not the primary consideration, e.g., major hole problems.

CwD Spear

CwD spear replaces the conventional threaded crossover, reducing connection time and ultimately making the worksite safer. The tool is simple to operate and is field-serviceable. CwD spear is connected directly to the top drive.

The string can be rotated and circulated at the same time, making the modified CwD spear an ideal upgrade to the type used for running casing. The spear can be used to replace conventional casing-running tools such as spider-type elevators and casing fill-up tool.

Internal Casing Drive Tool (ICDT)

ICDT operates in the same way as the CwD spear. The main difference between the tools is the internal gripping slip area. The ICDT slips are significantly larger and have a superior carrying capacity.

ICDT can replace the spider elevator and fill-up tool. It also provides a means of simultaneous circulation, reciprocation and rotation.

Top-Drive CwD System

The automated casing-running system eliminates the derrick Internal tools grab the casing man and allows for safe rotation from inside and external tools and reciprocation of the casing from outside. string, making drilling with casing possible with high efficiency.

Figure CD-4: CwD surface drive system. Courtesy Weatherford.

When drilling with casing, flow rate is considerably less than what is used for a conventionally drilled interval of equivalent hole size. This is necessary due to the reduced annular clearance and to achieve an optimum ECD. In soft “top-hole”

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formations, the bit is jetted for a large total flow area (TFA) as the best drilling performance is achieved by maximizing flow rate. In more competent formations, the bit is jetted to achieve the same hydraulic horsepower or as close as can be

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Rubber liner with straight flutes

Venting holes

Figure CD-5: Rotating centralizers for CwD - hardfaced and non-hardfaced. Courtesy Schlumberger.

Figure CD-6: Non-rotating centralizers for CwD. Courtesy Weatherford.

obtained to conventional best practice without running jets smaller than 12/32.

acts as a bearing to eliminate casing wear as well as to reduce friction and potential damage. This type of centralizer has been shown to effectively reduce the amount of torque required when drilling with casing. But because it reduces the mechanical contact with the wellbore wall, it must be used with caution in wells that depend on the wellbore strengthening of the plastering effect.

Drilling parameters when drilling with a CwD system are similar to what are used to drilling a convention interval with a PDC bit cutting the same size hole (both in terms of WOB and RPM). The casing string is commonly used to turn the bit in excess of 100 rpm. In order to achieve rate of penetration (ROP) that is equivalent to conventional operations, it is necessary to provide the same amount of energy towards the destruction of rock both mechanically and hydraulically.

Enhanced rig equipment - surface drive systems

When drilling conventionally, the drillstring is connected to the top drive by a crossover sub. A crossover from casing to the top drive is not a standard piece of rig equipment and is probably not available on the rig unless it has been pre-ordered. Applications engineers will ensure that the crossover is correctly specified to support the string weight, transmit rotary torque and seal against hydraulic pressure. Non-retrievable CwD can be accomplished using several methods to rotate the casing string (Figure CD-4).

CwD centralizers

Spray metal technology can also be used to build centralizers, stabilizers and wear bands directly onto casing for drilling (see Figure CD-7). The resulting blades, ribs and bands are at least as wear-resistant as steel.

CwD connections, torque rings and wear bands/ sleeves

Casing is designed to be run, not to be drilled with. Hence, certain modifications might be necessary to allow for drilling with standard casing. These include: • Premium CwD connections; • Torque rings for buttress connections in absence of special CwD connections to create a positive shouldered makeup; • Wear bands/sleeves to protect the casing/couplings from wear as well as from abrasive environments.

In most vertical surface or intermediate CwD applications, centralization is not a concern. If the CwD or liner drilling system is deployed in a deviated well, it is critical that the centralizers installed onto the casing are designed to withstand the harsh drilling environment. One strategy that has been routinely employed is to attach a solid body hydro-formed centralizer to the body of the casing by crimping it in place. The crimping process ensures the centralizer remains in place both axially and torsionally and also ensures the contact necessary between the casing and wellbore wall for the plastering effect to occur. Another method of centralizing casing is using a non-rotating centralizer with an internal rubber lining (see Figure CD6). The centralizer has a solid body, and the rubber lining

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Figure CD-7: Sprayed-on centralizers/stabilizers for CwD. Courtesy Weatherford.

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the plastering of drill cuttings, the true mechanism is not yet well understood. Pipe size and annular clearance have been reported as the critical parameters for increasing wellbore strength. The other factors include the casing’s contact with the wellbore wall, rotary speed, mud type, time, stress anisotropy, mud hydraulics, thermal effects and penetration rate.

Operations CwD connections. Courtesy Tenaris.

CwD connections. Courtesy U.S. Steel.

Wear bands/Sleeves. Courtesy TESCO.

Torque rings. Courtesy Premiere. Figure CD-8: CwD accessories.

Plastering effect

In addition to increasing drilling performance, CwD technology has also shown strong potential for drilling in weak sections to mitigate lost circulation and wellbore instability problems and reduce NPT in drilling operations, specifically in narrow pore-fracture pressure sedimentary basins and deep offshore applications. It offers hydraulic improvements and the ability to plaster cuttings to the wellbore wall, which may restore the wellbore’s hoop stress by wedging the created fractures and/or by increasing the fracture propagation pressure. Additionally, because of the larger pipe-to-annulus size ratio of CwD compared to conventional drilling, the casing rotation forms a better mud cake (see Figure CD-9). Although the increased wellbore containment is explained by

IADC Drilling Manual

Non-retrievable CwD systems are made up in the rotary table in similar fashion to how casing connection and accessories are installed into a standard shoe track. The main differences will be in the connection type and the amount of torque used to make-up all connections in the string (should be 20% higher than the maximum expected torque required to drill to TD). This may require power tongs. Floats are installed in the string that are rated for the expected circulating hours that are required to reach TD and cement the interval. The placement of the floats is as per the operators requirements on the amount of shoe track desired. Any centralization installed on the string is recommended to be done prior to the arrival of the casing to the rig. The casing is tripped into the hole using the same methods as conventional. It is recommended to fill the string at regular intervals during the trip. After reaching bottom, drilling can proceed according to the parameters specific to the bit used and optimized to the specific application. When making connections, time in slips should be minimized as much as possible. If any positive indication of flow is detected, the well can be controlled using the casing rams sized to the casing string, in the same way well control is implemented when running casing. After reaching TD, the well should be circulated till shakers are clean prior to rigging up for cement. Cementing operations are similar to conventional operations.

Why drill with a non-retrievable CwD system?

Advantages include: • Increased ROP in soft formations (eliminate need for control drilling due to improved hole cleaning); • Minimize rig time and floor operations by eliminating dedicated casing run; • Utilize the benefits of plastering effect to: • Reduce or eliminate the risk of lost circulation; • Reduce differential sticking while drilling depleted sands; • Extend casing point to eliminate casing/liner string; • Reduced overall well costs by reduction of time on well. One key advantage of CwD with a non-retrievable system involves the ability to take advantage of the high ROP experienced while drilling large outer diameter (OD) vertical top-hole sections. Drilling these top-hole sections has become an increasingly common practice for offshore wells in multiple locations.

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Figure CD-9: A and B describe two plausible mechanisms of plastering effect to increase wellbore integrity. Courtesy Weatherford.

Typical non-retrievable CwD problems

• High torque: Because the casing is larger in diameter and heavier than drillpipe, the torque required to rotate the pipe to TD is often much greater; • Hydraulics: As the casing is larger in diameter than drillpipe, the annulus between the casing and the drilled hole is much smaller; therefore, the hydraulics must be redesigned. Even with optimal mud rheology and reduced flow, it is very difficult to plan for CwD intervals deeper than 15,000 ft (5,000 m) due to higher ECDs that become increasingly hard to manage at greater depths; • Tripping casing: The bit must make the minimum casing depth in a single run to be successful. If the bit is unable to drill the planned footage to an acceptable casing point, the only option is to trip the casing to replace the bit.

Retrievable casing while drilling

Retrievable CwD systems provide all the advantages of a non-retrievable system but add the flexibility to incorporate directional and measuring/logging while drilling (M/LWD) tools to both steer and log the well while drilling. Whereas a non-retrievable system must guarantee that the entire interval be drilled in a single run, retrievable systems allow multiple trips to replace the drill bit or any other failed logging or directional component of the BHA. A retrievable system also assures that the casing can be run to TD, and it captures many of the savings that have been proven when CwD vertical wells. The same casing-running systems, centralizers and connections used with non-retrievable CwD are also used for the retrievable systems. Retrievable CwD systems use a special coupling with an internal profile installed above the last joint in the casing string.

IADC Drilling Manual

The full retrievable CwD will consist of the individual components listed below and shown in Figure CD-10. Also required will be the casing accessories to provide centralization for cementing and stabilization for drilling.

Locking assembly

The locking assembly must facilitate several requirements in order for the remainder of the assembly to effectively drill with casing. The assembly must allow: • Hydraulic isolation: All drilling fluid pumped from surface must be directed from the casing into the locking assembly, into the drillpipe BHA and ultimately through the bit below; • Crossover from the casing to drillpipe connection: Engaging the locking assembly in the profile nipple provides a downward-facing drillpipe connection used to connect the drillpipe BHA to the casing used to drive the string from surface; • Weight-on-bit transfer: The locking mechanism must allow weight on bit to be transferred from surface to the cutting structure; • Torsional transfer: The locking mechanism must transfer the torque that allows the drillpipe BHA to rotate at the same RPM as the string is turning at surface; • BHA retrieval: The locking assembly must be able to be used in tandem with drillpipe, wireline or hydraulic retrieval tools to convey the drillpipe BHA through the internal diameter (ID) of the casing string on multiple trips.

Internal duplex stabilizer

The internal duplex stabilizer is used to stabilize the drillpipe BHA inside the casing shoe joint below the locking assembly. This configuration provides lateral stabilization and ensures concentricity of the drillpipe BHA as it exits the casing shoe joint.

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Figure CD-10: CwD BHA with conventional positive displacement motor. Courtesy Schlumberger.

Underreamer

As all components in the drillstring BHA must be smaller than the drift of the casing to allow conveyance in and out of the hole, an underreamer must be used to open hole larger than the casing’s outer diameter. With respect to hydraulics, it is most common to underream the hole to the same size that would be used to drill the interval conventionally. For instance, when drilling an interval with 9 5⁄8-in casing, a 12 ¼-in underreamer would be used in tandem with an 8 ½-in pilot bit.

cleaning while drilling through offshore top-hole intervals has eliminated the standard practice of control drilling and allowed wells to be drilled significantly faster with casing than with conventional drillstrings. Directional drilling with smaller casing may sacrifice some drilling efficiency due to the requirement to use smaller motors.

Successful directional CwD operations require more than simply having directional tools available that can be run below the casing. BHA response may be quite different when CwD as compared to drilling with conventional systems. Extensive pre-project planning must be completed, including hydraulics analysis, torque-and-drag modeling, casing connection analysis and selection, and BHA design. Wellsite implementation and successful execution of operational procedures at the wellsite are critical to success. Figure CD-11: Tool face change when CwD

Retrievable CwD BHAs are primarily arranged into three categories: • Directional with conventional positive displacement motor (PDM); • Directional with rotary steerable systems; • Short stick-out assemblies (tangents and loss zones). CwD with a conventional PDM is similar to drilling with a conventional assembly. The motor orientations are extremely easy when drilling with the casing because there is very little twist between the surface and motor. For example, Figure CD-11 shows the toolface for about five minutes during which time the motor stalled, the drillstring was picked up and the motor restarted. The tool face changed less than 10° when the string was picked up and returned to its original position when drilling resumed. For larger sizes of casing, no loss of efficiency occurs while drilling with the steerable tools below the casing, allowing the operator to take full advantage of the faster tripping and trouble avoidance benefits provided by CwD. Improved hole

IADC Drilling Manual

Rotary steerable-based retrievable CwD assemblies, as shown in Figure CD-12, provide a unique synergy by having both the drilling hazard mitigation benefits of the plastering effect and superior hole cleaning by allowing the assembly to be steered with continuous rotation. CwD assemblies with conventional PDMs must sacrifice these benefits over the footage where steering is required. The drilling hazard mitigation aspects of CwD only occur after the formation drilled comes into contact with the casing component of the drillstring. For this reason, it is critical to manage the length of drillpipe that projects below the casing shoe or stick-out. In highly unstable formations or where large amounts of fluids are lost to the formation, it is critical to begin applying the plastering effect as soon as possible. In these circumstances, a short stick-out BHA, as shown in Figure CD-13, is a preferred design hold angle while drilling through difficult formations. It can also be used while drilling vertical intervals where more than one bit trip is required to reach TD.

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Figure CD-12: CwD BHA with rotary steerable system. Courtesy Schlumberger.

Additional advantages specific to a retrievable system include: • Capability of active directional control [steerable motor or rotary steerable system (RSS) in BHA]; • Ability to run logging tools in BHA; • Contingency operations to run Figure CD-13: CwD with short stick-out BHA. Courtesy Schlumberger. subsequent BHAs; • Eliminate open-hole tripping of BHA and risks associated with stuck pipe/LIH. Operations The same advantages can be obtained by the user whethRetrievable casing drilling BHAs are made up in two sections. er running a retrievable or non-retrievable casing system, First the conventional BHA is picked up and run in hole. Sechowever, the retrievable CwD system further enables the ondly, the shoe joint is picked up, and the BHA is made up to capability to run any choice of BHA components (directional the first joint of casing. The casing is then tripped into the hole and/or M/LWD). using the same methods as conventional. It is recommended to fill the string at regular intervals during the trip. After reaching bottom, drilling can proceed according to the parameters Typical retrievable CwD problems specific to the BHA design used and optimized to the specific • High torque: Because the casing is larger [in terms of application. When making connections, the amount of time outside diameter (OD)] and heavier than drillpipe, the the casing is in slips should be minimized as much as possitorque required to rotate the pipe to TD is often much ble. If any positive indication of flow is detected while drilling, greater. This is especially true in directional wells; the well can be controlled using the casing rams sized to the • Hydraulics: As the casing is larger (in terms of OD) and casing string, in the same way well control is implemented the annulus between the casing and the drilled hole is when running casing. If any positive indication of flow is demuch smaller, the hydraulics must be redesigned. Even tected while conducting BHA setting or retrieval operations, with optimum mud rheology and reduced flow, it is very a casing circulating tool is used along with the casing rams to difficult to plan for CwD intervals deeper than 15,000 ft secure the well. After reaching TD, the well should be circu(5,000 m) due to higher ECDs that become increasingly lated until shakers are clean prior to rigging up for cement. As hard to manage at greater depths; cementing floats are not present in the string, a cement plug • Stick-out management: The benefits of CwD do not is pumped into a landing profile to cement the interval. occur until the casing itself reaches the formations of concern. For example, if the directional/logging BHA extends 120 ft past the casing shoe and the ROP is 40 ft/ Why drill with a retrievable CwD system? hr, three hours of drilling are required before any benefit Similar to non-retrievable casing drilling systems, advantagof plastering effect (reduction in losses, for example) es include: may be realized; • Increased ROP in soft formations (eliminate need for • Fatigue management: The fatigue performance of the control drilling due to improved hole cleaning); liner pipe and connections is well understood. The safe • Minimize rig time and floor operations by eliminating number of total revolutions allowed for any given dedicated casing run; application is calculated in pre-job analysis, and total • Utilize the benefits of plastering effect to: revolutions are also monitored during job site execution • Reduce or eliminate the risk of lost circulation; to ensure the liner can be used to safely drill to TD. • Reduce differential sticking while drilling depleted Fatigue management is most critical when high doglegs sands; are predicted to cause high levels of reversing stresses • Extend casing point to eliminate casing/liner string; on the liner and its connections. The table below shows • Reduced overall well costs by reduction of time on well.

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CASING WHILE DRILLING the doglegs limits below which the onset of accumulated fatigue damage to the casing/liner and connections is not of concern. Casing Size

Dogleg to initiate fatigue

4 ½ in.

8°

7 in.

5°

9 5⁄8 in.

3°

13 3⁄8 in.

1.5°

Wells are commonly drilled with higher doglegs than shown in the table above; however, advanced fatigue analysis should be performed to ensure the accumulated fatigue is within safe limits.

Liner drilling

Numerous operators have utilized the benefits of CwD to successfully drill through challenging zones, saving both time and money through increased safety and efficiency, reduced NPT and the inherent ability to keep every ft drilled. Liner drilling, which retains these advantages, must be used in applications where CwD is not employable because of hydraulic, torque or well construction limitations. In cases of drilling the liner through incompetent formations, the wellbore strengthening provided by rotating the liner casing against the open hole is anticipated to assist in the reduction of losses and hole sloughing, the widening of the pore pressure-fracture gradient (PP-FG) windows and the potential improvement of the section’s formation leak-off test (LOT), any of which may permit deeper casing points to be realized as opposed to drilling these sections conventionally. In some cases of drilling deep wells, where the ability to deploy CwD is limited by the loading of the casing connections near the surface, a liner drilling system can be adopted because drillpipe is situated from the top drive to the liner top. This allows the transfer of higher surface loads to the drillstring, as the peak loading is seen on the drillpipe at the rig floor. The maximum load applied to the liner string is at the casing connection just below the liner top and is limited to the torsional and axial loads required to rotate and convey the liner pipe alone, as all drilling loads are transmitted to the BHA via an inner string. When liner drilling operations are applied in reservoir or intervals with hydrocarbon bearing formations, well control is of paramount importance. When drilling with the liner, drillpipe will always be positioned across the BOP and allows for well control operations using the same procedures and equipment as a conventional drilling scenario. Objectives for implementing liner drilling systems depend

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on the benefits necessary to complete the section as quickly, safely and efficiently as possible. On the rig floor, safety and efficiency of casing running and drilling operations are improved by the use of the automated casing-running system. Below the rotary table, the benefit of always having the drillstring across open hole, even while tripping BHAs, can assist in reducing NPT associated with open-hole problems, such as sloughing, influx, losses, and surge and swab. In many cases, improved drilling windows help to mitigate the above issues and potentially allow for casing seats to be pushed deeper, reducing the number of casing or liner strings required to reach TD. Due to the fact that during liner drilling operations are most likely to be applied when drilling into the reservoir, well control is of paramount importance. When drilling with the liner, drillpipe is always positioned across the BOP and in such allows for well control operations without restrictions. This is a considerable advantage when compared to normal casing drilling operations, where the casing is positioned across the BOP and might require particular BOP configurations.

Non-retrievable liner drilling

Non-retrievable liner drilling technology enables drilling the liner into the well across depleted or loss zones or unstable formations, setting the hanger and packer, and cementing in a single trip. Figure CD-14 shows the non-retrievable liner drilling system and the components of the assembly.

Non-retrievable liner drilling/setting sequence

The installation sequence shows a premium liner drilling system complete with liner top packer, liner hanger, liner wiper plug and drill bit (see Figure CD-15). The operation is set up to activate the system from a single setting ball, cement the liner, set the packer and retrieve the running tools. The time and complexity of the setting sequence are consistent with that of a conventional liner system. A top-drive CwD system is used to trip the liner into the hole with the drillable casing bit on bottom. The string is stabilized using casing stabilization capable of surviving the drilling process. The interval is drilled from surface, much as in a conventional drilling operation. Attention is paid to managing the narrow annulus between the liner and parent casing as well as monitoring torque and vibration of the assembly in open hole. After the target depth of the interval has been achieved, the liner hanger is set and cementation begins. The cementation process ends with the packer being set and the top of cement being reversed off the liner top. The running tool is then tripped out of hole. If for any reason the target depth of the interval is not reached, the liner must be tripped completely out of hole in order to replace the drillable casing bit. In addition, as no

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Figure CD-14: Non-retrievable liner drilling. Courtesy Weatherford.

Figure CD-15: Non-retrievable liner drilling setting sequence. Courtesy Weatherford.

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Figure CD-16: Retrievable liner drilling. Courtesy Schlumberger.

active directional control is possible, non-retrievable liner drilling assemblies are typically reserved for vertical applications or short tangent sections.

Why drill with a non-retrievable liner drilling system?

Advantages include: • Increased ROP in soft formations (eliminate need for control drilling due to improved hole cleaning); • Minimize rig time and floor operations by eliminating dedicated casing run; • Utilize the benefits of plastering effect to: • Reduce or eliminate the risk of lost circulation; • Reduce differential sticking while drilling depleted sands; • Extend casing point to eliminate casing/liner string; • Reduced overall well costs by reduction of time on well. A key advantage of drilling with non-directional liner drilling systems is the mitigation of drilling hazards through the plastering effect and the subsequent reduction in associated rig time due to lost circulation and stuck pipe events that occur when drilling unstable or depleted zones with conventional methods.

Typical problems with a non-retrievable liner drilling system

• High torque: Though the liner is larger in diameter and heavier than drillpipe, the torque required to rotate the pipe to TD is greater, but often not significantly greater than a conventional BHA. This is of course dependent on liner length and wellbore geometry, but with liner drilling systems, torque is far less limiting that in CwD systems, as the large diameter tubular extends only a fraction of the distance from TD to surface. As the drilling torque in most liner drilling systems runs through the liner connections, the connection must be capable of handling this safely; • Hydraulics: The annulus between the liner and the drilled hole is much smaller, as the liner is much larger in diameter than drillpipe. This geometrical change requires careful consideration when planning the drilling hydraulics. The hydraulics are even different from what is seen when CwD; because the liner does not extend to the surface, superior hole cleaning above the liner top may be difficult to achieve. Careful consideration must be taken when planning the mud rheology and flow rates to balance the generation of high ECDs with

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sufficient cuttings-carrying capability above the liner. This is critical to manage and becomes increasingly more difficult when the liner top is set at higher inclinations; • Tripping liner: The bit must make the minimum liner depth in a single run to be successful. If the bit is unable to drill the planned footage to reach an acceptable liner point, the only option is to trip the liner to replace the bit.

Retrievable liner drilling

Retrievable liner drilling technology enables the liner to be drilled directionally across depleted or loss zones or unstable formations while simultaneously logging the well. As the inner string and BHA are designed to drift through the liner, the operator has the ability to retrieve the BHA to the surface at will. While replacing the BHA, the liner is temporarily parked in tension anywhere in the wellbore. Additionally, if the liner becomes stuck, the BHA can still be pulled safely to surface, leaving a usable wellbore through which to drill the next section. After reaching TD, the liner is permanently hung, and the drill/logging BHA is retrieved to surface before running the cementing assembly in hole on a second trip. Figure CD-16 shows the component of the retrievable liner drilling system assembly. The drilling assembly is composed of six main components: • Drilling BHA (below liner shoe); • Inner string (including BHA below liner shoe); • Liner string; • Liner drilling tool; • Liner top equipment. The drilling BHA consists of the bit, directional tools, MWD tools, the underreamer and any other BHA components that are positioned below the liner shoe. The drilling BHA provides all functions of steering, measurement and hole enlargement required to achieve the goals of the planned liner interval. The inner string in this application is used to transmit the torque and weight on bit from the liner-running tool to the drilling BHA. The liner string in this application is removed from the

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torque path between the liner drilling tool and the drilling BHA. The liner string is conveyed from the start of drilling to the end of the planned interval with minimum torque applied across its length. The liner drilling tool is used to cross over from the liner string to the drillpipe. It transmits torque and WOB from surface through the liner and to the BHA below. The liner-running tool is also used to convey the liner top packer required to isolate the drilled interval after drilling is complete. The liner equipment includes the liner hanger and the polished bore receptacle (PBR). A liner top packer is introduced during the cementing run after the retrievable BHA has been retrieved. The liner top packer isolates the drilled-in liner from the parent casing string and is activated immediately following cementing operations.

Why drill with a retrievable liner drilling system?

Similar to non-retrievable liner drilling systems, advantages include: • Increased ROP in soft formations (eliminate need for control drilling due to improved hole cleaning); • Minimize rig time and floor operations by eliminating dedicated casing run; • Utilize the benefits of plastering effect to: • Reduce or eliminate the risk of lost circulation; • Reduce differential sticking while drilling depleted sands; • Extend casing point to eliminate casing/liner string; • Reduced overall well costs by reduction of time on well. Additional advantages specific to a retrievable system include: • Capability of active directional control (steerable motor or RSS in BHA); • Ability to run logging tools in BHA; • Contingency operations to run subsequent BHAs; • Eliminate open-hole tripping of BHA and risks associated with stuck pipe/LIH. The same advantages can be obtained by the user whether running a retrievable or non-retrievable casing system; however, the retrievable casing while drilling system further enables the capability to run any choice of BHA components (directional and/or M/LWD).

Typical problems with retrievable liner drilling systems

• High torque: Though the liner is larger in diameter and heavier than drillpipe, the torque required to rotate the pipe to TD is greater, but often not significantly greater than a conventional BHA. This is of course dependent on liner length and wellbore geometry, but with liner while

IADC Drilling Manual

drilling systems, torque is far less limiting that in casing while drilling systems as the large diameter tubular extends only a fraction of the distance from TD to surface. As the drilling torque in most liner drilling systems runs through the liner connections, the connection must be capable of handling this safely; • Hydraulics: The annulus between the liner and the drilled hole is much smaller, as the liner is much larger in diameter than drillpipe. This geometrical change requires careful consideration when planning the drilling hydraulics. The hydraulics are even different from what is seen when casing while drilling; because the liner does not extend to the surface, superior hole cleaning above the liner top may be difficult to achieve. Careful consideration must be taken when planning the mud rheology and flow rates to balance the generation of high ECDs with sufficient cuttings-carrying capability above the liner. This is critical to manage and becomes increasingly more difficult when the liner top is set at higher inclinations. • Stick-out management: The benefits of plastering effect do not occur until the liner shoe reaches the formations of concern. For example, if the directional/logging BHA extends 120 ft past the casing shoe and the ROP is 40 ft/ hr, three hours of drilling are required before any benefit (reduction in losses, for example) may be realized. • Fatigue management: The fatigue performance of the liner pipe and connections is well understood. The safe number of total revolutions allowed for any given application is calculated in pre-job analysis and total revolutions are also monitored during jobsite execution to ensure the liner can be used to safely drill to TD. Fatigue management is most critical when high doglegs are predicted to cause high levels of reversing stresses on the liner and its connections. The table below shows the doglegs limits below which the onset of accumulated fatigue damage to the casing/liner and connections is not of concern. Wells are commonly drilled with higher doglegs than shown in the table above; however, advanced fatigue analysis should be performed to ensure the accumulated fatigue is within safe limits. Casing Size

Dogleg to initiate fatigue

4 ½ in.

8°

7 in.

5°

9 5⁄8 in.

3°

13 3⁄8 in.

1.5°

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Safety and the environment

The CwD process offers significant improvements related to safety and the environment relative to conventional casing-running operations. As for safety, the floor becomes crowded on many rigs when the conventional casing-running equipment is rigged up while drillpipe is racked in the derrick. The casing tongs are often operated from scaffolding set up on the floor as a work platform. A workman is positioned in the derrick to help align the casing joint in the elevators. The overall result is an increased potential for falls from elevated work positions as well as for injuries from being caught between pieces of equipment as the casing is picked up, made up and run. Due to the reduced flow and standpipe pressure requirements of the CwD process, the rig is able to use significantly less fuel during the drilling process. This efficiency gain results in a net fuel saving that is not only a significant cost savings, but also an environmental benefit that reduces the carbon footprint of the drilling process.

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Conclusion

The CwD and liner drilling processes are currently being used by the industry to improve drilling efficiency in some applications and to provide drilling hazard mitigation in others. These processes must be implemented with careful attention to ensure that the torque required to reach TD as well as any fatigue accumulated during drilling does not affect the ability of the casing to secure the wellbore after it is cemented in place. Standard practices used with conventional drilling must be reevaluated in the context of the narrow annulus and adjusted where necessary in order to optimize drilling performance. The current toolbox gives the industry the ability to drill nearly any interval with either a casing or liner drilling solution. Because of its increased ROP and superior hole cleaning, CwD is fast becoming the standard approach to drilling tophole intervals, both vertical and directional, as the process simplifies operations by eliminating the need to run casing after reaching TD. As more wells are drilled in increasingly unstable or depleted formations, the technology becomes more valuable, as it provides economical and technical solutions for achieving drilling objectives. As the understanding of the mechanism for the plastering effect of CwD becomes better understood, the shift from anticipating a benefit to predicting the benefit as part of pre-planning the well will continue to expand the value of this emerging technology.

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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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CEMENTING

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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. AUTHORS AND REVIEWERS Ron Sweatman, Baker Hughes Kate H. Baker, Consultant Anthony Badalamenti, Consultant Glen Benge, Consultant Louis Bone, Halliburton Ramy Eid, Repsol Barbara Kutchko, U.S. DOE K.K. La Fleur, Consultant George Morgan, Derrick Equipment Co. Dan Mueller, ConocoPhillips Sam Pickett, Chesapeake Alfredo Sanchez, Top-Co David Stiles, ExxonMobil

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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: 978-0-9906220-5-5

Printed in the United States of America.

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Contents

CEMENTING

Preface..............................................................................CE-1 Cementing and safety..................................................CE-1 Personal safety.........................................................CE-1 JSA topics to consider............................................CE-1 Operational risk management.............................CE-1 Introduction ....................................................................CE-1 Relevancy of cementing for the drilling process.. CE-2 Well cementing purposes ......................................... CE-2 How cement works in well applications.......... CE-3 Types of cementing jobs and reasons for and types of cementing........................................................................ CE-3 Primary jobs............................................................. CE-3 Setting casing strings ......................................... CE-3 Squeeze cementing................................................ CE-3 Plug cementing....................................................... CE-5 Lost circulation cement squeezes and plugs ................................................................. CE-6 Cementing through the bit..........................................CE-7 Preparing the well and wellsite for cementing .................................................................CE-7 Pre-job meeting ..................................................... CE-8 Preparing the well for cementing...................... CE-8 Hole conditioning with casing on bottom....... CE-8 Rig personnel support of cementing operations........................................... CE-8 Rigging up and pressure testing treatment lines........................................................ CE-9 Components of a high-pressure line................ CE-9 Job design, pumping and displacing cement....................................................... CE-10 Estimating job volumes (cement, mix water, spacers, displacement)...................................... CE-11

IADC Drilling Manual

Estimating cement volumes.............................. CE-12 Hole size determination..................................... CE-12 Area experience and excess cement.............. CE-12 Addressing lost circulation in cement job design............................................................... CE-13 Mix water volumes ............................................. CE-13 Spacer volumes..................................................... CE-13 Water sources and supply................................. CE-13 Estimating displacement volumes................... CE-14 Hole-size determination Job time................................................................... CE-14 Pump rates and pressures................................. CE-14 Wait on cement (WOC) time and post-job rig operations .................................................................... CE-14 Cements and cement additives ............................. CE-14 Conditions and required properties................ CE-14 Cement additives................................................. CE-15 Cement slurry properties................................... CE-15 Cementing strings and associated hardware, including casing running tools................................ CE-16 Casing cementing string hardware................. CE-16 Guides & floating equipment............................ CE-18 Liner cementing tools..........................................CE-20 Casing running tools ..........................................CE-20 Conventional equipment/tools........................CE-21 Next-generation tools.........................................CE-21 Mechanized equipment......................................CE-23 Cement evaluation ....................................................CE-23 Outlook ......................................................................... CE-24

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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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CEMENTING

Preface

The Cementing Chapter contains information on the operational aspects and importance of cementing practices as they relate to drilling rigs. This chapter is intended as resource to help crews conduct safe and effective cementing operations, enabling wells to be drilled, completed, and operated more safely and efficiently.

Cementing and safety

Regardless of their location or industry, nearly all safety professionals contend that “the potential to cause harm” is what defines a safety hazard. In the oil and gas industry, a safety hazard often requires a more complete definition: a condition or activity that, if left unattended or uncontrolled, has the potential to injure workers, harm the environment or threaten assets. Whether on land or offshore, the cementing process includes the same basic steps: • Mobilize resources: equipment and materials; • Access the well: rig up the equipment; • Perform the job: cement the well; • Rig down equipment; • Demobilize resources (equipment, materials, personnel).

and

Cementing is part of the larger drilling process, and drilling is a part of the overall well construction process. These processes present safety hazards, of which there are two types: personal safety hazards and process safety hazards. The discipline of personal safety provides methods that enable personnel to work in the safest manner possible. Process safety, or operational risk management, includes procedures to mitigate operational risks that have the potential to injure workers and damage material, physical assets and the environment.

Personal safety

Job Safety Analysis (JSA) is widely used by contractors, operators and service companies to identify and mitigate safety hazards. By co-conducting preliminary job reviews, employees and managers can gain a shared ownership in a safety program that reduces and helps control risk.

JSA topics to consider

• Driving safety: traveling to land location or offshore load out point; • Personal protection Equipment: hard hats, safety glasses, gloves, etc; • Lock out tag out: equipment maintenance; • Rig-up and rig-down procedures and assignments;

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• Hand tools: equipment maintenance; • Work permit: hot work, high pressure, noise; • Confined space: working in pits or tanks; • Working at heights: rigging up equipment, iron, plug containers; • Dropped objects: hand tools, service iron; • Lifting and handling: iron, chemicals, related materials; • Stop Work authority: when in doubt, STOP; • Slips, trips and falls; • Pressurized equipment; • Chemical handling: movement, mixing of fluids (e.g., drilling mud, cement).

Operational risk management

A sound operational risk management program should enable analysis of operational components: equipment design and functionality, and operating and maintenance procedures. The resulting assessments will help mitigate the risk associated with job related tasks and help wellsite personnel guard against the uncontrolled release of hazardous materials or energy that could harm workers, property and the environment. Prior to conducting an operation, the answers to several questions should be obtained: • Have well conditions changed between “designed for and as drilled”? • Can the equipment being used perform as required? • Has the equipment been properly maintained and readied for service? • Do the personnel involved understand the cementing procedure and can it be safely conducted? • Is the well ready to be cemented? Operators and service companies have HSE, (health safety and environmental) guidelines that pertain to personal and process safety. These guidelines should be known, discussed and followed. Maintaining a disciplined process safety culture increases personnel health, environmental sustainability, and asset integrity.

Introduction

The process of cementing oil and gas wells requires close cooperation between the well operator, the drilling contractor, the cementing service company and the drilling fluids company. This section of the IADC Drilling Manual outlines the relevant cementing process concepts as they relate to establishing zonal isolation and provides insight into the efforts made by the drilling contractor’s personnel to achieve this goal.

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CEMENTING

Relevancy of cementing for the drilling process

Safely and efficiently establishing zonal isolation through cementing is one of the most essential operations in well construction. More recently, in granting approval for drilling permits and for progressive stages of the drilling process, oil and gas regulators have placed increased emphasis on the importance cementing plans and their execution. In reaction to this, the API/IADC Joint Industry Task Force recognized cementing as a key part of a safe drilling process and formally proposed this to the U.S. Department of the Interior (DOI). As a result, the DOI’s Bureau of Safety and Environmental Enforcement (BSEE) adopted the proposed safe drilling process by incorporating API RP 65 Part 2 and later API Standard 65 Part 2 (65-2) into a new federal regulation. API Standard 65-2 includes best drilling practices to improve primary cementing. BSEE now requires that API Standard 65-2 practices for well cementing be followed as a condition for receiving a permit to drill in waters and on lands that are held by the federal government. Regulating bodies in other parts of the world are now adopting or considering similar requirements. New API publications and revised editions strongly advocate the cementing process as a primary means to safe drilling. The API RP 96 publication entitled “Deepwater Well Design and Construction” makes many references to API Standard 65-2 practices, making it a “normative” reference, (e.g., to comply with RP 96 practices, operators must also comply with practices in API Standard 65-2).

Well cementing purposes

The principal reason for cementing in well construction is to fill the annular space between the casing and the wellbore with cement over specified formations or depth intervals. A cemented annulus provides several operational advantages: structural support for casing strings, corrosion prevention, and a barrier to prevent annular flow of oil, gas or water from one subsurface zone to another or to the surface. The principles and processes for establishing and maintaining cement as a barrier are central to providing well integrity. Establishing a barrier is especially important when the wellbore is constructed across certain intervals: • Fresh-water aquifers that hold usable sources of water; • Potential flow zones: permeable formations or those that can be fractured; • Hydrocarbon-bearing zones; • Between production zones that might become drawn down or over pressured relative to one another during the life of a field;

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• Across naturally occurring pore pressure ramps to prevent interzonal flow. Placing cement across and at sufficient height to be above potential flow zones should be considered, as it will ensure these areas of the well are isolated and the annular cement is providing a barrier. It is very important to preserve isolation between subsurface sections that have, or are expected to develop, different pressure gradients. This may require proper placement of cement across impermeable zones to ensure the wellbore does not become a leak point through the natural pressure barrier. A properly cemented annulus prevents formation fluids from flowing into the annular space. Formation brines are often highly corrosive to the steel used in tubulars. Accordingly, preventing such fluid movement will help protect casing from corrosion. A properly cemented annulus can also provide the structural integrity to endure certain stresses: • Axial loads arising from the suspended weight of subsequent casing strings, liners, BOPs or marine risers; • Axial loads from thermal expansion and contraction during drilling operations that may result in buckling or extensional yield; • Subsidence-induced strains associated with hydrocarbon extraction; • Side loads arising from mobile formations or geologic faults that may result in shear failure; • Stresses associated with completion operations such as hydraulic fracturing, thermal stresses anticipated during production and injection operations or unanticipated drilling and production operations issues that may result in burst or collapse failure. Cement may also be placed in an open-hole for several reasons: • Plugging back for abandonment of a hole section to achieve zonal isolation and prevent flow to and from an abandoned borehole; • Plugging back to sidetrack a well in which the cement plug must also provide enough integrity to enable the bit and bottomhole assembly to establish the new wellbore trajectory; • Squeezing or pumping cement into the formation exposed in the open-hole section making remediation necessary, lost circulation, to repair leaks, or strengthen the exposed casing shoe. Cement is also used in applications presented in other sections of this chapter.

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How cement works in well applications

Because cement can be mixed with water to create a slurry, it can be circulated into the well with pumps and directed to the required location where it transforms into solid mass that forms a barrier in the well. The hardening process is called cement hydration, which is a series of chemical reactions that change the cement particles into hydrated compounds. These materials form crystalline structures that interlock and give the set cement strength. This process is shown in the electron microscope images in the Figure CE-1 below.

Figure CE-1: Example Cement hydration showing initial mixing to growth of crystal structure that gives cement its strength.

Reasons for and types of cementing

The following sections describe the most common types of cementing jobs and the reasons why these jobs are conducted for well construction, well integrity remediation, and well abandonment. Some reasons may have been previously described in section 3; others may be conducted for well-specific conditions.

Primary jobs

Primary cementing is the process of placing cement at the required location in an annulus between the wellbore and casing or liner pipe string. Figure CE-2 (following page) illustrates the process of mixing and pumping the cement slurry into the well, separating the cement with wiper plugs, and placing the cement into the annulus with displacement fluid.

Setting casing strings

• Conductor casing provides structural support for well and completion equipment and is often the first pipe string installed in wells and is not typically designed for pressure containment. • Surface casing is run to protect fresh water aquifers and provides an attachment point for diverters or in some cases blow out preventer (BOP) equipment. Surface casing also provides structural support for the remaining casing strings. • Intermediate casing or liners are set for various reasons: enables drilling ahead with a mud weight between pore and fracture pressures, seals formation pore pressures while drilling deeper and provides wellbore stability. Several intermediate casing strings may be used depending on well conditions, and these strings may have

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higher pressure integrity than those run previously, especially when the next hole section must be drilled through formations characterized by abnormal pressures. • Production casing or liners are set across the reservoir interval within which the primary completion components are installed. Production casing or liners are most often set with cement, although isolation is sometimes achieved using external casing packers which may or may not be cement filled.

Squeeze cementing

Squeeze cementing is the most common type of remedial (secondary) cementing operation. The process involves placing a cement slurry into all necessary wellbore entry points (perforation, holes or split in casing, cement channels, etc.) under sufficient hydraulic pressure to dehydrate or “squeeze” water from the cement slurry, resulting in cement that will harden and seal the voids.

Application

Repair faulty, primary cement jobs: • Repair a weak or wet casing shoes; • Seal mud or gas channels formed in the cement during primary cementing operations; • Complete annular cement fill in casing or liner tops. Repair casing damage: • Repair split or parted casing; • Patch holes in casing or tubing; • Seal eroded or corroded casing. Alter well production characteristics: • Reduce oil/water ratios; • Change gas/oil ratios. Isolate/Seal formation intervals: • Seal lost-circulation and thief zones; • Seal off depleted zones from production intervals; • Prevent fluid migration between zones; • Permanently abandon nonproductive zones; • Temporarily abandon a production zone.

Common squeeze cementing techniques

Generally there are three squeeze cementing methods: • Bradenhead or low pressure method is typically performed under formation fracture pressure and without using a casing packer. The cement is placed in the wellbore using tubing or drillpipe. The pipe is then repositioned above the top of cement, the casing-pipe annulus is closed and hydraulic (pump) pressure is applied to squeeze the cement into the targeted area. Using this method makes accurate cement placement difficult, and usually more than one squeeze job is required. • Squeeze-packer or high-pressure method uses a casing

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Figure CE-2: Primary cementing process.

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CEMENTING packer to isolate the squeeze area from the rest of the well. This method enables closer control of the entire squeeze cementing process and permits a more efficient placement of the cementing slurry into targeted zone. • Top-down annular casing squeeze method is typically used to force cement to surface when it failed to do so during the primary cement job. These squeeze jobs are normally performed by pumping cement down the casing annulus by an outer casing valve or installing a small tubing string into the targeted annuli and pumping cement through this tubing. Monitoring the pressure of the inner casing pressure and the annular pressure in which the cement is being pumped is necessary to prevent casing damage caused by collapse (inner casing) or rupture (outer casing).

Job design

To design an effective cement squeeze plan, the well operator generally works with the cementing service provider to select the casing packer type, cement placement method (hesitation, stage or continuous pumping) and the cement slurry design. To make their selections, well operators and cement service providers use several variables: • • • • • •

Common squeeze cementing packers:

• Squeeze-cementing casing packers (tools) are used to control the placement of job fluids and isolate wellbore pressures during cement squeeze operations. Squeezecement packers are classified as either drillable or retrievable. The type of packer used is dependent on the squeeze job objective(s), casing and tubing condition, and formation parameters. • Drillable-casing packers (retainers) are designed and manufactured to be drilled out of the casing when required. Drillable casing packers can be set using conventional work strings in compression or tension, or by electric wireline operations. These tools typically incorporate a “sliding” or “poppet” valve, which closes when the work-string stinger is pulled out of the retainer following the squeeze job. The retainer contains the pressure below, which is beneficial in many cement squeeze operations. • Retrievable-squeeze packers are designed and manufactured using high-strength steel to provide a higher pressure rating than drillable casing packers. These retrievable packers also feature a fluid bypass system, which reduces formation surge and swab pressure events during installation and removal from the well. Additionally, the packers have mechanical and hydraulic casing slips, which anchor the packer to the casing wall. And, because they have a larger internal diameter, casing perforating tools and other diagnostic tools can be used during well operations. Since these packers feature high-strength steel, fluid circulation ports and casing slips, it is very important to monitor fluid volumes, casing and work string pressures, and pipe movement during operations to prevent the these packers from becoming “stuck” in the well. Removal of “stuck” retrievable squeeze packers usually requires extensive milling, which if unsuccessful may result in loss of the wellbore section or even the entire well.

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• • • •

Job objective; Well and operational risk and safety; Well operations and production history; Casing size, age and pressure rating; Drillpipe or tubing size and pressure rating; Formation properties; • Pore pressure; • Permeability; • Fracture gradient; • Fluids types (oil, gas, water, combination); Diagnostic logs (Cement bond, temperature, noise); Well fluids and type; Rig capabilities; Field history and previous squeeze job results.

Plug cementing

Plug cementing is another remedial cementing technique and refers to the method of placing the cement slurry into the wellbore to create a solid wellbore seal or “plug”. The general plug cementing process involves selecting the location for the plug, positioning the end of the work string at the bottom of the desired plug depth, mixing and pumping a cement slurry down the work string (drillpipe or tubing) into the wellbore, removing the work string from the cement column and allowing the cement slurry to harden in the wellbore.

Applications

Well or zone abandonment: • Seal a dry hole; • Seal depleted zones; • Seal non-commercial zones or wellbores; • Temporary well or zone abandonment. Zonal isolation or well stability: • Isolate one pressure zone from another; • Prevent zonal fluid communication; • Stop lost circulation events; • Enable drilling through fracture or weak formations.

Directional drilling (kick-off plugs):

• Support controlled changes in well trajectory (whipstock operations); • Sidetrack operators around a “fish”.

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Formation testing: • Creates a base for open-hole formation test tools.

Common plug techniques

Listed below are the four most frequently used cement plug placement methods: • Balanced-plug method is the most often used method to install or set a cement plug in the wellbore. It works by means of the “balanced hydrostatic pressures” concept. “Balanced” describes a condition in which the top of cement and spacer outside the work string are at the same height as the top of cement inside the work string at the end of pumping. To help achieve this balance, it is important that the well is in a fluid static state, the wellbore and drilling mud are prepared to receive cement, the spacers/flushes volumes and densities meet design requirements and the cement slurry is designed to ensure safe cement placement and removal of the work string. Rig operations should be prepared to begin removing (pulling) the work string from the cement at the design rate as soon as the cement is in place and surface pressure has been released. • Two-plug method uses wiper plugs or rubber balls to isolate the cement from well fluids (prevent contamination) in the drillpipe and provide positive surface pressure events, which are used as an indication of cement placement in the wellbore. Once the lead cement spacer or flush has been pumped into the work string, the bottom wiper plug or ball is released into the work string, the cement volume is mixed and pumped, the top wiper plug/ rubber ball is released and drilling mud is used to displace the cement. When the bottom plug/ball lands in a receiving tool, a positive surface event occurs that indicates the position of the leading edge of the cement slurry. Additional surface pressure is applied to release the bottom wiper plug/ball, enabling the cement to be pumped into place. The top wiper plug lands in the wiper plug/ball receiving tool, indicating that cement is in place. Surface pressure is then applied, causing the top wiper plug/ball to be sheared out of the tool, which reestablishes work string circulation. The work string is then pulled from the cement column at the designed rate; rig operations should be prepared to conduct this step as soon as the cement is in place and surface pressure has been released. • Dump bailer method incorporates the use of a cylindrical fluid container, which is run into the well with wireline. When the bottom of the dump bailer reaches the desired depth, an electrical or mechanical trigger is used to open the bottom of the cylindrical fluid container, thereby releasing the cement slurry into the well bore. Typically, this method requires multiple runs, because fluid container’s limited capacity. • Mechanically supported plug method is a variation of the

IADC Drilling Manual

balance plug method that incorporates a mechanical tool to provide a bottom for the cement column and prevent migration of the cement column down the wellbore. This method allows for a choice of several mechanical tools: inflatable packers, cement baskets, tools that use expandable membranes, which open when positioned in the wellbore. Once the mechanical tool is in the wellbore at the designed depth, the work string is positioned above the tool and the balance plug or two-plug method is used to place the cement column in the wellbore.

Job Design

When designing a cement plug that will meet the required objectives, the well operator will work with the cementing service provider to select the appropriate plug setting technique and the cement slurry design. To formulate a design operators and cement service providers consider a number of variables: • Job objective; • Well and operational risk and safety; • Well operations history; • Casing size, age and pressure rating; • Hole size and hole enlargement; • Well stability; • Drillpipe or tubing size and pressure rating; • Cement plug setting tools; • Well fluids and type; • Rig capabilities; • Field history and previous plug job results; • Hole angle.

Lost circulation cement squeezes and plugs

In some cases, controlling lost circulation during drilling operations may call for a cement squeeze or plug job to minimize or stop drilling fluid losses and help regain full returns of the circulation fluids to surface. The formation interval into which fluids are lost is commonly called the “thief zone.” Losses may be halted and well circulation restored by spotting a cement plug across the thief zone and, after waiting on cement (WOC), drilling back through the plug. This operation can sometimes be less costly than a squeeze-cement job. Spotting plug cement in open-holes across thief zones with smaller diameter tubing has the advantage of less risk for drillpipe sticking issues and better cement placement. The tubing is often called a “stinger pipe” which can be installed below the drillpipe. However, many plug and squeeze-cement jobs are pumped “through the bit” due to the time required to trip out and back into the well with a lost-circulation treatment bottomhole assembly (BHA). Low-pressure or depleted “thief zones” that steal well fluids drilling fluids can sometimes be sealed by a squeeze-cementing job. In severe cases, more than one job may be

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CEMENTING required. A combination squeeze-and plug-cementing job may be needed when losses occur after drilling out the casing shoe. This can sometimes improve cement placement in the annulus between the open hole and the shoe track including some distance above the shoe track. For deeper thief zones, drillpipe is pulled up above the top of the cement plug and, if needed, above the open-hole; applying squeeze pressure at this stage will force some plug cement into the thief zone. By placing the end of the drillpipe inside the casing shoe, the risk of stuck drill pipe can be eliminated.

Cementing through the bit

Conducting cementing operations when a drill bit is in the well, is a very high risk operation and requires an additional level of pre-job planning including both Job Safety Analysis (JSA) and risk assessments. When precautions were taken, cement slurries have been successfully pumped through the drilling BHA, including motors, without prematurely setting. One key condition for successful jobs is making sure the hole (motor, BHA, DP, annulus, etc.) is cooled by circulating enough drilling fluid. The BHA tools temperature readings should be used for test temperatures used in cement’s laboratory thickening time tests. When no temperature data is available, thermal modeling computer software can be run to determine how long it takes the circulating drilling fluid to cool the recently drilled “hot” hole section and BHA. The start of the cement squeeze or plug job can then be delayed until the hole and BHA (motor, etc.) is cool enough to prevent shorter than designed pump times. When needed, add retarder in the cement slurry based on lab testing with higher temperatures. Other recommendations are listed below: 1. Total bit nozzle flow area and other flow restrictions in the BHA should be sufficient for the designed pump rate and is sometimes specified to be greater than 0.5 sq. in.; 2. The backside surface pressure is continuously monitored to check if cement is circulated up the annulus. This is intended for placing plug cement, but not for squeezing cement; 3. For shoe squeezes, the bit and BHA are spotted inside the last string of casing one or two pipe stands above the shoe; 4. Open hole squeezes to control lost circulation, place the bit one or two pipe stands above the lost circulation zone. 5. Run a lab-tested, compatible spacer ahead and behind the cement slurry. Spacer volumes are determined based on conditions; 6. Do not stop pumping with cement inside the drill pipe (DP). When the spacer reached the bit, close the choke manifold to begin bullheading cement into the zone of interest; 7. A DP swivel is installed above the rotary table and DP is rotated either intermittently or continuously to check for

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any increase in TOB that may indicate that cement is in the annulus; 8. If TOB increases during the job, further action is taken to keep the DP free such as immediately PU one stand and check that TOB decreases before continuing the  squeeze.  9. If TOB doesn’t decrease and hook load increased during PU, immediately shut down the squeeze and take further action such as POOH to prevent planting DP; 10.After all cement slurry has cleared the DP, pull five stands or 500 ft of DP and continue checking TOB; 11. When the designed squeeze pressure is achieved, circulate drilling fluid to clear the annulus of any cement slurry. Continue to WOC until cement is set and rig is ready to continue drilling operations.

Preparing the well and wellsite for cementing Pre-job meeting

The service company supervisor should hold a pre-job meeting with his crew, the rig crew and all other involved personnel in cementing the well to review responsibilities and coordinate the operations to be performed. Safety should always be the top priority. That meeting may cover a number of topics: • Roles and responsibilities - It is important that everyone involved understand their role during the cement job; open communication is essential. The pre-job meeting is a means to establish everyone’s role and to discuss potential risks and contingency plans to deal with any issue that may develop. • Rigging-up and pressure testing of treatment lines should be discussed. • Job procedure – Every step of the cement job should be covered. Volume calculations of cement, mix water, displacement, expected pit gains should have been independently verified by at least two members of the team. The pressure to bump the plug calculation should also be independently verified. Depending on job specifics, there may be other pressure, volume or rate calculations that need to be performed and verified before the job. Equipment and material checks should be also be independently verified by two or more people. • Potential events to discuss – Unplanned issues include lost circulation, excess gas, well control issues, equipment failures, abnormally high or low pump pressure limits, slow mixing rates, cement volume shortages, lack of cement density control, failure of plug to bump on time and floats to hold. • Contingency plans – Circulating the job out and starting over criteria and switching from cement pumps to rig pumps in order to circulate out, dropping the top plug and

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displacing without pumping the planned job volume and a complete list of standby equipment on site. • Weather conditions – Considerations include how extreme heat, cold, or offshore sea state conditions might affect personnel, equipment and materials. Extreme temperatures may introduce conditions different from the cement job’s design conditions (ambient) that could cause compromise the job. For example, in the Middle East, on several occasions cement has prematurely set inside the batch mixer as a result of prepumping and variance in ambient temperature used by the design from lab: 120-140°F. The possibility of these effects should be discussed together with measures to mitigate the adverse effects of extreme weather conditions.

Preparing the well for cementing

Hole and mud conditioning for cementing operations should begin prior to tripping the drillstring out of the hole for the purpose of running casing. While the wellbore may be clean enough to enable trouble-free tripping operations, the presence of cuttings beds, fill on bottom, or mud with undesirable properties make running and cementing casing difficult. Even though the well will need to be circulated and conditioned again after casing is run to bottom, the hole should be clean and the drilling fluid should have the desired mud properties before casing is run. The drilling program should outline the hole-cleaning procedures to be followed for each hole section. The procedures should specify guidelines for flow rate, pipe reciprocation, pipe rotation, cuttings and gas monitoring as well as drilling fluid property specifications. Hole cleaning practices will differ between vertical or near vertical wells, and extended reach high-angle or horizontal wells. For wells with greater than 30° to 40° of inclination, torque-and-drag monitoring is recommended to help determine when the hole is clean. Torque-and-drag can be monitored by using work string pick-up and slack-off weight indicator readings and rotating torque measurements. Torque-and-drag monitoring can be used during hole cleaning and tripping operations to gauge the quality of the hole. This applies to tripping the drillstring or casing. Hole and mud conditioning becomes imperative in the following situations: • Liner cement jobs run with tight tubular/annular clearances, when the liner hanger is set the annular flow path becomes more restricted and prone to plugging with cuttings, debris or gelled mud; • All wells with tight annular clearances; • Wellbores with small mud weight margins between the minimum mud weight needed to control formation pressure and the mud weight that results in mud losses to the formation, resulting in loss of returns caused by

IADC Drilling Manual

bridging or plugging off with cuttings in tight clearances, and high equivalent circulating density (ECD) from the frictional pressure drop while circulating; • During casing or liner running, surge and swab pressures can result in losses or formation fluid influxes if the tripping speed is not controlled. The drilling program should specify the running speed to minimize surge effects. Computer programs are available to aid ECD management and to determine the proper tripping speed to minimize surge and swab forces. In very close-tolerance situations, “auto-fill” float equipment can be used to minimize surge pressures by allowing mud to flow up the inside of the casing while casing is run in the well. The “auto-fill” float equipment can be converted to conventional float equipment when needed. Surge pressures can also be minimized by controlling the mud properties so that they have non-progressive gel strengths and overall viscosity readings as low as practical for hole cleaning. Depending on well conditions, the well should be circulated at prescribed intervals while running in the hole to help break gel strengths and ensure the well is stable.

Hole conditioning with casing on bottom

Once casing is on bottom, the well should be circulated until well conditions are stable and the wellbore is free of excess gas. Mud properties in and out should be the same and within specifications. Between bottoms-up and the casing volume, a minimum of the larger of the two should be pumped. Pumping a minimum of one casing volume will indicate if there are any foreign objects in the casing that might plug up the float equipment. Pumping bottoms-up will reveal if there have been any influxes into the well during casing running operations. Other factors that may need to be considered for circulating with casing on bottom are the need to cool the wellbore down, cleaning the wellbore of cuttings and maintaining the optimum rheology for mud removal by cement. In general, the pump rate should be as fast as possible without inducing lost circulation.

Rig personnel support of cementing operations

Drilling rig personnel may be assigned a number of cementing operation support activities: • Identifying the location of mix water, drilling mud or both supply lines that furnish cementing equipment (cement pump/batch mixer) with mix water and drilling mud; • Ensuring there is sufficient cement mix water, drilling mud or both to mix and displace the cement and communicating and facilitating the method of fluid transfer (centrifugal pump, gravity feed, etc.); • Identifying the barite supply lines that furnish cementing equipment (cement pump/batch mixer) with bulk barite – typically for spacers; • Facilitating the movement of liquid additives (drums,

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CEMENTING totes, etc.) from the storage area to the liquid additive system and the pneumatic transfer of cement from the rig tanks to the cementing unit during cementing operations that take place offshore or at remote sites; • Informing the cementing service providers of any restrictions on the placement of the cementing equipment on location; • Monitoring returns at surface for change in flow rates and presence of pumped fluids (spacer and cement slurry) and diverting contaminated fluids from the active system; • Many operations require the rig pump to take over displacement – in this case rig personnel should coordinate closely with cementing personnel regarding volumes, rates and returns. Rig personnel should be cautious when working in or near the cement pumping unit, cement bulk equipment, liquid additive systems, process controls, batch mixers, flow/mass meters, densitometers, temporary bulk/liquid transfer lines, bulk manifolds and electronic cabling. Rig personnel should always be aware of the location and service state (not in service, pressure testing, in operation, etc.) of the high pressure discharge iron from the cementing unit to the rig floor as well as the status of pressurized bulk tanks, lines and hoses. During foamed cementing operations, care should be exercised around the cryogenic nitrogen storage tanks, nitrogen pumps and nitrogen discharge/vent lines.

Cement dust

Well cementing operations utilizes equipment designed to prevent the escape of cement dust into the atmosphere. However, in the event that personnel are exposed to `cement dust, hazard mitigation procedures are used to prevent injuries or health issues. Local regulators may publish these procedures to help prevent HSE incidents and require them to be posted on bulletin boards or included in the rig’s safety manuals at the wellsite. For example, the U.S. Occupational Safety and Health Administration’s (OHSA) guidelines are shown below: • Hazard: Exposure to cement dust can irritate eyes, nose, throat and the upper respiratory system. Skin contact may result in moderate irritation to thickening/ cracking of skin to severe skin damage from chemical burns. Silica exposure can lead to lung injuries including silicosis and lung cancer. Solutions:* • Rinse eyes with water if they come into contact with cement dust and consult a physician; • Use soap and water to wash off dust to avoid skin damage;

* Reference: OSHA 3221-12N 2004

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Wear a P-, N- or R-95 respirator to minimize inhalation of cement dust; Eat and drink only in dust-free areas to avoid ingesting cement dust.

Rig personnel may also provide support in the preparation of washes or spacers used in the cementing operation. The mixing of spacer fluids should be conducted using instructions provided by the cementing service company or, in the case of more complex spacer systems, under the direct supervision of the service company personnel. Rig personnel should always be mindful of the exposure and respiratory hazards associated with the handling and mixing of materials used to prepare washes and spacers. As such, rig personnel involved in the mixing of spacer fluids should always abide by the same personal protection equipment requirements as those used by the cementing service provider. Mixing cement slurry during the cementing operation is the responsibility of the cementing service company. However, rig personnel may be asked to provide assistance to the cementing service supervisor or other cementing personnel on certain occasions: • Assisting the cementing service providers with obtaining samples of cement slurry, bulk materials and liquid additives; • Providing a tally of materials being consumed, additives, mix water, etc; • Managing fuel and air supply for cementing equipment and ensuring that the air supply is dry; • Helping the cementing service company manage the rig bulk material supply system; • Measuring and recording slurry density using pressurized mud balance; • Assisting in efforts to repair cementing equipm

Rigging up and pressure testing treatment lines

In preparing for cementing and pumping operations, service company personnel rig up and use a high- pressure treatment line often referred to as a cement service line. They may ask the rig crew to assist them in this operation. High-pressure pumping requires managing hazards and risk. In addition, all personnel must comply with local regulations. Examples can be found under OHSA rules in North America, DNV in Norway or ANP in Brazil.

Components of a high-pressure line

• Chiksan/swivel joint is a high pressure articulating hardline used to make connections adjustable by rotating and a swiveling them. A double chiksan enables an easier rig up for spacing and flexibility, regarding vibrations and pump pulsations during operations. • Pressure relief (pop-off) valve is a safety device that protects contained systems from over pressuring. In most

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CEMENTING by line size, pressure and line service, liquid or gas. • Pressure testing should be conducted once the service line has been rigged up in accordance with all applicable operator, contractor or service company safety guidelines. The line should be tested to the expected working pressure, plus an agreed on safety factor.

Job design, pumping and displacing cement

Optimizing a cement job for proper placement begins with defining the objectives of a particular cement job. Whether the job is designed for casing support, wellbore isolation, formation isolation or providing a plug for directional operations, properly understanding the objectives of the job is a prerequisite to successful design. The next step in the design process is identifying the operating envelope for the job, which includes identifying the pore pressure and frac gradients in a well, temperatures, wellbore architecture and formations to be cemented. Once these parameters are identified, a cement slurry and job design can be developed to meet the objectives of a cement operation using industry recognized laboratory standards and methods.

Figure CE-3: Diagrams of incorrect and correct combinations of pressure unions. See p CE-10.

cases, it works by the tripping of a spring or shear pin that was set at a prescribed safe level, allowing unplanned high-pressure events to be vented or relieved into a lowerpressure or non-pressured destination source. • Plug Valves are high-pressure capable valves designed for a wide range of standard and sour gas drilling, production and well-servicing applications. These valves come in single- and dual-body designs in pressure ratings up to 20,000 psi. Depending on the pressure rating of the value, they range in size from one to four inches and are equipped with hammer unions or flange connections. They feature a two-piece floating plug/stem, and are capable of handling fluids with solids intermixed. This plug valve is used throughout the industry in temporary setups such as flowbacks, coiled tubing, well testing, fracturing and cementing operations. • Mismatched connections or pressure unions are potentially one of the most dangerous situations faced by rig and service personnel. For example, in Figure CE-3 a 1502 union will make up to a 602 or 1002 thread, but it will fail once the pressure rating of the lower union is exceeded. • Line restraints may be required by some operators or governmental regulators. Ratings of lines are determined

IADC Drilling Manual

In planning a cement job, slurry density, rheology and pump rate are optimized to the particular well conditions. The slurry design will take into account the required density, rheology and pump time required for cementing. The design may be as simple as cement and mix water, or it may require a more complex system with several additives, or systems containing nitrogen gas to foam the slurry to a specific density. The slurry’s density provides the necessary weight for well control, but it must be light enough not to fracture the well. During placement, the friction generated by the various fluids introduced into the well impact the ECD and must be controlled to prevent fracturing the well, resulting in lost circulation. Slurry densities, rheologies and pump rates are used to manage ECD. To optimize slurry placement, job design is based on various well parameters: frac gradient, pore pressure, formation type, wellbore architecture, etc. and the rig’s equipment capabilities and any logistic challenges. The final design should be a representation of all of these variables to achieve an optimized operation. A primary goal of any cement job is to replace the drilling mud in the well with uncontaminated cement. To achieve this, the drilling mud must be completely removed from the annular space. Contamination of cement by drilling mud can be detrimental to the final cement properties. Dilution of the cement by drilling mud can result in lowered strength, and if there is excessive contamination, the cement slurry may

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CEMENTING never gain measurable compressive strength. To completely minimize contamination, several good cementing practices are recommended. One of the keys to good cementing is centralized casing. Depending on the size of the casing and the open- hole, the degree of eccentricity that can be tolerated will vary. Larger annular spaces are more tolerant to eccentricity than smaller annuli. This is because there is less of a difference in fluid velocities for fluids flowing on the narrow or wide side of the annulus. With the casing properly centralized, the drilling mud should be conditioned prior to cementing. Pumping at least the volume of the annulus (bottoms up) is a common recommendation, though some work has shown that this should be a minimum volume and larger volumes are often beneficial. Optimizing mud displacement requires bulk and chemical removal of the mud. Bulk removal is conducted by “putting energy” into the well. This can be done in two ways: high pump rates and casing movement. Pump rates will be limited by the fracture pressures in the well, and the viscosity of the fluids being pumped. High rates may not be achievable in all cases, but the design should use the highest rates practicable, while taking the ECD into consideration. Pipe movement, either reciprocating or rotating, will put energy into the well; both invite additional risks. Reciprocation can be effective; however, consideration must be given to the surge and swab pressures in the well. There is also a risk of sticking the casing off-bottom if the casing cannot be lowered completely to bottom at the end of a cement job. Casing rotation can also be effective, although using this technique may require replacing the casing couplings to ensure they can withstand the increased torque on the connection. Additional equipment may be required on the rig to enable casing rotation, adding some degree of operational complexity. Centralization, pipe movement and pump rates and use of bottom wiper plugs are used in bulk drilling fluid removal. Equally important in this process are spacers or other fluids to separate the drilling mud from the cement. Many drilling fluids are not compatible with cement slurries, and mixtures of fluids can form a mass that cannot be pumped. To guard against this, spacers and washes (or flushes) provide a buffer between the cement slurry and drilling fluid in the well. Cement spacers, which are viscosified and can be weighted, also help prevent cement degradation caused by the mixing of cement slurries with drilling muds; reducing or preventing cement degradation can minimize formation damage.

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Flushes are used reactively to flush ahead of the spacer and cement slurry to improve mud displacement, control fluid loss, and alleviate lost circulation during cementing. Flushes are not generally viscosified and cannot be weighted. Types of flushes include water, brine and base oil. Spacers and flushes should be prepared according to instructions from the cement service provider. Regardless of the spacer or flush (or combination of the two) selection, sufficient volume of these materials must be used to provide sufficient separation of the drilling mud from the cement. A minimum of 500 annular feet of fluid should be used with preference given to 1,000-1,200 ft. Additional work has shown that a minimum of 10 minutes contact time may provide sufficient volume of fluid for wellbore cleaning. Once the slurry and job design are completed, and the well has been prepared for cementing, the on-site quality control for the job remains a key step in proper cementing. During the mixing of the cement slurry, careful attention must be paid to density control of the slurry. Optimally, cement slurry should be mixed to within +/- 0.2 lb/gal of the laboratory design. Mixing cement to the proper density is more important than attempting to achieve a particular mixing rate. While mixing rate is a consideration, density control is crucial to cementing success. When the cement has been mixed, the displacement of the cement begins. Normally this is preceded by dropping the top plug followed by introducing the displacement fluid. Once the top plug is dropped, the only variable that can be controlled is the pump rate. As noted earlier, optimizing the pump rate for proper mud removal while maintaining ECD control in the well is a key consideration regarding the job design. The cement is displaced until the top plug lands out on the float equipment, the landing collar or when a specific volume of displacement fluid has been pumped. Once the calculated volume of displacement fluid has been pumped, if the plug has not bumped, the pre-job plan should make it possible to identify the amount of “over displacement” that is to be pumped. Depending on the well requirements and plans, this volume might range from zero to half the shoe track volume. In cases where equipment must be pressured up to function, as with hydraulically activated packers, the plug must be displaced until it lands on the float equipment.

Estimating job volumes (cement, mix water, spacers, displacement)

Many different volume estimates are required to achieve a good cement job. Cement displacement volumes depend on the pumping schedule and are tracked by cementing company personnel as the job progresses. The volume of ce-

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ment needed depends on the hole size and the desired top of cement in the wellbore-casing annulus. Water requirements depend on the volume and density of cement needed and the specified volume and composition of spacers and flushes. Having enough makeup water on hand is essential, and the rig crew may need to provide this by ensuring sufficient tankage for hauled water or by securing a sufficiently plentiful water sources: surface water or aquifers.

Estimating cement volumes

Accurately determining the necessary cement volume depends on several factors: • If there is a loss zone that must be covered, it is important to bring the cement top just above the loss zone, but not so high that the hydrostatic head from the cement causes lost circulation; • In some cases it is imperative that the cement top be placed near the previous casing shoe, but not above the previous casing shoe where annular pressure build up in a trapped annulus could cause casing failure; • For foam cement jobs, the density and actual volume of cement placed is highly dependent on accurately knowing the hole size in each interval of the open-hole; • There are also regulatory and many other factors that may need to be considered. The first step in estimating cement volumes calls for determining the hole size in the interval where cement is to be placed. The second step involves determining the interval or length of hole section that needs to be covered with cement. The interval is usually defined by the top of cement (TOC) and the base of the cement. The planned TOC should be in the drilling plan and must meet regulatory and wellbore integrity related issues.

Hole size determination

• Bit size can be used to determine the hole size as it will provide an approximation for calculating cement volumes. However, the average hole size is usually larger than the bit size because of wellbore instability. Stresses in the earth can cause areas of the borehole to collapse and break off which enlarges the hole. When there is an appreciable difference in the direction of the geomechanical forces acting on the wellbore, the enlargement will usually be in the direction of the higher forces, causing an oval shaped hole. The magnitude of the enlargement depends primarily on the magnitude of the stresses in the earth, the formation strength and the density of the drilling fluid. Higher density fluids can help stabilize the wellbore, but there are risks, such as fracturing the formation (lost returns) and differential sticking, to consider before increasing the mud density. Wellbore enlargement can also be caused by interactions

IADC Drilling Manual

between wellbore fluids and the formation. It is also possible to have a hole size less than bit size because of filter cake buildup on permeable formations. If filter cake buildup is an issue, the drilling fluid can be treated to mitigate the problem. • Four-arm wireline calipers normally provide the highest amount of accuracy, especially when the wellbore shape becomes more oval, rather than a perfect circular shape. In an oval-shaped hole, a two-arm caliper tends to measure the maximum diameter of the oval, while a threearm caliper will tend to measure the minimum diameter of the oval. In a perfectly round hole, all caliper types will measure the hole size accurately. There are also nonmechanical acoustic type tools available that produce a hole caliper log. Multifinger calipers with 12 to 80 fingers are normally run in cased holes to inspect tubulars. • Fluid calipers provide an estimate of the circulating volume of the hole, but not necessarily the true volume of the hole. Fluid calipers are usually less reliable than wireline calipers since the circulating volume may be less than the true volume of the hole due to fluid bypassing of static mud pockets in enlarged sections of the wellbore. A fluid caliper also gives an average hole size over the entire open-hole interval. If there are enlarged whole sections in specific intervals, there may a problem with placing cement accurately. In situations where accurately determining the hole size in each interval of the hole is imperative, such as foam cementing, a fluid caliper may not provide the needed accuracy unless experience in the area can also be factored in. A fluid caliper is performed by pumping “marker” material down the drillstring and recording the volume of fluid pumped for the marker to be pumped around to surface in the annulus. The annular volume is calculated by subtracting the internal volume of the drillstring and the volume of steel in the drillstring. Using this volume, further calculations can be performed to estimate an equivalent hole size for the open-hole to estimate cement volumes. The marker can be paint, dyes, lost circulation material, carbide or any other pumpable material that can be easily detected at surface. Several consecutive fluid calipers should be run to increase accuracy.

Area experience and excess cement

Experience in an area helps to more accurately determine the cement volumes needed. Cement volumes can be based on a gauge hole (bit size) or caliper volume with an excess volume added. The excess volume is calculated by using the cement volume calculated from a gauge hole or caliper, multiplied by an excess factor, which is usually expressed in percentages. Excess cement is usually pumped for the following reasons:

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• In order to ensure cement is placed at or above the planned cement top; • In cases where cement is pumped to surface, pumping excess cement minimizes the volume of potentially contaminated cement due to intermixing with the spacer or mud with the leading edge of cement.

• Aids effective mud removal and increases displacement efficiency to provide a better cement seal; • Wets the casing and formation with water ahead of the cement to improve cement bonding when non-aqueous (oil-based) fluid is in the well prior to cementing.

Addressing lost circulation in cement job design

An essential component in making any cement slurry is the water. Water quality, volume, temperature and supply rate can all impact the ability to mix the cement to the proper density and the slurry properties in the well.

Cement alone is usually not effective at stopping losses during primary cementing. If possible, losses should be under control prior to the cementing process. In the event this is not possible, lost circulation material (LCM) is almost always added to the cement blend. Common types of LCM include: cellophane flakes, ground coal and gilsonite. There are some fibrous materials that can be used, but they introduce more operational complexity since they must be added directly to the mixing tub instead of being pre-mixed in the cement blend. Lost circulation can also be mitigated by designing a cement system with the lowest density slurry that still meets all the well requirements. Lower density systems can be designed using low density materials such as Pozzolan, fly ash, bentonite, hollow spheres or by foaming the cement with a gas such as nitrogen. Two-stage cementing may also be a viable alternative to prevent losses while cementing. The first stage of the cement is pumped to place the top of cement just above the loss zone. The stage tool is placed just above the loss zone. If losses are expected, the volume of cement available should be adjusted accordingly.

Mix water volumes

Once the cement volumes have been determined, the mix water volume requirements can be calculated. To ensure sufficient mix water is available for the job, excess volumes should be ordered to account for un-useable tank volume below the suction line, filling the lines, and wash-up after the cement has been mixed.

Spacer volumes

A spacer or wash fluid is usually pumped ahead of the cement. The spacer or wash fluid volume should be included in the drilling procedure for the well. There are a number of computer programs available to aid in the design (density, rheology, volume and other properties) of the spacer. Prejob testing should be conducted to ensure that the spacer is compatible with the drilling fluid and cement systems. The spacer or wash can improve the cement job by serving several purposes: • Prevents contamination of the mud and cement which could lead to gelation problems;

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Water sources and supply

Water quality is a key concern in cementing. Generally potable water is preferred for cementing, though sea water, brines or other types can be used. The key to success in cementing operations is to test the cement slurry in the lab with the water that is to be used at the wellsite during the actual job. In that way, any contamination of the water can be taken into account for the design. Inadvertently using sea water rather than fresh water, for example, can shorten thickening times and result in job failures. If sea water was used in the original design, the same sea water or water that is as close as possible to it should be used to mix the cement. Generally, this is only a concern for rigs located near river outlets where rain events on land can change the composition of water flow from the river, because such events have the potential to change the salinity of the sea water. In some cases, the impact of large rain events on land can reduce the salinity of the water to near fresh and may add lignins, which retard cement setting. Additionally, withdrawal points for sea water on the rig must be deep enough to avoid surface changes in sea water quality while high enough to avoid incorporating bottom sediments. Another important aspect of job execution is ensuring that sufficient water is available for the job and can be delivered to the cementing unit at the rate required for the cement job. Insufficient water supplies mean the volume of cement mixed on the job could be insufficient for the well requirements. Inadequate supply rates can reduce mixing rates, which will extend the time required to mix the needed volume of cement, potentially leading to a job failure. Finally the temperature of the mix water is important. Very hot water can lead to premature setting of the cement, while very cold water can impact the ability to mix the cement to the proper density. Hot water is a common problem on locations where the mix water has been stored in tanks exposed to direct sunlight. During summer months the water in these tanks can be quite warm, at times exceeding 120°F. If the water must be stored in tanks or high temperatures are anticipated, the lab testing of the cement should take the high-water temperature into account.

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Very cold water, coupled with cold cement can lead to mixing problems. Hydration of the cement particles is impaired, and achieving the proper cement slurry density can be difficult. In cold climates it is common to heat the mix water to counteract very cold and dry cement temperatures. If these conditions are anticipated on location, the laboratory testing can be adjusted to account for the temperature extremes.

Estimating displacement volumes

Displacement volumes can be calculated using the internal diameter of tubulars. If the cement plug does not bump after pumping the calculated cement volume, a plan should be in place to determine if additional volume above the calculated volume should pumped.

Job time

Changes in planned cement volumes directly affect job time. Ensure that the cement thickening time is adequate whenever there is a major change in cement volume. Since cement begins to react the moment it comes into contact with water, job time begins when cement mixing starts. Job time is estimated by calculating the time to mix and pump cement, drop cement plugs after cement mixing begins, plus the time to displace the plug to the float collar or baffle. A safety factor is added to the job time to estimate the thickening time or pump time needed for the cement. This safety factor enables slower than planned pump rates or unplanned shutdowns. The safety factor for thickening time requirements on cement will vary based on several factors: overall size of the job, job complexity and equipment on location. Safety factor policies vary, but it is common to see a one hour safety factor for cement job times that are one to three hours, with the safety factor increasing for larger or more complex jobs.

Pump rates and pressures

Planned pump rates and expected pump pressures should be included in the drilling procedure for the well. Computer simulation programs are available to help optimize pump rates and estimate pump pressures during a cement job. Pressure limits should be established for the cement job based on casing-burst and surface-equipment ratings. Often, the cement head has the lowest pressure rating.

Wait on cement and post-job rig operations

Wait-on-cement (WOC) time allows cement to develop the compressive strength necessary to continue with rig operations in a safe manner without affecting the cement’s ability to perform its necessary functions over the life of the well. Many regulatory agencies have requirements for WOC periods. Regulatory requirements may specify the time to reach a minimum compressive strength, a minimum time interval

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or a combination of the two. There may also be regulatory limits on the type of activity allowed during the WOC period. The WOC period begins when the cement displacement ends (plug bump), and the cement is allowed to stand in a static state. For most wells the hydrostatic head of the cement column in the annulus is greater than the hydrostatic head of the displacement fluid in the casing. When the pressure is bled off at the end of the displacement, the float equipment is checked to ensure that it holds the cement column in place by preventing backflow of cement from the annulus into the casing. If the float equipment does not hold, pressure must be maintained inside the casing until the cement has reached sufficient compressive strength to support its own weight. At this point, the pressure should be bled off the casing to minimize the chance of a micro-annulus forming. During WOC time, the well should be monitored to ensure that there is no flow from the annulus or the casing. There is a potential for the well to flow from either area until the cement has obtained sufficient strength to form a barrier. The cement’s compressive strength development should be lab tested as per procedures in API RP 10B-2 to determine WOC time periods that achieve the following values for the listed operations: • 50-psi cement compressive strength before removing the BOP or other well barrier; • 500-psi cement compressive strength before drilling out the casing or liner shoe; • 2,000-psi cement compressive strength before running cement evaluation logs or minimum 48 hours as per API Technical Report 10TR1.

Cements and cement additives Conditions and required properties

Cement used in oil wells is subjected to a wide range of temperature and pressure conditions. Accordingly, the use of a single-cement type is impractical; therefore, different types of cements and cement additives have been developed to meet a variety of conditions. A number of cements are available in the industry and include both ASTM and API cements: • Class A: Common cement used for shallow casing strings, similar to ASTM Type I; • Class C: Fine ground cement similar to ASTM type III, useful for low temperature cementing applications; • Class G: Most common oil well cement, universally used for all well conditions; • Class H: Coarser ground cement than a Class G, only available in certain regions of the United States.

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Table CE-1:Common families of additives and their effects on the slurry

Water Requirement Viscosity Thickening Time Early Strength Ultimate Strength Durability Fluid Loss Free Water

Decrease More

✓ ✓

✓

Less

Gas Migration Agents

LCM

✓

Free Water Control

✓

✓

✗

✗

✓

Higher

✗

✓

Lower Longer

✗

Shorter Less

✗

✓

✗ ✓

✓ ✓

✓ ✓

✓

✗

✗

✗

✓ ✓

More

✓

More

✗ ✗ ✓ ✓ ✗ ✗

✓

Less

✓ ✓

Better

✓

✗

Worse Improved

✗ ✗

✗

✗

✓

✓

Worse

✗

Less More

Salt (NaCl)

Increase

Weighting Agents

Density

Sand and silica flour



Effect

Cement Property Affected

Dispersants

Ž

Retarders

Additive Type or Effect

Accelerators

Extenders (Bentonite, Pozzolans, etc.)

✓ = Major Effect; ✗ = Minor Effect; [blank] = no or insignificant effect

✓

There are also a number of cements used that may not carry an API or ASTM rating. These include blends of Portland cement and other additives inter-ground or blended at the cement manufacturing site. Regardless of the cement type, the final cement slurry, with the appropriate additives, must be designed and tested for the expected well conditions. Portland cement by itself has a very limited range of properties, and requires the addition of cementing additives to alter its performance. Additives are used to alter the working time (or thickening time) of the cement, alter the rheology, enhance the fluid loss or alter other critical properties of the cement slurry.

Cement additives

Cement alone has a very limited application range. Because of the various conditions in the wellbore, the cement must be modified to enable it to be properly placed in the well and remain stable over time.

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✗ ✓

✓ ✓

✗

Table CE-1 lists several common families of additives and highlights their main function in the slurry. The table is not exhaustive and is intended only as a guide. Many additives when used together can enhance the properties listed. Additionally as the concentration of particular additives increases, the effect on slurry properties can change. For example, many fluid additives work better in conjunction with dispersants. The synergistic effect of various combinations of additives is common in cementing.

Cement slurry properties

There are three basic properties inherent in every cement slurry. These are the desired weight or density to which the slurry is to be mixed, the amount of water required per volume of dry cement to achieve that density and the resulting yield of the final slurry. Units for these properties are listed below (Table CE-2).

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Table CE-2: Units for density, water content and yield --

Oil Field

Metric

Density

lb/gal

kg/cu m

Specific Gravity

SG

g/ml

Water Content

gal/sack

l/metric tonne

Yield

cu ft/sack

cu m/metric tonne

The basic calculation for cement slurry properties is:

Density =

Total of all material mass Total of all material volumes

The yield and water content of the slurry are used to determine how much cement is required to perform a particular cement job, and the amount of water required on the rig to mix that volume of cement slurry. Bulk volume vs. cement volume Dry cement is delivered with air to the cement mixing unit from the bulk system. A bulk tank with a 1,000-cu ft volume capacity will not hold 1,000 sacks of cement, due to air entrainment within the dry cement or bulk additives blended in the cement. The bulk loading factor for a cement system must be considered when determining the amount of rig bulk storage. This varies with different cement systems, particularly those containing ultra-lightweight additives, silica or both.

Cementing strings and associated hardware, including casing running tools Casing cementing string hardware Cementing head equipment

• Circulating swages (casing swages) are temporary crossovers that facilitate circulation of the casing string prior to reaching casing TD. They can be threaded to match the casing or have an adaptor that attaches around a casing collar. The casing can be circulated using the rig pump or cementing unit. “Washing casing to bottom” is one function of a swage. • Wiper-plug container (cementing head) is a pressure chamber or device that attaches to the casing or drillpipe to allow circulation in the casing, the pumping of cement slurry and the dropping of wiper plugs or subsea plug activators. Casing wiper-plug containers can be single or double, enabling them to hold one or two wiper plugs, and

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can be manually or remotely operated. Drillpipe wiperplug containers are used in deepwater applications to set subsurface plugs using balls or darts through the drillpipe. • Casing wiper-plug systems are used to wipe the casing ID and separate cement from the drilling fluids. Generally, a plug system consists of a bottom and top plug. Bottom plugs are hollow and are used or launched ahead of the cement slurry. The bottom plug lands on a baffle or float collar, a diaphragm in the bottom plug ruptures and cement moves through the plug and into the annulus. A top plug is run or launched behind the cement to wipe the casing ID and separate the cement slurry from the drilling fluids. The top plug is a solid and signals a positive pressure indication when landing on the baffle or float collar once displacement is complete. Some casing plugs are equipped with a non-rotating feature that aids in drill out; teeth or slots on these plugs lock the plugs together and to the float collar. In this case, the compatibility between the plug and the float collar should be confirmed. • Conventional casing plugs are normally composed of five wiper fins and made from an elastomer molded to a hard core; they are launched from a casing wiper-plug container. These plugs are color coded and come in two types: • Top-casing wiper plugs are typically black and designed not to rupture; • Bottom-casing wiper plugs are typically red, yellow or orange and are hollow with a rupture disk. • Subsea/liner casing plugs are attached to the subsea casing-landing string and actuated using balls, darts or both through a drillpipe wiper plug container. • Casing centralizers Casing centralizers are mechanical devices attached or molded to the casing to increase casing stand-off, allowing better mud removal and cement placement. Several types of casing centralizers exist. The most common type used in vertical wells is the bow spring centralizer. Bow spring centralizers are in-stalled with an uncompressed diameter typically larger than the hole size (overgauge) to accommodate — to a certain extent — variations in hole diameter. The centralizer’s restoring force (representative of bow spring strength) will dictate the resulting stand-off at a particular point in the wellbore. Centralizers are selected for specific casing/hole size combinations. They also have a minimum compressed diameter. It is important to confirm that the smallest restriction in the well is larger than this number. Special bow spring models are also available for close-tolerance applications. Other types of bow spring centralizers include spiral bow for bridging key seats, and “turbolizers” with fins to promote fluid agitation. Semi-rigid or doublebow spring centralizers offer higher restoring forces and are commonly used in inclined wellbores. Commonly, though not always, these centralizers are run close to gage (uncompressed diameter equal to hole diameter).

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Table CE-3: API Ratings for float equipment (Specification 10F, Draft as of 1 May 2014, Glen Benge, personal communication ) FLOW DURABILITY TESTS Flowing Time

Reverse Flowing Time*

Flow Rate

Category

Total Flow, hours

Category

Reverse Flow, hours

Category

Flow rate, bbl/min

D8

8

AF4

4

R6

6

D12

12

AF8

8

R10

10

D24

24

AF12

12

R20

20

D36

36

* For casing fill-up equipment FLOW DURABILITY TESTS

Category

Temp. °C (°F)

Category

Pressure, kPa (psi)

T200

93 (200)

P1.5

10 300 (1 500)

T300

149 (300)

P3

20 700 (3 000)

T400

204 (400)

P5

34 500 (5 000)

T500

260 (500)

P10

68 950(10 000)

Installation of bow spring centralizers require placement around a limiting device, a stop collar or casing coupling. This allows the centralizer to be pulled in either direction, passing through tight spots without being pushed. Pulling a bow spring centralizer reduces its OD size and pushing it, increases its OD. This action will require a larger amount of pushing force when there are restrictions in the wellbore. Hinged bow spring centralizers can be installed by lacing them over the casing coupling when flush or semi-flush connections are not being used, or over a stop collars. The hinged types are the simplest and quickest to install. Some semi-positive designs cannot be installed over casing couplings, because the coupling will not allow the springs to fully compress (Figure CE-4).

when centralizers must pass through a restrictions before opening to provide standoff in a larger hole size, such as underreamed well sections. Centralizer placement programs enable the successful selection of equipment for applications and ensure proper placement for a quality primary cement job. An effective centralization program can contribute to getting casing to TD, obtaining complete zonal isolation, and establishing long term wellbore integrity. Spacing simulations identify what type of centralizers should be used in certain wellbore sections, their number and placement to achieve the in-

Solid body centralizers can be attached or molded onto the casing body. These centralizers are slightly smaller than the wellbore – often referred to as under gauge – and are used in deviated and horizontal wells. Rigid centralizers will support the weight of casing against the wellbore. Rigid centralizers are also available in special low-coefficient friction materials, such as polymer, and are designed specifically for horizontal and extended reach wells where drag reduction is needed, resulting in significantly reduced friction that aids getting the casing to bottom. Solid body centralizers are attached to the casing using set screws located on the collar or between two stop collars, depending on casing rotation and its purpose (Figure CE-5). Deepwater and tight-clearance applications often require integral centralizer subs, which are pieces of casing with a built-on centralizer (Figure CE-6). These subs are useful

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Figure CE-4: Bow spring centralizer types: Hinged welded, Double bow, Spiral bow and Turbolizer.

Figure CE-5: Solid body centralizer types.

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Figure CE-6: Internal centralizer subs.

Figure CE-7: Float shoe and nose types.

tended standoff results. Following a recommended program is paramount in obtaining a good primary cement job and reducing mud channeling, thereby eliminating the need for costly remedial cement work.

shoe is made of steel, usually to the same specifications as the casing. The internal body of the shoe is usually made of concrete or plastic to allow it to be drilled out. Float shoes are available with many options including down jets, up jets, side ports, and a variety of nose types (Figure CE-7).

• API Specification 10F* for float equipment testing outlines several categories of equipment that are available. When purchasing or evaluating float equipment, it is important to fully review all five categories outlined in Table CE-3. The combination of all five categories describes the durability and capability of the valve. Valve performance is measured in terms circulating time, flow rate, back pressure, and temperature. Therefore, it is important to match the performance of the float equipment to wellspecific actual casing running and cementing operations.

Guiding and Floating Equipment:

Guide shoes are tapered, rounded often bullet-shaped casing attachments placed at the bottom of the casing. When casing is being run into a well, the guide shoe helps direct it to the center of the wellbore. The outer body of the shoe is made of steel, usually to the same specifications as the casing. The internal body of the shoe is usually made of concrete or a plastic material to allow it to be drilled out. A guide shoe is opened ended and lacks a check valve. A Float shoe is a type of guide shoe with an integral check valve to prevent cement from U-tubing when it’s pumped in the well. The check valve may have a flapper valve or spring-loaded poppet valve assembly. The outer body of the * At print time, API Specification 10F had not been released; the specifications listed may have changed.

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Down jets provide the ability to circulate while running in hole and a means of washing to seat if required. Up jets allow cement to be pumped through them for optimum placement and to improve circulation, which promotes wellbore cleaning. Side ports enable circulation to be established when casing becomes plugged during running or when landed on bottom. A float shoe can also assist in floating the casing to TD and reduce casing hook load by controlling the rate and amount of fluid used to fill the casing (see automatic fill). • Float Collars are similar to float shoes but have a short piece of casing with a threaded box and pin that contains a check valve and provides a landing area for the cement wiper plugs. The check valve may have a flapper valve or spring-loaded poppet valve assembly. Single-valve or double-valve configurations are available in float equipment (Figure CE-8). Double valves act as additional backup when sealing high pressures from below. Double valves are a good option for reliability when longer than normal circulating times are expected or large amounts of abrasive solids must be circulated. • Automatic fill up equipment is one type of float equipment that reduces surge pressures while running casing by allowing some of the mud to flow up through the inside of the casing Once the casing reaches TD, the float valve is converted from auto-fill mode back to a conventional

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CE–19

Figure CE-8: Float collars.

check valve mode by pumping fluid at a predetermined rate or by mechanical means, such as dropping a ball. • Shoe track (shoe joint, float joint) is a length of casing between the landing collar. The shoe is left full of cement after a cement job to ensure quality cement around the casing shoe and reduces the risk of over displacing the casing string by such factors as fluid measurement or capacity calculations. The length of the shoe track is planned by the well designer and is usually as long as two or three casing joints. • Inner-string cementing involves cementing large diameter casing strings and eliminates the need to displace internal capacity and volume of the casing during cementing operations. Inner-string cementing usually requires a special sealing float shoe rather than the conventional guide shoe and float collar (Figure CE-9). Once the casing has been run, the inner-string cementing equipment (generally tubing or drillpipe) with a special seal adapter attached on the end, is run and stabbed into the float shoe. The seal adapter seals against the seal bore of the float shoe. Drilling mud is then circulated around the system to ensure that the stinger and annulus are clear of any debris. Next, the cement slurry is pumped with fluid liquid spacers ahead and behind the cement slurry. Cementing plugs are not typically used in this type of cementing operation. The cement slurry is generally underdisplaced, purposely left in the inner string and allowed to fall out on top of the float shoe. Underdisplacement ensures that the cement, not the spacer and drilling mud, is left in the casing on top of the shoe. After the cement has been displaced, and the float shoe has been checked for backflow, the work string is removed from the well. Inner-string cementing is suitable for 16-in. casing diameters and larger. Stage cementing tools (multistage cementers) are used when two or more separate sections behind a casing string

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Figure CE-9: Inner-string cementing equipment: latch-down drillpipe wiper plug, stab-in latch in drillpipe stinger, inner-string float shoe

need to be cemented. Applications for this include situations when the hydrostatic pressure of the cement column needs to be reduced as much as possible to prevent breaking down weak formations, encountering lost circulation zones that require cement to be placed above and below the zone or when the length of a string is too long to cement and the pumping pressure necessary to lift the column to surface would be excessive. Stage tools are installed at a predetermined point in the casing string above the float collar and can be operated hydraulically or mechanically. Note that casing, or any other type of tongs, should not be used on any part of the stage collar body during installation. Stage tool collars can be ordered for two- or three- stage cement jobs. These collars feature one or more internal sleeves that shift during stage cementing operations. These sleeves can be shifted open with hydraulic pressure or by dropping a dart that will land in the

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CEMENTING

Figure CE-10: Stage cementing tool positions (left to right) neutral, mechanically opened and closed.

opening seat by gravity for mechanical operation. It is important to note that free fall opening darts can only be used in wellbore deviations of less than 20° from vertical. Stage collars can be field set to open mechanically or hydraulically at different opening pressures by adding or removing shear screws from the tool. • Stage collars are closed by pumping a closing plug behind second stage cement and applying pressure after displacement is complete. Different plug set configurations can be used depending on whether the tool will be operated hydraulically, mechanically, or both (Figure CE10).

Liner cementing tools

Liner cementing tools are available in multiple configurations and are categorized by means of activation, amount of weight they can support or other features or abilities: • Mechanical hangers consist of a mandrel, j-slot, cones/ pads, slips and drag springs or both. These hangers are set by manipulation of the work string. In general the number of cones impacts the weight rating of the hanger. • Rotating or non-rotating hangers have a bearing that allows the liner to be rotated after the hanger slips have been energized. The liner’s rotating action improves cement placement.

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• Protective slips are recessed in the hanger body and protected while the liner is run into the wellbore, usually for drilling or reaming liner applications. • Hydraulic hangers are set by using differential pressure, usually a ball and ball seat configuration. These hangers are used in high-angle wells or deep liner depths. Hydraulic hangers do not have drag springs and can be rotated. Circulation pressures before setting the hanger are usually limited to 50% of the liner’s shear pressure. • Currently, there are two types of expanablee liner-hanger systems. The first type incorporates a section of expandable casing that is connected to the top of the liner pipe string. The expandable pipe section has an elastomer bonded to the outside surface, which is used to hang (support) the liner string and seal the liner/casing annulus in the “liner lap” (top of liner inside the previous casing). After the primary cementing operation is complete, the hanger is activated or “set” by using an expansion tool to expand the elastomer on the expandable hanger section of the liner. Since the expanded elastomer suspends the liner pipe string and also seals the “liner lap” annulus, the need for a liner top packer is eliminated. • The second type of hanger uses two different expandable pipe sections: one for the expandable slips and another for the expandable elastomer. The hanger is set to suspend the liner pipe string by expanding the expandable slips before the primary cementing operation. The “liner lap” annulus is later sealed after the primary cementing operation and when the cement WOC time has expired. This action also eliminates the need for a liner top packer. • Liner top packers are compression set packers run in conjunction with mechanical or hydraulic set hangers. After the cementing is completed, these packers are weight activated and locked in place.

Casing running tools

Casing was run the same way for over 50 years, using the same principles, only slightly influenced by a few changes in tool shapes and the sporadic implementation of additional features. These tools are commonly known as conventional tools. Some years ago it became evident that the industry needed a new way to run casing and the technology was amended to serve one of the most important activities in the drilling industry. Taking advantage of the increasingly popular use of top drive technology a new generation of automated casing running tools were developed, providing higher safety and quality standards while also adding new capabilities that increased efficiency and reduced costs. At the same time, conventional tools have evolved into mechanized tools to provide a safer and more efficient environment.

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CE–21

1: Main mandrel connected to top drive 2: Torque reaction bracket 3: Torque measurement system 4: Hydraulic bails 5: Compensation system 6: Hydraulic components (actuator) 7: Clamping system 8: Hydraulic spider

Figure CE-11: The tool is made up to the top drive by means of a top connection on the main mandrel. The torque reaction bracket is a required accessory, installed from the tool body to the top drive rails or pipe handler. It has the specific function: reacting to the friction of the swivel of the tool, avoiding the tool bails and housing to rotate when making up the pipe or rotating the casing string. The torque measurement system is located in the tool and measures the torque applied by the top drive and transferred by the casing running tool to the casing. This system also contains a radio frequency module that receives a signal from the tool and sends it to the computer to display a torque-turns graph in real time. The bails (hydraulically actuated from the control panel) manipulates the pipe from the V-door to the well center and enables stabbing of the joint pin into the box prior to making up the connection. The compensation system is a set of hydraulic cylinders incorporated in the tool to cushion the weight of the tool and casing joint, helping to preserve the threads and enable higher quality makeups. The clamping system can be internal or external depending on the casing size being run. Internal gripping is mostly used for bigger casing sizes where the pipe is clamped from the ID of the pipe. External gripping, on the other hand, is mostly used for smaller pipe sizes in which the OD of the pipe is clamped, similar to conventional elevators. Courtesy Weatherford International.

Conventional equipment/tools

Conventional tools have been used for many years and have become recognized as the most common way (and for many years the only way) to run casing. Conventional equipment consists of several different tools. The hydraulic power tong (powered by a diesel or electric power unit) used to makeup or break out joints of casing. The tong is usually controlled manually by an operator who activates the levers located to one side of the tool, enabling him to control the speed of rotation and the application of torque. The tong operator works with a stabber who is positioned on the casing board (about 40 ft above the rig floor) and is in charge of aligning the casing joints being made up, making it easier to engage the pipe threads. To run the casing, an elevator and spider are also needed. The elevator is installed in the bails of the top drive while the spider is located on the rotary table. Both can be pneumatically or hydraulically activated (can be done manually) depending on the rig conditions and the requirements of the job. Other

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tools that are part of this equipment are the single-joint elevator (SJE); used to manipulate each joint from the catwalk and V-door to the well center, the stabbing guide; used to easily insert the pin into the box of the joint prior to make up, and the torque-turn monitoring system which is usually an ex-proof computer used to track and record, in real-time, the makeup process to ensure the pipe manufacturer’s criteria is followed to achieve an integral connection.

Next-generation tools

These tools are designed to take advantage of the rotational capabilities of the top drive. These automated casing running and drilling tools come in different sizes and complexity levels to fit every application. From powerful triple rigs in offshore environments to super-single rigs onshore, covering a wide range of operations. These advanced casing running and drilling tools enhance safety and increase performance by adding several features to the casing running operations. • Safety – Statistics have proven that tubular handling is an

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CEMENTING

1: Connection to top drive 2: Hydraulic bails 3: Single joint elevator (SJE) 4: Service loop (hydraulic hoses) 5: Internal clamping system 6: Packer cup 7: Centralizer 8: Mud saver valve (MSV) 9: Remote control panel

Figure CE-12: Most casing-running tools also incorporate a fill-up and circulation tool which is used to fill up or circulate mud throughout the casing string and the wellbore. Courtesy Weatherford International.

activity with one of the highest incident rates in the drilling industry. The latest casing running tools greatly reduce risks, because they usually combine several conventional tools into one, which can be remotely operated to keep personnel out of hazardous areas, resulting in a safer work environment. • Efficiency and performance – Conventional equipment has been used to run casing successfully for many years. However, the equipment has certain limitations, specifically when there are difficult hole conditions due to formation restrictions, tight spots, trouble zones, or when or when casing must be run in a deviated wells. When these conditions arise, it is particularly helpful to have a tool with the capabilities to rotate, reciprocate (move the pipe up and down), and push down the casing string while circulating. The combination of these capabilities will highly increase the chances to land the casing at the intended TD. Most of the latest casing running tools incorporate these features. Casing running tools can be either mechanical or hydraulic. Each category has different features available, depending on the tool model, size, manufacturer, and the application. Figure CE-11 shows a typical hydraulic tool with the main components are identified.

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All casing running tools, mechanical or hydraulic, are connected to the top drive saver sub or the lower internal blow out preventer (IBOP) by means of the top connection on the tool mandrel (a cross over is commonly used in between). The main requirement to use any of these tools is a top drive; otherwise the use of this technology is not possible because the tool takes advantage of the rotational capabilities of the top drive to transfer torque to the pipe. The tool can rotate using an incorporated swivel. The casing is clamped by slips/ grapples that can be hydraulically or mechanically activated depending on the tool used. The clamping mechanism can be internal or external. Some tools also provide a compensation system and a torque measurement system that are specially required to monitor and record the torque-turn real time behavior of the makeup when working with premium connections, ensuring connection integrity by following the pipe manufacturer’s criteria. Most of these tools also incorporate a fill-up and circulation tool which is used to fill up or circulate mud throughout the casing string and the wellbore (Figure CE-12). The mud flows through the ID of the mandrel of the tool to the pipe. The fill-up tool contains a centralizer (used to guide the fillup tool inside the pipe), a packer cup (a rubber that seals against the walls of the pipe allowing pressure build up to

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CEMENTING

CE–23

Figure CE-13: In addition to automated casing running and drilling tools, technology has developed a new generation of casing equipment Conventional tools have evolved to a mechanized phase that provides different levels of automation, depending on the needs of the customer and application. These tools can be controlled remotely through pneumatic, hydraulic or even electronic automation.

circulate the mud, and a mud saver valve (a valve used to avoid mud spillage when the tool is removed from the pipe).

Mechanized equipment

In addition to automated casing running and drilling tools, technology has developed a new generation of casing equipment (Figure CE-13). Conventional tools have evolved to a mechanized phase that provides different levels of automation, depending on the needs of the customer and application. These tools can be controlled remotely by means of pneumatic, hydraulic or even electronic automation. Some of this equipment can be integrated into the control systems of a rig and operated from the driller’s cabin. Higher grades of automation and larger equipment are deployed in offshore environments where there is often more space on the rig floor, and the safety requirements are usually the highest in the industry.

Cement evaluation

The objective of cement evaluation is to confirm the cement has been successfully placed around the casing and the goals of the cement job have been met. To properly perform a cement evaluation, the objectives of the cement job must be understood, and a decision made regarding how the

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success of the operation will be determined. The goal of a cement job may be casing support, zonal isolation, pressure isolation (associated with a successful shoe test) or other criteria. It is important, before cementing operations begin, to establish and document the goals of a cement job, the methods to be used to evaluate the job and the criteria to be met to ensure the job was successful. Regardless of the cementing objectives, and even before any testing is performed, the job history provides strong indicators regarding successes or problems. Assessment of a cement job is based on many factors: • Accurate displacement volumes and surface pressure measurements, and the agreement of measured values with those in the pre-job plan; • Adequate circulation and cleaning of the hole prior to cementing; • Centralization; • Casing movement during circulation and cementing; • Using a properly designed spacer and cement slurry; • No lost returns; • Mud properties, including gas units, on breaking circulation and CBU on resuming operations after cementing fall within expected range;

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CE–24

CEMENTING

• Hard cement drilled out or evidence of cement softness that might indicate contamination; • Wiper plugs released and seated normally; • Was the top wiper plug observed leaving the cement plug container? • Did the plug land at the expected displacement volume, did the float(s) hold? • Were one or more bottom wiper plugs used? • Were the plastic viscosity (PV) and yield point (YP) of the mud reduced prior to cementing? • As applicable, did fluid returns at surface occur at the appropriate displacement volume? • Was the planned cement slurry density target met? • Was a mud/spacer/cement slurry density and rheology hierarchy followed, was the spacer compatible with the cement slurry and the drilling fluid? • Was the differential (lift) pressure measured during the cementing operation consistent with the calculated value? • Were the cement slurry properties determined at the appropriate test conditions? • After drilling out of the shoe track, was the formation integrity test or leak-off test result within expected values? The most common reason for setting cement is to achieve zonal or pressure isolation. Because pressure and fluid containment is process-safety crucial, it is good practice and frequently a regulatory requirement to verify that isolation has been achieved. This may be done by several pressure tests: • Casing pressure test: Any time prior to drill out, the casing is pressure tested for integrity; • Liner top test: A positive or negative pressure test used to ensure liner top integrity; • Formation integrity test (FIT): Conducted after the shoe is drilled out, pressurizing up to a predetermined equivalent mud weight at the shoe, this tests if the shoe and the annulus immediately above it are well cemented and have the integrity to allow the next section of hole to be drilled; • Leak-off test: Conducted after the shoe is drilled out, this tests formation strength by pressuring up to the point of leak off, into a permeable zone or by fracture initiation. The actual conducting of pressure testing and the proper interpretation of formation integrity testing are beyond the scope of this chapter.

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Another common goal of cementing is casing support. Casing support requires the presence of any solid material in the annulus, but not necessarily 100% circumferential coverage of the casing. Sand, barite, hematite, or other settled solid material can provide casing support providing it occupies the annulus. Collapsed formations can also provide casing support. In horizontal or high-angle wells, casing support can be established by the casing being in contact with the formation. If there is doubt about cement placement in the annulus, or doubt about the cement quality, a cement bond log (CBL) may be necessary. The CBL actually measures acoustic coupling; the presence of mechanical coupling between the cement, formation and pipe is inferred from the ability sound waves have to travel through the interface between materials. A fluid-filled annulus will show up as a high amplitude on the CBL, because there is nothing to dampen the vibration of the casing set up by the tool. Similarly, contamination of the cement with mud, other wellbore materials or both decreases its density and strength, and changes its acoustic properties, decreasing the ability of the cement sheath to control the “ringing” of the casing during logging. Interpreting cement bond logs requires engaging an expert. In one case, a sonic log can show “bonding” to a formation when the casing is simply laying against the formation, thus making a path for the sound. Conversely, the perception of “no cement” or “poor cement” can occur if testing is conducted prior to cement being set, which can occur for several reasons: • Over-estimation of the well’s bottomhole temperature; • Over-retardation of the cement slurries; • Underestimation of time required for a wellbore to heat up to bottomhole temperature after cement placement. The cement in the annulus will appear not to be set or deemed poor quality because of the low strength of the cement at the time of logging.

Outlook

Advances in the development of more effective cement sheath evaluation techniques continue to be made. Proper use of the newer techniques, incorporated with a clear concept of cement slurry design and strength development, demonstrate improved cement sheath quality and quantity. Correct application of the available cement evaluation tools and techniques requires an understanding of the measurement principles involved and the developmental stages of cement structure.

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CH

CHAINS AND SPROCKETS

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

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CHAPTER

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CHAINS AND SPROCKETS

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. As technology continues to develop, this manual will be updated. It is important that the user continue to update their knowledge through research and study. Principal Author John R. Wilbur, Timken-Drives LLC Reviewers Chuck Springman, Diamond Chain Chris Wilson, Diamond Chain

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CH–ii

CHAINS AND SPROCKETS

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: 978-0-9906220-0-0

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CHAINS AND SPROCKETS Contents CHAPTER CH

CH-iii

Contents

CHAINS AND SPROCKETS Construction and specifications............................... CH-1 Multiple strand chain.............................................CH-1 Connecting links......................................................CH-2 Offset links................................................................CH-2 Applicable standards & specifications................... CH-2 ANSI Standard ASME B29.1................................CH-2 API Specification 7F 8th edition.........................CH-2 Roller chain numbering & dimensions.................... CH-3 General dimensions............................................... CH-3 Roller chain numbering......................................... CH-3 Sprockets......................................................................... CH-7 Sprocket types..........................................................CH-7 Sprocket tooth form and diameters...................CH-7 Installation...................................................................... CH-7 Check condition of components.........................CH-7 Align shafts and sprockets...................................CH-7 Install chain.............................................................. CH-9 Connecting links..................................................... CH-9 Offset links............................................................... CH-9 Adjust chain tension.............................................. CH-9

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Ensure adequate clearance............................... CH-10 Provide adequate lubrication............................ CH-10 Install guards.......................................................... CH-10 Lubrication.................................................................... CH-10 Lubrication flow.................................................... CH-10 Lubricant characteristics.................................... CH-10 Types of lubrication............................................. CH-11 Type I: Manual or drip lubrication......... CH-11 Type 2: Bath or disc lubrication............. CH-11 Type 3: Oil stream lubrication................CH-12 Chain casings......................................................... CH-13 Maintenance................................................................ CH-14 Inspection and service schedule..................... CH-14 Inspect lubrication system................................ CH-15 Inspect for damaged chains or sprockets..... CH-15 Inspect for chain wear........................................ CH-16 Inspect for sprocket wear.................................. CH-16 Inspect for sprocket misalignment................. CH-17 Inspect guards....................................................... CH-17 Glossary.........................................................................CH-21

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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

CHAINS AND SPROCKETS

Construction and specifications Roller chain construction and types

General single strand. Roller chain is a series of alternating pin links and roller links in which the pins can turn inside the bushings (Figure CH-1).

CH–1

the cotter pins from being thrown out of the chain by high speed or vibration.

CH-3

CH-4

Figure CH-3: Riveted-type single-strand chain. Figure CH-4 shows a cottered-type single-strand chain. Figure CH-1: Roller chain construction.

The pin link (Figure CH-2) consists of two pins (A) assembled into two pin link plates (C) with controlled press fits to prevent the pins from rotating in the pin link plates. The roller link (Figure CH-2) consists of two bushings (B) assembled into two roller link plates (E) with controlled press fits to prevent the bushing from rotating in the roller link plates. Two rollers (D) are assembled, free to turn, on the outside of the bushings.

Multiple strand chain. Multiple strand chain consists of two or more single strands assembled on common pins. Multiple strand chains may be furnished with either riveted or cottered-type pins (Figures CH-5 and CH-6). Multiple-strand chains may also be furnished with either slip-fit or press-fit plates (Figure CH-7).

CH-5

CH-6

Figure CH-2: Pin link and roller link.

As the chain articulates, turning occurs only between the pin and bushing, so they are primarily subject to wear. The link plates mainly bear the tensile loads and securely locate the pins and bushings. The rollers absorb the impact and provide rolling action when the chain joint engages the sprocket tooth. Roller chain may be furnished with either riveted or cottered-type pins (Figures CH-3 and CH-4). Riveted-type pins have both ends riveted or swagged. Cottered-type pins have one end riveted or swagged and the other end crossdrilled to accept a cotter pin. Cotter pins for roller chain are carefully formed to fit snugly in the hole and are often heat-treated for high strength and toughness. This prevents

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CH-7

Figure CH-5: Multiple strand chain furnished with riveted pins. Figure CH-6: Multiple strand chain with cotter pins. Figure CH-7: Multiple-strand chain may have either press-fit or slip-fit center plates.

Slip-fit center plates have holes that are slightly larger than the pin and can be easily moved, or slipped, on and off of the pins. Slip-fit center plate multiple-strand chain can be readily disconnected in the field at any cottered pin link in the chain.

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CH–2

CHAINS AND SPROCKETS

Press-fit center plates have holes that are slightly smaller than the pin and must be driven, or pressed, on and off of the pins. Press-fit center plate multiple-strand chain normally can be disconnected in the field only at the connecting link with special pressing equipment. Both types have their advantages. Contact the chain manufacturer or representative for specific applications and benefits.

Connecting links

A connecting link is a pin link with a quick detachable retainer that normally is used to connect the two ends of a chain together to make it endless on a drive. There are three common types of connecting links with respect to retainers. They are the spring-clip type (Figure CH-8) the split cotter type, (CH-9) and single hook cotter type, (CH-9A).

Figure CH-10: Offset link.

CH-8

Figure CH-11: Two-pitch offset section.

ing links can be slip fit or press fit. The single-pitch offset link has a slip-fit, removable “D” flatted pin with a flat milled on one end that fits into a “D” shaped hole in the link plate (Figure CH-10).

CH-9

An offset section may be a two-pitch (Figure CH-11) press fit assembly.

CH-9A

NOTE: Avoid the use of offset links whenever possible. If an offset link is required, an offset section should be used because the press-fit pins give it higher working capacity. Figure CH-8 (top) shows spring-type clip, while Figure CH-9 (center) shows the split cotter type and Figure CH-9A shows the single-hook cotter type. The cotter-type connecting links look and sometimes are the same as the pin link in cottered-type chain. There also are two common types of connecting links with respect to cover plates or CO link plates. They are the pressfit type in which the cover plate has an interference fit on the pins. The press-fit cover plate connecting link has the working capacity that is virtually equal to single-strand or workslip multiple-strand chain and it is preferred for maximum capacity rating. The slip-fit cover plate connecting link used in conjunction with fatigue resistant slip fit center plates and where ease of coupling and uncoupling is important will provide ample working load in 95% of the applications.

Offset links

Offset links are combination links with a specially designed bend in the middle so that one end functions as pin link and the other end as a roller link. Offset links as with connect-

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Applicable standards & specifications ANSI Standard ASME B29.1

The ANSI standard ASME B29.1 defines power transmission roller chain, establishes a numbering system, and dictates limiting dimensions, chain length tolerance, and minimum chain tensile strength. This standard also defines sprockets for roller chain and sets tolerances or limits on critical sprocket dimensions.

API Specification 7F 8th edition

The API specification 7F refers to ANSI B29.1 for chain and sprocket definition, numbering, dimensions, and chain tensile strength. In addition, API specification 7F dictates minimum dynamic test requirements per the conformance test described in ASME B29.26 and minimum dynamic strength and pin and bushing press-out-forces approved in 2010 for each chain size. Note: There are no approved API offset/half links.

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CHAINS AND SPROCKETS

Roller chain numbering & dimensions General dimensions

Table CH-1 lists chains commonly used in the oilfield. The general dimensions of ASME\B29.1 precision standard roller chain are shown in Tables CH-1A (in.) and CH-1B (mm). The most important basic dimension of a roller chain is the pitch (P) which is the nominal distance between consecutive chain pins. Other key dimensions are proportional to the pitch. The roller diameter (Dr) and roller width (W) are approximately 5/8 of the pitch. The pin diameter (Dp) is approximately 5/16 of the pitch. The link plate thickness (LPT), for Standard Series chain, is approximately 1/8 of the pitch. The link plate thickness (LPT), for Heavy Series chain, is that of the next larger pitch standard series chain. The measuring load and minimum ultimate tensile strength of multiple strand chains is the single strand values multiplied by the number of strands. Measuring load is limited to a maximum of 1,000 lb. (4,448 N).

Roller chain numbering

Standard roller chains are designated by a numbering system which is defined in ANSI Standard ASME B29.1. This numbering system is based on standard dimensions that are pitch proportional; that is the major dimensions of a standard roller chain are proportional to the chain pitch.

Table CH-1: Common oilfield chains.

Pitch

1/8 ths

Std. No.

Heavy No.

0.25

2

25-Rollerless

none

0.375

3

35-Rollerless

none

0.50

4

41-Light Duty

none

0.50

4

40

none

0.625

5

50

none

0.75

6

60

60H

1.00

8

80

80H

1.25

10

100

l00H

1.50

12

120

120H

1.75

14

140

140H

2.00

16

160

160H

2.25

18

180

180H

2.50

20

200

200H

3.00

24

240

240H

Standard single-strand, single-pitch chain is identified by a two- or three-digit number. The right-hand digit is a zero for chain of standard proportions and containing a free roller, a 1 for lightweight chain, and 5 for rollerless bushing chain. The lefthand digit or digits indicate the number of ⅛-in. increments in the pitch. For example, a standard ¾-in. pitch roller chain has 6 increments of ⅛-in. in the pitch, so the number is 60. “Heavy” series chains have link plate thickness equal to the next larger standard size chain and are designated by the letter H immediately following the standard chain number. IE; 80H or 160H. Multiple-strand chain is designated by a hyphen and one or two digits indicating the number of chain strands. IE: 60-10 or 120H-3.

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CH–3

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CH–4

CHAINS AND SPROCKETS

, in. , in. , in. , in. , in.

Figure CH-12A: General chain dimensions. See Table CH-1A.

Table CH-1A: General chain dimensions, in.

Link Plate Thickness (LPT) Standard Chain No.

Pitch Max. Roller Nominal P Diam Dr Width W(1)

Nominal Pin Diam. Dp

Standard Series

Heavy Searies

Measuing Load lb(2)

Lenghth Tolerance in./ft

Min. Ultimate Tensile Strength Standard and Heavy Series lb(3)

25

0.250 0.130(4)

0.125

0.0905

0.030

—

18

0.031

780

35

0.375 0.200(4)

0.188

0.414

0.050

—

18

0.022

1,760

41

0.500

0.250

0.141

0.050

—

18

0.019

1,500

0.306

40

0.500

0.312

0.312

0.156

0.060

—

31

0.019

3,125

50

0.625

0.400

0.375

0.200

0.080

—

49

0.018

4,880

60

0.750

0.469

0.500

0.234

0.094

0.125

70

0.017

7,030

80

1.000

0.625

0.625

0.312

0.125

0.156

125

0.016

12,500

100

1.250

0.750

0.750

0.375

0.158

0.187

195

0.016

19,530

120

1,500

0.875

1,000

0.437

0.187

0.219

281

0.015

28,125

140

1.750

1.000

1.000

0.500

0.219

0.250

383

0.015

38,280

160

2.000

1.125

1.250

0.562

0.250

0.281

500

0.015

50,000

180

2.250

1.406

1.406

0.687

0.281

0.312

633

0.015

63,280

200

2.500

1.562

1.500

0.781

0.312

0.375

781

0.015

78,125

240

3.000

1.875

1.875

0.937

0.375

0.500

1000

0.015

112,500

NOTES: (1) See ANSI ASME B29.1 minimum dimensions (2) For single-strand chain. (3) For single-strand chain (4) Bushing diameter, as these chains have no rollers.

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CHAINS AND SPROCKETS

CH–5

, mm , mm , mm , mm , mm

Figure CH-12B: General chain dimensions. See Table CH-1B.

Table CH-1B: General chain dimensions, in. (mm)

Link Plate Thickness (LPT) Standard Chain No.

Pitch Max. Roller Nominal P Diam Dr Width W(1)

Nominal Pin Diam. Dp

Standard Series

Heavy Searies

Measuing Load N(2)

Lenghth Tolerance MM/M

Min. Ultimate Tensile Strength Standard and Heavy Series N(3)

25

6.35

3.30(4)

3.18

2.30

0.76

—

80.1

2.58

3,470

35

9.52

5.08(4)

4.78

3.58

1.27

—

80.1

1.83

7,825

41

12.70

7.77

6.35

3.58

1.27

—

80.1

1.58

6,672

40

12.70

7.92

7.92

3.96

1.52

—

137.9

1.58

13,900

50

15.88

10.16

9.52

5.08

2.03

—

218.0

1.50

21,270

60

19.05

11.91

12.70

5.94

2.39

3.18

311.4

1.42

31,270

80

25.40

15.87

15.88

7.92

3.18

3.96

556.0

1.33

55,600

100

31.75

19.05

19.05

9.52

3.96

4.75

867.4

1.33

86,870

120

38.10

22.22

25.40

11.10

4.75

5.56

1250.0

1.25

125,100

140

44.45

25.40

25.40

12.70

5.56

6.35

1704.0

1.25

170,270

160

50.80

28.57

31.75

14.27

6.35

7.14

2224.0

1.25

222,400

180

57.15

35.71

35.71

17.45

7.14

7.92

2816.0

1.25

281,470

200

63.50

39.67

38.10

19.84

7.92

9.52

3474.0

1.25

347,500

240

76.20

47.62

47.62

23.80

9.52

12.70

5004.0

1.25

520,400

NOTES: (1) See ANSI ASME B29.1 minimum dimensions (2) For single-strand chain (3) For single-strand chain (4) Bushing diameter, as these chains have no rollers

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CH–6

CHAINS AND SPROCKETS

Figure CH-13: Single and multiple stand chains.

Table CH-2A: Maximum chain width dimensions, in. (N−1 ) K + 2B.

Table CH-2B: Maximum chain width dimensions, mm (N−1 ) K + 2B. (cont’d)

Standard Chain No.

Number of Chain Strands 1

2

3

4

6

8

Standard Chain No.

25

0.38

0.63

0.88

1.14

1.64

2.14

35

0.68

1.08

1.48

1.88

2.67

3.47

41

0.74

—

—

—

—

40 50 60

0.84 0.96 1.28

1.36 1.68 2.14

1.94 2.40 3.04

2.50 3.10 3.94

80 100 120

1.58 1.90 2.30

2.74 3.30 4.10

3.90 4.72 5.88

5.04 6.12 7.68

140 160 180 200 240

Number of Chain Strands 1

2

3

4

6

8

25

9.6

16.0

22.3

28.9

41.6

54.3

35

17.2

27.4

37.5

47.7

67.8

88.1

—

41

18.7

—

—

—

—

—

3.65 4.54 5.78

4.75 5.95 7.55

40 50 60

21.3 24.3 32.5

34.5 42.6 54.3

49.2 60.9 77.2

63.5 92.7 78.7 115.3 100.0 146.8

120.6 151.1 191.7

7.37 9.00 11.30

9.70 11.80 14.85

80 100 120

40.1 48.2 58.4

69.5 99.0 128.0 187.1 83.8 119.8 155.4 228.6 104.1 149.3 195.0 287.0

246.3 299.7 377.1

2.54 2.94 3.54 3.82 4.40

4.46 6.38 8.30 12.25 5.26 7.56 9.86 14.55 6.00 8.60 11.18 16.45 6.62 9.60 12.30 18.00 7.85 11.31 14.77 21.69

16.15 19.10 21.55 23.52 —

140 160 180 200 240

64.5 74.6 89.9 87.0 111.7

113.2 133.6 152.4 168.1 199.3

162.0 192.0 218.4 243.8 287.2

311.1 369.5 417.8 457.2 550.9

410.2 485.1 547.3 597.4 ­—

60H 80H 100H

1.41 1.71 2.03

2.39 2.99 3.55

3.42 4.28 5.10

4.44 5.54 6.62

6.53 8.12 9.75

8.55 10.70 12.80

60H 80H 100H

35.8 43.4 51.5

60.7 75.9 90.1

86.8 112.7 165.8 108.7 140.7 206.2 129.5 168.1 247.6

217.1 271.7 325.1

120H 140H 160H

2.43 2.67 3.07

4.35 4.71 5.51

6.26 6.76 7.94

8.18 12.05 8.80 13.00 10.36 15.30

15.85 17.15 20.10

120H 140H 160H

61.7 67.8 77.9

110.4 159.0 206.5 306.0 119.6 171.7 223.5 330.2 139.9 201.6 263.1 388.6

402.5 435.6 510.5

180H 200H 240H

3.67 4.07 4.90

6.25 8.98 11.68 17.20 7.12 10.35 13.30 91.50 8.85 12.81 16.77 24.69

22.55 25.52 —

180H 200H 240H

93.2 158.7 228.0 296.6 436.8 103.3 180.8 262.8 337.8 495.3 124.4 224.7 325.3 425.9 627.1

572.7 648.2 —

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Copyright © 2015

210.8 250.4 283.9 312.4 275.1

CHAINS AND SPROCKETS

Sprockets

CH–7

to proper meshing with the chain. The outside diameter may vary depending on the type of cutter used. The approximate outside diameter may be calculated as follows:

Sprocket types

There are four types of sprockets covered by ANSI B29.1 and API SPEC 7F, and they are shown in Figure CH-14.

Outside Diameter = Pitch (0.6 + cot (180° ⁄ Nt)) Sprocket flange thickness and tooth section profile Sprocket flange thickness and tooth section profile dimensions are as shown in Table CH-4.

Caliper Diamete

r r

Caliper Diamete

Figure CH-14: Types of Sprockets.

Sprocket tooth form and diameters

The ANSI Standard sprocket tooth form is described in ANSI B29.1 and is too detailed to show here. Sprocket diameters are described in the following paragraphs and nominal pitch diameters and outside diameters are listed in an appendix. The tolerances and limits for sprocket diameters are contained in ANSI B29.1 and not repeated here. Pitch Diameter. The pitch diameter of a sprocket is the diameter of a circle followed by the centers of the chain pins as the sprocket revolves in mesh with the chain, and is a function of the chain pitch and of the number of teeth in the sprocket. The pitch diameter may be calculated as follows: Pitch Diameter =

Pitch

(

Sin 180° Nt

(

, (L)

Where Nt = Number of teeth This is a theoretical dimension, not directly measurable.

Maximum Hub Diameter Bottom Diameter Pitch Diameter Outside Diameter

Figure CH-15: Representation of key sprocket parameters.

Installation Check condition of components

Check shafts and bearings and assure that they are in good condition. Check shaft supports and bearing mounts and be sure they are correctly positioned and secure. If the chain is not new, be sure that it is clean and well lubricated. If sprockets are not new, be sure that they are not excessively worn or otherwise damaged.

Bottom diameter. The bottom diameter of a sprocket is the diameter of a circle tangent to the bottoms of the tooth spaces. The tolerance on the bottom diameter must be entirely negative to ensure that the chain will mesh properly with the sprocket teeth.

Align shafts and sprockets

Caliper Diameter. Since the bottom diameter of a sprocket with an odd number of teeth cannot readily be measured directly, this catalog lists caliper diameter which enable calculating the dimensions across the bottoms of tooth spaces most nearly opposite. As on bottom diameters, tolerances on caliper diameters must be entirely negative.

1. T  he shafts must be parallel within fairly close angular limits. This is readily accomplished by using a machinist’s level and feeler bars (See Figure CH-1). First, using the machinist’s level, make sure that both shafts are level or in the same plane. Then, using the feeler bars, make sure that the shafts are parallel in that plane. If the shafts can float axially, lock them in the normal running position before attempting to align them.

Outside Diameter. The outside diameter of a sprocket is comparatively unimportant, as the tooth length is not vital

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Good drive alignment is necessary to prevent uneven loading across the width of the chain and damaging wear between the sprocket teeth and the roller link plates of the chain. Aligning the drive is a straightforward, two-step procedure:

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CH–8

Chain  data  for  all  sprockets IADC Drilling Manual

ANSI  &   Pitch   Roller   Diamond  # (P) width  (W)

Roller   Diam.

*h

*g

*RC

Single   strand  t1   and  THR

Copyright © 2015

25 35 41 40 50 60 80 100 120 140 160 180 240

0.250 0.375 0.500 0.500 0.625 0.750 1.000 1.250 1.500 1.750 2.000 2.250 3.000

0.125 0.188 0.250 0.312 0.375 0.500 0.625 0.750 1.000 1.000 1.250 1.406 1.875

0.130 0.200 0.306 0.312 0.400 0.469 0.625 0.750 0.875 1.000 1.125 1.406 1.875

0.12 0.19 0.25 0.25 0.31 0.38 0.50 0.62 0.75 0.88 1.00 1.12 1.50

0.03 0.05 0.06 0.06 0.08 0.09 0.12 0.16 0.19 0.22 0.25 0.28 0.38

0.26 0.40 0.53 0.53 0.66 0.80 1.06 1.33 1.59 1.86 2.12 2.39 3.19

0.110 0.168 0.227 0.284 0.343 0.459 0.575 0.692 0.924 0.924 1.156 1.301 1.738

60H

0.750 1.000 1.250 1.500 1.750 2.000 2.500

0.500 0.625 0.750 1.000 1.000 1.250 1.500

0.469 0.625 0.750 0.875 1.000 1.125 1.562

0.37 0.50 0.62 0.75 0.88 1.00 1.25

0.09 0.12 0.16 0.19 0.22 0.25 0.31

0.80 1.06 1.33 1.59 1.86 2.12 2.65

0.459 0.575 0.692 0.924 0.924 1.156 1.389

Double  and  triple  strand t2

M2

M3

For  4  or  more  strands t4

M2

Standard  series  chain  sprockets 0.107 0.162 † 0.275 0.332 0.444 0.557 0.669 0.894 0.894 1.119 1.259 1.682

0.359 0.561 † 0.841 1.045 1.341 1.710 2.077 2.683 2.818 3.424 3.851 5.140

0.611 0.960 † 1.407 1.758 2.238 2.863 3.485 4.472 4.742 5.729 6.443 8.598

0.096 0.149 † 0.256 0.311 0.418 0.526 0.633 0.848 0.848 1.063 1.197 1.601

0.348 0.548 † 0.822 1.024 1.315 1.679 2.041 2.637 2.772 3.368 3.789 5.059

M3

Machining   Hot-­‐rolled   tolerance  on   tolerance  on   t  &  M tHR

M4

M5

M6

M8

K

0.600 0.947 † 1.388 1.737 2.212 2.832 3.449 4.426 4.696 5.673 6.381 8.517

0.852 1.346 † 1.954 2.450 3.109 3.985 4.857 6.215 6.620 7.978 8.973 11.975

1.104 1.745 † 2.520 3.163 4.006 5.138 6.265 8.004 8.544 10.283 11.565 15.433

1.356 2.144 † 3.086 3.876 4.903 6.291 7.673 9.793 10.468 12.588 14.157 18.891

1.860 2.942 † 4.218 5.302 6.697 8.597 10.489 13.371 14.316 17.198 19.341 N/A

0.252 0.399 † 0.566 0.713 0.897 1.153 1.408 1.789 1.924 2.305 2.592 3.458

-007 -008 -009 -010 -011 -012 -014 -016 -019 -020 -019 -020 -025

-021 -027 -032 -035 -036 -036 -040 -046 -057 -057 -062 -068 -087

2.474 3.092 3.711 4.696 4.958 5.935 7.444

3.502 4.375 5.250 6.620 7.013 8.371 10.527

4.530 5.568 6.789 8.544 9.068 10.807 13.610

5.558 6.941 8.328 10.468 11.123 13.243 16.693

7.614 9.507 11.406 14.316 15.233 18.115 22.859

1.028 1.283 1.539 1.924 2.055 2.436 3.083

-011 -012 -014 -016 -016 -019 -021

-036 -040 -046 -057 -057 -062 -072

Heavy  series  chain  sprockets 80H 100H 120H 140H 160H 200H

TABLE CH-4: FLANGE THICKNESS AND TOOTH SECTION PROFILE The l and M dimensions are for machined finish.

The T tolerances apply to hot-rolled plates used for plate sprockets and welded-hub sprockets. *Exact dimensions for sprocket tooth chamfers are not of critical importance. For nonstandard and narrow width chains, the dimension “g” is 1/6 P but should † No. be no 41greater chain isthan not 1/3W. made inh multiple = .5P strands.

0.444 0.557 0.669 0.894 0.894 1.119 1.344

1.472 1.840 2.208 2.818 2.949 3.555 4.427

2.500 3.123 3.747 4.742 5.004 5.991 7.510

0.418 0.526 0.633 0.848 0.848 1.063 1.278

1.446 1.809 2.172 2.772 2.903 3.499 4.361

CHAINS AND SPROCKETS

Figure CH-16: Sprocket schematics showing key measurement variables.

CHAINS AND SPROCKETS

CH–9

Figure CH-17: Align shafts.

Figure CH-18: Align sprockets.

Most single-strand drives will perform acceptably if the shafts are parallel and in the same plane within .050 in./ft or ¼ degree. However, high-speed, high-horsepower, or multiple-strand chain drives should be aligned within the tolerance obtained from the following formula:

together on one sprocket, using the sprocket teeth to hold the chain ends in position. With large heavy chains it may be necessary to block the sprockets to prevent them from turning while the chain ends are brought together. Insert the pins of the connecting link through the bushing holes to couple the chain endless. With long chain spans, it may be necessary to support the chain with a plank or rod while the connection is made. Then, install the cover plate and the spring clip, hook cotter or cotters. After the fasteners have been installed, the ends of the pins should be pressed back until the fasteners are snug against the cover plate. This restores the intended clearances across the chain and allows the joint to flex freely as it should. Again, the connection procedure is well described in the brochure, “Connect & Disconnect Instructions for ANSI B29.1 Chains.” (www.mpta.org)

.01 C Tolerance (in./ft) = 12 P n Where: C = center distance, in. P = chain pitch, in. n = number of chain strands 2. The sprockets must be mounted on the shafts as closely in line axially as practicable. This normally is done with a straightedge or a length of piano wire (See Figure CH-18). In practice, the maximum amount of axial misalignment is obtained from the following formula: Max. Offset (in.) = 0.045 P Where:

P = chain pitch, in.

This formula applies to both single and multiple strand chains.

Install chain

A new chain should be kept in its box until ready for installation to preserve the factory lubrication and prevent contamination by dirt and debris. If the new chain is not the correct length, in pitches, to fit on the drive, a long stock length may have to be shortened or several sections may have to be connected to make a chain the correct length. A brochure entitled “Connect & Disconnect Instructions for ANSI B29.1 Roller Chains,” published by the American Chain Association, describes how to do this. This can be downloaded free at www.MPTA.org. All chain and links in a given drive should be from the same manufacturer—otherwise, the drive may surge or run rough. Fit the chain around the sprockets and bring the free ends

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Connecting links

Connecting links should use interference fit cover plates because their capacity is virtually the same as the rest of the chain. The use of fatigue resistant slip fit cover plates are acceptable for ease of assembly and will work fine for 95% of applications.

Offset links

The use of offset links should be avoided whenever possible because their capacity can be much less than the rest of the chain, up to 40% less. Offsets are not API approved or tested.

Adjust chain tension

First, turn one sprocket to tighten one span of chain. Then use a straightedge and scale to measure the total mid-span movement in the slack span (Figure CH-19). Adjust the drive center distance or the idler to produce 4 to 6% mid-span movement for drives that are on horizontal centers to 45 degrees inclined, and 2 to 3% for drives that are inclined 45 degrees to vertical, subject to high shock loads, or on fixed centers.

Copyright © 2015

CH–10

CHAINS AND SPROCKETS Table CH-5: Recommended possible mid-span movement. AC in inches.

Target length between sprockets (in.) Drive Center Line

10

20

30

50

70

100

Horizontal 45°

0.4–0.6

0.8–1.2

1.2–1.8

2.0–3.0

2.8–4.2

4.0–6.0

45° to Vertical

0.2–0.3

0.4–0.6

0.6–0.9

1.0–1.5

1.4–2.1

2.0–3.0

Ensure adequate clearance

wear life. In addition to resisting wear between the pin and bushing, an adequate flow of lubricant smooths the engagement of the chain rollers with the sprocket, cushions roller-to-sprocket impacts, dissipates heat, flushes away wear debris and foreign materials, and retards rust.

Provide adequate lubrication

The lubrication should be applied to the upper edges of the link plates in the lower span of the chain shortly before the chain engages a sprocket (Figures CH-20 and CH-21). Gravity and centrifugal force both will aid in carrying the lubricant to the critical pin and bushing surfaces. Surplus lubricant spilling over the link plate edges will supply the roller and bushing surfaces.

Check the drive carefully to ensure that there is no contact between the drive and adjacent objects. Ample clearance must be provided to allow for chain pulsations, chain elongation from wear, and possible shaft-end float.

Before starting the drive, be sure that the specified lubrication system is working properly. See the section on Lubrication for details.

Install guards

If the roller chain drive does not run in a chain casing, it should be enclosed by a guard that will prevent people from being injured by inadvertent contact with moving components of the drive. More detailed information about guards can be found in the ANSI Standard ASME B15.l; Safety Standard for Mechanical Power Transmission Apparatus. Before installation, inspect the guard to be sure it is not broken or damaged, especially at or near the mounting points. Then, install the guard; making sure that all fasteners are secure and all safeguarding devices (such as presence sensors and interlocks) is functioning.

Lubrication Lubrication flow

Each joint in a roller chain is a journal bearing, so it is essential that the pin and bushing surfaces receive an adequate amount of the proper lubricant to achieve maximum

Figure CH-20: Guide to lubrication.

Lubricant characteristics off

Figure CH-19: Chain tension adjustment.

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Figure CH-21: Lubricate on the inside of the chain.

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CHAINS AND SPROCKETS

CH–11

Table CH-6 Recommended Grate

Temperature, Deg. F (Deg C)

SAE 5

-50 to + 50 (-46 to + 10)

SAE 10

-20 to + 80 (-29 to + 27)

SAE 20

+10 to + 110 (-12 to + 43)

SAE 30

+20 to + 130 (- 7 to + 54)

SAE 40

+30 to + 140 (- 1 to + 60)

SAE 50

+40 to + 150 (+ 4 to + 66)

Note: When the temperature range permits a choice, the heavier grade should be used. Lubricants for roller chain drives should have the following characteristics: • Sufficiently low viscosity to penetrate to the critical internal surfaces; • Sufficiently high viscosity or appropriate additives to maintain the lubricating pin under prevailing bearing pressures; • Clean and free from corrosives. • Capability to maintain lubricating qualities under the prevailing operating conditions. The requirements usually are met by a good grade of non-detergent, petroleum-based oil. Detergents normally are not necessary, but anti-foam, anti-rust, or film-strength improving additives often are beneficial. Heavy oils or greases should not be used because they are too thick to penetrate to the internal surfaces of the chain. The recommended oil viscosity for various surrounding temperature ranges is shown in Table CH-6.

Types of lubrication

There are three types of lubrication for roller-chain drives. The recommended type is based on chain speed and is selected from Table CH-7. These should be regarded as minimum lubrication requirements. The use of a better type may be beneficial.

Type 1: Manual or drip lubrication

For manual lubrication, oil is applied periodically with a brush or spout can, preferably once each 8 hours of operation. The time between applications may be longer than 8 hours, if it has proven adequate for that particular drive. The volume and frequency of oil application must be sufficient to prevent a red-brown (rust) discoloration of the oil in the joints. The red-brown discoloration indicates that the lubrication in the joints is inadequate. When rust discoloration is found, one should remove, clean, re-lubricate, and reinstall the chain before continuing operations. For drip lubrication, oil is dripped between the link plate

IADC Drilling Manual

Figure CH-22: Drip-free lubrication.

edges from a drill lubricator. Drip rates range from 4 to 20 drops/min or more, depending on chain speed. Here again, the drip rate must be sufficient to prevent a red-brown (rust) discoloration of the lubricant in the chain joints. Care must be taken to avoid misdirection of the oil drops by windage. For multiple strand chains, a distribution pipe is needed to feed oil to all link plates, and a wick packing is usually required to distribute oil uniformly to all the holes in the pipe (Figure CH-22).

Type 2: Bath or disc lubrication

For oil bath lubrication, a short section of the lower strand of the chain runs through a sump of oil in the drive housing (Figure CH-23). The oil level should just reach the pitch-line of the chain at its lowest point in operation. Long sections of chain running through the oil bath, as in a nearly horizontal lower span, should be avoided because it can cause oil foaming and overheating. For slinger-disc lubrication, the chain operates above the oil level. The disc picks up oil from the sump and slings it against a collector plate. Then the oil usually flows into a trough which applies it to the upper edges of the link plates in the lower span of the chain (Figure CH-24). The diameter of the disc should produce rim speeds to pick up the oil effectively, while higher speeds may cause oil foaming or overheating. For both oil bath and slinger-disc lubrication, the temperature of the oil bath and the chain should not exceed 180°F. Also, the volume of oil applied to the chain must be great enough to prevent a red-brown (rust) discoloration of the lubricant in the chain joints. For both oil bath and slinger-disc lubrication, the oil level in the sump should be checked after each eight hours of running time, and oil added when needed. At the same time the system

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CH–12

CHAINS AND SPROCKETS

Table CH-7: Lubrication type for pitch and speed Chain Pitch

Chain speed, fpm (m/min.) lubrication type

in.

(mm)

Type 1

Type 2

Type 3

0.50

(12.70)

Up to 290(88)

Up to 2200(670)

Over 2200(670)

0.625

(15.88)

240(73)

1930(588)

1930(588)

0.75

(19.05)

210(64)

1740(530)

1740(530)

1.00

(25.40)

170(52)

1480(451)

1480(451)

1.25

(31.75)

145(44)

1300(396)

1300(396)

1.50

(38.10)

125(38)

1170(357)

1170(357)

1.75

(44.45)

110(34)

1080(329)

1080(329)

2.00

(50.80)

100(30)

1000(305)

1000(305)

2.25

(57.15)

90(27)

930(283)

930(283)

2.50

(63.50)

85(26)

880(268)

880(268)

3.00

(76.20)

75(23)

790(241)

790(241)

Figure CH-23: Oil bath lubrication.

should be checked for leaking, foaming, or overheating.

Type 3: Oil stream lubrication For oil stream lubrication, a pump delivers oil under pressure to nozzles that direct an oil stream or spray onto the chain. The oil should be applied evenly across the width of the chain, and be directed onto the lower span from inside the chain loop (Figure CH-25). Excess oil collects in the bottom of the casing and is returned to the pump suction reservoir. A pressure-regulating valve may be used to return excess pump discharge to the reservoir. Oil cooling may be by ra-

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Figure CH-24: Slinger-disc lubrication

diation from the external surfaces of the reservoir or by a separate heat exchanger. Oil stream lubrication is always recommended for chains running at relatively high speeds and loads, and is absolutely essential for roller chains operating in the indicated galling region for any extended period.

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CHAINS AND SPROCKETS

CH–13

Table CH-8: Required oil flow for chain drives.

Horsepower Transmitted

Figure CH-25: Oil stream lubrication.

Minimum oil flow (gal/min)

50

1/4

100

1/2

150

3/4

200

1

250

1 1/4

300

1 1/2

400

2

500

2 1/2

600

3

700

3 1/4

800

3 3/4

900

4 1/4

1000

4 3/4

1500

7

2000

10

Figure CH-26: Typical oil-retaining chain casing.

The oil stream not only lubricates the chain, but also cools the chain and carries away wear debris from a drive chain being operated at or near full rated capacity. Table CH-8 shows the minimum oil flow rate based on the amount of horsepower transmitted. Here again, the oil level in the sump should be checked after each eight hours of operation time and oil added when needed. At the same time the system should be checked for leaking and overheating.

Chain casings

Chain casings (Figure CH-26) are used to facilitate lubrication and to protect the drive from being damaged by debris or contamination. Chain casings are usually made of sheet metal, stiffened by steel angles or embossed ribs, and have access doors or panels for inspection and maintenance of the drive.

chain wear elongation accumulates in the slack span, chain sag can become great enough to allow the chain to strike the bottom of the casing, damaging both the chain and casing. Casing clearance for maximum wear elongation percentages may be determined from Figure CH-27. In addition to the clearance to allow for chain sag, there should be at least 3 inches of clearance around the periphery of the chain and 3/4 inch on each side of the chain. When a chain casing is used for oil bath, slinger disc, or oil stream lubrication, it may need to be sized for adequate heat dissipation. The temperature rise of the oil in a chain casing may be estimated by the use of Figures CH-28 and CH-29 and their accompanying procedures.

Adequate clearances must be provided inside the chain casing or the useful wear life of the chain may be restricted. As

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CH–14

CHAINS AND SPROCKETS

Wear Elongation, Percent

To estimate the probable temperature rise of a chain case, the following formula may be used: T = 50.9 HP = °F above ambient AK T = Temperature rise, °F where HP = Transmitted horsepower A = Casing area exposed to air circulation in sq. feet K = Radiation constant in BTU per sq ft per hour per hour per degree Fahrenheit temperature difference K = 2.0 for still air 2.7 for normal free air circulation 4.5 for rapid air circulation

Figure CH-27: Casing clearance wear limit

To estimate the probable temperature rise of a chain case, the following formula may be used: 50.9 HP T = = °F above ambient AK T = Temperature rise, °F where HP = Transmitted horsepower



A = Casing area exposed to air circulation in sq. feet K = Radiation constant in BTU per sq ft per hour per hour per degree Fahrenheit temperature difference K = 2.0 for still air 2.7 for normal free air circulation 4.5 for rapid air circulation

Good practice limits the allowable operating temperature to approximately 180°F (temperature rise plus ambient). If the calculated temperature is greater than this value, a larger casing could be used or an oil cooler added to reduce the operating temperature to allowable limits. Figures CH-28 and CH-29 can be used for a quick approximation of possible temperature. Explanation: 1. Compute value of “X” and plot point *1 2. Draw vertical line from “X” value (point *1) to intersect appropriate centers (pt. *2) 3. Draw horizontal line from “centers” (pt. *2) and read exposed projected casing area (pt. *3) 4. At intersection of appropriate HP & horizontal line (pt. *4) from step 3, draw a vertical line and read approximate casing temperature rise. (pt. *5)

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Good practice limits the allowable operating temperature to approximately 180°F (temperature rise plus ambient). If the calculated temperature is greater than this value, a larger casing could be used or an oil cooler added to reduce the operating temperature to allowable limits. Figures CH-28 and CH-29 can be used for a quick approximation of possible temperature. Explanation: 1. Compute value of “X” and plot point *1 2. Draw vertical line from “X” value (point *1) to intersect appropriate centers (pt. *2) 3. Draw horizontal line from “centers” (pt. *2) and read exposed projected casing area (pt. *3) 4. At intersection of appropriate HP & horizontal line (pt. *4) from step 3, draw a vertical line and read approximate casing temperature rise. (pt. *5)

Maintenance

Inspection and service schedule

A roller chain drive requires proper and timely maintenance to deliver satisfactory performance and life. It is assumed that the shafts, bearings, and supports, the chain and sprockets, and the lubrication type have been properly selected and installed. A maintenance program must also be established to assure that: • The drive is correctly lubricated; • Drive interferences are eliminated; • Damaged chains or sprockets are replaced; • Worn chains or sprockets are replaced; • The sprockets are properly aligned; • The chain is correctly tensioned; • Guarding is in good condition and is properly installed. A roller chain drive should be inspected after the first 50 hours of operation. After that, drives subjected to heavy shock load or severe operating conditions should be inspected after each 200 hours, and more ordinary drives may be inspected after each 500 hours of operation. Expe-

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CHAINS AND SPROCKETS

CH–15

VALUES OF X Standard Casing P x = (t + T) + Wc + 9 6 Oversize Casing x = R 1 + R 2 + W P = Chain pitch, in. t = Number of teeth, small sprocket Wc = Chain width, inches R1 = Casing radius, small end, in. R 2 = Casing radius, large end, in. W = Casing width inches HP = Horsepower T = Number of teeth, large sprocket A = Area, sq ft

Figure CH-28

riences may indicate a longer or shorter interval between inspections. At each inspection, the following items should be checked and corrected when necessary.

Inspect lubrication system

For manual lubrication, be sure that the lubrication schedule is being followed and the correct grade of oil is being used. If the chain is dirty, clean it with kerosene or a nonflammable solvent and re-lubricate it. For drip lubrication, check the flow rate and be sure that the oil is being directed onto the chain correctly. For oil bath, slinger-disc, or oil-stream lubrication, be sure that all orifices are clear and that oil is being directed onto

IADC Drilling Manual

Figure CH-29

the chain correctly. Change the oil after the first 50 hours of operation and after each 500 hours thereafter (200 hours in severe service).

Inspect for damaged chains or sprockets

Inspect the chain for cracked, broken, deformed, or corroded parts and for tight joints or turned pins. If any are found, find and correct the cause of damage and REPLACE THE ENTIRE CHAIN. Even though the rest of the chain appears to be in good condition, it very probably has been damaged and more failures can occur in a short time. Inspect sprockets for chipped, broken, or deformed teeth. If any are found, correct the cause of the damage, and REPLACE THE SPROCKET AND CHAIN. Sprockets are stronger and less sensitive to damage than chain, but running a

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CH–16

CHAINS AND SPROCKETS Table CH-9: Chain wear elongation limits

ANSI Chain Number

Chain, in.

25

.250

6.35

35

.375

41

Pitch, mm

No. of Pitches

Measured Length Nominal

At 3% in.

Elongation mm

in.

mm

48

12.00

305

12.375

314

9.52

32

12.00

305

12.375

314

.500

12.70

34

12.00

305

12.375

314

40

.500

12.70

24

12.00

305

12.375

314

50

.625

15.88

20

12.50

318

12.875

327

60

.750

19.05

16

12.00

305

12.375

314

80

1.000

25.40

12

12.00

305

12.375

314

100

1.250

31.75

20

25.00

635

25.750

654

120

1.500

38.10

16

24.00

610

24.719

628

140

1.750

44.45

14

24.50

622

25.250

641

160

2.000

50.80

12

24.00

610

24.719

628

180

2.250

57.15

11

24.75

629

25.500

648

200

2.500

63.50

10

25.00

635

25.750

654

240

3.000

76.20

8

24.00

610

24.719

628

worn chain on new sprockets can ruin the new sprockets in a short time.

Inspect for chain wear

In most roller chain drives, the chain is considered worn out when it has reached 3% wear elongation. With 3% plus wear, the chain does not engage the sprockets properly and can cause damage to the sprockets or chain breakage. In drives with large sprockets (more than 66 teeth), allowable wear is limited to 200/N which may be substantially less than 3%. And, in fixed-center, non-adjustable drives, allowable wear may be limited to as little as one-half of one chain pitch wear elongation. N = Number of teeth on the large sprocket. To determine chain wear elongation, rotate the sprockets in opposite directions to make one span tight. Then measure a representative section of the tight span, as shown in Figure CH-30 and Table CH-9. If wear elongation exceeds 3% or a functional limit, replace the entire chain. Do not connect a

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new section of chain into a worn section because it will run rough and damage the drive.

Inspect for sprocket wear

A worn out sprocket is not nearly as well defined as a worn out chain. However, there are some sprocket characteristics that indicate when a sprocket should be replaced. Check for roughness or binding when a new chain engages or disengages the sprocket. Inspect for reduced tooth thickness and hooked tooth tips (Figure CH-31). If any of these conditions are present, the sprocket teeth are excessively worn and the sprocket should be replaced. Do not run new chain on worn out sprockets because it will cause the chain to wear rapidly. Also, do not run a worn chain on new sprockets because it will cause the sprocket to wear rapidly.

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CHAINS AND SPROCKETS

Figure CH-30: Measurement of chain length for wear.

Figure CH-31: Worn sprockets.

Inspect for sprocket misalignment

Inspect for significant wear on the inside surfaces of the chain roller link plates and on the sprocket flange faces. If this type of wear is present, the sprockets may be misaligned. Realign the sprockets as described in the installation instructions to prevent further abnormal chain and sprocket wear. If 5% or more of the link plate thickness is worn away (Figure CH-32), or if there are any sharp gouges in the link plate surface, the chain should be replaced immediately. If 10% or more of the sprocket-tooth flange thickness is worn away, (Figure CH-33), the sprocket should be replaced.

Figure CH-32: Chain misalignment wear.

Figure CH-33: Sprocket misalignment wear.

Inspect guards

Inspect the guards to ensure that they are in serviceable condition. The guards must not be bent or deformed so that intended clearance is reduced. Designed openings in the guards (mesh) must not be enlarged. The guards must not be broken or damaged, especially at or near the mounting points. If the guards are found to be in serviceable condition, reinstall them on the drive; making sure that all fasteners are secure and that all safeguarding devices (such as presence sensors and interlocks) are functioning.

Measure the total mid-span movement (Figure CH-19). If it exceeds the tabulated limit, adjust the center distance to obtain the required amount of slack. If elongation exceeds the available adjustment, and wear elongation still has not exceeded 3% or the functional limits, remove two pitches and reinstall the chain. If the minimum adjustment limit will not permit shortening the chain two pitches, the chain may be shortened by one pitch using an offset link or an offset section. Avoid this if at all possible.

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CH–18

CHAINS AND SPROCKETS

Table CH-10: Roller chain drive troubleshooting guide CONDITION / SYMPTOM

Excessive noise

POSSIBLE CAUSE

WHAT TO DO

Chain striking on obstruction

Replace chain and eliminate interference.

Loose casing or shaft mounts

Tighten bolts, realign drive, and re-tension chain.

Excess chain slack

Re-tension chain.

Excessive chain wear

Replace chain and sprockets and realign sprockets.

Sprocket misalignment

Replace chain and sprockets if indicated.

Inadequate lubrication

Realign sprockets.

Chain pitch too large

Re-tension chain.

Too few sprocket teeth

Replace chain if indicated. Re-establish proper lubrication. Redesign drive for smaller pitch chain. Check to see if larger sprockets can be used.

Chain climbs sprocket teeth

Excess chain slack

Re-tension chain.

Excessive chain wear

Replace and re-tension chain.

Excessive sprocket wear

Replace chain and sprocket and realign sprockets.

Extreme overload

Replace chain and eliminate cause of overload.

Excessive sprocket wear

Replace chain and sprockets and realign sprockets.

Chain clings to sprocket

Sprocket misalignment

Replace chain and sprockets if indicated. Realign sprockets.

Wear on inside of link platesand on one side of sprocket

Sprocket misalignment

Replace chain and sprockets if indicated. Realign sprockets.

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CHAINS AND SPROCKETS

CH–19

Table CH-11: Roller chain drive troubleshooting guide CONDITION/SYMPTOM Tight joints

Turned pins

POSSIBLE CAUSE

WHAT TO DO

Dirt or foreign material in chain joints

Clean and re-lubricate chain.

Inadequate lubrication

Replace chain and sprockets if indicated and realign sprockets.

Corrosion or rust

Replace chain and sprockets if indicated and realign sprockets.

Overloads bends pins or spreads roller link plates

Replace chain and eliminate cause of overload.

Inadequate lubrication

Replace chain and re-establish proper lubrication.

Overload

Replace chain and eliminate cause of overload.

Overload

Replace chain and eliminate cause of overload.

Loading above chain’s dynamic capacity

Replace chain and eliminate cause of high loading, or redesign drive for larger chain.

Exposure to corrosive environment combined with stress from press fit

Replace chain and protect from hostile environment.

Extreme overload

Replace chain and eliminate cause of overload, or redesign drive for larger chain.

High speed impact, or sprockets too small

Replace chain. Possibly redesign drive for smaller pitch chain or larger sprockets.

Chain riding high on sprocket teeth

Replace chain and readjust tension more often.

Speed/load too high

Reduce speed or load. Possibly redesign drive for smaller pitch chain.

Inadequate lubrication

Provide or re-establish proper lubrication.

Elarged holes

Cracked link plates (fatigue)

Cracked link plates (stress corrosion)

Broken pins

Broken Link Plates

Broken Link Plates

Broken, cracked, or deformed rollers

Broken, Cracked, or Deformed Rollers

Pin galling

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CH–20

CHAINS AND SPROCKETS

Worn link plate

Chain dragging on case, guide, or obstruction

Replace chain when 5% of contour worn away. Re-tension chain and eliminate interference.

Chain striking obstruction

Replace chain and eliminate interference.

Missing at assembly

Replace chain.

Broken and lost

Replace chain.

Exposure to moisture

Replace chain and protect from moisture.

Water in lubricant

Replace chain and protect from moisture.

Inadequate lubrication

Provide or re-establish proper lubrication.

Exposure to corrosive environment

Replace chain and protect from hostile environment.

Vibration

Replace chain. Reduce vibration. Use larger sprockets.

High speed

Replace chain. Reduce speed. Redesign drive to use smaller pitch chain.

Striking obstruction

Replace chain. Eliminate interference(s).

Cotters installed improperly

Correct installation.

Battered link plate edges

Missing parts

Rusted chain

Corroded or pitted chain

Missing or broken cotters

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CHAINS AND SPROCKETS

CH–21

Glossary

ROLLER CHAIN TERMS ANSI: American National Standards Institute. API: American Petroleum Institute. ASME: American Society of Mechanical Engineers. BUSHING: Fits inside rollers, similar in looks but smaller in diameter and longer. Pressed into inside link plates. Ref. Figure CH-1.

LINKPLATES: Total of four, two inside and two outside. Holds chain together. Ref. Figure CH-1. MASTER LINK: Also known as CONNECTING LINK. Used to connect the chain into a continuous strand. Ref. Figures CH-8, 9 and 9A. OFFSET LINK: Same as half link. PIN: Fits inside bushing and holds the outside link plates together. Pressed into outside link plates. Ref. Figure CH-1.

CONNECTINGLINK: Same as above. COTTER-PIN CHAIN: Chain with pins riveted on one end and cotter pin holes on the other end. Ref. Figure CH-4. COTTERS: Heat-treated spring steel wires formed into a shape with an eye that is used to help hold link plates on pins. Ref. Figures CH-9, CH-9A. HALF LINK: Also known as OFFSET LINK. Used to shorten chain by one pitch. Replaces one pin link and one roller link. Ref. Figure CH-10.

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PITCH: Distance from the centerline of one pin to the next. Width of the rollers. Ref. Figures CH-12A, CH-12B. RIVETED CHAIN: Chain with both ends of the pin riveted or side mashed. Ref. Figure CH-3 ROLLER WIDTH: Width of the rollers. Ref. Figures CH-12A, CH-12B.

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DIRECTIONAL DRILLING

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

PowerDrive Orbit ROTARY STEERABLE SYSTEM

PowerDrive Orbit RSS helped save 8.8 days drilling a high-angle well in a single run and increased ROP 100%. An operator used PowerDrive Orbit* RSS to deliver precise directional control while drilling an 8½-in section in a complex environment with interbedded layers and severe stick/slip. The system, using its newly developed pad design with metal-to-metal sealing, resisted the formation’s strong tendency to turn the well. The desired inclination of 45° was reached in 177 ft and ROP averaged at 16 ft/h, helping the operator save 8.8 days of rig time. Read the case study at

slb.com/PowerDriveOrbit *Mark of Schlumberger. © 2014 Schlumberger. 14-DR-0223

DIRECTIONAL DRILLING

DD-i

CHAPTER

DD

DIRECTIONAL 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. CONTRIBUTORS Greg Devenish, Baker Hughes Inc. Ron Dirksen, Halliburton Blaine Dow, Schlumberger Chris Maingot, Weatherford

REVIEWERS Carl Butler, Cobalt International Energy Barry Gabourie, Cobalt International Energy Chris McCartney, Consultant João Luis Vieira, Schlumberger

DD–ii

DIRECTIONAL DRILLING

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: 978-0-9906220-4-8

Printed in the United States of America.

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DIRECTIONAL DRILLING Contents CHAPTER DD

DD-iii

Contents

DIRECTIONAL DRILLING

Evolution of directional drilling since 1900........... DD-1 1900-1920s.............................................................. DD-1 1930s.......................................................................... DD-2 1940s-1960s............................................................DD-3 1970s..........................................................................DD-5 1980s..........................................................................DD-6 1990s-Present.........................................................DD-6 Directional surveying............................................. DD-7 Magnetic and gyroscopic sensors: instruments and theory............................................................................... DD-7 Magnetic sensors................................................... DD-7 The geomagnetic field..........................................DD-9 Gyroscopic sensors................................................DD-9 Free gyros...............................................................DD-10 Rate gyros (north-seeking gyros)...................DD-10 Inertial navigation systems................................DD-10 Directional surveying essentials.............................DD-10 Regulations.............................................................DD-10 Operator..................................................................DD-10 Services...................................................................DD-10 Anti-collision..........................................................DD-10 Rig personnel involved (operations only).....DD-11 Safety and handling.............................................DD-11 Defining the directional drilling objective............DD-11 Surface locations..................................................DD-11 Subsurface targets...............................................DD-11 Sizing of the target...............................................DD-11 Anti-collision..........................................................DD-12

IADC Drilling Manual

Survey accuracy....................................................DD-12 Trajectory design considerations....................DD-12 Well-profile types.................................................DD-14 Deviation control.........................................................DD-16 Borehole patterns................................................DD-17 Borehole patterns, keyseats and doglegs....DD-17 Control of hole angle..........................................DD-17 Bottomhole assemply components...................... DD-20 Vertical drilling systems........................................... DD-20 Positive displacement motors (PDM).................. DD-20 Steerable turbines...................................................... DD-22 Rotary steerable systems (RSS)............................. DD-22 High build rate rotary steerable systems............ DD-23 Open-hole whipstocks...............................................DD-24 Sidetrack drivers...................................................DD-24 Sidetrack categories............................................DD-24 Design considerations.........................................DD-24 Open-hole motor sidetrack with cement plug..................................................DD-25 Open-hole motor sidetrack with no cement plug............................................DD-25 Casing whipstocks/window cutting...............DD-25 Measuring tools..........................................................DD-26 Measurement while drilling/logging while drilling.........................................................DD-26 Bits................................................................................. DD-28 Other components.................................................... DD-29

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DIRECTIONAL DRILLING

Evolution of directional drilling since 1900

viated wells so that multiple boreholes could be drilled from one location and at various angles. These techniques allow drilling to contact larger quantity of oil and gas reserves, thereby minimizing associated drilling costs, as well as environmental impact.

Directional drilling is the science of controlling or correcting a wellbore, along a predetermined trajectory, to one or more underground targets or locations at given horizontal displacements (HD) and true vertical depths (TVD) from the point of origin. The central advantage of drilling directionally is that significantly more of the production formation is exposed to the well, compared to vertical wells (Figures DD-1 and DD-2).

1900-1920s

Directional drilling has come a long way since its origins. Through most of the 1800s, wells ostensibly went in only one direction—straight down. It was in the 1920s that the industry first became aware of wellbore deviation of apparently vertical holes. Once these holes could be surveyed, operators discovered that, having had no prior method for measuring inclination or direction, they had unknowingly drilled holes with up to 50° +/- of inclination. Deviation tendencies caused by formation dips, faults, bedding planes, etc., acting on the drill bit were causing the drift away from vertical. The bending characteristics of the drillstring, coupled with the amount of weight applied to the bit, were also factors affecting the desired outcome. Ultimately, surveys consisting of depth, inclination and direction would be used to accurately calculate a well’s position.

These techniques have been integral parts of the oil and gas industry since the 1920s. Operators must maintain wellbore verticality, construct curves (inclination builds and/or drops) and maintain tangents all in a specific direction. Applications include drilling to difficult-to-access locations and at river crossings as well as drilling relief wells, sidetracking, drilling multiple wells from one surface location or main wellbore (multilaterals) and drilling with wellbores having inclinations up to and exceeding 90°. High-inclination wells (80°+) are considered horizontal and have significantly augmented production due to their increased reservoir exposure as compared to their low-angle counterparts. Extended-reach (ER) wells push the horizontal limits of directional drilling even further.

The acid bottle technique, developed in the late 1800s in South African diamond mines to survey boreholes, became in the 1920s, the first method to be utilized solely for measuring inclination. A glass bottle filled with acid was lowered into the borehole where the acid would settle at an angle in the bottle lying parallel to the angle of inclination. After some time, the acid etched the glass, which allowed calcu-

Directional drilling has found a respected place in oilfields worldwide. Historically, engineers have used established methods based on years of prior experience to advance the science toward modern techniques. Directional drilling techniques were designed to improve the mechanics of deMagnetic Single Shot

Entirely Vertical/blind “Straight Holes”

Multilateral in Russia

Steel Whipsticks Hardwood Wedges Gyroscopic technology development

1900

1910

Mud Motor

Bent Housing Motors

Surface Readout Gyro

Relief Well

Rotary Steerable Systems

Measurement While Drilling (MWD)

Gyro MWD

1920

Acid bottle Surveying

Totco Drift tool

Stabilized Rotary BHAs

Horizontal Drilling Viable

Jetting method Magnetic Steering tools

North Seeking Gyro

* Set by Exxon Neftegas Ltd on the Sahkalin Shelf during 2013

Figure DD-1: Evolution of directional drilling.

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DD-1

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Adjustable Gauge Stabs Gyro Steering Tool

Extended Reach Record 41,667 ft*

DD-2

DIRECTIONAL DRILLING

In 1926, Sun Oil enlisted Sperry Corporation to use gyroscopic-based technology to make survey instruments for accurately measuring borehole inclination and direction. The rotating gyroscopes provided accurate measurements across three different axes and allowed drillers to accurately determine a borehole’s azimuth and inclination. The first magnetic single-shot and multi-shot instruments, which measured both inclination and direction, were developed in 1929 by H. John Eastman. These instruments used sensors employing magnetic compass needles and plumb bobs. They also featured mechanical timers that triggered a simple camera to record the survey on photographic film. The science of controlled directional drilling did not come about until the development of these magnetic single-shot and multi-shot instruments. There were three natural consequences of these accurate surveying methods: intentionally deviating wells to precise bottomhole locations; restricting vertical wells to at most a few degrees in inclination; and limiting the resultant wellbore drift. The first deliberately deviated wells were drilled in the late 1920s. Hardwood wedges were used, pushing the bit to one side of the hole and producing a deflection to direct the wells from vertical toward an intended direction.

1930s Figure DD-2: Key parameters in directional drilling.

lation of the wellbore’s inclination at a given depth. In the 1920s, Totco developed the mechanical drift recorder, which could only measure borehole inclination but was more accurate than the acid bottle and other early techniques. Unfortunately, neither of these methods shed light on the direction of well drift. The drive for wellbore control techniques and improved surveying methods was partly accelerated by the possibility that wells were drifting across lease lines. This led to court decrees that lease holders only owned deposits found within the downward vertical projection of their lease lines. Few at the time possessed technology enabling control of well drift. Among those leaseholders who did, some could not resist the temptation to produce oil from an unaware neighbor. Another method, developed by George Maas, used an acid-etch test tube in parallel with a compass needle that would lock into cooling gelatin, to record both inclination and direction. A vacuum flask was used to protect the gelatin from external heat in the borehole. This development was first described around 1912, yet the heat-shield principle is still used in modern survey instruments.

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In 1930, a French inventor named René Moineau discovered the principle of the progressive cavity pump which led to the development of downhole positive displacement motors (PDMs). PDMs would eventually become the most effective and commonly used deviation tools in the industry. Records from two wells drilled in Huntington Beach, California, in 1930 are the first records from directionally controlled boreholes drilled from an onshore location to oil/gas deposits under the ocean (offshore). The steel whipstock was the main deflection tool used from the 1930s until the 1950s. Early whipstocks were simply lowered into the borehole, oriented with the whip face in the desired direction and mechanically anchored at the bottom of the main wellbore (Figure DD-3). When the wellbore drifted off course, a whipstock was set and drilling operations would be diverted along the whip face. No attempts were made to retrieve these whipstocks and they were typically abandoned in the well. Beginning in 1932, directional wells were regularly drilled along the beachfront beneath the ocean. In 1933, the Signal Hill field was developed in Long Beach, Calif. The orientation of directional tools, including whipstocks, was accomplished by using a visual surface reference and maintaining the tool facing while it was lowered into the hole. Another method entailed running in a survey instrument so that it landed in a special mule-shoe key designed to

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DIRECTIONAL DRILLING

align it with the tool facing (Figure DD-4). This was recorded as a reference to the magnetic direction or high side of an inclined wellbore and the deviation tool could then be turned to the desired facing/direction. In 1934, a blowout occurred in a field owned by Humble Oil Company of Conroe, Texas. A gas kick from a high-pressure zone ignited, and the entire rig was engulfed in flames. After many months and attempts to bring the fire under control, other nearby rigs had to be closed down and the entire field was threatened. H. John Eastman, with his experience using whipstocks and surveying instruments, used a mobile drilling truck to drill a directional relief well close enough to the blowout well, killing the blowout on the first attempt. The oil industry subsequently accepted directional drilling as a reliable technique (Figure DD-5).

1940s-1960s

It’s likely that basic stabilized rotary bottomhole assembly (BHA) designs with drill collars for weight and stiffness, together with stabilizers precisely positioned for inclination control while drilling, originated in the 1940s. Historically, it had been possible to control the angle of directional wells during rotary drilling by correct design of the assembly and use of suitable drilling parameters. The three basic principles included holding inclination (locked/packed), building inclination (fulcrum) and dropping inclination (pendulum). Drill collars, when used without stabilization, tended to buckle and cause unwanted deviation and poor hole quality. Multiple stabilizers were positioned to increase the stiffness or to promote the natural bending of the drill collars, thereby pointing the drill bit or applying a side force to encourage the wellbore in a specific trajectory. Control of hole direction had traditionally been poor with basic rotary assemblies. Roller-cone bits usually walked to the right (clockwise), and directional control was previously limited to using well-stabilized assemblies to reduce this tendency. The normal prior practice with non-steerable assemblies was to lead the well an estimated amount to the left of the plan, thereby compensating for anticipated turns. Magnetic instruments naturally needed to be seated in a nonmagnetic environment if they were to run inside the drillstring to accurately measure direction. In the 1940s, nonmagnetic drill collars (NMDC) were placed in the lowest possible position of the drillstring with a crow’s foot baffle plate inserted below it. This allowed the drilling fluid to pass through the drillstring and, at the same time, provide a convenient seat for the survey instrument. Gyroscopic surveying, developed as early as 1929, was continuously improved from the 1940s to the 1960s. Gyros were also used to measure inclination, azimuth and the

IADC Drilling Manual

In Closed Position

Whipstock Locked for Setting

Ready to Start Drilling

Drilling Ahead on Whipstock

DD-3

Drilling Ahead in New Hole

Pin Sheared

Muleshoe stinger

Figure DD-3: Wellbore deviation with whipstocks.

Key

Muleshoe stinger

Figure DD-4: One method to orient directional tools was running in a survey instrument to land in a special muleshoe key designed to align it with the tool facing.

Key

Figure DD-5: Directional drilling is well accepted as a reliable technique to drill relief wells to kill blowouts. First recorded application was in 1934.

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DD-4

DIRECTIONAL DRILLING

deviation tool orientation. While magnetic instruments are dependent on the Earth’s natural lines of magnetic force, gyros use a gyroscopic compass to maintain a fixed-reference direction and to measure relative changes in direction at selected depths with the aid of a timer. This surveying technology enabled even more directional drilling applications, as it could be used in magnetic environments, e.g., for accurately sidetracking from inside the casing in a vertical hole where magnetic toolfaces would otherwise be impossible to orient or when drilling suffers from magnetic interference from nearby wells. The jetting technique was developed in the mid-1950s. Rarely used in the 21st century, it is still a valid and inexpensive deviation method for soft formations. A special jet bit may be used, but it is also common practice to use a standard soft formation tri-cone bit with one very large nozzle and two smaller ones. The idea is to point the big jet in the desired direction. With the majority of flow passing through the large-bore nozzle (big jet), the hole preferentially washes in the direction of the large nozzle and forms a pocket. Drilling can continue with the assembly following the direction of the pocket (Figure DD-6). While jetting is not common today, it can be useful tight an-

ti-collision scenarios exist in surface holes. Other notable points about jetting include: •• It is relatively inexpensive compared to conventional deflection tools; •• It allows surveys to be taken closer to the bit than any other deflection method; •• Jetting dogleg response can be inconsistent and difficult to predict; •• Effectiveness is reduced as bit diameter and BHA tubular diameter increase; •• Hole-opening runs are often required, as jetting is often performed in 8 ½ in. and 12 ¼ in. holes. The first downhole drilling motors or mud motors were designed and manufactured by Dyna-Drill in 1958. The motor was based on the 1930 Moineau design for progressive cavity pumps. The mud motor’s molded elastomeric insert, which is bonded to the inside of a cylindrical steel case, comprises the stator of the pump or motor unit. A helical rotor with one or more lobes rotates eccentrically within the stator (which contains one more lobe than the rotor). When differential pressure (i.e., mud flow through this power section) is applied across the assembly, the rotary power extracted from the rotor/stator assembly functions as a motor driving the drill bit. Many power section configurations have been developed, from those that generate high bit speeds

Figure DD-6: Jetting was developed in the mid-1950s. Rarely used today, it is still a valid and inexpensive deviation method in soft formations. Courtesy Baker Hughes Inc.

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DIRECTIONAL DRILLING

DD-5

Figure DD-7: Downhole drilling motors were introduced by Dyna-Drill in 1958. Courtesy Baker Hughes Inc.

but are limited to relatively low torque, to those allowing for slower-bit speeds but at a much higher-torque output (Figure DD-7).

Magnetic single shot

Mud motors were first used for directional control of boreholes in the 1960s. A bent sub (a short component for connecting two longer collars) was positioned directly on top of the mud motor (Figure DD-8). This directional drilling assembly would normally be used whenever the wellbore reached a depth that required deviating, normally to initiate/drill a curve or correct the wellbore. With the drillstring not rotating (rotary drive locked), drilling was accomplished by the motor-driven drill bit. This bit still rotated as long as there was mud flow and the ability to make new hole by sliding the drillstring. This would in effect kick off the wellbore in the direction of the bent-sub toolface. The BHA was usually pulled back out of the hole to prevent twisting off (breaking) the motor due to high stresses caused when trying to rotate the bent-sub configuration. Basic rotary assemblies would be run to continue controlling the well path until another motor run was necessary. Mud motors were sometimes used in vertical applications where high bit speeds were desirable. They had the added benefit of minimizing erosion and wear on the drillstring and casing strings since the drillstring would not need to be turned as fast due to the reduction of the surface revolutions per minute (RPM). The majority of mud motors were used in directional (deviated) wells. In these wells, one run with the bent-sub configuration could accomplish the same goal as multiple runs with other methods of steering the bit, but with greater accuracy, thus reducing time and cost. The rebel tool was introduced in the 1960s. It was one of the first directional drilling tools to control the direction of lateral wellbore trajectory while rotating and could be set up on surface for a left or right tendency. Inconsistent reliability of these tools led to their declined use in the industry.

1970s

Magnetic-steering tools were first used in 1969 but became more common in the 1970s. The steering tool was also used

IADC Drilling Manual

Bent sub

Downhole mud motor

Drill bit Figure DD-8: By the 1970s, mud motors dominated directional drilling. As above, they were used with a bent-sub for directional kick off.

to measure drift, direction and toolface during semi-continuous drilling and with downhole directional data available in real time on surface. An instrument assembly containing a magnetic survey package was sent downhole connected by a wireline. It was seated in a mule-shoe orienting sub (also called Universal Bottomhole Orienting sub or UBHO) that was connected to the top of a mud motor, thereby aligning it with the motor’s toolface. A coder converted data measurements to electrical pulses and transmitted the measurements to the surface through a shielded electric conduit to digital or video displays. Measurements were thus available immediately in real time at the surface for use in directionally controlling the wellbore. Even though these early steering tools provided the directional driller with valuable data in real time, the tools would have to be pulled out of the drill-

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DD-6

DIRECTIONAL DRILLING

The arrival and combination of bent-housing motors and measurement while drilling (MWD) surveying in the early 1980s was a significant, although costly, step toward overcoming the drawbacks of previous deviation systems (Figure DD-9). MWD allows downhole measurements from sensors at or near the bit to be sent to the surface continuously by mud-pulse telemetry, electromagnetic (EM) frequency communications or wired drillpipe. This allows for faster, more accurate and safer drilling. The survey tool’s accelerometers and magnetometers measure the inclination and azimuth of the wellbore and then transmit the information from a specific location to the surface in real time. The extra cost incurred from using the steerable system is counteracted by the savings in survey and trip time. MWD surveys allow the directional driller more control over survey intervals. It has become common to survey with every single stand of drillpipe (i.e., 90 ft) in the kickoff and curve phases without the additional time required by single-shot surveys. Figure DD-9: Introduction of an adjustable bent housing within the motor body allowed rotation (right), as well as “sliding” drilling (left). Courtesy Baker Hughes Inc.

string every time another joint or connection of drillpipe was added and then rerun. Steering tools were eventually used with side-entry subs that made drilled sections with mud motor assemblies continuous because the wireline entered the drillstring below the surface. This early real-time method of surveying made it possible to drill in deeper and more difficult scenarios by enabling precise directional control of the downhole tools. In the late 1970s, surface readout gyros (SRG) came onto the directional landscape. They needed to be oriented to a known location on surface prior to surveying or orientation. These gyros are extremely durable and are most commonly used in applications where movement is present such as drilling offshore or from floating rigs.

1980s

The mud motor evolved into an even more versatile directional drilling option when the bent-sub configuration was replaced by an adjustable bent housing in the motor body itself. The shorter bit-to-bend distance reduced the lever arm (bit offset), which in turn reduced the stress at the bend and led to single BHA runs, i.e., being able to drill continuously in rotary mode with the option to stop rotation and slide the drillstring in the direction required, thereby making corrections or maintaining build/turn rates without trips for any configuration changes. There are still limits regarding the severity of the bend, above which rotation is not recommended.

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In 1985, the first continuous north-seeking gyro was introduced. 1987 saw the addition of the first gyro-steering tool. In the late 1980s, adjustable-gauge stabilizers (AGS) were introduced to the industry. They were designed to change the characteristics of a rotary assembly by adjusting their effective blade diameter while drilling ahead. By strategically placing the AGS near or 15 to 30 ft above the bit, the gauge adjustment controls the inclination build or drop tendency and mitigates costly, time-consuming trips. The stabilizers are also used with steerable systems. The first purposeful horizontal well was drilled in Toxemia, Texas in 1929. Numerous horizontal wells attempted during the 1950s and 1960s in the Soviet Union and China yielded only limited success. As weak oil prices during the late 1970s and early 1980s pushed the industry toward cost-effective techniques, interest in horizontal drilling picked up. By the late 1980s, horizontal drilling finally became economically viable. Of the three categories of horizontal wells—short-, mediumand long-radius—medium radius is the most widely used. Medium-radius wells can be drilled relatively quickly, have less curvature and do not require use of specialized equipment.

1990s-Present

In the late 1990s, rotary steerable systems (RSSs) were introduced. When drilling in the sliding mode, steerable motors produced a level of wellbore tortuosity that not only negatively impacted critical follow-up operations, e.g., formation evaluation and running casing, but also hampered further sliding in ER wells. Unlike steerable motor assemblies, rotary steerable technology allows for remote-con-

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trolled directional drilling with continuous rotation from the surface without the need for sliding. There are two main categories of RSSs: push-the-bit and point-the-bit methods. The push-the-bit method uses external pads that push against the formation, directing the bit in the opposite direction. Point-the-bit systems normally bend or deflect the main shaft and, by using a pivot device, effectively point the bit in the desired direction. Drilling with an RSS provides many advantages over previous systems: •• More efficient weight transfer to the bit; •• Much improved hole quality leading to deeper/longer achievable wellbores with reduced wellbore drag; •• Improved formation evaluation and ease of running casing strings; •• Improved hole cleaning during drilling operations due to continuous rotation; •• Reduced risk of getting the drilling assembly stuck as there is continuous rotation; •• Increased rates of penetration (ROP) compared to motor sliding; •• More accurate placement of wellbores; •• Overall cost savings due to fewer BHA-related trips and faster ROPs. RSS technology has made access to difficult-to-reach reservoirs possible with precise directional control in previously inaccessible or uncontrollable formations. Horizontal applications like extended-reach drilling (ERD) have naturally benefitted greatly from RSS technology with wells drilled regularly with horizontal departures of 5,000 to 20,000 ft. The first gyro MWD was introduced in 2000. In 2013 in the Sahkalin Shelf, Exxon Neftegas Limited drilled the deepest wellbore ever recorded: 41,667 ft (12,700 m) with a horizontal reach 38,514 ft of (11,739 m). Current costs related to hydrocarbon production are driving the development of newer directional drilling technologies. Today, directional drilling has become a normal part of the drilling landscape, whereas once it was understood by very few. Probably the most significant advantage of this evolution is that oil-producing companies worldwide can now develop subsurface deposits that previously could never have been reached economically using other methods.

Directional surveying

Directional surveys are taken to determine the position of the borehole being drilled and to determine the orientation, or toolface, of directional drilling tools, e.g., mud motors, rotary steerable tools and whipstocks.

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DD-7

A directional survey, either magnetic or gyroscopic, is taken using one or more of a selection of available tools. The survey instrument measures the hole inclination (inc) and the hole azimuth or direction (azi). The inclination denotes the angle of the hole, with 0° meaning that the hole is vertical and 90° meaning the hole is horizontal. The azimuth is the direction from north: 0° is due north and 180° is due south as on a compass. The MD at which the survey is taken is recorded at surface, and a well deviation or survey record is then generated (see Table DD-1). The MD is referenced to the well’s zero reference point, which could be the wellhead, rotary table, mean sea level (MSL) or other reference the operator or the local authorities designate for their operations. Likewise, the north/east zero point reference can be the wellhead, well center, platform center or other reference point chosen by the operator or local authorities. The north reference can be true north (TN), grid north (GN) or magnetic north (MN). It is important to use the correct reference coordinates as the results of the survey record are used for other operations as explained later in this chapter. With the MD, inc and azi input variables, the position of the wellbore is calculated in terms of TVD, as well as north/ south (N/S) and east/west (E/W) departures from the reference point of the well. Several calculation methods can be used to approximate the well profile between survey stations, with the most commonly used being the minimum curvature method. In Table DD-1, the well starts off roughly in a northwest direction (azi ~300°) and the distance from the reference point increases in that direction. It should be noted that south and west in this example are expressed as negative numbers. Toward the bottom of the interval, the well turns in a westerly direction (azi ~260°) as the well is built to an inclination of ~70°. The departure continues to increase in the westerly direction and starts to slightly decrease in the northerly direction. The tool column notes that the top part of the well (down to 1,105 ft) was surveyed using a gyro-survey tool and the rest with an MWD survey tool.

Magnetic and gyroscopic sensors: instruments and theory Magnetic sensors

Magnetic survey instruments use electronics to measure the Earth’s gravity and magnetic field, most commonly along three orthogonal axes. For magnetic sensors to be accurate, they must be used within an environment far from materials that disturb the Earth’s magnetic field, e.g., steel casing and drill collars. These sensors can only be used in open hole

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DD-8

Table DD-1: Sample directional survey. This wells starts off heading northwest (azi ~ 300°), and the distance from the reference point increases in that direction. MD (ft)

INC (*)

AZL (*)

TYD (ft)

N/S (ft)

E/W (ft)

Tool

679.0

2.89

299.16

678.9

3.6

2.7

SR-Gyro-55(1)

725.0

4.49

297.38

724.8

5.0

0.1

SR-Gyro-55(1)

775.0

5.09

297.86

774.6

7.0

-3.6

SR-Gyro-55(1)

821.0

6.25

296.89

820.4

9.1

-7.6

SR-Gyro-55(1)

870.0

6.52

296.43

869.1

11.5

-12.5

SR-Gyro-55(1)

916.0

6.47

297.18

914.8

13.8

-17.1

SR-Gyro-55(1)

964.0

6.72

300.83

962.5

16.5

-21.9

SR-Gyro-55(1)

1010.0

7.59

303.62

1008.1

19.6

-26.8

SR-Gyro-55(1)

1059.0

8.84

304.73

1056.6

23.5

-32.6

SR-Gyro-55(1)

1105.0

10.33

306.26

1102.0

28.0

-38.8

SR-Gyro-55(1)

1154.9

10.97

306.14

1151.0

33.4

-46.2

MWD+IFR2+MS+sag(2)

1249.7

12.79

310.01

1243.8

45.5

-61.6

MWD+IFR2+MS+sag(2)

1345.4

14.25

306.47

1336.8

59.3

-79.1

MWD+IFR2+MS+sag(2)

1441.5

16.46

305.59

1429.5

74.3

-99.7

MWD+IFR2+MS+sag(2)

1535.5

17.50

301.31

1519.4

89.3

122.7

MWD+IFR2+MS+sag(2)

1630.4

18.59

302.17

1609.7

104.8

-147.7

MWD+IFR2+MS+sag(2)

1696.7

18.80

298.73

1672.4

115.5

-166.0

MWD+IFR2+MS+sag(2)

1757.0

18.77

298.18

1729.5

124.8

-183.1

MWD+IFR2+MS+sag(2)

1852.5

20.92

295.54

1819.3

139.4

-212.0

MWD+IFR2+MS+sag(2)

1947.6

25.06

292.03

1906.8

154.3

-246.0

MWD+IFR2+MS+sag(2)

2042.1

27.21

292.05

1991.7

169.9

-284.6

MWD+IFR2+MS+sag(2)

2137.0

30.84

291.63

2074.7

187.0

-327.3

MWD+IFR2+MS+sag(2)

2232.3

31.42

292.38

2156.3

205.5

-373.0

MWD+IFR2+MS+sag(2)

2327.4

35.63

292.98

2235.5

225.8

-421.4

MWD+IFR2+MS+sag(2)

2422.5

38.40

290.54

2311.4

246.9

-474.6

MWD+IFR2+MS+sag(2)

2517.3

42.48

288.71

2383.6

267.5

-532.5

MWD+IFR2+MS+sag(2)

2613.4

46.37

284.64

2452.2

286.8

-596.9

MWD+IFR2+MS+sag(2)

2708.4

48.97

279.31

2516.2

301.2

-665.6

MWD+IFR2+MS+sag(2)

2803.3

51.29

273.38

2577.0

309.2

-737.9

MWD+IFR2+MS+sag(2)

2899.4

54.08

268.08

2635.4

310.1

-814.3

MWD+IFR2+MS+sag(2) MWD+IFR2+MS+sag(2)

2994.4

56.77

265.45

2689.3

305.7

-892.4

3090.2

59.62

263.56

2739.7

297.9

-973.4

MWD+IFR2+MS+sag(2)

3185.3

63.02

262.45

2785.4

287.7

-1056.2

MWD+IFR2+MS+sag(2)

3279.1

65.81

261.16

2825.9

275.6

-1139.9

MWD+IFR2+MS+sag(2)

3374.8

70.37

260.38

2861.6

261.4

-1227.5

MWD+IFR2+MS+sag(2)

away from nearby casing and positioned within one or more sections of nonmagnetic material. The electronic-magnetic survey systems in use today are solid-state self-contained directional surveying instruments. Inclination is measured by gravity accelerometers. From this measurement, the vector components of each of the three axes are most often used to calculate hole inclination.

IADC Drilling Manual

Hole direction or azimuth is measured by using both gravity accelerometers and magnetometers which measure components of the Earth’s magnetic field orthogonally, i.e., in the same three axes as the accelerometers. From this measurement, the vector components can be used to determine hole direction. These sensors can be employed in different modes such as single-shot, multi-shot and MWD. The electronic-magnetic

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DD-9

single-shot records a single-survey record while drilling the well and is usually run on a wireline for quick retrieval. The data are stored downhole in the memory and retrieved at the surface to calculate the hole direction, inclination and toolface. The electronic-magnetic multi-shot uses the same components as the electronic single-shot. The sole difference is that electronic multi-shots record multiple survey records. During drilling operations, the MWD instrument acquires downhole information to allow drillers to make timely decisions. The magnetic survey information is obtained with the same sensors, but, unlike previously mentioned systems that only stored the information, the MWD encodes the survey data in mud pulses that are decoded at the surface.

The geomagnetic field

Figure DD-10: Magnetic sensors rely upon detecting the Earth’s magnetic field to determine hole direction. The Earth can be imagined as having a large bar magnet at its center, lying barely off the north/south spin axis. The normal lines of the magnetic field will emanate from the Earth’s core in a pattern.

Magnetic sensors rely upon detecting the Earth’s magnetic field to determine hole direction. The Earth can be imagined as having a large bar magnet at its center, lying barely off the north/south spin axis (see Figure DD10). The normal lines of the magnetic field will emanate from the Earth’s core in a pattern. At the MN and south poles, the lines of force (flux lines) will lie vertically, or at 90°, to the Earth’s surface. At the magnetic equator, the lines of force will be horizontal, or at 0°, to the Earth’s surface. At any point on the Earth, a magnetic field has strength and direction (vector). The strength is called magnitude and is measured in units of tesla. Usual measurements are approximately 60 microtesla at the magnetic north pole and 30 microtesla at the magnetic equator. The direction is always called magnetic north; however, the magnitude will be parallel to the surface of the Earth at the equator and point steeply into the Earth closer to the north pole. The angle that the vector makes with the Earth’s surface is called the magnetic dip.

The prevailing models used to estimate the local magnetic field are provided by the British Geological Survey (BGS) or the US Geological Survey (USGS). These models carry out a high-order spherical harmonic expansion of the Earth’s magnetic field and provide a very accurate global calculation of the magnetic field rising from the Earth’s core and mantle.

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Models are generally updated annually because even the field of the Earth’s core and mantle varies with time. It should be noted that these models do not include effects from crustal anomalies and materials near the surface of the Earth which can be quite significant. They also do not separate effects from various electrojets in the Earth’s atmosphere, the effects of solar storms or the diurnal variation in the Earth’s magnetic field. At high latitudes, these effects can be quite significant as well. One mitigation method is to make magnetic-observatory-quality measurements directly at the wellsite; however, this is rarely possible. A useful alternative is to interpolate the field at a given location and time, as measured by at least three nearby magnetic observatories, the triangle of which preferably includes the wellsite being surveyed. This is referred to as interpolated in-field referencing.

Gyroscopic sensors

Gyroscopic surveying instruments are used when the accuracy of a magnetic survey system could be corrupted by extraneous influences such as cased holes, production tubing, geographic location or nearby wells. A rotor gyroscope is composed of a spinning wheel mounted on a shaft. It is powered by an electric motor and is capable of reaching speeds exceeding 40,000 rpm. The spinning wheel (rotor) can be

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DIRECTIONAL DRILLING

oriented, or pointed, in a known direction. The direction in which the gyro spins is maintained by its own inertia and can therefore be used as a reference for measuring azimuth. An outer and inner gimbal arrangement allows the gyroscope to maintain its predetermined direction regardless of how the instrument is positioned in the wellbore. Gyroscopic systems (gyros) can be classified into three categories: free gyros, rate gyros and inertial navigation systems.

Free gyros

There are three types of free gyros: tilt scale, level rotor and stable platform. The tilt scale and level rotor are film systems. The stable platform uses the electronic system which has a shorter run time and faster data processing while monitoring continuously. Most free gyros are the stable-platform type. They use a two-gimbal gyro system like the level-rotor gyro, but with the gimbals remaining perpendicular to each other even when the instrument is tilted during use. The inner gimbal remains perpendicular to the tool axis (platform) instead of perpendicular to the horizon.

Rate gyros (north-seeking gyros)

Rate gyros use the horizontal component of the Earth’s rotational rate to determine north. The Earth rotates 360° in 24 hours, or 15° in one hour. The horizontal component of the Earth’s rate decreases with the cosine of latitude; however, a TN reference will always be resolved at a latitude of less than 80° north or south. The rate gyro, therefore, does not have to rely on a known reference direction for orientation. Inclination is measured by a triaxial gravity-accelerometer package. Rate gyros have a very precise drift rate that is small compared to the Earth’s spin rate. The Earth’s spin rate is lower at higher latitudes and affects the gyro’s ability to seek north, i.e., the fastest spin rate is at the Equator and the lowest are near the North and South Poles. This effect also increases the time required to seek north accurately and decreases the accuracy of the north reference.

Inertial navigation systems

Inertial navigation systems, the most accurate surveying method, use groups of gyros to orient the system to north. The systems measure movement in the x, y and z axes of the wellbore with gyros and gravity accelerometers. Because of the sensor design, this instrument can survey in all latitudes without sacrificing accuracy.

Directional surveying essentials Regulations

Generally, regulatory agencies require drillers to take surveys to map the position of the wells being drilled. A survey

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may be required for anywhere from every 100 ft (30 m) of wellbore drilled to every 500 ft (152 m) drilled. The position of the wells is important for future reference should a well intervention or well intersection for well control, workover or abandonment purposes be required. A survey is also required to ensure future wells can be drilled safely away from existing wellbores, especially those producing hydrocarbons and/or under pressure.

Operator

The operator will generally need to acquire survey data to satisfy regulatory requirements and to ensure that the well is drilled to the desired subsurface location. Accurate positional data is needed to confirm that the well is in the right location. Subsurface maps for drilling and production purposes rely on accurate well-placement information.

Services

Almost all services need survey data to plan and execute the work. Directional drilling, MWD and logging while drilling (LWD) contractors are generally responsible for acquiring the data and performing the needed quality assurance/quality control (QA/QC) on the data prior to handing it to the operator and all other parties on the wellsite. A dedicated survey company may be needed to perform survey services, especially when using gyro-based surveys. The surveyors work on their own or in conjunction with the directional drilling and/or MWD/LWD contractors. On simple wells where no collision risks exist, the survey services can be performed by the rig contractor.

Anti-collision

Between the operator and the directional drilling company, the survey data are used to ensure the well is being drilled in such a way that it penetrates the earth safely away from other wells. This process is called anti-collision or collision avoidance. Both in the planning phase and during the actual drilling, care must be taken to ensure the well path is at a safe distance from other wells. This is particularly true for those wells that are under pressure and/or producing hydrocarbons. Accidental collision with such wells can lead to serious incidents. If a well cannot be drilled at a safe distance from under-pressure or producing wells, these wells should be closed in and depressurized prior to continuing the drilling of the hole section through and past the danger zone. All survey instruments have a small element of error in their measurement. To account for these errors, along with the wellbore position (TVD, N/E, etc.), an ellipse of uncertainty around the position is calculated. The magnitude of the error and size of the ellipse depend on the survey instrument used—small for accurate instruments (e.g., north-seeking

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gyros), a little larger for most other surveys (e.g., MWD magnetic surveys) and largest for poorly controlled surveys (e.g., single-shot magnetic surveys). A well can be safely drilled if and when the ellipses between two wells do not touch or overlap and are a minimum distance from each other. If the ellipses touch or overlap, resurveying one or both wellbores using better survey instruments may remedy the situation.

Rig personnel involved (operations only)

Members of the drilling contractor’s crew may be needed to help perform the survey. MWD/LWD survey instruments are run in hole with the drilling BHA. The driller and the personnel on the rig floor are required to help make up and install the various pieces of the BHA. In most cases, the MWD/LWD crew and the directional driller must measure the offset between the MWD/LWD survey instruments and other drilling tools (e.g., rotary steerable tool, whipstock, mud motor, MWD or surface equipment) prior to running in hole. Gyro instruments are usually run on wireline into the drillstring. Besides the needed rig floor personnel, the gyro-survey engineer and the wireline operator are also needed for this operation. Single-shot surveys are run on slick line or dropped in the drillstring to be retrieved later. The survey engineer, rig floor personnel and/or a slick line operator are needed for this operation.

Safety and handling

As with all rig floor procedures, care must be taken when dealing with heavy equipment moving up, down and sideways. Particular care must be taken when running tools on slick lines. Stay away from moving parts, sheaves and the wireline drum if at all possible. Keep hands and other extremities, as well as hair and clothing, away from moving parts and the line when you must be in the vicinity. Use the appropriate personal protective equipment (PPE).

Defining the directional drilling objective

The basic premise of directional drilling is to drill a well from a fixed-surface location to desired subsurface locations or targets. Directional drilling objectives are governed by surface locations and subsurface targets; however, considerations are required beyond merely connecting the dots from point to point. Surface locations offshore from fixed platforms offer the best explanation.

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DD-11

Surface locations

Many constraints determine a surface location. On land, there may be physical constraints such as lease location and size; road access; waterways such as lakes, rivers, ponds or swamps; topography such as hills, valleys and mountains; and developments such as buildings, roads and parks. Other conditions, such as proximity to publicly- sensitive locations or sites of historic or social significance, may also be determining factors. Offshore, the surface location will be constrained by the physical location of the drilling unit. If it is a mobile drilling unit (e.g., a drillship, jackup or semisubmersible drilling unit), the rig may be located directly above the desired drilling targets. Occasionally, however, this may not be possible due to obstructions on the sea floor or sea current patterns. Additionally, the driller may be attempting to penetrate multiple subsurface targets that are not directly above one another. In this case, the mobile drilling unit cannot be located directly above all the desired well objectives. Fixed drilling units offshore on platforms of any type will require both directional drilling to navigate away from the existing wells on the platform and penetration of subsurface targets in achievable proximity to the platform.

Subsurface targets

The reservoir to be exploited is typically much larger than the surface area of the platform. Additionally, reservoirs generally require multiple wells to efficiently recover as much hydrocarbon from the field as possible. Depending on the characteristics of the reservoir, a blend of production and injection wells may be required to facilitate optimal recovery. As a result, strategic placement of the wells is required to achieve best production. For example, in simplest form, placing injection wells around the periphery of the field with producer wells in the middle will allow the injection pressure to push the reservoir fluids from the boundaries of the field toward the production wells in the center, thus enhancing and optimizing field production. In reality, reservoirs are often dipping in various directions, as subsurface pressures may have broken up the stratigraphy into various fault blocks, complicating well placement requirements and adding to the complexity of the directional drilling requirements. Drilling targets are therefore typically derived by the subsurface experts within the operating company – petrophysicists, geophysicists, geologists and reservoir engineers.

Sizing of the target

The sizing of the target is not arbitrary. Depending on the objectives of the well and the anticipated reservoir pressures, placing the well in the correct spot becomes critical to production success. In very new fields, large fault blocks may have trapped very high reservoir pressure. On entry into any part of the fault block, it is quite possible the well will be an immediate success as the pressure is suitably high to push the reservoir fluids to surface easily. If the well penetrates

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DIRECTIONAL DRILLING

only the top part of the reservoir, however, this pressure will ease over time as the well produces. This pressure easing is called drawdown. Recoverable reserves may be left behind if the wells are not optimally placed in the beginning of the life of the field. Nevertheless, a good understanding of the various subsurface structural challenges is only understood as the field produces over time. As a result, attempting to size targets continually results in a catch-22. The more one drills, the more one becomes aware about the best place to drill wells to optimize recovery. It is important to remember though that the best recovery is already influenced by previously-drilled wells. From a directional drilling perspective, and with respect to reservoir requirements, directional drilling targets become more challenging as a field ages.

the magnetic field varies more when drilling east to west across magnetic lines of flux. It therefore becomes evident that maintaining survey quality within even a single well is a significant challenge. Wells that are drilled in close proximity to other wells present complex survey problems because the MWD sensor will pick up magnetic readings from offset wells that are close-by. If the proximity cannot be avoided, gyro-survey instruments may be required to properly survey the well. Although a gyro survey is not influenced by nearby magnetism, the gyro measurement is influenced by vibrations, shocks and other motions typical in drilling environments. An absolute best measurement between magnetic versus gyro is not likely; trade-offs will be required at different points in the well.

Anti-collision

Survey accuracy

Anti-collision is an additional directional drilling challenge that presents itself as a field ages. As more wells are drilled in a field, the risk for potential well collisions grows; thus, the anti-collision objectives when drilling new wells can become very complicated. Some platforms offshore may have more than 50 individual well slots with potentially multiple wells per slot. Furthermore, multiple platforms may be required to fully produce the field. Each platform may have an equal number of wells. Because of anti-collision issues, the well design trajectory required to ultimately penetrate the reservoir target can be so complex that the well may be steered in completely the opposite direction from the final target merely to get away from the platform and avoid collision risk. This situation presents yet another challenge for the well, as this departure will increase the length of the well and will also add what may seem like erroneous well curvature along the borehole path. Related torque and drag considerations will be discussed in more detail later in this chapter. Multiple wells also present issues with survey quality. Today, the most common MWD tools utilize magnetic sensors to determine the direction of the well path. They are often coupled with a gravity sensor or direction and inclination (D&I) package that determines the inclination of the well. This D&I package continuously measures the magnetic field, which translates to a corresponding azimuth, or direction, of the well. The sensor must be isolated from nearby magnetic material in order to deliver a clean measurement. Obtaining this clean measurement within the drillstring itself is achieved by isolating the MWD tool from the rest of the steel drillstring with nonmagnetic collars and/or nonmagnetic heavyweight drillpipe (HWDP). The length of nonmagnetic material, and the spacing of MWD sensors within the BHA, is a function of the latitude of the drilling location and the direction in which the well will be drilled. The Earth’s magnetic field is much stronger at the poles than at the equator. The measurement of the strength of

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Survey accuracy will also influence target size. Regardless of the survey instrument used, there will be a small measurement error. This error can be affected by several factors such as the survey instrument quality and calibration; the surveying technique; pipe movement; survey frequency; hole size and condition; the BHA ; the well trajectory; and the geographic location to name only a few. In addition, surveying errors compound over the length of the well and the well position can be somewhere within a cone of uncertainty that reflects the maximum accumulated survey error. Understanding this cone of uncertainty is important when designing the geological targets for the well. The target defined by the subsurface team must account for this error to ensure the well penetrates the desired reservoir target. This uncertainty presents another challenge because this type of departure will also increase the length of the well and add what may seem like erroneous well curvature along the borehole path. The tortuosity of the well as a result of this complex curvature puts added strain on the drillstring and rig-drive system. Detailed torque-and-drag modeling becomes a requirement during the design stages of the well to ensure that the well can be drilled to the desired location with the equipment available. Enhancements to a drilling system, such as high-torque drillpipe, casing protectors, roller reamers, etc., could be required as a result.

Trajectory design considerations

Once the surface location and subsurface targets are known, the trajectory planning can commence. Trajectory design, however, is not as straightforward as it would appear. The well design with its respective casing and liner sizes and depths will constrain the trajectory. The rock properties in each hole section must also be considered. Certain directional drilling objectives cannot be achieved if the hole size and rock properties are not conducive. The BHA and drillstring components, such as the drive system and bit type,

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DD-13

will also influence the trajectory design, or vice versa, and will be selected based on trajectory design.

deflection of BHA components, enhancing the dogleg capabilities of the drilling assembly.

Designing a directional well will require blended consideration of several factors. It is easiest to lay out the factors one at a time and describe how each plays a role in optimum trajectory design, both positively and negatively.

Drilling fluid

Hole depth

Shallow-set casing is generally drilled vertically, as the rock near the surface is not competent enough to support large deviations in well trajectory. The larger casing strings are also not flexible enough to support much change in direction. In addition, the more well deviation that occurs in the shallow part of the well, the greater the friction losses will be deeper in the well. The majority of shallow directional requirements in large holes are for collision- avoidance purposes. The best trajectory design will attempt to achieve the directional drilling objectives of the well as efficiently as possible. This is best done in the shallower part of the well where the rock is softer and drilling can proceed faster once the larger-surface casing strings are run. Weight and torque transfer to the bit is more efficient at shallower depths; however, a few drawbacks must be counterbalanced. First, it is necessary to account for the overall depth of the well, as well as torque and drag considerations deeper down. The formation must also be competent enough to accommodate wellbore deviations, or doglegs, if they are required to reach the targets.

Hole size

As a rule, it is more difficult to achieve a larger dogleg in a big hole because of the reduced flexibility of the larger diameter BHA components and the competency of the rock at shallow depths. Large weight on bit (WOB) is required to bend the BHA components and achieve the necessary deflection to redirect the wellbore. Shallower depths do not typically have rock competent enough to support the WOB required to achieve the deflection.

Rock competency

Rock competency determines the limits of achievable dogleg severity (DLS). Soft rock may not support large deviation as the hydraulic power through the bit will cause hole enlargement before deviation can be achieved. On the other hand, if the rock is too hard, deviations will be difficult as the drilling process is too slow to redirect the well efficiently.

Wellbore inclination

Deflecting a well from vertical will require a higher ratio of steering. As inclination increases, wellbore deflection becomes easier. Gravity will begin to play a role in aiding the

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The drilling fluid has a significant impact on BHA directional performance for several reasons. First, the fluid type will impact hole gauge. If the hole is out of gauge, borehole contact with the BHA components required to impart bending force on the BHA will be thrown off and achievable dogleg will be impacted. In most cases, the DLS will deteriorate. In exceptional circumstances, however, the wellbore may be so out of gauge that excessive deflection occurs. In either case, the results will be unplanned and the outcome less than desirable. Wellbore friction is also affected by the drilling fluid. High friction will impact weight transfer and torque transfer to the BHA, negatively affecting directional performance and achievable dogleg. Hole cleaning will impact DLS as weight transfer is more limited if the hole is filled with cuttings. Mud design must be appropriate for the trajectory design to ensure that hole cleaning and borehole stability are effective. Mud weight is an additional factor affecting directional performance. Higher mud weights result in slower drilling and directional drilling becomes more difficult. If filter cake builds up along the wellbore due to the higher mud weights, it will impact weight transfer as the drillstring drag will increase. If this situation deteriorates, there is a serious risk of stuck pipe, particularly during slide drilling.

Hydraulics

Proper hydraulics is essential for effective bit performance and hole cleaning. Good jet-impact force at the bit will improve the ROP which will facilitate good directional response. The orientation of the jets may also impact directional response of the drilling system as the jet may cause hole washout ahead of the bit and undermine the directional efforts. Further up the hole, good hydraulics will keep the hole clean and improve weight transfer to the bit. At surface, pressure limitations on the pumps will affect flow rate, which in turn will impact the power supplied to the bit either through a motor, across the bit or through a RSS. All of these aspects will influence the directional capabilities of the drilling system.

Drillstring RPM

Drillstring rotating speed in revolutions per minute (RPM) is often the best means of agitating cuttings to help carry them out of the well; however, RPM will have an impact on trajectory. At higher RPMs, the string will stiffen and this will negatively impact the directional response of the BHA. High RPMs are also more prone to wipe out doglegs achieved in

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DIRECTIONAL DRILLING

Well profile types

Directional wells are often classified based on the type of profile. Directional profiles dictate the type of BHA components required and may also dictate the rig requirements needed to achieve the well objectives. A list of profiles, the well requirements dictating the need for such profiles, and BHA and rig considerations are described below.

Vertical Wells

Vertical wells are the simplest directional profile. If the formation allows, no directional control is required to maintain vertical. As formation strength increases, however, more WOB is required to achieve the ROP. As the WOB increases, the BHA components can flex and cause deflection of the well profile. In these cases, directional drilling may be required to return the well to vertical and ensure target penetration.

Basic directional wells – J- and S-profile

This well type is required when the rig cannot be located above the desired subsurface target (Figures DD-11a and DD-11b). The kickoff point (KOP) is the depth in the well at which point the direction begins to deviate toward the desired target. The depth of the KOP is a function of the distance required to drill to the target, the formation type and

True vertical depth

Horizontal wells

Horizontal wells are designed to intersect a target reservoir laterally at a designed vertical depth and remain within this reservoir for the length of the designed well section. The length of the lateral may be governed by reservoir size, lease boundaries or rig capabilities. The type of reservoir may vary from an ancient sandy riverbed to a limestone cave system. The objective may also be to intersect multiple natural fractures along the horizontal section that will flow hydrocarbons into the wellbore. More common now in unconventional reservoirs, the desired target may be a shale known to contain hydrocarbons that are released when the well is hydraulically fractured along the reservoir. Horizontal wells commonly use some means of LWD measurements to help geo-steer the well and remain within the reservoir target. From a rig perspective, rotary torque, hoisting capability and hydraulic horsepower (pump-pressure rating) are considerations for drilling a designed horizontal profile.

True vertical depth

KOP

}

the hole size. J- profile wells are common for single-target wells, multi-target wells at angle or wells that are a good distance from the rig location. S-profile wells may be designed for multiple stacked targets and wells closer to the rig. Similar to vertical wells, the J- and S-profile wells are generally not limited by hole size or rig capabilities. The depth of the well and drawworks load will determine the rig requirements.

KOP Build section EOB Tangent

}

the well after steering because wall contact with the drillstring will be more forceful.

}

DD-14

Build section EOB

Horizontal departure

Horizontal departure

Figures DD-11a and 11b: Examples of J- and S-profile wells (left and right, respectively).

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Extended-reach drilling

Extended-reach (ER) wells are very long wells with significant lateral reach to vertical depth ratio. Horizontal wells often fit this classification. Other types of ERD wells are required if a rig cannot be located close to the reservoir. In the early 1990s, ERD wells gained attention because of a BP Wytch Farm development campaign in Poole Harbour offshore Southern England. The region was a well-known tourist destination and offshore platforms were not desirable. Wells were drilled from a very powerful land rig, reaching out under the sea with ERD wells stretching more than 10 km offshore at a vertical depth of 1,600 m. The drilling campaign led to the development of new directional drilling technology, such as AGSs and RSSs. The technology pushed the boundaries of ERD drilling. As with horizontal wells, ERD wells challenge the limits of the rig from torque, hydraulics and hoisting standpoints. Additionally, wellbore drag due to the tremendous depth may limit the ability to slide drill with motors or turbines. This means rotary assemblies or rotary steerable technology may be required. Rotary steerable technology, combined with downhole motors to help rotation, may also facilitate the drilling of this type of well.

Reentry wells

Capitalizing on the costs spent drilling an original wellbore, a reentry well will deviate from an existing borehole, usually through a casing exit. The casing exit is facilitated with a mechanical whipstock oriented toward the desired reservoir target. Special milling and casing exit equipment is usually required to initially exit the wellbore. Whipstocks can usually be set at any depth, provided the casing size accommodates the desired hole size to exit the well and still reaches the target reservoir objective with single or multiple casing/ liner sections. Additionally, the rig must be capable of setting and triggering the mechanical anchoring device for the whipstock.

Short-radius wells

Short-radius wells have extreme doglegs exceeding 36°/100 ft drilled. Such wells may often be reentries. To accommodate such high DLS, one’s BHA and drillstring components must be very flexible. Tubulars with small outside diameters of 3 ½ in. or less should generally be used. Specially designed downhole motors are commonly required for short-radius wells. These motors may have multiple bends to help accomplish such high doglegs. They may also have articulated bends, which are like a loose knuckle when rotated, but during sliding will lock into place and allow the well to be directed at high dogleg. Short-radius drilling can be very challenging, because directional control is complicated by the articulated motor. MWD survey packages must also be at a sufficient distance from the magnetic BHA components to prevent interference and deliver good surveys. This distance is often 50 ft or more. A well that deviates at such a

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DD-15

high angle has the well direction established beyond repair by the time the early surveys are taken. The only recourse for correcting deviation errors is cementing off the well and redrilling. Rig requirements are generally benign as the drillstring has a small interior diameter (ID); the hole size is small; and consequently hook load and pump requirements are not taxing. Short- radius wells can even be drilled with coiled tubing units. The limitation with short-radius wells usually comes from completion and production sides, since the very small well diameter reduces the volume of produceable oil and gas.

Coiled tubing directional drilling

As with short-radius wells, coiled tubing directional drilling (CTDD) wells are typically limited due to the diameter of the coiled tubing. Because the coil is not able to rotate, directional drilling applications require special tools. A typical CTDD BHA requires a downhole motor to rotate the bit as well as a means of orienting the motor. Orienting devices have a ratchet-type lock at various toolfaces that are activated either electrically or hydraulically depending on the design. Due to the inability of this type of application to rotate, the wells are steered continuously, alternating the toolface to achieve the desired well profile. Alternatively, recent advances in small-diameter rotary steerable technology have enabled a BHA system that uses a motor to rotate a rotary steerable tool and bit at the end of the coil, eliminating the need for the orienting device. This combination allows for a straight well path between steering sessions and improves the overall well profile. Coiled tubing units use an injector head to push the coil into the well. The push power must overcome wellbore drag along the length of coil in the well while also providing the desired WOB. Because the coil cannot rotate, this drag can be substantial. Due to the tubing diameter, buckling is a high risk. Advances in coiled tubing hybrid rigs that combine coiled tubing and drillpipe have expanded the range of wells that can be drilled with coiled tubing. In some rig designs, the entire coil reel can be rotated at surface, eliminating many of the limitations of coiled tubing drilling.

Multilateral wells

The first multilateral well was drilled in the Soviet Union in 1953. Multilateral wells incorporate multiple departures from a main wellbore. This type of well may be used to develop fields with low-reservoir pressures that require reservoir contact to move hydrocarbons such as heavy oil applications. Additionally, multilateral wells may be a means of reducing overall development costs by eliminating the expense of drilling multiple wells from surface to reach the reservoir. Departure from the main wellbore is achieved

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DIRECTIONAL DRILLING

The drill bit will try to climb uphill, or up dip, in laminar formations. In general, it is much easier to drill a straight or nearly vertical hole in soft formations than in very hard formations. The effect of the drillstring bending and the influence of formation dips may be much less significant when drilling soft formations. Drilling hard formations at high dip angles requires high bit weights and works against drilling a straight or vertical hole.

Hole gauge Side force at bit Resultant force at bit Bit tilt angle

Side force at stabilizer Hole axis

Formation ansitropy

Figure DD-12: Forces acting on the drill bit and stabilizer.

through sidetracking off specially- designed mechanical devices or in open hole, depending on the competency of the rock and the completion plans for the well. The limitation of this approach is the hole size of the lateral legs off the main wellbore and the degree to which this wellbore size may impact wellbore production. Additionally, post-well intervention is important to consider. It may also be necessary to isolate different legs of the laterals along the wellbore depending on how the production engineer wishes to develop the field. As the complexity of the multilateral production and intervention requirements change, the complexity of the multilateral system requires changes as well.

Steam-assisted gravity drainage wells

Steam-assisted gravity drainage (SAGD) wells are essentially a pair of horizontal wells drilled in close proximity, one atop the other. This is a common application in heavy oil sands where heat is required to facilitate the flow of hydrocarbons. The top well is used to inject steam into the reservoir while the oil is produced from the bottom well. From a directional drilling perspective, the proximity between wells must be a precise distance in order to achieve the desired thermal effect and melt the oil without having too much steam break through into the producing well. Specialized magnetic-ranging technology is required to steer one well relative to the other and maintain this distance. The first lateral will be cased off after drilling; the second lateral will have special instruments that can measure the magnetic field of the casing in the offset well, guiding the steering.

Deviation control

A common problem in the drilling industry is the delivery of a smooth, cylindrical, vertical borehole. It is surprisingly difficult to maintain verticality while drilling as formation effects, BHA bending, bit-side cutting force and drilling dynamics all act to deviate the well path.

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Vertical wellbores are essential because operators must: •• Stay on a particular lease and not drift over onto adjacent property; •• Drill a near-vertical hole to meet field rules and legal requirements from regulatory agencies; •• Ensure drilling into a specific pay zone, e.g., a stratigraphic trap, a lensing sand or a fault block; •• Avoid production problems such as rod wear, tubing leaks, trouble setting packers and distorted casing; •• Ease the running of casing, ensuring better cement bonds and minimizing casing wear; •• Limit torque-and-drag due to curvature. The need to control the rate of build is driven by the need to drill a functional hole with a full-gauge smooth bore that is free from excessive doglegs, keyseats, offsets, spirals and ledges. In the early 1960s Arthur Lubinski made the point that rate of change in angle (expressed in degrees per 100 ft) is more important that the total deviation from vertical. At the time tables were used to determine the maximum permissible dogleg that would be acceptable for rotary drilling and completion (Lubinski, 1990). In the modern era, torque and drag and finite element analysis mathematical models determine each well’s maximum allowable dogleg. Generally, the tolerance for high dogleg increases with depth. The deeper the point of maximum curvature, the less the tension in the pipe. This is due to the fact that there is less weight hanging below the bend and therefore less lateral force exerted at the apex of the bend. The tension in the drillpipe forces itself laterally into the inside of the curve and wears a groove into the rock. This lateral force is proportional to the weight below the dogleg. A keyseat, a small-diameter groove worn into a large-diameter borehole, is usually formed in soft formations where drillpipe is pulled through an abrupt change in hole angle or direction. When large-diameter drillstring components are pulled into the groove, the string is restricted from moving upward. Keyseats can be prevented by restricting the DLS and can be removed by enlarging the diameter of the groove with downhole tools such as keyseat wipers and reamers. (Figures DD-12 and -13).

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DOG-LEG

KEY SEAT

Tension

Tension

DD-17

Borehole patterns, keyseats, and doglegs Drillpipe (DP) fatigue

•• Failure of the DP tube caused by stress reversals as pipe is rotated across the bend. Top View of Key Seat Section Lateral Force

B A

Stuck pipe

•• Large-diameter tools are pulled into keyseat; •• Poor hole cleaning due to hole enlargement and irregular hole geometry; •• Collapse of borehole wall.

Wellbore positioning

•• Loss of steering control in directional wells; •• Inability to intersect desired target. Tension

Wireline logging

Tension

Figure DD-13: Problems related to severe doglegs. A keyseat (right) is a small-diameter groove that wears into a large-diameter borehole. Key seats are usually formed in soft formations when drillpipe is pulled through an abrupt change in hole angle or direction.

•• Stuck tools in keyseats; •• Increased line tension due to capstan effect (wireline operations); •• Poor log quality, particularly from image logs, from damaged borehole wall.

Casing

•• Stuck casing; •• Distorted casing; •• Inability to run completion equipment. Figure DD-14a, b and c: Conceptual examples of three undesirable borehole patterns—from left, spiraling, hourglassing and rippling. Courtesy Baker Hughes.

Borehole patterns

Casing wear

•• Hole in casing caused by friction from drillpipe; •• Loss of pressure integrity.

Spiraling, corkscrewing, hourglassing, rippling and the formation of ledges and other borehole patterns are additional undesirable effects commonly encountered while drilling. These patterns are a consequence of bit tilt, bit side- cutting force, bit design, stabilizer spacing and BHA bending as well as formation variability, formation dip and bedding planes (Figure DD-14).

Cementing

Lateral movement of the bit, while drilling, occurs when an oscillation in the drillstring is transferred to the bit. This is common when low WOB is used with high rotary speeds. The lack of engagement of the bit face allows side cutting by the bit shoulders. This movement, or whirl, is repeated at high frequency and causes hole enlargement as the bit moves about the borehole from one side to the other. Once started, the pattern is self-generating and can be difficult to stop even when additional weight is placed on the bit. Drilling with whirl reduces drilling efficiency by causing hole enlargement, accelerated bit wear, spiraling, lateral vibration and stabilizer wear.

Control of hole angle

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•• Poor cement bond caused by off-center casing.

Production problems

•• Rod wear; •• Tubing leaks; •• Difficulty running packers.

Dumb-rotary BHAs, assemblies with neither mechanical nor electronic deflection devices, are the most economical approach to drilling simple trajectory wells. While fine control of azimuth is not always possible, a reasonable ability to control inclination is available with rotary BHAs. Gravity deflects and pulls on the BHA, allowing for inclination control. An inclined borehole is necessary for this method to be effective. The hole is drilled by the bit, and the BHA follows the bit. Two factors determine the directional behavior of the bit: the side force acting on the bit and the bit tilt angle. Both the force and the angle are controlled in rotary drilling assem-

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Figure DD-15: Two factors determine the directional behavior of the bit: the side force acting on the bit and the bit tilt angle.

blies by varying the size and spacing of the stabilization and by modifying the weight and rotary speed of the bit. (Figure DD-15). Three principles guide BHA design and influence bit, mostly in the vertical plane: the pendulum principle, the fulcrum principle and the stabilization principle.

Pendulum principle: drop inclination

The pendulum principle was the first directional control principle to be formulated, and was originally analyzed for slick assemblies drilling straight holes. The major design feature of a pendulum assembly is that there is either no near-bit stabilizer or an under-gauge near-bit stabilizer. For deviated wells, the portion of the assembly from the bit to the first string stabilizer hangs like a pendulum, and the weight of the pendulum presses the bit to the low side of the hole. In most cases where a pendulum assembly is used, the main factor causing deviation is the vertical component of the forces at the bit acting on the low side of the hole (Figures DD-16a, -16b and -16c). The length of collars from the bit to the first string stabilizer, the ‘pendulum,’ must not be allowed to bend too much toward the low side of the hole. If the collars make contact with the low side of the borehole, the effective length of the pendulum and the side force are both reduced. This situation could result in the bit axis tilting upward in relation to the hole axis, thus possibly reducing the dropping tendency and producing a build tendency. Careful selection of drilling parameters is therefore required.

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Figures DD-16a, b and c (from left): 90-ft pendulum BHA, 10-ft pendulum BHA and 8-ft locked BHA to maintain vertical. Courtesy Baker Hughes Inc.

Figures DD-17a and -17b (from left): Fulcrum assemblies typically utilize a full-gauge near-bit stabilizer and undergauge second stabilizer. From top, a 90-ft fulcrum BHA and a 60-ft fulcrum BHA. Courtesy Baker Hughes Inc.

High rotary speed (120-160 rpm-plus) helps keep the pendulum straight to avoid the situation mentioned above. Initially, low WOB should be used. Once the dropping trend has been established, moderate weight can be used to achieve a respectable ROP. Pendulum assemblies are prone to vibration and the creation of undesirable borehole patterns caused by a lack of stabilization at the bit. The low WOB required also results in slow ROP. Current thinking prescribes, rather than an un-stabilized bit, a near-bit stabilizer and a closely spaced (6- to 12-ft) string stabilizer to create a pendulum while mitigating vibration and improving hole quality.

Fulcrum principle: build inclination

Fulcrum assemblies typically utilize a full-gauge near-bit stabilizer and under-gauge second stabilizer. A side force is applied to the low side of the hole at the near-bit stabilizer which acts as a fulcrum to cause the bit to tilt toward the high side of the hole. The upward tilt of the bit cuts against the high side, increasing the inclination. The greater the WOB applied, the greater the force exerted on the high side (Figures DD-17a and -17b).

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Figure DD-18: Schematic illustrating tool behavior with and without stabilizers (right and left, respectively. At right, three stabilizers placed in quick succession behind the bit are separated by short and stiff drill collar sections. The three stabilizers will resist rounding a curve and forcing the bit to drill a reasonably straight path. The first of the three stabilizers should be immediately behind the bit, i.e., a near-bit stabilizer, and should be full gauge.

Rate of build can be increased by the following: •• Increase the distance from the near-bit stabilizer to the first string stabilizer; •• Increase hole inclination; •• Reduce drill collar diameter; •• Increase WOB; •• Reduce rotary speed •• Reduce flow rate in soft formations.

Stabilization principle: maintain inclination and direction Stabilized or packed assemblies are most effective when full-gauge stabilizers are used. The aim is to have the bit drill along the hole axis.

DD-19

Figures DD-19a and b (from left): The performance of a packed assembly can be fine-tuned by changing the length between the near-bit stabilizer and the first string stabilizer. This is particularly true at higher angle and bit weights. From top, a 10-ft packed BHA and a 20-ft packed BHA. Courtesy Baker Hughes Inc.

directional wells, maintaining angle and direction. High rotary speeds (120-160 rpm-plus) will augment the tendency to drill straight (Figures DD-19a and -19b). The performance of a packed assembly can be fine-tuned by changing the length between the near-bit stabilizer and the first string stabilizer. This is particularly true at higher angle and bit weights.

Full-gauge or near full gauge stabilizers are used at relatively short spacing to prevent bit tilt and bending in the drill collars as weight is applied to the bit.

Azimuth control

Three stabilizers placed in quick succession behind the bit are separated by short and stiff drill collar sections. The three stabilizers will resist rounding a curve and forcing the bit to drill a reasonably straight path. The first of the three stabilizers should be immediately behind the bit, i.e., a nearbit stabilizer, and should be full gauge (Figure DD-18).

The BHA will wander depending on the following: •• Formation effects (dip, bedding planes, anisotropy, etc.); •• BHA (stabilization, stiffness and drive mechanism); •• Turbine assemblies (typically walk left).

Assemblies which utilize this principle are called packedhole assemblies and are used to drill the tangent sections of

•• Roller-cone bits typically walk right; •• PDC bits lack predictable walk tendency.

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In reality there is very little control of hole direction when using dumb rotary BHAs.

Bit type and design

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jetting, positive-displacement motors (PDMs), drilling turbines, whipstocks and rotary steerable tools. These tools are used to initiate the kickoff from vertical to drill a planned trajectory to a specified target or to drill a sidetrack from an existing wellbore to a revised target at a controlled rate of curvature.

Figures DD-20a and b: Two variations of positive displacement motors. Courtesy Baker Hughes Inc.

As the various systems each have their own strengths and weaknesses, the choice of deflection device is determined by a variety of factors including the trajectory design, formation strength, well depth, drilling rig capability, daily cost, reservoir type and completion design. By any measure, the majority of directional wells worldwide are drilled with steerable PDMs.

Vertical drilling systems

Automated vertical drilling systems were the forerunner of today’s rotary steerable tools. They were initially developed in deep vertical wells drilled for research purposes. These automated systems detect any deviation from vertical and apply force to the borehole wall to drive the bit back toward vertical. Most service companies offer these vertical drilling tools in both stand-alone surface rotary driven and downhole motor-assisted variants.

Drilling parameters

•• Slow RPM generally walks right (direction of rotation); •• High WOB generally walks right (direction of rotation). The importance of stabilization in the control of wellbore trajectory cannot be understated and many technologies such as variable-gauge stabilizers have been developed to enhance the directional control of dumb-rotary BHAs. In addition, many automated vertical drilling systems, which continuously correct any deviation from vertical, have recently been developed by the large drilling service companies. Discussion of these various downhole tools are covered in another section of this manual.

Positive displacement motors (PDM)

Positive displacement motors (PDM) operate by converting the hydraulic energy generated by the rig pumps into mechanical energy to turn the bit. These motors have gone through enormous generational changes from their origins as a single high-speed, low-torque, high-RPM system mated with a bent sub to today’s steerable motors which come in a

Bottomhole assembly components

The BHA includes everything screwed to the drillpipe. The BHA comprises several components, all serving a particular purpose to help accomplish the objectives of the particular hole section being drilled. The directional driller ensures that all components meet the objectives of the run, validates the physical measurements of each component and visually inspects each component’s mechanical integrity. Typical BHA components, along with information on their influence on wellbore trajectory, are described below. Deflection tools currently used in directional drilling include

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Figure DD-21: Positive displacement motor. The drive mechanism is displacement by mud. Courtesy Baker Hughes Inc.

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DIRECTIONAL DRILLING

DD-21

Steel Elastomer Even wall stator

Standard stator

80% less elastomer Thin & “equidistant” elastomer layer Less distortion results in greater volumetric efficiency

Steel tube with cylindrical ID Varying elastomer layer thickness

Steel Elastomer Figure DD-22: Contoured steel vs. contoured elastomer. Courtesy Baker Hughes Inc.

variety of speed and power ranges (Figures DD-20a, -20b, and -21). Today’s motors are capable of a wide range of build rates as they can be configured with different bend and stabilization options. The housing-bend angle and stabilization geometry determine the maximum RPM that can be used in rotary mode and whether the motor can even be rotated. Motors are available with a variety of bent-housing geometries which influence bit-side force and buildup rate (BUR). Today, this includes adjustable and fixed-bend housings and short bit-to-bend configurations. Stabilization options which influence BUR and rotary drilling behavior include slick, fully-stabilized and partially-stabilized motors; clamp-on stator stabilizers; and a variety of kick pads to enhance the effect of the bent housing. Curved trajectory is achieved by the alternation of oriented-sliding (curved) intervals with rotary drilling (tangent) intervals. Motor-bearing sections have both axial and thrust bearings to deal with WOB and side forces. They are available in a variety of options including diamond bearings, sealed bearings and ball-and-race bearings. Motor power sections are available in a variety of torque, RPM and efficiency ranges. The stator of the power section has one more lobe than the rotor. PDMs are characterized

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by the ratio of rotor lobes to that of the stator, such that a 5:6 motor features five lobes on the rotor and six on the stator. Fluid pumped through the drillstring displaces the rotor inside the progressive cavities of the stator, forcing the rotor to turn. The mechanical characteristics of a PDM are such that as the number of rotor/stator lobes increases, RPM and mechanical efficiency decreases and torque output increases. Development of even-wall power section technology has greatly increased the power output of downhole motors. This stator technology uses a constant thickness of elastomer covering a variable thickness of steel to deliver torque and power increases of up to 100% over traditional stators, which have a variable thickness elastomer inside a constant-thickness steel tube. The contoured steel distorts less than contoured elastomer, resulting in greater volumetric efficiency (Figure DD-22). In general: •• With PDMs, torque is proportional to differential pressure; RPM is proportional to flow; •• The majority of PDM drilling is done with mid-range motors (5:6 or 7:8 lobes) to optimize between steering control and ROP; •• High-speed, low-torque motors are used to drill very hard rock with diamond-impregnated bits; •• Low-speed, high-torque motors are used to drill with

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Figure DD-25: PDM versus a turbodrill. Courtesy Baker Hughes Inc.

Figure DD-23: Drive mechanism for a turbine is the impact of mud flow.

large diameter PDC bits or with reamers; •• Increasing the bend in the motor increases both hole totuousity and vibration; •• BUR capability is governed by the motor contact points with the borehole (3-point geometry), which define a circle. The same geometric principles apply for RSSs.

Steerable turbines

Turbines have been utilized in the drilling industry for a number of years, primarily to drill very hard rock with diamond-impregnated bits or to drill through troublesome formations as quickly as possible. They have also been used to reduce stress on the drillstring by reducing the rotary speed at surface (Figure DD-23).

higher temperatures than mud motors; •• The operating life of turbines in terms of circulating hours can be 50-100% longer than PDMs; •• The BUR capability of turbines is less than that available from PDMs; •• Turbines generally have higher pressure drop across the tool than PDMs; •• Turbines are less tolerant of lost circulation material (LCM) than PDMs.

Rotary steerable systems (RSS)

Rotary steerable systems (RSS) operate on three basic design principles: •• Point the bit: the bit is angled to the desired direction as with a PDM; •• Push the bit: the hydraulic side force is activated near the bit face pushing the well trajectory to a desired direction; •• Combination of push-point principles. Figure DD-25 compares PDMs and turbodrills.

In general: •• Turbines induce rotation by the impact of mud flow on the rotor blades; •• With turbines, torque and RPM are inversely proportional. As torque increases, RPM decreases; •• The RPM is directly proportional to flow rate at a constant torque; •• Off bottom, turbine RPM will reach runaway speed and the torque is zero; •• On bottom, just at stall, a turbine achieves maximum torque and the RPM is zero; •• Maximum horsepower is achieved at half the stall torque and at half the runaway speed (optimum performance); •• Turbines operate at very high RPM and can operate at

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Like any BHA, the forces applied (either through gravity or by machine force) will act on the BHA and flex the components while redirecting the wellbore. The relationships between the BHA component flexibility, gravity effect and mechanical-applied force will all impact the directional performance of the system. The introduction of rotary steerable tools enabled the drilling of wells previously thought impossible (Figure DD-26). RSSs carried a premium price, but offer significant increases in efficiency. The RSS tools allowed the addition of extensive formation evaluation sensors to the BHA, allowing for realtime evaluation of the geologic space as well as optimized wellbore placement within the reservoir.

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Figure DD-26: Rotary steerable system. Courtesy Baker Hughes Inc.

Figure DD-27: High build-rate rotary steerable system. Courtesy Baker Hughes Inc.

With steerable motors, the forces necessary to overcome friction in oriented drilling meant that horizontal reach from surface was limited. Overall drilling efficiency was increased with RSSs due to higher overall ROPs achieved by reducing the time spent orienting and slide drilling (without rotation). In addition, as 3D steering was continuous, the same targets could be achieved more precisely with reduced curvature (2°-4°/100 ft) when compared to wells drilled with steerable motors. This reduced curvature also enabled the drilling of more complex profiles. Continuous rotation enhanced the quality of formation-evaluation measurements, particularly those yielding borehole images, and enabled the deployment of reaming while drilling devices for hole enlargement. Additionally, service companies developed rotary steerable tools with incorporated motor power sections near the bit, further increasing efficiency and extending horizontal reach. The ability to drill a smoother trajectory while continuously rotating allowed the drilling of more complex profiles and increased the available reach from fixed platforms, allowing field development with fewer wells and reduced capital investment. Typically, RSSs are capable of delivering 6°-7°/100 ft doglegs in 8 ½-in. hole size. Dogleg capability decreases as collar size and hole diameter increase. Conversely, dogleg capability increases as collar size and hole diameter decrease.

High build rate rotary steerable systems

Initially, rotary steerable tools were only deployed offshore where operating costs and rig rates were high, but the advent of unconventional resources in US land plays and the unique needs of those wells drove the development of a new generation of rotary steerable tools.

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Shale play wells are typically drilled to maximize reservoir exposure for fracturing operations, which are the largest component of the well cost. Correlation of the target formations via a gamma ray measurement is required for well placement, but the difficulty of formation evaluation in shale precludes the need for traditional measurements such as resistivity and neutron density. Constraints of tight boundaries and small leasing units require rapid build rates to maximize the lateral length. Wells are drilled to KOP and the angle built to horizontal at 8°12°/100 ft. Finally, an extensive lateral section is drilled through the reservoir. These wells require three different steerable PDM BHAs as the tool configuration needs to be adjusted for each of the vertical, curve and lateral sections. These multiple trips are not efficient, and the hole quality issues caused by fractional orientation, often require a cleanout trip before any casing or completion can be run. High build rate rotary steerable tools were developed to drill the entire well in one run Figure DD-27). These tools can maintain a vertical hole to the KOP, then build angle (capable of ± 15°/100 ft) through the curve and finally hold inclination in the long horizontal section. They contain only gamma ray sensors. This simplicity reduces the tool costs and increases drilling efficiency. From a client perspective, the superior hole quality allows immediate running of casing or completion and yields a better cement job or better production. The reduction in drilling time and subsequent well-construction savings lead to fewer days to deliver a well and a faster return on investment (ROI). One drawback is that rotary steerable tools can generate undesirable borehole patterns if used with shortgauge bits or if used with excessive deflection force.

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DIRECTIONAL DRILLING

Figure DD-28a and b: Examples of whipstock slides. At top is a short whipstock ,with a 3° slide angle, short radius, tight doglegs. The bottom shows a long whipstock, with 1 ½°-2° slide angle and a smooth window exit. Courtesy Baker Hughes Inc.

Open-hole whipstocks

Open-hole whipstocks are often used to initiate sidetracks in hard formations and also to perform sidetracks in horizontal sections where there is difficulty in laying a good cement plug. These whipstocks can be used in conjunction with other deflection tools to achieve difficult sidetracks. In fact, they can be used on sidetracks in place of cement plugs to save time. Stable anchors are a key to success with openhole whipstocks (Figures DD-28a and -28b). When using open-hole whipstocks, there are a number of planning considerations involved including: •• Anchor type (dependent on compressive strength of the formation); o Retrievable: mechanical, inflatable; o Permanent : cemented, mechanical, cemented inflatable; •• Cased-hole anchors (used with stuck liner or casing); •• Open-hole anchors (usually inflatable systems); •• Cemented tail pipe; •• Attachment to a fish (screwing into a fish, latching with an overshot).Anchor set mechanism; o Hydraulic; o Inflatable. •• Slide geometry; o Short (3° slide angle; short radius, tight doglegs); o Long (11/2°-2° slide angle; smooth window exit); o Note: The equivalent DLS of the whipstock slide curvature should be calculated to avoid exceeding connection tolerances. •• Orientation Method; o••MWD; o••Gyro.

Sidetracks

A sidetrack is defined as creating a new wellbore from an existing wellbore to the same or a different target. Sidetracks can be performed when casing is already in place; by cutting a window or milling a section of the casing; or in open hole with a cement plug, without a cement plug or with a permanent/removable whipstock. An open-hole sidetrack (OHST)

IADC Drilling Manual

can be executed as part of the original well plan or as the result of an unexpected situation, e.g., fish in the wellbore.

Sidetrack drivers

There are a variety of reasons to sidetrack a well: •• To exit the existing casing for reentry; •• To create the new legs or laterals of a multilateral well; •• To bypass fish or other obstructions in the original hole; •• To straighten a deviated hole; •• To develop a field with few slots; •• To land a well where a pilot well has already determined the correct zone; •• To hit a new zone or redefined target.

Sidetrack categories

•• OHST with motor: o Cement plug; o No cement plug. •• Cased-hole sidetrack: o Section milling; o Whipstock.

Design considerations

The three main considerations for selection of a sidetrack point are formation, depth and inclination. 1. Formation: To maximize the chances of success, the sidetrack point should be selected in the softest formation. Ideally, the formation should be softer than any cement plug used or should be between harder formations. Formation hardness will influence bit selection. It is better to choose a location of higher ROP—softer rock, for example. Trying to enter a hard rock would be considerably more difficult since the bit will always try to follow the path of least resistance. When using a motor or RSS, it is best to sidetrack at a place where the original hole has a build, drop or turn dogleg, i.e., sidetrack away from the original trajectory. 2. Depth: The depth of the sidetrack point determines the distance needed to be drilled (MD) to achieve the target and thereby the DLS required. The dogleg required will de-

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DIRECTIONAL DRILLING

DD-25

Figure DD-29: At top is a long slide whipstock (1 ½ - 2° slide angle) bottom short slide whipstock (3° slide angle). Courtesy Baker Hughes Inc.

termine the choice of deflection tool and the BHA design to achieve the sidetrack. 3. Inclination: The inclination at the sidetrack point is important because it dictates the sidetrack orientation relative to the high side of the hole. In an open-hole near-vertical sidetrack scenario, the sidetrack can be in any direction off a cement plug. In an inclined hole, gravity can be used to assist in getting away from the original hole by orienting the deflection tool to the low side of the hole. Orienting to the low side does not work with cased-hole whipstocks. If the wellbore to be sidetracked is vertical, a sidetrack will be more difficult to achieve since there is no support from the borehole to the BHA. In addition, the stabilizers will not be touching the borehole in a consistent manner. The best results would be obtained by using a whipstock or a good hard cement plug. Whenever possible, a drill-off test should be performed to evaluate the cement’s quality, i.e., strength. It is best to begin the sidetrack at the start of a joint/stand to avoid making a connection during the operation. Always try to stay on bottom. If it is necessary to make a connection, do not allow the pipe to rotate. While attempting a sidetrack in hard formation (unconfined compressive strength [UCS]>25k psi), a whipstock is the preferred choice since the cement will not be harder than the formation. For medium formations (UCS 15-25k psi), a motor with a good cement plug is the base for a successful sidetrack. For soft formations (UCS65°) as their weight and large OD increases friction against the borehole wall. HWDP is now more often used than drill collars to provide weight to the drill bit. This component is lighter and more flexible than drill collars, but heavier and stiffer than drillpipe. HWDP generates less friction and is more flexible; therefore, it is commonly run as a transition from the drill collars to the drillpipe in most directional wells.

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DOWNHOLE TOOLS

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

GeoSphere RESERVOIR MAPPING-WHILEDRILLING SERVICE

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CHAPTER

DH

DOWNHOLE TOOLS

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 David Herrington, National Oilwell Varco Lindsey Hughey, National Oilwell Varco Harald Witzler, National Oilwell Varco R.D. Morrison, National Oilwell Varco Scott Powell, National Oilwell Varco Ken Deringer, National Oilwell Varco

Dean Enterline, Baker Hughes Inc. Ron Dirksen, Halliburton Anthony Plana, Varel International Greg Hawley, Mesquite SWD Inc. Jaime Aros, Boretek.net

REVIEWERS Ron Dirksen, Halliburton Greg Devenish, Baker Hughes Inc.

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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: 978-0-9906220-8-6

Printed in the United States of America.

IADC Drilling Manual

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DOWNHOLE TOOLS Contents CHAPTER DH

DH-iii

Contents

DOWNHOLE TOOLS

Borehole enlargement ............................................................ DH-1 Physical operating principles......................................... DH-1 Common dimensions, weights, capacities............... DH-1 Related equipment............................................................ DH-1 Safety and handling.......................................................... DH-1 Applications........................................................................DH-2 Specialized situations.......................................................DH-3 Circulating subs ....................................................................... DH-3 Single cycle/single ball circulating sub......................DH-3 Multi-cycle/multi-ball tools.......................................... DH-4 Multi-cycle dart activated tools.................................. DH-4 Multi-cycle single ball tools.......................................... DH-4 Applications....................................................................... DH-5 Safety and handling......................................................... DH-6 General maintenance...................................................... DH-6 Downhole mud motors........................................................... DH-6 Top sub (saver sub)......................................................... DH-6 Dump sub........................................................................... DH-6 Rotor catch assembly...................................................... DH-6 Power section.....................................................................DH-7 Adjustable assembly and fixed housings................. DH-8 Applications....................................................................... DH-9 General maintenance.....................................................DH-10 Air hammers..............................................................................DH-10 Compressed air................................................................DH-10 Top sub...............................................................................DH-10 Case.....................................................................................DH-10 Piston....................................................................................DH-11 Driver sub...........................................................................DH-11 Drill bit.................................................................................DH-11 Check valve........................................................................DH-11 Bit retaining systems.......................................................DH-11 Choke...................................................................................DH-11 Air flow................................................................................DH-11 Lubrication..........................................................................DH-11 Safety and handling.........................................................DH-11 Rotary steerable systems (RSS)...........................................DH-11 RSS development.............................................................DH-11 ‘Push-the-bit’ tool...........................................................DH-13 IADC Drilling Manual

‘Point-the-bit’ tool...........................................................DH-13 Benefits...............................................................................DH-14 General maintenance.....................................................DH-14 Vibration, torque and drag....................................................DH-14 Description and basic theory......................................DH-14 Physical operating principles.......................................DH-14 Buckling..............................................................................DH-15 Drilling vibrations............................................................DH-15 Vibration analysis tools and software......................DH-16 Advanced torque and vibration technologies........DH-17 Measurement while drilling (MWD).................................DH-19 Description and basic theory......................................DH-19 Safety and handling........................................................DH-21 Applications......................................................................DH-21 General maintenance.....................................................DH-21 Logging while drilling (LWD)................................................DH-21 Description and basic theory......................................DH-21 Physical operating principles.......................................DH-21 Important for what and to whom?........................... DH-23 Standard location on a rig...........................................DH-24 Safety and handling.......................................................DH-24 Applications.....................................................................DH-24 General maintenance....................................................DH-24 Wireline logging......................................................................DH-24 Description and basic theory.....................................DH-24 Important for what and to whom?...........................DH-26 Standard location on a rig...........................................DH-26 Safety and handling.......................................................DH-26 Applications.....................................................................DH-26 General maintenance.................................................... DH-27 Jars............................................................................................... DH-27 Why do we need to jar?............................................... DH-27 Sticking.............................................................................. DH-27 What is a jar?.................................................................. DH-27 Mechanical jars...............................................................DH-28 Hydraulic jars ...............................................................DH-28 Applications.....................................................................DH-29 General Maintenance...................................................DH-30 Reference...................................................................................DH-30 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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Borehole enlargement

Hole enlargement, underreaming, and hole opening are all methods of increasing a wellbores diameter through the use of a fixed blade or expandable reamer during or after a well is drilled. This section will only focus on expandable reamers, while the fixed blades reamers information may be found in the drill bits section. The term hole enlargement is often used interchangeably with underreaming and hole opening. These operations are considered sub operations encompassed by the term hole enlargement, and are the methods of enlarging formation from an existing pilot hole. Hole opening is generally considered as the enlarging of a wellbore starting from the surface, with the expanded formation equal to or close to the inner diameter of any restrictions in the borehole. Underreaming is the method of enlargement formation at some point below the surface and beneath a restriction. The most frequently encountered restrictions are the ID of the casing and the wellhead or landing ring. All hole enlargement operations, like most drilling operations, limit the maximum outside diameter (OD) of the tools that can pass through. Historically, hole enlargement has been viewed as an undesirable, yet an often inevitable, operation for many wells. Expandable underreamers are often considered as a contingency, or necessary evil, when used in certain conditions—tight annulus, poor borehole formation conditions, and crooked boreholes. Running expandable underreamers in these applications aids in getting casing strings to TD and ensures an adequate annular volume for cementing. The practice of hole enlargement has increased over the years, beyond contingencies, wellbore remediation, and sidetracking. Especially in deeper drilling applications, the need for additional casing strings in straight and directional wells now requires tighter clearances between consecutive casing strings, and the need for increased annual area below a previous casing point. Historically this was achieved through dedicated expandable reamer runs or fixed blade reamer BHA’s. Expandable underreamers have become a more advanced solution to allow the running of fewer BHA’s for minimum clearance casing programs, which optimizes casing sizes. A growing need in hole enlargement applications, is the elimination of “rat hole”, the remaining pilot hole section below a standard reamer in the upper BHA. This remaining restriction limits the depth that casing may be set, and often requires a dedicated reamer run to enlarge this formation.

IADC Drilling Manual

DH–1

Physical operating principles

Generally, expandable reamers are activated (or deactivated) by dropping a ball or applying weight on bit to shear pins within the tool. New expandable reamers can activate the blades by adjusting the flow rate by dropping electronic chips. In the reamers, once the blades are activated, back pressure in the BHA will operate the tool and move the blades. This pressure is created from the restrictions of nozzles in the bit, small IDs of MWD/LWD tools, turbines, etc. The flow rates and back pressures to operate the tool are often calculated by the company providing the BHA or expandable hole enlargement tool. For this reason, it is important to follow the setup procedures recommended by these companies. Alternatively, the service company may provide a representative to support the reaming operations and configure the BHA and tools according to the calculated values. Expandable reamers are becoming more complex, and there operation is no longer dependent on the drilling fluid properties, instead they rely on internal mechanisms to function. The operation of the reamer blades begins with a signal sent from surface through pressure pulses in the drilling fluid or RPM variations. This signal is received by the tool where internal electronics, hydraulics, and motors move the blades. These tools will have service company support on the rig site to support the more complex functions.

Common dimensions, weights, capacities

The dimensions for most expandable reamers is determined by the casing and drill bit sizes. As the tool is intended to pass through a restriction and then open the hole, the largest outer diameter with the blades closed will be less than the restriction. In many cases the outer diameter of the tool body is approximately equal to the drill bit preceding the expandable tool. The tool body may be 1/4”– 1/2” less than the bit diameter to reduce friction and account for hole diameter variations.

Related equipment

In addition the expandable hole enlargement tools, a fixed blade stabilizer may be provided and run below the tool and an expandable stabilizer may also be placed in the BHA above the tool. These additional tools are intended to aid in stability and to reduce vibration transmission along the BHA or from the drill pipe.

Safety and handling Safe handling

Safe handling procedures will often be provided by the services company, and these tool may vary in length and other complexities, requiring special handling procedures.

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DOWNHOLE TOOLS

Operational risks

With expandable reamers, as with many mechanical downhole tools, various failure modes are present and have differing signals.

5. 6. 7.

A primary failure mode for reamers is washout, this failure is one of the most common as the expandable reamers require seals for blades functioning mechanism operated by high back pressure. If these seals fail, a decrease in pressure is often visible at surface, as with any washout. Additional washouts may occur with expandable tools with nozzle cavities. These nozzles, intended to clean and cool the cutting may washout and a similar decrease in pressure will be visible. To prevent washout, it is important to follow the drilling practices recommended by the tool provider including; drilling fluid properties, flow rates, and nozzle configurations. Recommendations may vary by tool, tool provider, and application.

8. 9.

Other risks associated with expandable hole enlargement tools are less evident at surface. These risks are related to vibrations and drilling dysfunctions in the BHA. These drilling vibrations are prevalent in hole enlargement applications, as traditional stabilization is less affective in enlarged wellbores. Most services companies have procedures to aid in the recognition and mitigation of the vibrations. Additionally, the services companies may have BHA and/or drill bit recommendation intended to prevent the vibrations from occurring.

Applications

All procedures for reamers may vary by tool provider. It is best to confirm specific procedures for a tool. The following information is provided for general reference.

Drop ball preparation procedures

1.• Rabbit the drill string to ensure the drop ball will pass through the drill string, especially the HWDP and DC’s. 2.• If running multiple drop ball reamers or stabilizers. These tools will likely require various ball sizes to activate. These ball should be identified and marked so they are dropped in the correct order.

Blade activation test (“window test”) 1.

Note the torque of the pilot bit while drilling the rat hole. 2. From the pipe tally and BHA measurements, position the expandable reamers cutter blades at the point to begin reaming and mark the drill pipe at surface, just above the rotary table. 3. Activate the cutter blades. 4. Increase flow and RPM to required parameters. Apply

IADC Drilling Manual

10.

11.

12.

weight and drill down about 10ft, then circulate for about five (5) minutes. Note the torque during reaming. Maintaining flow, stop pipe rotation. Make a second mark on the drill pipe at surface, just above the rotary table. Slowly pull the drill pipe up to surface pipe mark #1. Continue to pull on the drip pipe, once additional over pull of approximately 5,000-10,000 lb is noticed, STOP. This over pull indicates the blades have activated and are open. Slack off on drill string, shut off the flow, and rotate (30 to 40 RPM) to help de-activate the cutter blades (allow 1 minute). Pull up on the drill string until it clearly passes the surface pipe mark #1 as has entered into the previously drilled hole or the casing. This shows that the cutter blades are de-activated. RIH close to mark #2. Start pipe rotation and bring up the pumps as required. Apply weight and begin the drilling reaming operation.

A major challenge when drilling and reaming, is the potential for drilling off weight between the two cutting structures. This is most prevalent when drilling through transition zones in formation. Actions to Prevent premature damage to the bit and reamer when drilling through transition zones: 1.• When the bit enters the top of the inclusion or hard stringer a sharp decrease in ROP will be noticed. a.•Always monitor drilling dynamics and adjust parameters accordingly. 2.• Keep parameters until ROP increases. Indication that the bit exited the bottom of the inclusion. a.•Register approximate depth of the top and bottom of the inclusion. b. Confirm with MWD gamma ray and resistivity RT logs. c.•Register ROP and drilling parameters used while drilling the inclusion or hard stringer. 3.• When the reamer is about to approach the top of the inclusion/stringer. a.•ROP should not be higher than the ROP recorded when the bit drilled the same interval. Regardless of the bit ROP capabilities at the current point. b. RPM management is key to maximizing the hole enlargement tools cutter durability when drilling through the inclusions or hard / abrasive formations.

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DOWNHOLE TOOLS

Specialized situations

DH–3

Housing

Casing window exit Sleeve

When milling the casing window, 1-3 additional stands should be drilled to ensure the expandable reamer, expandable stabilizer, and any directional tools are clear from the casing or liner. Take valid directional surveys to ensure the directional plan is being followed. Make sure there is no risk that the pilot bit has tracked the cement outside the casing.

Drilling fluid flow “O” ring Shear pin Spacer thread sealant Pipe plug

Backreaming

•• Care should be taken once the pilot bit is pulled off bottom. At that point, the BHA will be in tension and low string RPM is critical to prevent pilot BHA whirl. •• Care should be taken as the bending moments increase while backing reaming drop sections. •• The pilot BHA stabilization is compromised as the lower BHA stabilizers are being pulled into the enlarged hole while back-reaming. 1.• Design the BHA in order to prevent the pilot bit from being pulled into the enlarged hole while back-reaming full stand. a.•The distance between the reamer blades and the bit should be greater than 1 stand (approximately 10 0ft), especially when heavy back-reaming is expected. b. If the pilot BHA is shorter than one stand, back ream only half the stand if required. 2.• Any evidence of formation change or stringers will cause increased torque as the cutters are pulled into those formation sections. a.•High torque spikes can cause damage to the cutting structure. If the hole enlargement tool causes stick/slip, the pilot BHA may continue to rotate. This may cause a pilot BHA twist-off. It is therefore important to know when these formation changes will occur and adjust the drilling parameters to suit.

Circulating subs

A circulation sub is a drilling tool used downhole (Figure DH-1). It can be placed in a variety of locations in the drill string, depending on the desired use. In simple terms this tool is used to divert drilling fluid flow and circulation path from the typical flow through the ID of the drill string, out from the end of the string and back to surface. The tool creates an alternative flow path by blocking the ID of the drill string and opening flow ports that direct fluid to the annulus. Circulation subs can be used in a number of applications,

IADC Drilling Manual

Figure DH-1: Single cycle circulation sub with shear pin and sliding sleeve.

though this chapter will focus on the two primary issues. These are the main uses for circulation subs. 1.• Using the tool to bypass the BHA to pump LCM for lost circulation situations 2.• Bypassing flow of drilling fluids to the annulus to increase annular velocities and turbulence. The latter is used in promoting efficient cutting transport to surface. There are a great number of variations of this technology, some of which are described below:

Single cycle/single ball circulating sub

The single cycle, single drop ball circulation sub is comprised of a ported body, a sliding sleeve, and a shear pin. The sleeve is shear pinned in place to maintain flow through the inside diameter, as well as closure of the annular ports (See Figure 1-1). This style of tool is activated by simply floating an activation ball down the drill string to land on a seating surface atop the sleeve. When the ball is landed, pressure builds above the tool shearing the pin and releasing the sleeve which travels downward within the tool, opening the annular ports. The ball then blocks flow to the bit and diverts it to the annulus. For years this technology has served the industry well, but the ports of this tool cannot be closed once the shear pin has broken and required the driller to pull the string to remove the tool making it less than efficient in today’s drilling world and so it is seen less often in the field.

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DOWNHOLE TOOLS around the BHA while boosting annular velocities above the circulating sub.

Multi-cycle single ball tools

These tools are operated by landing a steel ball on a steel ball seat, and creating differential pressure across the tool. This differential pressure forces the piston/sliding sleeve downward and opens the tool to the annulus once an activation flow rate has been achieved. These tools utilize a ball seat atop a ported valve piston (sleeve), an indexing mechanism, fixed mandrel, and a return spring. Once a ball has been landed on the seat, the valve piston is actuated axially on the fixed mandrel within the tool, landing in one of two different positions when the minimum activation flow rate is applied, depending on the position of the indexing mechanism.

Figure DH-2: Circulation sub with piston return spring in bypass position. Courtesy BICO Drilling Tools.

Multi-cycle/multi-ball tools

More advanced tools have added a spring mechanism below the sleeve to cause the valve piston to return to a closed position when pumps are shut down or when a ball is not on-seat, as well as the ability to pass the ball through the sleeve into a ball catch sub after bypassing operations are complete. (See Figure DH-2). This requires either the ball or the ball seat to be made from an easily extruded material such as nylon so that on or the other can deform, allowing the ball to pass thru. This effectively provides the ability to open and close the tool more than once. Confirmation of bypass or non-bypass positions can be determined by noting the pre-activation stand pipe pressure at a base line flow rate. In bypass position, a drop in SPP should be seen due to an increased total flow area (TFA) relative to the TFA of the bit and BHA. The number of cycles for this type of tool is proportional to the capacity of the ball catch sub. Due to the deformable materials used, these tools can be sensitive to temperatures and special attention must be paid when landing the activation ball to avoid premature extrusion of the ball thru the seat.

Multi-cycle dart activated tools

Additional tools also offer multiple cycles by way of a retrievable dart. They are for the most part identical in function to the multi-cycle/multi ball tools except that rather than collecting the activation balls below the tools, the dart must be fished each time the tool us used to deactivate. Additionally, thru-drilled darts offer the ability to split flow between the annulus and the bit allowing continued circulation

IADC Drilling Manual

In the bypass position (in which flow is directed to the annulus), the piston travels the full axial distance available for movement within the tool. This places the ports on the valve piston below the top of the mandrel which effectively seals off flow to the ID of the drill string, protecting the components therein from LCM or high flow rates. When the circulating pumps are shut down, a spring, located below the valve piston and indexing mechanism forces the piston back into its resting or “reset” position. When the pumps are restarted and flow is resumed above the activation flow rate it allows the indexing mechanism to shift to a secondary position which restricts the axial distance that the piston can travel downward. To allow for a non-bypass position, ports are located on the circumference of the valve piston which provides a flow path between the OD of the piston and the ID. The ports are positioned below the ball and seat to allow fluid flow that travels around the ball and seat to continue on a flow path into the ID of the piston and then through the ID of the mandrel and on to the BHA and bit. The ports are designed to align above the top of the mandrel opening, while sealing off flow to the external ports, when the landing position of the valve piston coincides with the non-bypass position. This provides the secondary flow path to the bit through the ID of the mandrel. To shift the tool from non-bypass back to bypass, the driller will shut down the pumps for 1 minute. Once flow is resumed above a specified flow rate the tool will be in the Bypass position. To shift back to non-bypass, this operation is repeated and can be done an infinite number of times. The above described positions can be viewed in Figure DH-2. This technology operates by utilizing differential pressure across the tool to actuate the piston; if flow is stopped or reversed due to sudden pressure below the tool, the valve will close. Only one ball drop is needed to activate the tool into its cycling mode. The current position of the tool can easily

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DOWNHOLE TOOLS

DH–5

be determined by comparing stand pipe pressure between shifts of the tool. A noticeable psi difference in SPP will be seen when shifting between flow to the bit and flow to the annulus (Figure DH-3). The amount of pressure differential seen depends on the size of the tool and restrictions in the BHA below. Temperature will not affect the maximum flow rate of the tool since a steel ball and seat are used.

Applications LCM Placement

The most common application for circulating subs today is placing aggressive LCM pills in lost circulation zones in the formation. Due to LCM’s nature to plug holes in the formation it is inherently hard to pass through BHA components with small through bores or passages, such as bits, downhole motors and MWD tools. Circulating subs are typically placed above these components and allow the use of aggressive LCM pills that would generally Figure DH-3: The 4 possible conditions in a multi-opening circulating sub. Courtesy National Oilwell Varco. clog up these BHA components. Circulating sub ports have large annular port diameters that are much harder to clog than bit jets or MWD bores. Once the circulation sub is activated, fluid only passes through these large OD ports and on to the annulus, thus bypassing the more sensitive BHA below. It is not uncommon to need to bypass the BHA multiple times during a single run due to lost circulation. For this reason, circulation subs with the ability to shift from bypass (flow to annulus only) to non-bypass (flow to the bit) are often used.

Wellbore cleanout

In wellbore cleanout applications, whether while drilling or during completion phases of the well, the tool permits an increased circulation rate to be applied by opening flow paths to the annulus of the well above the flow-restricting components of the BHA. Bypassing the BHA allows the maximum amount of fluid to be forced through the circulating sub OD ports to the annulus, thus increasing the total flow area and lowering the stand pipe pressure. In most cases, this is done while rotating the drill string to provide an evenly distributed 360 degree turbulence path where fluid is entering the annulus. ‘Bottoms-up’ circulating time is greatly reduced and hole cleaning is improved by bypassing flow to the annulus.

Deviated drilling

In deviated wells and especially in extended-reach laterals, the increased fluid velocity and turbulence aid in lifting cuttings up off the low side of the wellbore and homogenizing the distribution of cuttings within the drilling fluid. As velocity and turbulence decrease, farther away from the flow at

IADC Drilling Manual

Figure DH-4: Multi-opening circulating sub tool in lost circulation application.

the bit, gravity is more likely to act on cuttings and debris and cause it to fall to the low side of the wellbore. As cuttings build up on the low side of the drill string and around its sides, the contact area on which the string rests increases, increasing the frictional forces between the drill string and the wellbore. This of course causes increases in overall torque while decreasing the ability to effectively transfer weight to the bit. The end result is a drilling condition that raises the potential for stick slip, vibration, and stuck pipe events. Proper annular velocity and turbulence is required to suspend the cuttings in the fluid and make them available for transport up the annulus and back to surface. In wells such as these, where mud motors, MWDS, and other flow restricting components are present, it is often difficult to achieve flow rates high enough to generate turbulence and annular velocity high enough to effectively transport cut-

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DOWNHOLE TOOLS

Top sub/ Dump sub

Power section Rotor and stator

Driveshaft assembly

Adjustable assembly

Bearing assembly

Figure DH-5: Components of a downhole mud motor.

tings without over spinning the motor. In some cases, flow rates above a mud motors maximum flow rate are needed to clean the hole. By bypassing the motor and preventing overrun, a circulating sub can increase the motor’s reliability and operating hours. This reduces wear on the motor and reduces the chance of damage caused by high rpm seen when excessive flow rates are used to clean the hole.

the motor used to ensure proper connection type and to extend the usable life of the stator (Figure DH-6). The top connection is typically an API tool joint box, and is available with an optional “float bore” to accommodate API float valves. The lower connection usually uses a proprietary thread depending on the manufacturer that connects to the upper box of the stator housing.

Safety and handling

Dump sub

Care should be taken when dropping balls and/or darts down the drill-pipe to (de)-activate the subs.

The dump sub is also referred to as the bypass valve, dump valve and bypass sub.

General maintenance

Rotor catch assembly

Circulating subs are picked up and installed in the drillstring like most other smaller drillstring components. In most cases tongs should only be placed at the top and bottom of the sub for the purpose of torqueing and un-torqueing the connections. Tongs should not be placed around the area where the ports are located. Regular pipe dope is to be used.

Maintenance of the subs are mostly performed at the site of the supplier of the technology being used, however the threads that make up the connections should be maintained by applying proper pipe-dope and protected with the correct thread protectors.

Downhole mud motors

These are also referred to as mud motors, positive displacement motors (PDM), Moineau motors, performance motors, and progressive cavity pumps. See the separate chapter on Directional Drilling in the IADC Drilling Manual, 12th edition, for more information. Figure DH-5 diagrams the main components of a downhole mud motor.

Top sub (saver sub)

The top sub is simply a cross-over housing at the top end of

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The dump sub allows fluid to bypass the motor and fill the bore of the drill string when tripping into the hole. It also allows the drill string to drain when tripping out of the hole. When no dump sub is used, a wet trip out of the hole will occur if no other means of drainage is employed. There is little pressure loss through the dump sub when operating.

Extreme torque is generated at and near the power section and the joint connections are the weakest points in the string. For this reason some manufacturers include a rotor catch system that maintains a connection to the BHA even

Proprietary connection

API connection

Figure DH-6: Top sub of a downhole mud motor.

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DOWNHOLE TOOLS

Rotor catch ring

Stator

Rotor catch top sub

DH–7

Rotor Stage

?

Stator

Rotor

Nozzle or plug

6⅜ 4/5 7.0 Surge power section shown

Rotor catch stem

Figure DH-7: Rotor catch assembly.

Figure DH-9: Stage power section.

Rotor

Stator elastomer Stator major (valley)

Rotor major (peak)

Stator minor (peak) Stator tube

Rotor minor (valley)

Figure DH-8: Rotor and stator cross section.

if the connection between the power section and top sub breaks. This is a back-up mechanism to help prevent significant loss of equipment if the BHA were to break off at this point.

Power section

Power sections are the portion of the motor which transfer the axial force of mud flow into torsional force for transmission to the bit. The primary components are the rotor and stator (Figure DH-8). The rotor is a long helical steel component that sits inside the stator. The stator is a long tubular component with elastomer lining. The two parts fit together with a complimentary helical geometry that allows the conversion of axial force to torsional force. The rotor and stator are designed as helical elements with a major and minor diameter. The stator will have one more lobe than the rotor. The lobe is the curved spiral shape formed by the difference in the major and minor dimension. This difference in lobe count creates a fluid inlet area (cavity) where fluid can be pumped through to create rotation.

Transmission of axial to torsional force

•• The surface pump pressure forces mud into the power section inlet •• The first cavity at the top takes the mud in •• As this fluid cavity moves down through the stator, it pushes against the rotor, creating rotation

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Figure DH-10: Common lobe configurations with a generic summation of performance.

•• The cavity moves down through the stator, emptying out the bottom end •• Pressure continues to fill the spiral cavities and they continue rotating to empty •• Each cavity is a fixed (constant) volume, so the higher the flow rate, the faster the rotor turns A stage is the distance measured parallel to the axis between two corresponding points of the same spiral lobe (Figure DH-9). This distance is commonly referred to as the lead of the stator. A power section’s design is identified by its outer tube diameter, rotor/stator lobe configuration and number of stages. Tube sizes range in general from 1 11/16-in. to 11 ¼-in. tube OD. The lobe configuration selection is dependent on the application need. As a general rule, a high rotational speed power section will produce lower torque; inversely a low speed power section generates higher torque. Figure DH-10 shows common lobe configurations with a generic summation of performance: The rotational speed generated by the power section is proportional to the rate of fluid flow through the power section, i.e. increasing the flow rate through a given power section directly increases the output speed. To increase the output speed of a power section without changing the flow rate, the cavity size is changed. A high speed power section will

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DOWNHOLE TOOLS

Conventional

Even wall

and a thin elastomeric liner of even thickness. Backed by the contoured tube, the thinner elastomer liner maintains its sealing ability up to 75% higher differential pressure across each stage.

Adjustable assembly and fixed housings Adjustable assembly

Rubber Figure DH-11: Conventional vs even-wall power section. Courtesy National Oilwell Varco.

An adjustable assembly (Figure DH-12) connects the stator to the sealed bearing assembly and encloses the driveshaft assembly. The angle setting is field adjustable to produce a wide range of build rates.

Fixed housing

Fixed, non-adjustable housings are available (special order) in straight or fixed bend configurations.

Driveshaft assembly Figure DH-12: The adjustable assembly connects the stator to the sealed bearing assembly and encloses the driveshaft assembly. Courtesy National Oilwell Varco.

require a larger fluid inlet area (cavity) to allow more fluid throughput into the cavity. The torque generated by the power section is proportional to the differential pressure applied across the power section and is independent of fluid flow. Generally, the more weight applied to the bit, the higher the torque needed to keep thebit turning, so the higher the differential pressure across the power section. The maximum recommended differential pressure is limited by the stator elastomer. If pressure increases beyond the limits of the elastomer, the stator elastomer will deform, breaking the cavity seal so the mud flow leaks past the rotor and rotation stops – this is commonly known as a stalled motor. An increase in torque output can be achieved by three methods: •• Use a power section with more stages. As torque is proportional to the applied differential pressure, a power section of similar tube diameter, lobe configuration and profile construction will generate more torque as the number of stages increases; •• Use a high performance elastomer. Specially designed elastomers can allow as much as 50% higher differential pressure across each stage, generating 50% more torque with the increase in differential pressure; •• Use an even wall power section (Figure DH-11). Even wall power sections have a contoured stator tube ID

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The driveshaft assembly converts the eccentric motion of the rotor into concentric rotation for the bearing assembly. It also accommodates any angle set on the adjustable bent housing (or fixed bend housing) and carries the thrust load from the rotor caused by the pressure drop across the power section. The assembly consists of a driveshaft and two sealed and lubricated universal joints connecting to the rotor and the sealed bearing assembly.

Bearing Assembly »» Oil sealed bearing assembly

The bearing assembly transmits the rotation of the driveshaft assembly to the drill bit. It transmits the compressive thrust load created by the weight of the collars and drill string to the rotating bit box, and supports the radial and bending loads developed while directional or steerable drilling. It also carries the tensile “off-bottom” thrust load produced by the pressure drops across the rotor and the drill bit, as well as any load caused during back reaming. In oil-sealed bearing assemblies the radial bearings and thrust bearings are lubricated by and sealed in an oil chamber balanced to the internal tool pressure (Figure DH-13).

Figure DH-13: Oil sealed bearing assembly. Courtesy National Oilwell Varco.

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DOWNHOLE TOOLS

DH–9

•• Make up the drill bit to the proper torque with a bit breaker and the rig tong placed on the output shaft directly above the bit. Do not put rig tongs on the sealed bearing assembly housings. Inspect the output shaft seal area for any indication of an oil leak. Note: Avoid long periods without circulation if possible. Figure DH-14: Mud-lubricated bearing assembly. Courtesy National Oilwell Varco.

»» Mud lubricated bearing assembly

The mud lubricated bearing assembly is interchangeable with the sealed bearing assembly and performs the same basic function (Figure DH-14). In a mud lubricated assembly, a small percentage of the drilling mud is allowed to pass through the bearing chamber, to lubricate the bearings. Mud lubricated bearing assemblies can be used in the hottest holes with the lowest aniline point drilling fluids, as there are no elastomeric seals.

Applications Directional drilling

Most motors are used with adjustable housings to provide a method of drilling directionally downhole. The desired angle is obtained by selecting an appropriate fixed bend housing or is set in the adjustable housing sufficient to alter hole course with the drillstring not rotating and the tool face oriented. When the drill string is rotated with the motor operating, the system drills straight ahead.

»» Run preparation & rig site testing

•• Set the motor in the slips and install a safety clamp. Remove the lift sub and make up the Kelly/top drive. Remove the safety clamp and slips and lower the motor until the dump sub is below the drilling nipple, but visible. •• Start the rig pumps slowly; fluid should flow out of the dump sub ports. •• Increase the pump rate slowly until the dump sub closes. Leave the pumps running and make note of the circulation rate and stand pipe pressure when the dump sub closes. With the pump running and the dump sub closed, check to ensure that there is no drill fluid leakage through the ports. It is advisable to increase the pump speed in two or three steps, to the maximum circulation rate expected downhole, and note the circulation rate and standpipe pressure in each case. •• Shut down the pump. The dump sub may not open due to a pressure lock in the short hydraulic test circuit. If this occurs, bleed off the pressure to permit the dump sub to open.

IADC Drilling Manual

»» Starting the motor

Begin circulating “off bottom” with the bit turning freely. Perform circulation and pressure tests at the same circulation rates as the surface test, and note the readings. The pressure will be higher due to the restrictions of the drill string components added. The “off bottom” pressures noted may be higher than calculated. This is caused by bit dragon the side of the hole due to the bent sub, adjustable housing angle, and stabilization.

»» Drilling

After a short hole-cleaning circulation period, slowly lower the bit to bottom. When bottom is tagged, the standpipe pressure gauge will show an immediate increase. Increase the bit weight slowly to achieve the desired build up rate and/or rate of penetration. Do not exceed the recommended maximum differential pressure across the motor. The “off bottom” pressure is the total system pressure (read on the stand pipe gauge), from the standpipe, through the drillstring, the annulus, and back to the drilling nipple, while circulating with the bit “off bottom” (i.e., zero weight on bit). Periodically recheck the “off bottom” pressure. The standpipe pressure will slowly increase after hole cleaning due to the hydraulic energy required to lift the cuttings. The torque applied to the bit while “on bottom” is directly proportional to the difference between the “on bottom” and “off bottom” pressures (i.e. there are no friction losses through the rotating drillstring). An increase in the weight on bit produces an increase in torque. As the bit drills off, the weight on bit decreases and correspondingly the pressure and torque decrease. The standpipe pressure gauge can therefore be used as a torque indicator.

»» Stalling

If too much WOB is applied, the torque required to keep the bit turning creates a higher differential pressure than the seal between the rotor and stator elastomer can maintain. The drilling fluid breaks the seal and leaks through the power section without turning the rotor, so bit ceases rotation, or ‘stalls’. An increase in standpipe pressure will occur and penetration will cease. As the fluid leaks past, it erodes the elastomeric liner, which makes further stalling more likely and damages the liner, eventually leading to chunking.

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Figure DH-15: Schematic of a down the hole (DTH) air hammer. Courtesy of Boretek.net.

Also, stalling generates large pressure pulses, creating torque spikes that can cause chunking, connection back-off, or fracture of driveline components. Motor stall should be avoided, but when it occurs, it should be quickly remedied. If the bit is picked up off-bottom while drilling, the “trapped” torque within the drill string will be released uncontrollably, potentially causing damage to down-hole components or causing connections to back-off. This is especially true when a stall has occurred. Careful attention must be given to release the trapped torque in a controlled manner.

»» Over-running the bit

Rotating the drillstring with any positive displacement motor in a stalled condition may cause the upper portion of the motor (and drillstring) to over-run the bit. This condition can damage the stator elastomer liner and cause connection back-offs within the motor.

General maintenance

The mud motors should be cleaned and flushed with clean water after use, prior to laying down the tool. Drilling fluid left in the motor will cake and cause the bearings to seize. Chemicals in the drilling fluid can cause damage, or wear on the motor if not removed promptly. Proper pipe dope should be applied to the threaded connections at the top and bottom of the motor and applicable thread protectors installed. Dump subs should not be left in an “open” position. Other maintenance will be performed at the facility of the supplier of the motor.

Air hammers

Down the hole (DTH) hammers are used to drill in medium to hard formations when high penetration rates are required with minimal deviation (Figure DH-15). DTH hammers use the energy of compressed air to alternatively lift and drive an internal piston against a percussion bit. Penetration is achieved by the transmission of energy from the piston through the bit into the formation. In contrast with rotary drilling, DTH hammers only require enough weight on bit (WOB) to maintain contact between the bit face and drilling formation. RPM should be matched to percussion rate to ensure the bit inserts are positioned over new material with each blow. DTH hammers require greater air volume but less weight on bit when compared to rotary drilling.

Compressed air

Compressed air is supplied to the hammer from the drill string through the top sub. The pressure and velocity of the fluid provide the motive energy to operate the piston. Oil is injected into the compressed air to lubricate the DTH hammer and in some applications foaming agents may be added to assist in cutting evacuation. After transferring energy to the piston, low pressure exhaust air is directed through the face of the bit to flush the hole and transport cuttings to the surface.

Top sub

The top sub connects the DTH hammer to the drill string and transmits the pressurized air, thrust, and rotary torque from the drill. Sometimes referred to as the “backhead.”

Case

The case provides the central interface for assembly of the

IADC Drilling Manual

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DOWNHOLE TOOLS DTH hammer. The piston strokes within the inner volume of the case, and the spaces above and below the piston form the drive and lift chambers. The drive and lift chambers are filled with compressed air in an alternating manner in order to drive the piston into the bit and then lift it to reset for another cycle.

DH–11

in the range of 3000 ft/min and 5000+ ft/min. For mist drilling or directional drilling applications, air volume should be increased by 30% (i.e. 2400 SCFM for Dust Drilling vs. 3120 SCFM for Mist/ Directional). Air must remain on when the hammer is in the hole to prevent debris from entering.

The only moving part of the air hammer, the piston imparts energy through the bit to the formation. The piston reciprocates at a rate of 600 to 2000 beats per minute with a typical stroke length ranging from 60mm to 90mm. The piston’s design and air porting cause it to act as a valve, controlling the filling and discharging of the drive and lift chambers depending on its location.

Under normal drilling mode, the DTH hammer efficiently consumes air to operate the piston with sufficient exhaust air to flush the hole. In the event additional pressure is needed, the tool may be retracted slightly to remove the bit face from hole bottom. In this “flushing mode,” compressed air bypasses the piston for improved hole cleaning. Switching to Flushing Mode is usually the first troubleshooting step when the hammer is not firing consistently or cab pressure is too high.

Driver sub

Lubrication

Piston

This sub aligns with the splined section of the drill bit to transmit rotational force from the air hammer and drill string to the bit. Sometimes referred to as the “chuck.”

Drill bit

The bit is impacted by the piston at the bottom of each piston cycle. Elastic waves from impact travel through the shank of the bit to its head. Tungsten carbide inserts are then pressed against the rock face for a few milliseconds generating small craters and rock cuttings.

Check valve

Some DTH designs use a check valve in the top sub to eliminate potential air leakage and back flow.

Bit retaining systems

Systems vary by design, but most DTH hammers use a retaining system to prevent bit loss in the event of a down hole failure. Bit retaining rings between the drive sub and bit bearing allow the bit to extend from the tool without separation, while external bit head retainers are used prevent the head from falling down hole in the event of a shank separation.

Choke

Some hammers use a choke to regulate the air flow through the tool. The choke contains an orifice that passes a portion of the airflow directly through the tool to the hole face, improving flushing capacity. The choke may be replaceable or factory-set depending on design.

Air flow requirement

DTH hammer air requirements depend on three variables: design, bottom hole pressure, and inlet pressure. With a given design, a target bottom hole pressure is selected for optimal hole cleaning. The air supply requirement can then be expressed as a function of the inlet pressure. For effective hole cleaning, the air velocity through the annulus should be

IADC Drilling Manual

An on-board oiler is required whenever drilling with a DTH hammer. Oil is used to lubricate and cool the moving components as well as to create an air seal, preventing bypass for efficient operation. Injection rate is dependent on air volume. The oiler must remain on during hammer operation to prevent piston damage

Safety and handling

Standard lifting and handling procedures must be followed when removing or handling DTH hammers and bits. Eye and ear protection are required when drilling or conducting live surface tests due to the hazards of high pressure air discharge.

Rotary steerable systems (RSS) RSS development

The first commercial RSS revolutionized directional drilling in the 1990s. The technology has made improvements in reliability and is now a standard drilling tool, with both pushthe-bit and point-the-bit RSS applied in directional and vertical wells worldwide. Their use is not limited to high-cost offshore markets has become more common in lower-cost land markets. Initially targeted and utilized in applications that were extreme in directional nature (extended-reach and high-DLS build or turn), they have matured over the past 20 years and are now considered an appropriate technology option in all forms of directional applications, including vertical. The advantages of this technology are many for both main groups of users: geoscientists and drillers (Figure DH-16). A cleaner hole is also achieved when using rotary steerable systems. When slide drilling, cuttings are pulled downward by gravity and deposited around the low side of the drill-

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Steerable rotary drilling system

Steady deviation

Smooth hole

cost is reduced AND

Work over is made easier

Effect of high inclination is offset by continuous pipe rotation

while steering

Less drag

Tortuousity of well bore is reduced by better steering

Completion

Cleaner hole

Continuous rotation

Controlled by downhole servo independent of bit torque. No problems of toolface control with elastic drillstring

Less risk

Improves control of WOB

Greater reservoir exposure

of stuck pipe

Save time

Longer

Higher daily ROP, less wiper trips

extended reach

by geosteering

Fewer wells

to exploit a reservoir

and

/or

Fewer platforms to develop a field

and

/or

Less cost per foot

Less cost per barrel Figure DH-16: Rotary steerable system benefits tree. Source: M.A. Colebrook, S.R. Peach, “Application of Steerable Rotary Drilling Technology to Drill Extended Reach Wells” , F.M. Allen, G. Conran, IADC/SPE Paper #39327 Presented Dallas, Texas 3–6 March 1998.

string on their return to the surface. This buildup of cuttings reduces the clearance between the drill string and wellbore, adding additional contact around the low side of the string and increasing both torque and drag. The cuttings reduce the flow path for circulation, and can produce enough drag to pack off the bottom hole assembly (BHA), creating a stuck pipe event. Drilling with rotary steerable systems allows these cuttings beds to be continuously churned up and more evenly distributed in the flow of fluid back to surface. This results in more effective cuttings transport out of the well. Continuous rotation of the drill string allows for improved transportation of drilled cuttings to the surface resulting in better hydraulic performance, better weight transfer for the same reason allows a more complex bore to be drilled, and reduced wellbore tortuosity due to utilizing a steadier steering model. The well geometry therefore is less aggressive and the wellbore (wall of the well) is smoother than those drilled with a motor. Tortuosity and excessive dogleg severity can create significant challenges to overcome when getting casing to TD, resulting in excessive downtime and trips to ream the hole smooth. High tortuosity also increases the risk of stuck pipe events by creating multiple points within

IADC Drilling Manual

the well where mechanical sticking may occur. RSS technologies do not produce the instantaneous doglegs that bent housing motors do, and so result in a smoother wellbore with less risk of sticking. Maintaining wellbore quality, particularly borehole gauge, is crucial for obtaining predictable directional response in both push- and point-the-bit systems. Rotary-steerable system (RSS) delivers accurate wellbore placement and completion-ready wellbores in applications ranging from deep, hot holes to extended-reach underbalanced wells. This last benefit concerns geoscientists, because better measurements of the properties of the formation can be obtained, and the drillers, because the well casing or production string can be more easily run to the bottom of the hole. Commonly, RSS are segmented into two broad categories; Push-the-Bit and Point-the-Bit RS tools. Their distinct operating mechanisms are briefly described below. However, it should be noted that ‘Push’ and ‘Point’ are broad categorizations of these systems and their operating mechanisms vary considerably between suppliers. Operationally, these tools can be run either as a stand alone or in combination with

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DOWNHOLE TOOLS

Mandrel connection

Concentric stabilizer

Eccentric mass

Offset stabilizer

DH–13

Ledge wiper

Orientation housing

Stationary section Figure DH-17: High-temperature applications might require fully mechanical RSS tools. Courtesy National Oilwell Varco.

Figure DH-18: Offset stablizer dynamics. Courtesy National Oilwell Varco.

Video DH-1: Animation of a push-thebit RSS. Courtesy Schlumberger.

mud motors. These variations can result in quite diverse operational and performance characteristics.

‘Push-the-bit’ tool

The tool uses mud actuated pads to change the direction of drilling by pushing against the formation (Video DH-1). These tools are typically composed of a steering section and control unit. The steering section contains a number of pads (typically 3 or 4) that apply a lateral force against the wellbore to achieve deviation at the bit. These pads are either mud powered (powered by drilling fluid diverted from the main flow) or use an internal hydraulic system and provide a constant force to the bit. While certain systems have full external rotation of the entire RSS tool when in operation, a number of RSS suppliers utilize varied mechanisms to ‘hold’ the steering section static within the borehole. When no deviation is required, most systems can be set into a neutral mode. RSS tool settings are typically set using a series of mud pulse or RPM sequences sent from the surface.

IADC Drilling Manual

‘Point-the-bit’ tool

Point the bit controls the direction of build by pointing the bit in the desired direction while continuously rotating the drill string There are two primary categories of point tools: •• Tools that deviate via deflection of an internal shaft. This deflection, using a near-bit pivot point, will result in ‘tilting’ of the drill bit in the desired wellbore direction. The method of shaft deflection varies enormously, but most of these tools employ a static steering section; •• Point via fixed offset. Typically, the steering unit contains a bit shaft that has a fixed offset angle from the axis of the collar. This shaft passes through a universal joint and is connected to an internal drive mechanism. The operation of the mechanism allows the offset of the tool face to be held geostationary (via rotation in opposing direction) when steering, whereas the tool face is allowed to rotate when in straight mode. Directional control is managed by changing the timing or speed of the internal mechanism. These tools are predominantly fully rotational when operating i.e. they do not have a static steering section; •• There are pros and cons to both broad segments of RSS, as well as specific strengths and weaknesses due to the different steering mechanisms and mechanics employed by each RSS supplier. Actual tool selection

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will be resultant from a collective evaluation of the drilling challenges, directional requirements, cost, reliability, geographical service limitations, and prior experience / relationships. Recent years have seen further significant advancement in RSS technology and tool availability. Notable advances include: •• RSS for extreme diameter hole sizes i.e. tools that can directionally drill 3 7/8 in. and 26 in. hole sizes; •• Advances in DLS capability (tools that can deliver (15 + °/100 ft. [30 m]); •• Casing while directionally drilling with RSS; •• Coiled Tubing Drilling with RSS; •• Powered RSS: combination of RSS and downhole motor to improve drilling efficiency; •• Vertical drilling with RSS.

Benefits

•• Reduce drilling time to drill the vertical, curve and lateral section in one BHA with no sliding intervals or added trips for downhole motors; •• Increase reservoir exposure—kick-off deeper and land in the reservoir sooner ; •• Reduce sail angle required in extended reach drilling, reducing torque and drag, and facilitating faster, smoother tripping; •• Reduces drillstring buckling in long horizontals, greatly extending reach; •• Continuous rotation improves hole cleaning and reduces risk of getting stuck; •• Increases ability to drill with more aggressive bits; •• Smoother wellbore curvature reduces torque and drag; •• Lowers operating and lost-in-hole costs; •• Helps improve instantaneous and average rate of penetration; •• Helps reduce trips; •• Helps ensure precise wellbore placement in all drilling environments; •• More energy is directly applied to the bit improving cutting efficiency and rate of penetration while also overcoming stick-slip. The considerable benefits of using rotary steerable technology have been embraced by the industry and reflected in the continuation of exponentially growing demand, irrespective of business cycle. The initially obvious benefits of using these systems has now grown to include a whole host of “less tangible” benefits, which are probably of greater real value than the tangible ones. Bit technology has grown to keep pace with the need to obtain the best performance out of each of the very different available systems. It is becoming increasingly common to tailor-design bits to push performance limits.

IADC Drilling Manual

General maintenance

Like all other equipment tongs used for torqueing and un-torqueing the connections should be placed on the sections of the tools identified accordingly. Typically this will be at the extreme top and bottom of the tool. Use proper pipe dope on the threaded connections and install thread protectors when they are not in use. For more information on rotary steerable systems, see the separat chapter on Directional Drilling in the IADC Drilling Manual, 12th edition.

Vibration, torque and drag Description and basic theory

Vibration, torque and drag are present in every well drilled, and should always be considered when planning and executing a drilling program (Figure DH-19). Proper modeling and monitoring is essential to preven torque and drag from causing severe drilling problems. When preparations and proper mitigation techniques are not performed for drilling vibrations, the result will be increased drilling time and costs, damaged tools and additional problems.

Physical operating principles

Torque and drag are usually in reference to surface. These are very important measurements and values to observe when drilling ahead or running casing. Any axial movements when drilling, tripping pipe, or running casing creates torque and drag. Rotating the pipe will increase your torque in the string, but resist or decrease the drag. When no rotation is applied to

Figure DH-19: Any axial movement during drilling, tripping pipe or running casing creates torque and drag.

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DOWNHOLE TOOLS the string, the drag is a critical factor and failure component to the action being attempted. Torque will be the calculation we see at the top drive, and drag will be measured for the hook load with block weight. A typical T&D analysis starts by dividing the pipe into small elements. Calculation begins from the element at the bottom of the pipe, where weight on bit (WOB) or torque on bit (TOB) is expected. For each element, force and torque are balanced and the T&D at the top of the element are calculated step by step and from bottom to top, calculation is performed for each pipe element, until it reaches the rig floor. The deeper and more deviated wells will have significantly more T&D than the more basic vertical wells.

Buckling

Buckling is the sudden axial collapse and lateral displacement of a drill string column when the forces that destabilize it exceed the forces that stabilize it. In other words, when weight stacking becomes great enough, buckling of the drill pipe occurs. Buckling in sliding mode drilling will generally cause little or no structural damage to the drill string, where drillpipe is the least tolerant to buckling and HWDP is the most buckling tolerant. Figure DH-20 defines the equation for the critical buckling factor. Two types of buckling exist, and are explained below.

FCR = 2 x E = 30 x 106 (steel) π 4 4 I=

64

DH–15

E x I x KB x W x sin θ r

x (OD – ID )

FCR θ E KB I W r

= Critical sinusoidal buckling load (lb) = Inclination of the hole at the point of interest (degrees) = Young's Modulus = Buoyancy factor (unitless) = Moment of inertia (in.4) = Unit weight in air (lb/in.) = Radical clearance between pipe tool joint and hole (in.)

Figure DH-20: Calculation of critical buckling factor..

Figure DH-21: Sinusoidal buckling.

Sinusoidal buckling occurs when the pipe buckles in a “sinusoidal” wave pattern (Figure DH-21). With this type of buckling the pipe is engaging the wall at points, directing the drilling forces into the borehole wall rather than downhole to the bit. This can result in reduction in weight on bit (WOB) than what is expected to be from surface. Helical buckling is caused with the weight stacking continues past sinusoidal buckling. At this point, the drill pick collapses into the dimensional configuration of a coiled spring or helix(Figure DH-22). This type of buckling results in the same or an increased loss of downward force and WOB, due to the redirection of these forces onto the borehole wall. Tubular buckling typically occurs in a long horizontal well in the vertical section, and right after the curve section due to the axial force (WOB), downhole friction and the side force in the curve section. Figure DH-23 illustrates these locations. All buckling causes drill-string compression and will push the neutral point close to the surface . Ultimately, the drill team will consequently be unable to add further WOB.

Figure DH-22: Helical buckling.

Weight “stacks”

Drill bit

Drilling vibrations

Drilling vibrations are common and present in every well, in some form. It’s typically only severe levels of vibrations that we actually notice from surface or after tools are pulled, through dull grading and excessive wear. Any level of vibra-

IADC Drilling Manual

Static friction Figure DH-23: Tubular buckling typically occurs in the vertical secdtion of long horizontal well, and right after the curve section.

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DH–16

DOWNHOLE TOOLS

Figure DH-24: Three forms of drilling vibration exist — transverse (or lateral), axial and torsional (or stick slip).

Figure DH-25: Lateral vibrations cause the BHA to beat against the wellbore, enlarging the borehole and damaging gauge cutters, fatiguing connections and damaging downhole electronics.

tions downhole will reduce the effeciency of drilling operation, causing a reduction in rate of penetration (ROP) and therefore take longer to drill a given well, and costing more money to complet the project. Three main forms of vibration exist: lateral or transverse, axial, and torsional (stick slip). See Figure DH-24. Lateral vibrations are described as lateral displacement and beating of the BHA against the borehole. This is usually in the form of an eccentric rotation of the bit, BHA, or drill pipe in a backward motion, known as backward whirl. even causes damage to gauge cutters, increased torque in the string, an enlarged borehole, and fatigue to connections. During backward or even chaotic whirl, downhole electronics, such as the MWD, can be damaged (Figure DH-25). Axial vibrations are up and down resonant motions in the BHA, typically seen with roller cone bits. The bit does not actually leave the formation during this mode of vibration, but the ‘bounce’ could cause decreased effeciency in drilling, uneven wear or broken cutters and cones, or even pinched and failed bearings in the bit.

IADC Drilling Manual

Figure DH-26: Due to torsional vibrations (stick slip), the BHA/ bit slows down and winds up. When the wound-up string breaks free, the bit rotates at very high speeds, often causing heat checking on the bit and even “ring out” wear on the shoulder.

Torsional vibrations, also known as stick slip, can potentially be the worst of all, sometimes inducing a lateral vibration or whirl into the string during the ‘slip’ or spin-up phase. Torsional vibrations are defined as the the slowing down & speeding up of the BHA and bit, as they alternately rotate more slowly and more rapidly than the drill pipe. This is a result of the string periodically torquing up, then spinning free accelerating the bit to higher speeds. In severe cases the bit/BHA stops regularly, causing the string to wind up; the torque increases until the string finally breaks free and accelerates the bit to high rotational speeds. During stick-slip, bit RPM can be 2-3 times surface RPM. This can cause severe damage to even the best cutters, which can experience due to the rapid spinning three times the abrasion at a given moment during the ‘slip’ or release of built-up torque. The accelerated wear on the bit is usually in the form of heat checking and even ‘ring out’ wear on the shoulder of the bit. Often, severe stick-slip can be observed in top-drive RPM and torque readings. See Figure DH-26 for an example of the torsional and severe stick-slip effects on bit wear. For more information on drilling vibrations, refer to the separate Drilling Practices chapter of the IADC Drilling Manual, 12th edition.

Vibration analysis tools and software

Drillstring dynamics modeling software, otherwise known as critical speed analysis, enables pre-well analysis of the BHA and drillstring. The software predicts parameters that initiate vibration and high impact loading that can lead to premature bit and/or downhole tool failures, utilizing finite

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Figure DH-27: Two examples of reamers, which feature cutting structures comprising carbide chunks mixed into a durable hardfacing material. Most tools offer a tapered profile front to back, otherwise known as a ‘watermelon’ profile, to reach back and ream while going downhole, or while tripping out of hole, if the formation is undergauge.

element analysis to model the dynamics of the entire drillstring from the bit to the rig floor. Drillstring dynamics modeling software identifies combinations of operational conditions and/or drilling parameters that are more likely to result in detrimental axial, lateral, and/or torsional vibration while drilling. The results deliver a recommended set of drilling parameters based on a proven, scientific approach that minimizes the risk of vibration. Downhole drilling dynamic sensors/tools collect drilling data and store it in memory for detailed analysis on surface post well. Some tools can acquire an array of measurements including multi-axis vibration, load, torque, pressure, temperature and rotation at around 800Hz. Surface data acquisition, visualization and software analysis capabilities provide well construction teams with the information to optimize performance. An example of the measurement capabilities of top level drilling dynamics tools include: •• Weight on bit (WOB) and Torque on bit (TOB) ; •• Weight transfer indication; •• Torque loading; •• Multi-axis vibration; •• Shock impact; •• Damage determination; •• Annular pressure; ••Temperature; •• Stick-slip, whirl, torsional event detection and characterization.

Advanced torque and vibration technologies Integral reamers and wipers

These tools are used to reduce torque and drag, increase the rate of penetration, and improve operational efficiency. The tapered blade reamer should be considered standard BHA equipment for the removal of ledges and abrupt doglegs created while drilling. They can effectively removes keyseats encountered while tripping in and out of the hole, ultimately reducing the torque and drag on a given drill string (Figure DH-27).

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Many reamer and wiper produces exist on the market. The most common are roller reamers and ledge wipers, or ledge reamers. Typically these are string tools; however, some near-bit options exist too. An industry standard for a reamer would be a cutting structure made of carbide chunks mixed into a durable hardfacing material on the profile of the tool. This allows for an active cutting contact area when engaged with the borehole wall. Most tools offer a tapered profile front to back, otherwise known as a ‘watermelon’ profile, in order to reach back and ream while going downhole, or while tripping out of hole if the formation is undergauge. Other forms of cutting structures exist beyond the more economical jagged edge carbide pieces coating, such as carbide inserts, and the most premium design including PDC cutters. Such an example is shown below. This particular design allows for a passive gauge contact area in the center, to increase stabilization in the string, but allows for a cutting action while drilling or backreaming if the formation is at all tight or under gauge. This same design is effective in removing torque building ledges in directional wells. Due to the premium PDC feature, this type of tool will be the most durable tool design on the market. Roller reamers are initially used to ensure the diameter of the hole is cut to the true desired hole size. With the carbide insert teeth on the rollers, the tool is capable of removing formation not within gauge, due to a swelling formation or undergauge bit. This cutting action is also beneficial when directional ledges and deviations come into contact with the tool. As directional wells are formed, doglegs and micro ledges are created in the wellbore, causing increased torque and drag in the well. When a roller reamer comes into contact with these areas, the cutting action of the rollers help to remove or soften these ledges. The second function of this technology is to stabilizer the drill string in the well, and lower the torque necessary to rotate the stabilized section of the bha. As the rollers are

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Chisel cutter

Dome cutter

Figure DH-28: Chisel and dome cutters (above) are two options for roller reamers. A chisel cutter will be more aggressive and

Figure DH-29: In many cases, roller reamers can be serviced at the rig site. Roller cartridges can be removed and replaced. The illustrrations at left show an example of a replaceable cutter cartridge.

useful in soft to medium formations, whereas the domeshaped cutter is designed for a harder formation.

rotating, and not static, less torque in the string is required to rotate the tools and the surrounding BHA.

Sealed bearing roller reamers

Drilling fluid causes early bearing pin and cutter-bore wear to traditional unsealed reamer cutters. However, sealed bearing reamer features sealed and lubricated cutter assemblies using specially treated bearing pins and cutters fitted with low friction bearing materials. This results in a reamer that minimizes bearing wear and fully utilizes the cutting structure. Sealed-bearing roller reames are available in three-point or six-point configurations.

Roller reamer options

Numerous variations of roller reamers have been developed, offering options for various applications. These include type of bearing assembly, drilling-mud lubed or sealed-bearing lubricated, different angles of roller placement, and different cutter types on each roller. Two of the many options are displayed in Figure DH-28. A chisel cutter will be more aggressive and utilized in soft to medium formations, whereas the dome-shaped cutter is designed for a harder formation. In many cases, roller reamers are serviceable on-site. Roller cartridges can be removed and replaced with the use of a few specific tools, so that the tool can be rerun with new seals and cutters. See Figure DH-29 for an example of a replaceable cutter cartridge.

General maintenance

Reamers and especially roller reamers require regular maintenance and inspection. The features of the reamer and, in the case of roller reamers, the pockets and holes used to install, remove and carry the cutting structures require NDT testing after every job. Cutter surfaces should be visually inspected for broken or missing cutting elements and excessive wear and erosion damage. Manufacturer-supplied documentation should detail allowable wear and erosion limits For more on types of damage to cutters, see the separate Bits chapter of the IADC Drilling Manual, 12th edition.

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Threaded connections need to be treated with pipe dope and thread protectors installed when not in use. For more on thread protectors, see the separate Drill String chapter of the IADC Drilling Manual, 12th edition.

Ring gauge technology

Ring gauge technology is the only true continuous borehole contact design in a drilling tool. This concept can be added as a near-bit or string tool to maximize stabilization at the bit or in the BHA and to prevent harmful vibrations, such as lateral defections, whirl, and even micro stick-slip. The addition of a ring to a spiral stabilizer can add up to 100% more passive contact area to the tool over the most optimized drilling stabilizer designs. The increased borehole contact has also been tested to maximize the deflection potential when ran as a gauge extension on point-the-bit rotary steerable systems. These tools are fitted with a premium hardfacing, allowing them to be ran in the most extreme and harshest drilling applications, where severe vibrations often exist, without failure. Tool sizes for this technology range from 8 3/8 in. to 24 in., with the potential to get tool designs in sizes as small as 6 in. A connection exists for any drive type, from rotary drilling BHAs, to mud motor applications, and even used on unique point-the-bit rotary steerable systems (RSS). Each tool has a four-blade design, wrapped at or near 360°, with full and partial ring options for each tool size, but the calculated junk slot area (JSA: Not to be confused with the same acdronym for job safety analysis) does not change between the two designs. Recent designs have yielded high flow passages, allowing for continuous flow of cuttings and drilling fluids to pass through the tool without interruption. This is achieved by utilizing the strength of the ring to remove material from the body under the ring. The resulting JSA calculations near equal between that of a ring passage and non-ring flow areas. It should also be noted that each high flow design is typically significantly higher in terms of

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DOWNHOLE TOOLS JSA calculations than that of a standard bit in the same size, therefore a restriction in pressure and flow does not exist. Proper circulating fluid dynamics (CFD) studies were used in validating the final high flow designs. See figure 3 for CFD cutaway image, showing positive flow with little to no turbulence or restrictions.

Asymmetric vibration dampening

Asymmetric vibration dampening technology mitigates vibration using a simple eccentric-designed stabilizer that orbits the borehole, rather than centralizing itself in the center or the borehole. The unique orbit within the borehole is completely different than any other stabilizing technique, and should be carefully reviewed and placed within the BHA before use. The technology utilizes the simple effects of rotation to neutralize vibration. Using rotational speed of the string, the geometry forces the surrounding BHA, usually drill collars, to rotate off center. This off-center rotation is controlled and initiates an orbit or jump rope effect to the drill collars above and below. The controlled orbiting motion of this section in the BHA, dampens out lateral vibrations and minimizes or prevents stick-slip at the bit or in the BHA. Asymmetric vibration dampeners rotate differently than drill collars or stabilizers that have begun backward whirl harmonics. Due to the geometry, it will not enter the same backward vibration mode, and therefore eliminate the damaging high frequency vibration from entering this section of drill pipe. It should be noted that careful placement techniques and a specially designed software calculator are always utilized before running this tool. Due to the basic orbiting nature of the tool, it is a vibration mitigation tool in almost any application, standing out especially in borehole enlargement (BHE) wells, where pass thru tools and stabilizers cannot properly stabilize the enlarged hole above an underreamer. This is the original application for which the technology was initially developed in the late 90s. The tool also functions in applications such as ultra deep vertical rotary wells, and even high angle wells utilizing Rotary Steerable Systems. Industry technical papers and articles also refer to this technology as an Asymmetric Vibration Damping System (AVDT).

Measurement while drilling (MWD)

Measurement-while-drilling (MWD) technology is commonly used to provide real-time measurements of drilling related parameters measured by special instrumentation downhole and transmitted to surface using some form of

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MWD telemetry. MWD components are also called MWD survey tools and MWD directional tools. MWD provides directional information, including the inclination and direction of the borehole. Other information that can be gleaned using MWD includes: •• Pressure information: downhole pressure inside and outside the drillstring; •• Vibration information: accelerations experienced in the drillstring during the drilling process; •• Drilling parameters – weight and torque on bit and bending moment; •• Gamma-Ray – natural gamma radiation emitted by the formations downhole. All other data and information measured downhole in real-time and telemetered to surface would fall in the category of formation evaluation data and is typically referred to as logging while drilling, or LWD.

Description and basic theory

The purpose of the MWD technology is to provide real-time data related to the borehole being drilled so that the well can be drilled in the right location and along the correct trajectory and to monitor the forces being applied and experienced by the drilling tools downhole such that the process may be optimized and performed as efficiently as possible.

Physical operating principles

A MWD tool will typically consist of the following components: •• Telemetry device. The telemetry device is used to transmit the acquired downhole data to the surface for recording and analysis. There are several types of telemetry devices, such as: • Mud pulse telemetry: device creates pressure pulses in the drilling fluid that are detected at the surface and decoded. The device is most commonly some type of valve that for a short period partially blocks the flow of the drilling fluid through the drillstring creating a pressure increase seen at the surface. The device can be integral to a drill collar, or sub, or as a sonde that is inserted into a custom, or standard drill collar. This technology requires that drilling fluid is present in the well and circulating; • Electromagnetic (EM) telemetry: device that creates an electromagnetic field downhole. The field propagates through the rock to the surface where the small changes in current flow and/or magnetic properties inside the rock are detected and decoded. This technology works with and without a drilling fluid in the well and is thus suitable in areas where air, or foam drilling takes

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places, or with gasified drilling fluids, such as used in some underbalanced drilling operations. The EM signal propagates well in formations with low porosity and high impedence, but will die quickly in areas of high conductivity (such as in shallow offshore settings) and non-porous rocks (such as anhydrite, some salts and some volcanic rocks); • Acoustic telemetry: device that creates acoustic sound waves in the drillstring that are detected on the drillpipe at surface and decoded. This technology works well in vertical wells, but becomes increasingly difficult with wells where the drillstring makes a lot of contact with the borehole wall, with tapered drillstrings and in high mud weights; •• Power supply: device that creates and supplies power to the telemetry device and the instruments and sensors downhole. The most commonly used are: • Batteries: all types of batteries, depending on power requirements and environmental (temperature) conditions downhole. The batteries are usually carried in a special battery tube, or pressure case, or in a special insert within a sub. The advantages of batteries are that they are highly reliable and do not require additional gear to make the function. The downside is that they have a finite life; • Turbines: electromagnetic turbines powered by the drilling fluid are commonly used either on their own, or in combination with batteries to provide power to the downhole tool. The turbine only delivers power when circulating drilling fluid causes the rotor on the turbine to spin. Therefore, no power is available from the turbine when the drilling fluid is not present or not being circulated (pumped). The turbines also must be set up to deliver the correct amount of electric power and, since it is dependent on circulation of the fluid, must be set up according to the velocity of the fluid passing by the turbine. The turbines are usually incorporated into the telemetry device as one unit; •• Directional sensor: instrument to measure the borehole inclination and direction. This instrument typically is contained in a pressure case positioned in the center of the bore of a non-magnetic drill collar and connected directly to the telemetry and/or power supply device. Centralization is accomplished by the use of one or more sets of centralizers on the pressure case. Consult with the MWD supplier on the correct placement within and the amount of non-magnetic drill collar required to make a good measurement; •• Optional sensor packages: on occasion, more than the bare minimum directional measurement is included in

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the MWD tool string. These could be one or more of the following: • Pressure while drilling: device with one or more (usually two) pressure gauges measuring fluid pressure in the wellbore at the instrument depth. The measurements can be internal to the bore of the drillstring or external in the annulus between the drillstring and the borehole wall. The gauges, electronics and associated equipment are usually contained in a special sub that can be connected to the rest of the MWD string; • Vibration measurements: a device containing a number of accelerometers capable of measuring string accelerations along different axes (axial, lateral and angular), each indicating movement and shocks in the drillstring. The accelerometers can be integral to the directional measurement device, the pressure measurement device, or other, or used as a stand-alone sonde or sub connected to the rest of the MWD tool string; • Drilling parameters: a device containing a number of strain gauges to measure the weight, torque and (on some devices) bending moment in the bottomhole assembly. This device is typically a dedicated sub, which may contain pressure and vibration measurements as well. For accuracy, the strain measurements typically need to be corrected for pressure and temperature; • Gamma ray: a device with instruments capable of detecting gamma radiation emitted from the rock being drilled. Many different devices exist and they can be in the form of a sonde connected to the directional sensor or as a dedicated sub.

Important for what and to whom?

MWD data is important for a number of reasons and can provide: •• Directional data: acquiring regular directional data is a regulatory requirement and is thus important to all levels within the well's oil-company operator. In addition, it is important to the directional driller and company representatives on location to ensure the well is being drilled is on target. It is also important to all other personnel that will need to access, run and install equipment into the well and for production specialists to include in their production models; •• Pressure data is important to ensure the well is being cleaned, remains in good condition and to provide more accurate measurements during pressure tests and well control situations; •• Vibration data is important to drilling engineers, drillers, toolpushers and service company personnel to ensure the drilling process stays efficient and does not do preventable damage to the wellbore and the drillstring;

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DOWNHOLE TOOLS •• Drilling data can be used by those reviewing the vibration data to better manage the drilling process; •• Gamma ray is used to confirm or fine-tune geological models and predictions and to assist in placing the well in the right formations. The MWD equipment requires certain enabling surface equipment. This can range from a small console with a computer and display on the rig floor to a dedicated unit provided by a MWD contractor. Pressure transducers, displays, communication equipment, depth-measurement equipment and cabling will all be installed around the rig to detect the telemetry signals, decode and display them.

Safety and handling

MWD tools come in a variety of sizes, configurations and dimensions. Each has unique requirements for safe handling and operation. Common among most systems: •• Most systems will include service company personnel to assist in the safe handling; •• Most systems will recommend the use of filters or screens in the drillstring to keep debris in the drilling fluid invading the mud puls, or power turbine devices. Care should be exercised in the handling, installing and removing these from the rig floor; •• Sonde-based systems usually must be installed into and removed from special drill collars on the rig floor. Special handling tools are required. Installation typically requirse a hoist (air hoist, or similar). Mud solids might have settled into the tools, rendering removal more difficult. They might "jump" during removal, as well; •• Some tools can harbor a risk of trapped pressure. It is good practice for personnel to stand behind either end of the tool during disassembly — not in front; •• Some tools require testing at surface. Caution should be taken with fluid flow and pressure.

Applications

Follow the directions of the service company, or supplier on operational procedures. Surface testing is recommended for some tools. Follow guidelines and directions provided for minimum or maximum flow rates and pressures, minimum depth etc. Specialized situations can also occur. The mud pulse device and/or turbine for power will be sensitive to mud additives, loss circulation material and debris in the drilling fluid. Typically, the maximum amount of loss circulation material the system is tolerant to is appoximately 40 ppb medium nut plug or equivalent. Please consult with the provider on recommendations related to the exact type of LCM to be used.

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General maintenance

Repair and maintenance will be performed by the equipment provider. Tools and equipment should be flushed with clean water prior to laying down and shipping after downhole use. The material being used is mostly non-magnetic and thus an appropriate pipe dope must be used.

Logging while drilling (LWD)

Loging while drilling (LWD) technology is commonly used to provide real-time measurements of formation related parameters measured by special instrumentation downhole and transmitted to surface using some form of MWD telemetry. LWD is also refered to as MWD logging and formation evaluation while drilling (FEWD). Measurements available from LWD are: •• Gamma ray: natural gamma radiation emitted by the formations; •• Resistivity: Resistance, or conductance of the different rocks and fluids; •• Density: Specific gravity of the rocks; •• Neutron porosity: Fluid filled pore space volume of the rocks; •• Sonic: velocity of sound through the rock formations; •• Formation pressure and sampling: pressure of the fluids inside the formations and collection of fluid samples; •• Non-magnetic resonance (NMR): Magnetic resonance of the fluids in the rock.

Description and basic theory

LWD systems provide real-time data about the formations being drilled. The information is used to ensure the well is drilled in the correct location. The data collected is also provided to personnel engageed in planning and executing drilling, completion and production operations.

Physical operating principles

A LWD tool will typically consist of the following components: •• MWD Telemetry device. The telemetry device is used to transmit the acquired downhole data to the surface for recording and analysis. There are several types of telemetry devices, such as: • Mud pulse telemetry: device creates pressure pulses in the drilling fluid that are detected at the surface and decoded. The device is most commonly some type of valve that for a short period partially blocks the flow of the drilling fluid through the drillstring creating a pressure increase seen at the surface. The device can be integral to a drill collar, or sub, or as a sonde that is inserted into a custom, or standard drill collar. This

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technology requires that drilling fluid is present in the well and circulating; • Electromagnetic (EM) telemetry: device that creates an electromagnetic field downhole. The field propagates through the rock to the surface where the small changes in current flow and/or magnetic properties inside the rock are detected and decoded. This technology works with and without a drilling fluid in the well and is thus suitable in areas where air, or foam drilling takes places, or with gasified drilling fluids, such as used in some underbalanced drilling operations. The EM signal propagates well in formations with low porosity and high impedence, but will die quickly in areas of high conductivity (such as in shallow offshore settings) and non-porous rocks (such as anhydrite, some salts and some volcanic rocks); • Acoustic telemetry: device that creates acoustic sound waves in the drillstring that are detected on the drillpipe at surface and decoded. This technology works well in vertical wells, but becomes increasingly difficult with wells where the drillstring makes a lot of contact with the borehole wall, with tapered drillstrings and in high mud weights. •• Power supply, which creates and supplies power to the telemetry device, instruments and sensors downhole. The power supplies most commonly used are: • Batteries: all types of batteries, depending on pwer requirements and environmental (temperature) conditions downhole. The batteries are ususally carried in a special battery tube, or pressure case, or in a special insert within a sub. The advantages of batteries are that they are highly reliable and do not require additional gear to make the function. The downside is that they have a finite life; • Turbines: electromagnetic turbines powered by the drilling fluid are commonly used either on their own, or in combination with batteries to provide power to the downhole tool. The turbine only delivers power when circulating drilling fluid causes the rotor on the turbine to spin – thus no power is available from the turbine when the drilling fluid is not present, or not being circulated (pumped). The turbines will also need to be set-up to deliver the correct amount of electric power and, since it is dependent on circulation of the fluid, needs to be set up according to the velocity of the fluid passing by the turbine. The turbines are usually incorporated into the telemetry device as one unit. •• Sensor packages:One or more logging measurement is included in a LWD toolstring: • Gamma ray: a device with instruments capable of

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detecting the gamma radiation emitted from the rock being drilled. Many different devices exist and they can be in the form of a sonde connected to the directional sensor, or a dedicated sub; • Resistivity: a device that generates a current flow in the formation and measures the resistance of the rock. The current can be generated in a number of ways. The most commonly used in LWD applications are: Currents induced by an electromagnetic field, using tools commonly referred to as induction, or propagation tools. An alternating current is applied to a coil antenna placed on the LWD collar. The current in the coil will generate a magnetic field, which in turn will induce current flow in the formation, which in turn will generate another magnetic field and so on, propagating through to the formation. The speed with which the field propagates and the rate at which the field attenuates (becomes weaker) are measured by secondary coil antennae on the LWD tools and are a function of the resistivity of the formation, i.e. the rock and fluids contained in the rock; Current injected into the formation and collected further along the LWD collar. This will require a drilling fluid that is conductive,in order for the current to flow from the tool into the formation. The amount of current that can be injected based on the potential difference between the point of injection and return on the LWD collar is a function of the resistance of the formation between the 2 points. The tools are normally referred to as lateralog tools; • Density: A device that measures the density of the rock by using gamma radiation. A gamma-ray source, normally a source containing a very small amount of radioactive material such as Cs-137, emits gamma radiation into the formation. The gamma radiation is scattered and absorbed in the formation, but some will make its way back to gamma-ray detectors in the LWD tools. The amount of gamma radiation detected is a function of the density of the formation. The more radiation, the lower the densit,y and vice versa; • Neutron porosity: A device that measures the amount of the formation that is filled with fluid, i.e. not solid rock, by using neutron radiation. A neutron source, normally containing a very small amount of radioactive material, such as Am-241/ Be, emits fast neutrons into the formation. These neutron are slowed down through collisions with the atoms in the formation. The neutrons will slow faster in fluid than in solid rock. Some of the

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DOWNHOLE TOOLS neutrons will return to the LWD tool’s neutron detector where the slower neutron are counted. The more slow neutrons the higher the fluid content and thus the higher the porosity. The tools are calibrated in pure limestone and sandstone formations, with the pore space filled 100% with water. Corrections need to be applied for hydrocarbons and different rock types. The presence of gas will indicate an artificially low porosity – therefore the neutron porosity tool is often used to identify gas bearing zones in the formations drilled; • Sonic: a device that measures the speed of sound through the formation. The tool will have a sound source and a number of microphones evenly spaced along the length of the LWD tool. The acoustic tool will set up a number of different sound waves through the rock – the most common waves are referred to as compressional and shear waves. The microphoneswill pick up these waves as they pass by and the tool will calculate the time difference between passing by subsequent microphones. The measurement is used to supplement the density and neutron tools in estimating formation density and porosity as well as to determine rock strength; • Formation pressure and sampling: A device that uses a probe pressed against the formation to measure the pressure of the fluid within the rock. The rate with which the pressures build up and bleed-off provide a measure of the permeability of the rock and the rate at which the fluids can flow from the rock. Some newer tools have the capability to also pump some of that fluid out of the formation and into special containers. The fluid is retrieved when the tool returns to surface for laboratory analysis. The full analysis of the fluid is a critical factor and step in the development and exploitation of a reservoir bearing formation; • NMR, or MRIL/MRI-WD: Uses a magnetic field to polarize the protons within the fluids of the formation and a electro-magnetic “pulse” to set up a signal that will enable the logging engineer to break down the fluid into the different types of fluids contained in the formation. The types of fluids typically analyzed are free water, bound water (i.e., water attached to the rock grains), oil and gas. The measurement will also provide an indication of the mobility of the fluids and the permeability of the rock.

Important for what and to whom?

The LWD data is important for a number of reasons, detailed here by measurement type:

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•• Gamma ray is used to confirm, or fine-tune geological models and predictions and to assist in placing the well in the right formations. The readings will be used for lithology determination and to provide corrections in the processing of some of the data; •• Resistivity is used to identify zones where hydrocarbons are present and to calculate the amount of hydrocarbons. Resistivity should increase with depth as the rocks become more compacted, and thus tighter and bearing less fluid within. Trend analysis of the change in resistivity with depth is used to identify and approximate changes in pore pressure in the formations. Changes in the slope of resistivity change can be an indication of a change in pore pressure and an early warning of possible well control problems; •• Density/neutron porosity are normally used together to calculate the amount of porosity in the formations and to identify hydrocarbosn, especially gas-bearing formations. The data is an important input parameter in calculating the amount of hydrocarbons present in the formation. The density tool can be used like the resistivity tool to indicate changes in formation pressure, as well; •• Sonic data is used to correlate and calibrate seismic data and thereby improve the accuracy of the subsurface models used to determine where to drill. The data is also used to estimate formation porosity and can be used in combination with neutron/density tools to provide better estimates of that important parameter. The data is also used as inputs into geomechanical calculations to estimate rock strength and stresses. Finall,y the compressional wave velocity data can be used, just like the resistivity data, to identify and estimate changes in formation pore pressure; •• Formation pressure data is used while drilling to determine the correct mud weight required to maintain a stable hole and safe drilling conditions. The data is also used as an input into reservoir production models and algorithms to calculate expected rates of production and to determine where more complete pressure a production tests need to be conducted; •• Formation fluid sampling and analysis is important ion determining whether or not formation fluids are of sufficient quality for production and, if so, to determine how they will be produced, treated, processed, stored, and so on. •• NMR data are used to further refine reservoir production models and determination of what will and what will not be produced form the well, especially in formations that are dififcult to analyze with the more traditional tools described above. The tool’s measurement can be used as an alternative to neutron/ density tools for porosity measurements in some cases; •• Imaging tools are used as an input into geological

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models to more fully understand the geology of the rock formations. They are also used in “geosteering” to assist in determining how the well is intersection the formations and to correct the trajectory if needed.

Standard location on a rig

LWD equipment will have some surface equipment to make it work. This can range from a small console with a computer and display on the rig floor to a dedicated unit provided by a LWD contractor. Pressure transducers, displays, communication equipment, depth measurement equipment and cabling will all be installed on the rig in various locations to detect the telemetry signals, decode and display them. Some tools (density and neutron porosity) will require the use of radioactive sources, which will be stored in a special container on the rig and installed into and removed from the LWD tool on the rigfloor. Special equipment, monitors and personnel are required at those times. Other personnel should not be close to these operations.

Safety and handling

LWD tools come in a variety of sizes, configurations and dimensions. Each has unique requirements for safe handling and operation. Common among most systems: •• Most systems will have service company personnel to assist in the safe handling of the equipment; •• Most systems will recommend the use of filters or screens in the drillstring to keep debris in the drilling fluid from reaching the mud pulse or power turbine devices. Care should be exercised in handling, installing and removing these on the rig floor; •• Sonde-based systems usually need to be installed into and removed from special drill collars on the rig floor. Special handling tools will be required. The installation will typically require the use of a hoist (air hoist, or similar). Mud solids might have settled into the tools, rendering removal more difficult. They might "jump" during removal, as well; •• Some tools can harbor a risk of trapped pressure. It is good practice for personnel to stand behind either end of the tool during disassembly — not in front; •• Density and neutron porosity tools use radioactive sources that are installed and removed from the tools on the rig floor just prior to and upon completion of the bit run. Follow the directions of the LWD crew to minimize exposure to the radiation from these sources; •• Some tools require testing at surface. Care should be taken with fluid flow and pressure.

Applications

Follow the directions of the service company, or supplier on operational procedures. Surface testing is recommended for some tools – please follow the provided guidelines and

IADC Drilling Manual

directions for minimum, or maximum flow rates and pressures, minimum depth etc. Specialized situations can also occur. The mud pulse device and/or turbine for power will be sensitive to mud additives, loss circulation material and debris in the drilling fluid. Typically, the maximum amount of loss circulation material the system is tolerant to is appoximately 40 ppb medium nut plug or equivalent. Please consult with the provider on recommendations related to the exact type of LCM to be used.

General maintenance

Repair and maintenance will be done by the provider of the equipment. Tools and equipment should be flushed with clean water prior to laying down and shipping after use downhole. The material being used is mostly non-magnetic and thus appropriate pipe dope will need to be used.

Wireline logging

Openhole wireline logging does what LWD technology does; however, the measuring tools are run into the well on an electric wireline after a hole section is drilled. Wireline logging is commonly used to provide measurements of formation-related parameters measured by special instrumentation downhole and transmitted to surface through the wireline. There are a few more measurements available with wireline logging, compared to LWD, as well as some services that can only be done after drilling. Some wireline logging services are performed in cased holes, mainly for well integrity and production purposes. Most of these are run without a drilling rig present. The measurements available in Logging are: •• Gamma ray: natural gamma radiation emitted by the formations; •• Resistivity:– Resistance, or conductance of the different rocks and fluids; •• Density: Specific gravity of the rocks; •• Neutron porosity: Fluid-filled pore space volume of the rocks; •• Sonic: velocity of sound through the rock formations; •• Formation pressure and sampling: pressure of the fluids inside the formations and collection of fluid samples; •• NMR: Magnetic resonance of the fluids in the rock; ••Seismic.

Description and basic theory

Logging technology provides data about the formations through which the borehole is being drilled to glean information relating to the rocks and fluids present in those formations can be provided to the right folks for the planning and execution of drilling, completion and production operations.

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DOWNHOLE TOOLS

Physical operating principles

A logging tool will typically consist of the following components: •• Sensor packages –One or more logging measurement is included in a Logging toolstring: • Gamma ray: a device with instruments capable of detecting the gamma radiation emitted from the rock being drilled. Many different devices exist; • Resistivity: a device that generates a current flow in the formation and measures the resistance of the rock. The current can be generated in a number of ways, the common being: Currents induced by an electromagnetic field, using tools commonly referred to as induction tools. An alternating current is applied to a coil antenna placed on the logging collar. The current in the coil will generate a magnetic field, which in turn will induce current flow in the formation, which in turn will generate another magnetic field, and so on, propagating through the formation. The speed with which the field propagates and the rate at which the field attenuates (becomes weaker) are measured by secondary coil antennae on the tools and are a function of the resistivity of the formation, i.e., the rock and fluids contained in the rock; Current injected into the formation and collected further along the logging collar. This will require a drilling fluid that is conductive, in order for the current to flow from the tool into the formation. The amount of current that can be injected based on the potential difference between the point of injection and return on the logging collar is a function of the resistance of the formation between the 2 points. The tools are normally referred to as lateralog tools; • Density: A device that measures the density of the rock by using gamma radiation. A Gamma ray source, normally containing a very small amount of radioactive material, such as Cs-137, emits gamma radiation into the formation. The gamma radiation is scattered and absorbed in the formation, but some will make its way back to gamma-ray detectors in the logging tools. The amount of gamma radiation detected is a function of the density of the formation: the more radiatio,n the lower the densit,y and vice versa; • Neutron porosity: A device that measures the amount of the formation that is filled with fluid, i.e., not solid rock, by using neutron radiation. A neutron source, normally containing a very small amount of radioactive material, such as Am-241/Be, emits fast neutrons into the formation. These neutron are slowed down through collisions with the atoms in the formation. The neutrons

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•

• •

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will slow more quickly in fluid than in solid rock. Some of the neutrons will return to the logging tool’s neutron detector, where the slower neutron are counted. The more slow neutron,s the higher the fluid content and thus the higher the porosity. The tools are calibrated in pure limestone and sandstone formations, with the pore space filled 100% with water. Corrections need to be applied for hydrocarbons and different rock types. The presence of gas will indicate an artificially low porosity. Therefor,e the neutron porosity tool is often used to identify gas bearing zones in the formations drilled; Sonic: a device that measures the speed of sound through the formation. The tool will have a sound source and a number of microphones evenly spaced along the length of the Logging tool. The acoustic tool will set up a number of different sound waves through the rock. The most common waves are referred to as compressional and shear waves. The microphones will pick up these waves as they pass by. As the waves propagate along the tool, it will calculate the time difference between subsequent microphones. The measurement is used to supplement the density and neutron tools in estimating formation density and porosity as well as to determine rock strength; Formation pressure and sampling: a device that uses a probe pressed against the formation to measure the pressure of the fluid within the rock. The rate with which the pressures build up and bleed off provide a measure of rock permeability and the rate at which fluids can flow from the rock. Some tools have the capability to also pump some of that fluid out of the formation and into special containers. The fluid is retrieved when the tool returns to surface for laboratory analysis. The full analysis of the fluid is a critical factor and step in the development and exploitation of a reservoir bearing formation; NMR or MRIL use a magnetic field to polarize protons within formation fluids and an electromagnetic pulse to set up a signal that will enable the logging engineer to break down the fluid by type. The types of fluids typically analyzed are free water, bound water (i.e., water attached to the rock grains), oil and gas. The measurement will also provide an indication of the mobility of the fluids and the permeability of the rock; Imaging: “pictures” of various parameters of the rocks; Seismic is a service in which a strong acoustic source is placed at surface, while a set of geophones and hydrophones are lowered into the well on wireline to a desired depth. The acoustic source, which can be a strong vibrating tool, air or water gun, or an explosive charge, will send acoustic waves into the formation. These will be picked up by the geophones and hydrophones in the logging tool. As with the sonic tools,

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compressional and shear waves are transmitted and detected where possible.

Important for what and to whom?

The importance and use of logging data by measurement source is: •• Gamma ray is used to confirm, or fine-tune geological models and predictions and to assist in placing the well in the right formations. The readings will be used for lithology determination and to provide corrections in the processing of some of the data; •• Resistivity is used to identify zones where hydrocarbons are present and to calculate the amount of hydrocarbons. Resivity should increase with depth, because the deeper rocks become more compacted and tighter, leaving less room to hold fluids. Trend analysis of the change in resistivity with depth is used to identify and approximate changes in pore pressure in the formations. Changes in the slope of resistivity change can be an indication of a change in pore pressure and an early warning of possible well control problems; •• Density and neutron porosity are normally used together to calculate the amount of porosity in the formations and to identify hydrocarbons, especially gas-bearing formations. The data is an important input parameter in calculating the quantity of hydrocarbons present in the formation. Like the resistivity tool, the density tool can be used to indicate changes in formation pressure, as well; •• Sonic data is used to correlate and calibrate seismic data and thereby improve the accuracy of the subsurface models used to determine where to drill. The data is also used to estimate formation porosity and can be used in combination with neutron and density tools to provide better estimates of that important parameter. The data is also used as inputs into geomechanical calculations to estimate rock strength and stresses. Finally, the compressional-wave velocity data can be used, just like resistivity data, to identify and estimate changes in formation pore pressure; •• Formation pressure data is used while drilling to determine the correct mud weight required to maintain a stable hole and safe drilling conditions. The data is also used as an input into reservoir production models and algorithms to calculate expected rates of production and to determine where more complete pressure a production tests should be conducted; •• Formation fluid samples and analysis are important inpust into determining whether formation fluids are of sufficient quality for production and, if so, to determine how they will be produced, treated, processed, stored, and so on. •• NMR data are used to further refine reservoir

IADC Drilling Manual

production models and to determine what formations will be produced from the well. This is especially important in formations that are dififcult to analyze with the more traditional tools described above. In some cases, the tool’s measurement can serve as an alternative to neutron and density tools for porosity measurements; •• Imaging tools are used as an input into geological models to more fully understand the geology of the rock formations. They are also used in “geosteering” to assist in determining how the well is intersection the formations and to correct the trajectory if needed; •• Seismic is used to supplement traditional surface seismic acquired prior to drilling the wells, for calibration, additional inputs into models, or to resolve some features typically poorly resolved with surface seismic. The service is also referred to as VSP.Picture

Standard location on a rig

The logging equipment will have some surface equipment to make it work. This is normally in the form of a logging skid, or truck, which houses the surface computing system, as well as the winch and cablespool with the wireline. A sheave system will be installed on the rig floor and in the derrick to guide the control wireline movement into and out of the wellbore. Density and neutron porosity tools require radioactive sources. These should be stored in a special container on the rig and installed into and removed from the logging tools on the rig floor or catwalk. Special equipment, monitors and personnel are required at those times. All other personnel should avoid these operations.

Safety and handling

Logging tools come in a variety of sizes, configurations and dimensions. Each has unique requirements for safe handling and operation. Common among most systems: •• Most systems will have service company personnel to assist with safe handling; •• Density and neutron porosity tools use radioactive sources which are installed and removed from the tools on the rig floor just prior to and upon completion of the bit run. Follow the directions of the logging crew to minimize exposure to the radiation form these sources. Some tools require testing at surface. Care should be taken with fluid flow and pressure.

Applications

Follow the directions of the service company, or supplier on operational procedures. Surface testing is recommended for some tools. Please follow the provided guidelines and directions for minimum, or maximum pressures, minimum depth and so on.

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Figure DH-30: Hole problems that can lead to mechanical sticking.

The wireline can also be used for special operations such as setting bridge plugs, running freepoint tools, running perforating guns and so on. These might contain explosives, so appropriate precautions should be made. Follow the direction of the logging crew and any documentation from a job safety analysis.

General maintenance

Repair and maintenance will be done by the provider of the equipment. Tools and equipment should be flushed with clean water prior to laying down and shipping after use downhole.

Jars

Jars are used to free pipe stuck in the hole when normal pulling forces created by the rig’s drawworks are incapable of exerting enough force on their own to free the pipe. The pipe can be stuck for several reasons. Jars are also called accelerators, fishing jars and intensifiers.

Why do we need to jar?

Figure DH-31: In differential sticking, a major loss of fluid into the formation creates a pressure differential that forces the pipe against the wellbore.

Differential Sticking

It’s very simple. The sticking force is often much greater than the force that can be created by pulling or pushing on the string. The pulling force may be limited by the tensile strength of the pipe or the lifting capacity of the rig. The pushing force is limited by the ability of the string to fall downward in the hole. A jar allows us to greatly multiply these forces without exceeding the strengths of the pipe or the rig.

Differential sticking occurs when there is a significant loss of fluid to the formation which causes a differential in pressure between the annulus of the well and the formation. When pressure in the wellbore is greater than that of the formation, fluid is forced to the lower pressure area. Differential sticking occurs when migration of fluid from the well occurs at a rate which causes a vacuum effect in the wellbore that pulls the drill sting onto the wellbore wall, trapping it there (Figure DH-31).

Sticking

What is a jar?

Mechanical Sticking

Mechanical sticking occurs when a component or external feature of the drill string, such as the uphole shoulder of the bit or the edge of a stabilizer, becomes hung or caught on or within the formation (Figure DH-30).

IADC Drilling Manual

Very early jars were simply a tool with a sliding mandrel similar to a slide hammer that had a given distance of free stroke. An example of a very early jar was the bumper jar (with a sliding mandrel). The tool allowed for a set amount of free stroke of the string. An impact occurred when the stroke length was reached and motion suddenly ceased. When up firing, the string would be pulled rapidly upwards until the bumper jar reached its full stroke. Then, two shoul-

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Figure DH-32: Mechanical latch mechanism.

ders would collide inside the tool, like a hammer striking an anvil, creating an impact. When down firing, the string could be dropped rapidly to stroke the bumper jar from fully open to a fully closed position, where again, the two shoulders collided and an impact created. The disadvantage of these types of jars was the inability to store any energy. The impacts were limited by how fast the string could be raised stroking the bumper jar from fully closed to fully open. To apply additional energy to the impact event and to the stuck point, a system was created allowing additional overpull or weight to be applied to the string while delaying the stroke of the mandrel. This was essentially like stretching the spring on a mouse trap. The delay mechanism on mechanical jars, called a latch, has a preset release point. Once enough weight or pull is applied to the string and transferred down to the jar, the latch releases and all the stored energy is released rapidly and the hammer accelerates towards the anvil to create a much stronger impact. There are generally two types of jar delay mechanisms, hydraulic and mechanical. The term hydraulic or mechanical refers to the mechanism that the jar uses to delay the mandrel from stroking while the string is being either stretched or compressed, thus storing energy for improved impact.

Mechanical jars

A mechanical jar, the first iteration in the industry, uses a mechanism with a release load that is preset either at the service shop or the rig site. The mandrel is machined on the outer diameter with grooves that match rings cut on the inner face of a series of collets that are positioned around the circumference of the mandrel. A stack of Bellville springs provides compression that squeezes the collet plates inward on the mandrel to a predetermined level. The overpull or set weight must equal or exceed the preset latch release load in order to fire the jar. As a tensile load is applied to the string and the set release load is reached, the force of the collets on the mandrel is overcome. The device releases the stored

IADC Drilling Manual

Figure DH-33: Hydraulic jars use hydraulic pressure to hold the mandrel from stroking and a piston to slowly bleed off or meter the hydraulic pressure..

energy in the stretched string and the string snaps upward or downward, depending on the direction of force applied, and accelerates for the free stroke length of the mandrel until impact. If you cannot reach the set load the jar will not fire. Also, these jars fire at one and only one intensity, the one for which the latch is set. The jar cannot be fired at a higher load than the preset (Figure DH-32). The disadvantage of these jars is that the jar will not fire if the tensile load at the jar cannot be lowered at or below the preset release load.

Hydraulic jars

A hydraulic jar uses hydraulic pressure to hold the mandrel from stroking and a piston to slowly bleed off or meter the hydraulic pressure. This gives you from 30-90 sec at maximum overpull to several minutes at a low overpull to apply a load. Following a hydraulic delay, the load is released once the load exceeds the hydraulic force holding the mandrel from stroking (Figures DH-33 and -34). •• Overpull creates a high pressure and a low pressure area inside the hydraulic chamber; •• The fluid is forced through a restriction producing a delay period; •• After a certain metering stroke length, the jar is free to move through its free stroke and fires. Once the energy is released, simply apply force in the opposite direction of the firing to reset or “cock” the jar again. These jars can be reset hundreds of time downhole. The jarring load is infinitely variable ,simply by pulling or pushing more or less on the jar. By pulling a low tensile force, the jar will fire and create a small impact. By pulling the maximum

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Top sub

Knocker

Mandrel

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Metering section

Spline body

Bottom sub

Figure DH-34: Schematic of key components of a hydraulic jar.

Figure DH-35: Clamps onto the exposed mandrel hold the jar in the open position while being racked back in the derrick. It must support the weight of at least two drill collars above the tool.

recommended load, the jar will fire and create a large impact. It is sometimes said that hydraulic jars have no minimum tensile load required, but in reality they do. There is some seal friction from seals on seal surfaces and a slight interference fit of the piston in the detent portion of the hydraulic chamber. Typically these forces are quite small and will vary depending on jar size and type. The hydraulic jar will fire with any reasonable minimum load up to the maximum recommended load. Hydraulic jars are load and time sensitive.

Hydraulic jar safety

Special care MUST be taken when racking a hydraulic jar in the pipe rack. When tripping out of the well, sufficient overpull is applied to cock the jar and prepare it for a down-firing event. Hydraulic jars are designed to fire with very little weight applied. If a jar is tripped out and sitting on the bottom of a stand of tools or drill pipe, and there is any additional weight above the jar, this weight will begin the process of metering the fluid through the hydraulic delay mechanism. This will likely lead to a firing of the tool on the rig floor, compromising the safety of the entire rig and rig staff. If the jar is not equipped with an internal safety lock, then a safety collar must be applied around the open mandrel of

IADC Drilling Manual

Figure DH-36: Proper jar placement and setup depends on the type of sticking being encountered. Impact must exceed the sticking force for all sticking, but additional impulse is required to move differentially stuck pipe.

the jar to prevent the tool from stroking shut and firing (Figure DH-35).

Applications

There are some rules of thumb that have been around for a long time. Some are fairly accurate in a few instances, but the only way to be sure in all instances is to use a jar placement program or impact analysis software.

Jar placement in a fishing assembly

Refer to Figure DH-36. Jar placement, or “how many collars should I run between my jar and intensifier”, is a very common question. From the data entered into the program it will

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calculate “impact” and “impulse” at the stuck point based on a selected overpull applied to the jar and for the number of total collars input.

What is impact?

Impact is the force created when the jar comes to the end of its free stroke after being accelerated by the energy stored in the string and in the intensifier. The impact force can be as much as two to eight times the initial overpull. The impact force must be greater than sticking force for the fish to move.

What is impulse?

Impulse is how long the impact lasts (force x time). If the impact force is greater than the sticking force, the fish will move and impulse determines how far it moves.

How do impact and impulse affect jar placement?

There are two main types of sticking situations, mechanical and differential. Mechanical sticking is often over a relatively short length, and the fish may only need to be moved a short distance to come free. In this case, impact will typically be favored, with less concern for impulse. In differential or hydrostatic sticking situations where the stuck pipe may be several hundred feet long, it is common to use more impulse. Greater impulse usually comes at the cost of a decrease in impact, and if the lower impact force

IADC Drilling Manual

is not greater than the sticking force, the fish will not move. In any case, if the fish does not move, you are likely not exceeding the sticking force and it is common to switch to a higher impact fishing assembly. A general rule of thumb is to not sacrifice more than 20% of maximum impact to gain additional impulse.

General maintenance

Maintenance of the jars, accelerators and intensifiers are usually performed at the supplier's facility. However, the threads that make up the connections should be maintained by applying proper pipe-dope and protected with the correct thread protectors. Always install the safety clamp when the equipment is not being used. For more information on protecting connections and thread protectors, see the separate chapter on Drillstring in the IADC Drilling Manual, 12th edition. For more on fishing operations, see the separate chapter on Special Operations in the IADC Drilling Manual, 12th edition.

Reference

1.• M.A. Colebrook, S.R. Peach, “Application of Steerable Rotary Drilling Technology to Drill Extended Reach Wells” , F.M. Allen, G. Conran, IADC/SPE Paper #39327 Presented Dallas, Texas, 3–6 March 1998.

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DRILL STRING

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

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Worldwide QUALITY leader providing Drill Pipe since 2001 Manufacturing products ENGINEERED for long wear-life Offering API products and HIGH TORQUE products Unique manufacturing processes designed for DRILLING SUCCESS TSC Drill Pipe manufactures best in class Drill String components designed for all drilling applications including ERD and long laterals. We are focused on technical I

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c

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*See our high torque product tables in the appendix of this section, page DS-A2*

www.drillpipe.com [email protected] Tel: 832-230-8228

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T

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. 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 CONTRIBUTORS Ludivine Laurent, Vallourec Marta LaFuente, Vallourec Michael Jellison, NOV Grant Prideco Phillippe Machecourt, Vallourec David Pixton, NOV Vincent Flores, Vallourec Terry Howard, TIW Tom Smith, Consultant Yannick Mfoulou, Vallourec REVIEWER Robert W Schultz, Alcoa

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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: 978-0-9915095-3-9

Printed in the United States of America.

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DRILL STRING Contents CHAPTER DS

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Contents

DRILL STRING

Drill string & components........................................... DS-1 API/ISO specifications.......................................... DS-1 Drillpipe description and basic theory.....................DS-2 General information................................................ DS-2 Grades and lengths of steel drillpipe................DS-3 Marking......................................................................DS-3 Weld-on tool join description/basic theory..........DS-3 Tool-joint selection.................................................DS-3 Torsional strength...................................................DS-4 Elevator shoulder design.......................................DS-4 Tool-joint markings.................................................DS-5 Drillpipe upsets for weld-on tool joints............DS-5 High strength drillpipe...........................................DS-5 Cleaning and inspection........................................DS-5 Picking up the drill string....................................... DS-7 Thread compounds................................................. DS-7 Operating limits, safety and handling..................... DS-7 Effect of doglegs and floating operations........ DS-7 Extent of fatigue damage......................................DS-8 Cumulative fatigue..................................................DS-8 Floating drilling operations.................................DS-11 Notch fatigue..........................................................DS-12 Steel stenciling.............................................DS-13 Electric arc burns.........................................DS-13 Rubber protector grooves.........................DS-13 Tong marks....................................................DS-13 Slip marks......................................................DS-13 Crooked pipe fatigue............................................DS-13 Corrosion fatigue...................................................DS-13 Critical rotating speed..........................................DS-14 Collapsed pipe from drill-stem and BOP tests............................................................DS-14 Transition from drill string to drill collars.......DS-14 Maximum allowable pull and rotary torque..DS-15

IADC Drilling Manual

Make-up torque vs drilling torque....................DS-15 Fishing operations.................................................DS-16 Pulling out stuck pipe.................................DS-16 Jarring.............................................................DS-16 Torque in washover operations...............DS-16 Dynamic loading of drillpipe during tripping.................................................................DS-16 Operations and applications................................... DS-29 Drillpipe problems................................................ DS-29 Breaking in new tool joints...................... DS-29 Tripping......................................................... DS-29 Lowering the elevators...................... DS-29 Breaking out.......................................... DS-29 Alternating breaks...................... DS-30 Standing back............................... DS-30 Going in the hole................................. DS-30 Lubrication practice................... DS-30 Stabbing......................................... DS-30 Spinning up................................... DS-30 Make-up and tonging.................DS-31 Running In......................................DS-31 Laying down drill string......................DS-31 Damages and failures: Causes and prevention..................DS-31 Visual examination for damage while tripping..........................DS-31 Failures........................................... DS-33 Torsion........................................... DS-33 Downhole torque........................ DS-33 Other obvious forms of torsional failures................... DS-34 Overtorquing in the rotary table............................. DS-36 Other damage.............................. DS-36

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DRILL STRING

Repair of tool joints.............................................. DS-37 General.......................................................... DS-37 Field repair of damanged tool joints..... DS-37 Shop repair of damaged tool joints....... DS-38 O-ring use..................................................... DS-38 Welding procedures for downhole drilling tools................................................................ DS-38 Transportation....................................................... DS-39 Truck transportation.................................. DS-39 Offshore service vessels.......................... DS-39 Floor handling procedures................................ DS-40 Slips and bushings...................................... DS-40 Handling........................................................ DS-40 Storage........................................................... DS-40 Replacing slips with double elevators... DS-40 Slips alternative........................................... DS-41 Testing slips and bushings....................... DS-41 Proper slip handling................................... DS-41 Using tongs properly................................. DS-42 Setting slips on tool joint.......................... DS-42 Drillpipe corrosion................................................ DS-44 Corrosive agents.........................................DS-44 Factors affecting corrosion rates........... DS-45 Corrosion damage...................................... DS-45 Detecting and monitoring corrosion..... DS-46 Sulfide stress cracking........................................ DS-47 Mechanism................................................... DS-47 Critical SSC factors.................................... DS-47 Minimizing SSC........................................... DS-47 SSC in oil-based drilling fluids................ DS-48 Drillpipe inspection and classification.................. DS-49 Inspection standards........................................... DS-49 Limits of inspections............................................ DS-49 Definition of a crack............................................ DS-49 Measurement of pipe wall................................. DS-49 Cross-sectional area............................................ DS-49 Inspection classification marking.................... DS-50 Tool joints...................................................................... DS-50 Required tool-joint inspection.......................... DS-50 Optional tool-joint inspection........................... DS-50 Magnetic particle inspection............................ DS-51 Gauging and repairing damaged shoulders............................................................ DS-51 Aluminum drillpipe..................................................... DS-54 Tool joints............................................................... DS-54 Drill string care and handling............................ DS-55 Slips........................................................................... DS-55

IADC Drilling Manual

Blowout preventers.............................................. DS-55 Elevators.................................................................. DS-55 Maintenance.......................................................... DS-56 Coating.......................................................... DS-56 Worn rotary tables and bushings.......... DS-56 Straightening................................................ DS-56 Operating limits.................................................... DS-56 Elasticity........................................................ DS-56 Mixed strings............................................... DS-56 Stuck pipe and fishing............................... DS-56 Heavy weight drillpipe............................................... DS-57 Connection stress-relief design....................... DS-61 Cold working thread roots................................. DS-62 Directional & horizontal drilling....................... DS-62 Types of HWDP.................................................... DS-63 Standard HWDP......................................... DS-63 HWDP with three spiral wear pads...... DS-63 HWDP with continuous spiral wear pad.................................................. DS-63 HWDP material grades...................................... DS-63 Welded configuration............................... DS-63 Integral configuration................................ DS-63 Safety and handling............................................. DS-65 Failure prevention and troubleshooting......... DS-65 Downhole friction induced heating failures............................................................... DS-66 Identifying downhole heating................. DS-66 Mitigation methods................................... DS-67 Drill collars.................................................................... DS-68 Types of drill collars............................................. DS-68 Hardbanded drill collars........................... DS-68 Measuring length................................................. DS-69 Slip and elevator recess...................................... DS-69 Connections........................................................... DS-69 Stress relief features............................................ DS-69 Materials..................................................................DS-70 Sour service (ERS425)...............................DS-70 Non-magnetic DC.......................................DS-70 Operating procedures and best practices.....DS-70 Evaluation, testing and inspection...................DS-70 Calculating bending stress ratio (BSR)...........DS-70 Safety valves.................................................................DS-72 Kelly cock valve......................................................DS-72 KC2S assembly............................................DS-72 Kelly cock specifications...........................DS-72

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DRILL STRING RDCV........................................................................DS-72 RCDV specifications...................................DS-73 I-BOPs.......................................................................DS-73 I-BOP specifications...................................DS-73 I-BOP design.................................................DS-73 Accessories...................................................................DS-73 Subs...........................................................................DS-73 Linking subs..................................................DS-73 Lift subs..........................................................DS-73 Workover subs.............................................DS-73 Pup joints.................................................................DS-75 Stabilizers.................................................................DS-75 Kellys.........................................................................DS-75 Wired drill pipe.............................................................DS-76 System overview....................................................DS-76 System components.............................................DS-76 Electronic network devices.................................DS-76 Dimensions, weight and capacity....................DS-78 Drillpipe....................................................................DS-78 HWDP and drill collars........................................DS-78 Internal blowout preventers...............................DS-79 Related equipment................................................DS-79 Safety and handling..............................................DS-79 Proper handling......................................................DS-79 Rig setup...................................................................DS-79 Rig-site handling....................................................DS-79 Drilling and tripping..............................................DS-79 Common failure modes and mitigation..........DS-79 Uses & applications............................................. DS-80 Make-up and break-out...................................... DS-80

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Drifting wired tubulars........................................ DS-80 Wireline tools........................................................ DS-81 Best practices........................................................ DS-82 Environmental considerations.......................... DS-82 Fluid environment...................................... DS-82 Temperature and pressure...................... DS-83 Vibration....................................................... DS-83 Evaluation and inspection.................................. DS-83 Mechanical evaluation........................................ DS-83 Electrical evaluation............................................. DS-84 Standard location at a rig site........................... DS-84 Troubleshooting and failures............................ DS-84 General maintenance.......................................... DS-84 Surface equipment..................................... DS-84 Network health maintenance.................. DS-85 Proper storage considerations................ DS-85 Repairs..................................................................... DS-85 Surface equipment..................................... DS-85 Drill-stem tubulars..................................... DS-85 Related calculations and tables........................ DS-86 Important calculations.............................. DS-86 Drift size........................................................ DS-86 Cable volume............................................... DS-86 Landing string.............................................................. DS-86 Overview................................................................. DS-86 Common dimensions, weights, capacities... DS-86 Glossary......................................................................... DS-87 References.................................................................... DS-90 Appendix.......................................................................DS-A1

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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

DRILL STRING

Drill string and components

This chapter of the IADC Drilling Manual is concerned with the specifications, operating data, and the care and handling of drill string. It will also discuss troubleshooting of the problems that may occur. The IADC definition of a drill string is drillpipe with tool joints attached. Drill stem is all those members between the swivel and the bit, and it includes drill string, kelly or top drive, subs, drill collars, heavy weight drillpipe, stabilizers, shock absorbers, reamers and any other in-hole equipment used generally or part-time during drilling operations.

API/ISO specifications

In the worldwide oil industry today, an overwhelming majority of all tubular goods are manufactured to specifications developed and approved by the American Petroleum Institute. These specifications cover the mechanical properties of the steel, the details of manufacture and physical dimensions of the pipe. The latter include internal and external diameters, wall thickness, and upset dimensions for each nominal size, weight and grade, as well as tool joint type, OD and ID, and length. API Specification 5DP covers drillpipe. Bulletins 5A2, 5C2, and 5C3 cover aspects of the use of and care of drillpipe wall thickness or that joints would mate with similar products manufactured by different companies. To mitigate the resulting confusion and loss of time, the API was induced to undertake a program of standardization and marking. This program is a continuing one which enables changes to occur based upon improved technology and the needs of users and manufacturers to be disseminated to the industry in a minimum amount of time and with a high degree of accuracy. API Specifications and Recommended Practices cover a wide range of oilfield equipment in addition to tubular goods. These publications are revised as necessary and constitute one of the best sources of information on the design, manufacture, care, and use of drilling and production equipment. This section of the Drilling Manual relates not only to the API 5DP specifications, but also to Recommended Practice RP7G and RP7A1. These publications relate to the connections for the drill string and also to the design and operating limits of the drill stem. This section of the Drilling Manual discusses drill string care and use and gives examples of the types of problems usually encountered when the drill string is improperly used or used beyond its physical capabilities. This section also recommends practices which will overcome or eliminate the problems often encountered when using the drill stem. In the oil industry today, most drillpipe is manufactured to specifications developed and approved by API/ISO. This

IADC Drilling Manual

DS–1

Table DS-1: Drill pipe grades. Current Grades

Grade Code

Minimum Yield (psi)

E-75

E

75,000

X-95

X

95,000

G-105

G

105,000

S-135

S

135,000

Z-140*

Z

140,000

V-150*

V

150,000

U-165*

U

165,000

Drill pipe tubes are furnished in the following API length ranges: • Range 1: 18-22 ft; • Range 2: 27-30 ft; • Range 3: 38-45 ft. includes mechanical properties of the steel and physical dimensions of the tubes and their upsets. Normal tolerance on yield strength of drillpipe tubes is plus 30,000 psi. All grades above E-75 are referred to as high strength. Grades marked with an asterisk have been used ,but not been formally recognized. The production of high-strength drill-pipe tube began in the 1950s. When high strength tubes were accepted by API some 10 years later, tool joint dimensions (ODs and IDs) were those commonly used on E75 tubes. A committee was appointed, and tool-joint dimensions recommended, with the result that the torsional yield of the tool-joint pin was at least 80% as strong as the tube to which it was to be attached. Good practice is for the tool-joint box to be stronger than the pin initially, because wear will ultimately make the box the weaker member. The attaching of tool joints to upset drillpipe tubes by flash welding was replaced in the 1970s by inertia and friction welding. API/ISO specifications require the weld to be stronger than the tube body, have good ductility, and not be harder than 37 Rockwell C. Most sizes of drill-pipe tubes come in light weight, standard weight, and one or more heavier than standard weights. Both the grade code and the weight code should be stenciled on the pin base for finished drill string assemblies. It is recommended that these two codes (grade and weight) also be stenciled on a milled flat on the pin tong surface for quick identification. The numeric code is 1 for a light-weight tube and 2 for a standard weight tube. Heavier-than-standard tubes receive a 3, 4, or 5. Most of the tubes today are standard weight, and these receive the 2 designation. A complete

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DS–2

DRILL STRING Table DS-2: Tool joint connections. Grade code

Description

IF

Internal Flush

EH or XH

Extra Hole

SH

Slim Hole

OH

Open Hole

SL - H-90

Slim Line-Hughes-90

FH

Full Hole

H-90

Hughes-90

WO

Wide Open

NC

Numbered Connection

list of these may be found in API 5DP in Table C-12. Drill string nomenclature and abbreviations are detailed in Table DS-2.

Drillpipe description and basic theory

Figure DS-1: Weld-on tool joint. The flash-welded tool joint, introduced in 1938, was the industry’s first weld-on tool. Inertia welding was introduced in 1974 and continuousdrive friction welding in 1978.

Table DS-3: Interchangeability chart for tool joints. NC

NC26

NC31

NC38

Internal flush

2 3/8

2 7/8

3 1/2

Full hole

The drill string is required to serve three basic functions: • Transmit and support axial loads; • Transmit and support torsional loads; • Transmit hydraulics. The design parameters and a step-by-step procedure of designing a string are given in API RP 7G, 16th ed, Section 7. Another recommended source document is G. K. McKown, Drill String Optimization for High-Angle Wells, 1989 SPE/IADC Drilling Conference, SPE/IADC 18650. Seamless drillpipe is offered in the grades listed below under “Mechanical Properties API Steel Drill Pipe”. The drill string is used to transmit power by rotary motion from surface to a drill bit at the bottom of the hole, to convey flushing media to the cutting face of the tool, and to carry cuttings out of the hole. Thus, it plays a vital part in the successful drilling of oil and gas wells. Here are commonly used abbreviations for drill-pipe upsets: • IU: Internal upset; • EU: External upset; • IEU: Internal-external upset.

3 1/2

Wide open Slim hole

NC46

NC50

4

4 1/2

4 1/2

5

4

5

4

Extra hole

General information

NC40

3 1/2 2 7/8

4

4 1/2

With the exception of specialty tools, probably no other part of the drill stem is subjected to the complex stresses which drill string must withstand. For this reason, the combined skills of steel-industry engineers, with full cooperation from oil companies and drilling contractors and in conjunction with API and IADC, have been used in the development of this vital tool. The same skill was utilized in formulating suggested practices in the care and handling of pipe on the surface, while making trips in and out of the hole and while drilling. With this information, contractors and operators can extend drill-string life and realize inprove project economics. Drill string is an important and expensive part of the rig, but suffers from a relatively short life. The cost of the drill string places it in the category of a capital investment. It is not strictly expendable. A recommended practice, followed by many contractors, is to identify each joint upon purchase with an alpha-numeric serial. This serial number, along with the length of the joint, should be recorded when it is placed

Table DS-4: Mechanical properties of API steel drill pipe. Grade

E-75

X-95

G-105

S-135

Yield Strength (minimum psi)

75,000

95,000

105,000

135,000

Yield Strength (maximum psi)

105,000

125,000

135,000

165,000

Tensile Strength (minimum psi)

100,000

105,000

115,000

145,000

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DRILL STRING

DS–3

Markings at base of pin: ZZ 6 07 YY E 1 NC50

in the string. This practice, along with field support and office accounting, will facilitate: • Determining the useful life of the joint; • Recording types of service and stresses the joint might be exposed to; • Switching within the string to optimize use; • Determining causes of failures more accurately; • Preventing or minimizing downhole failures.

Tool joint mfctr: Month welded: Year welded: Pipe upsetter/processor Pipe grade: Pipe weight code Tool-joint type: Drill pipe grades Grade E-75 X-95 G-105 S-135 V-150

Grades and lengths of steel drillpipe

ZZ (ZZ Co.) 6 (June) 07 (2007) YY E 1 NC50

Symbol E X G S V

As discussed in API/ISO Specifications above, drillpipe tubes are furnished in the following API length ranges: • Range 1: 18-22 ft; • Range 2: 27-30 ft; • Range 3: 38-45 ft.

ZZ 6 07 YY E 1 NC50

Marking

Figure DS-2: Tool joint markings for component identification. Note: Pin base marks should be clear and legible and not struck over with manufacturing data.

Drillpipe identification is marked at the base of the pin by the tool joint manufacturer after the pin is affixed. The marking will be in accordance with Figure DS-2. It is further recommended that drillpipe other than standard weight Grade E-75, be marked according to Figures DS-3 through DS-5. This is to give the crew rapid identification of high strength drillpipe on the racks and on the floor during trips when it is in a combination string with Grade E-75. With little trouble, if necessary cleaning out the milled slot, the specific grade and weight can be determined from the stenciled figures. joint OD surfaces should be performed, with an emphasis on detection of longitudinal cracks. •  In highly stressed drilling environments or if evidence of fatigue damage is noted, magnetic particle inspection should be made of the entire box threaded area, especially the last engaged thread area, to determine if transverse cracks are present. • The wet fluorescent magnetic particle method is preferred.

Weld-on tool joint description/basic theory

Pipe Grade Code

Pipe Weight Code

Groove

Milled Slot 1/4 in.

L PB L PB 2

See note B

Figure DS-3: Identification of standard weight high strength drill pipe. (Refer to notes on p DS-4.) .

Pipe Grade Code

The flash welded tool joint was the first weld-on type tool joint introduced to the industry in 1938. Inertia welding was offered in 1974 and continuous-drive friction welding in 1978. Figure DS-1 illustrates weld-on tool joint.

Pipe Weight Code

Milled Slot 1/4 in.

Both inertia and continuous-drive friction welders use frictional heat for achieving welding temperatures. However, the inertia welder uses a flywheel and momentum principle, whereas the continuous drive-friction welder maintains a constant rpm motor and brake system.

L PB L PB 2

1” 45°

1/16R min. See Note B

Tool-joint selection

For many years tool joints have had a minimum yield strength of 120,000 psi. The old IF, XH, FH, etc., have been replaced with Numbered Connection series - NC plus a number in-

IADC Drilling Manual

Figure DS-4: Identification of heavier-than-standard weight Grade E-75 drill pipe. (Refer to notes on p DS-4.)

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DS–4

DRILL STRING

dicating pitch diameter in inches and tenths. NC46 replaces the old 4 ½-in. Extra Hole (XH). The NC series have the same “V” threads, but with a 0.038-in.rounded root radius. This offers a slightly better fatigue life and a slightly smaller cross section.

Pipe Grade Code

Pipe Weight Code

Milled Slot

Groove

1/4 in.

Table DS-3 shows the interchangeability between NC connections and the old style designations.

L PB L PB

Torsional strength

2

1”

The torsional strength of a tool joint is a function of several variables. These include the strength of the steel, connection size, thread form, lead, taper, and coefficient of friction on the mating surfaces of threads and shoulders. The torque required to yield a rotary-shouldered connection may be obtained from the equation in Appendix A, API RP7G. The pin or box area, whichever controls, is the largest factor and is subject to the widest variation. The tool-joint outside diameter (OD) and inside diameter (ID) largely determine the strength of the joint in torsion. The OD affects the box area and the ID affects the pin area. Choice of OD and ID determines the areas of the pin and box and establishes the theoretical torsional strength, assuming all other factors are constant. OD wear causes the greatest reduction in theoretical torsional strength of a tool joint. At whatever point the tooljoint box area becomes the smaller or controlling area, any further reduction in OD causes a direct reduction in torsional strength. If the box area controls when the tool joint is new, initial OD wear reduces torsional strength. It is possible to increase torsional strength by making joints with oversized OD and reduced ID.

1-1/4”

45°

1/16” R min. See Note B

Figure DS-5: Identification of heavier-than-standard weight high-strength drill pipe. (Refer to notes below.) Note A: Standard weight Grade E-75 drill pipe designated by an asterisk (*) in the drill pipe weight code will have no groove or milled slot for identification. Grade E-75 heavier than standard weight drill pipe will have a milled slot only in the center of the tong space. Note B: Groove radius approximately ⅜-in. Groove and milled

slot to be ¼-in. deep on 5 ¼-in. OD and larger tool joints, 3/16 in. deep on 5-in. OD and smaller tool joints.

Note C: Stencil the grade code symbol and weight code num-

ber corresponding to grade and weight of pipe in milled slot of pin. Stencil with ¼-in. high characters so marking may be read with drill pipe hanging in elevators.

Elevator shoulder design

Tool joint box elevator shoulders are manufactured in both the square and 18° taper. Most weld-on type tool joints are furnished with tapered shoulders. Tool joint pins are generally furnished with 35° tapered shoulders, but can be made available with an 18° tapered shoulder. Elevators are available to work with either 18° tapered or square-shouldered joints. Those for use with the 18° tapered shoulders are generally heavier due to the higher radial loading that results from the wedging action. API Specification 8C specifies elevator bores to correspond to dimensions of the box elevator upset. On some tool joint assemblies, such as slim hole, lifting plugs are used to provide the elevator shoulder necessary to handle the drill string.

IADC Drilling Manual

Figure DS-6: Plastic coating in the pin bore acts as a stress coat and serves as an early indicator of pin stretch.

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DRILL STRING

DS–5

Tool-joint markings

It is recommended that weld on tool joints be stenciled on the base of the pin with the information shown in Figure DS-2. In addition, it is further recommended that drillpipe weight and grade identification as shown in Figure DS-3, -4 and -5 be used.

Drillpipe upsets for weld-on tool joints

Figure DS-7: Thread protectors will prevent most tool-joint damage that can occur during moving or racking.

Drillpipe must have upsets for installation of weld-on type tool joints. This allows an adequate safety factor in the weld area for mechanical strength and metallurgical considerations. The tool joint is made with a welding neck or tang to facilitate welding API upsets for various sizes, grades and weights of drillpipe listed in API 5DP.

High-strength drillpipe

Because of deeper drilling and higher stress levels, grades of drillpipe stronger than Grade E-75 have been developed. High-strength drillpipe requires heavier and longer upsets than those used on Grade E-75. Tool joints on high-strength drillpipe are designed to fit the same elevators as those used for the Grade E-75 assemblies.

Stress, pounds per sq in. (psi) 50,000

45,000

Cleaning and inspection

40,000

35,000

30,000

25,000

20,000

15,000 10,000

100,0000

1,000,000

10,000,000

100,000,000

Pin and box thread and shoulders should be thoroughly cleaned to prepare them for adding to the string. Cleaning pays off in three ways. Cleaning: • Removes foreign material and permits proper make-up, thereby reducing danger of galling and wobbles; • Permits better inspection; • Increases the life of connections by eliminating abrasive materials.

Number of Cycles of Stress

Figure DS-8: S-N curve of mild steel shows number of cycles under stress to produce failure.

Connections should be thoroughly dried after cleaning so that the thread compound will properly adhere to the surface. An approved way to clean tool joint threads and shoulders is to wet the connection with kerosene or diesel; then brush with ordinary gel. Catch the old dope and gel and dispose of properly. This will leave connections clean and dry for visual inspection and for applying fresh thread compound. After cleaning, inspect thread and shoulders carefully. Damaged connections should never be run in the hole. Even slight damage will likely cause wobbling or leaking. Slight damage may be repaired at the rig with a shoulder dressing tool or file. Test each box and pin shoulder with a shoulder dressing tool test ring. Use the benchmark to make sure that no tool joint shoulder has been dressed beyond recommended limits. Check the plastic coating in the pin bore under the last engaged thread as a first check on pin stretch (Figure DS-6). After inspection, protect all boxes and pins with clean, dry thread protectors.

Figure DS-9: Example of pure fatigue in a drill string box.

IADC Drilling Manual

Copyright © 2015

DRILL STRING Dogleg Angle, Degrees

Dogleg Angle, Degrees 1.0

1.5

2.0

2.5

0

3.0 0

In corrosive muds reduce dog-leg angle to a fraction (.06 for very severe conditions) of value indicated by fatigue curve.

2

9 10 11

igue

2,00

8

e Yi

200

l

n di

g

G of

ra

de

“E

”

i lP

pe

12 13 14 15

Tension - Thousands of Pounds

0 L bs On To ol of G Jo rad in e “ t E” Dr ill Pi pe

7

Fat

Tension-Thousands of Pounds

6

Tension - Thousands of feet of pipe

5

il Dr

2.0

2.5

3.0 1 2

50

4

150

1.5

0

3

100

1.0

In corrosive muds reduce dog-leg angle to a fraction (0.6 for very severe conditions) of value indicated by fatigue curve.

1

50

0.5

3

100

150

200

250

16

5 6 7 8 9 10 11

ing eld Yi

17 18

4

nt oi

2,00 0L bs. on e of To Gra ol de J “E” Dri ll P ipe

0.5

Fatig u

0

300

e ad Gr of

e Pip rill D ” “E

12 13 14

Tension - Thousands of Feet of Pipe

DS–6

15 16 17 18

19

19 B4-4

Figure B4-4: Fatigue damage conditions in abrupt Figure DS-11: Fatigue for damage doglegs vs. tension 4 1/2”conditions - 16.6 lb/ft in drillabrupt pipe.

Figure DS-10: Fatigue damage conditions in abrupt

doglegs vs tension for 4 ½-in., 16.6 lb/ft drill pipe.

doglegs vs. tension for 3 ½-in., 13.3 lb/ft drill pipe.

Percent Fatigue Life Expended in a 30-foot Interval 0

50

100 3-1/2”

4-1/2” 5”

0

Dogleg angle Degrees 0.5

1.0

1.5

2.0

2.5

3.0 0

In corrosive muds reduce dog-leg angle to a fraction (0.6 for very severe conditions) B of value indicated by fatigue curve.

2,00 0L bs. on Fatig To ue o ol fG Jo rad in e“ E” Dr ill Pi p e

Tension - Thousands of Pounds

4

t

100

5

J

200

el Yi

a Gr of g n di

50

Dogleg Severity Degrees /100 Feet

5

7 8 9

” “E de

ip e ill P Dr

10 11 12 13 14 15 17 18

Figure B4-5: Fatigue damage conditions in abrupt

B4-5

Figure DS-12: Fatigue damage conditions in abrupt doglegs vs tension for 5-in., 19.5-lb/ft drill pipe

IADC Drilling Manual

9 8

A 10

B

C D

100

E 100

7

150 150

6

200 150

5

200 250

15

16

R

100

10

doglegs vs. 6tension for 4 1/2” - 16.6 lb/ft drill pipe.

Q

150

Tension - Thousands of Feet of Pipe

3

Length of Drill Pipe Below Dogleg (Thousand of Feet)

2

50

250

50 50

1

Tension In Drill Pipe In Dogleg (Thousands of Pounds)

0

3

4

For: Drill Pipe, 3-1/2”, 4-1/2” and 5” Grade “E” Steel; Rotary Speed, 100 RPM; Drilling Rate,10 Feet/Hour

Figure DS-13: Fatigue damage conditions in gradual doglegs vs tension in a non-corrosive environment.

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B4-6

DRILL STRING Percent Fatigue Life Expended in a 30-foot Interval 50

0

100

DS–7

many cleaning fluids can dilute the compound and keep it from adhering properly to the surfaces to be protected.

3-1/2” 4-1/2” 5”

0

Operating limits, safety and handling

Dogleg Severity Degrees / 100 Feet

8

5

50 50

50

7

100 100

6 5

100

10

150

150

4 200

Tension In Drill Pipe In Dogleg (Thousands of Pounds)

Length of Drill Pipe Below Dogleg (Thousands of Feet)

10 9

150 200

3

Effect of doglegs and floating operations

Metal is weaker under dynamic loading than under static conditions. Steel has the capability of absorbing dynamic loading, or cycles of stress, for an infinite number of reversals if the stress is kept under a certain limit. This is illustrated in Figure DS-8, which is a simple example of an S-N curve, stress vs number of cycles to produce failure. The point at which the curve straightens out is called the endurance limits of steel. If the stress never goes above that point, any number of cycles will not cause failure.

250

15

2

For: Drill Pipe, 3-1/2”, 4-1/2” and 5” Grade “E” Steel; Rotary Speed, 100 RPM; Drilling Rate,10 Feet/Hour Figure B4 -7: Fatigue damage conditions in gradual doglegs vs. tension in a corrosive environment

B4-7

Figure DS-14: Fatigue damage conditions in gradual doglegs vs tension in a corrosive environment.

Picking up the drill string

Thread protectors will prevent most of the tool joint damage which occurs in moving and racking. Threads and shoulders of both boxes and pins should be protected from damage when drill string is picked up or laid down. Do not permit threads or shoulders to strike steel on walk or ramp. Wood splinters from the walk can be packed so tightly into the threads that they are very difficult to remove. A clean thread protector made up hand-tight should be used in this operation. See Figure DS-7.

Thread compounds

Rotary-shouldered connections endure high unit stresses in normal service. Galling and seizing may occur if the separating film is insufficient to prevent metal-to-metal contact. This separating film is normally a soft metallic fiber (zinc or copper) in a greasebased carrier. A good thread compound, properly applied, should prevent or minimize galling in all but the most severe service, and it should also help to minimize make-up while drilling.

To illustrate simply, consider a nail bent back and forth until it breaks. With this mild steel, if the stress is kept below 27,000 psi, the nail will not break regardless of the cycles. At 30,000 psi the nail will break with 2,000,000 cycles, and at a stress of 48,000 psi, the elastic limit, the nail will break immediately. Such failures with cyclic stresses are called fatigue failures. The mechanism of fatigue failure is a progressive one. It starts a submicroscopic yielding of the atoms along the crystal slip planes. With alternating stress, this movement generates heat, lowering the cohesive strength of the constituents. As a result, submicroscopic cracks form, which will progressively unite until the crack becomes visible. The direction of the crack is normally perpendicular to the stress. Chemical composition, microstructure, surface finish, and tensile properties are some of the properties of steel that determine the fatigue or endurance limit. A very rough approximation of the fatigue strength of drillpipe when tested in the lab in air is one half of its tensile strength in a small scale RR. More metallurgical test sample, or 20% of the tensile strength in a full-size sample. In addition, the presence of notches and corrosion has a great effect on the fatigue strength.

The present API RP7A1 gives a method by which the friction factor may be compared between any thread compound and a reference compound. RP7A1 does not yet offer a way to compare resistance to additional make-up or resistance to galling.

Drillpipe is subjected to cyclic stresses in tension, compression, torsion, and bending. Tension and bending (alternate tension and compression of the same pipe wall) are the most critical stresses. The magnitude of any stress can be compounded by the effect of vibration. Pure fatigue failures in straight-hole drilling are becoming less frequent, except for doglegged or deviated holes or where failures are associated with notches and corrosion.

Thread compounds should not be thinned for ease of application. Dilution will reduce the percentage of the metallic constituent, which may make the compound inadequate to prevent galling. For best results, thread compound should be applied to clean, dry threads and shoulders. The presence of

The decrease in pure fatigue failures in straight-hole drilling owes to the general practice of using sufficient drill-collar weight, so that the drill string is in tension down through the top two or three drill collars. Buoyancy and hole inclination must be considered when calculating drill collar weight to

IADC Drilling Manual

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DS–8

DRILL STRING Dogleg Severity (Hole Curvature) - Degrees/100 ft

A

15

0 50

LB

LB

0

2,

LB

00

0

1, LB 0 00

00

LB

6,

00

0

LB

4,

0 5,

200

1

3,

2,

00

0

50

LB 00 3,0

0 LB 2,00

150

0 LB

50

0

1,

LB

00

0

LB

100

1,00

Bouyant Wt. Suspended Below the Dogleg Thousands of Pounds

LB

0

50

.

10

LB

0

5

0

00

B

LB

7,0

L 00 8,0

B

2

250

LEGEND Force on Tool Joints Force on Drill Pipe

300

B4-8

Figure DS-15: Lateral forces on 3 ½-in., 13.3 lb/ft Range 2 drill pipe with 4 ¾-in. tool joints.

keep drillpipe in tension. Today the major factor in fatigue failures is cyclic bending of pipe being rotated in a hole that is changing direction. This is commonly called a dogleg and occurs in straight-hole as well as directional drilling. Failure can occur even when proper drill collar weight is maintained and there is no permanent set in the drillpipe. When pipe is deflected and rotated, it goes through cycles of stress from tension to compression on each side of the pipe with each rotation. Drillpipe rotating at 100 rpm makes 144,000 rev/day, if left on bottom continually. Hence, in just seven days there could be more than a million stress cycles on the pipe when rotating under conditions creating variable stress. Using the S-N curve in Figure DS-8, if the stress were 32,000 psi, this is sufficient to cause pipe failure. The portion of the string right above the drill collars is potentially most subject to bending. Drill collar mass will resist bending, and deflection will occur above in the drillpipe. Also maximum stress on the drillpipe will occur from the run-out point of the upset to approximately 20 in. from the tool joint. As above, the tool joint will not bend. The bending occurs in the relatively thin pipe wall. This change of cross section in the tool joint acts as a vise and becomes the ful-

IADC Drilling Manual

crum of the bending force. If the pipe could bend uniformly throughout its length, stress would be lower and cycles of stress to failure higher.

Extent of fatigue damage

The amount of fatigue damage depends upon: • The tensile load in the pipe at the dogleg; • The severity of the dogleg; • The number cycles in the dogleg of each portion of the pipe; • The dimensions and properties of the pipe. Since tension in the pipe is critical, a shallow dogleg in a deep hole often becomes the source of difficulty. Further, rotating off bottom below a dogleg is not good practice because of the additional load of the drill collars. Figure DS-10 through Figure DS-12 from Hansford and Lubinski show conditions necessary for fatigue damage to occur. It is necessary to remain to the left of the fatigue curve to prevent fatigue damage. If these conditions are exceeded, a certain percentage of permanent damage will occur. The extent depends upon the number of cycles under the stressed conditions.

Cumulative fatigue

Methods are available for estimating the cumulative fatigue on joints of pipe which have been rotated through severe dog-

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DRILL STRING

DS–9

Dogleg Severity (Hole Curvature) - Degrees Per 100 Ft.

0

0

10

5

15

LB

50

0

LB

0

LB

100

LB 0 00 1

LB 00

3,0

00

LB

LB 00

2,0

2,5

1,5

00 0

LB

LB

00

00

8,

7,0

6,0

00

LB

LB

LB

6,

LB

00

00

4,0

250

5,0

0 LB

3,00 0 LB

2,00

200

1, 00 0

150 1,000 LB

Bouyant Wt. Suspended Below the Dogleg Thousands of Pounds

50

2

LEGEND Force on Tool Joints

300

Force on Drill Pipe B4-9

Figure DS-16: Lateral forces on 4 ½-in., 16.6 lb/ft Range 2 drill pipe with 6 ¼-in. tool joints.

legs. The method portrayed in Figure DS-13 and Figure DS-14 is a simple device to be used as a guide in the analysis of joints suspected of suffering fatigue damage. A correction formula to use for other penetration rates and rotary speed is: = x x It’s important to remember that such damage is permanent, even when the stress is relieved and/or the joint passes through the dogleg. Similar repetitive stresses on the joint will eventually cause failure. For example, from Figure DS-14, a tension of 70,000 lb on 3 ½-in. pipe in a 10° dogleg will expend 35% of the life of the joint. If the joint passes through this or a similar dogleg with the same rotary speed and penetration rate three times, it will fail. Three times the rotary speed or ⅓ the penetration rate will give the same effect. Similarly, drillpipe may be damaged on one hole, even though it does not fail. If it is placed near the top of the string on the same or next hole, it may or may not be able to withstand the very nominal bending stresses encountered. Thus, failures can occur later and far from the position in the string where the trouble started, or in subsequent wells.

is good practice to string-ream the dogleg area. This reduces the severity of the hole angle change. When drillpipe in a dogleg is in tension, it is pulled to the inside of the bend with substantial force. The lateral force will increase the wear of the pipe and tool joints. When abrasion is a problem, it is desirable to limit the amount of lateral force to less than about 2,000 lb on the tool joints by controlling the rate of change of hole angle. Values either smaller or greater than 2,000 lb might be in order, depending on formation at the dogleg. Figures DS-14 through DS-18, developed by Lubinski, show lateral force curves for both tool joints and drillpipe for 3 popular sizes. The first three figures are for three pipe sizes, Range 2. Figure DS-18, the last graph, is for 5-in., 19.5 lb/ft, Range 3 drillpipe. For conditions represented by points located to the left of curve No. 1, such as Point A in Figure DS-15, only tool joints, not drillpipe between tool joints, contact the wall of the hole. This should not be construed to mean the drillpipe body does not wear at all, as Figure DS-15 is for a gradual, rather than an abrupt dogleg. In an abrupt dogleg, drillpipe does contact the wall of the hole halfway between tool joints, and

If doglegs of sufficient magnitude are known or suspected, it

IADC Drilling Manual

Copyright © 2015

Figure B4-10

DS–10

DRILL STRING

Lateral forces on tool joints and range 2 drill pipe 5”, 19.5 lb per foot, range 2 drill pipe, 6 3/4” tool joints. Dog-leg Severity (Hole Curvature) - Degrees Per 100 Ft. 0

5

10

15

0

0 LB 1,00 0 LB 2,00

50

Bouyant Wt. Suspended Below the Dog-leg Thousands of Pounds

LB 00 3,0 LB 00 4,0

100

LB 00 5,0 LB 00 6,0

150

LB 00 7,0 LB 00 8,0

200

250

B 1,000 LB 1,50 0 LB 2,00 0 LB 2,50 0 LB 3,50 0 LB

500 L

300

0 LB

LEGEND

1

2

Force on Tool Joints Force on Drill Pipe B4-10

Figure DS-17: Lateral forces on 5-in., 19.5-lb/ft Range 2 drill pipe with 6 ⅜-in. tool joints.

the pipe body is subjected to wear. This lasts until the dogleg is rounded off and becomes gradual. For conditions represented by points located on Curve No. 1, theoretically the drillpipe contacts the wall of the hole with zero force at the midpoint between tool joints. For conditions represented by points located between Curve Nos. 1 and 2, theoretically the drillpipe still contacts the wall of the hole at midpoint only, but with a force which is not equal to zero. This force increases from Curve No. 1 toward Curve No. 2. Practically, of course, the contact between the drillpipe and the wall of the hole will be along a short length located near the midpoint of the joint. For conditions represented by points located to the right of Curve No. 2, the drillpipe theoretically contacts with the wall of the hole—not at one point, but along an arc with the increasing length to the right of Curve No. 2. On each of the Figures DS-15 through DS-18, there are, in addition to curves Nos. 1 and 2, two families of curves—one for the force on tool joint, the other for the force on drillpipe body. As an example, consider Figure DS-15. Point B

IADC Drilling Manual

indicates that if the buoyant weight suspended below the dogleg is 170,000 lb and if dogleg severity (hole curvature) is 10.1°/100 ft, then the force on tool joint is 6,000 lb and the force on drillpipe body is 3,000 lb. Tool joints rotated under high lateral force against the wall of the hole may be damaged as a result of friction heat checking. The heat generated at the surface of the tool joint by friction with the wall of the hole when under high radial thrust loads may raise the temperature of the tool joint steel above its critical temperature. Metallurgical examination of such joints has indicated affected zones with varying hardness as much as 3/16 in. below OD surface. If the radial thrust load is sufficiently high, surface heat checking can occur in the presence of drilling mud alternately being heated and quenched as it rotates. This action produces numerous irregular heat check cracks often accompanied by longer axial cracks and sometimes extending through the full section of the joint, and washouts may occur in the splits or windows. Maintaining hole angle control so that 2,000 lb lateral force is not exceeded will minimize or eliminate heat checking of tool joints. See Figure DS-52.

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DRILL STRING

DS–11

Dog-leg Severity (Hole Curvature) - Degrees Per 100 Ft. 0

0

5

10

15

0 LB

500 50

0 LB 1,00 LB 00 1,5 LB 00 2,0 0 LB 2,50 LB 00 3,0

100

B 5,000 L

LB 6,000 LB 7,000

0 LB 8,00

150

200

250

LEGEND

300

Force on Tool Joints

1,000 LB 2,000 LB 3,000 LB 4,000 LB

Bouyant Wt. Suspended Below the Dog-leg Thousands of Pounds

LB

Force on Drill Pipe

1

2

B4-11

Figure DS-18: Dog leg severity (hole curvature), degrees per 100 ft.

Floating drilling operations

Roll and pitch of a drilling vessel results in bending of the kelly and the first joint of drillpipe. Two major factors specific to floating drilling operations that contribute to drill-pipe fatigue are: • Rotary table is not centered at all times precisely above the subsea borehole; • Derrick is not always vertical, but follows the roll and pitch motions of the floater. This text pertains to prevention of fatigue due to the second factor above. When the derrick is inclined during a part of the roll or pitch motion, the upper extremity of the drill string is not vertical, while the drillpipe at some distance below the rotary table remains vertical. Thus, the drill string is bent. As drillpipe is much less rigid than the kelly, most of the bending occurs in the first length of drillpipe below the kelly. This subject is studied in the paper, “Effect of Drilling Vessel Pitch or Roll on Kelly and Drillpipe Fatigue,” by John E. Hansford and Arthur Lubinski1. Based on the Hansford and Lubinski paper, the following practices are recommended to minimize bending and, therefore, fatigue of the first joint of drillpipe, due to roll and/or pitch of

IADC Drilling Manual

a floater: • Multi-plane bushings should not be used. Either a gimbaled kelly bushing, or a one-plane roller bushing is preferable; • An extended-length kelly should be used in order to relieve the severe bending of the limber drillpipe through less severe bending of the rigid kelly extension. This extension may be accomplished by any of the following means: a. For Range 2 drillpipe, use a 54-ft kelly, which is ordinarily used with Range 3 pipe, rather than the usual 40-ft kelly; b. Use a specially made kelly at least 8 ft longer than the standard length; c. Use at least 8 ft of kelly saver subs between the kelly and drillpipe. • If b, above, is not implemented, avoid rotating off bottom with the kelly more than half way up for long periods of time, if the maximum angular vessel motion is more than 5° single amplitude. In this text, long periods of time are: a. More than 30 min for large hook loads; b. More than 2 hours for light hook loads. • If conditions prevent implementing b or c, above, the

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DS–12

DRILL STRING

Figure DS-19: Tongs applied to the pipe body can crush the pipe and cause failure through tong marks.

Figure DS-20: Pipe body slip marks can cause failure. The making up or breaking out of drill string without back-up tongs can also cause slippage and potentially dangerous notches. Back-up tongs should always be used.

Stress, pounds/sq in. (psi) 35,000

Air 30,000

Mildly

Corr

osive

25,000

20,000

Co

rro

siv

e

15,000

Ve

ry C

orr

osi

ve

10,000

5,000

0

1,000,000

2,000,000

3,000,000

4,000,000

Number of Cycles of Stress

Figure DS-21: Typical S/N curves for drill pipe in various media.

first joint of drillpipe below the kelly should be removed from the string at the first opportunity and discarded.

Notch Fatigue

After understanding the mechanism of fatigue failure, i.e., a progressive propagation of a minute crack, let us examine the effect of surface discontinuities upon the fatigue strength. Surface imperfections, either mechanical or metallurgical, depending upon their location, orientation, shape, and magnitude, greatly affect the fatigue limit. Aside from providing the initial distortion of the grain of steel, the notch raises the stress level

IADC Drilling Manual

.

and concentrates the breaking down of the metal structure. If a notch occurs upon a portion of the drill pipe which is not subject to stress, it will have little effect, but if located within 20 in. of the tool joint where maximum bending moments occur, it can form the nucleus of a fatigue break. A longitudinal notch is fairly harmless, but a circumferential (in the direction of applied stress) will lead to failure. A relatively extensive saucer-shaped notch with a rounded bottom will distribute the stress and be harmless. However, even a minute scratch, if sharp-bottomed, will in-

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DRILL STRING

crease stress and lead to failure. The shape of the bottom of the notch is critical. Perhaps this can be understood more readily by considering the problem of cutting a glass pane. If a new glass cutter with a sharp roller is used, a very light stroke with the cutter gives a clean break on bending the pane. If a dull cutter wheel is employed, giving a round bottom notch, the bending stress is distributed and the break will follow planes of weakness in the glass, rather than the score. As most mechanical notches contain cold-worked microstructure (with low ductility and consequent low fatigue limit), the magnitude of the notch affects the fatigue limit. Some steels are more sensitive to notches than other steels. This is referred to as notch sensitivity and is related to the ductility of the steel. Various surface conditions which can, or do, result in notch fatigue failures are: • Steel stenciling on drillpipe; • Electric arc burns; • Rubber protector grooves; • Tong marks; • Slip marks; • Formation and “junk” cuts.

DS–13

are in the direction of applied stress and seldom lead to failures. This perfectly longitudinal direction is important, as a very slight deviation from the vertical can become a stress concentration point. The application of tongs to the body of the pipe instead of to the tool joint is considered bad practice due to the possibility of crushing the pipe. See Figure DS-19.

Slip marks

Rotary table slips are made with fine serrations which ordinarily leave injurious marks on the drillpipe. However, the slips, if mistreated, worn, or carelessly handled, can score the pipe. Slips with worn, mismatched, incorrect size, or improperly installed gripping elements can allow one or two teeth or portions of teeth to catch the full load of the drill string, causing deep notching, cold work, and potential failure. See Figure DS-20. The practice of rotating drill string with the slips can, if any slippage occurs, leave a dangerous transverse notch in the drillpipe.

Crooked pipe fatigue

It’s critical not to run crooked drillpipe into the well. A crooked joint is always a potential failure. A crooked kelly can

Steel stenciling

Inasmuch as any transverse mark can be a dangerous stress concentration point, it is unsurprising that steel stencil marks can be the start of fatigue when parts of the letter are transverse to the pipe and the steel stamp is in the wrong place. No stamps should ever be made on the body of drillpipe.

Electric arc burns

Though rare, attaching a ground lead to the pipe rack instead of the material being welded does happen. This is particularly dangerous in that the subsequent arcing between the rail and the pipe goes unnoticed and the pits, though small, are surrounded by a wide band of burnt metal that is glass-hard and very prone to rapid fatigue failure.

Rubber protector grooves

A cause of notch fatigue failure is the occurrence of a circumferential groove at the top of the rubber drillpipe protectors. Modern protectors are designed to minimize this condition. This situation occurs when the rubber protectors are left in storage. The protector rubbers should be removed during the storage period.

Tong marks

Deep tong marks are probably the worst looking surface defects produced on drill string in the field. They are long, deep and frequently quite sharp. However, being longitudinal, they

IADC Drilling Manual

Figure DS-22: Drill pipe will bottleneck when pulled above its yield strength and will part when pulled to its ultimate tensile strength.

cause bending in the first joint of drillpipe below the rotary table. If the stress is high enough, failure will occur. Having a crown block off center can cause failure. This throws bending stresses in the kelly and drillpipe.

Corrosion fatigue

Corrosion fatigue, or fatigue in a corrosive environment, is probably the most common cause of drill-pipe fatigue failure. The fatigue life of drillpipe depends on the corrosiveness of the environment. As shown in Figure DS-21, drillpipe stressed at 27,500 psi in a non-corrosive environment (air) will not fail by fatigue; will have a fatigue life of 2,300,000 cycles in a mildly corrosive environment (salt water); a fa-

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DS–14

DRILL STRING

tigue life of 1,300,000 cycles in a corrosive environment (magnesium chloride solution); and a fatigue life of 500,000 cycles in a very corrosive environment (hydrochloric acid).

Critical rotating speed

Critical rotating speeds in drill string cause vibrations and are often the cause of crooked drillpipe, excessive wear, rapid deterioration, and fatigue failure. Critical speeds will vary with length and size of drill stem and collars and hole size. There is evidence in field tests that excessive power is required at the rotary to maintain a constant speed at critical conditions. This power indicator, surface evidence of vibration, or mechanical specific energy measurements should warn the crew that they are in the critical range. Various types of vibration may occur, including axial, torsional, and lateral vibration. The pipe between each tool joint may vibrate in nodes, as a violin string. Another type of vibration is of the spring pendulum type. Other types of vibrations may occur. Each vibration type has critical speeds at which they occur. Presently no generally accepted method exists to accurately predict critical rotary speeds.

Collapsed pipe from drill-stem and BOP tests

The effects of combination of hoop stress (collapse and burst) and axial stress (tension and compression) on drillpipe yield is discussed in API RP 7G, 16th ed, Section 12.

In carrying out various information tests, drillpipe is run empty in the well and set into the formation being tested before the valve at the bottom is opened. This subjects the bottom lengths to the full hydrostatic pressure of the drilling fluid and has been known to cause collapse. Worn pipe can contribute to collapse failures in drill stem testing. During BOP tests using a test string, be certain that the annulus is vented if a ram is closed beneath another closed ram or annulus. Failure to do this could result in collapsed pipe, since there is no place for the fluid being displaced by the operating rod to go.

Transition from drill string to drill collars

Frequent failure in the joints of drillpipe just above the drill collars suggests abnormally high bending stresses in these joints. When joints are moved from this location and rotated to other sections, the effect is to lose identity of these damaged joints. When these joints later fail through accumulation of additional fatigue damage, every joint in the string becomes suspect. One practice to reduce failures at the transition zone and to improve control over the damaged joints is to use 9–10 joints of heavy wall pipe, heavy weight or smaller drill collars, just above the collars. These joints are marked for identification, and used in the transition zone. They are inspected more frequently than regular drillpipe to reduce the likelihood

Example 1: Determine the stretch in a 10,000-ft string of drill pipe freely suspended in 10-lb/gal drilling fluid.

e=

L1 2 9.625 × 10 7

[ 65.44 − 1.44 Wg ]

=

10,000 2 65.44 − 1.44 Wg ] = 53.03 in 9.625 × 10 7 [

Where: L1 = Length of free drill pipe, ft Wg = Weight of drilling fluid, lb/gal e = total elongation, in.

Example 2: Determine the free length in a 10,000 ft string of 4 ½-in. OD 16.60 lb/ft drill pipe which is stuck, and which stretches 49 in. due to a differential pull of 80,000 lb.

e=

L1 2 9.625 × 10 7

Where: L1 = e = WDP = P =

[ 65.44 − 1.44 Wg ]

=

10,000 2 65.44 − 1.44 Wg ] = 53.03 in 9.625 × 10 7 [

Length of free drill pipe, ft total elongation, in. Weight of drill pipe, lb/ft Load, lb

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DRILL STRING

of service failures. The use of heavy wall pipe reduces the stress level in the joints and ensures longer life in this severe service condition.

Maximum allowable pull and rotary torque

Pure tension failures are involved while pulling on stuck drillpipe. As the pull on the pipe exceeds the yield point (minimum area yield), the metal distorts in a characteristic “necking down” of the weakest area of the pipe wall or smallest cross sectional area. The minimum yields are shown in Table DS-4. Tables DS-5, DS-7 and DS-9 show torsional and tensile data for new, premium and Class 2 drillpipe, respectively. Tables DS-6, DS-8 and DS-10 show collapse and internal pressure data for the same respective types of drillpipe. If pull is further increased to exceed the ultimate strength, the string will part. See Figure DS-22. Such failures normally occur near the top of the string which is subject to the pull plus the weight of the string. When drillpipe is stuck, the yield or ultimate strengths might be exceeded due to errors in weight indicators. Such pulls should be tempered with good judgment, proper safety factors, or recognition that an emergency exists. Tension figures in the above-mentioned tables are for new pipe and reductions in cross-sectional area based on the IADC-API used-pipe classification system. Safety factors should be applied and account taken for wear since purchase or last grading of the pipe. Unless there is an area of concentrated tension, loading damage can occur by a uniform linear yielding or stretch of the pipe and downgrading of the entire string. Closely examine the full upper part of a drill string suspected of being pulled beyond yield point determine whether lengths are correct or stretched. Compare the “before and after” length tally or check the outside diameter with calipers. Dangerous elongation can be detected readily and the damaged lengths discarded. But what is “dangerous” elongation? Unfortunately, this is difficult to define. Stretching and distortion causes work-hardening of metal with a consequent loss in ductility. Even worse, the stretch might not be as uniform as it appears. If non-uniform, this will produce an area of low ductility and reduced cross section not discernible by eye or measurement. In addition, another phenomenon has taken place which is not measurable. This is called the “Bauschinger Effect.” Simply stated, this means that steel which has been overstressed in tension has a reduced yield point in compression. Thus, a piece of stretched drillpipe will not again yield

IADC Drilling Manual

DS–15

to a tension load until the previous tension load has been exceeded, but suffers a reduced compressive yield strength. It is dangerous if such a joint is at the bottom of the drill string where compressive loading occurs. Thus, it is good practice to discard all stretched lengths, or at least to downgrade them to less severe service. Drill string torque will reduce the tensile yield. This must be considered when drilling, tripping (back reaming with top drive) and fishing, as in washover operations or working stuck pipe. Allowable pull and torque combinations for drill string may be determined with the following formula:

Qr =

J 6√3D

YM 2 – P 2 A2

Where: QT = Minimum torsional yield strength under tension, lb-ft J = Polar moment of inertia = π / 32 (D4 - d4) for tubes D = Outside diameter, in. d = Inside diameter, in. YM = Minimum unit yield strength, psi SM = Minimum unit shear strength, psi (SM = YM) P = Total load in tension, lb A = Cross-sectional area – sq in. An example of the torque which may be applied to the pipe which is stuck while imposing a tensile load is as follows: Assume: • 3 ½-in. OD, 13.30 lb. Grade E-75 drillpipe • 3 ½-in. IF tool joints • Stuck point: 4,000 ft • Tensile pull: 100,000 lb • New drillpipe Then: QT = 17,253 lb-ft For further information on allowable hookloads, torque applications, and pump pressure use, refer to Stall and Blenkarn: Allowable Hook Load and Torque Combinations for Stuck Drill Strings.

Make-up torque vs drilling torque

Use the proper thread lubricant and manufacturer’s recommended make-up torque. API RP 7G now recommends makeup torque equal to 60% of tool joint torsional yield strength. Sometimes downhole make-up occurs in spite of the use of proper thread lubricant and recommended make-up torque. Downhole make-up causes tight breaks and can result in

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DS–16

DRILL STRING

Torque in washover operations

damaged threads and sealing shoulders. The following techniques can be used to prevent downhole make-up: • Limit rotating torque to 80% of recommended makeup torque using rotary table torque limiting devices. Determine the stretch in a 10,000 ft string of drillpipe freely suspended in 10 lb/gal drilling fluid; • Increase make-up torque to 70% of tool joint torsional yield strength. Never exceed 70% of yield.

Fishing operations Pulling out stuck pipe

It is not normally considered good practice to pull on stuck drillpipe beyond the limit derived from the API-IADC Used Drill Pipe Classification System. These limits are given in Tables DS-5 through DS-10. Assume the pipe is near the minimum cross-sectional area of its class and will fail in tension under excessive loads. For example, assuming a string of 5-in., 19.5-lb/ft Grade E-75 drillpipe is stuck, the following approximate values for maximum hook load would apply: • Premium Class: 311,540 lb; • Class: 270,430 lb. The stretch caused by the weight of drillpipe suspended in a fluid should be considered, and the proper formulas for stretch when free or stuck should be used. For additional information on fishing, refer to the Special Operations Chapter of the IADC Drilling Manual, 12th edition.

Jarring

It is common during fishing, testing, coring, and other operations to run rotary jars to aid in freeing stuck assemblies. Normally the jars are run below several drill collars which act to concentrate the blow at the fish. It is necessary to take the proper stretch to produce the required blow. The momentum of the moving mass of drill collars and stretched drillpipe returning to normal causes the blow after the jar hammer is tripped. A hammer force of three to four times the excess of pull over pipe weight is possible, depending on type and size of pipe, number (weight) of drill collars, drag, jar travel, etc. This force may be large enough to damage the stuck drillpipe and should be considered when jarring operations are planned.

IADC Drilling Manual

Although little data is available, torque loads during washover operations are significant. Friction and drag on the wash pipe causes considerable torque increases on tool joints and drillpipe. Friction and drag effects must be considered when pipe is to be used in this type of service. This is particularly true in both directional wells and deep straight holes with small tolerances. The effect of torque on maximum allowable pull should be considered.

Dynamic Loading of drillpipe during tripping

• When running a string of drillpipe into or out of the hole, the pipe is subjected not to its static weight, but to a dynamic load; • The dynamic load oscillates between values which are greater and smaller than the static load, since the greater values may exceed the yield. This results in fatigue and shortening of pipe life; • Dynamic loading exceeding yield may occur only in long strings such as 10,000 ft; • Dynamic loading increases with the length of drill collar string; • In the event the smallest value of the dynamic load tries to become negative, the pipe is kicked off the slips, and the string may be dropped into the hole; • The likelihood of dynamic loading resulting in a jump off (kicking of the slips) increases as the drillpipe string becomes shorter and the collar string becomes longer; • For a long drillpipe string, such as 10,000 ft., a jump off is possible only if drillpipe, after having been pulled from the slips, is dropped to a very high velocity, such as 16 ft/sec; • Dynamic phenomena are severe only when damping is small, which may be the case in exceptional holes, in which there are no doglegs; the deviation is small; the cross-sectional area of the annulus is large; and the mud viscosity and weight are small; • In case of small damping, the running of a stand of drillpipe should not be less than 15 seconds. For a more detailed study of the phenomena the following references are given: • Arthur Lubinski, Dynamic Loading of Drillpipe During Tripping, Journal of Petroleum Technology (Aug. 1988). The paper was previously presented at the 1988 IADC/ SPE Drilling Conference, SPE/IADC 17211.

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Table DS-5: New Drill Pipe — Torsional and Tensional Data O.D.

Nom. Nom. Wt.

Torsional Data Torsional Yield Strength, ft-lb

Wall

in.

in.

2 3/8

4.85

0.19

4,763

6,033

6,668

8,574

8,891

9,526

6.65

0.28

6,250

7,917

8,751

11,251

11,668

12,501

6.85

0.217

8,083

10,238

11,316

14,549

15,087

10.4

0.362

11,554

14,635

16,176

20,798

21,568

13.3

0.368

18,551

23,498

25,972

33,393

15.5

0.449

21,086

26,709

29,520

14

0.33

23,288

29,498

15.7

0.38

25,810

32,693

15.4

0.33

26,683

17.1

0.38

16.6 20

2 7/8 3 1/2

IADC Drilling Manual

4 4 1/4 4 1/2 5

Copyright © 2015

5 1/2 5 7/8

6 5/8

lb/ft

E-75

X-95

G-105

S-135

Z-140

V-150

Tensile Data Based on Min. Values Load at Min. Yield Strength, lb U-165

X-95

G-105

S-135

Z-140

V-150

U-165

10,479

97,817

123,902

136,944

176,071

182,593

195,635

215,198

13,751

138,214

175,072

193,500

248,786

258,000

276,429

304,072

16,165

17,782

135,902

172,143

190,263

244,624

253,684

271,804

298,984

23,109

25,420

214,344

271,503

300,082

385,820

400,110

428,689

471,558

34,629

37,103

40,813

271,569

343,988

380,197

488,825

506,929

543,139

597,453

37,954

39,360

42,171

46,388

322,775

408,848

451,885

580,995

602,513

645,550

710,105

32,603

41,918

43,470

46,575

51,233

285,359

361,454

399,502

513,646

532,670

570,717

627,789

36,134

46,458

48,178

51,620

56,782

324,118

410,550

453,765

583,413

605,020

648,236

713,060

33,798

37,356

48,029

49,807

53,365

58,702

304,797

386,077

426,716

548,635

568,955

609,595

670,554

29,640

37,543

41,495

53,351

55,327

59,279

65,207

346,502

438,902

485,103

623,704

646,804

693,004

762,304

0.337

30,807

39,022

43,130

55,453

57,507

61,614

67,776

330,558

418,707

462,781

595,004

617,041

661,116

727,227

0.43

36,901

46,741

51,661

66,422

68,882

73,802

81,182

412,358

522,320

577,301

742,244

769,734

824,715

907,187

–

0.3

35,431

44,880

49,604

63,776

66,139

70,863

77,949

332,223

420,816

465,113

598,002

620,150

664,447

730,892

19.5

0.362

41,167

52,144

57,633

74,100

76,844

82,333

90,567

395,595

501,087

553,833

712,070

738,443

791,189

870,308

25.6

0.5

52,257

66,192

73,160

94,062

97,546

104,514

114,965

530,144

671,515

742,201

954,259

989,602

1,060,288

1,166,316

21.9

0.361

50,710

64,233

70,994

91,278

94,659

101,420

111,562

437,116

553,681

611,963

786,809

815,950

874,233

961,656

24.7

0.415

56,574

71,661

79,204

101,834

105,605

113,148

124,463

497,222

629,814

696,111

894,999

928,147

994,444

1,093,888

–

0.32

53,065

67,216

74,291

95,517

99,055

106,131

116,744

418,837

530,527

586,372

753,907

781,829

837,674

921,442

23.4

0.361

58,605

74,233

82,047

105,489

109,396

117,210

128,931

469,013

594,083

656,619

844,224

875,491

938,026

1,031,829

26.3

0.415

65,508

82,977

91,712

117,915

122,282

131,017

144,119

533,890

676,261

747,446

961,002

996,595

1,067,780

1,174,558

25.2

0.33

70,580

89,402

98,813

127,045

131,750

141,161

155,277

489,464

619,988

685,250

881,035

913,666

978,928

1,076,821

27.7

0.362

76,295

96,640

106,813

137,331

142,417

152,590

167,849

534,198

676,651

747,877

961,556

997,169

1,068,396

1,175,235

–

0.5

98,893

125,264

138,450

178,007

184,600

197,785

217,564

721,585

914,007

1,010,218

1,298,852

1,346,958

1,443,169

1,587,486

–

0.522

102,202 129,455

143,082

183,963

190,776

204,403

224,843

750,628

950,796

1,050,880

1,351,131

1,401,173

1,501,257

1,651,383

–

0.625

116,684 147,800

163,358

210,032

217,811

233,368

256,705

883,573

1,119,192

1,237,002

1,590,431

1,649,336

1,767,146

1,943,860

–

0.75

132,159 167,401

185,023

237,886

246,697

264,318

290,750

1,038,198

1,315,051

1,453,477

1,868,757

1,937,970

2,076,396

2,284,036

–

0.813

139,147 176,253

194,806

250,465

259,741

278,294

306,124

1,113,339

1,410,229

1,558,674

2,004,010

2,078,232

2,226,677

2,449,345

DRILL STRING

E-75

DS–17

DS–18

O.D.

Nom. Nom. Wt.

in.

in.

2 3/8

4.85 6.65

IADC Drilling Manual

2 7/8 3 1/2 4 4 1/4

Copyright © 2015

4 1/2 5

5 1/2 5 7/8

6 5/8

Collapse Pressure Based On Minimum Values, psi

Wall lb/ft

V-150

Internal Pressure At Minimum Yield Strength, psi

E-75

X-95

G-105

S-135

Z-140

U-165

E-75

X-95

G-105

S-135

Z-140

V-150

U-165

0.19

11,040

13,984

15,456

19,035

19,588

20,661

22,182

10,500

13,300

14,700

18,900

19,600

21,000

23,100

0.28

15,599

19,759

21,839

28,079

29,119

31,199

34,319

15,474

19,600

21,663

27,853

28,884

30,947

34,042

6.85

0.217

10,467

12,940

14,020

17,034

17,500

18,398

19,650

9,907

12,548

13,869

17,832

18,492

19,813

21,794

10.4

0.362

16,509

20,911

23,112

29,716

30,817

33,018

36,319

16,526

20,933

23,137

29,747

30,849

33,052

36,357

13.3

0.368

14,113

17,877

19,758

25,404

26,345

28,226

31,049

13,800

17,480

19,320

24,840

25,760

27,600

30,360

15.5

0.449

16,774

21,247

23,484

30,194

31,312

33,549

36,903

16,838

21,328

23,573

30,308

31,430

33,675

37,043

14

0.33

11,354

14,382

15,896

20,141

20,742

21,912

23,581

10,828

13,716

15,159

19,491

20,213

21,656

23,822

15.7

0.38

12,896

16,335

18,055

23,213

24,073

25,793

28,372

12,469

15,794

17,456

22,444

23,275

24,938

27,431

15.4

0.33

10,743

13,583

14,740

17,994

18,501

19,483

20,864

10,191

12,909

14,268

18,344

19,024

20,382

22,421

17.1

0.38

12,213

15,469

17,098

21,983

22,797

24,425

26,868

11,735

14,865

16,429

21,124

21,906

23,471

25,818

16.6

0.337

10,392

12,765

13,825

16,773

17,228

18,103

19,320

9,829

12,450

13,761

17,693

18,348

19,658

21,624

20

0.43

12,964

16,421

18,149

23,335

24,199

25,927

28,520

12,542

15,886

17,558

22,575

23,411

25,083

27,592

–

0.3

7,122

8,346

8,882

10,185

10,355

10,652

10,982

7,875

9,975

11,025

14,175

14,700

15,750

17,325

19.5

0.362

9,962

12,026

12,999

15,672

16,079

16,858

17,926

9,503

12,037

13,304

17,105

17,738

19,005

20,906

25.6

0.5

13,500

17,100

18,900

24,300

25,200

27,000

29,700

13,125

16,625

18,375

23,625

24,500

26,250

28,875

21.9

0.361

8,413

10,019

10,753

12,679

12,957

13,473

14,139

8,615

10,912

12,061

15,507

16,081

17,230

18,953

24.7

0.415

10,464

12,933

14,013

17,023

17,489

18,386

19,636

9,903

12,544

13,865

17,826

18,486

19,807

21,788

–

0.32

5,855

6,704

7,046

7,737

7,801

7,884

8,094

7,149

9,055

10,009

12,868

13,345

14,298

15,728

23.4

0.361

7,453

8,775

9,362

10,825

11,023

11,376

11,793

8,065

10,216

11,291

14,517

15,054

16,130

17,743

26.3

0.415

9,558

11,503

12,414

14,892

15,266

15,976

16,939

9,271

11,744

12,980

16,688

17,306

18,543

20,397

25.2

0.33

4,788

5,321

5,500

6,036

6,121

6,260

6,391

6,538

8,281

9,153

11,768

12,204

13,075

14,383

27.7

0.362

5,894

6,755

7,103

7,813

7,881

7,970

8,157

7,172

9,084

10,040

12,909

13,387

14,343

15,778

–

0.5

10,466

12,938

14,018

17,031

17,497

18,395

19,646

9,906

12,547

13,868

17,830

18,491

19,811

21,792

–

0.522

10,888

13,791

15,121

18,500

19,030

20,057

21,505

10,342

13,099

14,478

18,615

19,304

20,683

22,751

–

0.625

12,816

16,234

17,942

23,069

23,923

25,632

28,195

12,382

15,684

17,335

22,288

23,113

24,764

27,241

–

0.75

15,059

19,074

21,082

27,106

28,110

30,117

33,129

14,858

18,821

20,802

26,745

27,736

29,717

32,689

–

0.813

16,149

20,455

22,608

29,068

30,144

32,297

35,527

16,107

20,402

22,549

28,992

30,066

32,213

35,435

DRILL STRING

Table DS-6: New Drill Pipe — Collapse, and Internal Pressure Data

TableDS-7: Premium Drill Pipe — Torsional and Tensional Data O.D.

Nom. Nom. Wt.

Torsional Data Torsional Yield Strength, ft-lb

Wall

in.

in.

2 3/8

4.85

0.19

3,725

4,719

5,215

6,705

6,954

7,450

8,195

76,893

6.65

0.28

4,811

6,093

6,735

8,659

8,980

9,621

10,583

107,616

6.85

0.217

6,332

8,020

8,865

11,397

11,819

12,664

13,930

10.4

0.362

8,858

11,220

12,401

15,945

16,535

17,716

19,488

13.3

0.368

14,361

18,191

20,106

25,850

26,808

28,723

15.5

0.449

16,146

20,452

22,605

29,063

30,140

14

0.33

18,196

23,048

25,474

32,753

15.7

0.38

20,067

25,418

28,094

36,120

15.4

0.33

20,886

26,456

29,241

17.1

0.38

23,097

29,256

16.6

0.337

24,139

20

0.43

28,684

–

0.3

19.5

2 7/8 3 1/2

IADC Drilling Manual

4 4 1/4 4 1/2 5

Copyright © 2015

5 1/2 5 7/8

6 5/8

lb/ft

E-75

X-95

G-105

S-135

Z-140

V-150

Tensile Data Based on Min. Values Load at Min. Yield Strength, lb U-165

E-75

X-95

S-135

Z-140

V-150

U-165

97,398

107,650

138,407

143,534

153,786

169,165

136,313

150,662

193,709

200,883

215,232

236,755

106,946

135,465

149,725

192,503

199,633

213,893

235,282

166,535

210,945

233,149

299,764

310,866

333,071

366,378

31,595

212,150

268,723

297,010

381,870

396,014

424,300

466,730

32,292

35,522

250,620

317,452

350,868

451,115

467,823

501,239

551,363

33,966

36,392

40,031

224,182

283,963

313,854

403,527

418,472

448,363

493,199

37,458

40,134

44,147

253,851

321,544

355,391

456,931

473,855

507,701

558,472

37,595

38,988

41,773

45,950

239,732

303,661

335,625

431,518

447,501

479,465

527,411

32,335

41,574

43,114

46,193

50,813

271,758

344,227

380,461

489,164

507,281

543,516

597,867

30,576

33,795

43,451

45,060

48,278

53,106

260,165

329,542

364,231

468,297

485,641

520,330

572,363

36,332

40,157

51,630

53,543

57,367

63,104

322,916

409,026

452,082

581,248

602,776

645,831

710,414

27,905

35,346

39,067

50,229

52,089

55,810

61,391

262,386

332,355

367,340

472,294

489,787

524,772

577,249

0.362

32,285

40,895

45,200

58,114

60,266

64,571

71,028

311,536

394,612

436,150

560,764

581,533

623,071

685,378

25.6

0.5

40,544

51,356

56,762

72,980

75,682

81,088

89,197

414,690

525,274

580,566

746,442

774,088

829,380

912,319

21.9

0.361

39,864

50,494

55,809

71,754

74,412

79,727

87,700

344,780

436,721

482,692

620,604

643,589

689,560

758,516

24.7

0.415

44,320

56,139

62,048

79,776

82,731

88,641

97,505

391,285

495,627

547,799

704,313

730,398

782,569

860,826

–

0.32

41,867

53,032

58,614

75,361

78,152

83,734

92,108

331,209

419,532

463,693

596,177

618,257

662,419

728,660

23.4

0.361

46,134

58,437

64,588

83,042

86,117

92,269

101,495

370,298

469,044

518,417

666,536

691,222

740,595

814,655

26.3

0.415

51,408

65,116

71,971

92,534

95,961

102,815

113,097

420,619

532,785

588,867

757,115

785,156

841,239

925,363

25.2

0.33

55,766

70,637

78,073

100,379

104,097

111,532

122,685

387,466

490,790

542,452

697,438

723,270

774,932

852,425

27.7

0.362

60,191

76,243

84,268

108,345

112,357

120,383

132,421

422,418

535,063

591,385

760,352

788,514

844,836

929,320

–

0.5

77,472

98,131

108,461

139,450

144,615

154,944

170,439

567,843

719,268

794,980

1,022,117

1,059,973

1,135,686

1,249,254

–

0.522

79,967

101,291

111,953

143,940

149,271

159,933

175,927

590,230

747,625

826,322

1,062,415

1,101,763

1,180,461

1,298,507

–

0.625

90,745

114,944

127,044

163,342

169,392

181,491

199,640

692,132

876,701

968,985

1,245,838

1,291,980

1,384,264

1,522,691

–

0.75

101,939 129,122

142,714

183,489

190,285

203,877

224,265

809,353

1,025,180

1,133,094

1,456,835

1,510,792

1,618,706

1,780,576

–

0.813

106,846 135,338

149,584

192,322

199,445

213,691

235,060

865,753

1,096,620

1,212,054

1,558,355

1,616,072

1,731,506

1,904,657

DRILL STRING

G-105

Data based on 20% uniform wear on outside diameter.

DS–19

DS–20

Table DS-8: Premium Drill Pipe — Collapse, and Internal Pressure Data Nom. Nom. Wt.

in.

in.

2 3/8

4.85 6.65

2 7/8

IADC Drilling Manual

3 1/2 4 4 1/4 4 1/2

Copyright © 2015

5

5 1/2 5 7/8

6 5/8

Collapse Pressure Based On Minimum Values, psi

Wall lb/ft

V-150

Internal Pressure At Minimum Yield Strength, psi

E-75

X-95

G-105

S-135

Z-140

U-165

E-75

X-95

G-105

S-135

Z-140

V-150

U-165

0.19

8,522

10,161

10,912

12,891

13,178

13,713

14,407

9,600

12,160

13,440

17,280

17,920

19,200

23,100

0.28

13,378

16,945

18,729

24,080

24,972

26,756

29,431

14,147

17,920

19,806

25,465

26,408

28,295

34,042

6.85

0.217

7,640

9,017

9,633

11,186

11,399

11,784

12,249

9,057

11,473

12,680

16,303

16,907

18,115

21,794

10.4

0.362

14,223

18,016

19,912

25,602

26,550

28,446

31,291

15,110

19,139

21,153

27,197

28,205

30,219

36,357

13.3

0.368

12,015

15,218

16,820

21,626

22,427

24,029

26,432

12,617

15,982

17,664

22,711

23,552

25,234

30,360

15.5

0.449

14,472

18,331

20,260

26,049

27,014

28,943

31,837

15,394

19,499

21,552

27,710

28,736

30,789

37,043

14

0.33

9,012

10,795

11,622

13,836

14,164

14,782

15,603

9,900

12,540

13,860

17,820

18,480

19,800

23,822

15.7

0.38

10,914

13,825

15,190

18,593

19,127

20,162

21,623

11,400

14,440

15,960

20,520

21,280

22,800

27,431

15.4

0.33

8,063

9,565

10,246

12,003

12,252

12,708

13,283

9,318

11,802

13,045

16,772

17,393

18,635

22,421

17.1

0.38

10,302

12,555

13,590

16,461

16,902

17,750

18,924

10,729

13,591

15,021

19,313

20,028

21,459

25,818

16.6

0.337

7,525

8,868

9,467

10,964

11,168

11,533

11,969

8,987

11,383

12,581

16,176

16,775

17,973

21,624

20

0.43

10,975

13,901

15,350

18,806

19,349

20,402

21,892

11,467

14,524

16,053

20,640

21,404

22,933

27,592

–

0.3

4,644

5,134

5,290

5,854

5,931

6,054

6,160

7,200

9,120

10,080

12,960

13,440

14,400

17,325

19.5

0.362

7,041

8,241

8,765

10,029

10,192

10,476

10,785

8,688

11,005

12,163

15,638

16,218

17,376

20,906

25.6

0.5

11,458

14,514

16,042

20,510

21,126

22,329

24,048

12,000

15,200

16,800

21,600

22,400

24,000

28,875

21.9

0.361

5,730

6,542

6,865

7,496

7,550

7,612

7,895

7,876

9,977

11,027

14,177

14,703

15,753

18,953

24.7

0.415

7,635

9,011

9,626

11,177

11,390

11,774

12,238

9,055

11,469

12,676

16,298

16,902

18,109

21,788

–

0.32

3,582

4,001

4,191

4,520

4,538

4,546

4,546

6,536

8,279

9,151

11,765

12,201

13,072

15,728

23.4

0.361

4,922

5,495

5,694

6,204

6,296

6,450

6,605

7,374

9,340

10,323

13,273

13,764

14,747

17,743

26.3

0.415

6,699

7,798

8,269

9,368

9,503

9,728

9,949

8,477

10,737

11,867

15,258

15,823

16,953

20,397

25.2

0.33

2,931

3,252

3,353

3,429

3,429

3,429

3,429

5,977

7,571

8,368

10,759

11,158

11,955

14,383

27.7

0.362

3,615

4,029

4,222

4,562

4,582

4,592

4,592

6,557

8,306

9,180

11,803

12,240

13,114

15,778

–

0.5

7,639

9,015

9,631

11,183

11,397

11,781

12,246

9,057

11,472

12,679

16,302

16,906

18,113

21,792

–

0.522

8,286

9,855

10,570

12,435

12,702

13,197

13,830

9,455

11,976

13,237

17,019

17,650

18,910

22,751

–

0.625

10,842

13,733

15,001

18,341

18,863

19,876

21,303

11,321

14,340

15,849

20,377

21,132

22,642

27,241

–

0.75

12,879

16,314

18,031

23,183

24,042

25,759

28,335

13,585

17,208

19,019

24,453

25,358

27,170

32,689

–

0.813

13,887

17,591

19,442

24,997

25,923

27,775

30,552

14,726

18,653

20,616

26,507

27,489

29,452

35,435

Data based on 20% uniform wear on outside diameter.

DRILL STRING

O.D.

Table DS-9: Class 2 Drill Pipe — Torsional and Tensional Data O.D.

Nom. Nom. Wt.

Torsional Data Torsional Yield Strength, ft-lb

Wall

in.

in.

2-3/8

4.85

0.19

3,224

4,083

4,513

5,802

6,017

6,447

7,092

66,686

84,469

6.65

0.28

4,130

5,232

5,782

7,434

7,710

8,260

9,086

92,871

117,636

6.85

0.217

5,484

6,946

7,677

9,871

10,236

10,967

12,064

92,801

10.4

0.362

7,591

9,615

10,627

13,663

14,169

15,181

16,699

143,557

13.3

0.368

12,365

15,663

17,312

22,258

23,082

24,731

27,204

15.5

0.449

13,828

17,515

19,359

24,890

25,812

27,655

14

0.33

15,738

19,935

22,034

28,329

29,378

15.7

0.38

17,315

21,932

24,241

31,167

32,321

15.4

0.33

18,082

22,903

25,314

32,547

17.1

0.38

19,951

25,271

27,932

16.6

0.337

20,908

26,483

20

0.43

24,747

31,346

–

0.3

24,230

19.5

0.362

25.6 21.9

2-7/8 3-1/2

IADC Drilling Manual

4 4 1/4 4-1/2 5

Copyright © 2015

5-1/2 5-7/8

6-5/8

lb/ft

E-75

X-95

G-105

S-135

Z-140

V-150

Tensile Data Based on Min. Values Load at Min. Yield Strength, lb U-165

E-75

X-95

G-105

Z-140

V-150

U-165

93,360

120,035

124,480

133,372

146,709

130,019

167,167

173,359

185,742

204,316

117,548

129,922

167,043

173,229

185,603

204,163

181,839

200,980

258,403

267,973

287,114

315,825

183,398

232,304

256,757

330,116

342,342

366,795

403,475

30,421

215,967

273,558

302,354

388,741

403,139

431,934

475,128

31,477

34,624

194,363

246,193

272,108

349,853

362,810

388,725

427,598

34,629

38,092

219,738

278,334

307,633

395,528

410,177

439,476

483,423

33,752

36,163

39,779

207,970

263,428

291,158

374,346

388,210

415,939

457,533

35,912

37,242

39,902

43,892

235,406

298,182

329,569

423,732

439,425

470,813

517,894

29,271

37,634

39,028

41,816

45,997

225,771

285,977

316,080

406,388

421,439

451,542

496,696

34,645

44,544

46,194

49,494

54,443

279,501

354,035

391,302

503,103

521,736

559,003

614,903

30,691

33,922

43,614

45,229

48,460

53,306

228,103

288,931

319,344

410,586

425,793

456,206

501,827

27,976

35,436

39,166

50,356

52,221

55,951

61,547

270,432

342,547

378,605

486,778

504,807

540,864

594,951

0.5

34,948

44,267

48,927

62,906

65,236

69,895

76,885

358,731

454,392

502,223

645,715

669,630

717,461

789,207

0.361

34,582

43,804

48,415

62,247

64,553

69,164

76,080

299,533

379,409

419,346

539,160

559,128

599,066

658,973

24.7

0.415

38,384

48,619

53,737

69,090

71,649

76,767

84,444

339,534

430,076

475,347

611,160

633,796

679,067

746,974

–

0.32

36,385

46,087

50,938

65,492

67,918

72,769

80,046

288,119

364,951

403,367

518,615

537,823

576,238

633,862

23.4

0.361

40,049

50,729

56,069

72,088

74,758

80,098

88,108

321,861

407,691

450,605

579,350

600,807

643,722

708,094

26.3

0.415

44,559

56,441

62,382

80,206

83,177

89,118

98,030

365,201

462,588

511,282

657,362

681,709

730,403

803,443

25.2

0.33

48,497

61,430

67,896

87,295

90,528

96,995

106,694

337,236

427,166

472,131

607,026

629,508

674,473

741,920

27.7

0.362

52,308

66,257

73,231

94,154

97,641

104,616

115,077

367,454

465,442

514,436

661,418

685,915

734,909

808,400

–

0.5

67,094

84,986

93,932

120,770

125,243

134,189

147,608

492,739

624,136

689,835

886,931

919,780

985,478

1,084,026

–

0.522

69,214

87,671

96,899

124,585

129,199

138,427

152,270

511,957

648,479

716,740

921,523

955,654

1,023,915

1,126,306

–

0.625

78,310

99,193

109,634

140,958

146,179

156,620

172,282

599,173

758,952

838,842

1,078,511

1,118,456

1,198,346

1,318,180

–

0.75

87,615

110,979

122,661

157,707

163,548

175,230

192,753

698,906

885,281

978,469

1,258,031

1,304,625

1,397,812

1,537,594

–

0.813

91,628

116,063

128,280

164,931

171,040

183,257

201,582

746,632

945,734

1,045,285

1,343,938

1,393,714

1,493,265

1,642,591

DRILL STRING

S-135

Data based on 30% uniform wear on outside diameter.

DS–21

DS–22

Table DS-10: Class 2 Drill Pipe — Collapse, and Internal Pressure Data Nom. Nom. Wt.

in. 2 3/8 2 7/8

IADC Drilling Manual

3 1/2 4 4 1/4 4 1/2

Copyright © 2015

5

5 1/2 5 7/8

6 5/8

in.

Collapse Pressure Based On Minimum Values, psi

Wall lb/ft

E-75

X-95

G-105

S-135

Z-140

V-150

Internal Pressure At Minimum Yield Strength, psi U-165

E-75

X-95

G-105

S-135

Z-140

V-150

U-165

4.85

0.19

6,852

7,996

8,491

9,664

9,812

10,063

10,324

8,400

10,640

11,760

15,120

15,680

16,800

18,480

6.65

0.28

12,138

15,375

16,993

21,849

22,658

24,276

26,704

12,379

15,680

17,331

22,282

23,107

24,758

27,234

6.85

0.217

6,055

6,963

7,335

8,123

8,204

8,320

8,413

7,925

10,039

11,095

14,265

14,794

15,850

17,435

10.4

0.362

12,938

16,388

18,113

23,288

24,151

25,876

28,463

13,221

16,746

18,509

23,798

24,679

26,442

29,086

13.3

0.368

10,858

13,753

15,042

18,396

18,921

19,938

21,373

11,040

13,984

15,456

19,872

20,608

22,080

24,288

15.5

0.449

13,174

16,686

18,443

23,712

24,591

26,347

28,982

13,470

17,062

18,858

24,246

25,144

26,940

29,634 19,058

14

0.33

7,295

8,570

9,134

10,520

10,704

11,031

11,407

8,663

10,973

12,128

15,593

16,170

17,325

15.7

0.38

9,531

11,468

12,374

14,840

15,211

15,917

16,873

9,975

12,635

13,965

17,955

18,620

19,950

21,945

15.4

0.33

6,437

7,458

7,889

8,861

8,974

9,155

9,308

8,153

10,327

11,414

14,675

15,219

16,306

17,936

17.1

0.38

8,527

10,167

10,919

12,900

13,188

13,723

14,418

9,388

11,892

13,144

16,899

17,525

18,776

20,654

16.6

0.337

5,951

6,828

7,185

7,923

7,995

8,094

8,248

7,863

9,960

11,009

14,154

14,678

15,727

17,299

20

0.43

9,631

11,598

12,520

15,033

15,413

16,135

17,118

10,033

12,709

14,047

18,060

18,729

20,067

22,073

–

0.3

3,365

3,812

3,980

4,239

4,245

4,245

4,245

6,300

7,980

8,820

11,340

11,760

12,600

13,860

19.5

0.362

5,514

6,262

6,552

7,079

7,115

7,293

7,550

7,602

9,629

10,643

13,684

14,190

15,204

16,724

25.6

0.5

10,338

12,640

13,685

16,587

17,034

17,893

19,084

10,500

13,300

14,700

18,900

19,600

21,000

23,100

21.9

0.361

4,334

4,733

4,899

5,465

5,525

5,613

5,666

6,892

8,730

9,649

12,405

12,865

13,784

15,162

24.7

0.415

6,050

6,957

7,329

8,115

8,196

8,311

8,407

7,923

10,035

11,092

14,261

14,789

15,845

17,430

–

0.32

2,745

3,012

3,085

3,116

3,116

3,116

3,116

5,719

7,244

8,007

10,294

10,676

11,438

12,582

23.4

0.361

3,608

4,023

4,215

4,553

4,572

4,582

4,582

6,452

8,172

9,033

11,613

12,044

12,904

14,194

26.3

0.415

5,206

5,863

6,105

6,561

6,669

6,854

7,058

7,417

9,395

10,384

13,351

13,845

14,834

16,317

25.2

0.33

2,227

2,343

2,346

2,346

2,346

2,346

2,346

5,230

6,625

7,322

9,414

9,763

10,460

11,506

27.7

0.362

2,765

3,037

3,113

3,148

3,148

3,148

3,148

5,737

7,267

8,032

10,327

10,710

11,475

12,622

–

0.5

6,053

6,961

7,334

8,121

8,202

8,318

8,411

7,925

10,038

11,094

14,264

14,792

15,849

17,434

–

0.522

6,639

7,720

8,182

9,252

9,381

9,597

9,802

8,273

10,479

11,582

14,892

15,443

16,546

18,201

–

0.625

9,412

11,314

12,202

14,610

14,971

15,656

16,582

9,906

12,547

13,868

17,830

18,491

19,811

21,792

–

0.75

11,669

14,780

16,336

21,004

21,782

23,173

24,993

11,887

15,057

16,642

21,396

22,189

23,774

26,151

–

0.813

12,620

15,985

17,667

22,715

23,557

25,239

27,763

12,885

16,321

18,039

23,194

24,053

25,771

28,348

Data based on 30% uniform wear on outside diameter.

DRILL STRING

O.D.

DRILL STRING

DS–23

Table DS-11: Dimensional data—rotary shouldered connections. 1

2

3

4

5

6

7

8

Size OD

Nominal Weight Threads & Couplings

Plain End Weight*

Wall Thickness

ID

Section Area Body of Pipe**

Polar Sectional Modulus ***

Sectional Modulus

in.

lb/ft

lb/ft

in.

in.

sq in.

cu in.

cu in.

d

A

Z

I/C

D 2 3/8

4.85

4.43

0.190

1.995

1.3042

1.321

0.66

6.65

6.26

0.280

1.815

1.8429

1.733

0.87

6.85

6.16

0.217

2.441

1.8120

2.241

1.12

10.40

9.72

0.362

2.151

2.8579

3.204

1.60

3 1/2

13.30

12.31

0.368

2.764

3.6209

5.144

2.57

15.50

14.63

0.449

2.602

4.3037

5.847

2.92

4

14.00

12.93

0.330

3.340

3.8048

6.458

3.23

15.70

14.69

0.380

3.240

4.3216

7.157

3.58

15.40

13.82

0.330

3.590

4.0640

7.399

3.70

17.10

15.71

0.380

3.490

4.6200

8.219

4.11

16.25

15.06

0.300

4.400

4.4296

9.825

4.91

19.50

17.93

0.362

4.276

5.2746

11.415

5.71

25.60

24.03

0.500

4.000

7.0686

14.491

7.25

21.90

19.81

0.361

4.778

5.8282

14.062

7.03

24.70

22.54

0.415

4.670

6.6296

15.688

7.84

2 7/8

4 1/4 5

5 1/2 5 7/8

6 5/8

–

18.99

0.320

5.235

5.5845

14.715

7.36

23.40

21.26

0.361

5.153

6.2535

16.251

8.13

26.30

24.20

0.415

5.045

7.1185

18.165

9.08

25.20

22.19

0.330

5.965

6.5262

19.572

9.79

27.70

24.21

0.362

5.901

7.1226

21.156

10.58

* lb/ ft = 3.3996 x A (col. 6) ** A = π / 4 x (D2 - d2) *** Z = π / 16 x (D4 - d4) / D NOTE: Table is based on API RP7G, 16th ed, Table 1

IADC Drilling Manual

Copyright © 2015

DS–24

DRILL STRING

Table DS-12: Dimensional data—rotary shouldered connections. Size

Type

O.D.

I.D.

Pitch dia.

2 3/8

PAC SH NC23 REG. SL H90 OH LW OH SW WO NC26 PAC SH REG. OH LW OH SW SL H90 XH WO NC31 FH PAC SH REG. XH SL H90 OH LW OH SW FH NC38 WO H90 NC35 SH NC40 H90 OH LW OH SW NC44 NC46 WO SH REG. FH NC46 H90 OH LW OH SW NC50 WO H90 XH H90 REG. FH NC56 IF REG H90 NC61 FH IF H90 REG NC70 H90 REG NC77 H90

D 2 7/8 2 7/8 3 1/8 3 1/8 3 1/4 3 1/8 3 1/4 3 1/8 3 3/8 3 1/8 3 3/8 3 3/4 3 3/4 3 7/8 4 1/8 4 1/4 4 1/8 4 1/8 4 1/4 3 3/4 4 1/8 4 1/4 4 3/4 4 3/4 4 1/2 4 3/4 4 5/8 4 3/4 4 3/4 5 1/4 4 3/4 4 5/8 5 1/4 5 1/2 5 1/4 5 1/2 6 6 1/4 5 3/4 5 5 1/2 6 6 1/4 6 5 5/8 5 7/8 6 3/8 6 1/8 – 6 5/8 – 6 3/4 7 7 7 3/8 7 3/4 – 8 1/4 8 8 1/2 – 8 7/8 9 1/2 – 10 10 –

d 1 3/8 1 1/4 1 1/4 1 1 13/16 2 1 3/4 2 1 3/4 1 1/2 1 3/4 1 1/4 2 7/16 2 5/32 2.151 1 7/8 2 7/16 2 1/8 2 1/8 2 2 1/8 1 1/2 2 7/16 2 11/16 3 2 11/16 2 7/16 2 11/16 3 2 3/4 2 11/16 2 9/16 2 13/16 2 13/16 3 15/32 3 1/4 2 1/4 3 1/4 3 7/16 2 11/16 2 1/4 3 3 1/4 3 1/4 3 31/32 3 3/4 3 3/4 3 7/8 – 3 3/4 – 2 3/4 4 3 3/4 4 13/16 3 1/2 – 3 5 5 29/32 – 4 3 – 4 3/4 3 –

C 2.203 2.230 2.355 2.365 2.578 2.588 2.588 2.605 2.668 2.369 2.668 2.740 2.984 2.984 3.049 3.119 3.121 3.183 3.365 2.884 3.183 3.240 3.604 3.688 3.728 3.728 3.734 3.808 3.808 3.929 3.531 3.604 4.072 4.304 4.416 4.416 4.417 4.626 4.626 3.808 4.365 4.532 4.626 4.638 4.752 4.752 5.042 5.042 4.908 5.042 5.179 5.234 5.591 5.616 6.189 5.758 5.804 6.178 6.520 7.251 6.252 6.715 7.053 7.141 7.667 7.741 8.016

2 7/8

3 1/2

4

4 1/2

5 5 1/2

6 5/8

7 7 5/8 8 5/8

Thds/ Taper in. 4 4 4 5 3 4 4 4 4 4 4 5 4 4 3 4 4 4 5 4 4 5 4 3 4 4 5 4 4 3 1/2 4 4 4 3 1/2 4 4 4 4 4 4 5 5 4 3 1/2 4 4 4 4 3 1/2 4 3 1/2 4 4 4 4 4 3 1/2 4 4 4 3 1/2 4 4 3 1/2 4 4 3 1/2

1 1/2 2 2 3 1 1/4 1 1/2 1 1/2 2 2 1 1/2 2 3 1 1/2 1 1/2 1 1/4 2 2 2 3 1 1/2 2 3 2 1 1/4 1 1/2 1 1/2 3 2 2 2 2 2 2 2 1 1/2 1 1/2 2 2 2 2 3 3 2 2 1 1/2 1 1/2 2 2 2 2 2 3 2 3 2 2 2 3 2 2 3 3 3 3 3 3 3

Form V-076 V-038R V-038R V-040 90-V-084 V-076 V-076 V-038R V-038R V-076 V-038R V-040 V-076 V-076 90-V-084 V-038R V-038R V-038R V-040 V-076 V-038R V-040 V-038R 90-V-084 V-076 V-076 V-040 V-038R V-038R 90-V-050 V-038R V-038R V-038R 90-V-050 V-076 V-076 V-038R V-038R V-038R V-038R V-040 V-040 V-038R 90-V-050 V-076 V-076 V-038R V-038R 90-V-050 V-038R 90-V-050 V-050 V-050 V-038R V-038R V-050 90-V-050 V-038R V-050 V-038R 90-V-050 V-050 V-038R 90-V-050 V-050 V-038R 90-V-050

Bevel dia.1 D R 2 45/64 2 25/32 3 3 1/64 3 1/8 3 3 9/64 3 1/16 3 17/64 3 3 17/64 3 17/64 3 39/64 3 39/64 3 29/32 4 1/32 3 5/8 3 61/64 4 7/64 3 19/32 3 61/64 4 5/64 4 17/32 4 7/16 4 23/64 4 23/64 4 31/64 4 17/64 4 37/64 4 63/64 4 33/64 4 13/32 5 1/64 5 17/64 5 3/16 5 9/32 5 11/16 5 17/32 5 17/32 4 37/64 5 19/64 5 17/32 5 23/32 5 23/32 5 1/2 5 9/16 5 19/64 6 1/16 – 6 1/16 – 6 15/32 6 23/32 6 47/64 7 9/64 7 21/64 – 7 13/16 7 45/64 8 1/4 – 8 7/16 8 31/32 – 9 33/64 9 11/32 –

Ctbr Ctbr dia. depth box Q C L QC 2 13/32 3/8 2 1/2 5/8 2 5/8 5/8 2 11/16 5/8 2 49/64 5/8 2 51/64 5/8 2 51/64 5/8 2 55/64 5/8 2 15/16 5/8 2 37/64 3/8 2 15/16 5/8 3 1/16 5/8 3 13/64 5/8 3 13/64 5/8 3 15/64 5/8 3 23/64 5/8 3 3/8 5/8 3 29/64 5/8 3 11/16 5/8 3 7/64 3/8 3 29/64 5/8 3 9/16 5/8 3 7/8 5/8 3 7/8 5/8 3 61/64 5/8 3 61/64 5/8 4 3/64 5/8 4 5/64 5/8 4 5/64 5/8 4 3/16 5/8 3 13/16 5/8 3 7/8 5/8 4 11/32 5/8 4 9/16 5/8 4 41/64 5/8 4 41/64 5/8 4 11/16 5/8 4 29/32 5/8 4 29/32 5/8 4 5/64 5/8 4 11/16 5/8 4 7/8 5/8 4 29/32 5/8 4 57/64 5/8 4 61/64 5/8 4 61/64 5/8 5 5/16 5/8 5 5/16 5/8 5 11/64 5/8 5 5/16 5/8 5 7/16 5/8 5 37/64 5/8 5 29/32 5/8 5 15/16 5/8 6 29/64 5/8 6 1/16 5/8 6 1/16 5/8 6 1/2 5/8 6 27/32 5/8 7 33/64 5/8 6 9/16 5/8 7 3/32 5/8 7 3/8 5/8 7 29/64 5/8 8 3/64 5/8 8 1/16 5/8 8 21/64 5/8

1

The bevel diameters on drill stem members may vary. The length of perfect threads in box shall not be less than maximum pin length (LPC), plus ⅛ in. Note: See Table DS-2 for nomenclature. 2

IADC Drilling Manual

Copyright © 2015

Depth of

Pin length

L BC 3 3 1/2 3 5/8 3 5/8 3 7/16 3 3 3 3 5/8 3 3 5/8 4 1/8 3 1/8 3 1/2 3 9/16 4 5/8 3 5/8 4 1/8 4 1/8 3 7/8 4 1/8 4 3/8 4 1/8 3 13/16 3 7/8 3 7/8 4 3/8 4 5/8 4 1/8 4 5/8 4 3/8 4 1/8 5 1/8 4 7/8 4 1/8 4 5/8 5 1/8 5 1/8 5 1/8 4 5/8 4 7/8 4 5/8 5 1/8 5 1/8 4 3/8 4 3/8 5 1/8 5 1/8 5 3/8 5 1/8 5 3/8 5 3/8 5 5/8 5 5/8 5 5/8 5 5/8 5 5/8 6 1/8 5 5/8 5 5/8 6 1/8 5 7/8 6 5/8 6 3/4 6 7 1/8 7 1/4

L PC 2 3/8 2 7/8 3 3 2 13/16 2 3/8 2 3/8 2 3/8 3 2 3/8 3 3 1/2 2 1/2 2 7/8 2 15/16 4 3 3 1/2 3 1/2 3 1/4 3 1/2 3 3/4 3 1/2 3 3/16 3 1/4 3 1/4 3 3/4 4 3 1/2 4 3 3/4 3 1/2 4 1/2 4 1/4 3 1/2 4 4 1/2 4 1/2 4 1/2 4 4 1/4 4 4 1/2 4 1/2 3 3/4 3 3/4 4 1/2 4 1/2 4 3/4 4 1/2 4 3/4 4 3/4 5 5 5 5 5 5 1/2 5 5 5 1/2 5 1/4 6 6 1/8 5 3/8 6 1/2 6 5/8

Major cone dia. D L 2.366 2.438 2.563 2.625 2.725 2.751 2.751 2.813 2.876 2.532 2.876 3.000 3.147 3.147 3.196 3.327 3.329 3.391 3.625 3.047 3.391 3.500 3.812 3.835 3.891 3.891 3.994 4.016 4.016 4.125 3.739 3.812 4.280 4.500 4.579 4.579 4.625 4.834 4.834 4.016 4.625 4.792 4.834 4.834 4.915 4.915 5.250 5.250 5.104 5.250 5.375 5.519 5.825 5.876 6.397 5.992 6.000 6.438 6.753 7.459 6.500 7.000 7.313 7.389 7.952 8.001 8.264

Flat dia.

Small dia.

D LF 2.318 2.328 2.437 2.515 2.672 2.656 2.656 2.703 2.750 2.437 2.750 2.890 3.047 3.047 3.157 3.217 3.217 3.266 3.453 3.000 3.266 3.390 3.702 3.780 3.797 3.797 3.884 3.891 3.906 4.052 3.625 3.703 4.156 4.313 4.484 4.484 4.499 4.709 4.709 3.906 4.515 4.682 4.709 4.709 4.828 4.828 5.135 5.135 4.922 5.135 5.188 5.410 5.715 5.703 6.281 5.882 5.813 6.266 6.643 7.344 6.313 6.890 7.141 7.202 7.840 7.828 8.077

D S 2.069 1.959 2.063 1.875 2.432 2.454 2.454 2.417 2.376 2.235 2.376 2.125 2.834 2.787 2.890 2.660 2.829 2.808 2.750 2.641 2.808 2.562 2.229 3.503 3.485 3.485 3.056 3.349 3.433 3.458 3.114 3.229 3.530 3.792 4.141 4.079 3.875 4.084 4.084 3.433 3.562 3.792 4.084 4.084 4.446 4.446 4.500 4.500 4.313 4.500 4.583 4.332 4.991 4.626 5.564 5.158 5.167 5.063 5.920 6.626 5.125 5.688 5.813 5.858 6.608 6.376 6.608

Table DS-13: Thread form dimensions. Threads/in. V-055 NC10 thru NC16

6

Taper in./ft 1-1/2

H 0.144150

hn-hs

Sm-Srs fm-frs

fcn-fcs

0.055930

0.040650

0.047569

P 0.16667

Fcn-Fcs

0.055

IADC Drilling Manual

V-038R NC23 thru NC50 2-3/8 thru 4-1/2 SH & WO, 2-7/8, 3-1/2 XH 5-1/2, 6-5/8 IF

4

2

0.216005

0.121844

0.038

0.056161

0.25

0.065

NC56 thru NC77

4

3

0.215379

0.121381

0.038

0.055998

0.25

0.065

Fm-Frs

0.047

Copyright © 2015

5

3

0.172303

0.117842

0.020

0.034461

0.20

0.040

V-050 6-5/8 Reg, 5-1/2, 6-5/8 FH

4

2

0.216005

0.147804

0.025

0.043201

0.25

0.050

5-1/2, 7-5/8, 8-5/8 Reg

4

3

0.215379

0.147303

0.025

0.043076

0.25

0.050

V-065

4

2

0.216005

0.111459

0.048385

0.056161

0.25

0.065

0.056

H-90 (90-V-050) 3-1/2 thru 6-5/8 H-90

3-1/2

2

0.141865

0.100000

0.017043

0.024823

0.025714

0.050

0.034

H-90 (90-V-050) 7 thru 8-5/8 H-90

3-1/2

3

0.140625

0.099280

0.016733

0.024613

0.025714

0.050

0.034

SL H-90 (90-V-084)

3

1-1/4

0.166215

0.090000

0.034107

0.042107

0.333333

0.084

0.068

V-076 PAC, OH

4

1-1/2

0.216224

0.092504

0.057948

0.065772

0.25

0.076

0.067

Thread height, not truncated Thread height, truncated Root truncation Crest truncation Width of flat, crest Width of flat, root Root radius Crest radius

0.015

0.015

0.038

0.015

0.038

0.015

0.020

0.015

0.025

0.015

0.025

0.015 0.015

0.030

0.015

0.030

0.015

0.030

0.015

0.015

0.015

DS–25

H hn-hs Sm-Srs, fm-frs fcn-fcs Fcn-Fcs Fm-Frs rm-rrs r

r

DRILL STRING

V-040 2-/8 thru 4-1/2 Reg, 2 7/8 thru 4-1/2 FH

rm-rrs

Table DS-14: Minimum OD * and Recommended Make-Up Torque of Weld-On Type Tool Joints Based on Torsional Strength of Box and Drill Pipe

Premium Class

New Tool Joint Data

Class 2

Copyright © 2015

ID

Make-Up Torque

Min OD Tool Joint

Min Box Shoulder, Eccentric Wear

Make-Up Torque for Min OD Tool Joint

Min OD Tool Joint

in.

in.

ft-lbs

in.

in.

ft-lb

in.

in.

ft-lb

NC31

4 1/8

2 1/8

7,070

3 27/32

5/32

4,970

3 27/32

5/32

4,970

NC31

4 1/8

2

7,890

3 27/32

5/32

4,970

3 27/32

5/32

4,970

X-95

NC26

3 3/8

1 3/4

4,130

3 3/8

11/64

4,130

3 3/8

11/64

4,130

EU

X-95

NC31

4 1/8

2

7,890

3 29/32

3/16

5,730

3 27/32

5/32

4,970

10.40

EU

G-105

NC31

4 1/8

2

7,890

3 15/16

13/64

6,110

3 7/8

11/64

5,350

10.40

IU

S-135

2 7/8 PAC

3 1/8

1 1/2

3,420

3 1/8

15/64

3,420

3 1/8

15/64

3,420

2 7/8

10.40

EU

S-135

NC31

4 3/8

1 5/8

10,100

4 1/16

17/64

7,690

4

15/64

6,890

3 1/2

13.30

EU

E-75

NC38

4 3/4

2 11/16

10,800

4 1/2

11/64

7,270

4 15/32

5/32

6,770

3 1/2

13.30

EU

X-95

NC38

5

2 9/16

12,100

4 19/32

7/32

8,820

4 17/32

3/16

7,790

3 1/2

13.30

EU

X-95

NC40

5 1/4

2 9/16

16,600

4 27/32

13/64

9,600

4 27/32

13/64

9,600

3 1/2

13.30

EU

G-105

NC38

5

2 1/8

15,900

4 21/32

1/4

9,880

4 19/32

7/32

8,820

3 1/2

13.30

EU

G-105

NC40

5 1/4

2 9/16

16,600

4 7/8

7/32

10,200

4 27/32

13/64

9,600

3 1/2

13.30

EU

S-135

NC38

5

2 1/8

15,900

4 13/16

21/64

12,600

4 23/32

9/32

11,000

3 1/2

13.30

EU

S-135

NC40

5 1/4

2 9/16

16,600

5

9/32

12,600

4 29/32

15/64

10,800

3 1/2

15.50

EU

E-75

NC38

5

2 9/16

12,100

4 17/32

3/16

7,790

4 15/32

5/32

6,770

3 1/2

15.50

EU

X-95

NC38

5

2 7/16

13,200

4 21/32

1/4

9,880

4 19/32

7/32

8,820

3 1/2

15.50

EU

X-95

NC40

5 1/4

2 9/16

16,600

4 7/8

7/32

10,200

4 27/32

13/64

9,600

3 1/2

15.50

EU

G-105

NC38

5

2 1/8

15,900

4 23/32

9/32

11,000

4 5/8

15/64

9,350

3 1/2

15.50

EU

G-105

NC40

5 1/4

2 9/16

16,600

4 15/16

1/4

11,400

4 27/32

13/64

9,600

3 1/2

15.50

EU

S-135

NC40

5 1/2

2 1/4

19,600

5 3/32

21/64

14,400

4 31/32

17/64

12,000

4

14.00

IU

E-75

NC38

5

2 7/16

13,200

4 19/32

7/32

8,820

4 17/32

3/16

7,790

4

14.00

IU

E-75

NC40

5 1/4

2 11/16

15,300

4 27/32

13/64

9,600

4 27/32

13/64

9,600

4

14.00

IU

X-95

NC38

5

2 7/16

13,200

4 3/4

19/64

11,500

4 21/32

1/4

9,880

4

14.00

IU

X-95

NC40

5 1/4

2 11/16

15,300

4 15/16

1/4

11,400

4 27/32

13/64

9,600

4

14.00

EU

X-95

NC46

6

3 1/4

19,900

5 13/32

13/64

12,100

5 13/32

13/64

12,100

Nom. Wt.

in.

lb/ft

2 7/8

10.40

EU

E-75

2 7/8

10.40

EU

E-75

2 7/8

10.40

IU

2 7/8

10.40

2 7/8 2 7/8

Upset

Grade

Conn

Min Box Make-Up Shoulder, Torque for Min Eccentric Wear OD Tool Joint

4

14.00

IU

G-105

NC40

5 1/2

2 7/16

17,900

5

9/32

12,600

4 29/32

15/64

10,800

4

14.00

EU

G-105

NC46

6

3 1/4

19,900

5 7/16

7/32

12,800

5 13/32

13/64

12,100

4

14.00

EU

S-135

NC46

6

3

23,400

5 9/16

9/32

15,800

5 1/2

1/4

14,300

4

15.70

IU

E-75

NC38

5

2 7/16

13,200

4 21/32

1/4

9,880

4 19/32

7/32

8,820

4

15.70

IU

E-75

NC40

5 1/4

2 11/16

15,300

4 7/8

7/32

10,200

4 27/32

13/64

9,600

4

15.70

IU

X-95

NC40

5 1/2

2 7/16

17,900

5

9/32

12,600

4 29/32

15/64

10,800

4

15.70

IU

G-105

NC40

5 1/2

2 7/16

17,900

5 1/16

5/16

13,800

4 31/32

17/64

12,000

4

15.70

EU

G-105

NC46

6

3

23,400

5 15/32

15/64

13,500

5 13/32

13/64

12,100

DRILL STRING

IADC Drilling Manual

OD

Nom. Size

DS–26

Drillpipe

Table DS-14: Minimum OD * and Recommended Make-Up Torque of Weld-On Type Tool Joints Based on Torsional Strength of Box and Drill Pipe Drillpipe Nom. Size

Nom. Wt.

Premium Class

New Tool Joint Data

Upset

Grade

Conn

OD

ID

Make-Up Torque

Min OD Tool Joint

Min Box Shoulder, Eccentric Wear

Class 2

Make-Up Torque for Min OD Tool Joint

Min OD Tool Joint

Min Box Make-Up Shoulder, Torque for Min Eccentric Wear OD Tool Joint

IADC Drilling Manual Copyright © 2015

in.

in.

ft-lbs

in.

in.

ft-lb

in.

in.

ft-lb

15.70

EU

S-135

NC46

6

3

23,400

5 21/32

21/64

18,100

5 17/32

17/64

15,000

4 1/2

16.60

IEU

E-75

NC46

6 1/4

3 1/4

19,900

5 13/32

13/64

12,100

5 13/32

13/64

12,100

4 1/2

16.60

EU

E-75

NC50

6 3/8

3 3/4

22,400

5 13/16

13/64

14,100

5 13/16

13/64

14,100

4 1/2

16.60

IEU

E-75

NC46

6 1/4

3

23,400

5 13/32

13/64

12,100

5 13/32

13/64

12,100

4 1/2

16.60

EU

X-95

NC50

6 3/8

3 3/4

22,400

5 27/32

7/32

14,900

5 13/16

13/64

14,100

4 1/2

16.60

EU

X-95

NC50

6 5/8

3 3/4

22,400

5 27/32

7/32

14,900

5 13/16

13/64

14,100

4 1/2

16.60

IEU

X-95

NC46

6 1/4

3

23,400

5 17/32

17/64

15,000

5 7/16

7/32

12,800

4 1/2

16.60

EU

G-105

NC50

6 3/8

3 3/4

22,400

5 29/32

1/4

16,600

5 13/16

13/64

14,100

4 1/2

16.60

IEU

G-105

NC46

6 1/4

3

23,400

5 19/32

19/64

16,500

5 1/2

1/4

14,300

4 1/2

16.60

IEU

S-135

NC46

6 1/4

2 3/4

26,600

5 25/32

25/64

21,200

5 21/32

21/64

18,100

4 1/2

16.60

EU

S-135

NC50

6 5/8

3 1/2

26,700

6 1/16

21/64

21,000

5 31/32

9/32

18,400

4 1/2

20.00

EU

E-75

NC50

6 3/8

3 3/4

22,400

5 13/16

13/64

14,100

5 13/16

13/64

14,100

4 1/2

20.00

IEU

E-75

NC46

6 1/4

3

23,400

5 1/2

1/4

14,300

5 13/32

13/64

12,100

4 1/2

20.00

IEU

X-95

NC46

6 1/4

2 3/4

26,600

5 21/32

21/64

18,100

5 9/16

9/32

15,800

4 1/2

20.00

EU

X-95

NC50

6 3/8

3 1/2

26,700

5 15/16

17/64

17,500

5 7/8

15/64

15,800

4 1/2

20.00

EU

G-105

NC50

6 5/8

3 1/4

30,700

6 1/32

5/16

20,100

5 29/32

1/4

16,600

4 1/2

20.00

IEU

S-135

NC46

6 1/4

2 3/4

26,600

5 15/16

15/32

25,300

5 13/16

13/32

22,000

4 1/2

20.00

EU

S-135

NC50

6 5/8

3

34,500

6 7/32

13/32

25,600

6 3/32

11/32

21,900

5

19.50

IEU

E-75

NC50

6 3/8

3 1/2

26,700

5 7/8

15/64

15,800

5 13/16

13/64

14,100

5

19.50

IEU

X-95

NC50

6 3/8

3 1/2

26,700

6 1/32

5/16

20,100

5 15/16

17/64

17,500

5

19.50

IEU

X-95

5 1/2 FH

7 1/4

3 3/4

38,500

6 1/2

1/4

20,200

6 13/32

13/64

17,100

5

19.50

IEU

G-105

NC50

6 5/8

3 1/4

30,700

6 3/32

11/32

21,900

6

19/64

19,200

5

19.50

IEU

G-105

5 1/2 FH

7

4

33,400

6 9/16

9/32

22,300

6 15/32

15/64

19,200

5

19.50

IEU

S-135

NC50

6 5/8

2 3/4

38,000

6 5/16

29/64

28,400

6 3/16

25/64

24,600

5

19.50

IEU

S-135

5 1/2 FH

7 1/4

3 1/2

43,300

6 3/4

3/8

28,700

6 5/8

5/16

24,400

5

25.60

IEU

E-75

NC50

6 3/8

3 1/2

26,700

6 1/32

5/16

20,100

5 15/16

17/64

17,500

5

25.60

IEU

E-75

5 1/2 FH

7

3 3/4

37,700

6 1/2

1/4

20,200

6 13/32

13/64

17,100

5

25.60

IEU

X-95

NC50

6 5/8

3

34,500

6 7/32

13/32

25,600

6 3/32

11/32

21,900

5

25.60

IEU

X-95

5 1/2 FH

7

3 1/2

37,700

6 21/32

21/64

25,500

6 9/16

9/32

22,300

5

25.60

IEU

G-105

NC50

6 5/8

2 3/4

38,000

6 9/32

7/16

27,400

6 5/32

3/8

23,700

5

25.60

IEU

G-105

5 1/2 FH

7 1/4

3 1/2

43,300

6 23/32

23/64

27,600

6 5/8

5/16

24,400

5

25.60

IEU

S-135

5 1/2 FH

7 1/4

3 1/4

47,200

6 15/16

15/32

35,400

6 13/16

13/32

30,900

5 1/2 21.90

IEU

E-75

5 1/2 FH

7

4

33,400

6 15/32

15/64

19,200

6 13/32

13/64

17,100

DS–27

lb/ft

4

DRILL STRING

in.

DS–28

Table DS-14: Minimum OD * and Recommended Make-Up Torque of Weld-On Type Tool Joints Based on Torsional Strength of Box and Drill Pipe Drillpipe Nom. Wt.

in.

lb/ft

5 1/2

Upset

Grade

Conn

Class 2

OD

ID

Make-Up Torque

Min OD Tool Joint

Min Box Shoulder, Eccentric Wear

Make-Up Torque for Min OD Tool Joint

Min OD Tool Joint

Min Box Make-Up Shoulder, Torque for Min Eccentric Wear OD Tool Joint

in.

in.

ft-lbs

in.

in.

ft-lb

in.

in.

ft-lb

IADC Drilling Manual Copyright © 2015

21.90

IEU

X-95

5 1/2 FH

7

3 3/4

37,700

6 5/8

5/16

24,400

6 17/32

17/64

21,200

5 1/2 21.90

IEU

G-105

5 1/2 FH

7 1/4

3 1/2

43,300

6 23/32

23/64

27,600

6 19/32

19/64

23,300

5 1/2 21.90

IEU

S-135

5 1/2 FH

7 1/2

3

52,100

6 15/16

15/32

35,400

6 13/16

13/32

30,900

5 1/2 24.70

IEU

E-75

5 1/2 FH

7

4

33,400

6 9/16

9/32

22,300

6 15/32

15/64

19,200

5 1/2 24.70

IEU

X-95

5 1/2 FH

7 1/4

3 1/2

43,300

6 23/32

23/64

27,600

6 19/32

19/64

23,300

5 1/2 24.70

IEU

G-105

5 1/2 FH

7 1/4

3 1/2

43,300

6 25/32

25/64

29,800

6 11/16

11/32

26,600

5 1/2 24.70

IEU

S-135

5 1/2 FH

7 1/4

3 1/2

43,300

7 1/32

33/64

38,900

6 7/8

7/16

33,200

6 5/8 25.20

IEU

E-75

6 5/8 FH

8

5

43,900

7 7/16

1/4

26,800

7 3/8

7/32

24,100

6 5/8 25.20

IEU

X-95

6 5/8 FH

8

5

43,900

7 5/8

11/32

35,100

7 1/2

9/32

29,600

6 5/8 25.20

IEU

G-105

6 5/8 FH

8 1/4

4 3/4

51,300

7 11/16

3/8

38,000

7 19/32

21/64

33,700

6 5/8 25.20

IEU

S-135

6 5/8 FH

8 1/2

4 1/4

65,000

7 29/32

31/64

48,200

7 25/32

27/64

42,300

6 5/8 27.70

IEU

E-75

6 5/8 FH

8

5

43,900

7 1/2

9/32

29,600

7 13/32

15/64

25,500

6 5/8 27.70

IEU

X-95

6 5/8 FH

8 1/4

4 3/4

51,300

7 11/16

3/8

38,000

7 9/16

5/16

32,300

6 5/8 27.70

IEU

G-105

6 5/8 FH

8 1/4

4 3/4

51,300

7 3/4

13/32

40,900

7 21/32

23/64

36,600

6 5/8 27.70

IEU

S-135

6 5/8 FH

8 1/2

4 1/4

65,000

8

17/32

52,700

7 27/32

29/64

45,200

6 5/8

-

IEU

S-135

6 5/8 FH

8 1/2

4 1/4

65,000

8 1/2

25/32

65,000

8 5/32

39/64

60,400

6 5/8

-

IEU

S-135

6 5/8 FH

8 1/2

4 1/4

65,000

8 1/2

25/32

65,000

8 1/2

25/32

65,000

6 5/8

-

IEU

S-135

6 5/8 FH

8 1/2

4 1/4

65,000

8 1/2

25/32

65,000

8 1/2

25/32

65,000

6 5/8

-

IEU

S-135

6 5/8 FH

8 1/2

4 1/4

65,000

8 1/2

25/32

65,000

8 1/2

25/32

65,000

* Tool joint diameters specified are required to retain torsional strength in the tool joint comparable to the torsional strength of the attached drillpipe. These should be adequate for all service. Tool joints with torsional strengths considerably below that of the drillpipe may be adequate for much drilling service.

DRILL STRING

Nom. Size

Premium Class

New Tool Joint Data

DRILL STRING

Operations and applications

DS–29

Tool Joint Box Upset (internal)

Drillpipe problems

Weld zone

As a rule, tool joints are weaker in torsion than the tubes to which they are attached. Input torque while drilling should be limited to 80% of tool joint make-up torque. The stick/ slip action of PDC bits makes this a difficult rule to follow. In critical situations, measure breakout torque frequently. Breakout should be 80% to 90% of make-up torque. If there are connections above this level, back off on operating conditions (bit weights and rotary speeds).

Pipe body

Pay close attention to thread compound and recommended make-up torques. Never use API TUBING COMPOUND or API MODIFIED on tool joints. Their effect is to weaken the connection and cause it to fail at a lower torque value. Know the OD/ID of every connection that goes in the hole and also the shoulder-to-shoulder length and grade of the tubular member. Should a tubular failure occur while drilling, ask that all usual and unusual operating conditions be noted. Call the most reputable fishing tool professional, and provide him with this information. Make the top half of the failure available as is. Place a value on the components of the fish in the hole and the cost of drilling the hole below the failure. Set a limit on time to spend on recovery of the fish.

Breaking in new tool joints

Specific recommendations concerning cleaning, inspection, make-up, handling, etc., are extremely important throughout the life of tool joints. In addition, there are extremely important factors to consider during the break-in period of new joints. The newly machined surfaces are more apt to gall than those which have had some use. After some service, the surfaces undergo certain changes which offer more resistance to galling. Therefore, the initial make-up and first few trips are the most critical time, and extra care is essential to give longer trouble-free service. The following steps should be specifically observed on new joints: • Verify recommended make-up torque. Check condition and/or accuracy of all make-up equipment and gauges. Include saver sub condition in this check; • Observe all threads and shoulders for handling damage; repair as necessary; • Coat all threads and shoulders liberally with thread compound containing 50% by weight finely powdered metallic zinc and not more than 0.3% sulfur; • On initial make-up, and for several trips thereafter, stab carefully, make-up slowly, and tong to full make-up using both sets of tongs;

IADC Drilling Manual

Weld zone Upset (internal) Tool Joint Pin

Figure DS-23 showing basic components of the drillpipe.

• Watch for excess resistance during make-up and breakout. Galling, cross threading, and crest to crest makeup can cause excess resistance during make-up. Galling or downhole make-up can cause high breakout torques. Breakout torques over 90% of make-up are warning flags. Galling occurs more often on new or recut threads. See Figure DS-23; • Alternate breaks on every trip and continue to stab carefully, make-up slowly, and tong to full make-up using both sets of tongs; • Avoid high torque situations with new tool joints until they have received a good breaking in.

Tripping »» Lowering the elevators Box shoulder may be badly damaged if struck by elevators or hook. See Figure DS-70. Severe damage can be properly repaired only by reworking the box in the machine shop.

»» Breaking out When breaking the connection, use both breakout and backup tongs. After breaking the connections, rotate out slowly. Keep just enough tension on the hook spring to keep minimum pressure on the disengaging threads; but keep enough tension to avoid the end of the pin striking the box shoulder. See Figure DS-24. When lifting the pin from the box, the joint must be pushed

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DS–30

DRILL STRING

• Alternating breaks Come out of hole on a different break each trip so that every connection can be periodically broken and its condition observed and torque rechecked. This may prevent wobbles and leakage failures. Also, excessive breakout torque may indicate abnormal downhole torque conditions. Check for damage due to excessive torque.

Figure DS-24: Indentation by pin end bumping shoulder face may destroy seal, resulting in leaking and washout.

• Standing back When standing the pipe back, be sure setback area is clean. If the desired position of stand is not achieved, do not use wrench jaw or other sharp-edged tool to jack it into position. This will cause shoulder damage and lead to an epidemic of shoulder leakage and washouts. Special handling tools, as shown in Figure DS-26, are available to minimize such trouble.

»» Going in the Hole • Lubrication Practice Before each joint is added to the string, it should be cleaned and dried. This includes complete removal of rust preventatives or previously applied tool joint compound. When the joint is picked up and on each trip, thread compound should be evenly distributed over pin and box thread and shoulder, preferably with a round, stiff bristle brush. See Figure DS-27. Keep compound and brush clean and free from dirt.

Figure DS-25: Box shoulder will be damaged when struck by elevators. Take care that this does not happen during trips.

• Stabbing Do not allow the ends of the pins to strike the box shoulders. Such damage may be avoided by achieving coordination between drillers and floormen. See Figure DS-29. • Spinning Up Before spinning up pipe, be sure connections are in alignment. Don’t rotate pipe too fast; if a joint wobbles and binds, high speeds can burn threads. The use of kelly spinners during high-speed drilling operations has become quite common on broken-in tool joints. This is particularly true in the high-cost offshore environment. Kelly spinners rotate the kelly at high rates into the mousehole joint, and sub-

Figure DS-26: Using a recommended type of pipe jack will reduce damage to pin shoulders.

to the side to prevent the pin from striking the shoulder when it drops back down. Breakout torque should be 8090% of make-up torque. High breakout torque is a warning. Look for galling and/or thread damage. If neither is found, downhole make-up may have occurred. Reduce input torque while drilling.

Figure DS-27: Lubricate threads and shoulders every trip. A round, stiff bristle brush gives best results.

DRILL STRING

sequently, the mousehole joint, as it enters the joint in the rotary table. Extra care is necessary to ensure that the connection is clean and adequately lubricated and that the joint does not wobble and bind. After both spinning operations, the rotary tongs should be used to tighten the joints to the recommended torque. Failure to follow the procedures may increase the likelihood of damage.

DS–31

• Make-up and tonging When making up the connection, use both make-up and back-up tongs. Avoid forced make-up of improperly engaged threads. In stabbing, flat thread crests on the pin can land opposite similar crests on the box. This results in jamming action, and forced make-up will cause serious damage. A slight amount of left hand rotation with tongs will free them. The stand can be lifted, rotated slightly, and stabbed again. See Figure DS-30. Tonging tool joints properly is the most important single factor in prevention of tool joint troubles. Table DS-16 gives the recommended make-up torques for the various sizes, types, and classes of tool joints. Torque measuring equipment should always be used to prevent under torque or over torque of tool joints. Slicker than normal thread compounds can contribute to torsional problems. • Running in Refer to “Floor handling procedures” elsewhere in this chapter.

Figure DS-28: Pure thread galling results from lack of lubricating film. This allows steel surfaces to freeze together.

Figure DS-29: Bumping of box shoulder by end of pin while stabbing is a common cause of damage.

»» Laying down drill string When laying down the drill string, specific operations should include: • Wash tool joints and drill string internally and externally with clear fresh water. This will remove any salt or other corrosive agent which might bring about more rapid deterioration; • Apply a rust preventive compound to the threads and shoulders, particularly if drill string is to be stored for any length of time. Some thread compound manufacturers have started adding a rust preventive to their thread compounds; • Install thread protectors before swinging through “V” door and onto walk. Keep walk clear—do not allow joint coming down to hit another joint or other objects on the walk. Be sure thread protectors are installed tightly on boxes and pins. See Figures DS-33 and DS-34; • Check drill string for straightness and straighten if needed. When racking, use wood spacers between layers. Three spacers are desirable—one in the center and one close to either end and behind the tool joints. Spacers should be thick enough to keep tool joints separated when rolling drill string.

»» Damage and failures­—cause and prevention

Figure DS-30: While stabbing, flat thread crests on pin may land opposite similar crests on box. Forced makeup causes thread damage and possibly galling.

IADC Drilling Manual

• Visual examination for damage while tripping • Look for dry or muddy threads (See Figure DS-35); check for washing and galling: check for worn threads. Correct any damage and return to service. Be sure to check that proper make-up torque and procedures are being used. Measure breakout torque periodically;

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DS–32

DRILL STRING

Damage from tongs

Figure DS-31: Shoulders may be damaged when tongs are allowed to engage the shoulder.

Figure DS-34: When laying down pipe, keep walk clear. Do not allow a joint coming down to hit another joint or an object on the walk..

Watch for dry connections

Figure DS-32: Bucking up is one of the most critical rig activities in the life of a tool joint.

Figure DS-35: Watch for dry connections when making trips as they are positive indications that something is wrong.

Figure DS-33: Install thread protectors before laying down a joint.

Figure DS-36: Gall on the shoulder or threads prevents shoulder from sealing, causing washing of shoulder and threads.

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DRILL STRING

Figure DS-37: Connection will not develop maximum strength and will lack shoulder support with insufficient make-up torque. This can cause fatigue failure in the pin.

• Look for galling on threads and shoulders. See Figure DS-36. When galling is encountered, check for proper thread compound, proper torque, and adequate shoulder areas; • Look for wear on tool joints and drill pipe. If eccentric tool joint wear is noticed, check pipe for straightness; • Watch for undercutting of the tool joint in the area of the 18° elevator shoulder. Undercutting may be more prevalent on tool joints with hardbanding but may also occur on tool joints without hardbanding. Check pipe for straightness. Check operations for critical rotating speed; • While tripping, watch tool joints for evidence of pin stretch and box swelling due to over-torquing. Over-torquing frequently occurs downhole while drilling; • Watch for washouts in drill pipe in the connection area of the joint, in the slip area and in the transition between the upset and the pipe nominal wall. • Failures • Do not allow a descending joint to hit another joint or other object on the walk; • Watch for mashes, dents, slip cuts and other similar damage. These areas are potential areas to originate failures and should be thoroughly investigated before running in the hole; • Fatigue: Most fatigue failures in a tool joint occur in the last engaged thread of the pin. This area lies approximately 1 in. from the pin shoulder. The most common cause of fatigue failures is insufficient make-up torque to stabilize the box and pin shoulders and threads. As a result, stress reversals are permitted that exceed the endurance limit of the material and result in failures. See Figure DS-37. Mechanical damage and/or galling can also allow conditions

IADC Drilling Manual

DS–33

Figure DS-38: Tension due to excessive torque is normally a cup-and-cone-type fracture.

of instability, causing a fatigue crack to occur. When fatigue cracks occur or are suspected, a magnetic particle inspection of the pin thread areas should be made. Some of the indications that a pin could have been subjected to fatigue are: • Galled face and shoulders; • Worn and lapped threads; • Galled threads; • Dry or muddy pins; • Washed, mud-cut faces and shoulders. • Torsion Torsional failure and torsional damage to joints are both obvious and obscure, catastrophic and passive. • Downhole torque The most common cause of torsional failure is downhole torque. Apparently the worst condition exists when the bottom portion of the drill stem stops rotation or hangs up, and the upper portion, the drill string, keeps turning due to momentum or rotational forces from the rotary table or top drive. One of the most common types of torsional failures is tensile failure of the pin. The fracture surface appearance is usually the classical cup/cone type failure as illustrated in Figure DS-38. The concave portion of the fracture surface will be on the pin dutchman that remains in the box. The convex portion of the fracture surface will be on the pin body. This type of failure occurs instantaneously when the connection suddenly makes up downhole, and the rotation of the pin into the box produces tensile stresses in the last engaged thread area above the strength of the material. The torque required to produce this type of failure is much higher than the recommended make-up torque. This type of failure is common in new drill strings. To reduce the incidence of this type of failure, use the recommended make-up for tool

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DS–34

DRILL STRING

B3-26

Figure DS-42: Excessive torque may result in swelled and split tool joint box or a stretched pin. Figure DS-39: Excessive torque may result in swelled and split tool joint box.

joint and the recommended tool joint thread compound. • Other obvious forms of torsional failures On worn tool joints, boxes may bell or split. Sometimes the belling may be detected by placing a straight edge on the box and looking for belling. Sometimes the box OD near the make-up shoulder may be a bright shiny color caused by a belled box rubbing in the hole while rotating. Figure DS-39 shows an example of a split box. Figures DS40 and DS-41 show examples of belled boxes.

Figure DS-40: A tool joint belled out by excessive torque also has internal distortion.

Another problem occurs with tool joints due to torsion. This is commonly referred to as stretched pins. Stretched pins may occur along with other types of torsional failures or they may be the only evidence of over-torquing. The stretch is produced by the same mechanism as failures caused by downhole torque and torsion. However, the torque is insufficient to produce failure, or the torque is removed before failure occurs, due, perhaps, to the failure of another tool joint in the string. This type of torsional damage is difficult to detect, but dangerous because cracks may be present that will progress to failure if not detected and removed. Alternatively, cracks may develop from the stretched area. Stretch may be present in varying degrees and may be detected and measured in several ways. The most accurate method of detecting and measuring pin stretch is with a dial indicator lead gauge as shown in Figure DS-42. It is recommended that any pin that has more than 0.006 in. stretch within 2 in. be re-machined. Stretch may be detected with a thread profile gauge as shown in Figures DS-42 and DS-43. The amount of stretch is difficult to determine by this method.

Figure DS-41: Excessive torque while drilling may result in a belled box if the box is the weaker member. Other connections may show a depressed box shoulder and possibly a sheared three-sided ring with the box shoulder as one side.

IADC Drilling Manual

Stretch may sometimes be detected by other means when lead and profile gauges are not available. A straight edge may be used by putting it on the crest of the threads. If the pin is stretched, the 3rd, 4th, and/or 5th thread crest from

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DRILL STRING

DS–35

Figure DS-43: Thread profile gauge indicates necking down and stretching of thread lead due to excessive torque.

Figure DS-47:Insufficient make-up torque allows wobbling and produces lapped, sharp, and broken threads, and broken pins.

Figure DS-44: Excessive torque, either downhole or during makeup in rotary table, results in stretched and necked-down pin.

Figure DS-48: Wobble about two opposite high places on shoulder breaks threads on axis and laps those at 90° from axis.

AXIS OF WOBBLE

90° FROM AXIS OF WOBBLE

Figure DS-45: Lapped threads, indicated by ridge on shoulder and thread flank, are evidence of wobbling connection caused from insufficient make-up torque.

Figure DS-49:Wobble causes threads to break. When connection is backed out, the broken threads become fouled. Such troubles are often incorrectly referred to as galls. Shoulder is the only seal

Channel

Box

Pin

Figure DS-46: Lapped threads, indicated by ridge on shoulder and thread flank, are evidence of wobbling connection caused from insufficient make-up torque.

IADC Drilling Manual

Figure DS-50: The shoulder is the only area of seal in a rotaryshouldered connection. Between crest and root, threads have a clearance which acts as a channel for lubricant and fluid.

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DS–36

DRILL STRING

the shoulder will not lie in the plane of the thread crest. Daylight or space will occur between the crest of the thread and the straight edge. When checking with a straight edge, use caution that mechanical damage to the threads is not contributing to the space between thread crest and straight edge.

Figure DS-51: Washing will occur if the connection is not tightened with tongs and there is complete absence of a shoulder seal.

If the drill string has been plastic coated, an inspection of the plastic coating in the stretched area may reveal circumferential cracks in the plastic coating. The circumferential cracks will coincide with the pin thread roots near the last engaged thread in the pin bore. Usually the pin will be stretched over 0.006” in 2” when cracks occur in plastic coating. When torsional failures or damages are detected, all pins left in the string should receive a magnetic particle thread inspection to detect any cracks that may have occurred in the thread roots. • Overtorquing in the rotary table Although downhole torque might be the major cause of torsional damage and failures, torsional damage can also be initiated by over-torquing in the rotary table. This is most prevalent on tool joints 3 ½ in. and smaller. Using the recommended make-up torque and proper tool joint thread compound will minimize torsional damage due to over-torquing. • Other damage Watch for lapped and worn threads for indications of wobble. Insufficient make-up torque allows wobbling and produces lapped and worn threads that may result in a broken tool joint pin. See Figures DS-46, DS-47 and DS-48.

Figure DS-52: Heat-checking and resulting fractures are revealed under blacklight. Examine boxes and pins for longitudinal cracks.

Pin Benchmark

0.125

+0.010 -0.000

In 1980 API established a benchmark: A circle-bar was stenciled ⅛ in. from the sealing shoulder, so all could understand how much a shoulder might have been dressed. This was a step forward, but an improvement was soon found in a 360° bench-

Box Benchmark R0.06

0.020 Min. 0.032 Max. R0.028 Min. R0.034 Max.

Benchmark dia. C’bore dia. ± 0.016 ±0.008 R0.031

C’bore dia. ±0.008

Bevel from bottom of counterbore +0.000

0.125 -0.010

Cylindrical dia. ±0.016 Benchmark dia. Cylindrical dia. +0.032 ±0.016

Notes: 1. Pin Benchmark is equal to Cylinder Diameter + 0.032. 2. Box Benchmark is equal to Counterbore Diameter + 0.016.

Figure DS-53: A 360° style benchmark.

IADC Drilling Manual

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DRILL STRING

DS–37

mark (Figure DS-53) which was also placed ⅛ in. from the sealing shoulder on pins and boxes. This more accurate and accommodating benchmark should be used on all new and recut connections, except when it interferes with a pin-base relief groove.

rosion, corrosion fatigue, and sulfide stress cracking (SSC). See “Sulfide stress cracking” within “Drill Pipe Corrosion” for a discussion of these effects and how to control them.

Sandpaper and a half-inch drill have been used to dress some shoulders. While this can be performed successfully, failure to change the sandpaper frequently has resulted in shoulders which leaked because they were not flat and square within 0.002 in.

General

Washes on faces can be caused by insufficient make- up torque, galled threads, or stabbing damage. The shoulder is the only seal in the tool joint and will not prevent leaking if the connection is not made up to recommended torque. See Figures DS-50 and DS-51. Washed or damaged tool joint faces should be repaired immediately. Be careful of the dressing method employed. Make-up shoulders are to be flat and square within 0.002 inches. The threads should also be inspected for any damage. Heat checking or friction cracking is the result of rapid heating and cooling of the tool joint box or pin OD. A pattern of parallel surface cracks is formed perpendicular to the direction of rotation. Heating above the critical temperature results from the friction developed between the tool joint OD and the casing, formation, whipstock, or some other object that the tool joint may rub against. Drilling fluid provides the environment for the rapid cooling. Figure DS-52 shows a blacklight photograph of a heat-checked tool-joint box which has progressed to a fracture through the wall. Blacklight inspections for longitudinal cracking are needed to determine the full extent of the damage. Check boxes and pins and replace affected material. Heat checking/quench cracking of tool joints occurs frequently because of doglegs high in the hole. Arthur Lubinski described this first in 1949 and suggested drill string was in danger when side thrust reached 2,000 lb/joint. If a high dogleg has occurred, reduce the hang-down weight below the dogleg to keep the side thrust in a safe range, inspect for longitudinal cracks, and replace affected tool joints. The kelly saver sub should be cleaned and inspected every time it is removed from the rat hole and always maintained in good condition. The saver sub mates with every tool joint box in the string as drilling progresses. If a saver sub is damaged, it should be repaired or replaced immediately. For this reason, a spare sub in good condition should be kept on the rig at all times. Follow recommended break-in practices when a newly threaded saver sub is placed in service. Always keep the rathole as clean as possible. Damage to and failure of tool joints can be caused by cor-

IADC Drilling Manual

Repair of tool joints The repair of damaged tool joints in the field and in the shop is discussed in subsections B and C respectively. The degree of damage is the determining factor in deciding whether it can be repaired in the field by shoulder dressing tools or by shop machine work. In either event, the following paragraph regarding plug and ring gauges adopted by the API Task Group on Care and Use of Drill String should be considered: The API Task Group on Care and Use of Drill String has determined that ring and plug standoffs should not be used to determine whether to reject or retain a tool joint. This is because, when plug and ring gauges are used, thread wear, plastic deformation, mechanical damage, and cleanliness can lead to incorrect results. Smooth sealing shoulders are more critical to tool joint operation than gauge stand off. When refacing tool-joint shoulders, material should be removed only when necessary; i.e., when it appears necessary to dress the make and break shoulder so it will seal again. Not more than 1/32 in. should be removed at one refacing and not more than 1/16 in. cumulatively. Use the benchmark to control this operation.

Field repair of damaged tool joints

Tool joints found to have slightly damaged shoulders can usually be repaired at the rig with handheld tools. Such dam-

Figure DS-54: Shoulder dressing tool can repair galled and scored box shoulders.

age includes slight crowning of the shoulders due to wobble, slight leakage dents or upsets, fins and galls. Where shoulders are obviously damaged, as those in Figure DS-54, repairs shouldbe made. In checking over a string of tool joints all the shoulders not obviously in need of repairs should be checked for flatness with the test ring as shown in Figure

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DS–38

DRILL STRING

Figure DS-55: Shoulder dressing tool can repair galled and scored box shoulders.

DS-55. Shoulders must be faced flat and square with the threads. Threads must be deburred and checked with a thread profile gauge before facing. Before using the test ring, be sure the shoulders and the ring are clean and dry. Hold the ring, which is flat itself, against the shoulder by applying pressure with the fingers at two diametrically opposed points, as shown in Figure DS-55 and attempt to make it rock. Repeat at points 90° from the first points of pressure. If the ring rocks at all, the shoulder is either rough or crowned and it should be faced off flat with a shoulder dressing tool. API specifications require the makeup shoulders on tool joints to be flat and square within 0.002 in., as related to the threads. The preferred method to dress shoulders is with a mechanical device. Sandpaper discs have not proven effective in attaining this tolerance.

Shop repair of damaged tool joints

Threads on pins and boxes must be thoroughly cleaned and buffed. Magnetic particle inspection must be conducted on the pin-box thread roots. If cracks are found, the connection must be cut off. After machining, the connections must be rechecked for cracks. No cracks should remain in the newly cut connections. The thread gauge stand-off must be checked with hardened and ground gauges to API specifications. A thread-profile gauge must fit the threads. Further checking of thread lead, thread taper and thread forms may be indicated. Pay special attention to the following: • The specified thread root radius must be maintained. Lack of a proper radius in the root of the thread will result in premature fatigue failures; • Thread depth and thread crests must be maintained within specifications to avoid interference when connection is made up;

IADC Drilling Manual

• Thread angles must be maintained and the threads must be normal to the axis of the connection; • A radius at the shoulder of the pin connections must be maintained to specification; • Specified perfect thread lengths must be maintained; • All dimensions such as counterbore diameter and length, pin thread length, shoulder bevel diameter, etc., shall be checked against specification drawings; • All newly-machined threads and shoulders should be treated to protect against galling during the break-in period. A phosphate coating is the usual treatment; • All connections shall be properly greased and thread protectors installed immediately after inspection; • Contact manufacturers for thread and dimensional data on non-API connections.

O-ring use

Several years ago, two major operators were testing very high-pressure drilling methods, and they requested tool joints that could hold 10,000 psi. Two tool-joint manufacturers conducted tests and provided O-ring tool joints that performed well. Later reports said some pressures ran as high as 14,000 psi. The efforts of one manufacturer required special grooves on the tool joints’ pin base and box counterbore. (API tolerances on these two areas are not suitable for the proper fit and squeeze on an O-ring.) The first user reported that they opted for an O-ring with a harder durometer reading than was recommended. They also found it necessary to limit the amount of thread compound used on each connection. An overly generous application was found to force the O-ring between the mating shoulders, which damaged the O-ring, rendering it ineffective. If an operation calls for considerably higher pump pressures, contact your tool-joint manufacturer and ask for its version of a “proper” O-ring tool joint. Tool joints designed for O-rings can be used as standard tool joints, but standard tool joints should not be expected to serve as high-pressure O-ring connections.

Welding procedures for downhole drilling tools

Usually the materials used to manufacture downhole drilling equipment (tool joints, drill collars, stabilizers and subs) are AISI 4135, 4140 or 4145 steels. These alloy steels are normally in the heat-treated state. They are only weldable if proper procedures are implemented to prevent cracking and to recondition welded sections. Welded areas can only be reconditioned. They cannot be restored to their original state, free of metallurgical damage, unless a complete heat treatment is conducted after welding.

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DRILL STRING

DS–39

Figure DS-56: After refacing a box shoulder, the shoulder should be flat and square with the threads.

Improper Handling Method

Figure DS-58: A groove can be caused by corrosion of protectors left on pipe in storage.

• Load so that all pin ends are on the same end of the truck (and conversely, that all box ends are at the other end); • Space pipe properly to prevent shoulders from chafing adjacent joints; • Do not overload truck, boat, or barge; • Retighten load-binding chains after hauling the load a short distance. Load settling can loosen the chains. Recommended Handling Method (With Thread Protectors in Place)

Figure DS-57: Use proper handling procedureswhen loading drill pipe with hooks, slings, etc.

When welding is mandatory on downhole drilling tools, it is recommended that procedures outlined by the American Welding Society be consulted. The mechanical properties of API rotary-shouldered connections on all drill-stem members will be adversely affected by welding and will likely fail to meet minimum requirementsunless proper procedures are used to prevent cracking and to recondition the section where welding has been performed, accoding to API RP76, 16th edtion.

Transportation Truck transportation

API tubular goods in general, and threads in particular, require careful handling in transportation and storage as well as during drilling operations. The following precautions should be taken for truck transportation: • Load pipe on bolsters and tie down with suitable chain at the bolsters. In hauling long pipe, tie the middle down with an additional chain;

IADC Drilling Manual

Offshore service vessels

The following are suggestions for loading and securing drill pipe and casing on offshore vessels: • Thread protectors must be installed on both ends of pipe before loading begins; • Place pipe on wooden stringers spaced roughly 10 ft apart and shimmed to the same horizontal plane; • Lay down wooden strips to separate each layer of pipe. Strips should be lined up on a vertical plane with the deck stringers; • Secure tubulars to the deck or hull of the vessel with load-binding cables or chains attached at structurally sound locations. The number and size of such cable or chains is usually determined by the boat captain according to expected sea conditions. Properly sized steam boat ratchets or turnbuckles are used to maintain proper chain or cable tension. Each layer of pipe should be blocked, unless vertical stanchions are provided; • Take special precautions when loading and unloading pipe at offshore wellsites. In rough seas, handling pipe loads by crane must be minimized, due to safety concerns related to the movement of swinging loads; • Moving pipe between drilling tenders and the floor of offshore platforms presents handling problems. Close supervision is critical to devise and regulate proper handling. When possible, trolley lines, whirley cranes, and other means for controlled descent of pipe when lowering it from the derrick floor to the tender are recommended to prevent severe damage to drill string.

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DS–40

DRILL STRING

available and can do a better job in blocking the pipe.

Floor handling procedures

ConventionalLong Rotary Slips

Slips and bushings

Standard Bowl

Effective Backing

8- 13/16”

Effective Backing

4”

ExtraLong Rotary Slips

12- 13/16”

Extended Bowl

Figure DS-59: Extended-bowl, extra-long rotary slips and pin-drive allow for more effective support for heavy strings.

Handling

The following precautions should be observed in handling pipe: • Before unloading, ensure that thread protectors are tightly in place; • Do not unload pipe by dropping. Avoid rough handling which might ding or dent the body of the pipe. Out-of- roundness will greatly reduce collapse strength; • When rolling down skids, pull the pipe parallel to the stack. Do not allow pipe to gather momentum or to strike ends, because the danger of thread damage exists even with protectors in place; • Stop each length before it reaches preceding length, then push together by hand.

Storage

The following precautions are recommended for pipe storage: • Do not pile pipe directly on ground, rails, or steel or concrete floors. The first tier of pipe should be no less than 12 in. from the ground to isolate drillpipe from moisture and dirt; • Pipe should rest on supports properly spaced to prevent bending of the pipe or damage to the threads. The stringers should lie in the same plane, be reasonably level and be supported by piers adequate to carry the full stack without settling. • Separate successive layers of pipe with wooden strips so that no weight rests on the tool joint. Use at least three spacing strips, placed at right angles to the pipe and directly above lower strips and supports to prevent bending; • Block pipe by nailing 1 in. × 2 in. × 2 in. wooden blocks to both ends of the spacing strips. Plastic chocks are

IADC Drilling Manual

The successful handling of drill pipe with rotary slips and master bushings for all depths and drilling conditions is directly dependent on the following factors: •  Compatibility in design and manufacture of master bushings and drill pipe slips; • Proper application, based on hookload, of square-drive and pin-drive type rotating equipment; • Wear conditions existing in rotary table equipment. Square-drive master bushings and/or matching bowls with the appropriate shorter slips can be used successfully when hookload does not exceed 250,000 lb. For greater hookloads, use a master bushing designed to accept a 4-pin drive kelly bushing. This type of bushing has an extended API taper, thus increasing back-up support for the slips. Extra-long slips, which are designed to be compatible, will more effectively distribute the forces working to crush or “bottleneck” the drill pipe. A comparison of conventional and extra-long slips and standard and extended-bowl master bushing combinations can be seen in Figure DS-59. Proper maintenance of master bushings and rotary slips are central to preventing cutting, gouging, and bottlenecking of drill pipe. This will prevent unnecessary downgrading and discarding of pipe, and will also minimize washouts and other types of downhole failures. The damaging effects of worn rotary tables, master bushings, and rotary slips can be seen in Figure DS-60. Obviously, the drill pipe will be damaged under these circumstances. This is an extreme case; however, the same type of damage can be incurred with less worn equipment. Figure DS-60 shows a split master bushing. A similar condition occurs after several years to the bowls and outer hull of a solid or hinged master bushing.

Replacing slips with double elevators

Some 60% of the tube failures appear to be in the slip area. Unless special care is taken with the maintenance and use of slips, slip marks can turn into life-shortening stress raisers. The slip area is also just beyond the minimum internal upset (miu) fadeout, which occurs in the high-stress area. The first reported use of double elevators instead of slips was on the first 25,000-ft well in the US. High-strength tubes were new, and concern existed about notch sensitivity in the harder, stronger tubes. The operator and contractor initially agreed that double elevators might prove slower

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DRILL STRING

than slips, but experience proved that operations using double elevators equalled the speed with slips.

Pipe is bottlenecked

DS–41

Gripping area of slips is greatly reduced

Other applications for double elevators also exist. This could present another method to extend drill-string life without lengthening trip times.

Slips alternative

Improperly maintained slips can shorten the useful life of drill string. Throwing the slips on moving pipe can damage tubes, as does the use of slips as backup tongs. Review your tube failures and consider the use of double elevators on your rig. An early application of this idea was on the first 25,000 ft. well in the United States. High-strength drill pipe was new, and concern for notch sensitivity prompted this move.

Worn master bushing

Taper changed

Reduced backup area causes wear and crushing in backs of slips

Worn rotary table Slips deformed

Slower trips were accepted, but double elevators proved to be as fast on trips as the use of slips. Quick-release elevators and a short two-piece stool on the rotary table are the items needed. Review your drill pipe tube failures which have occurred in the slip area and consider elevators on your rig.

Figure DS-60: Drill pipe will be damaged if there is any combination of worn and new master bushings, rotary table, or slips.

Testing slips and bushings

A slip test is an invaluable aid to determining the degree of rotary equipment wear. Conduct this test every three months and whenever new master bushings or set of slips is put into service. For accurate results, use a hook load of at least 100,000 lb: • With a wire brush, clean slip inserts and an area of pipe without insert marks; • Wrap two layers of test paper or mud sack around the cleaned section of pipe. Tape the paper on top and bottom to the pipe; • Place the slips around the pipe and on the paper. Hold the slips in place while the pipe is lowered at normal speed; • After the slips are set, hold them firmly around the pipe as it is raised. The slips should be carefully removed to prevent damage to the paper. Then carefully remove the paper. Observe the inner layer of paper, because the outer will be marked with misleading slip impressions. If full insert contact is indicated, the master bushing and slips are in good condition. No further analysis is necessary. Conversely, absent full contact, the test should be rerun with new slips. If the second test results in full contact, discard the old slips. They are worn, crushed or otherwise distorted. Cut off the toes of discarded slipsto prevent refurbishment

IADC Drilling Manual

Excessive stress placed on slip segments

6 in. Ribs cracked

Figure DS-61: Damage is caused to drill pipe if slips of the wrong size are used. and reuse. If the results of the second test indicate top contact only, the master bushing and/or bowls are worn and should be inspected for replacement.

Proper slip handling

Slips should always be the correct size for the pipe. Figures DS-61 and DS-62 show the effects of using the wrong size slip in tubular goods. Slips that are smaller than the pipe will damage the pipe and the corners of the slips as well as increase the risk of dropping a string of pipe. Slips that are too large will not contact the pipe all the way around and will also increase the risk of dropping the pipe and destroying

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DRILL STRING

Pipe and collars larger than the slips rapidly wear down the outer edges of the gripped elements with damage as shown below. If slips are used on overly large drill-stem elements, the same slips will quickly damage smaller pipe of the correct size. This is due to reduced contact surface of the gripping elements. Using slips for brakes can cause:

4 1/2 in.

Deformed bodies

• Swedges and elongates pipe in slip area; • Stretches and bottlenecks pipe; • Transmission of excessive load to rotary table and master bushing or slip bowl. Do not let the slips “ride” on the pipe while it is being pulled out of the hole. This practice accelerates wear on the slip’s gripping elements. It also might cause the slip to be ejected from the rotary bowl when a tool joint comes through, with possible injury to personnel.

Figure DS-62: Damage is caused to drill pipe if slips of wrong size are used.

Never re-sharpen inserts. Doing so causes improper contact with the pipe, resulting in both pipe and slip damage, as illustrated in Figure DS-64.

Setting slips on tool joint

Downward Motion

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 if the driller does not pick up high enough for the slips to fall around the pipe properly. See Figure DS-65. This can ruin the slips and damage the tool-joint box and pipe body. B

A

C

Using tongs properly

Tonging tool joints properly is the most important single factor in prevention of tool-joint problems. The appendix provides recommended make-up torques for various sizes, types, and classes of tool joints. Torque-measuring equipment should always be used to prevent under-make-up or over-make-up. Slicker-than-normal thread compounds can contribute to torsional problems. Always use back-up tongs when making up or breaking out drill pipe stands. Without back-up tongs, the pipe may rotate and cause deep slip cuts.

Downward Motion

Figure DS-63: Effects of stopping downward motion of drill pipe with slips.

Avoid using a single tong. Use of only one tong greatly increases the possibility of bending or “hooking” the pipe at the rotary.

the center part of the slips’ gripping surface. The downward motion of the drill pipe must be stopped with the drawworks brakes, not with the slips. Figure DS63 shows the effect of stopping the motion of the pipe with slips. This can occur when the floor hands are not careful to set the slips after the driller has stopped the pipe.

IADC Drilling Manual

Keep the tool joint as close to the rotary table as possible during make-up and breakout. There is a maximum height that a tool joint can be positioned above the rotary slips with the pipe still enabled to resist bending. See Figure DS-66. This is while maximum torque is applied. Factors governing the height limitation are: • Angle of separation between tongs;

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DS–43

New or like-new gripping elements carry concentrated load and deeply penetrate the pipe.

Backs and faces permanently deformed

Resharpened gripping element carries no load. Gripping elements which carry concentrated load are forced into slip bodies resulting in permanent damage to slips.

Figure DS-64: Never use resharpened gripping elements.

• Minimum tensile yield strength of pipe; • Length of the tong handles; • Maximum recommended make-up torque. Although it is not recommended to use as single tong, as discussed above, should a lone tong be used with a locked rotary table, the height of the tool joint should not exceed that shown in Case I of Figure DS-66. In addition, line pull should not exceed recommended make-up torque with tongs at 90° to the jerk line.

Figure DS-65: Try to prevent catching the tool joint accidentally with the slips.

Table DS-15: Section modulus values. Pipe OD, in.

Nominal pipe weight, lb/ft

I/C, cu in.

2-3/8

4.85 6.65 6.85 10.40 9.50 13.30 15.50 11.85 14.00 15.70 13.75 16.60 20.00 22.82 16.25 19.50 25.60 19.20 21.90 24.70 25.20 27.70

0.66 0.87 1.12 1.60 1.96 2.57 2.92 2.70 3.22 3.58 3.59 4.27 5.17 5.68 4.86 5.71 7.25 6.11 7.03 7.84 9.79 10.58

2-7/8 3-1/2

4

Sample Calculations

The height above the rotary table can be calculated using the formulas from Figure DS-66, where: Hmax

Height of tool joint above slips, ft

Ym

Minimum tensile yield of pipe, psi Grade E-75 75,000 Grade X-95 95,000 Grade G-105 105,000 Grade S-135 135,000

LT

Tong arm length, ft (measured on rig)

P

Line pull, lb

4-1/2

5

5-1/2

6-5/8

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DRILL STRING P

Hmax LT

P

P

Hmax

LT

P

Case 1

Case 2

Hmax = .053 Ym LT (I/C) T

Hmax = .038 Ym LT (I/C) T

Figure DS-66: The sketches and formulas show how to calculate the height of a tool joint above the slips.

T

P * LT, make-up torque, Table B1-7

I/C

Section modulus of pipe, in., Table DS-16.

Assume: Premium 4 ½-in., 16.60 lb/ft, Grade E75 drill pipe, with 4 ½-in., XH 6-in. OD, 3 ¼-in. ID tool joints. Tong arm 3 ½-ft

Tongs at 90° Ym = 75,000 psi (for Grade E75) I/C = 4.27 cu in. LT = 3.5 ft T = 12,085 ft-lb

Drill pipe corrosion

One of the most prevalent causes of premature drill stem failures is the damage resulting from corrosion, corrosion fatigue, and sulfide stress cracking. This section will briefly describe the manner in which the damage occurs, how to detect it, and how to control it. However, because of the complexity of the problem and its serious economic and safety effects, expert technical advice should be obtained when such damage is evident or suspected.

Corrosive agents

Corrosion may be defined as the alteration and degradation of material by its environment. The principal corrosive agents affecting drill stem materials in water-based drilling fluids are dissolved gases (oxygen, carbon dioxide, and hydrogen sulfide), dissolved salts, and acids. Oxygen (O2) is the most common corrosive agent. In the presence of moisture, it causes steel to rust, the most common form of corrosion. Oxygen causes uniform corrosion

IADC Drilling Manual

and pitting, leading to washouts, twist-offs and fatigue failures. Since oxygen is soluble in water, and most drilling fluid systems are open to the air, the drill stem is continually exposed to potentially severe corrosive conditions. Carbon Dioxide (CO2) dissolves in water to form carbonic acid, a weak acid that corrodes steel by hydrogen evolution, the same as other acids, unless the pH is maintained above 6. At high pH values, carbon dioxide corrosion damage is similar to oxygen corrosion damage, but progresses more slowly. When carbon dioxide and oxygen are both present, however, the corrosion rate is higher than the sum of the rates for each alone. Carbon dioxide in drilling fluids can originate in the make-up water, gas inflow from a formation, thermal decomposition of dissolved salts, organic drilling fluid additives, or bacterial action on organic material in the makeup water or drilling fluid additives. Hydrogen Sulfide (H2S) dissolves in water to form an acid somewhat weaker and less corrosive than carbonic acid, although it may cause pitting, particularly in the presence of oxygen or carbon dioxide. More significantly, H2S greatly affects a form of hydrogen embrittlement known as sulfide stress cracking. Sulfide stress cracking is dealt with in detail below in this section. Sources of hydrogen sulfide in drilling fluids include makeup water, gas-bearing formation fluid inflow, bacterial action on dissolved sulfates, or thermal degradation of sulfur-containing drilling fluid additives. Dissolved Salts (chlorides, carbonates, and sulfates) increase the electrical conductivity of drilling fluids. Since most corrosion processes involve electrochemical reactions, the increased conductivity may result in higher corrosion rates. Concentrated salt solutions are usually less corrosive than diluted solutions, due to decreased oxygen

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DS–45

solubility. Dissolved salts also may serve as a source of carbon dioxide or hydrogen sulfide in drilling fluids. Dissolved salts in drilling fluids can originate in the makeup water, formation fluid inflow, drilled formation, or drilling fluid additives. Acids corrode metals by lowering the pH (causing hydrogen evolution) and by dissolving protective films. Dissolved oxygen appreciably accelerates the corrosion rates of acids, and dissolved hydrogen sulfide greatly accelerates hydrogen embrittlement. Organic acids (formic, acetic, etc.) can be formed in drilling fluids by bacterial action or by thermal degradation of organic drilling fluid additives. Organic acids and mineral acids (hydrochloric, hydrofluoric, etc.) may be used during workover operations or stimulating treatments.

Factors affecting corrosion rates

Key among the many factors affecting corrosion rates of drill stem materials are: • pH: This is a scale for measuring hydrogen ion concentration. The pH scale is logarithmic, i.e., each pH increment of 1.0 represents a tenfold change in hydrogen ion concentration. The pH of pure gas-free water, is 7.0. pH values less than 7 are increasingly acidic, and pH values greater than 7 are increasingly alkaline, like soap. In the presence of dissolved oxygen, the corrosion rate of steel in water is relatively constant between pH 4.5 and 9.5; but it increases rapidly at lower pH values and decreases slowly at higher pH values. Aluminum alloys however, may show increasing corrosion rates at pH values greater than 8.5; • Temperature: In general, corrosion rates increase with increasing temperature; • Velocity: In general, corrosion rates increase with higher rates of flow; • Heterogeneity: Localized variations in composition or microstructure can increase corrosion rates. “Ringworm” corrosion sometimes found near upset areas improperly heat treated after upsetting is an example of corrosion caused by non uniform grain structure; • High Stresses: Highly stressed areas may corrode faster than areas of lower stress. The drill stem just above drill collars often shows abnormal corrosion damage, partially due to higher stresses and high bending moments.

Corrosion damage

Corrosion can take many forms and may combine with other types of damage (erosion, wear, fatigue, etc.) to cause extremely severe damage or failure. Several forms of corrosion may occur at the same time, but one type will usually predominate. Knowing and identifying the forms of corrosion

IADC Drilling Manual

Figure DS-67: Example of a washout caused by pitting corrosion. can be helpful in planning corrective action. The forms of corrosion most often encountered with drill string are: • Uniform or General Attack: During uniform attack, the material corrodes evenly, usually leaving a coating of corrosion products. The resulting loss in wall thickness can lead to failure from reduction of the material’s load carrying capability; • Localized Attack (Pitting): Corrosion may be localized in small, well-defined areas, causing pits. See Figure DS-67. Their number, depth, and size can vary considerably, and they might be obscured by other corrosive effects. Pitting is difficult to detect and evaluate, since it can occur under corrosion products, mill scale and other deposits; in crevices or other stagnant areas; in highly stressed areas, etc. Pits can cause washouts and can serve as points of origin for fatigue cracks. Chlorides, oxygen, carbon dioxide, and hydrogen sulfide, especially in combination, are major contributors to pitting corrosion; • Erosion-Corrosion: Many metals resist corrosion by forming protective oxide layers or tightly adherent deposits. If these films or deposits are removed or disturbed by high velocity fluid flow, abrasive suspended solids, excessive turbulence, cavitation, etc., accelerated attack occurs at the fresh metal surface. This combination of erosive wear and corrosion may cause pitting, extensive damage and failure: • Fatigue in a Corrosive Environment (Corrosion Fatigue): Metals subjected to cyclic stresses of sufficient magnitude will develop fatigue cracks that may grow until complete failure occurs. The limiting cyclic stress that a metal can sustain for an infinite number of cycles is known as the fatigue limit. See Figure DS-68. In a corrosive environment, no fatigue limit exists since failure will ultimately occur from corrosion, even in the absence

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DRILL STRING

Stress, psi

as soon as possible, and the elapsed time between collection and analysis reported. See ASTM (American Society for Testing Materials) D3370, Standard Practices for Sampling Water from Closed Conduits, for guidance on sampling and shipping procedures.

45,000

40,000

35,000

30,000

In Air 25,000

In S

alt W

ater

20,000

15,000 0

2,000,000

4,000,000

6,000,000

8,000,000

10,000,000

Number of Cycles of Stress

Figure DS-68: Typical fatigue curves of a steel tested in air and in salt water. of cyclic stress. The cumulative effect of corrosion and cyclic stress (corrosion fatigue) is greater than the sum of the damage from each. Fatigue life will always be less in a corrosive environment, even under mildly corrosive conditions that show little or no visible evidence of corrosion.

Detecting and monitoring corrosion

The complex interactions between various corrosive agents and the many factors controlling corrosion rates make it difficult to accurately assess the potential corrosiveness of a drilling fluid. Various instruments and devices such as pH meters, oxygen meters, corrosion meters, hydrogen probes, chemical test kits, test coupons (corrosion rings), etc., are available for field monitoring of corrosion agents and their effects. The monitoring systems described in API RP 13B-1 (Recommended Practice for Field Testing Water-Based Drilling Fluids) and API RP 13B-2 (Recommended Practice for Field Testing Oil-Based Drilling Fluids) can be used to evaluate corrosive conditions. Pre-weighed test rings (corrosion ring coupons) can be placed in recesses at the back of tool-joint box threads at selected locations throughout the drill stem, exposed to the drilling operation for a period of time, then removed, cleaned and reweighed. The degree and severity of pitting observed and the type of corrosion by-products can help determine corrective action. Chemical testing of drilling fluids should be performed in the field whenever possible, especially for pH, alkalinity, and dissolved gases (oxygen, carbon dioxide, and hydrogen sulfide). See API RP 13B-1 and API RP 13B-2. Laboratory testing: When laboratory examination of drilling fluid is desired, representative samples should be collected in a 0.5- to 1-gal (2- to 4-l) clean container, allowing approximately 1% of container volume for air space and sealing tightly with a suitable stopper. Chemically resisting glass, polyethylene, and hard rubber are suitable materials for most drilling fluid samples. Samples should be analyzed

IADC Drilling Manual

When laboratory examination of corroded or failed drill stem material is required, use care in securing the specimens. If torch cutting is needed, avoid making physical or metallurgical changes in the area to be examined. Specimens must not be cleaned, wire brushed or shot blasted in any manner and should be wrapped and shipped without damaging the corrosion effects or fracture surfaces. Whenever possible, both fracture surfaces should be supplied. Drill pipe coatings: Internally coating the drill pipe and attached tool joints can provide effective protection against corrosion in the pipe bore. In the presence of corrosive agents, however, the corrosion rate of the drill stem OD may be increased. Drill pipe coating is a shop operation in which the pipe is cleaned of all grease and scale, sand or grit blasted to white metal, plastic coated and baked. After baking, the coating is examined for breaks or holidays. Minimizing corrosion in water-based drilling fluids: The selection and control of appropriate corrective measures is usually performed by competent corrosion technologists and specialists. Generally, one or more of the following measures is used, but certain conditions may require more specialized treatments: •  Control the pH. When practical to do so without upsetting other desired fluid properties, the maintenance of a pH of 9.5 or higher will minimize corrosion of steel in water-based systems containing dissolved oxygen. In some drilling fluids, however, corrosion of aluminum drill pipe increases at pH values higher than 8.5; • Use appropriate inhibitors and/or oxygen scavengers to minimize weight loss corrosion. This is particularly helpful with low pH, low-solids drilling fluids. Inhibitors must be carefully selected and controlled, since different corrosive agents and different drilling fluid systems (particularly those used for air or mist drilling) require different types of inhibitors. The use of the wrong type of inhibitor, or the wrong amount, may actually increase corrosion; • Use plastic coated drill pipe. Care must be exercised to prevent damage to the coating. Note: Plastic coating does not prevent sulfide stress cracking; •  Use degassers and desanders to remove harmful dissolved gases and abrasive material; •  Limit oxygen intake by maintaining tight pump connections and by minimizing pit jetting. Close the mud hopper throat valve when not mixing sack material; •  Limit gas-cutting and formation fluid inflow by

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DRILLING FLUID PROCESSING

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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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DRILLING FLUID PROCESSING

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DRILLING FLUID PROCESSING

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 Leon Robinson, PhD, Exxon Production Research Corp emeritus Reviewers Robert Urbanowski, Precision Drilling Corp Charles G. Mangum, Axon Rig Concept and Design

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DRILLING FLUID PROCESSING

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: 978-0-9909049-6-0

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DRILLING FLUID PROCESSING Contents

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CHAPTER FP

DRILLING FLUID PROCESSING

General fundamentals................................................... FP-1 Drilling fluid processing................................................ FP-1 Notes on safety............................................................... FP-1 Drilling fluid properties.................................................FP-2 Benefits of mechanically removing drilled solids..FP-3 Drilling fluid particle sizes and effects.....................FP-3 Methods of controlling drilled solids........................FP-4

Dilution.....................................................................................FP-4

Effect of equipment solids removal efficiency

on clean drilling fluid ..........................................................FP-5 100% removal of drilled solids.........................................FP-5 90% removal of drilled solids...........................................FP-5 80% removal of drilled solids...........................................FP-5 70% removal of drilled solids............................................FP-6 60% removal of drilled solds............................................FP-6

Chemical treatment....................................................... FP-7 Mechanical treatment................................................... FP-7 Mechanical separation: Basics...................................FP-9 Summary of effective mechanical solids control........FP-8

Equipment arrangement...............................................FP-9 Unweighted drilling fluid...............................................FP-9 Weighted drilling fluid.................................................FP-10 Weighted and unweighted drilling fluid processing.. FP-11 Equipment used to remove undesirable material from a drilling fluid.................................FP-11

Flow distributor....................................................................FP-11 Shale shakers........................................................................FP-11 Screening surfaces.............................................................FP-11

Screen labeling..............................................................FP-14 Equipment.......................................................................FP-14 Vibrating mechanism.........................................................FP-15

Main shakers..................................................................FP-15 Triple-deck shakers......................................................FP-16

Contents Maintenance..................................................................FP-17 Wash screens.......................................................................FP-17 Check screens for proper tension..................................FP-17

Degassers.......................................................................FP-19 Effect of gas-cut drilling fluid....................................FP-21 Removing gas bubbles............................................... FP-22 Installation.............................................................................FP-23

Hydrocyclones.............................................................. FP-23 Desilters.......................................................................... FP-25

Maintenance.........................................................................FP-26

Mud cleaners................................................................ FP-26

Installation.............................................................................FP-28

Centrifuges.................................................................... FP-29 Principles of performance......................................... FP-29 Decanting centrifuge.................................................. FP-30 Perforated cylinder centrifuge................................. FP-31 Applications..........................................................................FP-31 Operating tips......................................................................FP-32

Bypass trough............................................................... FP-32

Bypass troughs after the shale shakers........................FP-32

Slug tank......................................................................... FP-34 Trip tanks....................................................................... FP-36 Piping and equipment arrangement....................... FP-36 Fraction of fluid processed..........................................FP-39

Sizing mud systems..................................................... FP-37

Suction section....................................................................FP-37

Surface volumes........................................................... FP-37

Plugged bit method............................................................FP-38 Cased-hole method............................................................FP-38

Lost circulation............................................................. FP-38 Rapid drilling in large diameter holes.................FP-42 Deep drilling with large diameter drillpipe........... FP-40 Sizing steel pits............................................................. FP-40

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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DRILLING FLUID PROCESSING

General fundamentals Drilling fluid maintenance costs, as well as overall well costs, can be reduced dramatically when proper solids control techniques are used. Early drilling operations were mostly in boreholes that could be drilled with water and did not require weighting agents to control high-pressure formations. Solids were simply settled as the drilling fluid passed through a series of pits before being pumped back downhole. This method worked very well for shallow wells which contained no abnormal pressure formations. A drilling fluid which needed to be used in these wells could not allow all of the solids to settle and still retain the heavier mud weights needed to control the abnormally high-pressure. However, the full extent of the impact of retained drilled solids was not really appreciated until the mid to late 1900s. After using the ‘settling method’ for many years, the next innovation in solids control came when shale shakers were introduced in the early 1930s. One of the first shakers was not actually a ‘shaker’ but a rotating drum of very coarse wire mesh. The drilling fluid would force the drum to turn, ejecting some of the solids, and retaining most of the liquid phase (and solids). The mining industry was using a vibrating screen for coal classification and was adopted by drillers to remove more solids and retain most of the weighting material. This machine used an unbalanced elliptical motion to move solids down the screen while forcing the drilling fluid to pass through the screen. After these found success, the hydrocyclones were also adopted from the mining industry and developed during the 1940s for use on drilling rigs. These hydrocyclones spin the fluid inside a chamber causing the solids to be forced against the inside wall of the cone. The next development was the centrifuge during the late 1940s and early 1950s. The centrifuge removes solids smaller than about 10 microns. Drilled solids that were not removed from the drilling fluid when they were large could be removed with the centrifuge. When they become smaller than the size of barite, salesmen frequently incorrectly labeled it as a “barite recovery” device. At this time, there is no equipment available for use on a drilling rig which will separate drilled solids from barite in the same size range. A centrifuge separates particles by mass not species, dimensions or composition. In a weighted drilling fluid, a centrifuge removes small drilled solids and small particles of barite; it recovers barite and drilled solids that are larger than about 10 microns. By the early 1970s shale shakers had developed to the point where screens labeled 60 to 80 mesh were the finest that could be used on rigs. Solids between the finest mesh size opening (250 microns to 180 microns) and the maximum barite size (75 microns) could not be removed from the drilling

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FP-1

fluid. These particles created poor filter cakes and also continued to degrade in to colloidal sizes. The mud cleaner was invented to remove drilled solids in this size range. Desilter hydrocyclones processed the drilling fluid and the underflow (containing these solids) was filtered through a fine screen. A single, four-inch desilter, at that time, could process about 50 gpm, with a 1 gpm underflow. This small flow rate could be processed using fine screens on the shale shakers available at that time. Using mud cleaners reduced the occurrences of stuck pipe and lost circulation. When the linear motion shale shakers were introduced, fine screens could be used which separated solids down below 75 microns. The use of mud cleaners decreased significantly, because the assumption was made that all of the fluid was being processed through the same size screen as the mud cleaner could use. However, to the surprise of many, when mud cleaners were used after processing “all” of the drilling fluid through a “200-mesh” screen, many solids were removed from the drilling fluid. In retrospect, this should have been anticipated. Desilters processing an unweighted drilling fluid would frequently plug with large solids even after passing through screens labeled “80-mesh” or 177 micron openings. The apex of a desilter is many times larger in diameter than 177 microns. This means that these solids bypassed the screen. In current drilling fluid processing, a mud cleaner still removes a large quantity of drilled solids and serves as a ‘back-up’ to the fine mesh screens used on the currently available linear and balanced elliptical motion shale shakers. When these fine screens break, the rig crew does not always quickly detect the break. Frequently, the screen breaks in a region covered by a pool of liquid and it is not visible until a connection is made. A mud cleaner provides insurance that the drilling fluid remains free of the detrimental drilled solids.

Drilling fluid processing The mud tanks on a drilling rig should have three easily identifiable sections: 1) Removal Section; 2) Additions Section and 3) Suction Section. The size of these tanks depends on the drilling rig size. Rigs used to drill very shallow holes may have all of these sections in one or two tanks. Deep wells will require much more drilling fluid and the tank system will be very large.

Notes on safety Design fluid processing areas to be safe. Drilling fluid residue on a steel deck presents an extreme slip hazard. Use serrated steel grating or fiberglass grating with a non-slip surface wherever possible. Non-slip stairway treads are a must. Use properly built hand rails with toe plates along all walkways, stairs and pit tops. Maintain a safe lighting level around all equipment, stairs and walkways. Wash equipment and clean up drilling fluid spills as soon as possible.

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DRILLING FLUID PROCESSING

Eyewash stations and shower(s) should be provided throughout the surface drilling fluid system areas. Proper protective clothing in good condition should always be readily available to those mixing chemicals and they should be worn. Some combination of goggles, dust masks, face shields, rubber gloves and rubber aprons are required depending on the particular chemicals being mixed. Spilled chemicals and bags should be cleaned up quickly and disposed of in a proper manner according to company policy and/or environmental regulations. A responsible qualified person should periodically inspect all electrical devices, electric cable lighting and fittings for physical damage or excessive corrosion. A shock hazard or explosion hazard can exist if this special equipment is not maintained in a proper state. Always use an approved Classified Area electrical device or fitting in an area requiring Division I/Zone I or Division II/Zone lI explosion-proof or vapor tight electrical devices and fittings. The temperature class (T rating) should be considered when selecting lighting and electrical equipment to ensure that equipment is below auto-ignition temperature of any flammable gasses which are likely to be present.

Drilling fluid properties A good drilling fluid should have the lowest possible viscosity when it strikes the bottom of the hole to remove drilled solids created by the drill bit. Then the fluid must have a sufficient viscosity to transport drilled solids out of the bore hole. This change in viscosity is created by having a fluid which changes viscosity with shear rate (Figure FP-1). Viscosity is defined as the ratio of shear stress to shear rate. When the shear stress is expressed in dynes/cm2 and the shear rate in reciprocal seconds, the viscosity has the units of poise. The rheological model normally used on drilling rigs is one of the simplest possible models to describe the relationship between shear stress and shear rate: Shear Stress = (PV) (Shear Rate) + YP,

Eq 1

Eq 2

Eq 3

Viscosity: ft 2 =

CCI =



where PV is the plastic viscosity and YP is the yield point.

The equation is described as a straight line where PV is the slope and YP is the intercept on the Shear Stress axis at zero Shear Rate. This is called the Bingham Plastic rheology model. Mathematically, if the value of Shear Stress is inserted into the definition of viscosity, then Eq 1 is the result. As shear rate gets larger and larger, the last term of the above equation gets smaller and smaller. If the shear rate goes to infinity, the viscosity is equal to the plastic viscosity. So PV is the viscosity the fluid would have at a very high shear rate— such as the shear rate through the bit nozzles. This highshear-rate viscosity (PV) needs to be kept as low as possible to assist with the fluid hydraulic impact or hydraulic power being capable of removing the largest quantity of drilled cuttings. PV is controlled by four factors: liquid phase viscosity, size, shape and number of solids. Transport of drilled solids requires increasing the low-shearrate viscosity of the drilling fluid be sufficient to prevent solids from tumbling in the annulus. Currently, there are guidelines (API RP13D) available that work well for drilling fluid at angles less than the angle of repose of drilled solids in the well—around 35° to 40°. An empirical carrying capacity index (CCI) seems to work well with water-based or Non-Aqueous Drilling Fluid (NADF). (Eq 2). Sharp edge cuttings are discharged from the shale shaker when CCI is equal to one. The “K” in the equation is the viscosity constant in the Power Law rheology model. (Eq 3). The factor of “n” is usually less than ‘1’ for drilling fluids. If n=1, the fluid is said to be Newtonian, where the shear stress increases uniformly with shear rate. This means the viscosity is constant, no matter how fast the fluid is moving. The definition of viscosity is the ratio of shear stress to shear rate. When the shear stress is measured in dynes/sq cm and the shear rate is measured in reciprocal seconds, the

shear stress (PV)(shear rate) + YP YP = = PV + shear rate shear rate shear rate

(mud weight, ppg)(Annular velocity, ft/min)(K,eff.cp.) 400,000

Shear Stress = K (shear rate) n

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FP-3

K-Viscosity: eff cp Plastic Viscosity: cp 2000

5

10

15

20

25

30 35

40

K: eff cp

45

1000

0

0

10

20

30

40

50

Yield Point lb/100 sq ft Figure FP-1: Effective viscosity vs Yield Point..

viscosity will have the units of ‘poise’. With the rheometers used in drilling fluid measurements, the shear stress is measured at two different shear rates. With the concentric cylinder rheometer, the outer cylinder is rotated at 600 rpm or 300 rpm and the shear stress measured in lb/100 sq ft. The plastic viscosity (PV) of the drilling fluid is calculated by subtracting the 300-rpm shear stress (R300) from the 600-rpm shear stress (R600). The yield point of the drilling fluid (YP) is calculated by subtracting the PV from the R300 reading. Multiplying the rpm by 1.7 changes the units to reciprocal seconds. Multiplying the shear rate in lb/100 sq ft by 5.11 will change the units to dynes/sq cm.



Eq 4

n=3.322 x Log (R600/R300)



Eq 5

K= 511(1-n) x (R300)

Usually, the morning report forms will provide the PV and YP of the drilling fluid, not the actual readings. The equations above can be modified for easier use:

Eq 7

K= 511(1-n) x (R300)

Eq 6

n = 3.322 Log 2PV + YP PV + YP

The power law constants of ‘n’ and ‘K’ can be calculated from the equations:

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FP-4

K-Viscosity: eff cp Plastic Viscosity: cp 5

CCI =

10

Solving this equation for the value of K:

1000

K: eff cp

(10 ppg)(K)(65 ft/min) = 1 400,000

800

15

600

20 25

400

K=

400,000 (10.0 ppg)(65 ft/min)

K =615 eff cp

This value of K is shown by the blue circle in Figure FP-1a. If the YP is increased to about 15 lb/100 sq ft, CCI will be about 1.0. This should greatly improve cuttings transport.

200

0

20 10 Yield Point: lb/100 sq ft

Because these equations are somewhat complicated, a graphical solution is provided. The CCI equation (Eq 2) contains an empirical number (400,000) that is an approximation. This value is useful to only one significant figure; consequently, the value of K does not have to be calculated to the nearest decimal value. This means that reading the number from a chart will be sufficiently accurate to provide guidance about what yield point will be needed.

Note: The lowest annular velocity may be in a zone which is washed out, rather than in the casing/drillpipe annulus. In some cases, the CCI has had to be increased to 1.5 instead of 1.0. This also could be caused by the change in rheology of the drilling fluid because of temperature and pressure in the well bore. The yield point is measured at the same temperature daily. The wellbore temperature (and pressure for non-aqueous drilling fluids) changes the low shear rate viscosity. This change depends upon the ingredients in the drilling fluid and cannot be predicted. The empirical value of 400,000 for the constant seems to account for these changes reasonably well. The CCI concept has been field tested and, in most cases, works well. However, the technique simply provides some basic guidelines that should be modified as needed to ensure that the cuttings being transported in wells up to 35° will have sharp edges.

Application: Figure FP-1a: Determining Yield Point needed to clean hole properly.

Calculate the CCI for a 10-ppg drilling fluid with PV = 10 cp and YP = 5 lb/100 sq ft being circulated in a hole where the lowest annular velocity in a well is 65 ft/min. From the Figure FP-1a, K = 130 cp (red circle).

CCI = 0.13

CCI =

(10 ppg)(80 eff cp)(65 ft/min) 400,000

With a value so much smaller than one, the cuttings are not being transported to the surface without tumbling. No cuttings would have edges as thin as fingernails. The YP needs to be increased so that CCI will be equal to one.

Good solids control actually starts at the drill bit. Cuttings made by the drill bit should be removed from the bottom of the hole before the next row of teeth regrind them. This means that the fluid should strike the bottom of the hole with the greatest force or impact possible OR the greatest power possible. Hydraulic optimization is necessary to insure that the cuttings are being removed as quickly as possible. A low plastic viscosity will enhance this. After the cuttings are removed from beneath the drill bit, they need to be brought to the surface without regrinding. The cuttings should have sharp edges on them. This means that they will be as large as possible when they are being processed by the shale shakers. Large solids are easier to remove than smaller ones. A general “rule of thumb” 1 requiring annular velocity to be about 100 to 125 ft/min or higher to carry cuttings out of the wellbore is a good starting point. However, this annular velocity cannot always be achieved in washed-out zones and large diameter risers and casing. For this reason, the low1

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Preston Moore, Drilling Practices Manual, PennWell, 1975, p 229.

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DRILLING FLUID PROCESSING

shear-rate viscosity must be elevated to allow the transport of drilled solids in the vertical and near-vertical sections of the well. The CCI applies only to holes at an angle lower than the angle of repose of solids on the side of the wellbore (usually around 42°).

Benefits of mechanically removing drilled solids a. Raises the founder point of the bit which increases drilling penetration rate; b. Decreases filter cake thickness, which: • • • • •

Reduces drillstring torque and drag; Reduces differentially pressure stuck pipe; Provides better electric logs; Allows cement to fill more of the annulus; Allows casing to be moved during cement placement.

c. Reduces wear of expendables in the drilling fluid system; d. Reduces dilution costs to keep drilled solids concentration within specifications; e. Enhances quality of electric logs; f. Decreases volume of discarded fluid needed when controlling drilled solids with dilution; g. Decreases the cost of building excessive volumes of drilling fluid as required by dilution. From an economical point of view, the drilling benefits of removing drilled solids can be divided into two categories: • Visible nonproductive Time (NPT); • Invisible nonproductive Time (NPT). Stuck pipe is a very visible NPT. The drilling rig cannot drill and must solve the problem by recovering the drillstring (or fish), sidetracking the well, or abandoning the well. The cost of this event is relatively easy to identify. However, drilling with a drill bit, when the bit loading has exceeded to founder point, results in a much lower drilling rate and increases the bit wear. This is an invisible NPT. Removal of drilled solids could increase the ability of the drilling fluid to remove cuttings from below the bit (decreasing plastic viscosity) and increase penetration rates. The question becomes is the rock “harder” or is the bottom of the hole not being cleaned by the hydraulics. Clearly, drilling half as fast as possible and using three bits instead of one in an interval would greatly affect the economics of drilling. The ability to properly cement a well is essential for the life of the well. Leaving a thick filter cake on the formation that cannot be removed by the

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FP-5

cement could result in flow behind casing while the well is being produced. If this is not detected, a significant amount of production could be lost. This would be a large cost for an invisible NPT.

Drilling fluid particle sizes and effects Drilling fluids are classified as water-based or Non-Aqueous Drilling Fluid (NADF). NADF can consist of a diesel oil, a mineral oil or a synthetic fluid (such as polyalpha olefin, esters, ethers or others). With the more frequent use of polycrystalline diamond compact (PDC) bits, more and more NADF are being used now even though it may be more expensive than water. The benefits from wellbore stability and enhancing the action of the PDC bits against the rock creates a less expensive hole even though the cost of the drilling fluid may be higher. The solids phase of any drilling fluid are two basic types: Commercial solids and drilled solids. Not all solids in the colloidal range are detrimental to a drilling fluid system. Some fine particles in the colloidal size range are necessary to build a thin, slick, compressible filter cake. These reduce the probability of differential pressure sticking of the drill string. They also increase the low-shearrate viscosity of the drilling fluid used to transport drilled solids up the vertical (or almost vertical) part of the bore hole. Commercial solids also are used to build a gel structure which suspends the barite and drilled cuttings when the mud pumps are turned off. The different sizes of particles in a drilling fluid have been labeled for ease of communication: • Cuttings: 440 microns and larger; • Sand: 75-440 microns; • Silt: 2–75 microns; • Clay: 0.5–2 microns; • Colloids: less than 0.5 microns . Note: 0.001 in. = 25.4 microns A sand-size particle refers to the effective diameter of the particle NOT the material. In other words, barite particles larger than 75 microns would still be called “sand” in a drilling fluid report. These large particles in a filter cake would be detrimental to the filter cake quality. Particles larger than 75 microns should be removed from the drilling fluid even if they are diamond, gold, silver, barite or pearls. They destroy the filter cake quality. Too many small particles are also not desirable in a filter cake. Drilled solids should be removed the first time they are circulated to the surface or they will eventually degrade to colloid sizes by continuous circulation through the mud pumps, drill

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DRILLING FLUID PROCESSING

Dilution

Drilled solids can be controlled by removing some of the ‘dirty’ drilling fluid and replacing the volume with clean drilling fluid containing no drilled solids. This is an expensive method. Figure FP-2A: 2,000 bbls drilling fluid containing 200 bbl of drilled solids or 10% volume.

Figure FP-2B: 1,000 bbl drilling fluid discarded leaving 1,000 bbl of drilling fluid containing 10% volume drilled solids.

Figure FP-2C: After dilution, the drilling fluid once again contains only 100 bbl of drilled solids for the 2,100 bbl.

pipe, bit jets, bit teeth, etc. As an example,one particle having a diameter of 100 microns will become 125,000 particles, with a diameter of 2 microns and require 50 times as much liquid to coat the surface of this same mass of drilled solids without any reduction in solids concentration. This thickening process, occurring without an absolute increase in solids concentration, increases the plastic viscosity and is responsible for poor wall cakes. High plastic viscosity is very detrimental to the entire drilling process and is an economic burden. Adding more of the liquid phase to the system reduces the concentration of those solids, thus reducing the plastic viscosity. Removal of drilled solids during the early circulation stages with solids removal equipment at the surface is much simpler and less expensive. Obviously, these benefits are the result of planning prior to drilling a well and are accomplished through the use of properly designed, sized and operated solids removal equipment. The drilling crew has an obligation to become knowledgeable in the proper use of the equipment: otherwise, its potential benefits may be reduced or nullified.

Methods of controlling drilled solids

For example, envision 2,000 barrels of drilling fluid in a well and in the mud tanks collected into a single tank (Figure FP-2A). Assume the drilling fluids specifications require 5% volume drilled solid (which would be 100 bbl). After drilling 1,250 ft of a 9 7/8 in.-hole without removing any drilled solids, the volume of drilled solids would increase by about 100 bbl of solids if the formation had 15% porosity. This would double the volume of drilled solids in the system. To meet the required drilling fluid specification of 5% volume drilled solids, one half of the drilling fluid must be discarded. If clean drilling fluid is now added to the system, the 10% by volume of drilled solids in the 1,000 bbl (or 100 bbl of drilled solids) will now be spread throughout the drilling fluid system of 2,100 bbl. The new hole volume has increased by 100 bbl. This meets the specifications for the drilling fluid as required by the drilling program. If the drilling fluid costs only $20/bbl, the cost of decreasing solids in this manner is prohibitive (Figure FP-2B). After drilling only 1,250 ft of new hole, 1,000 bbl of drilling fluid must be discarded to bring the drilled solids back into a reasonable value. A lower concentration of drilled solids would be better but far too expensive when dilution is used to control drilled solids. Two costs are associated with this process: the cost of the new drilling fluid (1,000 bbl) and the cost of disposal of the dirty 1,000 bbl discard. With drilling fluid costs ranging from $30 to $600 per barrel, the cost would be prohibitive to use this method of solids control except for the cheapest of the cheap drilling fluids. Because it is so expensive, a compromise is frequently made to allow the drilled solids to increase to levels above 10% to 12% by volume (Figure FP-2C). Frequently, when the solids control equipment is inadequate or, more often, plumbed incorrectly, the drilled solids will increase somewhat more slowly. If the target drilled solids concentration can be raised to a much higher concentration, less drilling fluid needs to be used to meet the specifications. The NPT (visible and invisible), however, will notice the relaxation of the stringent requirements. The out-of-pocket money for treating the drilling fluid will be lower but the total cost of the well (and long-term effects) will be significantly higher.

a. Dilution of drilling fluid; b. Chemical treatment; c. Mechanical removal of drilled solids.

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6

90% removal of drilled solids

Ratio of Dilution Volume to Volume Solids Drilled

Again drill 100 bbl of drilled solids. In this case, 90 bbl of drilled solids would be discarded and 10 bbl of drilled solids would remain in the drilling fluid.

5 4

Volume of discarded drilled solids = (0.35) (volume of discard) 90 bbl = (0.35)(volume of discard) Volume of discard = 257 bbl Ratio of volume of discard to volume drilled solids = 2.57

3 2 1 0

FP-7

0

20 40 60 80 100 Equipment Solids Removal Efficiency: %

Figure FP-3: Calculations for five different equipment solids-removal efficiencies indicate that discard volume rises rapidly after reaching a minimum value.

Effect of equipment solids removal efficiency on clean drilling fluid needed This is a theoretical analysis of the effect of equipment solids removal efficiency and concentration of drilled solids in the discard stream. For these calculations, 100 bbl of drilled solids will report to the surface. The target drilled solids concentration is 8% by volume. See Figure FP-3.

100% removal of drilled solids

If this could be accomplished and the drilled solids were 35% volume of the discard, the discard volume could be calculated: Volume of discarded drilled solids = (0.35)(volume of total discard) Assume 100 bbl of drilled solids arrive at the surface. If all are discarded, the total volume of discard would be: 100 bbl = (0.35)(volume of total discard) Volume of discard = 286 bbl The ratio of discarded volume to volume of drilled solids removed would be 2.86. In other words, for every barrel of drilled solids removed from the drilling fluid system, 1.86 bbl of drilling fluid would accompany the one barrel of drilled solids. The pit levels would drop by 286 bbl during this period and must be added to the active system to keep the pit levels constant. The concentration of drilled solids would decrease from 8% volume to a lower number (depending upon the volume of drilling fluid in the active system). The addition of 296 bbl of clean drilling fluid will reduce the drilled solids concentration because the 186 bbl of drilling fluid discarded with the 100 bbl of drilled solids would contain 15 bbl of drilled cuttings. This reduces the total drilled solids in the drilling fluid.

IADC Drilling Manual

In this case, 90 bbl of drilled solids and 167 bbl of drilling fluid would be discarded; or a total of 257 bbl would be required to keep the pit levels constant. The remaining solids would need to be diluted with clean drilling fluid. Drilled solids = (0.08)(dilution volume) Dilution volume = 10 bbl/0.08 = 125 bbl The dilution volume would consist of 10 bbl of drilled solids and 115 bbl of clean drilling fluid. Since 257 bbl would be required to keep the pit volumes constant and only 115 bbl would be needed to keep the pit levels constant, the total drilled solids in the active system would decrease.

80% removal of drilled solids Again drill 100 bbl of drilled solids. In this case, 80 bbl of drilled solids would be discarded and 20 bbl of drilled solids would remain in the drilling fluid. Volume of discarded drilled solids = (0.35) (volume of discard) 80 bbl = (0.35)(volume of discard) Volume of discard = 229 bbl Ratio of volume of discard to volume drilled solids = 2.29 In this case, 80 bbl of drilled solids and 149 bbl of drilling fluid would be discarded; or a total of 229 bbl would be required to keep the pit levels constant. The remaining solids would need to be diluted with clean drilling fluid. Drilled solids = (0.08)(dilution volume) Dilution volume = 20 bbl/0.08 = 250 bbl The dilution volume would consist of 20 bbl of drilled solids and 230 bbl of clean drilling fluid. Since 250 bbl would be required to keep the pit volumes constant and only an additional 7 bbl would be needed to keep the pit levels constant, the total drilled solids in the active system would be almost balanced. That is the volume of clean drilling fluid needed would be almost exactly the volume which was discarded from the active system.

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DRILLING FLUID PROCESSING

Optimum Solids Removal Efficiency = Eq 8

(1-Target Drilled Solids Conc in Drilling Fluid) 1-Target Drilled Solids Conc + (Target Drilled Solids Conc)(Drilled Solids Conc in Discard)

Assume the drilled solids concentration in the discard is 35% volume and the target drilled solids concentration is 8% volume. Optimum Solids Removal Efficiency =

(1– 0.08) 1– 0.08 + (0.08/0.35)

70% removal of drilled solids Again drill 100 bbl of drilled solids. In this case, 70 bbl of drilled solids would be discarded and 30 bbl of drilled solids would remain in the drilling fluid. Volume of discarded drilled solids = (0.35) (volume of discard)

= 0.80

Volume of discarded drilled solids = (0.35) (volume of discard) 60 bbl = (0.35)(volume of discard) Volume of discard = 171 bbl Ratio of volume of equipment discard to volume drilled solids = 1.71

70bbl = (0.35)(volume of discard) Volume of discard = 200 bbl Ratio of volume of equipment discard to volume drilled solids = 2.0 In this case, 70 bbl of drilled solids and 130 bbl of drilling fluid would be discarded; or a total of 200 bbl would be required to keep the pit levels constant. The remaining solids would need to be diluted with clean drilling fluid.

Drilled solids = (0.08)(dilution volume) Dilution volume = 30 bbl/0.08 = 375 bbl The dilution volume would consist of 30 bbl of drilled solids and 345 bbl of clean drilling fluid. Since 200 bbl would be required to keep the pit volumes constant, an additional 175 bbl would be needed to dilute the remaining drilled solids to the targeted value of 8% volume. Only a volume of 200 bbl is available after the solids removal equipment has discarded the 70% volume of solids arriving at the surface and the liquid associated with the cuttings. The actual discard would be the 200 bbl from the equipment and an additional 175 bbl to allow the remaining drilled solids to be diluted to the targeted value of 8% volume. This means that the ratio of actual volume of discard to the volume drilled would be (200 bbl + 175 bbl)/100 bbl or 3.75.

60% Removal of drilled solids Again, drill 100 bbl of drilled solids. In this case, 60 bbl of drilled solids would be discarded and 40 bbl of drilled solids would remain in the drilling fluid.

IADC Drilling Manual

In this case, 60 bbl of drilled solids and 111 bbl of drilling fluid would be discarded; or a total of 171 bbl would be required to keep the pit levels constant. The remaining solids would need to be diluted with clean drilling fluid. Drilled solids = (0.08)(dilution volume) Dilution volume = 40 bbl/0.08 = 500 bbl The dilution volume would consist of 40 bbl of drilled solids and 460 bbl of clean drilling fluid. Since 111 bbl would be required to keep the pit volumes constant, an additional 349 bbl would be needed to dilute the remaining drilled solids to the targeted value of 8% volume. Only a volume of 111 bbl is available after the solids removal equipment has discarded the 70% volume of solids arriving at the surface and the liquid associated with the cuttings. The actual discard would be the 111 bbl from the equipment and an additional 349 bbl to allow the remaining drilled solids to be diluted to the targeted value of 8% volume. This means that the ratio of actual volume of discard to the volume drilled would be (171 bbl + 349 bbl)/100 bbl or 5.0. The information just calculated for the five different equipment solids removal efficiencies indicates that the volume of discard rises rapidly after it reaches a minimum value. In this case, with 35% volume of drilled solids in the discards and a targeted drilled solids concentration of 8% volume, the optimum solids removal efficiency is around an 80% removal efficiency. This optimum value of removal efficiency for various targeted drilled solids concentrations and drilled solids concentration in

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FP-9

2. Fine Screen Shaker: 75 microns and larger (weighted drilling fluids). 44 microns and larger (unweighted drilling fluids); 3. Mud Cleaner: 75 microns and larger (weighted fluids). 44 microns and larger (unweighted fluids); 4. Desanders: 100 microns and larger; 5. Desilters: 15 microns and larger;

Solids removal efficiency Figure FP-4: This series of curves reveals how rapidly dilution volume increases with poor removal efficiency.

the discarded slurry should be calculated from the equation: If the same analysis is performed for other solids removal efficiencies and other values of targeted drilled solids concentrations, a series of curves reveals how rapidly the dilution volumes increase with poor removal efficiencies (Figure FP-4). As the requirement for a clean drilling fluid decreases (i.e., going from a 4% volume drilling fluid to a 12% volume drilling fluid), the volume of dilution decreases markedly. This, however, simply means that the drilling fluid cost will decrease while the well costs rise rapidly.

Chemical treatment Chemical treatment of a water-based drilling fluid for solids removal involves adding a “flocculant” to the drilling fluid; This causes extremely small solids to agglomerate together so they can be removed mechanically or allowed to settle by gravity in the mud tanks. Normally, a flocculant is used in conjunction with mechanical treatment. For example, flocculants can be added at the flow line to increase the particle sizes so they can be removed with the shaker screen. Flocculants are also added to drilling fluid being processed by a centrifuge. The low-shear-rate inside of the centrifuge prevents the flocculated particles from separating and this makes an effective tool for decreasing the concentration of very small particles.

Mechanical treatment

6. Centrifuge: 5–10 microns and smaller (weighted drilling fluids); 5–10 microns and larger (unweighted drilling fluids). Each piece of mechanical equipment is effective within a certain particle size range. Shale shakers separate by the size of the particles; the other devices which use centrifugal force for separation separate by mass of the particle. Using all of the equipment listed above throughout a drilling program will produce maximum benefits without overloading any one piece of equipment. None of the above items will take the place of another piece of equipment; however no piece of equipment operating at optimum efficiency should cause downstream equipment to become overloaded. In some wells, depending upon the size of the drilled solids, the mud cleaner or the centrifuge might not be needed. Removing solids from spud of a drilling operation is a first priority in solids control as it is much easier to remove one particle 100 microns in diameter with a fine screen shaker than it is to attempt to remove 125,000 particles of 2 micron size with a centrifuge. In unweighted drilling fluids, the fine screen shakers and desilters are generally used until the point of adding barite for weight-up. If only coarse screens (API 80) can be used on the main shaker, the desander is needed to prevent solids overload in the desilters. With fine screens (API140 and up) the desanders are not needed. Centrifuges can be used to increase drilled solidsremoval, although this is not common. With weighted drilling fluids, fine screen shakers, mudcleaner sand centrifuges are used.

This is the method of mechanically removing solids using shale shakers, desanders, desilters, mud cleaners and centrifuges. Each piece of equipment generally limited to the following range of particle removal:

Mechanical separation-basics

1. Scalping Shale Shaker: 440 microns and larger;

Shakers are vital to solids control and should process all of the drilling fluid returning through the flow lines. A standard scalping shaker performs adequately for small rigs oper-

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Mechanical separation equipment employs mass differences, size differences, or a combination of both to selectively reject undesirable solids and retain desirable solids in a drilling fluid.

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DRILLING FLUID PROCESSING

ating at shallow depths with low solids native drilling fluid, however, fine screen shale shakers are generally more efficient and remove more drilled solids. The desanders and desilters are located directly downstream from the shale shaker. They should be sized to process at least 110% to 125% of the rig circulation rate while discarding undesirable cuttings and solids larger than around 20 microns. The desander removes the majority of the solids down to the 75 micron size range and prevents the desilter from being overloaded. The desilter removes the majority of solids down to around the 15 micron range, in an unweighted drilling fluid. When fine screens are mounted on the main shakers (above API140), desanders are not needed. In a weighted drilling fluid, desilters remove much larger solids and do not remove the very small sizes. Liquid loss from desanding and desilting an unweighted drilling fluid is relatively insignificant compared to the amount of drilling fluid that must be removed from the mud tanks to eliminate the same amount of solids. Attempts to recover the liquid phase results in the recovery of very fine colloidal solids and is not recommended. When drilling with a weighted drilling fluid, the desander and desilter cannot be used economically because they discard too much of the valuable barite. Therefore, fine screen shakers and mud cleaners are used to remove solids down to 75 microns. The mud cleaner will remove solids which have bypassed the main shaker screens and keep all retained solids to sizes less than ‘sand’ (or 75 microns). This is essential to provide the correct ingredients in the drilling fluid to form good, thin, slick, compressible filter cakes. Colloidal solids will continuously increase in a drilling fluid. This increases the plastic viscosity, decreases filter cake quality, and is detrimental to drilling performance. In a weighted drilling fluid, centrifuges are used to remove solids smaller than 5 to 10 microns. [It is not used to recover anything but is used like all solids control equipment to eliminate drilled solids without discarding all of the drilling fluid.] Only a fraction of the drilling fluid is processed with each circulation, because the filtration additives and the low-shear-rate modifiers are also removed with the colloidal material. These must be added back to the drilling fluid when centrifuges are used.

Summary of effective mechanical solids control a. Obtain solids removal equipment from reputable manufacturers and size it to process drilling fluid at the manufacturer’s recommended capacity. Except for shale shakers and centrifuges, the process rate

should be 110 to 125% of the flow rate entering the suction tank of the equipment. b. Remove as many drilled solids as possible the first time they are circulated to the surface. c. Do not bypass the shale shaker or other equipment, if at all possible. d. Use the smallest screen openings possible on the shale shakers. e. Maintain an adequate inventory of recommended spare parts. f. Assign rig personnel on each tour to be responsible for equipment operation and maintenance. g. Any drilling fluid brought to a rig should be added to the mud tanks through the shale shaker. h. Sufficient shaker capacity should be available to process the entire top-hole flow rate.

Equipment arrangement All drilling fluid systems should have three easily identifiable sections: A removal section, an addition section and a suction section (Figure FP-5). This includes rigs mounted on the back of trucks and the largest deepwater drilling rigs. The sections, obviously, do not have to be the same size for all of these rigs. A small drilling fluid system might have only two mud tanks divided into compartments. The larger rigs might have several mud tanks in the suction section.

Unweighted drilling fluid For unweighted drilling fluid, the first option is the ‘gumbo’ slide. When drilling very young (geologically speaking) formations containing a lot of clay, the clay tends to form large rings/balls or agglomerations as it moves up the wellbore. Inhibitive drilling fluids with good carrying capacity tend to mitigate this. However, a gumbo slide can remove these large masses of sticky clay before they reach the next shaker. The next shaker is called a ‘scalping’ shaker and usually has a very coarse screen mounted on it. Gumbo will not easily be transported off the end of a linear motion or a balanced elliptical motion screen. The fluid then is processed through the main shaker which should have very fine screens to remove as many drilled solids as possible. See Figure FP-6. Below the main shaker can be a sand trap. This is very effective only if coarse screens are mounted on the main shaker

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DRILLING FLUID PROCESSING

ADDITION SECTION

REMOVAL SECTION

FROM WELL

WELL

TO WELL

SUCTION / SLUG / PILL SECTION

Figure FP-5: All drilling fluid systems hould have three easily identifiable sections: removal, addition and suction.

and no fine screen shakers are available. Solids settle in this compartment and are discarded frequently. Recently, however, the low-shear-rate viscosity of drilling fluid has been elevated to assist in transporting cuttings to the surface. The solids do not settle rapidly in transit in the wellbore because of this viscosity. The residence time in the sand trap is short and very few solids will settle. If fine screens are mounted on the main shaker, the settling rate of solids smaller than 75 microns is very low. Many rigs are now eliminating the sand trap when sufficiently fine screens can be mounted on the main shakers. The fluid passing through the shaker screen may have gas in it. Centrifugal pumps cannot pump gas-cut drilling fluid

very effectively. The gas tends to accumulate in the center of the impeller and eventually vapor locks the pump. If gas does enter and collect in a centrifugal pump, cavitation bubbles destroy the pump impeller. Since centrifugal pumps are needed to process the drilling fluid, a good degasser is necessary. A vacuum in the chamber causes atmospheric pressure to push fluid into the degasser. The fluid flows down some baffle plates and the gas does not have to travel a long distance to enter the vacuum chamber. A jet pump is used to cause the fluid to leave the degasser and flow into the next compartment. The fluid driving the jet pump removing fluid from the degasser is from a centrifugal pump getting its fluid from a compartment of degassed drilling fluid downstream from the vacuum degasser. A bank of desanders is needed to decrease the solids loading of the desilters. These were necessary before the advent of the linear motion or the balanced elliptical motion shakers were available. If API 140, or finer, screens are mounted on the main shaker, they will remove the solids that were normally removed by the desanders. In this case, the desanders are no longer needed and can be deleted along with the related desander suction tank. A centrifuge is used as if it is a super-desilter. The heavy (or underflow) slurry is discarded and the light (or overflow) slurry is retained. This eliminates solids which are larger than about 10 microns for the fluid processed. All solids Slug Tank

Gumbo Slide

To Well

Mud Guns Suction Section

To Trip Tank

Scalping Shaker

By-Pass Through Main Shaker

agitator

Sand Trap

Removal Section

Addition Section

Figure FP-6: Tank arrangement for unweighted drilling fluid.

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FP-11

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FP-12

Flow From Well

Slug Tank

Gumbo Slide

To Well

To Trip Tank

Mud Guns Suction Section

Scalping Shaker

Main Shaker

agitator By-Pass Trough

Sand Trap Mud Cleaner

Removal Section

Addition Section

Figure FP-7: Tank arrangement for a weighted fluid is very similar to that for unweighted fluids.

removal equipment except the centrifuge should process about 110 to 125% of the flow rate pumped downhole. The hydrocyclones and the degasser should process more fluid than is entering the suction tank of that equipment. This is discussed in depth in another section of this chapter.

Weighted drilling fluid A weighted drilling fluid is defined as a drilling fluid which contains commercial additives to increase the drilling fluid density. Usually, barite is added to increase the mud weight. There is currently no rig equipment available which will separate barite from drilled solids. Consequently, the drilled solids roughly in the same size range as the barite cannot be removed. See Figure FP-7. The tank arrangement for a weighted drilling fluid is almost identical to the tank arrangement used for unweighted drilling fluid. The primary difference is the economic restriction of discarding all of the desilter underflow. To retain the barite in the desilter underflow, a screen is mounted on a shaker to allow all of the barite and some drilled solids to return to the active system. The screen discard will have some large barite particles (that are undesirable) and mostly drilled solids. This equipment is called a mud cleaner. When the linear motion shale shakers were introduced and

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API 170 or API 200 screens could be used on the main shaker, mud cleaners were deemed as superseded by the new technology. After a period of time, mud cleaners became popular again because all of the drilling fluid is not always processed through the main shaker. This should have been obvious with the experience of finding desilters plugged with solids which are much larger than the screen openings.

Weighted and un-weighted drilling fluid processing In both active systems, all tanks are stirred except the sand trap (if used). Agitators are recommended instead of mud guns in the removal section. Mud guns in the removal section add the volume of fluid that is entering a removal compartment which would need additional solids removal capacity for the additional flow rate. Both mud guns and agitators should be used in the additions and suction section. The additions section should be well blended with the suction section. All fluid in both sections should be homogeneous in terms of mud weight and rheology. Slug tanks are used to blend slurries to be used as sweeps through the well, or when mixing a pill to be spotted, or when tripping pipe. A heavy weight drilling fluid is placed in the upper part of the drill string before pulling pipe from the hole during a trip. This keeps the liquid level in the drill pipe below the rig floor and prevents drilling fluid from

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FP-13

1/2 inch

1/2 inch

DRILLING FLUID PROCESSING

1/2 inch

1/2 inch

Figure FP-9: Two versions of a 20-mesh screen. The screen on the left will handle higher flow rates, but the right-hand screen will remove more drilled solids.

1/2 inch

Figure FP-8: Flow distributors are installed in the flow line when multiple main shakers are used. Courtesy Derrick Equipment Co.

splashing onto the rig floor and people. Calculation procedures to determine the volume and/or mud weight of the slug are presented in the section after the solids removal equipment is described.

1/2 inch

Equipment used to remove undesirable material from a drilling fluid Flow distributor The details of the equipment will be discussed next. When multiple main shakers are used, a flow distributor (Figure FP-8) will be inserted in the flow line to provide each shaker with the correct (equal) amount of drilling fluid. The flow from the well enters the distribution chamber at point 1. From there, the fluid overflows into each outer compartment to ensure separate and equal flow to each main shale shaker.

Shale shakers When drilled cuttings exit the well, they should be removed as quickly and as efficiently as possible. Shakers are used first to remove particles larger than the openings in the shaker screen. Particles smaller than the openings in the screen pass through the holes of the screen along with the liquid phase of the drilling fluid. Particles too large to pass through the screen are separated from the drilling fluid for disposal. Basically, a screen acts as a “go-no-go” gauge: Either a particle is small enough to pass through the screen opening or it is not. The drilled solids which are removed are not dry, of course. Consequently some drilling fluid is lost with the cuttings.

Screening surfaces Screening surfaces used in solids control equipment are generally made of woven wire screen cloth, in many different sizes and shapes. The screen cloth used on shale shak-

IADC Drilling Manual

Figure FP-10: Not all screens feature openings of identical dimensions in both directions. This screen has 16 openings/in. in one direction and 20 in the other.

ers has changed significantly during the past several years. At one time, the screens were defined by the mesh size. When all of the screens had square openings and were all made from the same diameter wire, this was a very efficient way of describing screen cloth. When different diameter wires were used, this description failed to indicate what size particles would pass through the screen. Two screen wires with 20 openings/in. in each direction would be called 20-mesh screens (Figure FP-9). The performance on a shale shaker, however, would be significantly different. The screen on the left would be able to handle a larger flow rate of drilling fluid than the screen on the right. The screen on the right would remove more drilled solids than the screen on the left. Clearly, designation by screen mesh would not be descriptive of actual performance here. The screening industry started making screens where the openings were not the same dimension in each direction. These screens with oblong openings and were designated with one number which was the sum of the openings in each direction. This screen has 16 openings/in. in one direction and 20 openings/in. in the other direction and would have been called an oblong 36 (Figure FP-10). The screen designation then became even more confusing when one screen was placed on top of another screen (Figure FP-11). The opening sizes were no longer uniform in either direction. If the oblong screen was placed on top of the square mesh screen in drawings above, the opening sizes of

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DRILLING FLUID PROCESSING

Figure FP-11

Figure FP-11: Setting screens of differing meshes atop one another caused further nomenclature confusion.

this layered screen cannot be described by using the ‘mesh’ concept. The API formed a committee of experts to address this problem and attempt to describe shaker screens. At first, this committee wanted to develop a performance test that could be used to predict behavior of these screens on a drilling rig. This was soon deemed impractical because too many variables affect performance. The next quest was to provide some method of describing screens that would be capable of providing a fair comparison between different vendors. Finally, the decision was made to describe the largest particle that would be returned to the drilling fluid. A distribution of openings was not definitive enough. The distribution of opening sizes had been used earlier because the curves resembled a ‘cut-point’ curve. However, solids did not select openings which were exactly their size. Small solids pass through the large openings along with the larger solids. After several tests, the committee finally evolved a test method that could give repeatable results in several laboratories. A small amount of aluminum oxide grit in a variety of sizes is placed on a screen sample. The screen sample is shaken with a vibrator for ten minutes and the largest particle which passes through the screen is determined. This became the recommendations in API RP 13C and is now used widely to compare shaker screens. To determine the size of a screen’s maximum opening, it is mounted in a disc and placed in a RoTap machine with two ASTM standard screens above and two standard screens below it (Figures FP-12 and -13). A known quantity of various size grit is placed on the top screen, and the screen is shaken for 10 min. By weighing the grit on each screen, the size of the maximum opening can be determined. This is explained in great detail in API RP 13C. Several grits were tested by the API committee, and the grit which gave reproducible results was aluminum oxide. Under a microscope, the aluminum oxide grit looks almost like shale cuttings that arrive at the surface when the cuttings are being properly transported to the surface.

IADC Drilling Manual

Figure FP-12 (top) shows a RoTap used to test different-sized screens to determine the size of the maximum opening. Aluminum oxide (Figure FP-13) gave reproducible results.

To sieve the aluminum oxide grit, the ASTM E-11 Wire Cloth Standard was adopted, Table FP-1. This lists the opening size for screens in metric units—either millimeters or microns. Since this was going to be an international standard and metric units would be used, the concept of openings per inch could not be used. However, the standard had the ‘mesh’ designation listed as an alternative designation. API RP 13C used this number as the ‘API Number’. This meant that the labels on the screens would have familiar units for the rig hands—even though they were no longer “mesh”. The only screen sizes will therefore be only those sizes listed in the E-11 Specification. There will be an API 170 or an API 200 screen but there can be no API 175 or API 210 screen if they are labeled according to the procedures listed in API RP 13C. Perhaps not surprisingly, several vendors had drastic changes that needed to be made in their labeling. But, the procedure outlined in API RP 13C levels the playing field for vendors. This procedure will clearly describe the opening sizes of the screens but it does not, nor is it intended to, predict performance of the screen. For screen designation, API RP 13C also describes the nonblocked area of the screen. Attempts were made to try to identify the open area of a screen that is not blocked by wire. This would be a very difficult problem with the fine screens currently used. Instead, API RP13C recommends reporting the area of the screen which is not blocked with panels or adhesives. All openings in a panel or a screen are measured

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FP-15

Table FP-1: Partial List of ASTM E-11 Wire Cloth Standard Test Sieves Standard mm

API number

Permissible variation+/-mm

Maximum openings for 5% mm

Maximum individual opening mm

2.36

8

0.080

2.515

2.600

2.00

10

0.070

2.135

2.215

1.70

12

0.060

1.820

1.890

1.890

16

Microns

0.045

1.270

1.330

Microns

Microns

Microns

850

20

35

925

970

710

25

30

775

819

600

30

25

660

695

500

35

20

550

585

425

40

19

471

502

355

45

16

396

426

300

50

14

337

353

250

60

12

283

306

212

70

10

242

263

180

80

9

207

227

150

100

8

175

192

125

120

7

147

163

106

140

6

126

141

90

170

5

108

122

75

200

5

91

103

63

230

4

77

89

53

270

4

65

89

45

325

3

57

76

38

400

3

48

66

and summed to provide the area of the total screen available for sieving. API RP 13C recommends that the conductance of the screen be included in the screen description. Screen conductance describes the flow capacity of a screen. Conductance is defined as the permeability of the screen divided by the screen thickness. Darcy’s Law, Eq 9, is used to determine the permeability of screens:

Eq 9

q=

K(Δp·A) µ·L

Next, solve Darcy’s law for the permeability per unit length, or conductance, C:

Eq 10

C=

Conductance C is usually reported in kilodarcys per millimeter; Conductance of a screen is determined by measuring the flow rate of a Newtonian fluid with a known viscosity, flowing through a shaker screen, with a measured area perpendicular to the flow, and a known pressure drop. Motor oil was selected as the fluid to be used for conductance measurements because it was viscous enough to flow at a slow rate and it also contains ingredients which would make the screen oil-wet. The screen wires must be wet with the fluid used in the test. The flow rate through the screen must be laminar to provide a reproducible number. Therefore, the velocity should be maintained below a range of 2 cm/sec to 3 cm/sec (around 1 in./sec).

K µ·q = L Δp · A

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FP-16

Oil Reservoir

Adjustable Valve Flow Diverter Test Screen

Figure FP-15a: Screen label, style #1.

API 170

Catch Pan

(92 microns) Conductance: 1,4 kD/mm Non-blanketed Area: 7,23 ft² Conforms to API RP 13C

Electronic Balance

Overflow

Polygon Plus 123 Screens, Inc. Shaker XYZ Made in USA Lot 456 Order 101112 07.08.2009

Overflow

POLYGON PLUS 123

Figure FP-15b: Screen label, style #2.

Figure FP-14a (top): Schematic of set up for conductance measurements. Figure FP-14b shows the actual test set up.

A large volume of motor oil is placed in a large container above the sample screen (Figures FP-14a and -14b). The screen is mounted in a cylinder of PVC pipe that has an inside diameter of 5.75 in. and extends one, two, or three in. above the screen. The screen is placed under a container of about 50 gallons of motor oil. The motor oil flows onto the screen and overflows over the edges into overflow containers. The fluid which flows through the screen is captured in a container mounted on an electronic balance. When the weight in the catch pan starts increasing at a uniform rate, the increase in weight can be timed. The volume flow rate can be determined from charts indicating the density of the oil as a function of temperature.

Screen labeling Screens that have been tested with the procedure in API RP

IADC Drilling Manual

13C, should have a label that provides the information about the largest opening size (in microns) from the test, the API number, the conductance, and the unblocked screen area. The API information appears in the section on the left side of the label and the manufacturer’s part number and other information appears on the right side of the label (Figure FP-15a). The label may also be arranged in a vertical manner. The API information will appear in the top section and the manufacturer’s information will appear in the bottom section (Figure FP-15b).

Equipment The first line of defense against highly undesirable drilled solids has been, and will continue to be, the shale shaker. Without properscreening of the drilling fluid during this initial removal step, reduced efficiency and effectiveness of all downstream solids control equipment on the rig is virtually assured. The shale shaker, in various forms has played a prominent role in oilfield solids control schemes for several decades. Shakers have evolved from small relatively simple devices capable of running only the coarsest screens to the models of today.

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FP-17

SCREEN MOTION

VIBRATOR

SCREEN MOTION

SHAKER SCREEN

Figure FP-16: Unbalanced elliptical motion machines feature a downward slope to properly transport cuttings..

Vibrating mechanism The purpose of vibrating the shaker screen is to move a wire sieve through the fluid to separate the solids particles from the liquid. This motion will increase the throughput capacity. This vibrating action causes rapid separation of drilling fluid from oversize solids which reduces the volume of drilling fluid lost with the solids. The vibration also is used to transport the larger solids across the screen to remove them from the system. Four types of motion are available on shale shakers currently available: • Elliptical, “unbalanced” design; • Circular,“balanced” design; • Linear, “straight-line” design; • Elliptical, balanced design. The unbalanced elliptical motion machines have a downward

Figure FP-18: Circular motion shaker with vibrator at center of gravity. Consistent, circular vibration allows solids transport with the basket oriented horizontally.

slope (Figures FP-16 and FP-17). This slope is required to properly transport cuttings across the screen and off the discharge end. However, the downward slope reduces fluid retention time and limits the capacity of this shaker. Optimum screening with these types of shakers is usually in the 30–40 mesh (400–600 micron) range. This was the design of the first shale shakers introduced to the drilling rigs. The next generation of machines, which were introduced into the oilfield in the late 1960s and early 1970s, produces a circular motion (Figure FP-18). The consistent, circular vibration allows adequate solids transport with the basket in a flat, horizontal orientation. This design often incorporates multiple decks to split the solids load and to allow finder screens, such as screens with 150- to 180-micron openings (API 60 or API 80 screens) The third type of motion produces linear, or straight-line, movement of the screen (Figure FP-19). This motion is developed by a pair of eccentric shafts rotating in opposite directions. Linear motion provides superior cuttings conveyance and is able to operate at an uphill slope. Better conveyance and longer fluid retention allow the use of screens with 75-micron openings (API 200 screens).

Figure FP-17: Unbalanced elliptical shaker, Triflo Model 148E. Courtesy Tri-Flo International Inc.

IADC Drilling Manual

The fourth type of motion is similar to the linear motion except the screen vibrates in a thin elliptical motion (Figure FP-20). This balanced elliptical motion moves the solids in a manner similar to the linear motion shakers, but the screen does not experience the abrupt start and stop at the end of each motion. Again, these shakers can have API 200 (75-micron openings) mounted on them and have a large flow capacity.

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DRILLING FLUID PROCESSING

TWO VIBRATORS

TWO VIBRATORS NOT ALIGNED WITH SCREEN

FLUID IN

SCREEN MOTION

SOLIDS OFF

FLUID IN

SCREEN

SOLIDS OFF

Figure FP-19: The linear motion shaker is driven by a pair of eccentric shafts rotating in opposite directions.

To prevent damage to fine screens mounted on the linear or balanced elliptical motion shakers, a very coarse screen is mounted on a shaker to treat the drilling fluid as soon as it return to the surface. This is a good application for the circular motion or the unbalanced elliptical motion shakers. Tests have indicated that more solids are removed from the system if a very coarse screen is mounted on the scalping shaker before the fluid is processed through the fine screens on the main shaker. The main shaker would be a linear motion or a balanced elliptical motion shaker. If a fine screen is mounted on the scalping shaker, some of the solids seem to deteriorate because of the multiple impacts. The purpose of the scalping shaker is to remove the very large solids which frequently arrive at the surface. These solids usually come from the borehole wall and can be very large. They need to be removed to prevent damage to the fine screens which should be mounted on the main shakers (linear motion or balanced elliptical motion). Some designs use dual screens, dual decks and dual units in parallel to provide more efficient solids separation and greater throughput. Depending on the particular unit and screen openings used, capacity of scalping shakers can vary from 100–1,600 gpm or more. Screen sizes commonly used with scalping shakers range from API 10 to API 80. Scalping shakers normally require minimal maintenance. Other than periodic greasing, the following check list should be implemented while making a trip: • Wash down screens; • Check screens for proper tension; • Shut down shaker when not drilling in order to extend screen life;

IADC Drilling Manual

Figure FP-20: This balanced elliptical motion moves the solids in a manner similar to the linear motion shakers, but the screen does not experience the abrupt start and stop at the end of each motion.

• Dump and clean possum belly (or back tank)-BUT do not empty the possum belly into the active system; • Clean the tension rails; • Inspect rubber screen supports for wear. IMPORTANT! Install replacement screens properly, square on the deck, with even tension according to the manufacturer’s recommendations. Scalping shakers are generally adequate for top-hole drilling and for shallow holes when used with other solids control equipment, such as hydrocyclones. For deeper holes and when using weighted drilling fluids or an expensive liquid phase, a scalping shaker might be used with fine screen shakers. Tests have indicated that when processing drilling fluid through a scalping shaker in front of a fine screen shaker, a very coarse mesh screen (such as an API 10 to API 20) should be used on the scalping shaker to remove the largest quantity of drilled solids.

Main shakers The main vibratory shale shakers are usually linear motion or balanced elliptical motion shale shakers. Some manufacturers are now making shakers that can have either motion. Figures FP-21 through FP-25 show some contemporary shakers.

Triple deck shakers A relatively new procedure is being used now in areas where lost circulation is prevalent. The concept is based on the observation that the hoop stress around a wellbore can be

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DRILLING FLUID PROCESSING

Figure FP-21: Derrick Dual Pool shaker. Courtesy Derrick Equipment Co.

Figure FP-23: MI SWACO MD2 dual-deck, flat-bed shaker. Courtesy MI SWACO, a Schlumberger company.

increased if a fracture is propped open with large solids. This effect was observed initially in PIT tests. When the fracture is propped open, the well bore is ‘strengthened’ or a ‘stress cage’ is developed which increases the pressure required to open the fracture again. To form this stress cage, large solids must be present in the drilling fluid; consequently, large particles (usually calcium carbonate or limestone) are added to the drilling fluid. To prevent loss of this material, triple deck shakers are being used. The top deck removes the very large particles. The middle deck screen is sized to capture the propping particles and return them to the drilling fluid. The lower deck is designed to remove particles from the drilling fluid that are larger than barite but smaller than the added proppants. The drilling fluid rheology cannot be accurately measured with the traditional rheometers, because the large particles must be removed for the measurement. The gap between the bob and the outer rotating cylinder is usually smaller than the added solids.

IADC Drilling Manual

FP-19

. Figure FP-22: Fluid Systems 5000BLE Low Profile shaker. Courtesy Fluid Systems

Figure FP-24: National Oilwell Varco VSM Multi-Size shaker. Courtesy National Oilwell Varco.

A triple deck shaker was introduced in the early 1960s. This was a circular motion shaker and never became very popular. Louis Brandt was a design engineer with IMCO and resigned about the time these shakers were placed on the market. He formed The Brandt Company and made double deck, circular motion shakers instead of a triple deck. The design was intended to use the top deck as a scalping deck with a very coarse screen and the finer screen (usually an API 80 or coarser) was mounted on the lower deck. In use, many drilling superintendents mounted the finer screen on top, because they had trouble observing when the screen failed. Lost circulation can be corrected by the wellbore strengthen concept but can also be solved with other methods. Field trials have indicated that removal of drilled solids from the drilling fluid will provide one solution. If pressure cannot enter a crack, the wellbore is strengthened by the pressure difference between the wellbore pressure and the formation pressure. Wells with very ‘clean’ drilling fluid have been

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FP-20

DRILLING FLUID PROCESSING

Figure FP-25: Cutaway shows key components of a shaker. Courtesy Cubility.

more drilling fluid.

Maintenance Because of their greater complexity and use of finer screens, fine screen shakers generally require more attention than scalping shakers. Nonetheless, their more effective screening capabilities more than justify the higher operating cost. This is especially true when rig rates are high and/or expensive drilling fluid systems are used.

Video FP-1: Shale shaker in action. Video by IADC, access courtesy Derrick Corp.

Besides periodic lubrication, fine screen shakers require the same minimum maintenance as scalping shakers while making a trip.

drilled through over 5,000 ft of ‘drawn-down’ sands where the pressure differential varied from less than 1,000 psi to more than 6,000 psi.

Wash screens

Another concept is now available to process the drilling fluid through a screen instead of shaking the screen. A continuous belt is rotated to form a bed of drilling fluid. A vacuum beneath the belt draws the drilling fluid through the screen. An air jet removes the cuttings as they reach the end of the horizontal surface of the belt. The clean belt then moves back to provide a continuous screen to accept

Check screens for proper tension

IADC Drilling Manual

Drilling fluid which dries on a shaker screen during a trip will plug the small screen openings and is very difficult to remove.

•When using panel screens, plug any openings which have ruptured screens; • Shut down shaker when not drilling to extend screen life; • Vibrating a dry screen drastically shortens screen life of fine screens;

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FP-21

• Dump the back tank into a disposal tank.

In addition, frequent checks must be made for screen plugging or blinding and broken screens. All will occur more frequently on fine screen shakers than on the coarser screens on scalping shakers. Specifically, the screens should be checked while making a connection when all of the fluid has drained from the back section of the shaker. Screen blinding, while present to some degree on scalping shakers, is more frequent with fine screen shakers. If the openings become coated over, the throughput capacity of the screen can be drastically reduced and flooding of the screen may occur. Screen blinding can be caused by sticky particles (drilled clay) coating over the screen openings, the evaporation of water from dissolved solids, or from grease. Linear motion or elliptical motions shakers do not transport sticky clays efficiently. A scalping shaker is necessary to remove most of these particles before they reach the main shakers. Most of the time, a screen wash-down is needed to cure the problem. This wash-down may simply be a high-pressure water wash, a solvent (in the case of grease, pipe dope or asphalt blinding), or a mild acid soak (in the case of blinding caused by hard water). Stiff brushes should not be used to clean fine screens because of the fragile nature of fine wire in the screen cloth. Screen capacity, or the volume of drilling fluid which will pass through a screen without flooding, varies widely depending on shaker model and drilling conditions. Screen opening size, drilling rate, bit type, formation type, and drilling fluid type, weight, drilling fluid surface tension, thickness of the wetting ring of liquid around the wires, and viscosity affect throughput to some degree. The shaker capacity is directly related to the opening sizes in the screen and the smaller the opening sizes, the lower the screen capacity. Drilling rate affects screen capacity because increases in drilled solids loading reduce the effective screen area available for drilling fluid to flow though. Increased high-shear-rate viscosity (called PV), is usually associated with an increase in percent solids by volume and/or increase in mud weight has a markedly adverse effect on screen capacity. As a general rule, for every 10% increase in Plastic Viscosity (PV), there is a 2–5% decrease in throughput capacity. Other factors which decrease the screen capacity are: screen motion, screen velocity, the low-

IADC Drilling Manual

API 60

Flow Rate

Solids dumped from the back tank do not settle in sand traps. They tend to stay suspended and very quickly plug desilters as soon as circulation resumes. These solids also eventually grind into smaller pieces and are detrimental to drilling performance.

API 100

API 200

Increasing: - mud weight - low-shear-rate viscosity - high-shear-rate viscosity - solids loading - liquid surface tension Figure FP-26: Effect of key parameters on fluid flow rate through three standard screen sizes.

shear-rate viscosity of the drilling fluid, total solids loading (amount of oversize and the quantity of solids which pass through the screen), the thickness of the ring of liquid adhering to the screen wires, the thickness of the layer of drilling fluid adhering to the solids, and the surface tension of the fluid. Mud type also has an effect on screen capacity (Figure FP-26). Higher viscosities generally associated with NADF (Non-Aqueous Drilling Fluid) result in lower screen throughput than would be possible with a water-based drilling fluid of the same mud weight. Some drilling fluid components, such as synthetic polymers, also have an adverse effect on screen capacity. Starch, for example, is large enough to plug an API 200 screen. As a result, no manufacturer can offer a standard throughput for all operating conditions. This is the reason the API RP 13C committee elected to simply try to describe the screens instead of trying to develop a procedure which would predict performance. The capacities of shakers can vary from 50 to 800 gpm.

Degassers When drilling subsurface formations, the fluid inside the formations is released into the drilling fluid system. If gas is contained in the rock being drilled, this gas is circulated out of the hole with the drilling fluid. This is called ‘back-ground’ gas. As gas rises up the hole and the pressure is decreased, a

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DRILLING FLUID PROCESSING

FP-22

Effect of Gas Cut Mud on Bottomhole Pressure

Depth, ft 1,000

0

20

Change in Pressure, psi 40 60 80

10 ppg 18 ppg

100

120

10,000 20,000 10% gas cut

25% gas cut

50% gas cut

100,000

Figure FP-27: Gas has a minimal effect on mud weight at depths. At 20,000 ft, bottomhole pressure changes very little due to the small decrease in mud weight.

gas bubble will expand. A large amount of gas at the surface could be a very small amount at the drill bit. The degassers are not specifically used to remove gas from the drilling fluid before it is pumped back downhole because the downhole pressure will decrease. Centrifugal pumps will not pump gaseous drilling fluid very efficiently. The gas collects in the center of the impeller and eventually blocks liquid flow from entering the pump. Figure FP-27 illustrates the minimal effect that gas has on mud weight at various hole depths. At 20,000 ft the decrease in mud weight is so small that the bottomhole pressure changes very little. The background gas needs to be removed from the drilling fluid so that centrifugal pumps can be used to process the drilling fluid. This background gas does not indicate an impending kick. There is no need to try to increase the mud weight to eliminate background gas. Air can also be introduced into the drilling fluid system through the mud hopper. When the mud hopper is left running, air is pulled into the flow stream in the additions section. Some contractors place a short piece of 20-in. or 26in. casing at the end of the mud hopper line. The discharge line from the mud hopper enters tangentially into the short piece casing that is positioned vertically. A top, with a large (10–12-in. diameter) hole, is welded to the upper end of the casing. The bottom is left open at the top of the drilling fluid in the tank. When the mud hopper is left running, the air entrained in the drilling fluid is removed with the centrifugal force of the drilling fluid swirling inside of the casing.

Figure FP-28: Horizontal tank/jet pump vacuum degasser. The long, horizontal, downsloping baffles allow fluid to flow down these baffles in a thin layer, releasing the gas bubbles.

Degassers are the most effective way to remove unwanted gas. They are designed to rapidly bring gas bubbles to the surface of the drilling fluid, break them and remove them to a safe location away from the rig. Vacuum degassers use a combination of turbulent flow and reduced internal tank pressure to move gas-cut drilling fluid and release gas bubbles. Several designs are available; the most common types are the horizontal tank/jet pump design, the vertical tank/jet pump design, and the vertical tank/self- priming pump design.

Figure FP-29: This design of vertical tank with jet pump features several conical baffles within the tank, increasing baffle surface area within a compact footprint.

IADC Drilling Manual

The horizontal tank/jet pump design has a long horizontal tank with long down-sloping baffles inside (Figure FP-28). fluid flows down these baffles in a thin layer, releasing the gas bubbles. A vacuum pump is used to remove the gas from the tank and dispose of it at a safe distance from the rig. The vacuum pump also reduces the internal tank pressure, drawing fluid into the tank and increasing the gas bubble sizes, improving removal efficiency. Most of the time the volume of gas removed is small compared to the capacity of the vacuum pump so a 3-way valve is installed in the gas

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DRILLING FLUID PROCESSING Jet Pump

Valve

Valve Opening

From Suction Shale Shakers

FP-23

Belt Drive

Spray Tank

Motor

Degassed Drilling Fluid

Bearing Shaft

Top Edge of Pit

Support Bracket

Pipe Frame

Gas-Cut Degassed Drilling Drilling Fluid Overflow Fluid

Under Flow

Gaseous Fluid Inlet Impeller

Suction for Hyrdocyclones

Casing

Figure FP-30: Horizontal tank vacuum degasser. The vacuum pump and jet pump arrangement are the same as in the vertical design.

Figure FP-31: In an atmospheric degasser, a submerged centrifugal pump sprays a thin sheet of drilling fluid against the wall of a tank. Gas leaves the thin layer, and the impact causes the rest of the gas to separate.

piping to let air in and prevent too much vacuum in the tank. The fluid level inside the tank and the operation of the 3-way valve is controlled automatically by a float inside the tank.

required a small blower can be mounted on the vent hood to aid with gas removal.

The jet pump discharges the degassed drilling fluid from the tank and returns it to the next downstream compartment. There is no re-mixing of released gas and fluid. The jet pump is used because there is still a small amount of gas left in the drilling fluid—but it may be enough to gas-lock a direct feed centrifugal pump. The gas passes easily through the jet pump, floats to the surface of the discharge compartment and breaks out from surface. The vertical tank/jet pump design has two variations. The first of these (Figure FP-29) is similar to the horizontal/jet pump design. Instead of a long horizontal tank with a single series of baffles, this design has several conical baffles stacked inside a vertical cylindrical tank. This design increases baffle surface area in a compact footprint. The vacuum pump and jet pump arrangement are the same as for the horizontal design (Figure FP-30), although some vertical designs have been used with self-priming feed pumps. An atmospheric degasserwas invented by Walter Liljestrand and developed in the early 1970s (Figure FP-31). A submerged centrifugal pump sprays drilling fluid in a thin sheet of drilling fluid against the wall of a tank. Gas leaves the thin layer of the drilling fluid, and the impact causes the remainder of the gas to separate from the drilling fluid. Comparison of mud weight before and after processing indicates this effectively removed gas. The degassed drilling fluid drains from the spray tank through a trough or pipe to the next downstream compartment. The released gas flows with the degassed fluid. This gas could be piped away from the rig by covering the trough with a vent hood and flexible hose. If

IADC Drilling Manual

Effects of gas-cut drilling fluid Gas-cut drilling fluid has several effects. Some of these are obvious and others are not. Wrong action in a gas-cut drilling fluid can cause higher drilling costs, lost circulation or a blowout. It is important to recognize both the source (gas or air) and effects of “bubbles in the drilling fluid”. In conventional drilling fluids, air in the fluid is usually a result of the drilling fluid flowing down the flow line and through processing equipment. The main damage from air is corrosion. Air in the fluid: • Makes foam on the surface of the mud tanks; • Reduces measured mud weight; • Usually makes larger bubbles than hydrocarbon gas; • Corrodes the drill string; • Will not be detected by the mud logger; • May reduce centrifugal pump performance; • May significantly reduce the mud pump volumetric efficiency. Gas-cut drilling fluid reduces the mud weight measured with a mud balance. It does not change the true mud weight, but it creates a wrong, urgent feeling to weight up. This can result in great harm. For example: The well profile calls for a 10.0 ppg drilling fluid to maintain pressure control at 10,000 ft. The mud engineer mixes the right ingredients to make a 10.0 ppg fluid. While drilling ahead the mud is gas-cut by 0.6 ppg but this is not realized. So, even though the actual mud weight is 10.0 ppg,

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FP-24

DRILLING FLUID PROCESSING

the measured mud weight in the mud balance is 9.4 ppg. Barite is added to bring measured weight up to 10.0 ppg, but this causes the true mud weight to be 10.6 ppg.

“poor-boy” degassers or “gas-busters”, mud/gas separators receive severely gas-cut drilling fluid from a rotating control device (i.e., rotating head) or a choke manifold during a kick.

Three things happen: • First, the increased mud weight reduces drilling rate with the roller-cone bits; • Second, the gas in the mud reduces pump volume efficiency and the fluid flow rate down the drill pipe; • Third, the risk of losing circulation and/or stuck pipe due to greater hydrostatic pressure is increased if the formation is pressure sensitive. At 10,000 ft this increases bottomhole pressure by 312 psi.

Mud/gas separators flow the gas-cut drilling fluid in thin sheets over a series of baffles arranged inside a vertical tank. The resulting turbulent flow breaks out large gas bubbles which then rise through a vertical vent line and are released a safe distance from the rig. Caution should be used to make the discharge line for the gas effluent very large to decrease the pressure required to dispose of the gas. If the gas discharge line is too small, the back pressure may eliminate the liquid seal at the bottom of the tank and dump gas onto the drilling fluid tanks. The return drilling fluid flows into the back tank of the shale shakers for further processing.

When weighing mud samples: • Use a clean and calibrated mud balance; • Be sure the place the sample is taken is well stirred; • Be sure the sample is the same as the fluid being circulated; • Fill the mud balance cup completely; • If gas-cut mud is suspected, use a pressurized mud balance (see API RP13B) or hand vacuum to degas the sample thoroughly before weighing. Another technique that seems to give mud weights within 0.05 ppg of the value measured with a pressurized mud balance is to use a defoamer on the sample. Add some defoamer to a mud cup full of drilling fluid and pour it through the funnel two or three times to agitate, then weigh in a regular mud balance. If the true mud weight shows a low reading, it still may not be due to gas or air. Oil or water flows will also reduce mud weight as will weighting material dropping out of poorly agitated drilling fluid systems. Inadequate suspension properties in a drilling fluid may also result in barite leaving the drilling fluid on the way out of the hole. A degasser cannot restore mud weight caused by these problems. Main mud pumps are positive displacement pumps. They are designed to pump gas-free drilling fluid with about 95% to 97% volumetric efficiency. Gas-cut drilling fluid reduces pump flow rate because the positive displacement cylinders are not filled with liquid. Measurements indicated in one well that 6% volume gas/air in the water-based drilling fluid reduced the volumetricefficiency of a triplex pump to 85%. This makes it difficult to maximize the hydraulic impact or hydraulic power of the fluid passing through the nozzles of the drill bit.

Removing gas bubbles Mud/gas separators are designed to remove large amounts of large bubbles from the drilling fluid. Sometimes called

IADC Drilling Manual

Gas discharge lines offshore are typically 8–12 in. in diameter. Onshore the discharge lines may be only 6 in. diameter depending upon the drilling area. When a gas bubble reaches the surface during a well control event, the velocity of the gas can be very large. The pressure loss through the discharge line varies as the fifth power of the vent line inside dimension.

Installation Actual placement of the degasser and related pump will vary with the design of the degasser, but these recommendations may be used as a general rule: • Install a screen in the inlet pipe to the degasser to keep large objects from being drawn into the degassing chamber; • Locate the screen about one foot above the pit bottom and in a well-agitated spot; • There should be a high equalizer line between the suction and discharge compartment. This allows the remaining gas at the surface of the downstream compartment to flow back into the degasser compartment for further gas removal; • The equalizer should be kept open to allow back flow of processed drilling fluid to the suction side of the degasser; • Route the liquid discharge pipe to enter the next compartment or pit below the liquid level to prevent aeration; • Install the gas discharge line to safely vent the separated gas to atmosphere or to a flare line. Maintenance of degassers varies considerably depending on make and model. In general, the following guidelines apply: • Check to make sure the suction screen is not plugged; • Routinely lubricate any pumps and other moving parts and check for wear; • Keep all discharge lines open and free from restrictions, such as caused by solids buildup around valves;

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DRILLING FLUID PROCESSING

FP-25

Figure FP-32: Design features of cyclone units vary widely from supplier to supplier and no two manufacturers’ cyclones have identical operating efficiency, capacity or maintenance characteristics. Earlier hydrocyclones were commonly made of cast iron with replaceable liners and other wear parts made of rubber or polyurethane to resist abrasion. Most of the current hydrocyclones are made entirely of polyurethane and are less expensive, last longer, and weigh less. Manifolding multiple cyclones in parallel can provide sufficient capacity to handle the required circulating volume plus some reserve as necessary. Manifolding may orient the cyclones in a vertical position or nearly horizontal—the choice is one of convenience, as it does not affect cyclone performance. These cyclones are being used in an in-line desilter. Courtesy Derrick Equipment Co.

• If the degasser uses a vacuum, keep it at the proper operating level, according to the manufacturer’s recommended range for the mud weight and process rate; • Check all fittings for air leaks; • If the unit uses a hydraulic system, check it for leaks, proper oil level and absence of air in the system.

Hydrocyclones Hydrocyclones (also referred to as cyclones or cones) are simple mechanical devices, without moving parts, designed to speed up the settling process. Feed pressure is transformed into centrifugal force inside the cyclone to accelerate particle settling. In essence, a cyclone is a miniature settling pit which allows very rapid settling of solids under controlled conditions (Figure FP-32). Hydrocyclones have become important in solids control systems because of their ability to efficiently remove particles smaller than the finest shaker screens. They are also uncomplicated devices, which make them easy to use and maintain. A hydrocyclone consists of a conical shell with a small opening at the bottom for underflow discharge, a larger opening at the top for liquid discharge through an internal “vortex finder”, and a tangential feed nozzle on the side of the body near the wide (top) end of the cone. Drilling fluid enters the cyclone under pressure from a centrifugal feed pump. The velocity of the fluid causes the particles to rotate rapidly within the main chamber of the cyclone. Small solids and the liquid phase of the drilling fluid tend to spiral inward and upward for discharge through the liquid outlet (overflow). Heavy, coarse solids and the liquid

IADC Drilling Manual

film around them tend to spiral outward and downward for discharge through the solids outlet (underflow). The size of oilfield cyclones commonly varies from 4–12 in. inside diameter (Table FP-2). This measurement refers to the inside diameter of the largest cylindrical section of the cyclone. In general, the larger cones have higher cutpoints and a greater throughput. Typical cyclone capacities and feed pressures are shown in the table below. The cut points shown are for very light slurries of drilling fluid. The cut points for weighted drilling fluids are much higher. The internal geometry of a cyclone also has a great deal to do with its operating efficiency. The length and angle of the conical section, the size and shape of the feed inlet, the size of the vortex finder, and the size and adjustment means of adjusting the underflow opening all play important roles in a cyclone’s effective separation of solids particles. (Figures FP-33 and -34.) Operating efficiencies of cyclones may be measured in several different ways, but since the purpose of a cyclone is to discard drilled solids with minimum fluid loss, both aspects must be considered. In a cyclone, larger particles have a higher probability of reporting to the bottom (underflow) opening, while smaller particles are more likely to report to the top (overflow) opening. The most common method of illustrating particle separation in cyclones is through a cutpoint curve. The data for the cutpoint curves below were for processing an unweighted, relatively thin water-based drilling fluids and operated with the proper head applied. Particle separation in cyclones can vary considerably depending on such factors as feed pressure, mud weight, percent solids and properties of the liquid phase of the drilling fluid. Generally increasing any of these factors will increase

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DRILLING FLUID PROCESSING

FP-26

Table FP-2: Typical cyclone capacities and feed pressures Cone Size (ID)

4 in.

5 in.

6 in.

8 in.

10 in.

12 in.

Capacity (GPM)

50–75

70–80

100–150

150–250

400–500

400–500

Feed Pressure (PSI)

30–40

30–40

30–40

25–30

20–30

20–30

Cut Point (Microns)

15–20

20–25

25–30

30–40

30–40

40–60

Clean Drilling Fluid (overflow) Vortex Finder

Feed nozzle Drilling Fluid In

Drilling fluid moves inward and spirals upward

Sand and Silt spin against wall and downward toward discharge

Solids Discharge (Underflow) Figure FP-33: Schematic of hydrocyclone, which are important because of their ability to remove particles smaller than the finest shaker screens.

Spray Discharge

Rope Discharge

Figure FP-34: A hydrocyclone with a spray discharge remove significantly more solids than one with a rope discharge.

IADC Drilling Manual

the size of solids actually separated by the cyclone and decrease the volume of solids removed. While a spraying underflow will also discharge more fluid, the benefits of more efficient solids removal and less cone wear outweigh cost of the additional fluid loss.

Desanders Desanders are hydrocyclones larger than 5-in. diameter (6-, 8-, 10- or 12-in. ID). Generally, the smaller the cone, the smaller size particles the cone will separate. Desanders are primarily used to remove the high volumes of solids associated with extremely fast drilling of a large diameter hole, especially when a fine screen shaker is not available. Desanders are installed downstream from the shale shaker and degasser. The desander removes sand-sized particles and larger drilled solids which have passed through the shaker screen and discards them along with some liquid. The partially clean drilling fluid is discharged into the next compartment downstream (Figure FP-35). When installing a desander, follow these general recommendations: • Size the desander to process 100–125% of the flow rate entering the suction tank of the desander; • Keep all lines as short and straight as possible with a minimum of pipe fittings. This will reduce loss of pressure head on the feed line and minimize backpressure on the overflow line; • Do not reduce the diameter of the overflow line from that of the overflow discharge manifold; • Direct the overflow line downward into the next downstream compartment at an angle of approximately 45°. The overflow discharge line should never be installed in a vertical position, doing so may cause excessive vacuum on the discharge header and pull solids through the cyclone overflow thus reducing the cyclone’s efficiency; • Install a vacuum breaker in the overflow line if the desander is over 8–10 ft above the drilling fluid level in the mud tanks; • Install adequate walkways and hand rails around the desander to allow proper maintenance; • Keep the end of the discharge line above the surface of

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DRILLING FLUID PROCESSING

100

Percent Mass Removed: %

The cyclones in desilter units operate on the same principle as the cyclones used as desanders. They simply make a finer cut and the individual cone throughput capacities are less than desander cones. Multiple cones are usually manifolded in a single desilter unit to meet throughput requirements. Desilters should be sized to process 100–125% of the flow rate entering the suction tank for the desilters. [Note that this does not say 100–125% of the flow rate down the hole.]

80

60

6”

8” 10”

12” D50

40

API 200 Screen

20

0 0

25

50

75

FP-27

100

125

Particle Size - Equivalent Diameter: microns

Figure FP-35: These cut point curves show the removal of solids from a relatively low-weight drilling fluid.

the liquid level in the pits to avoid creating a vacuum in the line; • Install a low equalizer line to permit back-flow into the desander suction. Operating the desanders at peak efficiency is a simple matter, since desanders are relatively uncomplicated devices. Here are a few fundamental principles to keep in mind: • Operate the desander unit at the supplier’s recommended head (or feedmanifold pressure, usually around 30 to 35 psi). A feed pressure that is too low decreases the separation efficiency, while too high a pressure shortens the life of cyclone wear parts; • Check cones regularly to ensure the discharge orifice Is not plugged; • Run the desander continuously while drilling and shortly after beginning a trip for “catch-up” cleaning; • Operate the desander with a spray rather than a rope discharge to maintain peak efficiency. Use of desanders is normally discontinued when expensive materials such as barite or some polymers are added to a drilling fluid because a desander will discard a high proportion of these materials along with the drilled solids. Similarly, desanders are not generally cost effective when a NADF is used because the cones also discard a significant amount of the liquid phase.

Desilters A desilter uses smaller hydrocyclones (usually 4- or 5-in. ID) than a desander and therefore generally removes smaller particles. The smaller cones enable a desilter to make the finest particle size separation of any full flow solids control equipment—removing solids in the range of 15 microns and larger. This makes it an important device for reducing average particle sizes and removing abrasive grit from unweighted drilling fluids.

IADC Drilling Manual

Installation of the desilters is normally downstream from the shale shaker, degasser, and desander and should allow ample space for maintenance. Here are some fundamentals for installing desilters: • Take the desilter suction from the compartment receiving fluid processed by the desander; • Do NOT use the same pump to feed both the desander and desilter. If both pieces of equipment are to be operated at the same time, they should be installed in series and each should have its own centrifugal pump; • Keep all lines as short and straight as possible; • Install a guard screen with approximately 1/4-in. openings at the suction to the desilter pump to prevent large trash or drilled solids from entering the unit and plugging the cones; • Position the desilter on the pit high enough so the overflow manifold will gravity-feed fluid into the next downstream compartment at an angle of approximately 45°. REMEMBER: no vertical overflow discharge lines; • Keep the end of the discharge line above the surface of the liquid in the tanks to avoid creating a vacuum in the line; • Install a low equalizer line for back flow to the desilter suction compartment; Running a desander ahead of a desilter is required if coarse screens are used on the shale shakers. Desanders take a big load off the desilters and improves their efficiency; • Operate the cones with a spray discharge. Never operate the desilter cones deliberately with a rope discharge since a rope underflow cuts cone efficiency in half—or worse, causes cone plugging, and increases wear on cones. Use enough cones and adjust the cone underflow openings to maintain a spray pattern; • Operate the desilter unit at the supplier’s recommended feed manifold pressure. This is generally between 70 and 80 feet of head. Too much pressure will result in excessive cone wear. As mud weight increases, feed pressure will also increase. As a rule of thumb, desilter cones should operate at a feed pressure of 4 times mud weight. [calculate this with the equation used in well control: Pressure, psi = 0.052 (mud weight, ppg)(head, ft)] A centrifugal pump is a constant head device so the

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FP-28

DRILLING FLUID PROCESSING

pressure will automatically increase as the mud weight increases; • As mud weight increases, the cone bottoms can be opened slightly to help increase solids removal efficiency; • Check cones regularly for bottom-plugging or flooding, since a plugged cone allows solids to remain in the active system. If a cone bottom is plugged, unplug it with a welding rod or similar tool. If a cone is flooding, the feed may be partially plugged or the bottom of the cone may be worn out; • Run the desilter continuously while drilling and also for a short time during a trip. The extra cleaning during the trip can reduce overload conditions during the period of high solids loading Immediately after a trip.

Maintenance The smaller cyclones of a desilter are more likely than desander cones to become plugged with oversized solids, so it is important to inspect them often for wear and plugging. This may generally be done between wells unless a malfunction occurs while drilling. The feed manifold should be flushed between wells to remove trash. Keep the shale shaker well maintained—never bypass the shaker or allow large pieces of material to get into the active system. Note: the fact that some solids can plug the bottom of a cone means that all of the fluid from the well did not pass through the shaker screens. A desilter will discard an appreciable amount of barite because most barite particles fall within the silt size range. Desilters are therefore not recommended for use with weighted drilling fluids. Similarly, since hydrocyclones discard some liquid along with the drilled solids, desilters are not normally used with NADF unless another device (centrifuge or mud cleaner) is used to decrease the liquid discard in the cone underflow.

Mud cleaners Mud cleaners were developed in the early 1970s to remove drilled solids from weighted drilling fluid. They have also proved valuable tools in closed systems and other “dry location” applications. These devices use a combination of hydrocyclones and very fine vibrating screens (API140 to AP200) to remove fine drilled solids while returning valuable mud additives and liquids back to the active mud system. The first field test of the mud cleaner was on an exploration well (drilling below production zones) in Bayou Sale, near Franklin, La (Figure FP-36a). Ten cones were fed with a centrifugal pump driven by a diesel engine. The large ‘pond’ in the background was the ‘reserve pit’ and the small pond just behind the mud cleaner was a ‘duck’s nest’ used to store ex-

IADC Drilling Manual

Figure FP-36a: In the first field test of a mud cleaner, ten cones were fed with a centrifugal pump driven by a diesel engine. The large “pond” in the background was the “reserve pit” and the small pond immediately behind the mud cleaner was a “duck’s nest” used to store excess drilling fluid after removal from the system.

cess drilling fluid when it was removed from the system for dilution. The large vertical section of casing just beside the shiny mud cleaner was a “roughneck proof flow meter”. To obtain cut points, the flow rates from the desilters needed to be measured. The overflow from the desilters was routed beneath the vertical casing with a valve downstream of the casing. The inside of the casing was calibrated to measure gallons. When the valve was closed, the overflow from the desilters filled the casing. By timing the fill, the flow rate could be established. The system was so new that it had to mounted on a platform at the end of the degasser tank because the operator did not want to “clutter up” the mud tank system. The 4-in. cones were from Pioneer Centrifuge Co., and each weighed about 40 lb with a rubber insert in a cast iron body. The mud cleaner was 5 ft in diameter and had two decks in it. Ten cones put about 50 gpm on the 200 square mesh screens. Plastic ring 'sliders' mounted beneath the single layer screen prevented near-size blinding and gave support to the fine wire. The vibration motor was mounted underneath the screens and rotating a vertical shaft. The unbalanced weight on top and another one on the bottom of the motor controlled the height of the screen motion and the rotation speed of the slurry as it rotated in an increasing diameter until it reached the discard port. Both ports (clean fluid through screen and discard solids off the screen) had rubber sleeve down spouts. Measurements on discarded solids were made every two hours from 11,000–16,000 ft during most of the months of November and December. Just before Christmas the unit was shut down because they thought they only had 80 ftdrill and “we were not helping because they were having no

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DRILLING FLUID PROCESSING

FP-29

ers should be used in place of desilters alone in weighted drilling fluid applications. Comparing the drilling fluid content of the cone underflow (8 bbl/hr) to the fluid content of the mud cleaner discard (1.4 bbl/hr) shows another benefit of mud cleaners over desilters in NADF and other drilling fluids which have an expensive liquid phase. The primary purpose of solids control equipment is to remove drilled solids NOT recover barite. Salvaging barite is a great by-product of the device, but the removal of the drilled solids is the most important aspect.

Figure FP-36b: A second field test was followed by one at Tilden, Texas, using potassium chloride drilling fluid. The mud cleaner removed detrimental drilled solids and also recovered a significant quantity of expensive drilling fluid.

problems”. The interval was being drilled with an 11 ppg gel/ lignosulfonate fluid through about a dozen or more drawndown Miocene sands. One formation at 11,000 ft had the original pore pressure. The produced formations had pressure differentials in the 2,000–6,000 psi range. No stuck pipe or lost circulation was experienced during the drilling of this 5,000-ft interval. They actually had to drill 200 ft more and they called just before New Year's to come back over and turn on our “robot”. They had to make wiper trips between every logging run. Logging tools were sticking and the torque and drag was significant. Several circulations and a wiper trip were required before it was safe to run and cement the protective casing string. The casing was run and cemented with no difficulty. That field test was followed by one at Tilden, Texas, using potassium chloride (KCl) drilling fluid as it was being developed (Figure FP-36b). The 5-ft diameter shaker was replaced with two 4-ft diameter shakers. The mud cleaner not only removed drilled solids that would have been detrimental to drilling performance, but also recovered a significant quantity of the very expensive liquid phase of the drilling fluid. Most mud cleaners use multiple 4-or 5-in. cyclones, processing 400–850 gpm. The liquid throughput is only one measure of mud cleaner capacity; more important is the capacity of the vibrating screen to remove drilled solids. Some field data of a mud cleaner processing an 11.2-ppg drilling fluid shows the mud cleaner was discarding 46,800 pounds of drilled solids each 24 hours, along with 2,925 pounds (29 sacks) of barite. The fine screen under the hydrocyclones salvaged 71,955 pounds (720 sacks) of weighting material per day. From this, it is obvious why mud clean-

IADC Drilling Manual

Mud cleaners should be considered in these applications: • Whenever the application requires finer screens than the existing shaker can handle; • Unweighted oil-based drilling mud [NADF]; • Expensive polymer systems; • Whenever the cost of water is high; • Unweighted water-based drilling fluids with high disposal costs and/or environmental restrictions; • When use of coarse lost circulation material forces bypassing of the shale shaker; • Workover and completion fluid cleanup; • As a back-up insurance for solids that are not removed by the main shakers. An increasingly important application of mud cleaners is the removal of drilled solids from unweighted water-based drilling fluid in semi-dry form. This system is commonly used in areas where environmental restrictions prohibit the use of earthen reserve pits and expensive vacuum truck waste disposal from steel pits is the alternative. The mud cleaner is used to discard drilled solids, in semi-dry form which is classified as legal land fill in most areas and is subject to economical dry-haul disposal techniques (dump truck or portable waste containers).

Installation Mud cleaners are installed downstream of the shale shaker and the degasser. The same pumps used to feed the rig’s desander or desilter are often reconnected to feed the mud cleaner when weight material is added. (Most mud cleaners are designed to also function as desilters on unweighted drilling fluid by rerouting the cone underflow or by removing or blanking off the screen portion of the unit. The mud cleaner may then be used to replace or augment the rig’s desilter during top hole drilling.) Frequently, a bank of desilters is mounted over a main shaker if it can use an API170 or API 200 screen. In the upper part of the hole (unweighted drilling fluid), the shaker will process fluid from the flow line and the desilters will discard all of the underflow. Down deeper in the hole, where the flow rate in the well does not require as many

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FP-30

DRILLING FLUID PROCESSING

Figure FP-37: After a shaker removes large volumes of cuttings, drilling fluid is pumped into the mud cleaner’s hydrocyclones with a centrifugal pump. The overflow from the cyclones is returned to the active system. Instead of discarding the underflow, the solids and liquid exiting the bottom of the cyclones are directed onto a fine screen. Drilled solids larger than the screen openings are discarded. The remaining solids, including most of the barite in weighted systems, pass through the screen and are returned to the active drilling fluid system. The cut point and amount of solids removed by a mud cleaner depends primarily on the fine shaker screen used. Since many designs of mud cleaners exist, performance and economics will vary with machine and drilling variables. Photo on left is a Triflo Model 16-4/146E mud cleaner, courtesy Tri-Flo International Inc. Right photo of an M-I SWACO 8T4 D-Silter, courtesy M-I SWACO.

main shakers, one shaker can be converted into a mud cleaner. The flow from the wellbore no longer goes to one of the main shakers; instead it will process the underflow from the desilters. Follow these guidelines when installing mud cleaners to allow peak efficiency: • Size the mud cleaner to process 110–125% of the flow rate entering the desilter suction tank; • Take the mud cleaner suction from the compartment receiving fluid processed by the degasser; • If the mud cleaner has both a desander and a desilter bank of cones, the suction and discharge for each set of cones is the same as it would be in an unweighted drilling fluid system; • Confirm that the mud cleaner can process over 100% of the flow entering the suction compartment of the desilters; • Keep all lines as short and straight as possible; • Install a guard screen with approximately 1/4-in. openings at the suction to the desilter to prevent large trash from entering the unit and plugging the cones. The open area of the screen should be at least twice the pipe area; • Position the mud cleaner on the pit high enough so the overflow manifold will gravity-feed fluid into the next downstream compartment at an angle of approximately 45°. Remember—no vertical overflow discharge lines; • Provide walk-ways and sufficient space for routine maintenance; • Provide a vacuum breaker in the desilter overflow manifold to avoid creating a vacuum in the line; • Install a low equalizer line for back-flow to the mud cleaner suction compartment; • Return the fluid underflow from the mud cleaner screen in a well-agitated spot. This will prevent concentrated barite from settling in the mud tank. [The screen underflow will have no carrying capacity.]

IADC Drilling Manual

To operate mud cleaners at maximum efficiency, remember these fundamentals: • Operate mud cleaners continuously on the full circulating volume to achieve maximum drilled solids removal; • Operate mud cleaners with in the limits of the screen capacity. A mud cleaner with a cyclone throughput of 800 gpm is of little value if the cone underflow exceeds the screen capacity resulting in flooding and high drilling fluid losses; • Do NOT judge screen efficiency simply on the basis of cuttings dryness or color. The total amount of drilled solids in the discarded material, along with the ratio of barite to drilled solids, must be determined to evaluate economic performance; • Select the number of cones to be operated so that all of the drilling fluid entering the desilter suction tank can be processed and use the finest screen possible, preferably an API 170 or an API 200; Some general guidelines for correct mud cleaner operation: • Run the mud cleaner continuously while drilling and for a short period of time while making a trip for “catch-up” cleaning; • Start up the shaker before engaging the feed pump; • Shut down the feed pump before turning off the vibrating screen. Permit the screen to clear itself, then rinse the screen with water or oil spray before shutting down the screen; • For peak efficiency, operate the cones with a spray rather than a rope discharge. This is just as important, or maybe more so, with a mud cleaner as with operating the desilters and desanders; • Check cones regularly for bottom plugging or flooding, since a plugged cone allows solids to return to the active system. If a cone bottom is plugged, unplug it with a welding rod or similar tool. If a cone is flooding, the feed

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DRILLING FLUID PROCESSING

is partially plugged or the bottom of the cone may be worn out; • When a significant amount of barite is added to increase mudweight, incorrectly plumbed surface systems will require that the mud cleaners be shut down for one or two full circulations. The 3% by weight of API barite larger than 75 microns will result in a significant quantity of barite being removed from the drilling fluid system. Circulating through the bit nozzles tends to decrease the barite size; • If the quantity of liquid exiting the desilters is insufficient to allow the screen to properly separate solids, a small spray of drilling fluid has proven to be effective in allowing better screening of the underflow. Sprays of water or oil generally will increase the dilution of the drilling fluid and can be costly. Frequently, one of the desilters can be removed from the manifold and a short hose with valve can be used to provide the small amount of drilling fluid needed to prevent ‘piggy-backing’ of the solids. Maintenance of mud cleaners generally combines the requirements of desilters and fine screen shakers: • Lubricate periodically; • Check screen for proper tension; •Inspect the screen to ensure it is free of tears, holes and dried drilling fluid before startup; • Shut down unit when not drilling to extend screen life; • Check feed manifold for plugging of cyclone feed inlets; clean each as necessary; • Check cyclones for excessive wear and replace parts as necessary.

Centrifuges Shale shaker screens remove solids according to their size. Hydrocyclones and centrifuges remove solids according to particle size AND density. Both of these devices apply a centrifugal force to cause larger masses to move outward more than the lighter particles. The centrifugal force causes the particles to settle. The same effect could be created by allowing the fluid to remain motionless for a long period of time and allowing the solids to settle by gravity. The centrifugal force simply increases the apparent ‘gravity’ force and causes solids to settle much faster. Settling in a Newtonian fluid (like water or oil) can be described with Stokes Law: Vs = aK(ds2)(Ds-Di)/U, where: Vs = the terminal settling velocity of a spherical particle a = the acceleration applied to the particle ds = the diameter of the particle Ds = the density of the solid particle Di = the density of the liquid K = a dimensional constant U = the viscosity of the liquid

IADC Drilling Manual

FP-31

This equation indicates that larger particles (of the same density) will settle more rapidly than smaller ones, that high density solids will settle more quickly than low density ones and that high acceleration and low viscosity increase the settling rate. This equation could also be applied to the sand trap described earlier. Low-shear-rate viscosities of drilling fluids have increased so much in recent years that the small particles do not have time to settle in the sand trap. Generally, the barite will settle first (it has a higher density), and very few drilled solids will have time to settle. A centrifuge speeds up the settling rate but also requires an adjustment of the viscosity to enhance the rate of settling. Dilution fluid is usually blended with the input slurry to decrease the low-shear-rate viscosity.

Principles of performance The first practical application of centrifuges to process drilling fluid came in the early 1950s. Until that time, coarse shaker screens and dilution were the only means of mechanical solids control. The first centrifuges were oilfield adaptations of industrial decanting centrifuges and were used to remove ultra-fine solids from weighted drilling fluids. In the mid-1960s, the rotary mud separator (or perforated cylinder centrifuge) was introduced, also to process weighted drilling fluids. It wasn’t until the mid-1980s that centrifuges were routinely used in unweighted fluid applications. Today, centrifuges are a common piece of equipment in virtually all solids removal systems. The key difference between oilfield centrifuges and previously discussed solids control devices is the operating capacity and duration. Unlike screens, cyclones and mud cleaners, which operate continuously on the full circulation volume, centrifuges operate on a small fraction of the circulating volume (usually 5–10%). By limiting the input volume, a centrifuge can run continuously to treat sufficient fluid to control properties. In a weighted drilling fluid where the colloidal particles are removed, the plastic viscosity is an indicator of the centrifuge effectiveness. Plastic viscosity should always be as low as possible for the best drilling performance. The classic use of centrifuges is to remove colloidal size solids from weighted drilling fluids to maintain a low plastic viscosity which can result from high colloidal content. Both the decanting, solid bowl centrifuge and the perforated cylinder centrifuge are used in this application. Both of these centrifuges will separate the solids by mass independent of whether they are barite or drilled solids. Both discharge streams will contain barite and drilled solids.

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DRILLING FLUID PROCESSING

FP-32

100

Mass percent to underflow, %

80

Feed: 7.5 gpm water, 15.2 gpm drilling fluid

60

Light slurry: 17.0 gpm Heavy slurry: 5.7 gpm

40

Figure FP-39: A decanting centrifuge comprises a conveyor screw inside a bowl rotated at very high speeds (1,600-3,600 rpm).

20 0

0

5

10 15 20 25 30 Particle size, microns

35

40

Decanting centrifuge processing 17.2-ppg active mud system

Figure FP-38: In this cut-point curve for a decanting centrifuge, nearly all solids larger than 10 microns were in the centriguge underflow

Decanting Centrifuge The cut-point curve for a decanting centrifuge was measured on a drilling rig circulating a 17.2-ppg water-based drilling fluid. The feed slurry was diluted with about one-half of the flow rate of the drilling fluid. Nearly all solids larger than 10 microns were in the underflow of the centrifuge (Figure FP-38). The D50 cut point would be in the solid size range of around 6 microns. Decanting centrifuges are so named because they can remove, or “decant”, free liquid from the separated solid particles and leave only adsorbed or “bound” water on the surface. The decanting centrifuge is the most common type of centrifuge found in drilling applications. Bowl sizes in common oilfield applications include 14×20 in., 14×22 in., 18×28 in., and 24×38 in. The larger bowls have a greater capacity at a comparable efficiency. In field operation, the decanting centrifuge is fitted with a housing over the bowl, liquid and solids collection hoppers, skid, feed slurry pump, raw mud and dilution water connections, power source, meters and controls. Flow capacities up to 500 gpm are now available. In many cases, with water-based drilling fluid only about 25 gpm is processed continuously through the decanting centrifuge for the normal weighted drilling fluid application. The feed rate is substantially decreased as mud weight increases. Dilution water is required to compensate for increasing viscosity, generally associated with increasing mud weight in order to maintain satisfactory separation efficiency.

IADC Drilling Manual

A decanting centrifuge consists of a conveyor screw inside a bowl rotated at very high speeds (1,600–3,600 rpm). The feed drilling fluid is usually diluted with liquid and then pumped into inner shaft of the conveyor. As the conveyor rotates, drilling fluid is thrown out the feed ports into the inner bowl. (See Figure FP-39.) Centrifugal force pushes the heavy, coarse particles in the rotating fluid against the wall of the bowl, where the scraping motion of the conveyor screw moves them toward and out the solids (or heavy slurry) discharge port. The light, fine solids tend to remain in suspension in the pools between the conveyor flutes and are carried out the overflow ports along with the liquid phase. The fraction of low gravity solids in the discard can be determined using the same methods a mud engineer uses to determine low gravity solids in the drilling fluid. The discard from a decanting centrifuge that is performing properly will have about 60% volume solids and 40% volume liquid. This is difficult to pack in a retort cup for an accurate measurement. The graph is accurate but can be used to estimate the concentration of low gravity solids by weighing the discard slurry in a mud balance. If the slurry weighs about 22 ppg, it would contain about 18% volume low gravity (SG 2.6) solids if the discard contained a total of 60% volume solids. The barite (SG 4.2) in the heavy slurry discard volume would be 42% volume. With a ten-barrel discard volume, four barrels would be liquid (40% volume); 1.8 barrels would be low gravity solids; and 4.2 barrels of the slurry would be barite. If this is functioning as a ‘barite recovery centrifuge’ acting on stored drilling fluid, the “barite recovery” would contain too many drilled solids to be effective. Centrifuges separate by mass and not by species or color or flavor. Particles that have the same mass will be found together in one of the discharge streams. Both discharge streams will have barite and low gravity solids in them. Figure FP-40 is drawn accurately, but can be used to estimate ratios of low-gravity solids to barite for both the underflow (heavy slurry) discard from the centrifuge or the solids discarded from a fine screen on the mud cleaner. For example, if the

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DRILLING FLUID PROCESSING

FP-33

Mass percent to underflow, %

Heavy slurry: 13.7 gpm

Density of discards, ppg

Figure FP-40: This chart can be used to estimate ratios of low-gravity solids to barite for both underflow (heavy slurry) centrifuge discard or solids discarded from a fine screen on a mud cleaner.

concentration of total solids was 58% volume instead of 60% volume the decision made from the data wouldn’t change.

Perforated cylinder centrifuge

Particle size, microns Rotary mud separator Processing a 15.0-ppg active mud system Figure FP-41: The D50 cut point of the rotary mud separator (also called a perforated cylinder centrifuge) is around 8-9 microns when processing a 15.0-ppg water-based drilling fluid.

ids can pass through the multiple 1/2-in. perforations to exit through the center shaft. The larger solids are concentrated against the annular wall for discharge at an underflow port.

The rotary mud separator (or perforated cylinder centrifuge, Figure FP-41) processes the drilling fluid by controlling the mass of solids which pass through the perforations in a rotating cylinder. The flow rate of both effluent streams is controlled with positive displacement pumps. The beneficial feature of this centrifuge is the fact that both discharge streams are pumpable. The decanting centrifuge’s heavy slurry is about 55 to 60% volume solids and cannot be pumped. The decanting centrifuge must be mounted over a well-agitated tank so the heavy slurry can be blended with the active system. The rotary mud separator can be positioned near the mud tanks and does not have to be mounted above the tanks.

Flow into and out of the machine is controlled by positive displacement pumps. Two pumps are located at the feed end—one for feed drilling fluid and another for dilution water. A third pump controls the flow split and separation or cut by drawing fluid from the underflow port in the outer cylinder.

The D50 cut point of the rotary mud separator is around 8 to 9 microns when processing a 15.0-ppg water-based drilling fluid. About 10% of the particles between 10 and 15 microns remained in the drilling fluid. About 5 % of the particles between 15 and 20 microns remained in the drilling fluid.

Unlike the decanter which produces one wet and one relatively dry fraction, both slurry streams exiting the perforated cylinder centrifuge are wet and pumpable.

Perforated cylinder centrifuges operate somewhat differently than decanting centrifuges but for the same ultimate purpose. The rotary mud separator consists of a perforated cylinder (or rotor) about 3 ft long, revolving at about 2,300 rpm, which is contained in an outer stationary cylindrical case. A diluted feed of weighted drilling fluid is pumped into the stationary case tangential to the rotor. The unit separates the feed slurry into two streams of differing density and particle size distribution. Under centrifugal force, only the finer sol-

IADC Drilling Manual

The flow capacity varies between 10 and 30 gpm, depending on mud weight and the desired separation. Dilution water used to reduce feed viscosity is generally held to about 70% of the drilling fluid feed rate. Ordinarily a volume equal to 60– 90% of the total of feed mud and dilution water reports to the underflow containing the coarser particle size distribution.

Applications Plastic viscosity can be effectively controlled by discarding a relatively small amount of colloidal size solids from either a water-based drilling fluid or a NADF. Standard centrifuge applications take advantage of their ability to make a very fine cut as illustrated above. When treating weighted water-base drilling fluids, centrifuges can be used intermittently to process a small portion of the volume circulated from the wellbore to reduce the colloidal content and improve the flow properties of the drilling fluid (i.e., decrease PV). The feed to the centrifuge can also

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DRILLING FLUID PROCESSING

FP-34

Table FP-3: Fluid-flow sizing data Fluid flow sizing chart Size: 8 in. wide x 8 in. high with 4 in. liquid depth and clean bottom Required slope Avg. liquid viscosity of trough bbl/min ft3/sec ft/sec Inches drop/running ft 9.5 0.9 4 1/8 in. 11.9 1.1 5 3/16 in. 14.3 1.3 6 1/4 in. 17.8 1.7 7.5 3/8 in. 23.8 2.2 10 1/2 in. *Minimum slope of 1/4 in./ft is the recommended minimum to prevent frequent clogging Fluid flow rate

GPM 400 500 600 750 1,000

Fluid flow sizing chart Size: 12 in. wide x 12 in. high with 4 in. liquid depth and clean bottom Fluid flow rate GPM 900 1,123 1,347 1,684 2,245

Avg. liquid viscosity

Required slope of trough

bbl/min ft3/sec ft/sec Inches drop/running ft 21.4 2 4 1/8 in. 26.7 2.5 5 3/16 in. 32.1 3 6 1/4 in. 40.1 3.75 7.5 3/8 in. 53.5 5 10 1/2 in. *Minimum slope of 1/4 in. / ft is the recommended minimum to prevent frequent clogging Fluid flow sizing chart Size: 15 in. wide x 15 in. high with 9 in. liquid depth and clean bottom Required slope of trough bbl/min ft3/sec ft/sec Inches drop/running ft 37.4 3.5 4 1/8 in. 50.2 4.7 5 3/16 in. 59.9 5.6 6 1/4 in. 75.8 7 7.5 3/8 in. 100.2 9.4 10 1/2 in. *Minimum slope of 1/4 in. / ft is there commended minimum to prevent frequent clogging Fluid flow rate

GPM 1,570 2,110 2,510 3,140 4,210

Avg. liquid viscosity

Fluid flow sizing chart Size: 18 in. wide x 18 in. high with 12 in. liquid depth and clean bottom Required slope of trough bbl/min ft3/sec ft/sec Inches drop/running ft 64.1 6 4 1/8 in. 80.2 7.5 5 3/16 in. 96.2 9 6 1/4 in. 120.3 11.25 7.5 3/8 in. 160.4 15 10 1/2 in. *Minimum slope of 1/4 in. / ft is the recommended minimum to prevent frequent clogging Fluid flow rate

GPM 2,690 3,360 4,040 5,050 6,730

IADC Drilling Manual

Avg. liquid viscosity

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DRILLING FLUID PROCESSING

be decreased so that it is processing a smaller amount per hour but being used during an entire bit run. This will keep the drilling fluid homogeneous instead of allowing solids to increase between uses. In order to remove these solids, the liquid fraction from the decanter (or the lighter slurry fraction from the rotary mud separator) is discarded. The sandsize and silt-size solids remain in the drilling fluid. The centrifuge is installed downstream from all other solids control equipment. Ideally, suction for a centrifuge feed would be taken from the same pit or compartment which receives the discharge from the desilters or mud cleaners. The centrifuge underflow (solids) should be discharged into a well-stirred location in the pit for thorough mixing with the drilling fluid before the solids have a chance to settle to the bottom of the pit. This is especially important with a decanting centrifuge because solids discarded from a decanter will not flow. The centrifuge removes solids which control filtration and low-shear-rate viscosity. These additives must be replaced to keep the drilling fluid specifications in the appropriate order. Frequently, waste disposal costs become so large that they become a driving force to treat drilling fluid instead of drilling performance. These costs are quite visible and attract a lot of attention from personnel not familiar with drilling processes. Costs that are this visible are somewhat like the cost of adding barite to a drilling fluid to increase the density to 10 ppg or 11 ppg. The cost of barite saved will certainly be easily calculated and clearly demonstrate that the ‘dirty’ drilling fluid is much cheaper. The consequences, however, have been demonstrated many times. The total cost of the well increases significantly. If the costs were independent of each other, barite usage would decrease dramatically. Solids can be hauled from a location in dump trucks much cheaper than a vacuum truck. The trend is to ‘dewater’ the drilling fluid, recover the drier solids and return the liquid back to the drilling fluid system. The returning fluid contains the damaging colloidal solids that increase plastic viscosity and affect drilling performance. NADF is reportedly tolerant of drilled solids—primarily because the yield point does not respond in the same manner as it does with drilled solids in a water-based drilling fluid. However, these drilled solid have a great effect on the plastic viscosity and the filter cake thickness. Filter cake thickness can increase without an increase in fluid loss. As matter of fact, drilled solids in either NADF or water-based drilling fluid will decrease the fluid loss but increase the cake thickness.

Operating tips Centrifuges are relatively easy to operate, but they require

IADC Drilling Manual

FP-35

special skills for repair and maintenance. Rig maintenance of centrifuges is limited to routine lubrication of the unit. Although operating procedures will vary in detail from model to model, a few universal principles apply to virtually all centrifuges: • If the solids underflow is to return to the system, locate the centrifuge so the underflow falls into a well-stirred spot; • If the solids underflow is to be discarded (unweighted drilling fluid), locate the machine so the underflow can be removed easily; • Do not locate the machine solids or liquid returns too close to the rig pump suction. Allow time and space for adequate mixing; • Liquid effluent lines should have a constant downward slope.

Bypass trough Bypass troughs after the shale shakers By-pass troughs (or ditches) are a common means of moving drilling fluid during drilling fluid swap-outs. When the drilling fluid is changed from the fluid in the tanks to another fluid, the removal section is not used. The water-based drilling fluid could be changed to a NADF, or the NADF could be changed to a water-based drilling fluid, or a drill-in fluid might be needed, or a completions fluid could be needed in the hole. Bypass troughs are simple, effective, easy to follow and easy to clean. The only real problem with troughs is the tendency of barite and cuttings to settle and clog the troughs. Troughs should be sized so that the average velocity of the fluid is no less than 4 ft/sec and no more than 8 ft/sec. Frequent clogging will occur if the velocity is less than 4 ft/sec. Excessive slopes and messy splashing will occur ifthe velocity exceeds 8 ft/sec. Troughs should have at least 1/4-in./ft of slope so they will tend to be self-cleaning. If a trough is used between the bell nipple and the shakers, its slope may need to be 1 in. or more per ft. The following charts maybe used as guidelines for sizing these troughs.

Slug tank A slug tank or pit is typically a small 20–50 bbl compartment within the suction section of the active system. This compartment is isolated from the active system and is available for small volumes of specialized fluid. Most drilling fluid systems should have more than one of these small compartments. They are manifolded to a mixing hopper so that solids and chemicals may be added and are used to create heavier slurry to be pumped into the drill pipe before trips (i.e., slugs). This makes the fluid level in the drill pipe stand at a lower level than the fluid in the annulus. This prevents

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DRILLING FLUID PROCESSING

FP-36

Table FP-4 Height of slugs Drill pipe (in.)

4 1/2

5

5 1/2

6 5/8

Weight (lb/ft)

16.6

19.5

24.7

25.2

Height filled with 20 and 30 bbl slugs (ft) 20bbl

1,406

1,126

944

579

30 bbl

2,110

1,690

1,415

868

Delta MW for 5 1/2-in. Drill Pipe 2.00

1.20

1.80

1.00

Slug Volume

0.80

20bbl 30bbl

0.60

40bbl 50bbl

0.40 0.20

Mud Weight Increase Needed, ppg

Mud Weight Increase Needed, ppg

Mud Weight Increase for 4 1/2-in. Drill Pipe 1.40

0 9

10

11

12

13

14

15

16

17

18

1.60 1.40

Slug Volume

0.20

20bbl

1.00

30bbl

0.80

40bbl

0.60

50bbl

0.40 0.20

19

0

Mud Weight, ppg

9

10

11

12

13

14

15

16

17

18

19

Mud Weight, ppg

Figure FP-41: Mud weight increases for 4 1/2-in. drill pipe.

Figure FP-43: Increasing mud weight for 5 1/2-in. drill pipe. MW Increase for 6 5/8-in. Drill Pipe 3.50

Increase in MW for 5-in. Drill Pipe 1.60 1.40

Slug Volume

0.20 1.00

20bbl 30bbl

0.80

40bbl

0.60

50bbl

0.40 0.20

Mud Weight Increase Needed, ppg

Mud Weight Increase Needed, ppg

1.80

3.00

2.50

Slug Volume

2.00

20 bbl 30bbl

1.50

40bbl 50bbl

1.00

0.50

0

9

10

11

12

13

14

15

16

17

18

9

19

10

11

12

13

14

15

16

17

18

19

Mud Weight, ppg

Mud Weight, ppg

Ficure FP-42: Increasing mud weight for 5-in. drill pipe.

Ficure FP-44: Mud weight increase for 6 5/8-in. drillpipe

drilling fluid inside the pipe from splashing on the rig floor during trips because the liquid level in the drill pipe will be below the rig floor. These compartments are also used to create various pills or viscous sweeps. The main pump suction is manifolded to the slug pit(s).

The internal volumes of various drill pipes are available in many charts. A few are presented below to use as illustrations of the calculation technique.

The top of the fluid in the drill string while tripping should be about one hundred feet below the surface. A slug of weighted drilling fluid is pumped into the drill pipe to keep the level in the drill pipe below the flow line. The density of the slug or the increase in mud weight above the original density of fluid depends upon the inside diameter of the drill string and the initial mud weight.

IADC Drilling Manual

To create a liquid level inside of the drill pipe 100 ft below the flow line, the mud weight of the slug can be calculated from the equation below which assumes the height of the slug is given for a specific volume of the slug. Sample Calculations:

Eq 11

MWslug =

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MWorig (100 ft + Hslug ) Hslug

DRILLING FLUID PROCESSING

With a 10-ppg drilling fluid in a 4 1/2-in. drill pipe, the mud weight of the 20 bbl slug would be:

the slug. Modify Eq 11, using X instead of the 100 ft and solve the equation for X.

With a 30-bbl slug, the mud weight of the slug should be:

Eq 11

MWslug =

MWorig (100 ft + Hslug ) Hslug

10 ppg(100 ft + 1406 ft) = 10.7 ppg MWslug = 1406 ft

With a 15-ppg drilling fluid in 6 5/8-in., 25.2-lb/ft drill pipe, the mud weight of a 20-bbl slug would be: MWslug =

10 ppg(100 ft + 2110 ft) = 10.5 ppg 2110 ft

Eq 11

MWslug =

MWorig (100ft + Hslug ) Hslug

Eq 12

MWslug =

MWorig (X + Hslug ) Hslug

Eq 13

X=

(MWslug)(H slug)–(MWorig )(Hslug) MWorig

Calculate the depth of the top of a 20 bbl slug in a 15 ppg drilling fluid in 6 5/8-in., 25.2 lb/ft drill pipe, using a slug mud weight of 16 ppg.

With a 30 bbl slug, the mud weight of the slug should be. Eq 13

MWslug =

15 ppg(100 ft + 579 ft) = 17.6 ppg 794 ft

(MWslug)(H slug)–(MWorig )(Hslug) MWorig

X=

From Table FP-4, a 20-bbl slug in a 6 5/8-in., 25.2 lb/ft drill pipe would be 794 ft.

One can calculate the increase in mud weight required 15 ppg(100 ft + 868 ft) = 16.7 ppg MWslug = 868 ft

FP-37

(16ppg )(794 ft )–(15ppg )(794 ft ) = 53 ft 15ppg

X=

to lower the liquid level in the drill pipe. These increases are shown graphically in the next four graphs for 4 1/2-, 5-, 5 1/2-, and 6 5/8-in. drill pipe. Four different slug volumes are used. As would be expected, the increase in mud weight decreases as the volume of the slug is increased. For the largest drill pipe shown here (6 5/8 in.), a small slug of 20 bbl is needed to increase mud weight by 3.1 ppg, if the mud weight was 18 ppg.

In this case, the drilling fluid would probably not drain from the drill string and the crew would say the slug didn’t work.

Sample calculations: • Increase mud weight needed for slug to lower the liquid level in 4 1/2-in. drill pipe to 100 ft below the flow line. • Increase mud weight needed for slug to lower the liquid level in 5 in. drill pipe to 100 ft below the flow line. • Increase mud weight needed for slug to lower the liquid level in 5 1/2-in. drill pipe to 100 ft below the flow line. • Increase mud weight needed for slug to lower the liquid level in 6 5/8-in. drill pipe to 100 ft below the flow line.

Trip tanks

Eq 11 could also be used to determine the location of the drilling fluid surface inside of the drill string for various increases in mud weight. Many drillers use an arbitrary guideline to increase mud weight by different amounts to create

IADC Drilling Manual

If the slug was 30 bbl, the top of the drilling fluid in the pipe would be below the flow line and still ineffective. X=

(16ppg )(868 ft )–(15ppg )(868 ft ) = 58 ft 15ppg

A trip tank is used to measure the volume of drilling fluid entering or leaving the wellbore during a trip (Figure FP-45). The volume of fluid that replaces the volume of the drill string (steel volume) is normally monitored on trips to make certain that formation fluids are not entering the wellbore. When one barrel of steel (drill string) is removed from the borehole, one barrel of drilling fluid should replace it to maintain a constant liquid level in the wellbore. If the drill string volume is not replaced, the liquid level may drop low enough to permit formation fluid to enter the wellbore due to the drop in hydrostatic pressure. This is known as a “kick.” Usually, someone is assigned the responsibility of recording the volume required to fill the hole after each row of drill pipe is racked in the derrick (or alternately specified number of stands). Fluid may be returned to the trip tank during the trip into the well. The excess fluid from the trip tank should be returned to the active system across the shale shakers. Large solids can come out of the well and plug the hydrocyclones if this drilling fluid bypasses the shakers.

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DRILLING FLUID PROCESSING

Table FP-5: Trip-tank displacement

Bell Nipple

Close valves to drill Annular Preventer

Small Centrifugal Pump

Fill from Mud Gun Line

Ram Preventer

TRIP TANK

Figure FP-45: A trip tank is used to measure the volume of drill-

ing fluid entering or leaving the wellbore during a trip.

Flow Distribution Chamber

Scalping Shaker API 10 to API 20 Screens

Close Valve to Drill Fill from Mud Gun Line

TRIP TANK

Bell Nipple

Annular Preventer Ram Preventer

Small Centrifugal Pump

Figure FP-46: If a flow distribution chamber is used to distribute drilling fluid to the main shakers, it can also be used with the trip tank.

The addition of trip tanks to drilling rigs significantly reduced the number of induced well kicks. Trip tanks have replaced the obsolete or older system of drillers filling the hole with drilling fluid with the rig pumps by counting the mud pump strokes (the volume was calculated for the displacement of the drill pipe pulled). The problem here is that a certain pump efficiency is estimated in these calculations. If the mud pump is not as efficient as estimated, slowly but surely the height of the column of drilling fluid filling the hole decreases. This decreases hydrostatic head and if formation pressures are greater than the hydrostatic head of the drilling fluid a “kick” will occur. Another common cause of inducing a kick was to continue filling the hole with the same number of strokes used for the drill pipe even when reaching the heavy weight drill pipe, or drill collars were pulled. Both the heavy weight drill pipe and drill collars have more displacement per stand than the drill pipe. There-

IADC Drilling Manual

Drill pipe size (in.) 3 1/2 3 1/2 4 1/2 4 1/2 4 1/2 5 1/2 5 1/2 5 1/2 6 5/8 6 5/8 6 5/8 7 5/8 8 5/8

wt/ft lb/ft 11.20 13.30 12.75 13.75 16.60 19.00 22.20 22.25 22.20 25.20 31.90 29.25 40.00

displacement gal/100 ft 15.6671 18.8097 17.3403 18.7038 22.8959 25.2813 29.9347 34.8663 28.9939 33.9029 45.3926 39.9840 53.6942

bbl/100 ft 0.3730 0.4479 0.4129 0.4453 0.5451 0.6019 0.7127 0.8301 0.6903 0.8072 1.0808 0.9520 1.2784

fore, a reduction in the height of the column of drilling fluid in the wellbore would occur and problems would result. If a flow distribution chamber is used to distribute drilling fluid to the main shakers, it can also be used with the trip tank (FIgure FP-46). A small centrifugal pump continuously circulates drilling fluid into the wellbore. As pipe is withdrawn, the trip tank calibration can indicate the volume of drilling fluid needed to keep the wellbore filled. If the volume of drilling fluid is less than the volume of pipe removed from the bore hole, a formation may be flowing into the wellbore. The volume of fluid displaced on the trip back into the hole can also be carefully measured. Solids that are displaced from the wellbore, especially on trips back into the wellbore, will be removed by the scalping shaker. The trip tanks can also be connected with valves to keep the top of the hole filled with a small centrifugal pump. The tanks are filled with drilling fluid from the mud gun lines.

Piping and equipment arrangement Drilling fluid should be processed through the solids removal equipment in a sequential manner. The most common problem on drilling rigs is improper fluid routing, which causes some drilling fluid to bypass the sequential arrangement of solids removal equipment (Figure FP-47). When a substantial amount of drilling fluid bypasses a piece or pieces of solids removal equipment many of the drilled solids cannot be removed. Factors that contribute to inadequate fluid routing include ill-advised manifolding of centrifugal pumps for hydrocyclone or mud cleaner operations, leaking valves, improper mud gun setup and use in the removal section, and routing drilling fluid incorrectly through mud ditches. Each unit of solids control equipment should have its own

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DRILLING FLUID PROCESSING

FP-39

Unprocessed Processed Each dot represents 100gpm

NIGHTMARE!!

Hydroclones

Centrifugal Pump

Figure FP-48: Adequate fluid processing with 100% processing efficiency. Figure FP-47: The solids-removal section should have a minimum number of valves so that plumbing is correct for processing fluid correctly.

dedicated, single purpose pump—with no routing options. When the pump is turned on, there should be only one place for the fluid to go. Hydrocyclones and mud cleaners have only one correct location in tank arrangements and, therefore, should have only one suction location. Routing errors should be corrected and equipment color-coded to eliminate alignment errors. If worry about an inoperable pump suggests allowing other pumps in the system to be used, they generally will not process the drilling fluid in a correct manner. Making an easy access to the pumps and having a standby pump in storage can save money. Common and oft heard justifications for manifolding the pumps are “I want to manifold my pumps so that when my pump goes down, I can use the desander pump to run the desilter, etc.” or “I can pump from anywhere to anywhere with any pump”. These statements indicate a poor understanding of drilled solids removal. Unfortunately, some of these conditions are contractual requirements imposed on a drilling contractor by an operator. This arrangement almost automatically guarantees that the system will not process drilling fluid correctly. Having a dedicated pump properly sized and set up with no opportunity for improper operation will give surprisingly long pump life as well as processing the drilling fluid properly.

Fraction of fluid processed The removal section should be arranged so that all fluid entering the suction compartment of the degasser is properly processed through the degasser. All fluid entering the suction compartment of the hydrocyclones should be processed through the hydrocyclones. If multiple paths are provided so that fluid can be pumped from any compartment to any other compartment, the solids removal equipment usually is unable to perform properly. This can be demonstrated with some simple plumbing sketches (Figures FP-48, -49, and -50).

IADC Drilling Manual

Unprocessed Processed Each dot represents 100gpm

Centrifugal Pump

Hydroclones

Figure FP-49: Inadequate fluid processing with 50% processing efficiency.

Processing efficiency is calculated with Eq 14: Eq 14

Fluid Processed Process = 100 Efficiency Fluid Entering Suction Compartment

Adequate processing

For the flow situation illustrated in Figure FP-48, the fluid processed is equal to the fluid entering the suction compartment. Process efficiency is then: 600 gpm Process = 100 = 100% Efficiency 600 gpm

Inadequate processing

In the case shown in Figure FP-49, half the drilling fluid reporting to the surface will not be processed through the hydrocyclones. Drilled solids will increase and trouble follows:

600 gpm Process = 100 = 50% Efficiency 1200 gpm

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DRILLING FLUID PROCESSING

Suction section

Unprocessed Processed Each dot represents 100gpm

Hydroclones

Centrifugal Pump

Figure FP-50: Adequate fluid processing with back flow between compartments.

Normally, the rig should process more fluid through the desilters than is entering the suction compartment. This will provide a back flow through the equalizing line (Figure FP50). If pumps are needed for completions or for drilling fluid swap-out, they should be added to the drilling fluid processing plant. The drilling fluid processing pumps should not be used or manifolded into that system. Although this may look like a more expensive arrangement, a risk analysis of things that can go wrong should convince the most frugal drilling groups that they are well worth the additional expense. Rule: one pump, one switch, one function.

Sizing mud systems Surface drilling fluid systemsizes partially determines drilling fluid costs. Larger volumes of drilling fluid cost more because more ingredients are needed to blend the slurry and maintain it. Maintenance of good drilling fluid properties may cost more but give great financial returns in drilling performance. Control of drilling fluid properties to eliminate visible and invisible Non-Productive Time (NPT) pays great dividends. There are various ways of sizing surface circulating systems. Several factors must be taken into consideration, such as depth capacity of the rig and the area in which it will be working. Obviously, rigs capable of drilling deep wells will require larger fluid systems. Conversely, rigs that specialize in drilling shallow wells might want to have a small, one tank system that facilitates quick rig moves. The tank can be divided into the removal, addition and suction sections. Also, rigs drilling wells with high bottomhole temperatures will need larger surface systems to give the drilling fluid longer to cool before being recirculated. The suction section should contain sufficient fluid to meet various needs when problems arise. The removal section (where undesirable ingredients—like drilled solids and gas—are removed) can be as small as practical to build and maintain.

IADC Drilling Manual

One of the major functions of this section is to contain enough uniform, blended, homogeneous drilling fluid so that well control measurements are always possible. After a kick is detected and the BOP closed, the drill pipe pressure reveals the amount of underbalanced at the bottom of the hole—BUT ONLY IF THE FLUID IN THE DRILLPIPE HAS THE SAME DENSITY FROM TOP TO BOTTOM. When performing a Pressure Integrity Test [PIT] or a Leak-Off Test [LOT], the fluid in the drill string must have the same density from top to bottom. Otherwise it is not possible to calculate the pressure at the end of the drill string.

Surface volumes The largest surface volume of drilling fluid should be in the suction section. Many rules of thumb have been proposed for creating the correct volume of drilling fluid needed on the surface when drilling a well. However, no matter what rule of thumb is used, the fluid in the drill string should have a homogeneous mud weight so that bottomhole pressures may be calculated. One suggestion, and possibly a regulation in some places, requires that one and one-half the hole volume be available on the surface. The two most common rules of thumb are presented below.

Plugged bit method The plugged bit method determines the minimum-size drilling fluid system based on the volume required to fill the hole when pulling a plugged bit and assumes all the fluid inside the drill string is lost. For example, a rig rated to 20,000 ft is capable of handling 5inch drill pipe and 80,000 pounds of drill collars to that depth. The total displaced volume is: • 20,000 ft of 5-in. × 0.0243 bbl/ft = 486 bbl • 80,000 lbs/2,718 lbs/bbl = 29 bbl • Total volume required = 515 bbl This method gives a close approximation of the maximum volume required to fill the hole when tripping a plugged string. Usually the volume is increased by about 20%, or 100 bbl, as a safety factor. This method indicates that the minimum-size suction section should be 615 bbl, plus a reserve to allow for kicks or lost circulation. Usually, the volume of the reserve system should be similar to that of the active system. Total system volume using the plugged bit method in this case is approximately 1,230 bbl.

Cased hole method The cased hole method simply doubles the volume contained in the final string of casing as a guideline for sizing a

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DRILLING FLUID PROCESSING

MUD PUMP SECTION To Trip Tank

REMOVAL SECTION

Suction Tank

Slug Tank

Suction Tank

Suction Tank

ADDITION SECTION

Pill Tank

Mud Hopper

Mud Hopper

Valve

To Disregard or Reserve Agitator

Mud Gun

Figure FP-51: Suction tanks, slug tank, and pill tank arrangements

Table FP-6: Capacity of internal upset drill pipe Dril pipe size (in.)

Weight lb/ft

Capacity l/m

Capacity gal/ft

Capacity bbl/1,000 ft

4

4

6.15

0.4930

11.75

4

4

5.65

0.4551

10.84

4½

4½

7.94

0.6390

15.22

4½

4½

7.42

0.5972

14.22

4½

4½

6.72

0.5406

12.87

5

5

9.85

0.7928

18.88

5

5

9.27

0.7560

17.76

5

5

8.11

0.6520

15.54

5½

5½

11.57

0.9314

22.18

5½

5½

11.05

0.8898

21.19

6 5/8

6 5/8

18.64

1.5008

35.73

6 5/8

6 5/8

19.03

1.4517

34.56

6 5/8

6 5/8

16.82

1.3541

32.24

IADC Drilling Manual

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DRILLING FLUID PROCESSING

suction system. For example, consider a rig rated to 15,000 feet, with 7-in. casing as the final string. The total cased hole volume is: 15,000 ft of 7-in. casing × 0.0390 bbl/ft = 585 bbl Doubling this volume gives a total suction volume of approximately 1,200 bbl. The fluid in this section should be blended to be a homogeneous slurry ready to be pumped down the hole. When the well is shut-in because of a kick, the standpipe pressure is read to determine the under-balance pressure at the bottom of the hole. The drilling fluid in the drill string must have the same mud weight from top to bottom for these readings to be have any meaning. A 4-in. diameter cylinder has a volume of 16 barrels per 1,029 ft. A 4-in. diameter cylinder could represent the drill string. A 15,000-ft length of the four inch drill string could represent the drill string. It would have a volume of 233 bbl. Between two and three times this volume should be available in the suction section to insure homogeneous mud weight in the drill string while drilling. The capacity of some common drill pipe sizes is presented in the table for Capacity of Internal Upset Drill Pipe. From a practical point of view, there are three conditions which should also be addressed: • Lost circulation; • Rapid drilling in large diameter holes; • Deep drilling with large diameter drill pipe.

Lost circulation In regions where vugular formations are prevalent, large quantities of drilling fluid may be required. Frequently in some areas where the formations cannot be sealed, drilling requires a mud cap on the annulus above the lost circulation zone. Naturally fractured formations can ‘drink’ a large quantity of drilling fluid and the processing plant on the surface needs to be geared to blending fluid rapidly. However, many lost circulation problems are created by allowing the drilled solids to build within a drilling fluid. Very low drilled solids content has been demonstrated to circumvent lost circulation in many cases. Wells have been drilled through very permeable, depleted Miocene sands with no lost circulation (or stuck pipe) with intervals of pressure differentials as much as 6,000 psi between the wellbore pressure and the formation gas pressures. The 11.0-ppg drilling fluid had less than two percent drilled solids in it.

Rapid drilling in large diameter holes Large surface holes drilling at 200 to 400 ft/hr will gener-

IADC Drilling Manual

ate a large number of cuttings. If fine screens are used, a large volume is removed as these cuttings are discarded. In a 20-in. diameter hole drilling at 400 ft/hr will generate about 780 barrels of cuttings in five hours. The discard of the wet cuttings will remove about 2,340 bbl of fluid from the mud system. This quantity of fluid must be rebuilt during this period to keep the pit levels constant. On an hourly basis, 155 bbl of hole is generated. Assuming that this is 1/3 of the discard (the solids are wet when they are removed), 465 bbl must be rebuilt every hour, or new drilling fluid mixed at about 8 bbl/min. It would probably be prudent to have three times the 465 bbl, or about 1,400 bbl, available in the active surface system to maintain constant rheology and mud weight while drilling. The surface system must have the capability to keep up with the volume discarded while drilling, otherwise advanced planning and premixing of reserve mud should be considered. This should be planned for the worst case which would be bigger diameter hole where high penetration rates are common. For example, for a 14 3/4-in. hole section drilling at an average rate of 200 ft/hr and with a solids removal efficiency of 80%, the removal system will be discarding approximately 34 bbl of drilled solids per hour plus the associated drilling fluid coating these solids. Normally the drilled solids are about 30 to 40% volume of the discard. In most instances, about a minimum of two to four barrels of material will be discarded for every barrel of hole drilled. If this is the case, the volume of drilling fluid in the active system will decrease by 400 barrels per hour. If the rig cannot mix drilling fluid fast enough to keep up with these losses, reserve mud and or premixed drilling fluid should be available to blend into the active system to maintain the proper volume.

Deep drilling with large diameter drill pipe The trend in offshore drilling is to use large diameter drill pipe to decrease the pressure loss inside the drill string and to increase the annular velocity to improve hole cleaning. However, when performing a pressure integrity test (PIT) or taking a kick, the surface pressure will be used to determine the bottomhole pressure. The drilling fluid within the drill string must be a homogeneous slurry—same mud weight from top to bottom—to be able to make accurate measurements. For example, when a well is shut-in after taking a kick, the surface pressure is measured at the upper end of the drill string. The amount of additional mud weight needed to kill the well is calculated from that pressure. If half the drill pipe is filled with a lighter, or heavier, drilling fluid, the calculation will not be possible. The amount of fluid necessary to fill a drill string can be estimated from an approximate relationship. A square of

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DRILLING FLUID PROCESSING

the diameter (in inches) of a cylinder is the volume of the cylinder in barrels per 1,029 ft. This can be used to quickly approximate the volume of fluid needed to fill a 14,000-ft string of 5-in. drill pipe. The inside diameter of 5-in. drill pipe is around 4.2-in. The volume of a 4.2-in. diameter cylinder is approximately 18 bbl/1,000 ft. The volume of a 14,000 ft cylinder with this diameter would be 250 bbl (14 times 18). To maintain a uniform blend of drilling fluid in the drill pipe, three to four times this volume should be available in the suction tank. For a more rigorous calculation, from the table, a 5-in., 19.5 lb/ft drill pipe, 14,000 ft long, would have an internal volume of 248.6 bbl.

Sizing steel pits Once the volume of the drilling fluid system is determined, the general layout and individual tank sizes may be considered. There should be sufficient space for solids removal equipment, pit agitators and fluid transfer pumps. Other considerations are placement and size of equalizer lines, bypass troughs, compartments, pump suction and discharge lines, water lines and additional operator-specified equipment. The overall weight and dimensions of each mud tank on land rigs have transportation limitations based on local transport regulations. Using the earlier example of a 615-bbl system, this system requires approximately:

FP-43

Assume the rig pumps cannot effectively pick up the bottom 18 in. of drilling fluid and most crews run the fluid system about one ft below the top of the tank. This means that 2.5 ft of the inside tank height is unusable. For a mud tank height of 8 ft, the usable height is 5.5 ft. With a tank width of 8 ft, each linear foot of tank length contains: 8 ft × 5.5 ft = 44 sq ft In this example, overall tank length should be: 3,450 cu ft /44 sq ft = 78 ft This length for the additions and suction section will be adequate to fill the final string of casing or when tripping with a plugged drill string. These tanks must be well-stirred to create a homogeneous fluid in case of a kick and to prevent solids settling which would greatly reduce the available volume of fluid available when needed. After the volume of drilling fluid necessary is determined and some rough estimates of width, height and total length have been made, each section can be planned. An innovative tank suction arrangement places the suction at the very bottom of the tank, placing a large flat plate above the suction as a vortex breaker. With this arrangement, it is often possible to draw fluid levels down almost to the plate height before the centrifugal pump begins to suck air. This increases effective tank volume. Another tank suction arrangement uses a small sump with the pump suction line drawing from this sump. This further increases tank draw down and maximizes usable tank volume.

615 bbl × 5.61 cuft/bbl= 3,450 cu ft of usable suction tank volume.

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DRILLING FLUIDS

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

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

DRILLING FLUIDS

FL-i

CHAPTER

FL

DRILLING FLUIDS

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.

Principal Authors Paul Scott, ConocoPhillips Paul Broussard, Repsol Mike Freeman, Schlumberger/M-I Swaco Fred Growcock, Oxy Ron Bland, Baker Hughes

Reviewers Tom Carter, Chevron Ben Bloys, Chevron Malcolm Ellice, Halliburton Joe Hurt, IADC Alan Spackman, IADC Paul Breaux, IADC

FL–ii

DRILLING FLUIDS

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: 978-0-9915095-4-6

Printed in the United States of America.

IADC Drilling Manual

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DRILLING FLUIDS Contents CHAPTER FL

DRILLING FLUIDS/CIRCULATING SYSTEM/DRILLING AND COMPLETIONS Introduction......................................................................FL-1 Drilling fluid function and performance...................FL-1 Physical operating principles...............................FL-2 Testing drilling fluid properties...................................FL-2 Purpose of testing...................................................FL-2 Density or mud weight..........................................FL-2 Viscosity....................................................................FL-2 Gel strengths........................................................... FL-4 Filtration or fluid loss............................................ FL-4 Sand content............................................................FL-5 Solids, oil and water content...............................FL-5 Chemical content....................................................FL-5 Importance of the drilling fluid...................................FL-5 General rig personnel involved...................................FL-5 Categories of drilling fluids..........................................FL-5 Pneumatic drilling fluids........................................FL-7 Dry gas...............................................................FL-7 Mist.................................................................... FL-8 Foam.................................................................. FL-8 Aerated fluids.................................................. FL-8 Water-based fluids (aqueous fluids)................ FL-8 Water or brine................................................. FL-8 Spud mud......................................................... FL-8 Native muds..................................................... FL-8 Low-solids systems........................................ FL-9 Low-solids/non-dispersed system............ FL-9 Polymer muds................................................. FL-9 Lightly treated muds..................................... FL-9 Flocculated bentonite systems................... FL-9 Dispersed muds.............................................. FL-9 Seawater or brackish water......................... FL-9 Saturated salt.................................................. FL-9 Inhibitive drilling fluid systems................. FL-10 Potassium chloride (KCl) polymer.......... FL-10 KCl polyglycol................................................ FL-10 Polyamine systems...................................... FL-10 Calcium systems.......................................... FL-10 Silicate systems............................................ FL-10 Encapsulating polymer systems.............. FL-10 High-performance water-based muds (HPWBM)...................................................... FL-10 High-temperature (HT), high-temperature/

IADC Drilling Manual

FL-iii

Contents high-pressure (HTHP) and ultra-HTHP systems........................................................... FL-11 Non-aqueous-based mud systems (oil-based)............................................. FL-11 Invert emulsions........................................... FL-11 Calcium soap systems................................ FL-12 Surfactant emulsifier systems.................. FL-12 Low-clay, flat rheology systems.............. FL-12 Relaxed fluid-loss systems........................ FL-12 All oil systems............................................... FL-12 Special application fluids................................... FL-12 Completion brines........................................ FL-12 Drill-in fluids.................................................. FL-12 Other special application fluids............... FL-12 Additives................................................................. FL-12 Weight materials.......................................... FL-13 Viscosifiers..................................................... FL-13 .Filtration control additives (fluid-loss control additives)........................................................ FL-13 Thinners (deflocculants)............................ FL-13 pH/alkalinity control chemicals............... FL-13 Calcium removers........................................ FL-13 Surfactants and emulsifiers...................... FL-13 Shale inhibitors............................................. FL-14 Corrosion inhibitors/scavengers/ biocides........................................................... FL-14 Lubricants....................................................... FL-14 Defoamers...................................................... FL-14 Flocculants..................................................... FL-14 Temperature stability agents.................... FL-15 Foaming agents............................................. FL-15 Hydrate supperssants................................. FL-15 LCM/bridging agents.................................. FL-15 Location on a rig site................................................... FL-15 Installation............................................................. FL-16 Safety and handling..................................................... FL-16 Proper handling for safety................................. FL16Fire hazards and zones............................... FL-16 Chemical hazards.........................................FL-17 Hydrogen sulfide (H2S).......................FL-17 Carbon dioxide (CO2)..........................FL-17 Carbon monoxide (CO)........................FL-17

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DRILLING FLUIDS

Lime...........................................................FL-17 Caustic (sodium hydroxide or NaOH) and caustic potash (Potassium hydroxide or KOH)................................................... FL-18 OBM surfactants....................................FL-18 Physical hazards........................................... FL-18 Heat.......................................................... FL-18 Sack cutting............................................ FL-18 Cranes...................................................... FL-18 Noise..........................................................FL-19 Pits and walkways.................................FL-19 Closed-vessel entry...............................FL-19 Tank strength..........................................FL-19 Spills...........................................................FL-19 Lifting.........................................................FL-19 Waste disposal.......................................FL-19 Pressure washing/rig cleaning...........FL-19 Use of icons/colors/risk factors to visually denote danger........................................................FL-19 System maintenance and contamination treatments..................................................................... FL-20 General maintenance of drilling fluid properties..................................................... FL-20 Density (mud weight)........................................ FL-20 Rheology increase........................................ FL-20 Rheology decrease....................................... FL-20 API and HTHP fluid loss.................................... FL-20 Salinity.................................................................... FL-20 Alkalinity (pH control)....................................... FL-20 Total hardness/excess lime content.............. FL-21 Sand content......................................................... FL-21 Solids, water and oil content............................ FL-21 Methylene blue test............................................ FL-21 Electrical stability................................................ FL-21 Contamination treatment for drilling fluids. FL-21 Potential problems that can affect mud systems................................................................. FL-21 Weight material settling or sag....................... FL-21 Sag or settling treatment and prevention recommendations................................................ FL-21 Static settling................................................. FL-21 Dynamic settling........................................... FL-25 Bed slumping................................................. FL-25 Corrosion................................................................ FL-25 General treatment procedures................. FL-25 Dissolved oxygen......................................... FL-25 Acid gases (CO2 and H2S)....................... FL-25 Bacterial degradation.................................. FL-25 Gas hydrates......................................................... FL-25 Prevention and mitigation recommendations when drilling with a riser............................ FL-26

WBMs..................................................................... FL-26 NAFs........................................................................ FL-26 Well operations.................................................... FL-26 Deepwater riser issues....................................... FL-26 Hole cleaning................................................. FL-26 Rheology effects........................................... FL-26 Balling with WBM........................................ FL-26 Stuck pipe.............................................................. FL-26 Treatments..................................................... FL-26 Lost circulation..................................................... FL-27 Salt formations and rubble zones................... FL-27 Treatments............................................................ FL-27 HTHP conditions.................................................. FL-28 Wellbore stability issues................................... FL-28 Calculations and tables.............................................. FL-29 Brine tables............................................................ FL-29 Important calculations....................................... FL-29 Volume of mud in the circulating system..... FL-29 Surface system volume calculations.............. FL-29 Rectangular tank volume........................... FL-29 Upright cylindrical tank volume............... FL-31 Hole volume calculations (pipe in hole).FL-31 Annular volume (or pipe displacement).FL-31 Pipe (or hole) capacity....................................... FL-31 Circulation times and strokes........................... FL-31 Pump output and circulation rate............ FL-31 Triplex mud pumps............................. FL-31 Duplex mud pumps............................ FL-32 Mud cycle (complete circulation of active system)................................................................... FL-32 Bottoms up (bit to surface).............................. FL-32 Surface to bit (pipe capacity displacement).FL-32 Hole cycle time..................................................... FL-33 Hole volume (pipe out of hole)........................ FL-33 Hydrostatic pressure and hydrostatic gradient................................................................... FL-34 Quantities of mud materials............................. FL-35 Weight-up formula....................................... FL-35 Volume increase due to material additions......................................................... FL-35 Dilution and blending.................................. FL-35 Annular velocity................................................... FL-36 Government regulations............................................FL-40 Health and safety regulations..................................FL-40 Environmental regulations........................................ FL-41 Transportation regulations........................................FL-43 Cited references...........................................................FL-44 Additional references.................................................FL-45 Appendix: Safety data sheets, hazard labels & NFPA Diamond........................................................ FL-A1

DRILLING FLUIDS

Introduction

FL-1

The principal functions of drilling fluid are to:

Drilling fluids are fluids that are used during the drilling of subterranean wells. They provide primary well control of subsurface pressures by a combination of density and any additional pressure acting on the fluid column (annular or surface imposed). They are most often circulated down the drill string, out the bit and back up the annulus to the surface so that drill cuttings are removed from the wellbore.

• •

Control subsurface pressures, maintaining well control; Remove drill cuttings from beneath the bit and circulate them to the surface; • Maintain wellbore stability, mechanically and chemically; • Transmit hydraulic energy to the drill bit and downhole tools; • Cool and lubricate the drill string and bit; Drilling fluids have a number of alternative names, acronyms • Allow adequate forand slang terms used within mation evaluation; the industry. The most widely • Provide a completed used name is “mud” or “drillwellbore that will produce hying mud” and both these terms drocarbons; will be used interchangeably • Suspend or minimize throughout this chapter. Oththe settling of drill cuttings or er drilling fluid names and weight material when circulaacronyms are: water-based tion is stopped, yet allow the mud (WBM), oil-based mud (OBM), synthetic-based mud Figure FL-1: Drilling fluids are major factors in a successful drilling removal of drill cuttings in the surface fluids processing sys(SBM), non-aqueous fluid program. Courtesy MI-SWACO, a Schlumberger company. tem; and (NAF), invert emulsion fluid • Form a low permeability, thin and tough filter cake (IEF), high performance water-based mud (HPWBM), drill-in across permeable formations. fluid (DIF) and reservoir drilling fluid (RDF). Similar to drilling fluids are so-called completion fluids that are used to finish The performance of these functions depends upon the type the well after drilling is completed. The fluids used during of formation being drilled and the various properties of the completions are often referred to as workover and compledrilling fluid. Often, compromises are necessary due to a vation (WOC) fluids, clear brines and/or packer fluids. riety of factors. The selection and design of a particular drilling fluid and its properties depends on the complexity of the Drilling fluid is a major factor in the success of the drilling well being drilled, subsurface pressures and temperatures, program and deserves careful study. Discussion in this manlogistics, cost and local experience. Drilling fluid perforual, however, is limited to its general features. A compremance is also affected by the drilling equipment being used. hensive and more academic text on drilling fluids is “Composition and Properties of Drilling and Completion Fluids” by The properties of the drilling fluid should be adjusted to the Caenn, Darley and Gray. The suppliers of drilling fluid matehydraulics available for the drilling operation and the well derials also offer a wide range of publications and numerous sign. Rate of penetration (ROP) and bit life can be improved articles can be located in the technical literature of the oil by optimizing the hydraulic horsepower at the bit, especially and gas industry. for roller cone bits. The ROP and bit life for polycrystalline diamond compact (PDC) cutter bits is improved when an adequate flowrate is used with minimal overbalance. Drilling fluid properties and circulation rates determine the parasitic Drilling fluids range from simply water or oil to compressed pressure losses in the drill string and the available pressure at air and pneumatic fluids to more complex water-based or the bit for optimized drilling performance. The ROP is also afoil-based systems. Drilling fluid additives include weightfected by the density of the mud and nature of the suspended ing materials; viscosifiers; filtration control additives; pH/ solids. Regular and complete tests are essential to the control alkalinity control chemicals; dispersants/deflocculants/ of mud properties. The interpretation of the results of these thinners; surfactants and emulsifiers; shale inhibitors; corrotests and treatments to maintain appropriate fluid properties sion inhibitors/oxygen scavengers/hydrogen sulfide (H2S) is vital to the success of the drilling program. scavengers; lubricants; and bridging agents/lost circulation materials (LCMs). A brief description of these categories is included later in this section.

Drilling fluid function and performance

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DRILLING FLUIDS

Testing drilling fluid properties

,

Various properties of drilling fluid are monitored and adjusted to achieve desired performance. Procedures for measuring fluid properties can be found in API Recommended Practice 13B-1 for water-based drilling fluids and Recommended Practice 13B-2 for oil-based drilling fluids. These procedures are revised and extended periodically as improvements are made and new tests are developed.

Purpose of testing

Routine testing is carried out on drilling fluids to determine the following: the density or mud weight; viscosity; gel strengths, filtration rate (also called fluid loss); sand content; solids, oil and water content; and chemical properties.

Density or mud weight

Density or mud weight is the mass per unit volume. In the field, it is measured with a mud balance and is most often reported in pounds per gallon (lb/gal or ppg); specific gravity or SG (g/ml); kilograms per cubic meter (kg/cu m); or pounds per cubic foot (lb/cu ft). Density is used to determine the hydrostatic pressure of the mud column and can also be measured and expressed as a gradient such as pounds per square inch per thousand feet (psi/1,000 ft). This allows for easy calculation of the hydrostatic pressure at any depth.

Figure FL-2: Basic land rig circulating system.

Physical operating principles

The three main functions of drilling fluids are to: • Control subsurface pressures: These pressures are controlled by the hydrostatic pressure of the drilling fluid plus any surface-imposed pressure on the annulus. While circulating, annular pressure losses also impose additional pressure on the wellbore. Hydrostatic pressure is increased by increasing the density of the drilling fluid. This is normally carried out by adding barite (BaSO4), a high-density inert powder. • Circulate drill cuttings from the well: This is dependent on a combination of fluid velocity, fluid viscosity, fluid density and drill string rotation. • Maintain wellbore stability: This is dependent on the strength of the rocks being drilled, local subsurface stresses, differential pressure at the wellbore, drilling fluid chemistry, formation composition, filtration control, filter cake quality and bridging solids.

The mud scale is calibrated with water (freshwater weighs 8.34 lb/gal and seawater weighs 8.55 lb/gal). The mud scale has four units scales graduated on the beam: lb/gal or ppg, g/cc, lb/cu ft and psi/1,000 ft. Please refer to the section entitled Calculations and Tables for the appropriate calculations and unit conversions.

Viscosity

Viscosity is a measure of the drilling fluids internal resistance to flow, or how thick or thin it is. Drilling fluids are non-Newtonian, meaning that their viscosity is not constant for all shear rates. These non-Newtonian fluids behave very differently than liquids like water or oil which are Newtonian with a constant viscosity regardless of shear rate. Non-Newtonian drilling fluids are shear thinning such that they have lower viscosity at high-shear rates and higher viscosity at low-shear rates. This is desirable for drilling where minimum pressure losses are wanted for the high-shear conditions inside the narrow bore of the drill string. Higher viscosity is wanted in the low-shear conditions of the larger annulus. Viscosity depends on the viscosity of the base liquid and the

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type and concentration of solids in the drilling fluid. Viscosity is usually higher for higher density fluids due to the increased concentration of weight material such as barite. As a general rule, thicker fluids are needed for larger diameter hole sizes and thinner fluids are needed for smaller hole sizes which have smaller annular flow areas. Viscosity is measured with two primary tools; a) the Marsh funnel (Figure FL-3) which is used to frequently measure relative changes in viscosity, and b) a direct reading viscometer (Figure FL-4), which is used to measure the viscosity, gel strengths, and non-Newtonian characteristics precisely. The Marsh funnel is used to monitor relative changes in viscosity and is commonly reported as “funnel viscosity”. The Marsh funnel viscosity is reported as the number of seconds required for a given fluid to flow a volume of 1 qt into a graduated mud cup. Its design and calibration can be verified using water. One quart of fresh water should be collected in 26 (±0.5) sec at a temperature of 70 (±5) °F.

Figure FL-3: Drilling fluid balance and Marsh funnel are used to measure fluid viscosity.

A direct indicating rotational viscometer is used to measure the viscosity at different shear rates to determine the rheology model coefficients. For field operations, the Bingham plastic rheology model coefficients of plastic viscosity (PV) and yield point (YP) are monitored. These two coefficients are used to monitor the non-Newtonian properties of the drilling fluid. These viscometers indicate the shear stress as a “dial unit” or “degree” (Ɵ) at a given shear rate (one dial unit equals about 1 lb/100 sq ft). The dimensions of the direct indicating viscometer are selected so that the PV and YP can be quickly calculated from the shear stress values measured at shear rates of 600 and 300 rpm. The PV in centipoise (cps) is calculated from the 600-rpm dial reading (Ɵ600) minus the 300-rpm dial reading (Ɵ300). The YP in lb/100 sq ft is then calculated from the 300-rpm dial reading minus the PV. PV (cps) = Ɵ600 – Ɵ300

Eq 1

YP (lb/100 sq ft) = Ɵ300 – PV

Eq 2

Viscosity should be measured and reported at standard temperatures which are usually 120°F for most wells or 150°F for high-temperature wells. Shear stress values should also be measured at other shear rates for improved accuracy when calculating pressure losses and when cleaning the hole. Typical six speed shear rates are taken at 600, 300, 200, 100, 6 and 3 rpm. The Bingham plastic YP overestimates the real YP for most drilling fluids as well as the shear stress values at lower shear rates. For this reason, using better rheology models such as the Herschel Bulkley model is recommended for improved accuracy.

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Figure FL-4: Direct indicating viscometer (6 speed).

The PV depends mainly on the concentration of solids and the viscosity of the base liquid. It is representative of highshear rate viscosity such as is present inside the bore of the drill string. The YP is a measure of the degree of non-Newtonian shear thinning behavior (increased thickening at lowshear rates is implied from higher YPs). The YP is a result of the attractive forces between particles in the fluid at lower shear rate conditions. It is also a measure of the hole cleaning capabilities of a fluid in vertical intervals. Often, a low-

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DRILLING FLUIDS an indication if the fluid is continuing to gel with longer periods of time (called progressive gels) or if it has reached a relatively constant value (called flat gels).

Filtration or fluid loss

Filtration or fluid loss is a relative measure of the liquid that could invade a permeable formation through deposited mud solids. This liquid is called filtrate and the deposited solids are called filter cake or mud cake. There are two standard filtration tests that measure the volume of filtrate collected after a 30-min period of time using filter paper. These tests are the low-temperature/low-pressure fluid loss test, often called the American Petroleum Institute (API) test, and the high-temperature high-pressure (HTHP) test. Results are reported as the milliliters (ml) which flow through a 7.1-sq in. area. The HTHP filtration test unit is a half-area (3.5-sq in.) press; therefore, the measured filtrate value is doubled for reporting. Filter cake thickness is measured and reported in units of 1/32 in. (or millimeters where SI units are used). A filter cake thickness of 3 means 3/32 in.

Figure FL-5: API low-temperature, low-pressure filter press.

shear-rate yield point (LSRYP) is calculated using the shear stress values at 6 rpm and 3 rpm to better evaluate the real YP, the hole cleaning potential and the propensity for having barite sag. LSRYP = (2 x Ɵ3) - Ɵ6

Eq 3

Gel strengths

Gel strengths refer to the shear stress required to initiate flow after static periods of time. They are a measure of the degree of gelation that occurs due to the attractive forces between particles over time. Higher gel strengths are reported in the same units as YP (lb/100 sq ft). Sufficient gel strength will suspend drill cuttings and weighting materials during connections and other static conditions. Gel strengths directly affect surge and swabbing pressures when making connections, tripping pipe or running casing. They also affect the pressure required to “break circulation” and the ease of releasing entrained gas or air. Gels are determined using the same direct indicating rotational viscometer as is used for viscosity. They are measured by observing the maximum shear stress value while slowly turning the rotor or by using the 3-rpm setting after being static for some period of time. Standard values for gel strength are taken after 10 sec, 10 min and sometimes after 30 min. The change in gel strength values between these time periods also give

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The basic filtration test is called the low-temperature/ low-pressure or API fluid loss test and is performed at ambient temperatures and 100 psi. The more advanced test is the HTHP filtration test that is performed at a temperature closer to the bottomhole temperature and at a 500-psi differential pressure. While there is no standard temperature for the HTHP test, temperatures between 275°F and 325°F are often set as the standard. This, of course, is dependent on the area and operator. The HTHP test should preferably be run at the actual bottomhole temperatures and differential pressures existing in the wellbore, if possible. Filtration rate and filter cake thickness are both monitored and reported properties. High fluid loss and thick filter cakes significantly increase the possibility of having differentially stuck pipe. A desirable filter cake is one that has ultralow permeability and is thin, tough, compressible and slick (lubricious). These desirable properties cannot be determined from the fluid loss values alone and many low fluid loss drilling fluids do not have a good quality filter cake. A desirable filter cake is achieved by minimizing the drill solids content (colloidal-sized solids) of the drilling fluid and maintaining the proper concentration of filtration control additives. For most WBMs, the best quality filter cake is achieved by using an adequate quantity of high-quality bentonite. There are many factors affecting filtration control including: thermal stability of the system; concentration, size, and type of solids; the type and concentration of filtration control additives being used; and the presence of any contaminants in the mud. Filtration control comes with increased cost. Local experience and the frequency of stuck pipe should be used to establish the target values for fluid loss and filter cake for the formation and hole interval.

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DRILLING FLUIDS

Sand content

Sand content refers to the volume percent of whole mud that are “sand sized” particles, meaning they are larger than 74 microns and do not pass through a 200 mesh screen. These may be actual quartz sand or may be the coarse-sized barite particles, sized bridging solids, LCM, drilled solids or any other particles larger than 74 microns. Sand content is measured using a sand content graduated glass tube, funnel and 200 mesh sieve. It is monitored to gauge the effectiveness of solids control equipment, the shale shaker screen condition and the potential for increased abrasion to mud pumps and other equipment in the circulating system including drill string and downhole equipment.

Solids, oil and water content

Solids, oil and water content are measured using a distillation report. With this information and other data from the chemical analysis, a complete breakdown of the composition of the drilling fluid can be made, often called a solids analysis. This will include oil content, water or brine content, low-gravity solids (mainly drill solids) and high-gravity solids (normally barite). Solids content affects drilling rate, flow properties, gel strengths and the overall stability of the mud. Often, the frequency of dilution and chemical treatments are based on the results from this analysis. Optimum solids content and good solids control is essential for overall superior mud performance.

Chemical content

Chemical tests are carried out on the whole mud and filtrate to monitor specifications and to identify contamination. Depending on the type of drilling fluid being used, these tests may include: pH, various measures of alkalinity (PM, PF, and MF for WBM and POM for NAF), lime content, chloride (or salt), calcium (or total hardness), carbonate/bicarbonate, sulfate, methylene blue test (MBT), H2S, electrical stability, water activity and others. A description of these chemical tests is outside the scope of this document, although the significance of some of these tests is shown in the section entitled System Maintenance and Contamination Treatments.

Importance of the drilling fluid

The performance of the drilling fluid is critical to everyone involved with the operation and to all aspects of the drilling operation. The drilling fluid is the primary means to keep the well from blowing out and it is responsible for keeping the hole in good condition such that drilling operations can continue to the desired depth. Drilling and completion fluids are one of the most important parts of the well construction process and ultimately the performance of the fluid will determine the success or failure of the operation. The responsibility of the proper selection and application of the drilling

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fluid is held jointly between the fluids supplier, the drilling contractor and the operator.

General rig personnel involved

The general rig personnel involved with monitoring, operating and maintaining the drilling fluid are the drilling fluids technician (called the mud engineer) and one or more of the drilling crew. The drilling fluids technician is normally employed by the drilling fluids supplier or may be a consultant working for the operator or drilling contractor. The mud engineer performs periodic testing of the drilling fluid properties and recommends the treatments to be made. The derrickman is most often the rigsite worker who monitors mud weight and funnel viscosity, adds chemicals and controls the fluid processing equipment. The driller controls flow of the drilling fluid to the wellbore with the mud pumps. On more complicated operations such as deepwater and offshore operations, the drilling fluid responsibilities described above for the derrickman may be performed by additional rig crew. This is usually someone assigned to monitor the shale shakers, mud pits and/or mixing operations.

Categories of drilling fluids

There are three broad categories of drilling fluids: • Pneumatic fluids, which use compressed air or gas, foam and aerated muds; • WBMs, which use water or brine as the base fluids; and • NAFs, which use oil or other non-aqueous base fluids called OBMs or SBMs. Within each of these three broad categories, there are numerous variations in fluid properties and products that may be used dependent on the practices in an area and the drilling fluids supplier. Numerous common names, acronyms, abbreviations and trade names can describe the particular system being used. The selection of the drilling fluid system for a particular well is based on numerous factors including: local practices; operator preferences; supplier’s range of systems and products; density required to control subsurface pressures; hole size; characteristics of the formations to be drilled (including wellbore stability); anticipated temperature and pressure; completion type; common regional drilling problems; logistics; cost and quality; and health, safety and environmental (HSE) considerations. Wells are spudded with simple low-density drilling fluids and altered with each interval to address the conditions of the particular interval being drilled. Generally, the density and complexity of the drilling fluid system being used increases with depth due to increased pressures and tem-

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DRILLING FLUIDS

Pneumatic

Dry Gas (air, N2 or field gas)

Water Base

Water or Brine

Oil Base ( Non Aqueous)

100% or All Oil

Special Application Fluids

Completion Fluids (Clear Brines)

Drill-In Fluids Emulsions Mist

Spud Muds Other (milling, packers, spacers, pills, spotting fluids

Native Muds

Foam Low Solids; lowsolids/ non-dispersed, polymer, lightlytreated

Aerated liquids Dispersed

Inhibitive; potassium, calcium, silicate, Polymer encapsulating

High Performance WBM

Figure FL-6: General classification of drilling fluids.

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peratures. The categories of products used in drilling fluids by functionality are: base fluid; weight material; viscosifiers; fluid loss control additives; pH or alkalinity control; viscosity thinners; surfactants or emulsifiers; shale inhibitors; corrosion inhibitors; lubricants; bridging agents; and LCMs.

Dry gas and mist drilling use a blooie line to contain the flow and direct it to a cuttings pit which is a sufficient distance from the rig. Air, mist and foam drilling are open-ended circulating systems where the fluids are not recirculated.

The required density is one of the primary considerations when selecting a drilling fluid. Table FL-1 gives the approximate minimum and maximum density values for drilling fluids while Table FL-2 provides the approximate minimum and maximum density values for completion brines which are sometimes used as the base fluid for drilling muds. The listed minimum densities are the lowest densities that make economic sense for a particular salt.

Mist drilling is similar to dry air drilling except it uses a small volume of injected surfactant and water. This prevents

Pneumatic drilling fluids

Pneumatic drilling fluids comprise: • Dry gas, including air, nitrogen and field gas; • Mist; • Foam; • Aerated fluids. Drilling with pneumatic fluids is covered extensively in the Managed Pressure, Underbalanced and Air/Gas/Mist/ Foam Drilling Chapter of the IADC Drilling Manual, 12th edition.

Dry gas

Dry gas drilling is often called air or dust drilling. It is used mainly in areas with hard, competent and dry formations, especially in areas where severe lost circulation occurs. Pneumatic fluids include air or dust drilling, nitrogen (generated with membrane units), natural gas, mist, foam and aerated liquid systems. Drilling with pneumatic systems is often referred to as underbalanced drilling or UBD because the hydrostatic pressure is less than the pore pressure of the formation. The advantages of using pneumatic fluids are an elimination or reduction in lost circulation and much higher ROPs, often more than three times that of mud drilling. Air hammers and special hammer bits can be used with air or mist drilling which significantly increases ROP and bit life. Disadvantages of pneumatic operations include: additional equipment; complexity; possibility of downhole fires or flammability of produced fluids at the surface; and the potential for aggressive corrosion. For dry gas drilling, compressed gas is injected at the standpipe at a volumetric flowrate that is sufficient to circulate cuttings from the hole based on the size of the hole, ROP and depth. Dust is expelled from the well at the outlet. Dry gas can be used until significant amounts of formation water or oil are produced into the annulus. All pneumatic fluids use a rotating control device (rotating head) to seal the annulus at the surface and direct the flow safely away from the rig floor.

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Mist

Table FL-1: Density of drilling fluids. Drilling Fluids

Minimum Density

Maximum Density

lb/gal

g/ml

lb/gal

g/ml

Air Gas Mist

0.0

0.00

0.5

0.06

Foam

0.3

0.04

3.6

0.43

Foam with Back Pressure

2.0

0.24

5.8

0.70

Oil

6.3

0.76

7.5

0.90

Aerated Mud

4.0

0.48

8.3

1.00

Fresh Water/ Seawater

8.3

1.00

8.6

1.03

Native/ Unweighted Mud

8.3

1.00

10.5

1.26

Weighted Mud

8.3

1.00

22.5

2.70

Table FL-2: Density of completion brines. Completion Brines

Minimum Density

Maximum Density

lb/gal

g/ml

lb/gal

g/ml

KCl (Potassium Chloride) and NaCl (Sodium Chloride)

8.3

1.00

10.0

1.20

Na Formate (Sodium Formate)

8.3

1.00

11.1

1.33

CaCl2 (Calcium Chloride)

8.3

1.00

11.6

1.39

NaBr (Sodium Bromide)

10.0

1.20

12.5

1.50

K Formate (Potassium Formate)

8.3

1.00

13.2

1.58

CaBr2 (Calcium Bromide)

11.7

1.40

15.1

1.81

ZnBr2 (Zinc Bromide)

15.1

1.81

19.2

2.30

Cs Formate (Cesium Formate)

8.3

1.00

20.0

2.40

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downhole fluid intrusions from aggregating drill cuttings and dust into an annular plug called a mud ring. Mist injection fluid formulations can include inhibitors and additives to minimize problems related to water-reactive shales. Dry gas and mist drilling allows productive formations to be evaluated as the drilling progresses.

Foam

Foam drilling uses a lower volume of compressed gas and injects a higher volume of surfactant and water than mist drilling. Foam is generated at the surface and circulates through the well. Compared to mist drilling, foam drilling provides a higher hydrostatic pressure, better hole cleaning and can tolerate higher water or oil intrusions. It is used when a higher density is needed to control downhole water or oil flows or for better wellbore stability. Foam is also applicable to larger diameter sections or for workover operations when cleaning out sand or other debris from the wellbore. Foam formulations can include clays and polymers for increased carrying capacity and stability as well as inhibitors to minimize problems related to water-reactive shales.

Aerated fluids

Aerated drilling is used for intermediate density applications where the density required is less than water but more than can be achieved with foam. Aerated mud drilling involves using mud pumps to pump a normal liquid drilling mud at a reduced rate and injecting compressed gas at the standpipe such that the wellbore is circulated with two-phase aerated flow. The ratio of injected gas to the liquid flowrate determines the downhole density and the propensity for surging in the annulus. Surging is where the two-phase flow is unstable and flow from the well is intermittent. Aerated muds offer many of the advantages of drilling with mud in that the mud properties can be adjusted and the liquid is recirculated through the mud pits. Aerated drilling is also done with straight water, brine or oil.

Water-based fluids (aqueous fluids)

Water-based fluids, or water-based muds (WBMs), are the most widely used type of drilling fluid systems and are almost always used to spud the well. They range from simply drilling with water to formulated water-based systems with targeted property specifications and concentrations for various additives that are used to achieve the desired properties. The type of system to be used on a particular well is dependent on the type of water locally available, the required mud weight, local drilling practices and potential problems that may be encountered. WBMs comprise a mixture of water and reactive solids, inert solids, functional chemicals and sometimes non-aqueous liquids. Most WBM systems can be formulated from freshwater or seawater.

IADC Drilling Manual

Some of the common water-based systems are: • Water or brine; • Spud muds; • Native muds; • Low solids; low-solids/non-dispersed, polymer, & lightly treated • Dispersed; • Seawater; • Saturated salt water; • Inhibitive; and • High-performance WBMs.

Water or brine

Freshwater, seawater or field brine can be used in many locations to effectively drill where higher mud weight is not needed. When this can be done with minimal drilling problems, straight water usually produces the highest rates of penetration and delivers a well at the lowest possible cost. On land, large horseshoe circulating pits are sometimes used to settle drill solids. Large volume-inclined plate separators can also be used to remove drill solids so that drilling can continue with basically just water.

Spud mud

Spud muds are high-viscosity fluids used to spud the larger diameter and shallow first interval of each well. They are prepared from whatever water source is available and whatever clay or polymer will yield sufficient viscosity in this water. For freshwater or drill water, bentonite (called gel) is most often used. 20 to 50 lb/bbl of bentonite is pre-hydrated in freshwater four to six hours. It is then usually flocculated with lime or seawater to increase viscosity prior to spudding to carry large cuttings or gravel from the well. Bentonite does not fully yield in salty or hard waters (above about 1,500 mg/l chlorides or 320 mg/l total hardness). For locations without access to fresh or drill water, attapulgite, guar gum, xanthan gum or other products are required to generate viscosity in salty or hard waters.

Native muds

Native muds are simply water or spud mud that incorporate native clays and drill solids to form a low quality but often effective drilling fluid. Native muds have: increased viscosity for better hole cleaning; slightly higher mud weights (limited to about 10.5 ppg); the ability to bridge solids to seal off high-permeability zones and form a filter cake; and a limited degree of filtration control. All of these depend on the formations being drilled and the characteristics of the water being used. Native muds often suffer from being unstable and having high fluid loss and thick filter cakes that can lead to stuck pipe. Once chemical treatments are used to achieve target viscosity and fluid loss properties (called “mudding up”), these systems would be more appropriately called lightly treated systems.

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Low-solids systems

The names of these systems are often misused and interchanged. They are usually termed low-density systems.

»» Low-solids/non-dispersed (LSND) system

This is a polymer-exended bentonite freshwater system with minimal drill solids. Only polymers are used for fluid loss and viscosity control. Originally, these were unweighted muds with 5lb/bbl in NAFs if H2S is detected. Biocides are chemicals that either kill or inhibit bacterial and possibly fungal growth in drilling and completion fluids. Bacterial growth is often first indicated by a foul odor that can smell like yeast (fermenting beer) or rotten eggs (sulfate- reducing bacteria) and possibly foaming or frothing in the pits. Biocides are industrial strength products and special care should be taken in selecting and using these products. As is the case when using any drilling fluid chemical, the proper PPE should be used to prevent exposure.

IADC Drilling Manual

Biocides range from simple inorganic chemicals like bleach (hypochlorite) and swimming pool chlorine products to those which increase pH such as soda ash, caustic soda and lime. More complex organic industrial biocides include products such as glutaraldehyde, isothiazolone, triazine, carbamates and bronopol.

Lubricants

Lubricants are products used to reduce the coefficient of friction of the drilling fluid to reduce torque and drag between the drill string and casing or open hole. Lubricants are most often used in WBMs and include: straight oils such as diesel, mineral and synthetic oils (olefins and esters) and vegetable oils; blends of oils and oil-based materials; graphite; polyglycols; glycerin; fatty acid blends; asphalt; gilsonite; and sulfonated asphalt. Solid lubricants such as glass and copolymer beads are also used as “ball bearing type” friction reducers.

Defoamers

These are products designed to control foam and foaming action in WBMs, particularly that which occurs in brackish, seawater or saturated salt systems. Defoamers include: octyl alcohol and other fatty alcohols; aluminum stearate which is mixed onsite in diesel oil or delivered as a liquid suspension; polyglycols; butyl phosphate; and silicone based products.

Flocculants

Flocculants refer to high molecular weight polyacrylamide polymers that can be used to flocculate and aggregate reactive drill solids so that they can be removed at the shale shaker or with a centrifuge and products used to flocculate bentonite-based muds for improved hole cleaning. Similar polymer products are added in small quantities to dry bentonite or bentonite slurries to increase viscosity. Inorganic chemicals can also be used to flocculate slurries including many chemicals that are a source of soluble calcium or other multivalent ions like aluminum or iron or products that are a source of chlorides or carbonates such as sodium chloride or soda ash. Lime, gypsum, soda ash or even seawater are commonly used to flocculate.

Temperature stability agents

These are products used to improve the temperature stability (rheology and filtration) of a fluid formulation and/or individual product above its normal range. For some applications, these are the base fluids chosen for the formulation such as saturated brines or fluids with anti-oxidant characteristics like formate brines. In other applications, these products are additives like pH buffers, alcohols, glycols, amines, synthetic polymers and organic chemicals.

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Foaming agents

Foamers are chemicals which are surfactants (surface active agents) that create foam for air drilling with mist or foam operations.

Hydrate suppressants

These are brines or low molecular weight alcohol or glycol-based additives which are used in WBMs for hydrate inhibition in deepwater and cold climate operations.

LCM/bridging agents

These products are used to remedy downhole mud losses to highly permeable zones, fractures or faults. Most LCMs are low-cost agricultural or industrial waste products that vary by geographic region. There is no standard sizing convention for LCMs between LCM type or between manufacturers. Names like fine, medium and coarse are relative (even within one company’s product line); for example, coarse calcium carbonate is usually smaller than fine nut shells. Likewise, numbers given to products can be misleading. Some companies use a number to indicate the median particle size and other companies use a number to indicate the screen size used to classify the product. A number like 300 could mean the median size is 300 micron or that the product was sized with a 300 mesh screen meaning the median size might be on the order of 55 microns. Bridging agents are most often applicable for sealing high-permeability formations like coarse sands, gravel beds and other forms of high “matrix” permeability. These bridging products include granular materials like coarse calcium carbonate, ground nut shells, and granular graphite or flake materials like mica or ground plastic laminate. Bridging agents are also the LCMs that are most often used for wellbore strengthening preventative practices where 10 to 50 lb/bbl of LCM is carried in the fluid while drilling. Conventional LCMs are categorized by particle type: granular, fibrous, and flake. They are limited to a maximum size of about 2 mm for most applications where mud motors and measurement while drilling (MWD) tools are used. Granular materials can be made from any material. Common granular LCMs are nut shells, granular graphite, petroleum coke, ground coal, sized wood chips or tree bark, ground rubber, sized plastic, swellable polymers and sized calcium carbonate. Fibrous materials include products like cedar fiber, shredded cane stalks, cotton seed hulls/cotton lint, mineral fiber (rock wool), sawdust, fiberglass, shredded paper and cloth, nylon and other synthetic fibers, carpet fiber, foam and animal hair.

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Flake materials include mica, cellulose, cellophane, flaked graphite, flaked calcium carbonate and ground plastic laminate. A common all-purpose LCM product is a blend of fibers and granular and flake materials. These sealing blends are effective for porous loss zones, vugs and fractures. The blend of various types of materials allows a larger diameter opening to be sealed than would be possible if a singular additive was used. Natural fractures, induced fractures and losses associated with faults are the predominant cause of lost circulation and are often difficult to cure. For severe and total lost circulation situations, other special application fluids are used. These include high-fluid-loss/high-solids squeezes (diatomaceous earth), settable slurries (resins, cross-linked polymers, magnesium based cements, thixotropic cement), downhole mixed diesel oil bentonite squeezes (called “gunk”) for WBMs and organophilic clay in water squeezes for NAFs (“reverse gunk”). Special care should be taken when selecting LCM products to resolve downhole losses in producing reservoir hole intervals. The intent is to avoid damage to the producing formation and subsequent reduction in well productivity.

Location on a rig site

Drilling fluids circulate through the wellbore (Figure FL-2) from a reserve volume of fluid in the mud pits at the surface. High-pressure reciprocating piston mud pumps pump the mud from the mud pits to the standpipe then to the top drive or kelly and into the bore of the drill string at high velocity. The mud exits the drill string at the bit nozzles at extreme velocity to clean the bit and cuttings from beneath the bit. In the annulus, the velocity is reduced and the non-Newtonian mud becomes more viscous which helps carry cuttings from the well. At the surface, the shale shakers screen out drill cuttings and return the mud to the mud pits for re-circulation. Additional fluid processing equipment is located on or near the mud pits. These may include the mud/gas separator, degasser, desander, desilter, mud cleaner and centrifuge.

Installation

Drilling fluids are normally mixed on location in the mud pits by adding dry and liquid products. Dry products are introduced into the fluid with a jet mixing hopper while liquid products are most often poured directly into the suction pit over a location that has good stirring. Products are usually protected from the weather and stored in a covered shed/ container or room normally located adjacent to the mud pumps and suction mud pit. Bulk materials such as barite or

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DRILLING FLUIDS

bentonite are stored in silos and pneumatically transferred to a mixing hopper. Drill water, base oil or brine is stored in large tanks and pumped to the mud pits.

Safety and handling

Drilling fluids and general rig operations use a number of different chemicals for various operations. Each chemical has unique chemical and physical properties which need to be considered for safe handling. Information about chemicals and hazards is provided by the supplier in several forms. These include the: safety data sheets or SDS (previously referred to as the MSDS or material safety data sheets); product labels; transportation labels; National Fire Protection Association (NFPA) labels or other labels used in transportation; and hazardous materials information system (HMIS) labels. The United Nations (UN) has sponsored a global standard for the classification and labeling of chemicals called the globally harmonized system (GHS). This system has standard formats for SDS and product labels. GHS addresses the hazards related to physical, health, and environmental dangers. Information on the SDS and product labels should be used to determine safe handling procedures and the PPE required. See the Appendix for information on GHS safety data sheets and product labels, plus information on NFPA and HMIS labels.

Proper handling for safety Fire hazards and zones

When drilling wells to collect hydrocarbons, it is possible for hydrocarbons to be returned with the circulating fluids. Wherever the returning fluid is open to the air, flammable

Table FL-3: DNV fire hazard zones. Hazardous areas are divided into zones depending upon the grade (frequency and duration) of release*: Zone 0: Explosive gas atmosphere is continuously present or present for long periods (typical for continuous grade source present for more than 1000 hours a year or that occurs frequently for short periods). Zone 1: Explosive gas atmosphere is likely to occur in normal operation (typical for primary grade source present between 10 and 1000 hours a year). Zone 2: Explosive gas atmosphere is not likely to occur in normal operation and if it does occur, is likely to do so infrequently and will exist for a short period only (typical for secondary grade source present for less than 10 hours per year and for short periods only). Non-hazardous areas are areas, which are not hazardous according to the definitions above. Guidance note: Note that conditions of ventilation may change the zone definition for each grade of release. The likelihood of detecting the leak may also influence the zone. * VERITAS, Det Norske, OFFSHORE STANDARD DNV-OS-A101 and DNV-OS-A101.

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natural gas and light hydrocarbons can be released. The risk of fire can be greatly reduced by eliminating sources of ignition from those areas. Rig areas are classified into three zones based on the potential for explosive mixtures to be present (Table FL-3): • Zone 0 includes production-related equipment or internal tanks and piping used for drilling fluids that have a high frequency of containing gas • Zone 1 includes the bell nipple, exposed areas of the flowline, shale shakers and other areas where gas is often present. If gas has been picked up while drilling, it comes out of the solution as it passes through the screens. Even without formation hydrocarbons, OBM may release flammable vapors if it arrives at the shaker at temperatures above its flashpoint. Enclosure and ventilation of the shaker area can significantly reduce vapor concentrations and risk of fire. • Zone 2 consists of the rest of the drilling area which is made up of the derrick, drilling floor, degassers and Blowout Preventer (BOP) area. This may also include active mud in open gutters (troughs) before final degassing, the vent from the degasser system and racked drill pipe if it is coated with drilling mud. In Zones 1 and 2, sources of ignition (such as lighting fixtures, motors and switches) are tightly controlled to eliminate propagation of a flame. Cell phones, electronic cameras and other electrified equipment cannot be used in these areas. Oily rags saturated with diesel fuel, mineral oil or formation fluids represent a significant risk of spontaneous combustion. These rags can be accumulated in large numbers because rags are conveniently used to wipe mud balances and other pieces of drilling equipment. The oil adsorbed onto the fabric presents a high-surface area, allowing the normally slow oxidation by air to proceed much faster than when stored as a liquid. When stored as an open pile, the resulting heat can result in spontaneous combustion and fire. All oily rags and similar materials must be stored in proper, air-restricting containers.

Chemical hazards

It is impossible to list all the chemicals used in drilling operations or to predict what products may be used in the future. The hazards of storing and handling each product must be evaluated on both an individual basis and in conjunction with the other products already present. Chemical handling hazard recognition posters and similar guides can be useful in reminding the crew of the need to properly classify, handle and store materials. Products that can react with each other should be stored

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separately; for example, acids like citric acid should be stored in a separate area from caustics (bases) like caustic soda. The best guide to the safe handling and storage of drilling fluid products is the SDS that accompanies it. It may be called a product data safety sheet or MSDS depending on the jurisdiction. Recommendations for storage appear in Section 7 of the SDS. Even non-reactive chemical products must be protected from rainwater and wash water. Wet sacks can fail, exposing the contents to personnel and the drilling environment. A spill of bentonite clay, for example, becomes slippery when wet. Big bags of barite and other fine solids can become almost solid blocks of paste if rainwater is allowed to enter them. Some chemical hazards include hydrogen sulfide (H2S), carbon dioxide (CO2), carbon monoxide (CO), lime, caustics and OBM surfactants.

»» Hydrogen sulfide (H2S)

H2S represents a special hazard. It is colorless and both highly poisonous at very low levels and highly flammable. While it has a strong odor at low concentrations, it may be undetectable at high concentrations. H2S can come from drilled gases and from biodegradation of drilling fluid and completion fluids, especially when seawater or sulfate brines are used. Even in routine operations, there must be continual monitoring of H2S gas at the shale shaker area, mud tank area, drill floor and above or in the mud flow line. Because H2S is heavier than air, testing for it should always be performed prior to entering any closed or confined spaces that have contained drilling or other well work-related fluids, particularly confined spaces, in low-lying areas, and below grade (such as underground or underdeck tanks or enclosed areas). Almost any untreated seawater system will develop H2S if it is untreated and stored under static conditions. The naturally occurring sulfate-reducing bacteria use the sulfates found in seawater to digest hydrocarbons, polysaccharides and other oilfield materials. This results in the generation of H2S as a waste product. This is especially common in packer fluids or temporary abandonment fluids. Where formation fluids containing H2S are likely to be encountered, additional contingencies such as self-contained breathing apparatus and dual flare lines must be employed. See the H2S Handbook and API RP 49 Recommended Practice for Drilling and Well Servicing Operations Involving H2S for more detailed recommendations.

»» Carbon dioxide (CO2)

Carbon dioxide is a common component of diesel exhausts and formation fluids. It can be produced by thermal and bio-

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degradation of drilling and completion fluid products. Colorless and odorless, it acts as an intoxicant at low concentrations (2 to 3%) and an asphyxiant at high concentrations (>10%). Proper ventilation and control of confined space entry, especially of pits and other areas where gases can collect, is required for protection.

»» Carbon monoxide (CO)

Carbon monoxide is also a common component of diesel exhaust but is rarely found in drilling fluids. Unlike carbon dioxide, carbon monoxide is poisonous and can cause headaches and nausea at low concentrations (10, use caustic to increase Pf --Increase thinners like lignosulfonate, lignite or tannin to deflocculate -Raise mud weight to control CO2 influx -May require additional fluid loss additives

Hydrogen Sulfide – H2S

-Reduction in pH -Discoloration of mud system -“Rotten egg” odor to mud -Rheology and Filtrate increases -Formation of black scale on DP -Foaming in pits

Increase pH to >11.5 -Keep 2+ ppb excess lime in system and a Pf >1.0 using lime and caustic soda or convert to lime-based mud -Use zinc oxide, zinc carbonate or iron oxide to precipitate sulfides -Raise mud weight to control H2S influx -Consider using hematite for slugs and density

Formation Gas

-Excess mud flow and pit increase -Increase in gas content from the gas detector -Reduction in mud weight at shaker due to gas cut Foaming in pits -Well flows when pumps shut off -Increased viscosity

Begin well control procedures if a kick has occurred -Raise mud weight to control gas influx -Route return mud flow through gas separator and/or degasser -Use defoamer for entrained gas in mud pits -Treat mud properties as necessary

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Table FL-5: NAF (OBM, MOBM, SBM) Fluids Contaminants. Contamination Type

Indications in Mud System

Recommended Treatment Options

Water Influx (Rain, formation water, saltwater flow or any other source)

-Increased water content variation of the OWR/SWR -Lower electrical stability (ES) -Grainy or dull appearance to mud in pits -Increase in mud pit level -Presence of water in the HTHP filtrate -Increased rheology (PV, YP, Gels) -Reduction in excess lime and Pom

-Add emulsifier and wetting agents -Add base fluid to correct OWR / SWR -Add fresh mud volume to the system -Add lime to increase lime content -Adjust chloride content of water phase -If downhole influx, increase mud weight to control flow

Water-Wet Solids

-Lower ES Readings -Grainy or dull appearance of mud in pits -Water-wet barite being discarded at shale shaker -Decrease in mud weight -Sticky solids or barite sag -Water in HTHP filtrate -Cuttings integrity decrease

-Add significant amounts of emulsifier and wetting agent -Add lime to maintain excess lime -Add barite to maintain mud weight -Add fresh uncontaminated mud volume

Salt (Halite, Sylvite, Carnallite, Zechstein)

-Presence of salt crystals on shale shaker screens -Increase in water phase salinity -Reduced Electrical Stability -Possible reduction in excess lime

-Add water to prevent super saturation (especially for Carnallite) -Add emulsifier/wetting agents to coat cuttings -Monitoring of Pm & lime content if Carnallite is seen –to minimize precipitation of MgOH2 -Monitor binary salt content

Excessive Drill Solids (Low Gravity Solids or LGS)

-High PV (possibly high gels & YP) -Increase in LGS % -Increase in total solids or mud weight -Increase in filter cake thickness -Higher Funnel Viscosity -Reduction of electrical stability

-Optimized use of solids control equipment -Base fluid dilution -Use thinner -Dilution with whole mud/premix

Acid Gas (H2S or CO2)

-Reduction of excess lime content & POM -Reduction in ES -Mud weight reduction at shaker due to gas cut -For H2S, smell of rotten eggs -Discoloration of mud and drill pipe (dark or black) -Foaming in pits -Increase in fluid loss and filter cake thickness

-Increase the mud weight to control gas -Increase excess lime content to >5 ppb -Use of H2S scavenger if H2S detected -Add emulsifier and wetting agent to keep ES >300 volts -Use Garrett Gas Train or other method to test for acid gases while drilling section -Consider using hematite for slugs and density

Reservoir Hydrocarbon entrained in the mud system

-Reduction in the mud weight or gas cut mud -Reduction in viscosity -Increase in OWR / SWR -Increase in fluid loss and filter cake -Decrease in excess lime & Pom -Discoloration of mud or oil floating on top of mud system -Smell of crude or increased vapors

-Increase mud weight to control influx -Increase emulsifier content -Add fluid loss additives -Add lime if needed -Skim off any oil floating on the mud system -Zero discharge should be evaluated if discharging cuttings -Adjust OWR/SWR with water and salt or brine

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Table FL-6: Common Drilling Fluid Chemicals. COMMON NAME

CHEMICAL NAME

FORMULA

USAGE

Ammonium Stearate

Aluminum Stearate

Al(C18H3O2)3

Foaming problems

Ammonium Bisulfite

Ammonium Bisulfite

(NH4)HSO3

Oxygen Scavenger

Anhydrite

Calcium Sulfate

CaSO4

Calcium Source

Barite

Barium Sulfate

BaSO4

Weighting Agent

Bicarbonate (Baking Soda)

Sodium Bicarbonate

NaHCO3

Treat out calcium from cement Crosslinking Agent

Borax

Sodium Borate Pentahydrate

Na2B4O7×5H2O

Calcium Bromide

Calcium Bromide

CaBr2

Completion Fluids

Calcium Carbonate

Calcium Carbonate

CaCO3

Weighting agent, LCM material

Calcium Chloride

Calcium Chloride

CaCl2

Chloride source

Caustic Potash

Potassium Hydroxide

KOH

Alkalinity

Caustic Soda

Sodium Hydroxide

NaOH

Alkalinity

CMC Polymer

Carboxymethylcellulose Polymer

Numerous – takes on many forms

Fluid Loss Additive

Galena

Lead Sulfide

PbS

Weighting Agent

Gypsum

Calcium Sulfate

CaSO42H20

Calcium Source

Hematite

Ferric Oxide

Fe2O3

Weighting Agent

HEC Polymer

Hydroxyethylcellulose Polymer

[C6H7O2OH3-x(OCHOHCH3)x]n

Viscosity

Iron Oxide

Iron Oxide

FeO

Treat H2S gas

Gel

Bentonite

Al2O34SiO2H2O

Viscosity

Lignosulfonate

Sodium or Calcium Lignosulfonate

NaLS (various, depending on manufacture)

Dispersant / Deflocculant

Lignite

Lignite

None

Fluid Loss / Dispersant

Mag Ox

Magnesium Oxide

MgO

Alkalinity

Mica (LCM)

Mica

Numerous – takes on many forms

LCM Material

PAC Polymer

Polyanionic Cellulose Polymer

C6H7O2(OH)2CH2COONa

Fluid Loss Additive

Pecan Nut Hull (LCM)

Pecan Nut Hull

None

LCM Material

Salt (Driller’s Salt, Salt Evaporate, Halite)

Sodium Chloride

NaCl

Chloride Source

Salt Gel, attapulgite

Hydrous Magnesium Aluminum Silicate

3MgO1.5Al2O38SiO29H2O

Viscosity in salt muds

SAPP

Sodium Acid Pyrophosphate

Na2H2P2O7

Treat Calcium / Dispersant

STP

Sodium Tetraphosphate

Na3PO4

Treat Calcium / Dispersant

Sodium Bromide

Sodium Bromide

NaBr

Completion Fluids

Sodium Ash

Sodium Carbonate

Na2CO3

Treat out calcium

Walnut Hull (LCM)

Walnut Hull

None

LCM Material

XCD – XC Polymer

Xanthan Gum Polymer

(C35H49O29)n

Viscosity

Zinc Bromide

Zinc Bromide

ZnBr2

Completion Fluids

Zinc Carbonate

Zinc Carbonate

ZnCO3

Sulfide Scavenger

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If sag is suspected: • Clean up sagged barite beds by high flowrates and rotation (> 75 rpm) prior to POOH. • Monitor sag tendency with a Viscometer Sag Shoe Test (VSST), keeping the difference in mud weight to 75 rpm) to move cuttings up and out of the hole.

Corrosion

Corrosion is the deterioration of a metal surface due to reaction to its environment. It is a particular issue for low pH WBMs, aerated fluids, packer fluids and completion brines. There are many forms of corrosion: general, pitting, stress corrosion cracking, sulfide stress cracking, erosion corrosion, corrosion fatigue, galvanic corrosion, and de-alloying. These types of corrosion can be accelerated by low pH, salt concentration, dissolved oxygen, acid gases (CO2 and H2S), higher temperatures and pressures, bacterial degradation and scale. Corrosion is monitored and diagnosed by using drill string corrosion coupons installed in the last joint of pipe above the BHA and one installed near the surface (such as in the Kelly safer sub).

General treatment procedures »» Dissolved oxygen

For dissolved oxygen: • Maintain ph >10.0. • Submerge mud-mixing guns. Only operate mixing equipment when needed and minimize all sources of air entrainment. • Add defoamer to the mud system. • Add oxygen scavenger, film-forming amine or a passivating inhibitor. If scale is observed on the corrosion monitoring coupons, add a scale inhibitor.

»» Acid gases (CO2 and H2S)

For acid gases: • Raise pH to 10-11.5, depending on the acid gas encountered and increase PF to >1.0. • Monitor acid gas levels with the Garrett Gas Train and appropriate Dräger tubes or other procedures.

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»» Bacterial degradation

Gas hydrates

Gas hydrates are ice-like materials that can form in WBMs when mixed with gas at low temperatures and high pressures. This can happen in deepwater operations and in arctic locations. When gas mixes with a WBM, the combination of high pressure and/or low temperatures can form gas hydrates at temperatures much higher than the freezing point of water. Hydrates are also found in shallow formations below the seabed in deep or cold oceans and in arctic permafrost land areas. Hydrate formation can cause serious well control problems in deepwater wells: plugging of choke and kill lines, plugging in and around BOP equipment; and loss of water from the drilling fluid. Periods of no circulation with gas entering the wellbore are the most susceptible times when hydrates are likely to form, especially in the BOP stack and choke and kill lines.

Prevention and mitigation recommendations (when drilling with a riser): »» WBMs

Elevate the salt content to >20% by weight or close to saturation. Add sufficient concentrations of diethylene glycol (DEG) or monoethylene glycol (MEG) inhibitors. In sufficient quantities, these chemical inhibitors can prevent hydrate crystal formation. Other types of inhibitors are “kinetic” inhibitors that allow the hydrates to form but restrict the crystal growth in such a way that the fluid should stay pumpable.

»» Non-aqueous fluids (NAF)

Since the internal phase of these systems is water, they are susceptible to gas hydrate formation as well. Due to the reduced amount of water in the system (15-30%), if hydrates form, they will not form a solid blockage and are likely to remain pumpable. There will, however, still be a need to inhibit

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gas hydrates. This is done through maintaining the concentration of calcium chloride in the brine phase. Typically, >25% by weight of calcium chloride is kept in the water phase as inhibition against hydrates.

»» Well operations

Maintain adequate mud weight to keep gas out of the wellbore! No available gas means no hydrates will form. If using WBMs, spot high-salt or glycol-treated fluids across the BOP stack and in the choke and kill lines as a preventative measure. High concentrations of natural gas hydrates can sometimes be found near the base of permafrost in arctic locations. If hydrates are encountered, lower the ROP substantially to bring up the gas slowly and in a manageable fashion.

gating together to form mud rings or restrictions inside of the riser. Treatments with surfactants and other anti-balling additives or a cleanout trip may be needed if the problem is severe. Use a riser boost pump and adequate circulation times prior to trips to clear cuttings from the riser.

Stuck pipe

Deepwater riser issues

Stuck pipe issues can be divided into mechanical and differential causes. Some of the causes of mechanical sticking include hole packoff /bridges, settled cuttings, shale instability, loosely consolidated formations and junk in the hole. Wellbore geometry issues may also lead to mechanical sticking and include key-seats, an undergauge hole, stiff BHA, severe doglegs, mobile formations and casing failures. Differential sticking is caused by high overbalance, stationary drill string, high fluid loss or a thick filter-cake. It is worse with high-density or high-solids mud systems.

Hole cleaning

Treatments for differential sticking

Due to the larger internal diameters of a riser when drilling smaller hole size intervals, the annular velocity in the riser is typically very low and poor hole cleaning may be a problem. Elevating the viscosity by increasing the YP, LSRYP and lowshear rate viscosity (three and six rpm shear stress values) will aid hole cleaning. Muds which become more viscous at cold temperatures and those with high progressive gel strengths are detrimental when the mud sits in the riser for an extended period of time, such as during a trip. The use of “flat rheology” NAF systems will help mitigate the cold temperature affects. After increased viscosity, the other factor that improves hole cleaning is annular velocity. When drilling with fast ROPs in large diameter sections (>17.5 in.), it is often necessary to use flowrates over 1400-1600 gal/min to clean the riser (especially large PDC cuttings). The use of a riser boost pump is recommended to aid with hole cleaning and to maintain a clean riser.

Rheology effects

During periods of shut down, cold-water temperature effects will raise the rheology of the system. The use of “flat rheology” mud systems for deepwater applications is becoming more commonplace. These systems maintain a fairly level YP and gel strength throughout the 40°F-150°F temperature range. They also minimize the higher annular pressure that occurs during circulation after long static periods of time as the mud system heats up and thins down.

Balling with WBM

If WBM is used, shallow reactive formations (gumbo) or a long trip might lead to softening and hydration of reactive cuttings entrained in the mud system which have not been cleaned from the riser, even if the WBM system is thought to be “inhibitive”. This could lead to cuttings sticking and aggre-

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• Reduce mud weight if possible. • Use NAF spotting fluid to “crack” the filter-cake and equalize differential pressures between the formation and the borehole. • Reduce the API and HTHP fluid loss to create a thin and low-permeability filter cake for WBMs. • Use lubricants and additives that will make the lubricity of the filter lower and less susceptible to differential sticking. Note: Spotting fluids utilized in offshore environments may be subject to regulatory limitations for discharge.

Lost circulation

The partial or complete loss of mud returns is a lost circulation event. It is typically seen by reduced pit volume, loss of pump pressure and reduced volume of return flow at the shale shaker. Keeping the hole full when the loss event occurs is paramount for wellbore stability and maintaining well control. Loss mechanisms are: surface system losses; naturally occurring faults and open fractures; high-permeability formations (such as shallow gravel and dolomite or carbonate formations with vugs); induced fractures; and fracture wellbore breathing (ballooning). Induced fracture losses are one of the most common causes of lost circulation. This often happens when the mud weight is increased while drilling deeper during an interval to control increasing pore pressure at greater depths. This increase in density may exceed the fracture pressure somewhere above in the open hole, inducing a fracture. This induced fracture is most often near the last casing shoe or in a severely depleted formation. While LCM treatments may be effective,

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it is often necessary to find a way to drill ahead to the casing point with the losses or run the casing early. Wellbore strengthening is a drilling fluid technique that uses a certain concentration of sized LCM to prevent lost circulation by preventing or limiting induced fractures. Theories vary on how wellbore strengthening works and on what concentration or particle size should be used. The concentration and particles need to be in the drilling fluid prior to drilling the interval and they need to be maintained continuously. Concentrations in the order of 20 to 50 lb/bbl are used for wellbore strengthening and particle sizes range from a narrow 250-650 micron range to a wide 50-2000 micron range. Wellbore strengthening has allowed intervals to be drilled without losses using mud weights that are several pounds per gallon higher than offset wells where this strategy was not used. Losses to high-permeable formations or natural subsurface conditions, such as a fault or open fracture, are often identified by a drilling break just prior to the loss event. These kinds of loss zones can normally be treated with LCM if a large enough material can be used. Effective bridging can be achieved at concentrations as low as 10 lb/bbl if the size of the material is half the diameter of the fracture or pore opening. Keep in mind that most LCMs have a wide particle size distribution and it is only the larger particles that initiate the bridge or sealing process. LCM sizes are also limited by drill string components, with 2 mm being about the largest size that can be used with most LWDs/MWDs and mud motors. LCM material types for seepage to moderate losses would include granular (particulate), fibrous/cellulosic, flakes/ platelets and mixed LCM types. These are often locally sourced low-cost agricultural or industrial byproducts. Pills, squeezes and spotting solutions for persistent loss zones include: dilatant slurries; high fluid-loss, high-solids dewatering squeezes; cross-linked polymer pills; gunk or reverse gunk squeezes activated downhole; sodium silicate pills; latex pills; swellable polymer pills; mud gelling material pills; barite/hematite plugs; thixotropic LCM/WSM (wellbore strengthening material) plugs; cement plugs; and resin-coated sand pills. An important tool to have before drilling is a lost circulation decision tree. This helps determine the proper treatment based on the amount of losses, local experience and availability of products. An example is provided in Figure FL-7. Note that this is only an example.

Salt formations and rubble zones

The major problems typically associated with drilling salt

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formations are: stuck pipe; managing salt saturation or oversaturation of mud system, bit-balling and losses when encountering salt inclusions; wellbore enlargement when drilling through the salt formation and/or through shales above or below the salt formation (rubble zones); excessive torque and pack-offs caused by salt creep; difficulty evaluating the required mud weight; well control issues; and excessive mud losses. The rubble zone that might lie beneath, adjacent to or on top of the salt section usually consists of a series of highly reactive shale stringers that are embedded with unconsolidated sands. This zone could be over-pressured at the entry point because of a gas pocket under the salt or other reasons. For the remainder of the section, it could be under-pressured (leading to numerous problems) or unconsolidated (causing severe lost circulation problems). Determining the mud weight needed to drill out the bottom of the salt is difficult as salt does not have a true pore pressure and can be drilled significantly over-pressured or under-pressured.

Treatments

Treatment methods include the following: • Wellbore Enlargement in Salt: Drill with saturated salt WBMs or NAFs. Minimize the addition of water and monitor chlorides; • Formation Gas or Saltwater in the Rubble Zone: Increase mud weight to the safest level to control the intrusions; • Lost Circulation: Pretreat with LCM before entering the rubble zones. The LCM might include calcium carbonate, graphite materials and cellulosic LCM. Other LCM types might be needed if losses are severe. Develop a lost circulation strategy for the rubble zone prior to the start of the well; • Drilling Below Salt: Have a salt exit strategy developed prior to drilling below the bottom of the salt. This might include entraining the mud system with a variety and high concentration of LCM, having a LCM pill built and ready to pump and other operational procedures; • Stuck in Salt: Spot a fresh water pill across the suspected stuck pipe zone to dissolve the salt.

HTHP conditions When using WBM and NAF systems, HTHP wells are susceptible to problems such as high-temperature gelation, barite sag, high-solids content, dehydration, decreases in total alkalinity and increased fluid losses. The use of temperature stable mud products is key to minimizing these potential problems. Rheology stabilizers, thinners, chemicals to reduce fluid loss and aid in filter cake building, barite sag treatment chemicals and others must be stable to the highest BHT expected to be seen. The mud system should be run with minimum low gravity solids (LGS) to reduce or prevent HTHP gelation problems. Higher concentrations and tem-

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Lost Circulation Remedial Treatment Options (based on loss type / amount).

Matrix Permeability Depeleted Zones Microfractures

Natural Fractures Induced Fractures Vugs / Fractured Limestone

See page losses (100 bbls/hr WBM or >30 bbls /hr NAF

Water Base Mud

Non-Aqueous Fluid

Water Base Mud

Non-Aqueous Fluid

Water Base Mud

Non-Aqueous Fluid

LCM Pill - Materials: 10 ppb Fiber 10 ppb CaCO3 - Fine 10 ppb CaCO3 - Med 15 ppb Nut Shells - Med

LCM Pill - Materials: 2 ppb Wetting Agent 20 ppb CaCO3 F/M 20 ppb Graphite Med 10 ppb Fiber LCM F

LCM Pill - Materials: 20 ppb CaCO3 - Med 20 ppb CaCO3 - Fine 15 ppb Nut Shells- Med 15 ppb Fiber LCM F

LCM Pill - Materials: 2 ppb Wetting Agent 30 ppb CaCO3 F/M 30 ppb Graphite Med 10 ppb Fiber LCM F

LCM Pill - Materials: 40 ppb CaCO3 M/C 30 ppb Graphite Med 10 ppb Nut Shells - Med 20 ppb Fiber LCM F/M

LCM Pill - Materials: 2 ppb Wetting Agent 40 ppb CaCO3 M/C 40 ppb Graphite Med 20 ppb Fiber LCM F/M

No success

No success

No success

High Fluid Loss Pills Reactive Pills

Cross-Linked Polymer Pills

Large Particulate LCM Pills

Soft / Hard Plugs

Attapulgite Squeeze Diatomaceous Earth / LCM Squeeze Diaseal-M Squeeze Reactive, NonParticulate LCM Pill

Crome-Polymer Crosslinked Pills Borate-Polymer Crosslinked Pills

Conventional LCM - 140-160 ppb (Fibers, Granular, Flakes, Mixed LCM)

Gunk Squeeze Reverse-Gunk Squeeze Base Oil-Bentonite-Squeeze Base Oil-Bentonite-Cmt Squeeze Barilte Plugs Cemet Plugs

Misc Materials

Swellable CoPolymers Sodium Silicate Pills Thixotropic LCM Pills

Figure FL-7: Lost-circulation decision tree example.

perature stabilizing additives may be required to make the system tolerant of HTHP conditions. One means of addressing the gelation potential is to spot a pill on the bottom with increased additions of temperature stable products prior to making a trip. Have a HTHP drilling plan in place prior to the start of a well. For a NAF system, the utilization of temperature-stable organophilic clays and emulsifiers/wetting agents should be selected to minimize problems.

Wellbore stability issues

Wellbore stability issues are often exemplified by excess shale cuttings coming over the shaker, splintery shale cuttings, mud losses, tight holes on trips or connections, hole fill-up while tripping, the need for excessive reaming when making connections and other drilling problems. High-angle wellbores and certain directions will require higher mud weights than a vertical well to maintain stability. Some things to keep in mind for the mud system include: • Keep the mud weight high enough to maintain mechanical hole stability and prevent sloughing; • Keep fluid loss as low as possible and use deformable plugging agents to keep micro-fractured shales from being invaded and swelling, crumbling or delaminating; • Increase rheology to increase the hole cleaning ability of mud and address the pack-off issues;

IADC Drilling Manual

• Keep shales from swelling or failing from chemical interactions by using a NAF system or inhibitive WBM system.

Calculations and tables Brine tables

Brines and fluids containing salts, are often used as the base fluid for drilling fluids and for completion fluids. Sodium chloride and calcium chloride are the most common salts used. The density of all brines changes significantly with temperature. It is critical to know the temperature at which the density is measured as well as the temperature of a given application. The freezing points and crystallization temperatures listed in Table FL-7 for sodium chloride and Table FL-8 for calcium chloride are examples only. These values vary significantly depending on the purity of the salt or brine being used and with contamination.

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DRILLING FLUIDS

Important calculations

FL-29

Rect. tank vol. (cu m) = length (m) x width (m) x depth (m)

Volume of mud in the circulating system

Everyone involved with managing the circulation system needs to know the volume of the circulating system and the volume of the hole at all times. They must also be able to determine changes and circulation requirements for performing various operations. This includes the mud in the active pits and the mud in the hole, both with pipe in the hole (at any depth) and with no pipe in the hole.

Eq 6

Upright cylindrical tank volume Cyl. tank vol. (bbl) = 0.14 x [ dia. (ft) ]2 x height (ft)

Eq 7

Cyl. tank vol. (cu m) = 0.7854 x [ dia. (m) ]2 x height (m)

Eq 8

Circulating system vol.= surface system vol. + hole vol. Eq 4 Note: 1 cu m = 1,000 liters Similar calculations can be made to determine the volume in reserve or storage tanks and pits. Customary units for drilling fluid volumes are oilfield barrels (42 US gallons) abbreviated by bbl or cubic meters (cu m). (1 cu m = 6.29 bbl.)

Surface system volume calculations Rectangular tank volume Rect. tank vol. (bbl) length (ft) x width (ft) x depth (ft)  = 5.61 cu ft/bbl

Eq 5

Surf. system vol. = tank1 + tank 2 + tank 3 +...+ tankn

Eq 9

Note: Many surface systems have substantial volumes of mud in piping or troughs that lead to and from the wellhead. These volumes should be estimated and included in the surface volume. Rounded tank bottoms and internal piping not filled with active mud should likewise be excluded from surface volume calculations.

Table FL-7: Sodium chloride brine (100% pure NaCl). Density @ 68°F (20°C)

Specific Gravity

Sodium Chloride

Sodium Chloride (100%)

Sodium Chloride (100%)

Water

Sodium Ion

Chloride Ion

Freezing Pt or Crystallization Temp*

(lb/gal)

(g/mL)

(wt %)

(lb/bbl)

(kg/m3)

(vol / final vol)

(mg/L)

(mg/L)

°F

°C

aw

8.34

1.000

0.0

0.0

0

1.000

0

0

32

0

1.000

8.4

1.007

1.0

3.6

10

0.996

0

0

31

-1

0.995

8.5

1.019

2.7

9.7

28

0.991

0

0

29

-2

0.986

8.6

1.031

4.4

15.8

45

0.985

0

0

27

-3

0.976

8.7

1.043

6.0

22.0

63

0.979

0

0

25

-4

0.965

8.8

1.055

7.7

28.4

81

0.972

0

0

23

-5

0.954

Water Activity

8.9

1.067

9.3

34.8

99

0.966

0

0

21

-6

0.941

9.0

1.079

10.9

41.3

118

0.960

0

0

19

-7

0.928

9.1

1.091

12.5

47.9

137

0.953

0

0

16

-9

0.914

9.2

1.103

14.1

54.6

156

0.946

0

0

14

-10

0.900

9.3

1.115

15.7

61.3

175

0.939

0

0

11

-12

0.884

9.4

1.127

17.2

68.0

194

0.932

0

0

8

-13

0.868

9.5

1.139

18.7

74.8

214

0.925

0

0

5

-15

0.852

9.6

1.151

20.2

81.7

233

0.917

0

0

2

-17

0.835

9.7

1.163

21.7

88.5

253

0.909

0

0

-2

-19

0.817

9.8

1.175

23.2

95.4

272

0.902

0

0

-6

-21

0.799

9.9

1.187

24.6

102.3

292

0.894

0

0

8

-13

0.781

10.0

1.199

26.0

109.1

311

0.886

0

0

27

-3

0.762

* Examples only. Freezing point and crystallization temperature vary significantly depending on salt/brine purity.

IADC Drilling Manual

Copyright © 2015

FL-30

DRILLING FLUIDS

Table FL-8: Calcium chloride brine (94-97% grade powder). Density @ 68°F (20°C)

Specific Gravity

Calcium Chloride

Calcium Chloride

Calcium Chloride

Water

Calcium Ion

Chloride Ion

Freezing Pt or Crystallization Temp*

(lb/gal)

(g/mL)

(wt %)

(lb/bbl)

(kg/m3)

(vol / final vol)

(mg/L)

(mg/L)

8.34

1.000

0.0

0.0

0

1.000

0

0

32

0

1.000

8.5

1.019

2.3

8.4

24

0.995

8,200

14,500

28

-2

0.997

8.6

1.031

3.7

13.7

39

0.991

13,500

23,900

26

-3

0.992

8.7

1.043

5.1

19.2

55

0.988

18,800

33,300

25

-4

0.986

8.8

1.055

6.5

24.7

70

0.984

24,300

43,000

23

-5

0.978

°F

Water Activity

°C

aw

8.9

1.067

7.9

30.3

87

0.981

29,800

52,800

21

-6

0.969

9.0

1.079

9.2

36.0

103

0.977

35,400

62,700

19

-7

0.959

9.1

1.091

10.6

41.8

119

0.973

41,100

72,800

17

-8

0.948

9.2

1.103

11.9

47.7

136

0.969

46,900

83,000

15

-9

0.936

9.3

1.115

13.2

53.6

153

0.965

52,700

93,300

12

-11

0.923

9.4

1.127

14.5

59.6

170

0.961

58,600

103,700

9

-13

0.908

9.5

1.139

15.8

65.6

187

0.957

64,600

114,200

6

-14

0.893

9.6

1.151

17.0

71.7

205

0.953

70,600

124,800

3

-16

0.876

9.7

1.163

18.3

77.9

222

0.948

76,600

135,500

0

-18

0.859

9.8

1.175

19.5

84.1

240

0.944

82,700

146,300

-4

-20

0.841

9.9

1.187

20.7

90.3

258

0.939

88,800

157,200

-8

-22

0.822

10.0

1.199

22.0

96.6

276

0.934

95,000

168,100

-13

-25

0.802

10.1

1.211

23.1

102.9

294

0.929

101,200

179,100

-18

-28

0.782

10.2

1.223

24.3

109.2

312

0.924

107,500

190,100

-23

-31

0.760

10.3

1.235

25.5

115.6

330

0.919

113,700

201,200

-29

-34

0.739

10.4

1.247

26.6

121.9

348

0.914

120,000

212,300

-36

-38

0.716

10.5

1.259

27.8

128.3

366

0.908

126,300

223,400

-43

-42

0.693

10.6

1.271

28.9

134.8

384

0.903

132,600

234,600

-51

-46

0.669

10.7

1.283

30.0

141.2

403

0.897

138,900

245,700

-59

-51

0.645

10.8

1.295

31.1

147.6

421

0.892

145,200

256,900

-40

-40

0.620

10.9

1.307

32.1

154.0

439

0.886

151,500

268,100

-22

-30

0.595

11.0

1.319

33.2

160.4

458

0.880

157,900

279,300

-11

-24

0.569 0.543

11.1

1.331

34.2

166.9

476

0.874

164,200

290,500

0

-18

11.2

1.343

35.3

173.3

494

0.868

170,500

301,600

13

-11

0.516

11.3

1.355

36.3

179.7

513

0.862

176,800

312,700

25

-4

0.489

11.4

1.367

37.3

186.0

531

0.855

183,100

323,800

35

2

0.462

11.5

1.379

38.3

192.4

549

0.849

189,300

334,900

44

7

0.435

11.6

1.391

39.2

198.7

567

0.842

195,500

345,900

51

10

0.407

* Examples only. Freezing point and crystallization temperature vary significantly depending on salt/brine purity.

IADC Drilling Manual

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DRILLING FLUIDS

Hole volume calculations (pipe in hole) Eq 10

Hole vol. = ann. vol. + pipe cap. 

Annular volume (or pipe displacement):

For each section with different annular dimensions (inside diameter (ID) casing or open hole or outside diameter (OD) pipe), calculate: [ ID (in.)2 – OD (in.)2 ] Ann. vol. (bbl/ft) =



Eq 11

1,029

Ann. vol. (cu m/m) =

[ ID (mm)2 – OD (mm)2 ] 

Eq 12

FL-31

The values from Eq 14 and Eq 15 are then multiplied times the interval lengths to calculate the pipe (or hole) capacity for each section. The total pipe (or hole capacity) is then the sum of each different section volume from surface to total depth.

Pipe cap. = PCap1 + PCap2 + PCap3 +...+ PCapn 

Eq 16

Note: When calculating the hole capacity of the open hole, use the bit diameter multiplied by a factor to account for wellbore enlargement (typical values are 1.1 for OBMs and 1.25 to 1.5 for WBMs). These washout values can vary widely and are highly dependent on the formation drilled and other factors.

1.273 x 106 The values from Eq 11 and Eq 12 are then multiplied times the interval lengths to calculate the annular volume for each section. The total annular volume is then the sum of each annular volume from the surface to the total depth: Total ann. vol. = AV1 + AV2 + AV3 +...+ AVn 

Eq 13

Note: Pipe displacement volumes are important when determining if the hole is taking or giving the correct volume of fluid when tripping pipe or running casing. While these values can be calculated with Equations 11 or 12 (if the dimensions of the tool joints or casing collars are taken into account), it is recommended that displacement volumes be obtained from tables for the particular size and weight of pipe that includes the specific tool joint or casing connection dimensions.

Pipe (or hole) capacity

Pipe capacity is used to determine the volume of fluid inside the drill string. Hole capacity is used to determine the volume of fluid in the wellbore when the drill string is not in the well. For each section with different pipe (or hole) size, use the ID dimension of the pipe (or hole) and then calculate as follows:

Pipe (or hole) cap. (bbl/ft) =

ID (in.)2 1,029 

Eq14

2 Pipe (or hole) cap. (cu m/m) = ID (mm.) 6 1,273 x 10

Hole cap. = HCap1 + HCap2 + HCap3 +...+ HCapn 

Circulation times and strokes Pump output and circulation rate

The pump output (PO) can be calculated using Equations 18-19 or 21-22 for any liner size or stroke length. These values can also be found in the manufacturer’s tables or in generic tables like Tables FL-9 and FL-10. Mud pump efficiency is affected by many factors with operating pressure, pump RPM, mud weight, suction pressure, and the presence of larger mud particles (LCM and sand) having the greatest influence. Mud pump efficiency values are normally in the 75 to 95% range.

Triplex Mud Pumps

Triplex pumps have three pistons and pump fluid on the forward stroke only (single acting). As compared to duplex pumps, triplex pumps often have shorter stroke lengths (612 in.), operate at higher speeds (50-150 strokes/minute) and have higher efficiency (85-95%). PO (bbl/ Stk) = liner ID (in.)2 x stk (in.) x Eff. (decimal) Eq 18  4,118 PO output (l/Stk) = liner ID (mm)2 x stk (mm) x Eff. (decimal) Eq 19  424,413 Circ. rate (bbl/min) = bbl/stk x stk/min + bbl/stk x stk/min Eq 20

Eq15

IADC Drilling Manual

Eq 17

(Total for all pumps being used.)

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FL-32

DRILLING FLUIDS

Duplex mud pumps

Duplex pumps have two piston rods and four pump chambers so that they pump fluid on both the forward and backward stroke (double acting). On the backward stroke, the rod displaces some of the liner-swept volume and must be considered in the pump output calculation. Since rod diameters are different, it is important to use the correct value. Table FL-8 is an example and uses a typical rod diameter. As compared to triplex pumps, duplex pumps often have longer stroke lengths (8-18 in.), operate at lower speeds (40-80 strokes/minute)and have lower efficiency (75-90%). PO (bbl/Stk) =

circ. rate (cu m/stk)

6,177



BU (min)

=

BU (min)

=

ann. vol. (bbl)

ann. vol. (cu m)

BU (stk)

=

BU (stk)

=

ann. vol. (bbl)

Mud cycle (complete circulation of active system)

Mud cycle (min) =

circ. rate (bbl/min)

circ. rate (cu m/min)



Eq 24

During drilling operations, it is important to know the pipe capacity (or pipe displacement) and surface to bit time. This is the time required for the mud at the pump suction to be pumped down the drill string to the bit. This is used when displacing cement jobs, spotting pills for lost circulation, stuck pipe or other operations and during well control procedures to know when a new mud weight has reached the bit.

Surf. to bit (stk)

=

pipe cap. (bbl) circ. rate (bbl/min)

Eq 31 

pipe cap. (cu m) circ. rate (cu m/min) pipe cap. (bbl) circ. rate (bbl/stk)

Eq 32  Eq 33





 Mud cycle (stk) =

Surface to bit (pipe capacity/displacement)

Surf. to bit (min) =

circ. system vol. (cu m)

Eq 30

circ. rate (cu m/stk) 

Eq 23



Note: Circ. rate (bbl/min) = Circ. rate (gal/min) ÷ 42 gal/bbl

Mud cycle (min) =

ann. vol. (cu m)

Surf. to bit (min) =

circ. system vol. (bbl)

Eq 29

circ. rate (bbl/stk) 

The circulation rate (bbl/min) is the same as Equation 20.

Circulating system volume is calculated from Equation 4 (surface system volume + hole volume).

Eq 28

circ. rate (cu m/min) 



Eq 22

In mud conditioning, it is important to know the mud cycle time. This is the time required for the mud in the active system to make one complete circulation - mud from the pump suction is circulated to the bottom of the hole, out the bit, up the annulus, through the pits and back to the pump suction. When adding weight material or chemical treatments, it is often recommended to add these materials at such a rate that the mud will make at least one complete cycle during the treatment so that they are evenly distributed.

Eq 27

circ. rate (bbl/min) 

636,620 x Stk (mm) x Eff. (decimal) 

Eq 26

During drilling operations, it is important to know the bottoms-up (BU) or bit to surface time. This is the time required for the mud at the bit to be circulated up the annulus to the surface. It is important to know this time when circulating the hole clean prior to tripping, estimating the depth at which cuttings are being generated or when circulating and evaluating an influx from the well.

Eq 21

[ 2 x liner ID (mm)2 - Rod OD (mm)2 ]



Bottoms-up (bit to surface)

[ 2 x liner ID (in.)2 - Rod OD (in.)2]

x Stk (in.) x Eff. (decimal) PO (l/Stk) =

circ. system vol. (cu m)

Mud cycle (stk) =

circ. system vol. (bbl)

Eq 25

Surf. to bit (stk)

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circ. rate (bbl/stk)





=

pipe cap. (cu m) circ. rate (cu m/stk) 

Eq 34

DRILLING FLUIDS

FL-33

Table FL-9: Triplex mud pump output. TRIPLEX MUD PUMP OUTPUT (barrels/stroke) 100% Efficiency Liner ID (in.)

Stroke Length (in.) 6.0

6.5

7.0

7.5

3.00

0.0131

3.25

0.0154

8.0

8.5

9.0

0.0142

0.0153

0.0167

0.0180

0.0164

0.0175

0.0186

0.0197

0.0192

0.0205

0.0218

0.0231

9.5

3.50

0.0178

0.0193

0.0208

0.0223

0.0238

0.0253

0.0268

0.0283

3.75

0.0205

0.0222

0.0239

0.0256

0.0273

0.0290

0.0307

0.0324

10.0

11.0

12.0

4.00

0.0233

0.0253

0.0272

0.0291

0.0311

0.0330

0.0350

0.0369

0.0389

4.25

0.0263

0.0285

0.0307

0.0329

0.0351

0.0373

0.0395

0.0417

0.0439

4.50

0.0295

0.0320

0.0344

0.0369

0.0393

0.0418

0.0443

0.0467

0.0492

0.0541

4.75

0.0329

0.0356

0.0384

0.0411

0.0438

0.0466

0.0493

0.0521

0.0548

0.0603

5.00

0.0364

0.0395

0.0425

0.0455

0.0486

0.0516

0.0546

0.0577

0.0607

0.0668

0.0729

5.25

0.0402

0.0435

0.0469

0.0502

0.0535

0.0569

0.0602

0.0636

0.0669

0.0736

0.0803

5.50

0.0441

0.0477

0.0514

0.0551

0.0588

0.0624

0.0661

0.0698

0.0735

0.0808

0.0881

5.75

0.0482

0.0522

0.0562

0.0602

0.0642

0.0682

0.0723

0.0763

0.0803

0.0883

0.0963

6.00

0.0525

0.0568

0.0612

0.0656

0.0699

0.0743

0.0787

0.0831

0.0874

0.0962

0.1049

6.25

0.0569

0.0617

0.0664

0.0711

0.0759

0.0806

0.0854

0.0901

0.0949

0.1043

0.1138

6.50

0.0616

0.0667

0.0718

0.0769

0.0821

0.0872

0.0923

0.0975

0.1026

0.1129

0.1231

6.75

0.0664

0.0719

0.0774

0.0830

0.0885

0.0940

0.0996

0.1051

0.1106

0.1217

0.1328

7.00

0.1309

0.1428

7.50

0.1503

0.1639

To convert to gallons/stroke multiply barrels/stroke x 42 To convert to liters/stroke multiply barrels/stroke x 159

Hole cycle time

During drilling operations, it is important to know the time or strokes for mud at the pump suction to be circulated down the drill string out the bit and up the annulus to the shale shakers. This is most often needed when increasing the mud weight to determine when the wellbore is fully displaced to the new mud weight. Hole cycle

= surf. to bit + BU

Eq 35

Hole volume (pipe out of hole)

Hole volumes are important to know when tripping in or out of the hole as they determine if the surface volume and pit capacity is sufficient. Hole volumes can be calculated in the same way pipe capacity is calculated (as shown below or found in the tables). For each hole section with different ID dimensions for the casing or open hole, calculate:

IADC Drilling Manual

Hole vol (bbl/ft)

Hole vol (cu m/m)

=

=

ID (in.)2 1,029

Eq 36 

ID (mm)2 1.273 x 106

Eq 37 

The values from Eq 36 and Eq 37 are then multiplied times the interval lengths to calculate the hole volume for each selection. The total hole volume with no pipe in the hole is then the sum of each different hole section volume from the surface to the total depth: Hole vol. (no pipe) = HV1 + HV2 + HV3 + .......... +HVn



Hydrostatic pressure and hydrostatic gradient

Eq 38

The hydrostatic pressure (PHYD) is the pressure the fluid column exerts on the wellbore. It is primarily controlled by increasing or decreasing the drilling fluid density or mud weight (MW).

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DRILLING FLUIDS

FL-34

Table FL-10: Duplex Mud Pump Output. DUPLEX MUD PUMP OUTPUT (barrels/stroke) 100% Efficiency Stroke Length (in.) 8

Liner ID (in.)

10

12

14

15

16

18

2.25

2.50

2.50

3.0

Rod size (in.) 1.75

2.0

2.0

4.00

0.0375

0.0453

0.0544

0.0611

0.0625

0.0667

0.0670

4.25

0.0428

0.0520

0.0624

0.0704

0.0725

0.0774

0.0790

4.50

0.0485

0.0591

0.0709

0.0803

0.0832

0.0887

0.0918

4.75

0.0545

0.0666

0.0799

0.0908

0.0944

0.1007

0.1053

5.00

0.0608

0.0745

0.0894

0.1018

0.1062

0.1133

0.1195

5.25

0.0674

0.0828

0.0993

0.1135

0.1187

0.1266

0.1344

5.50

0.0744

0.0915

0.1098

0.1256

0.1317

0.1405

0.1501

5.75

0.0817

0.1006

0.1207

0.1384

0.1454

0.1551

0.1665

6.00

0.0893

0.1101

0.1321

0.1517

0.1597

0.1703

0.1836

6.25

0.0972

0.1200

0.1440

0.1656

0.1745

0.1862

0.2014

6.50

0.1055

0.1303

0.1564

0.1800

0.1900

0.2027

0.2200

6.75

0.1141

0.1410

0.1693

0.1951

0.2061

0.2198

0.2393

7.00

0.1230

0.1522

0.1826

0.2106

0.2228

0.2377

0.2593

7.25

0.1322

0.1637

0.1965

0.2268

0.2401

0.2561

0.2801

7.50

0.1417

0.1757

0.2108

0.2435

0.2580

0.2752

0.3016

7.75

0.1516

0.1880

0.2256

0.2608

0.2765

0.2950

0.3238

8.00

0.1618

0.2007

0.2409

0.2786

0.2957

0.3154

0.3468

To convert to gallons/stroke multiply bbl/stroke x 42 To convert to liters/stroke multiply bbl/stroke x 159

PHYD (lb/in.2) =

PHYD (kPa)

MW (lb/gal) x 0.052 x TVD (ft)

Eq 39

While circulating, the annular pressure losses (APL) act to increase the pressure on the wellbore. This is called the equivalent circulating density (ECD).

= MW (kg/cu m) x 0.00981 x TVD (m) Eq 40

The hydrostatic pressure gradient (PHYD: G) is the rate at which the hydrostatic pressure increases with true vertical depth and has units of pressure per depth. The hydrostatic gradient for a given area is often compared to the gradient for fresh water (0.433 psi/ft) or seawater (0.465 psi/ft). PHYD: G (psi/ft)

PHYD: G (kPa/m) 

=

MW (lb/gal) x 0.052

= MW (kg/cu m) x 0.00981

Eq 41

Eq 42

IADC Drilling Manual



ECD =

PHYD + APL TVD x K (units conversion)

Eq 43

During well control and managed pressure drilling operations, surface pressures act on the hydrostatic column such that downhole wellbore pressures are increased by the amount of the surface pressure.

Quantities of mud materials

Mud weight can be increased with barite. The quantity of barite needed to increase the mud weight depends on the density of the barite. Currently, the two most common Specific Gravities (SG) for barite are either 4.2 or 4.1. Density expressed as specific gravity (g/ml) or using kg/l units have the same numerical value.

Copyright © 2015

DRILLING FLUIDS

»» Weight-up formula

For 4.1 SG barite these become:

The generalized weight-up formula is: Vol. inc. (bbl) =

Weight material (lb/bbl) =

SGwt mat x 350[MW2 (lb/gal) - MW1 lb/gal]

W2

SGwt mat x 8.345 – MW2 (lb/gal)



Vol. inc. (cu m) =

SGwt mat x 1000 [MW2 (kg/l) – MW1 (kg/l)] SGwt mat – MW2 (kg/l)



Eq 45

MW1 = initial mud weight MW2 = desired mud weight

1,435

Eq 50 

kg barite added 4,100

Eq 51 

Note: As an approximation, for every 14 sacks (100 lb) of barite, the volume will increase 1 bbl. For every 100 sacks (100 lb) barite, the volume increases 6.9 bbl.

»» Dilution and blending

It is common practice to blend two fluids or to dilute with water or NAF base fluid to reduce mud weight.

For 4.1 SG barite these become: Weight material (lb/bbl) =

1,435 [MW2 (lb/gal) – MW1 (lb/gal)] 34.2 – MW2 (lb/gal)

Eq 46 

The generalized dilution or blending formula (allowing the volume to increase) is:

Vorig x (MWorig – MWdesired)

Weight material (kg/cu = m) 4,100 [MW2 (kg/l) – MW1 (kg/l)] 4.1 – MW2 (kg/l)

Eq 47 

Vadded fluid is the volume of fluid to add to achieve the desired change in mud weight. Vorig is the original mud volume. MWorig is the original mud weight. MWadded fluid is the mud weight for the fluid being added. MWdesired is the desired final mud weight. When diluting with fresh water (8.345 lb/gal or SG 1.0), this becomes:

»» Volume increase due to material additions

When weighting up and making other treatments, the volume of material added increases the mud volume. For dry materials, this volume must be calculated based on the SG of the material.

Vwater (bbl) = Vorig (bbl) x [MWorig (lb/gal) – MWdesired (lb/gal) ] MWdesired (lb/gal) – 8.345

The generalized volume increase formulas for material additions are:

Eq 53

Vwater (cu m) =

lb material added SGmaterial x 350

Eq 52 



Note: As an approximation, in the mud weight range between 9 and 12 lb/gal, 60 lb/bbl (or 60 100 lb sacks barite/100 bbl) increases the mud weight 1.0 lb/gal. For mud weights above 12 lb/gal, divide the desired final weight by 0.2 to find the lb/bbl of barite needed to increase the mud weight 1.0 lb/gal (or the number of 100 lb sacks/100 bbl).

=

lb barite added

Eq 44

Weight material (kg/cu = m)

Vol. inc. (bbl)

FL-35

Eq 48

Vorig (cu m) x [MWorig (kg/l) – MWdesired (kg/l)] MWdesired (kg/l) - 1.0

Eq 54

 Vol. inc. (cu m) =

kg material added SGmaterial x 1000

Eq 49



IADC Drilling Manual

Annular velocity

Annular velocity is the mud velocity in the annulus between the drill string and the OD of the open hole or casing. This value helps when evaluating hole cleaning, especially in vertical sections where a value of 100 ft/min is considered to be sufficient for most situations. The usual US oilfield expression of this velocity is in feet per minute.

Copyright © 2015

FL-36

DRILLING FLUIDS

Ann. Vel.

=

Ann. Vel. (ft/min) =

24.5 x circ. rate (gpm)

circ. rate ann. vol.

Ann. Vel. (ft/min) = Eq 55

hole ID (in.)2 – pipe OD (in.)2

Eq 57 



circ. rate (bbl/min) ann. vol. (bbl/ft)

Eq 56

Ann. Vel. (m/min)



Drilling operations generally report the circulation rate in gallons per minute (gpm) and use inches; therefore, a common formula used for annular velocity is:

IADC Drilling Manual

Copyright © 2015

=

circ. rate (cu m/min) ann. vol. (cu m/m)

Eq 58 

IADC Drilling Manual Copyright © 2015

Weight-up Chart for 4.1 SG Barite pounds of barite per bbl mud (upper right section) and Dilution with Fresh Water bbl water per bbl mud (lower left section) Initial Mud Weight (lbm/ gal)

Desired Mud Weight (lbm/gal) 8.5

8.3

9.0 39.9

9.0

3.23

9.5

10.0

10.5

11.0

11.5

12.0

12.5

13.0

13.5

14.0

69.7

100.8

133.2

167.0

202.3

239.2

29.0

59.3

90.8

123.7

158.0

193.9

277.7

318.1

360.5

404.9

451.6

500.8

231.5

270.8

312.0

355.2

400.6

448.4

29.6

60.5

92.8

126.4

30.3

61.9

94.8

161.6

198.4

236.9

277.3

319.7

364.2

411.1

460.4

512.5

567.5

625.7

687.4

752.9

129.3

165.3

203.1

242.6

284.2

327.8

373.7

422.1

473.1

527.0

584.0

644.5

708.6

30.9

63.2

97.0

132.3

169.2

208.0

248.6

291.4

336.3

383.7

433.7

486.4

542.3

601.5

664.4

31.6

64.6

99.2

135.4

173.3

213.1

254.9

299.0

345.3

394.2

445.9

500.6

558.5

620.1

32.3

66.1

101.5

138.6

177.6

218.5

261.6

307.0

354.8

405.4

458.9

515.6

575.8

33.1

67.7

104.0

142.1

182.1

224.2

268.6

315.4

364.8

417.2

472.6

531.5

33.8

69.3

106.6

145.7

186.8

230.2

276.0

324.3

375.4

429.6

487.2

34.7

71.0

109.3

149.5

191.8

236.5

283.8

333.7

386.7

442.9

72.8

112.1

153.5

197.1

243.2

292.0

343.7

398.6

36.4

74.7

115.1

157.7

202.7

250.3

300.7

354.3

37.4

76.7

118.3

162.1

208.6

257.8

310.0

38.4

78.8

121.6

166.9

214.8

265.7

39.4

81.1

125.1

171.9

221.5

40.5

83.4

128.9

177.2

41.7

85.9

132.9

43.0

88.6

9.5

6.45

0.76

10.0

9.68

1.53

0.43

10.5

12.90

2.29

0.87

0.30

11.0

16.13

3.05

1.30

0.60

0.23

11.5

19.35

3.82

1.73

0.91

0.46

0.19

12.0

22.58

4.58

2.16

1.21

0.70

0.38

12.5

25.81

5.34

2.60

1.51

0.93

0.56

0.32

0.14

13.0

29.03

6.11

3.03

1.81

1.16

0.75

0.48

0.27

0.12

0.16

14.5

15.0

15.5

16.0

16.5

17.0

17.5

18.0

552.5

607.1

664.8

725.8

790.5

859.2

498.8

551.9

608.1

667.4

730.4

797.2

13.5

32.26

6.87

3.46

2.11

1.39

0.94

0.63

0.41

0.24

0.11

14.0

35.48

7.63

3.90

2.42

1.62

1.13

0.79

0.55

0.36

0.21

0.10

14.5

38.71

8.40

4.33

2.72

1.86

1.32

0.95

0.68

0.48

0.32

0.19

15.0

41.94

9.16

4.76

3.02

2.09

1.51

1.11

0.82

0.60

0.43

0.29

0.18

0.08

15.5

45.16

9.92

5.19

3.32

2.32

1.69

1.27

0.96

0.72

0.54

0.39

0.27

0.16

16.0

48.39

10.69

5.63

3.63

2.55

1.88

1.43

1.09

0.84

0.64

0.48

0.35

0.24

0.15

0.07

16.5

51.61

11.45

6.06

3.93

2.78

2.07

1.58

1.23

0.96

0.75

0.58

0.44

0.32

0.23

0.14

0.07

17.0

54.84

12.21

6.49

4.23

3.02

2.26

1.74

1.37

1.08

0.86

0.68

0.53

0.41

0.30

0.21

0.13

17.5

58.06

12.98

6.93

4.53

3.25

2.45

1.90

1.50

1.20

0.97

0.78

0.62

0.49

0.38

0.28

0.20

0.12

0.06

18.0

61.29

13.74

7.36

4.83

3.48

2.64

2.06

1.64

1.32

1.07

0.87

0.71

0.57

0.45

0.35

0.26

0.18

0.12

35.5

0.09

0.08

0.06

44.3

DRILLING FLUIDS

Table FL-11: Data shows the quantity of barite in lb/bbl (same as 100 lb sacks /100 bbl) needed to increase the mud weight (upper right) and the volume of water in bbl water per bbl mud needed to decrease the mud weight (lower left). Keep in mind weight materials are small sized powders with high-surface area. Base fluid (water or oil) is often required to be added simultaneously when weighting-up to properly wet the material and maintain the desired viscosity and rheology values.

Table FL-11: Weight-Up (Barite) and Dilution (Water).

0.05

FL-37

FL-38

Table FL-12: Weight-Up (Barite) and Dilution (Water) - SI units (metric) Weight-up Chart for 4.1 SG Barite kg of barite per m3 mud (upper right section) and Dilution with Fresh Water m3 water per m3 mud (lower left section) Desired Mud Weight (kg/L) 1.02

1.00

1.05

1.10

1.15

1.20

1.25

1.30

67.2

136.7

208.5

282.8

359.6

68.3

139.0

212.1

287.7

69.5

141.4

215.8

70.7

1.05

.50

1.10

4.00

1.00

1.35

1.40

1.45

IADC Drilling Manual

1.50

1.55

1.60

1.65

1.70

1.75

439.3

521.8

607.4

366.1

447.3

531.5

292.9

372.7

143.9

219.6

71.9

146.4 73.2

Copyright © 2015

1.80

1.85

1.90

696.2

788.5

884.3

984.0

1087.8

1195.8

618.9

709.6

803.9

902.0

1004.1

1110.4

455.6

541.5

630.8

723.5

820.0

920.4

1308.5

1426.1

1548.9

1677.3

1811.6

1221.3

1337.0

1457.8

1584.1

1716.3

1025.0

1134.0

1247.8

1366.7

1490.9

1620.9

298.2

379.6

464.2

551.9

643.1

738.0

223.6

303.7

386.8

473.1

562.7

656.0

836.7

939.6

1046.8

1158.7

1275.6

1397.7

753.1

854.2

959.6

1069.6

1184.4

1304.5

149.1

227.8

309.4

394.2

482.4

574.0

669.4

768.8

872.3

980.4

1093.3

1211.4

1334.9

74.5

151.9

232.1

315.4

402.0

75.9

154.7

236.5

321.6

492.0

585.7

683.3

785.1

891.3

1002.2

1118.2

1239.5

410.0

502.0

597.9

697.9

802.2

911.1

1025.0

1144.2

77.4

157.7

241.2

78.8

160.8

328.0

418.4

512.5

610.6

713.0

820.0

931.8

1048.8

246.0

334.7

427.1

523.4

623.9

728.9

838.6

953.5

80.4

164.0

251.0

341.7

436.2

534.8

637.8

745.5

858.1

82.0

167.3

256.3

348.9

445.7

546.7

652.3

762.8

83.7

170.8

261.7

356.5

455.6

559.1

85.4

174.5

267.4

364.4

465.9

87.2

178.3

273.3

372.7

89.1

182.2

279.5

91.1

186.4 93.2

1.15

6.50

2.00

0.50

1.20

9.00

3.00

1.00

0.33

1.25

11.50

4.00

1.50

0.67

0.25

1.30

14.00

5.00

2.00

1.00

0.50

0.20

1.35

16.50

6.00

2.50

1.33

0.75

0.40

1.40

19.00

7.00

3.00

1.67

1.00

0.60

0.33

0.14

1.45

21.50

8.00

3.50

2.00

1.25

0.80

0.50

0.29

0.13

1.50

24.00

9.00

4.00

2.33

1.50

1.00

0.67

0.43

0.25

0.11

1.55

26.50

10.00

4.50

2.67

1.75

1.20

0.83

0.57

0.38

0.22

0.10

1.60

29.00

11.00

5.00

3.00

2.00

1.40

1.00

0.71

0.50

0.33

0.20

0.09

1.65

31.50

12.00

5.50

3.33

2.25

1.60

1.17

0.86

0.63

0.44

0.30

0.18

0.08

1.70

34.00

13.00

6.00

3.67

2.50

1.80

1.33

1.00

0.75

0.56

0.40

0.27

0.17

1.75

36.50

14.00

6.50

4.00

2.75

2.00

1.50

1.14

0.88

0.67

0.50

0.36

0.25

0.15

0.07

1.80

39.00

15.00

7.00

4.33

3.00

2.20

1.67

1.29

1.00

0.78

0.60

0.45

0.33

0.23

0.14

1.85

41.50

16.00

7.50

4.67

3.25

2.40

1.83

1.43

1.13

0.89

0.70

0.55

0.42

0.31

0.21

0.13

0.06

1.90

44.00

17.00

8.00

5.00

3.50

2.60

2.00

1.57

1.25

1.00

0.80

0.64

0.50

0.38

0.29

0.20

0.13

0.17

0.08

0.07

0.06

1.95

2.00

2.05

2.10

2.15

2.20

1952.4

2100.0

1854.8

2000.0

2255.0

2417.9

2589.5

2152.5

2312.8

1757.1

1900.0

2481.6

2050.0

2207.7

2373.7

1525.6

1659.5

1430.2

1561.9

1800.0

1947.5

2102.6

2265.8

1700.0

1845.0

1997.4

1464.3

2157.9

1600.0

1742.5

1892.3

2050.0

1366.7

1500.0

1640.0

1787.2

1942.1

1269.0

1400.0

1537.5

1682.1

1834.2

1171.4

1300.0

1435.0

1576.9

1726.3

1073.8

1200.0

1332.5

1471.8

1618.4

976.2

1100.0

1230.0

1366.7

1510.5

878.6

1000.0

1127.5

1261.5

1402.6

667.4

781.0

900.0

1025.0

1156.4

1294.7

572.1

683.3

800.0

922.5

1051.3

1186.8

476.7

585.7

700.0

820.0

946.2

1078.9

381.4

488.1

600.0

717.5

841.0

971.1

286.0

390.5

500.0

615.0

735.9

863.2

190.7

292.9

400.0

512.5

630.8

755.3

95.3

195.2

300.0

410.0

525.6

647.4

97.6

200.0

307.5

420.5

539.5

100.0

205.0

315.4

431.6

102.5

210.3

323.7

105.1

215.8

1.95

46.50

18.00

8.50

5.33

3.75

2.80

2.17

1.71

1.38

1.11

0.90

0.73

0.58

0.46

0.36

0.27

0.19

0.12

0.06

2.00

49.00

19.00

9.00

5.67

4.00

3.00

2.33

1.86

1.50

1.22

1.00

0.82

0.67

0.54

0.43

0.33

0.25

0.18

0.11

0.05

2.05

51.50

20.00

9.50

6.00

4.25

3.20

2.50

2.00

1.63

1.33

1.10

0.91

0.75

0.62

0.50

0.40

0.31

0.24

0.17

0.11

0.05

2.10

54.00

21.00

10.00

6.33

4.50

3.40

2.67

2.14

1.75

1.44

1.20

1.00

0.83

0.69

0.57

0.47

0.38

0.29

0.22

0.16

0.10

0.05

2.15

56.50

22.00

10.50

6.67

4.75

3.60

2.83

2.29

1.88

1.56

1.30

1.09

0.92

0.77

0.64

0.53

0.44

0.35

0.28

0.21

0.15

0.10

0.05

2.20

59.00

23.00

11.00

7.00

5.00

3.80

3.00

2.43

2.00

1.67

1.40

1.18

1.00

0.85

0.71

0.60

0.50

0.41

0.33

0.26

0.20

0.14

0.09

Table FL-12: For SI (metric) units,Table FL-12 shows the quantity of barite in kg/m3 needed to increase the mud weight (upper right) and the volume of water in cu m water per cu m mud needed to decrease the mud weight (lower left).

107.9 0.04

DRILLING FLUIDS

Initial Mud Weight (kg/ gal)

DRILLING FLUIDS

Table FL-13 : Unit Conversions for Density. Desired Units (multiply by)

Original units SG

kg/cu m

lb/gal

lb/cu ft

1

1,000

8.345

62.4

0.001

1.0

0.008345

0.0624

lb/gal

0.12

120

1

7.48

lb/cu ft

0.016

16.0

0.1337

1

SG (g/mL) kg/cu m

Table FL-14: Other Conversion Factors — US Oilfield and SI (Metric). Original Units

Desired Units

Multiply by

barrel (bbl)

cubic feet (cu ft)

5.615

barrel (bbl)

cubic meter (cu m)

0.159

barrel (bbl)

US gallon (gal)

42

US gallon (gal)

liter (l)

3.785

cubic meter (cu m)

barrel (bbl)

6.289

liter (l)

1,000

cubic meter cu m)

Mass (weight) kilogram (kg)

pound (lb)

2.204

pound (lb)

kilogram (kg)

0.454

US ton (t)

pound (lb)

2,000

metric ton (mt)

kilogram (kg)

1,000

metric ton (mt)

pound (lb)

2,204

Length or distance feet (ft)

meter (m)

0.3048

inch (in.)

centimeter (cm)

2.54

inch (in.)

millimeter (mm)

25.4

meter (m)

feet (ft)

3.281

Pressure (force/area) lb/sq in. (psi)

kiloPascal (kPa)

6.895

lb/sq in. (psi)

bar (bar)

0.06895

lb/sq in. (psi)

kg/sq cm

0.0703

kiloPascal (kPa)

lb/sq in. (psi)

0.145

bar (bar)

kiloPascal (kPa)

100

Atmosphere (atm)

lb/sq in. (psi)

14.7

bar

lb/sq in. (psi)

14.5

Temperature Centigrade (°C) to Fahrenheit (°F)

°F = ( °C x 1.8 ) + 32

Fahrenheit (°F) to Centigrade (°C)

°C = (°F – 32 ) 1.8

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FL-39

FL-40

DRILLING FLUIDS

Government regulations

Regulations on the use and disposal of drilling fluids exist in many forms. These regulations generally focus on the health and safety of workers and the protection of the environment. Potential hazards of drilling fluid materials are identified in MSDSs1, along with recommended practices for managing the HSE risks and regulations pertinent to the country (and hemisphere) of origin of the material. Recent developments have led to formation of the GHS which has modified the MSDS requirements. 2 Among the changes, the word “Material” has been dropped from the new standard forms and they are now simply labeled “SDS” instead of “MSDS.” Drilling fluids may contain potentially hazardous materials that are regulated either at the source, during storage or transport, during use and/or during disposal. These include the base fluid itself, which can range from fresh water to produced brines to various types of NAFs. In addition, various additives can pose HSE risks. The types of materials that are of particular concern include cationic polymers, surfactants, biocides, trace heavy metals, alkalinity control agents, flammable materials, oxidizers and other potentially corrosive or reactive compounds as well as any material containing a relevant concentration of a listed hazardous chemical. Even generally innocuous materials like starches, which are normally used as filtration control agents, may pose a potential explosion hazard as dusts. Various materials can also be an environmental risk for low forms of life and are controlled or banned in some applications. It is imperative that drilling fluid suppliers, service companies and operators all have a thorough understanding of the HSE limitations of each and every material used to formulate drilling fluids.

Health and safety regulations

Workplace restrictions defined by individual companies and governmental bodies like OSHA define limits of exposure for workers to various materials to protect their health and safety 3, 4. Engineering and administrative protocols, as well as PPE, are also prescribed. Volatile, flammable and/or aromatic materials, such as diesel fuel oil, have received much attention; However, materials thought to be acutely and/or chronically toxic, such as products containing heavy metals, have also received scrutiny. 5-11 Various international organizations have attempted to provide some guidance on the use and disposal of materials used in drilling oil and gas wells. OSPAR is the mechanism by which fifteen European governments came together to define protocols for the protection of the marine environment of the North-East Atlantic. It started in 1972 with the Oslo Convention against dumping. It was broadened to cov-

IADC Drilling Manual

er land-based sources and the offshore industry by the Paris Convention of 1974. These two conventions were unified (hence OSPAR), up-datedand extended by the 1992 OSPAR Convention. The new annex on biodiversity and ecosystems was adopted in 1998 to cover non-polluting human activities that can adversely affect the sea. The OSPAR Convention requires application of best available techniques (BAT) and best environmental practice (BEP) to prevent and eliminate marine pollution. OSPAR has pioneered this concept internationally and adopted a large number of BAT and BEP recommendations for various industrial technologies and sources of land-based pollution. Indeed, the majority of governments involved in offshore exploration and production or E & P (including Africa, the Middle East and the Far East), but some onshore as well, subscribe to the precepts of the OSPAR Convention. BAT is defined by OSPAR as “the latest stage of development (state of the art) of processes, of facilities or of methods of operation which indicate the practical suitability of a particular measure for limiting discharges, emissions and waste.” BEP is defined as “the application of the most appropriate combination of environmental control measures and strategies”.

Table FL-15 : Hazard ranking of materials under charm model12 Key to HQ Bands Min Value

Max Value

Category

>0

=1

=30

=100

=300

=1,000

Purple

At the beginning of 1996, OSPAR released the offshore chemical notification scheme (OCNS) which manages chemical use and discharge by offshore petroleum industries in the UK and the Netherlands. The OCNS uses the OSPAR harmonized mandatory control scheme (HMCS) developed through the OSPAR Decision 2000/2. This scheme ranks chemical products according to the hazard quotient (HQ) which is calculated using the chemical hazard and risk management (CHARM) model. The lower the HQ, the more hazardous the material. The ranking is shown in Table FL-15.

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FL-41

Table FL-16: E&P Waste Discharge Limitsa,b. E&P Waste

Disposal Technique

pH

Electrical Conductivity (mmhos/cm)

Sodium Adsorption Ratio

Exchangeable Sodium

Oil & Grease (%)

(%)

Oil & Grease (%)

NPDESc

NPDES

NPDES

NPDES

NPDES

Roadspreading

6-9

75 rpm) prior to POOH. • Monitor sag tendency with a Viscometer Sag Shoe Test (VSST), keeping the difference in mud weight to 75 rpm) to move cuttings up and out of the hole.

Corrosion

Corrosion is the deterioration of a metal surface due to reaction to its environment. It is a particular issue for low pH WBMs, aerated fluids, packer fluids and completion brines. There are many forms of corrosion: general, pitting, stress corrosion cracking, sulfide stress cracking, erosion corrosion, corrosion fatigue, galvanic corrosion, and de-alloying. These types of corrosion can be accelerated by low pH, salt concentration, dissolved oxygen, acid gases (CO2 and H2S), higher temperatures and pressures, bacterial degradation and scale. Corrosion is monitored and diagnosed by using drill string corrosion coupons installed in the last joint of pipe above the BHA and one installed near the surface (such as in the Kelly safer sub).

General treatment procedures »» Dissolved oxygen

For dissolved oxygen: • Maintain ph >10.0. • Submerge mud-mixing guns. Only operate mixing equipment when needed and minimize all sources of air entrainment. • Add defoamer to the mud system. • Add oxygen scavenger, film-forming amine or a passivating inhibitor. If scale is observed on the corrosion monitoring coupons, add a scale inhibitor.

»» Acid gases (CO2 and H2S)

For acid gases: • Raise pH to 10-11.5, depending on the acid gas encountered and increase PF to >1.0. • Monitor acid gas levels with the Garrett Gas Train and appropriate Dräger tubes or other procedures.

IADC Drilling Manual

»» Bacterial degradation

Gas hydrates

Gas hydrates are ice-like materials that can form in WBMs when mixed with gas at low temperatures and high pressures. This can happen in deepwater operations and in arctic locations. When gas mixes with a WBM, the combination of high pressure and/or low temperatures can form gas hydrates at temperatures much higher than the freezing point of water. Hydrates are also found in shallow formations below the seabed in deep or cold oceans and in arctic permafrost land areas. Hydrate formation can cause serious well control problems in deepwater wells: plugging of choke and kill lines, plugging in and around BOP equipment; and loss of water from the drilling fluid. Periods of no circulation with gas entering the wellbore are the most susceptible times when hydrates are likely to form, especially in the BOP stack and choke and kill lines.

Prevention and mitigation recommendations (when drilling with a riser): »» WBMs

Elevate the salt content to >20% by weight or close to saturation. Add sufficient concentrations of diethylene glycol (DEG) or monoethylene glycol (MEG) inhibitors. In sufficient quantities, these chemical inhibitors can prevent hydrate crystal formation. Other types of inhibitors are “kinetic” inhibitors that allow the hydrates to form but restrict the crystal growth in such a way that the fluid should stay pumpable.

»» Non-aqueous fluids (NAF)

Since the internal phase of these systems is water, they are susceptible to gas hydrate formation as well. Due to the reduced amount of water in the system (15-30%), if hydrates form, they will not form a solid blockage and are likely to remain pumpable. There will, however, still be a need to inhibit

Copyright © 2015

FL-26

DRILLING FLUIDS

gas hydrates. This is done through maintaining the concentration of calcium chloride in the brine phase. Typically, >25% by weight of calcium chloride is kept in the water phase as inhibition against hydrates.

»» Well operations

Maintain adequate mud weight to keep gas out of the wellbore! No available gas means no hydrates will form. If using WBMs, spot high-salt or glycol-treated fluids across the BOP stack and in the choke and kill lines as a preventative measure. High concentrations of natural gas hydrates can sometimes be found near the base of permafrost in arctic locations. If hydrates are encountered, lower the ROP substantially to bring up the gas slowly and in a manageable fashion.

gating together to form mud rings or restrictions inside of the riser. Treatments with surfactants and other anti-balling additives or a cleanout trip may be needed if the problem is severe. Use a riser boost pump and adequate circulation times prior to trips to clear cuttings from the riser.

Stuck pipe

Deepwater riser issues

Stuck pipe issues can be divided into mechanical and differential causes. Some of the causes of mechanical sticking include hole packoff /bridges, settled cuttings, shale instability, loosely consolidated formations and junk in the hole. Wellbore geometry issues may also lead to mechanical sticking and include key-seats, an undergauge hole, stiff BHA, severe doglegs, mobile formations and casing failures. Differential sticking is caused by high overbalance, stationary drill string, high fluid loss or a thick filter-cake. It is worse with high-density or high-solids mud systems.

Hole cleaning

Treatments for differential sticking

Due to the larger internal diameters of a riser when drilling smaller hole size intervals, the annular velocity in the riser is typically very low and poor hole cleaning may be a problem. Elevating the viscosity by increasing the YP, LSRYP and lowshear rate viscosity (three and six rpm shear stress values) will aid hole cleaning. Muds which become more viscous at cold temperatures and those with high progressive gel strengths are detrimental when the mud sits in the riser for an extended period of time, such as during a trip. The use of “flat rheology” NAF systems will help mitigate the cold temperature affects. After increased viscosity, the other factor that improves hole cleaning is annular velocity. When drilling with fast ROPs in large diameter sections (>17.5 in.), it is often necessary to use flowrates over 1400-1600 gal/min to clean the riser (especially large PDC cuttings). The use of a riser boost pump is recommended to aid with hole cleaning and to maintain a clean riser.

Rheology effects

During periods of shut down, cold-water temperature effects will raise the rheology of the system. The use of “flat rheology” mud systems for deepwater applications is becoming more commonplace. These systems maintain a fairly level YP and gel strength throughout the 40°F-150°F temperature range. They also minimize the higher annular pressure that occurs during circulation after long static periods of time as the mud system heats up and thins down.

Balling with WBM

If WBM is used, shallow reactive formations (gumbo) or a long trip might lead to softening and hydration of reactive cuttings entrained in the mud system which have not been cleaned from the riser, even if the WBM system is thought to be “inhibitive”. This could lead to cuttings sticking and aggre-

IADC Drilling Manual

• Reduce mud weight if possible. • Use NAF spotting fluid to “crack” the filter-cake and equalize differential pressures between the formation and the borehole. • Reduce the API and HTHP fluid loss to create a thin and low-permeability filter cake for WBMs. • Use lubricants and additives that will make the lubricity of the filter lower and less susceptible to differential sticking. Note: Spotting fluids utilized in offshore environments may be subject to regulatory limitations for discharge.

Lost circulation

The partial or complete loss of mud returns is a lost circulation event. It is typically seen by reduced pit volume, loss of pump pressure and reduced volume of return flow at the shale shaker. Keeping the hole full when the loss event occurs is paramount for wellbore stability and maintaining well control. Loss mechanisms are: surface system losses; naturally occurring faults and open fractures; high-permeability formations (such as shallow gravel and dolomite or carbonate formations with vugs); induced fractures; and fracture wellbore breathing (ballooning). Induced fracture losses are one of the most common causes of lost circulation. This often happens when the mud weight is increased while drilling deeper during an interval to control increasing pore pressure at greater depths. This increase in density may exceed the fracture pressure somewhere above in the open hole, inducing a fracture. This induced fracture is most often near the last casing shoe or in a severely depleted formation. While LCM treatments may be effective,

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DRILLING FLUIDS

it is often necessary to find a way to drill ahead to the casing point with the losses or run the casing early. Wellbore strengthening is a drilling fluid technique that uses a certain concentration of sized LCM to prevent lost circulation by preventing or limiting induced fractures. Theories vary on how wellbore strengthening works and on what concentration or particle size should be used. The concentration and particles need to be in the drilling fluid prior to drilling the interval and they need to be maintained continuously. Concentrations in the order of 20 to 50 lb/bbl are used for wellbore strengthening and particle sizes range from a narrow 250-650 micron range to a wide 50-2000 micron range. Wellbore strengthening has allowed intervals to be drilled without losses using mud weights that are several pounds per gallon higher than offset wells where this strategy was not used. Losses to high-permeable formations or natural subsurface conditions, such as a fault or open fracture, are often identified by a drilling break just prior to the loss event. These kinds of loss zones can normally be treated with LCM if a large enough material can be used. Effective bridging can be achieved at concentrations as low as 10 lb/bbl if the size of the material is half the diameter of the fracture or pore opening. Keep in mind that most LCMs have a wide particle size distribution and it is only the larger particles that initiate the bridge or sealing process. LCM sizes are also limited by drill string components, with 2 mm being about the largest size that can be used with most LWDs/MWDs and mud motors. LCM material types for seepage to moderate losses would include granular (particulate), fibrous/cellulosic, flakes/ platelets and mixed LCM types. These are often locally sourced low-cost agricultural or industrial byproducts. Pills, squeezes and spotting solutions for persistent loss zones include: dilatant slurries; high fluid-loss, high-solids dewatering squeezes; cross-linked polymer pills; gunk or reverse gunk squeezes activated downhole; sodium silicate pills; latex pills; swellable polymer pills; mud gelling material pills; barite/hematite plugs; thixotropic LCM/WSM (wellbore strengthening material) plugs; cement plugs; and resin-coated sand pills. An important tool to have before drilling is a lost circulation decision tree. This helps determine the proper treatment based on the amount of losses, local experience and availability of products. An example is provided in Figure FL-7. Note that this is only an example.

Salt formations and rubble zones

The major problems typically associated with drilling salt

IADC Drilling Manual

FL-27

formations are: stuck pipe; managing salt saturation or oversaturation of mud system, bit-balling and losses when encountering salt inclusions; wellbore enlargement when drilling through the salt formation and/or through shales above or below the salt formation (rubble zones); excessive torque and pack-offs caused by salt creep; difficulty evaluating the required mud weight; well control issues; and excessive mud losses. The rubble zone that might lie beneath, adjacent to or on top of the salt section usually consists of a series of highly reactive shale stringers that are embedded with unconsolidated sands. This zone could be over-pressured at the entry point because of a gas pocket under the salt or other reasons. For the remainder of the section, it could be under-pressured (leading to numerous problems) or unconsolidated (causing severe lost circulation problems). Determining the mud weight needed to drill out the bottom of the salt is difficult as salt does not have a true pore pressure and can be drilled significantly over-pressured or under-pressured.

Treatments

Treatment methods include the following: • Wellbore Enlargement in Salt: Drill with saturated salt WBMs or NAFs. Minimize the addition of water and monitor chlorides; • Formation Gas or Saltwater in the Rubble Zone: Increase mud weight to the safest level to control the intrusions; • Lost Circulation: Pretreat with LCM before entering the rubble zones. The LCM might include calcium carbonate, graphite materials and cellulosic LCM. Other LCM types might be needed if losses are severe. Develop a lost circulation strategy for the rubble zone prior to the start of the well; • Drilling Below Salt: Have a salt exit strategy developed prior to drilling below the bottom of the salt. This might include entraining the mud system with a variety and high concentration of LCM, having a LCM pill built and ready to pump and other operational procedures; • Stuck in Salt: Spot a fresh water pill across the suspected stuck pipe zone to dissolve the salt.

HTHP conditions When using WBM and NAF systems, HTHP wells are susceptible to problems such as high-temperature gelation, barite sag, high-solids content, dehydration, decreases in total alkalinity and increased fluid losses. The use of temperature stable mud products is key to minimizing these potential problems. Rheology stabilizers, thinners, chemicals to reduce fluid loss and aid in filter cake building, barite sag treatment chemicals and others must be stable to the highest BHT expected to be seen. The mud system should be run with minimum low gravity solids (LGS) to reduce or prevent HTHP gelation problems. Higher concentrations and tem-

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DRILLING FLUIDS

FL-28

Lost Circulation Remedial Treatment Options (based on loss type / amount).

Matrix Permeability Depeleted Zones Microfractures

Natural Fractures Induced Fractures Vugs / Fractured Limestone

See page losses (100 bbls/hr WBM or >30 bbls /hr NAF

Water Base Mud

Non-Aqueous Fluid

Water Base Mud

Non-Aqueous Fluid

Water Base Mud

Non-Aqueous Fluid

LCM Pill - Materials: 10 ppb Fiber 10 ppb CaCO3 - Fine 10 ppb CaCO3 - Med 15 ppb Nut Shells - Med

LCM Pill - Materials: 2 ppb Wetting Agent 20 ppb CaCO3 F/M 20 ppb Graphite Med 10 ppb Fiber LCM F

LCM Pill - Materials: 20 ppb CaCO3 - Med 20 ppb CaCO3 - Fine 15 ppb Nut Shells- Med 15 ppb Fiber LCM F

LCM Pill - Materials: 2 ppb Wetting Agent 30 ppb CaCO3 F/M 30 ppb Graphite Med 10 ppb Fiber LCM F

LCM Pill - Materials: 40 ppb CaCO3 M/C 30 ppb Graphite Med 10 ppb Nut Shells - Med 20 ppb Fiber LCM F/M

LCM Pill - Materials: 2 ppb Wetting Agent 40 ppb CaCO3 M/C 40 ppb Graphite Med 20 ppb Fiber LCM F/M

No success

No success

No success

High Fluid Loss Pills Reactive Pills

Cross-Linked Polymer Pills

Large Particulate LCM Pills

Soft / Hard Plugs

Attapulgite Squeeze Diatomaceous Earth / LCM Squeeze Diaseal-M Squeeze Reactive, NonParticulate LCM Pill

Crome-Polymer Crosslinked Pills Borate-Polymer Crosslinked Pills

Conventional LCM - 140-160 ppb (Fibers, Granular, Flakes, Mixed LCM)

Gunk Squeeze Reverse-Gunk Squeeze Base Oil-Bentonite-Squeeze Base Oil-Bentonite-Cmt Squeeze Barilte Plugs Cemet Plugs

Misc Materials

Swellable CoPolymers Sodium Silicate Pills Thixotropic LCM Pills

Figure FL-7: Lost-circulation decision tree example.

perature stabilizing additives may be required to make the system tolerant of HTHP conditions. One means of addressing the gelation potential is to spot a pill on the bottom with increased additions of temperature stable products prior to making a trip. Have a HTHP drilling plan in place prior to the start of a well. For a NAF system, the utilization of temperature-stable organophilic clays and emulsifiers/wetting agents should be selected to minimize problems.

Wellbore stability issues

Wellbore stability issues are often exemplified by excess shale cuttings coming over the shaker, splintery shale cuttings, mud losses, tight holes on trips or connections, hole fill-up while tripping, the need for excessive reaming when making connections and other drilling problems. High-angle wellbores and certain directions will require higher mud weights than a vertical well to maintain stability. Some things to keep in mind for the mud system include: • Keep the mud weight high enough to maintain mechanical hole stability and prevent sloughing; • Keep fluid loss as low as possible and use deformable plugging agents to keep micro-fractured shales from being invaded and swelling, crumbling or delaminating; • Increase rheology to increase the hole cleaning ability of mud and address the pack-off issues;

IADC Drilling Manual

• Keep shales from swelling or failing from chemical interactions by using a NAF system or inhibitive WBM system.

Calculations and tables Brine tables

Brines and fluids containing salts, are often used as the base fluid for drilling fluids and for completion fluids. Sodium chloride and calcium chloride are the most common salts used. The density of all brines changes significantly with temperature. It is critical to know the temperature at which the density is measured as well as the temperature of a given application. The freezing points and crystallization temperatures listed in Table FL-7 for sodium chloride and Table FL-8 for calcium chloride are examples only. These values vary significantly depending on the purity of the salt or brine being used and with contamination.

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DRILLING FLUIDS

Important calculations

FL-29

Rect. tank vol. (cu m) = length (m) x width (m) x depth (m)

Volume of mud in the circulating system

Everyone involved with managing the circulation system needs to know the volume of the circulating system and the volume of the hole at all times. They must also be able to determine changes and circulation requirements for performing various operations. This includes the mud in the active pits and the mud in the hole, both with pipe in the hole (at any depth) and with no pipe in the hole.

Eq 6

Upright cylindrical tank volume Cyl. tank vol. (bbl) = 0.14 x [ dia. (ft) ]2 x height (ft)

Eq 7

Cyl. tank vol. (cu m) = 0.7854 x [ dia. (m) ]2 x height (m)

Eq 8

Circulating system vol.= surface system vol. + hole vol. Eq 4 Note: 1 cu m = 1,000 liters Similar calculations can be made to determine the volume in reserve or storage tanks and pits. Customary units for drilling fluid volumes are oilfield barrels (42 US gallons) abbreviated by bbl or cubic meters (cu m). (1 cu m = 6.29 bbl.)

Surface system volume calculations Rectangular tank volume Rect. tank vol. (bbl) length (ft) x width (ft) x depth (ft)  = 5.61 cu ft/bbl

Eq 5

Surf. system vol. = tank1 + tank 2 + tank 3 +...+ tankn

Eq 9

Note: Many surface systems have substantial volumes of mud in piping or troughs that lead to and from the wellhead. These volumes should be estimated and included in the surface volume. Rounded tank bottoms and internal piping not filled with active mud should likewise be excluded from surface volume calculations.

Table FL-7: Sodium chloride brine (100% pure NaCl). Density @ 68°F (20°C)

Specific Gravity

Sodium Chloride

Sodium Chloride (100%)

Sodium Chloride (100%)

Water

Sodium Ion

Chloride Ion

Freezing Pt or Crystallization Temp*

(lb/gal)

(g/mL)

(wt %)

(lb/bbl)

(kg/m3)

(vol / final vol)

(mg/L)

(mg/L)

°F

°C

aw

8.34

1.000

0.0

0.0

0

1.000

0

0

32

0

1.000

8.4

1.007

1.0

3.6

10

0.996

0

0

31

-1

0.995

8.5

1.019

2.7

9.7

28

0.991

0

0

29

-2

0.986

8.6

1.031

4.4

15.8

45

0.985

0

0

27

-3

0.976

8.7

1.043

6.0

22.0

63

0.979

0

0

25

-4

0.965

8.8

1.055

7.7

28.4

81

0.972

0

0

23

-5

0.954

Water Activity

8.9

1.067

9.3

34.8

99

0.966

0

0

21

-6

0.941

9.0

1.079

10.9

41.3

118

0.960

0

0

19

-7

0.928

9.1

1.091

12.5

47.9

137

0.953

0

0

16

-9

0.914

9.2

1.103

14.1

54.6

156

0.946

0

0

14

-10

0.900

9.3

1.115

15.7

61.3

175

0.939

0

0

11

-12

0.884

9.4

1.127

17.2

68.0

194

0.932

0

0

8

-13

0.868

9.5

1.139

18.7

74.8

214

0.925

0

0

5

-15

0.852

9.6

1.151

20.2

81.7

233

0.917

0

0

2

-17

0.835

9.7

1.163

21.7

88.5

253

0.909

0

0

-2

-19

0.817

9.8

1.175

23.2

95.4

272

0.902

0

0

-6

-21

0.799

9.9

1.187

24.6

102.3

292

0.894

0

0

8

-13

0.781

10.0

1.199

26.0

109.1

311

0.886

0

0

27

-3

0.762

* Examples only. Freezing point and crystallization temperature vary significantly depending on salt/brine purity.

IADC Drilling Manual

Copyright © 2015

FL-30

DRILLING FLUIDS

Table FL-8: Calcium chloride brine (94-97% grade powder). Density @ 68°F (20°C)

Specific Gravity

Calcium Chloride

Calcium Chloride

Calcium Chloride

Water

Calcium Ion

Chloride Ion

Freezing Pt or Crystallization Temp*

(lb/gal)

(g/mL)

(wt %)

(lb/bbl)

(kg/m3)

(vol / final vol)

(mg/L)

(mg/L)

8.34

1.000

0.0

0.0

0

1.000

0

0

32

0

1.000

8.5

1.019

2.3

8.4

24

0.995

8,200

14,500

28

-2

0.997

8.6

1.031

3.7

13.7

39

0.991

13,500

23,900

26

-3

0.992

8.7

1.043

5.1

19.2

55

0.988

18,800

33,300

25

-4

0.986

8.8

1.055

6.5

24.7

70

0.984

24,300

43,000

23

-5

0.978

°F

Water Activity

°C

aw

8.9

1.067

7.9

30.3

87

0.981

29,800

52,800

21

-6

0.969

9.0

1.079

9.2

36.0

103

0.977

35,400

62,700

19

-7

0.959

9.1

1.091

10.6

41.8

119

0.973

41,100

72,800

17

-8

0.948

9.2

1.103

11.9

47.7

136

0.969

46,900

83,000

15

-9

0.936

9.3

1.115

13.2

53.6

153

0.965

52,700

93,300

12

-11

0.923

9.4

1.127

14.5

59.6

170

0.961

58,600

103,700

9

-13

0.908

9.5

1.139

15.8

65.6

187

0.957

64,600

114,200

6

-14

0.893

9.6

1.151

17.0

71.7

205

0.953

70,600

124,800

3

-16

0.876

9.7

1.163

18.3

77.9

222

0.948

76,600

135,500

0

-18

0.859

9.8

1.175

19.5

84.1

240

0.944

82,700

146,300

-4

-20

0.841

9.9

1.187

20.7

90.3

258

0.939

88,800

157,200

-8

-22

0.822

10.0

1.199

22.0

96.6

276

0.934

95,000

168,100

-13

-25

0.802

10.1

1.211

23.1

102.9

294

0.929

101,200

179,100

-18

-28

0.782

10.2

1.223

24.3

109.2

312

0.924

107,500

190,100

-23

-31

0.760

10.3

1.235

25.5

115.6

330

0.919

113,700

201,200

-29

-34

0.739

10.4

1.247

26.6

121.9

348

0.914

120,000

212,300

-36

-38

0.716

10.5

1.259

27.8

128.3

366

0.908

126,300

223,400

-43

-42

0.693

10.6

1.271

28.9

134.8

384

0.903

132,600

234,600

-51

-46

0.669

10.7

1.283

30.0

141.2

403

0.897

138,900

245,700

-59

-51

0.645

10.8

1.295

31.1

147.6

421

0.892

145,200

256,900

-40

-40

0.620

10.9

1.307

32.1

154.0

439

0.886

151,500

268,100

-22

-30

0.595

11.0

1.319

33.2

160.4

458

0.880

157,900

279,300

-11

-24

0.569 0.543

11.1

1.331

34.2

166.9

476

0.874

164,200

290,500

0

-18

11.2

1.343

35.3

173.3

494

0.868

170,500

301,600

13

-11

0.516

11.3

1.355

36.3

179.7

513

0.862

176,800

312,700

25

-4

0.489

11.4

1.367

37.3

186.0

531

0.855

183,100

323,800

35

2

0.462

11.5

1.379

38.3

192.4

549

0.849

189,300

334,900

44

7

0.435

11.6

1.391

39.2

198.7

567

0.842

195,500

345,900

51

10

0.407

* Examples only. Freezing point and crystallization temperature vary significantly depending on salt/brine purity.

IADC Drilling Manual

Copyright © 2015

DRILLING FLUIDS

Hole volume calculations (pipe in hole) Eq 10

Hole vol. = ann. vol. + pipe cap. 

Annular volume (or pipe displacement):

For each section with different annular dimensions (inside diameter (ID) casing or open hole or outside diameter (OD) pipe), calculate: [ ID (in.)2 – OD (in.)2 ] Ann. vol. (bbl/ft) =



Eq 11

1,029

Ann. vol. (cu m/m) =

[ ID (mm)2 – OD (mm)2 ] 

Eq 12

FL-31

The values from Eq 14 and Eq 15 are then multiplied times the interval lengths to calculate the pipe (or hole) capacity for each section. The total pipe (or hole capacity) is then the sum of each different section volume from surface to total depth.

Pipe cap. = PCap1 + PCap2 + PCap3 +...+ PCapn 

Eq 16

Note: When calculating the hole capacity of the open hole, use the bit diameter multiplied by a factor to account for wellbore enlargement (typical values are 1.1 for OBMs and 1.25 to 1.5 for WBMs). These washout values can vary widely and are highly dependent on the formation drilled and other factors.

1.273 x 106 The values from Eq 11 and Eq 12 are then multiplied times the interval lengths to calculate the annular volume for each section. The total annular volume is then the sum of each annular volume from the surface to the total depth: Total ann. vol. = AV1 + AV2 + AV3 +...+ AVn 

Eq 13

Note: Pipe displacement volumes are important when determining if the hole is taking or giving the correct volume of fluid when tripping pipe or running casing. While these values can be calculated with Equations 11 or 12 (if the dimensions of the tool joints or casing collars are taken into account), it is recommended that displacement volumes be obtained from tables for the particular size and weight of pipe that includes the specific tool joint or casing connection dimensions.

Pipe (or hole) capacity

Pipe capacity is used to determine the volume of fluid inside the drill string. Hole capacity is used to determine the volume of fluid in the wellbore when the drill string is not in the well. For each section with different pipe (or hole) size, use the ID dimension of the pipe (or hole) and then calculate as follows:

Pipe (or hole) cap. (bbl/ft) =

ID (in.)2 1,029 

Eq14

2 Pipe (or hole) cap. (cu m/m) = ID (mm.) 6 1,273 x 10

Hole cap. = HCap1 + HCap2 + HCap3 +...+ HCapn 

Circulation times and strokes Pump output and circulation rate

The pump output (PO) can be calculated using Equations 18-19 or 21-22 for any liner size or stroke length. These values can also be found in the manufacturer’s tables or in generic tables like Tables FL-9 and FL-10. Mud pump efficiency is affected by many factors with operating pressure, pump RPM, mud weight, suction pressure, and the presence of larger mud particles (LCM and sand) having the greatest influence. Mud pump efficiency values are normally in the 75 to 95% range.

Triplex Mud Pumps

Triplex pumps have three pistons and pump fluid on the forward stroke only (single acting). As compared to duplex pumps, triplex pumps often have shorter stroke lengths (612 in.), operate at higher speeds (50-150 strokes/minute) and have higher efficiency (85-95%). PO (bbl/ Stk) = liner ID (in.)2 x stk (in.) x Eff. (decimal) Eq 18  4,118 PO output (l/Stk) = liner ID (mm)2 x stk (mm) x Eff. (decimal) Eq 19  424,413 Circ. rate (bbl/min) = bbl/stk x stk/min + bbl/stk x stk/min Eq 20

Eq15

IADC Drilling Manual

Eq 17

(Total for all pumps being used.)

Copyright © 2015

FL-32

DRILLING FLUIDS

Duplex mud pumps

Duplex pumps have two piston rods and four pump chambers so that they pump fluid on both the forward and backward stroke (double acting). On the backward stroke, the rod displaces some of the liner-swept volume and must be considered in the pump output calculation. Since rod diameters are different, it is important to use the correct value. Table FL-8 is an example and uses a typical rod diameter. As compared to triplex pumps, duplex pumps often have longer stroke lengths (8-18 in.), operate at lower speeds (40-80 strokes/minute)and have lower efficiency (75-90%). PO (bbl/Stk) =

circ. rate (cu m/stk)

6,177



BU (min)

=

BU (min)

=

ann. vol. (bbl)

ann. vol. (cu m)

BU (stk)

=

BU (stk)

=

ann. vol. (bbl)

Mud cycle (complete circulation of active system)

Mud cycle (min) =

circ. rate (bbl/min)

circ. rate (cu m/min)



Eq 24

During drilling operations, it is important to know the pipe capacity (or pipe displacement) and surface to bit time. This is the time required for the mud at the pump suction to be pumped down the drill string to the bit. This is used when displacing cement jobs, spotting pills for lost circulation, stuck pipe or other operations and during well control procedures to know when a new mud weight has reached the bit.

Surf. to bit (stk)

=

pipe cap. (bbl) circ. rate (bbl/min)

Eq 31 

pipe cap. (cu m) circ. rate (cu m/min) pipe cap. (bbl) circ. rate (bbl/stk)

Eq 32  Eq 33





 Mud cycle (stk) =

Surface to bit (pipe capacity/displacement)

Surf. to bit (min) =

circ. system vol. (cu m)

Eq 30

circ. rate (cu m/stk) 

Eq 23



Note: Circ. rate (bbl/min) = Circ. rate (gal/min) ÷ 42 gal/bbl

Mud cycle (min) =

ann. vol. (cu m)

Surf. to bit (min) =

circ. system vol. (bbl)

Eq 29

circ. rate (bbl/stk) 

The circulation rate (bbl/min) is the same as Equation 20.

Circulating system volume is calculated from Equation 4 (surface system volume + hole volume).

Eq 28

circ. rate (cu m/min) 



Eq 22

In mud conditioning, it is important to know the mud cycle time. This is the time required for the mud in the active system to make one complete circulation - mud from the pump suction is circulated to the bottom of the hole, out the bit, up the annulus, through the pits and back to the pump suction. When adding weight material or chemical treatments, it is often recommended to add these materials at such a rate that the mud will make at least one complete cycle during the treatment so that they are evenly distributed.

Eq 27

circ. rate (bbl/min) 

636,620 x Stk (mm) x Eff. (decimal) 

Eq 26

During drilling operations, it is important to know the bottoms-up (BU) or bit to surface time. This is the time required for the mud at the bit to be circulated up the annulus to the surface. It is important to know this time when circulating the hole clean prior to tripping, estimating the depth at which cuttings are being generated or when circulating and evaluating an influx from the well.

Eq 21

[ 2 x liner ID (mm)2 - Rod OD (mm)2 ]



Bottoms-up (bit to surface)

[ 2 x liner ID (in.)2 - Rod OD (in.)2]

x Stk (in.) x Eff. (decimal) PO (l/Stk) =

circ. system vol. (cu m)

Mud cycle (stk) =

circ. system vol. (bbl)

Eq 25

Surf. to bit (stk)

IADC Drilling Manual

Copyright © 2015

circ. rate (bbl/stk)





=

pipe cap. (cu m) circ. rate (cu m/stk) 

Eq 34

DRILLING FLUIDS

FL-33

Table FL-9: Triplex mud pump output. TRIPLEX MUD PUMP OUTPUT (barrels/stroke) 100% Efficiency Liner ID (in.)

Stroke Length (in.) 6.0

6.5

7.0

7.5

3.00

0.0131

3.25

0.0154

8.0

8.5

9.0

0.0142

0.0153

0.0167

0.0180

0.0164

0.0175

0.0186

0.0197

0.0192

0.0205

0.0218

0.0231

9.5

3.50

0.0178

0.0193

0.0208

0.0223

0.0238

0.0253

0.0268

0.0283

3.75

0.0205

0.0222

0.0239

0.0256

0.0273

0.0290

0.0307

0.0324

10.0

11.0

12.0

4.00

0.0233

0.0253

0.0272

0.0291

0.0311

0.0330

0.0350

0.0369

0.0389

4.25

0.0263

0.0285

0.0307

0.0329

0.0351

0.0373

0.0395

0.0417

0.0439

4.50

0.0295

0.0320

0.0344

0.0369

0.0393

0.0418

0.0443

0.0467

0.0492

0.0541

4.75

0.0329

0.0356

0.0384

0.0411

0.0438

0.0466

0.0493

0.0521

0.0548

0.0603

5.00

0.0364

0.0395

0.0425

0.0455

0.0486

0.0516

0.0546

0.0577

0.0607

0.0668

0.0729

5.25

0.0402

0.0435

0.0469

0.0502

0.0535

0.0569

0.0602

0.0636

0.0669

0.0736

0.0803

5.50

0.0441

0.0477

0.0514

0.0551

0.0588

0.0624

0.0661

0.0698

0.0735

0.0808

0.0881

5.75

0.0482

0.0522

0.0562

0.0602

0.0642

0.0682

0.0723

0.0763

0.0803

0.0883

0.0963

6.00

0.0525

0.0568

0.0612

0.0656

0.0699

0.0743

0.0787

0.0831

0.0874

0.0962

0.1049

6.25

0.0569

0.0617

0.0664

0.0711

0.0759

0.0806

0.0854

0.0901

0.0949

0.1043

0.1138

6.50

0.0616

0.0667

0.0718

0.0769

0.0821

0.0872

0.0923

0.0975

0.1026

0.1129

0.1231

6.75

0.0664

0.0719

0.0774

0.0830

0.0885

0.0940

0.0996

0.1051

0.1106

0.1217

0.1328

7.00

0.1309

0.1428

7.50

0.1503

0.1639

To convert to gallons/stroke multiply barrels/stroke x 42 To convert to liters/stroke multiply barrels/stroke x 159

Hole cycle time

During drilling operations, it is important to know the time or strokes for mud at the pump suction to be circulated down the drill string out the bit and up the annulus to the shale shakers. This is most often needed when increasing the mud weight to determine when the wellbore is fully displaced to the new mud weight. Hole cycle

= surf. to bit + BU

Eq 35

Hole volume (pipe out of hole)

Hole volumes are important to know when tripping in or out of the hole as they determine if the surface volume and pit capacity is sufficient. Hole volumes can be calculated in the same way pipe capacity is calculated (as shown below or found in the tables). For each hole section with different ID dimensions for the casing or open hole, calculate:

IADC Drilling Manual

Hole vol (bbl/ft)

Hole vol (cu m/m)

=

=

ID (in.)2 1,029

Eq 36 

ID (mm)2 1.273 x 106

Eq 37 

The values from Eq 36 and Eq 37 are then multiplied times the interval lengths to calculate the hole volume for each selection. The total hole volume with no pipe in the hole is then the sum of each different hole section volume from the surface to the total depth: Hole vol. (no pipe) = HV1 + HV2 + HV3 + .......... +HVn



Hydrostatic pressure and hydrostatic gradient

Eq 38

The hydrostatic pressure (PHYD) is the pressure the fluid column exerts on the wellbore. It is primarily controlled by increasing or decreasing the drilling fluid density or mud weight (MW).

Copyright © 2015

DRILLING FLUIDS

FL-34

Table FL-10: Duplex Mud Pump Output. DUPLEX MUD PUMP OUTPUT (barrels/stroke) 100% Efficiency Stroke Length (in.) 8

Liner ID (in.)

10

12

14

15

16

18

2.25

2.50

2.50

3.0

Rod size (in.) 1.75

2.0

2.0

4.00

0.0375

0.0453

0.0544

0.0611

0.0625

0.0667

0.0670

4.25

0.0428

0.0520

0.0624

0.0704

0.0725

0.0774

0.0790

4.50

0.0485

0.0591

0.0709

0.0803

0.0832

0.0887

0.0918

4.75

0.0545

0.0666

0.0799

0.0908

0.0944

0.1007

0.1053

5.00

0.0608

0.0745

0.0894

0.1018

0.1062

0.1133

0.1195

5.25

0.0674

0.0828

0.0993

0.1135

0.1187

0.1266

0.1344

5.50

0.0744

0.0915

0.1098

0.1256

0.1317

0.1405

0.1501

5.75

0.0817

0.1006

0.1207

0.1384

0.1454

0.1551

0.1665

6.00

0.0893

0.1101

0.1321

0.1517

0.1597

0.1703

0.1836

6.25

0.0972

0.1200

0.1440

0.1656

0.1745

0.1862

0.2014

6.50

0.1055

0.1303

0.1564

0.1800

0.1900

0.2027

0.2200

6.75

0.1141

0.1410

0.1693

0.1951

0.2061

0.2198

0.2393

7.00

0.1230

0.1522

0.1826

0.2106

0.2228

0.2377

0.2593

7.25

0.1322

0.1637

0.1965

0.2268

0.2401

0.2561

0.2801

7.50

0.1417

0.1757

0.2108

0.2435

0.2580

0.2752

0.3016

7.75

0.1516

0.1880

0.2256

0.2608

0.2765

0.2950

0.3238

8.00

0.1618

0.2007

0.2409

0.2786

0.2957

0.3154

0.3468

To convert to gallons/stroke multiply bbl/stroke x 42 To convert to liters/stroke multiply bbl/stroke x 159

PHYD (lb/in.2) =

PHYD (kPa)

MW (lb/gal) x 0.052 x TVD (ft)

Eq 39

While circulating, the annular pressure losses (APL) act to increase the pressure on the wellbore. This is called the equivalent circulating density (ECD).

= MW (kg/cu m) x 0.00981 x TVD (m) Eq 40

The hydrostatic pressure gradient (PHYD: G) is the rate at which the hydrostatic pressure increases with true vertical depth and has units of pressure per depth. The hydrostatic gradient for a given area is often compared to the gradient for fresh water (0.433 psi/ft) or seawater (0.465 psi/ft). PHYD: G (psi/ft)

PHYD: G (kPa/m) 

=

MW (lb/gal) x 0.052

= MW (kg/cu m) x 0.00981

Eq 41

Eq 42

IADC Drilling Manual



ECD =

PHYD + APL TVD x K (units conversion)

Eq 43

During well control and managed pressure drilling operations, surface pressures act on the hydrostatic column such that downhole wellbore pressures are increased by the amount of the surface pressure.

Quantities of mud materials

Mud weight can be increased with barite. The quantity of barite needed to increase the mud weight depends on the density of the barite. Currently, the two most common Specific Gravities (SG) for barite are either 4.2 or 4.1. Density expressed as specific gravity (g/ml) or using kg/l units have the same numerical value.

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DRILLING FLUIDS

»» Weight-up formula

For 4.1 SG barite these become:

The generalized weight-up formula is: Vol. inc. (bbl) =

Weight material (lb/bbl) =

SGwt mat x 350[MW2 (lb/gal) - MW1 lb/gal]

W2

SGwt mat x 8.345 – MW2 (lb/gal)



Vol. inc. (cu m) =

SGwt mat x 1000 [MW2 (kg/l) – MW1 (kg/l)] SGwt mat – MW2 (kg/l)



Eq 45

MW1 = initial mud weight MW2 = desired mud weight

1,435

Eq 50 

kg barite added 4,100

Eq 51 

Note: As an approximation, for every 14 sacks (100 lb) of barite, the volume will increase 1 bbl. For every 100 sacks (100 lb) barite, the volume increases 6.9 bbl.

»» Dilution and blending

It is common practice to blend two fluids or to dilute with water or NAF base fluid to reduce mud weight.

For 4.1 SG barite these become: Weight material (lb/bbl) =

1,435 [MW2 (lb/gal) – MW1 (lb/gal)] 34.2 – MW2 (lb/gal)

Eq 46 

The generalized dilution or blending formula (allowing the volume to increase) is:

Vorig x (MWorig – MWdesired)

Weight material (kg/cu = m) 4,100 [MW2 (kg/l) – MW1 (kg/l)] 4.1 – MW2 (kg/l)

Eq 47 

Vadded fluid is the volume of fluid to add to achieve the desired change in mud weight. Vorig is the original mud volume. MWorig is the original mud weight. MWadded fluid is the mud weight for the fluid being added. MWdesired is the desired final mud weight. When diluting with fresh water (8.345 lb/gal or SG 1.0), this becomes:

»» Volume increase due to material additions

When weighting up and making other treatments, the volume of material added increases the mud volume. For dry materials, this volume must be calculated based on the SG of the material.

Vwater (bbl) = Vorig (bbl) x [MWorig (lb/gal) – MWdesired (lb/gal) ] MWdesired (lb/gal) – 8.345

The generalized volume increase formulas for material additions are:

Eq 53

Vwater (cu m) =

lb material added SGmaterial x 350

Eq 52 



Note: As an approximation, in the mud weight range between 9 and 12 lb/gal, 60 lb/bbl (or 60 100 lb sacks barite/100 bbl) increases the mud weight 1.0 lb/gal. For mud weights above 12 lb/gal, divide the desired final weight by 0.2 to find the lb/bbl of barite needed to increase the mud weight 1.0 lb/gal (or the number of 100 lb sacks/100 bbl).

=

lb barite added

Eq 44

Weight material (kg/cu = m)

Vol. inc. (bbl)

FL-35

Eq 48

Vorig (cu m) x [MWorig (kg/l) – MWdesired (kg/l)] MWdesired (kg/l) - 1.0

Eq 54

 Vol. inc. (cu m) =

kg material added SGmaterial x 1000

Eq 49



IADC Drilling Manual

Annular velocity

Annular velocity is the mud velocity in the annulus between the drill string and the OD of the open hole or casing. This value helps when evaluating hole cleaning, especially in vertical sections where a value of 100 ft/min is considered to be sufficient for most situations. The usual US oilfield expression of this velocity is in feet per minute.

Copyright © 2015

FL-36

DRILLING FLUIDS

Ann. Vel.

=

Ann. Vel. (ft/min) =

24.5 x circ. rate (gpm)

circ. rate ann. vol.

Ann. Vel. (ft/min) = Eq 55

hole ID (in.)2 – pipe OD (in.)2

Eq 57 



circ. rate (bbl/min) ann. vol. (bbl/ft)

Eq 56

Ann. Vel. (m/min)



Drilling operations generally report the circulation rate in gallons per minute (gpm) and use inches; therefore, a common formula used for annular velocity is:

IADC Drilling Manual

Copyright © 2015

=

circ. rate (cu m/min) ann. vol. (cu m/m)

Eq 58 

IADC Drilling Manual Copyright © 2015

Weight-up Chart for 4.1 SG Barite pounds of barite per bbl mud (upper right section) and Dilution with Fresh Water bbl water per bbl mud (lower left section) Initial Mud Weight (lbm/ gal)

Desired Mud Weight (lbm/gal) 8.5

8.3

9.0 39.9

9.0

3.23

9.5

10.0

10.5

11.0

11.5

12.0

12.5

13.0

13.5

14.0

69.7

100.8

133.2

167.0

202.3

239.2

29.0

59.3

90.8

123.7

158.0

193.9

277.7

318.1

360.5

404.9

451.6

500.8

231.5

270.8

312.0

355.2

400.6

448.4

29.6

60.5

92.8

126.4

30.3

61.9

94.8

161.6

198.4

236.9

277.3

319.7

364.2

411.1

460.4

512.5

567.5

625.7

687.4

752.9

129.3

165.3

203.1

242.6

284.2

327.8

373.7

422.1

473.1

527.0

584.0

644.5

708.6

30.9

63.2

97.0

132.3

169.2

208.0

248.6

291.4

336.3

383.7

433.7

486.4

542.3

601.5

664.4

31.6

64.6

99.2

135.4

173.3

213.1

254.9

299.0

345.3

394.2

445.9

500.6

558.5

620.1

32.3

66.1

101.5

138.6

177.6

218.5

261.6

307.0

354.8

405.4

458.9

515.6

575.8

33.1

67.7

104.0

142.1

182.1

224.2

268.6

315.4

364.8

417.2

472.6

531.5

33.8

69.3

106.6

145.7

186.8

230.2

276.0

324.3

375.4

429.6

487.2

34.7

71.0

109.3

149.5

191.8

236.5

283.8

333.7

386.7

442.9

72.8

112.1

153.5

197.1

243.2

292.0

343.7

398.6

36.4

74.7

115.1

157.7

202.7

250.3

300.7

354.3

37.4

76.7

118.3

162.1

208.6

257.8

310.0

38.4

78.8

121.6

166.9

214.8

265.7

39.4

81.1

125.1

171.9

221.5

40.5

83.4

128.9

177.2

41.7

85.9

132.9

43.0

88.6

9.5

6.45

0.76

10.0

9.68

1.53

0.43

10.5

12.90

2.29

0.87

0.30

11.0

16.13

3.05

1.30

0.60

0.23

11.5

19.35

3.82

1.73

0.91

0.46

0.19

12.0

22.58

4.58

2.16

1.21

0.70

0.38

12.5

25.81

5.34

2.60

1.51

0.93

0.56

0.32

0.14

13.0

29.03

6.11

3.03

1.81

1.16

0.75

0.48

0.27

0.12

0.16

14.5

15.0

15.5

16.0

16.5

17.0

17.5

18.0

552.5

607.1

664.8

725.8

790.5

859.2

498.8

551.9

608.1

667.4

730.4

797.2

13.5

32.26

6.87

3.46

2.11

1.39

0.94

0.63

0.41

0.24

0.11

14.0

35.48

7.63

3.90

2.42

1.62

1.13

0.79

0.55

0.36

0.21

0.10

14.5

38.71

8.40

4.33

2.72

1.86

1.32

0.95

0.68

0.48

0.32

0.19

15.0

41.94

9.16

4.76

3.02

2.09

1.51

1.11

0.82

0.60

0.43

0.29

0.18

0.08

15.5

45.16

9.92

5.19

3.32

2.32

1.69

1.27

0.96

0.72

0.54

0.39

0.27

0.16

16.0

48.39

10.69

5.63

3.63

2.55

1.88

1.43

1.09

0.84

0.64

0.48

0.35

0.24

0.15

0.07

16.5

51.61

11.45

6.06

3.93

2.78

2.07

1.58

1.23

0.96

0.75

0.58

0.44

0.32

0.23

0.14

0.07

17.0

54.84

12.21

6.49

4.23

3.02

2.26

1.74

1.37

1.08

0.86

0.68

0.53

0.41

0.30

0.21

0.13

17.5

58.06

12.98

6.93

4.53

3.25

2.45

1.90

1.50

1.20

0.97

0.78

0.62

0.49

0.38

0.28

0.20

0.12

0.06

18.0

61.29

13.74

7.36

4.83

3.48

2.64

2.06

1.64

1.32

1.07

0.87

0.71

0.57

0.45

0.35

0.26

0.18

0.12

35.5

0.09

0.08

0.06

44.3

DRILLING FLUIDS

Table FL-11: Data shows the quantity of barite in lb/bbl (same as 100 lb sacks /100 bbl) needed to increase the mud weight (upper right) and the volume of water in bbl water per bbl mud needed to decrease the mud weight (lower left). Keep in mind weight materials are small sized powders with high-surface area. Base fluid (water or oil) is often required to be added simultaneously when weighting-up to properly wet the material and maintain the desired viscosity and rheology values.

Table FL-11: Weight-Up (Barite) and Dilution (Water).

0.05

FL-37

FL-38

Table FL-12: Weight-Up (Barite) and Dilution (Water) - SI units (metric) Weight-up Chart for 4.1 SG Barite kg of barite per m3 mud (upper right section) and Dilution with Fresh Water m3 water per m3 mud (lower left section) Desired Mud Weight (kg/L) 1.02

1.00

1.05

1.10

1.15

1.20

1.25

1.30

67.2

136.7

208.5

282.8

359.6

68.3

139.0

212.1

287.7

69.5

141.4

215.8

70.7

1.05

.50

1.10

4.00

1.00

1.35

1.40

1.45

IADC Drilling Manual

1.50

1.55

1.60

1.65

1.70

1.75

439.3

521.8

607.4

366.1

447.3

531.5

292.9

372.7

143.9

219.6

71.9

146.4 73.2

Copyright © 2015

1.80

1.85

1.90

696.2

788.5

884.3

984.0

1087.8

1195.8

618.9

709.6

803.9

902.0

1004.1

1110.4

455.6

541.5

630.8

723.5

820.0

920.4

1308.5

1426.1

1548.9

1677.3

1811.6

1221.3

1337.0

1457.8

1584.1

1716.3

1025.0

1134.0

1247.8

1366.7

1490.9

1620.9

298.2

379.6

464.2

551.9

643.1

738.0

223.6

303.7

386.8

473.1

562.7

656.0

836.7

939.6

1046.8

1158.7

1275.6

1397.7

753.1

854.2

959.6

1069.6

1184.4

1304.5

149.1

227.8

309.4

394.2

482.4

574.0

669.4

768.8

872.3

980.4

1093.3

1211.4

1334.9

74.5

151.9

232.1

315.4

402.0

75.9

154.7

236.5

321.6

492.0

585.7

683.3

785.1

891.3

1002.2

1118.2

1239.5

410.0

502.0

597.9

697.9

802.2

911.1

1025.0

1144.2

77.4

157.7

241.2

78.8

160.8

328.0

418.4

512.5

610.6

713.0

820.0

931.8

1048.8

246.0

334.7

427.1

523.4

623.9

728.9

838.6

953.5

80.4

164.0

251.0

341.7

436.2

534.8

637.8

745.5

858.1

82.0

167.3

256.3

348.9

445.7

546.7

652.3

762.8

83.7

170.8

261.7

356.5

455.6

559.1

85.4

174.5

267.4

364.4

465.9

87.2

178.3

273.3

372.7

89.1

182.2

279.5

91.1

186.4 93.2

1.15

6.50

2.00

0.50

1.20

9.00

3.00

1.00

0.33

1.25

11.50

4.00

1.50

0.67

0.25

1.30

14.00

5.00

2.00

1.00

0.50

0.20

1.35

16.50

6.00

2.50

1.33

0.75

0.40

1.40

19.00

7.00

3.00

1.67

1.00

0.60

0.33

0.14

1.45

21.50

8.00

3.50

2.00

1.25

0.80

0.50

0.29

0.13

1.50

24.00

9.00

4.00

2.33

1.50

1.00

0.67

0.43

0.25

0.11

1.55

26.50

10.00

4.50

2.67

1.75

1.20

0.83

0.57

0.38

0.22

0.10

1.60

29.00

11.00

5.00

3.00

2.00

1.40

1.00

0.71

0.50

0.33

0.20

0.09

1.65

31.50

12.00

5.50

3.33

2.25

1.60

1.17

0.86

0.63

0.44

0.30

0.18

0.08

1.70

34.00

13.00

6.00

3.67

2.50

1.80

1.33

1.00

0.75

0.56

0.40

0.27

0.17

1.75

36.50

14.00

6.50

4.00

2.75

2.00

1.50

1.14

0.88

0.67

0.50

0.36

0.25

0.15

0.07

1.80

39.00

15.00

7.00

4.33

3.00

2.20

1.67

1.29

1.00

0.78

0.60

0.45

0.33

0.23

0.14

1.85

41.50

16.00

7.50

4.67

3.25

2.40

1.83

1.43

1.13

0.89

0.70

0.55

0.42

0.31

0.21

0.13

0.06

1.90

44.00

17.00

8.00

5.00

3.50

2.60

2.00

1.57

1.25

1.00

0.80

0.64

0.50

0.38

0.29

0.20

0.13

0.17

0.08

0.07

0.06

1.95

2.00

2.05

2.10

2.15

2.20

1952.4

2100.0

1854.8

2000.0

2255.0

2417.9

2589.5

2152.5

2312.8

1757.1

1900.0

2481.6

2050.0

2207.7

2373.7

1525.6

1659.5

1430.2

1561.9

1800.0

1947.5

2102.6

2265.8

1700.0

1845.0

1997.4

1464.3

2157.9

1600.0

1742.5

1892.3

2050.0

1366.7

1500.0

1640.0

1787.2

1942.1

1269.0

1400.0

1537.5

1682.1

1834.2

1171.4

1300.0

1435.0

1576.9

1726.3

1073.8

1200.0

1332.5

1471.8

1618.4

976.2

1100.0

1230.0

1366.7

1510.5

878.6

1000.0

1127.5

1261.5

1402.6

667.4

781.0

900.0

1025.0

1156.4

1294.7

572.1

683.3

800.0

922.5

1051.3

1186.8

476.7

585.7

700.0

820.0

946.2

1078.9

381.4

488.1

600.0

717.5

841.0

971.1

286.0

390.5

500.0

615.0

735.9

863.2

190.7

292.9

400.0

512.5

630.8

755.3

95.3

195.2

300.0

410.0

525.6

647.4

97.6

200.0

307.5

420.5

539.5

100.0

205.0

315.4

431.6

102.5

210.3

323.7

105.1

215.8

1.95

46.50

18.00

8.50

5.33

3.75

2.80

2.17

1.71

1.38

1.11

0.90

0.73

0.58

0.46

0.36

0.27

0.19

0.12

0.06

2.00

49.00

19.00

9.00

5.67

4.00

3.00

2.33

1.86

1.50

1.22

1.00

0.82

0.67

0.54

0.43

0.33

0.25

0.18

0.11

0.05

2.05

51.50

20.00

9.50

6.00

4.25

3.20

2.50

2.00

1.63

1.33

1.10

0.91

0.75

0.62

0.50

0.40

0.31

0.24

0.17

0.11

0.05

2.10

54.00

21.00

10.00

6.33

4.50

3.40

2.67

2.14

1.75

1.44

1.20

1.00

0.83

0.69

0.57

0.47

0.38

0.29

0.22

0.16

0.10

0.05

2.15

56.50

22.00

10.50

6.67

4.75

3.60

2.83

2.29

1.88

1.56

1.30

1.09

0.92

0.77

0.64

0.53

0.44

0.35

0.28

0.21

0.15

0.10

0.05

2.20

59.00

23.00

11.00

7.00

5.00

3.80

3.00

2.43

2.00

1.67

1.40

1.18

1.00

0.85

0.71

0.60

0.50

0.41

0.33

0.26

0.20

0.14

0.09

Table FL-12: For SI (metric) units,Table FL-12 shows the quantity of barite in kg/m3 needed to increase the mud weight (upper right) and the volume of water in cu m water per cu m mud needed to decrease the mud weight (lower left).

107.9 0.04

DRILLING FLUIDS

Initial Mud Weight (kg/ gal)

DRILLING FLUIDS

Table FL-13 : Unit Conversions for Density. Desired Units (multiply by)

Original units SG

kg/cu m

lb/gal

lb/cu ft

1

1,000

8.345

62.4

0.001

1.0

0.008345

0.0624

lb/gal

0.12

120

1

7.48

lb/cu ft

0.016

16.0

0.1337

1

SG (g/mL) kg/cu m

Table FL-14: Other Conversion Factors — US Oilfield and SI (Metric). Original Units

Desired Units

Multiply by

barrel (bbl)

cubic feet (cu ft)

5.615

barrel (bbl)

cubic meter (cu m)

0.159

barrel (bbl)

US gallon (gal)

42

US gallon (gal)

liter (l)

3.785

cubic meter (cu m)

barrel (bbl)

6.289

liter (l)

1,000

cubic meter cu m)

Mass (weight) kilogram (kg)

pound (lb)

2.204

pound (lb)

kilogram (kg)

0.454

US ton (t)

pound (lb)

2,000

metric ton (mt)

kilogram (kg)

1,000

metric ton (mt)

pound (lb)

2,204

Length or distance feet (ft)

meter (m)

0.3048

inch (in.)

centimeter (cm)

2.54

inch (in.)

millimeter (mm)

25.4

meter (m)

feet (ft)

3.281

Pressure (force/area) lb/sq in. (psi)

kiloPascal (kPa)

6.895

lb/sq in. (psi)

bar (bar)

0.06895

lb/sq in. (psi)

kg/sq cm

0.0703

kiloPascal (kPa)

lb/sq in. (psi)

0.145

bar (bar)

kiloPascal (kPa)

100

Atmosphere (atm)

lb/sq in. (psi)

14.7

bar

lb/sq in. (psi)

14.5

Temperature Centigrade (°C) to Fahrenheit (°F)

°F = ( °C x 1.8 ) + 32

Fahrenheit (°F) to Centigrade (°C)

°C = (°F – 32 ) 1.8

IADC Drilling Manual

Copyright © 2015

FL-39

FL-40

DRILLING FLUIDS

Government regulations

Regulations on the use and disposal of drilling fluids exist in many forms. These regulations generally focus on the health and safety of workers and the protection of the environment. Potential hazards of drilling fluid materials are identified in MSDSs1, along with recommended practices for managing the HSE risks and regulations pertinent to the country (and hemisphere) of origin of the material. Recent developments have led to formation of the GHS which has modified the MSDS requirements. 2 Among the changes, the word “Material” has been dropped from the new standard forms and they are now simply labeled “SDS” instead of “MSDS.” Drilling fluids may contain potentially hazardous materials that are regulated either at the source, during storage or transport, during use and/or during disposal. These include the base fluid itself, which can range from fresh water to produced brines to various types of NAFs. In addition, various additives can pose HSE risks. The types of materials that are of particular concern include cationic polymers, surfactants, biocides, trace heavy metals, alkalinity control agents, flammable materials, oxidizers and other potentially corrosive or reactive compounds as well as any material containing a relevant concentration of a listed hazardous chemical. Even generally innocuous materials like starches, which are normally used as filtration control agents, may pose a potential explosion hazard as dusts. Various materials can also be an environmental risk for low forms of life and are controlled or banned in some applications. It is imperative that drilling fluid suppliers, service companies and operators all have a thorough understanding of the HSE limitations of each and every material used to formulate drilling fluids.

Health and safety regulations

Workplace restrictions defined by individual companies and governmental bodies like OSHA define limits of exposure for workers to various materials to protect their health and safety 3, 4. Engineering and administrative protocols, as well as PPE, are also prescribed. Volatile, flammable and/or aromatic materials, such as diesel fuel oil, have received much attention; However, materials thought to be acutely and/or chronically toxic, such as products containing heavy metals, have also received scrutiny. 5-11 Various international organizations have attempted to provide some guidance on the use and disposal of materials used in drilling oil and gas wells. OSPAR is the mechanism by which fifteen European governments came together to define protocols for the protection of the marine environment of the North-East Atlantic. It started in 1972 with the Oslo Convention against dumping. It was broadened to cov-

IADC Drilling Manual

er land-based sources and the offshore industry by the Paris Convention of 1974. These two conventions were unified (hence OSPAR), up-datedand extended by the 1992 OSPAR Convention. The new annex on biodiversity and ecosystems was adopted in 1998 to cover non-polluting human activities that can adversely affect the sea. The OSPAR Convention requires application of best available techniques (BAT) and best environmental practice (BEP) to prevent and eliminate marine pollution. OSPAR has pioneered this concept internationally and adopted a large number of BAT and BEP recommendations for various industrial technologies and sources of land-based pollution. Indeed, the majority of governments involved in offshore exploration and production or E & P (including Africa, the Middle East and the Far East), but some onshore as well, subscribe to the precepts of the OSPAR Convention. BAT is defined by OSPAR as “the latest stage of development (state of the art) of processes, of facilities or of methods of operation which indicate the practical suitability of a particular measure for limiting discharges, emissions and waste.” BEP is defined as “the application of the most appropriate combination of environmental control measures and strategies”.

Table FL-15 : Hazard ranking of materials under charm model12 Key to HQ Bands Min Value

Max Value

Category

>0

=1

=30

=100

=300

=1,000

Purple

At the beginning of 1996, OSPAR released the offshore chemical notification scheme (OCNS) which manages chemical use and discharge by offshore petroleum industries in the UK and the Netherlands. The OCNS uses the OSPAR harmonized mandatory control scheme (HMCS) developed through the OSPAR Decision 2000/2. This scheme ranks chemical products according to the hazard quotient (HQ) which is calculated using the chemical hazard and risk management (CHARM) model. The lower the HQ, the more hazardous the material. The ranking is shown in Table FL-15.

Copyright © 2015

DRILLING FLUIDS

FL-41

Table FL-16: E&P Waste Discharge Limitsa,b. E&P Waste

Disposal Technique

pH

Electrical Conductivity (mmhos/cm)

Sodium Adsorption Ratio

Exchangeable Sodium

Oil & Grease (%)

(%)

Oil & Grease (%)

NPDESc

NPDES

NPDES

NPDES

NPDES

Roadspreading

6-9