GBP Casing and Liner Running

Casing and Liner Running Best PracticesCreated: June 2004

Global

Best Practices for

Casing and Liner Running

Table of Contents

Casing and Liner Running Best Practices 11

IntroductionTable ofC

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Casing/Liner

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Eng. & Field

PlanningStudy

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Table of ContentsIntroduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Purpose . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Safety Notice . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3Tips for Using This Document . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

Reminders . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Time-Saving Navigation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

Table of Contents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Colored Tabs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Where Am I? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

General Casing and Liner Operations . . . . . . . . . . . . . . . . . . . .5Risk Identification and Procedures . . . . . . . . . . . . . . . . . . . . . . . . .5

Quality Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5Casing Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Tubing Material Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6Connections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7Casing Slip/Casing Compatibility and Design . . . . . . . . . . . . . . . . .7Dog Legs, Hole Diameter, Annular Clearance, and Deviation . . . .7Buckling Due to Temperature Effects While Drilling . . . . . . . . . . . .8Shoe Track Length . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8Wiper Plug Planning and Selection . . . . . . . . . . . . . . . . . . . . . . . . .9Autofill Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10Inner String . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Liner Hanger Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12Liner Hangers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12

Pressure Limitations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12Liner Top Packers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13Liner Tieback Sleeve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13Running Tool Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Casing Accessories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14Centralizer Planning and Selection . . . . . . . . . . . . . . . . . . . . . . . . 14

Bow-Spring Centralizers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15Rigid Centralizers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15Solid Body Centralizers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15Bow-Spring Centralizer Subs . . . . . . . . . . . . . . . . . . . . . . . . . . 16Quick Reference for Centralizer Selection and Installation . . .16Examples of Centralizer Types . . . . . . . . . . . . . . . . . . . . . . . . . 17

Table of Contents



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Guide Shoes and Float Equipment Planning and Selection . . . . .18Quick Reference for Guide Shoe and Float Equipment Selection . . . . . . . . . . . . . . . . . . . . . . . . . . . .19Examples of Casing Accessories . . . . . . . . . . . . . . . . . . . . . . . 20

Engineering and Field Planning Summary . . . . . . . . . . . . . . . . 23Engineering Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23Contingency Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Field Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

Pipe Handling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27Pre-Run Preparation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27

Vessel-to-Rig Pipe Rack . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27Casing Handling from Rig Pipe Rack to Rotary Table . . . . . . . 28Making Up and Running Casing—Slip to Slip . . . . . . . . . . . . .29

IntroductionT

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IntroductionPurposeThis best practice is an effort by the Casing, Liner Running, and Cementing Network to provide the Unocal Global Drilling Community with best practice recommendations to improve the success of Unocal's global casing, liner run-ning, and cementing operations. Unocal spends millions of dollars each year on casing, liner running, and cementing operations. Poor planning and opera-tional execution not only can lead to failure, but can result in the loss of hydrocarbon recovery from the wellbore.

Critical thinking and sound judgment will never be replaced by a best practice or standard operating procedure (SOP), but these recommendations can help operators identify some of the common risks and provide experienced-based solutions. Risk identification and mitigation is the essence of our daily work; this best practice can be used as a roadmap towards measures to prevent or mitigate problems.

This best practice is a companion to the Global Best Practices for Cementing published by the Casing, Liner Running, and Cementing Network in 2002. You can access the Global Best Practices for Cementing at the following URL:https://myteam.unocal.com/myteam/llisapi.dll/Global_Best_Practices_for_Cementing.pdf?func=doc.Fetch&nodeId=4844684&docTitle=Global+Best+Practices+for+Cementing

You can access the Central Drilling Group website by copying and pasting the following URL into your browser: http://mymigportalv2.unocal.com:7778/portal/page?_pageid=34,66322&_dad=portal&_schema=PORTAL

Safety NoticeJob safety is top priority in any operation. The recommended practices listed in this document are intended to stimulate critical thought and minimize the risk of accidents or injuries to personnel. This document is not intended to replace or supersede the sound judgment of experienced personnel.

Unocal management encourages all parties to continually strive to handle and run pipe as safely as possible. All involved individuals will be required to actively participate in pre-job safety meetings intended to identify and elimi-nate any/all unsafe conditions. Inexperienced individuals, individuals failing to exhibit an acceptable attitude towards safety, and other individuals deemed potentially at risk (for any reason) should be identified and removed from the location. This Global Best Practices for Casing and Liner Running is a living document and suggestions are appreciated.

Visit the Engineering Network LiveLink site to view this best practice, the Global Best Practices for Cementing document, and to obtain additional information.

https://myteam.unocal.com/myteam/llisapi.dll/Global_Best_Practices_for_Cementing.pdf?func=doc.Fetch&nodeId=4844684&docTitle=Global+Best+Practices+for+Cementing

http://mymigportalv2.unocal.com:7778/portal/page?_pageid=34,66322&_dad=portal&_schema=PORTAL


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Introduction

Tips for Using This DocumentThis document contains seven main categories:

• Table of Contents• Introduction• General Casing and Liner Operations: Provides recommendations for cas-

ing and liner design, planning, and running• Liner Hanger Assemblies: Contains information about liner hangers, liner

top packers, liner tieback sleeves, and running tools• Casing Accessories: Provides recommendations for the selection and

application of centralizers, float equipment, wiper plugs, and autofill equipment

• Engineering and Field Planning Summary: Provides information that should be considered in engineering, contingency, and field planning pro-cedures

• Pipe Handling: Contains additional information on pipe/casing handling

RemindersIn many of the sections, you will find white text in the blue column at the left of the page, topped with an orange bar. These comments are emphasized to indicate their importance in the success of the job.

Time-Saving NavigationThis document is easily navigated from either the Table of Contents or the colored tabs located at the right side of every page.

Table of ContentsThe Table of Contents allows you to view the subtopics discussed within each major section. To navigate to a particular topic, just click on the entry.

Colored TabsThe blue and orange tabs at the right of each page offer quick navigation to any major section of the document, including the Table of Contents, from any page in the document.

Where Am I?The title of the section you are viewing is always located in the upper right corner of the page, in the same color as its corresponding tab.

General Casing and Liner Operations



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General Casing and Liner OperationsThis section provides recommendations for casing and liner equipment design and procurement. Risks, design considerations, and typical problems are also provided.

Risk Identification and ProceduresOne of the most important aspects of casing, liner, and cementing operations is identifying objectives and risks for a particular job, and then selecting equipment and procedures to mitigate the risks while achieving the goals. Choices and decisions are made every day that involve both risk and reward. Every aspect of Unocal’s business has trade-offs and consequences. Seldom are there rewards without a trade-off either in additional dollars spent, more complicated equipment, longer drill-out times, or additional time needed to execute a plan.

A key to successful casing, liner running, and cementing operations is advance identification of the job goals, objectives, and risks, as well as a pro-cedure and selection of equipment that provides the best chance of success. Hardly ever are there two well conditions with the same circumstances—one generic procedure is not sufficient for Unocal operations. Job and well vari-ables are constantly changing, including operational costs, hole cleaning, hydraulics, fracture gradients, percentage of openhole annular volume rela-tive to displacement volume, presence or absence of pay, hole clearance, and a whole host of other possible parameters. In general, no two wells will have the same circumstances and thus, each should be unique enough to justify a site separate procedure to enhance the chance of success.

Quality ControlQuality is crucial to success in every aspect of a casing or liner running job. Quality must be included in all aspects of a job including the condition and selection of mechanical equipment, the risk analysis of conditions and equip-ment chosen for a particular operation, the specific procedures used, and the effective communication of specific wellbore conditions and goals. Failure in any of these aspects can result in overall job failure even though most aspects of a job may be successful. Success is realized for casing and liner operations when all of these aspects are well thought out and incorporated into the job plan. Most often, the issues that are well thought out and managed during an operation do not pose a problem; problems usually result from those aspects of a job that were not identified or considered.

A key to successful operations is the identification of goals, objectives, and risks. A well planned procedure and proper selection of equipment will provide the best chance of success.




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Casing DesignVarious factors can impact casing design such as environment, load, well work, and geology. Often, the highest induced load cases to consider for design are those associated with intentional well work operations such as hydraulic fracturing and should not be overlooked. Geologic considerations such as flowing plastic salt stringers must also be incorporated in the risk analysis of material selection. Salt at elevated temperatures acts as a fluid at overburden pressure. For these instances, the casing collapse rating must be designed to exceed the overburden pressure at depth. The casing must also be designed either to withstand the annular pressure build-up due to the tempera-ture increase of production operations, or the well pressure system must be managed during production operations to mitigate this risk to the wellbore.

Tubing Material SelectionIt is important to understand as much as possible about the life of a wellbore in order to effectively design the tubing and casing for a given well. The well's design must account for any corrosion, erosion, sulfide stress cracking, or chloride stress cracking for the life of the well. Chloride stress cracking will usually only occur as a result of a planned wellbore intervention opera-tion such as acidizing.

When selecting casing grade and metallurgy, the life of the well must be con-sidered, especially for tubular strings exposed to production fluids in high temperature environments containing corrosive components. For a well with small reserves and a short life, it may be acceptable to run carbon steel tubing and accept 10 mils of wall loss per year. In contrast, for a well with very large reserves and a long life, it would probably be appropriate to use corrosion resistant alloys (CRA), which would mitigate corrosion concerns and enable the well to be exposed to corrosive production fluids.

A vast array of materials is available with specifications to meet the design requirements for the working environment throughout the entire service life of the well. Design requirements for tubing materials will vary and should always be based on the expected length of the life of the well and corrosion resulting from temperature and production fluids composition. There are many industry-related sites and literature from casing manufacturers provid-ing suitable material based on various partial pressures of CO2, H2S, and free sulfur.

Use industry best practices and API recommended practices for selection, manufacturing, and inspection of tubular goods.

Consider the life of the well when selecting casing grade and metallurgy.




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ConnectionsCasing and liner connections must meet the minimum job requirements for the application. The torque rating of the connections must be greater than the torque created during field execution if a liner is to be rotated. Be aware of all connections and torque ratings in the liner hanger/packer assembly. All thread compounds used should also meet the manufacturer's recommendations.

Include a connection specification sheet with make-up procedures and torque values in the drilling program for quick reference by the Unocal Drill Site Manager (DSM).

Casing Slip/Casing Compatibility and DesignCasing slips must be compatible with the actual casing outside diameter (OD) that is to be run. Casing can be manufactured 1% over the specified OD and still be within API allowances. For example, 9 5/8-in. (9.625-in.) casing can actually be 9.72-in. OD and still meet API specifications. If a standard designed 9 5/8-in. casing slip is utilized with the larger OD casing, the taper on the bowl would allow only 2/3 of the slip segment to enter the bowl before taking weight during the hanging off process. In this circumstance, the com-pression load exerted on the casing by the slips is significantly increased. This scenario can cause casing collapse. To prevent this situation, caliper the cas-ing and size the casing slips accordingly.

The design of casing, casing slips, and wellhead equipment must include the hanging load of the casing as well as all additional loads that may be applied. Substantial additional loads may be placed on the surface equipment and cas-ing by hanging off drill pipe on storm packers and/or pressure testing above packers set in the casing string. Normally, emergency slips used with mandrel hanger systems have limited ratings that must be evaluated for all subsequent operations once they have been installed. An emergency slip fully rated to the full casing capacity should be obtained during the procurement process.

Dog Legs, Hole Diameter, Annular Clearance, and DeviationDog legs, hole diameter, annular clearance, and deviation are important vari-ables in a well and must be considered and managed to get the casing to the bottom. Dog legs can significantly impact all of the following aspects of drill-ing operations: getting casing strings down, wear on the casing resulting from a dogleg, fatigue of the drill string when drilling below a dogleg, and increased torque and drag.

Casing can be manufactured 1% over the specified OD and still be within API allowances.




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In these conditions, it is important to use a bottomhole assembly with a geom-etry that has a stiffness greater than the casing to be run into the hole. The maintenance and control of hole angle and dog legs in the upper portion of a well is extremely important to risk management and well planning.

Buckling Due to Temperature Effects While DrillingFor wells with intermediate casing strings, it is important to mitigate buckling of the casing and its resulting excessive casing wear. As the well is drilled to deeper depths at higher temperatures, the thermal effects of the well can cause buckling of the casing in an uncemented section of the well. To prevent exces-sive casing wear from this effect, apply additional tension in the casing to offset the forces created by the temperature effect.

• To prevent temperature-induced buckling, apply additional tension after running and cementing by pulling on the casing in excess of its weight before setting the slips.

• In situations in which it is not possible to pull enough tension in the casing above the freeze point to prevent buckling, the recommendation is to bring the top of cement higher.

• Applying additional tension by bumping the plug and holding internal pressure on the casing while the cement is setting should be considered after all other options have been explored.

Shoe Track LengthThe shoe track length is a very important element of well design to help man-age cement slurry contamination during cementing operations. Care must be given to depth, number of wiper plugs planned, and hole and mud conditions to determine shoe track length. Use the following method to determine the appropriate shoe track length:

Required Shoe Track Length (ft) = “Total” Displacement Volume (bbl) x 0.01315/Casing Capacity (bbl/ft)

Divide this number by the average joint length. Based on local experience, wiper plug systems, and other conditions, evaluate the calculated requirement and round up or down the number of joints as appropriate.

Refer to Unocal’s Global Best Practices for Cementing document for addi-tional methods and recommendations for determining the appropriate shoe track length.

Be aware that high temperatures may cause tubular buckling if tension is not applied to the casing.




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Wiper Plug Planning and SelectionWiper plugs are necessary for successful cementing operations. Proper plan-ning and selection are critical to managing the risks of running wiper plug systems. For additional information on this subject, refer to the Global Best Practices for Cementing document.

• Evaluate the mechanical and pressure release devices for the wiper plugs to prevent unplanned release or the inability to release the wiper plugs as planned. Pressures to shear a pin or release a collet are often non-exacting; this potential for variability must be taken into account when planning and selecting wiper plug and hydraulic liner hanger systems.

• If multiple liner equipment vendors are employed, it is imperative that the Unocal Drilling Engineer coordinating the operation ensures that good communication exists between all parties and that equipment compatibil-ity issues are addressed.

• On deep wells, it is common to use two or maybe even three drillpipe sizes. Provide the work string sizes to the vendor to ensure the selection of proper darts.

• On casing/liner jobs, follow the liner/float equipment vendor's recommen-dations for making up and running wiper plug systems to prevent damage to the assembly.

• The drillpipe wiper dart's nose must pass through the smallest restriction in the work string and running tool assembly, yet wipe the drill pipe in the largest drillpipe ID. When necessary, all vendors need to confirm work string sizes in order to select the proper drillpipe wiper darts.

• If possible, use a common size drillpipe as a running string for liners.

• Plugs for running tools should be assembled before they are shipped to location. To protect the plug, cover the plug assembly with a liner pup joint. A Unocal Drilling Engineer should be present to witness the assem-bly makeup.

• On casing/liner jobs, follow the liner/float equipment vendor’s recom-mendations on making up and running wiper plug systems to prevent damage to the well.

• A detailed wiper dart/plug release procedure should be prepared and reviewed prior to each job.

• It is advisable that the Unocal DSM witness the loading and release of wiper darts/plugs during job execution.

• For operations in which reducing drill out times are critical to cost struc-ture and where PDC bits will be used to drill out, use wiper plugs that are PDC drillable and have an anti-rotation feature.

The Unocal Drilling Engineer must ensure that good communication exists between all parties and that equipment compatibility issues are addressed.




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Autofill EquipmentThe use of autofill equipment provides valuable benefits to casing and liner running operations by allowing for faster running speeds, saving time to fill the casing as it is run, reducing surge pressures on the well, and reducing loss of returns.

To ensure proper use of autofill equipment, adhere to the following recom-mendations:

• Conventional ball-activated autofill equipment has a low-flow entry area which may lead to solids buildup and plugging. When available, use large-bore ball activated autofill equipment to eliminate this problem.

• Employ autofill float equipment that can be activated independent of the setting of the liner hanger should a well control condition arise while run-ning in hole.

• Evaluate the risk before running mechanically activated autofill equip-ment that requires a ball to be dropped to convert it to non-autofill mode. A preferred option is to run the casing with the ball in place such that the system functions as “flow activated.”

• Evaluate operations and specify the appropriate setting pressure when using pressure-activated autofill equipment. Setting pressure can vary greatly depending on the application. Deactivation of autofill equipment is not an exact value and should be evaluated.

• Consider using differential-fill float equipment when there is a need for autofill equipment that is designed to maintain a set pressure differential between the casing and annulus. Typically this is 90% of the annulus pres-sure.

• If surge pressure is a concern, consider using a ball-converted ported sub (liner bypass tool) that has ports to allow fluid to enter the casing above the float equipment and reduces surge pressure. When run in combination with a large cross sectional area of the autofill, the bypass tool can signif-icantly reduce the downhole effects of surge.

• The Unocal Drilling Engineer should provide specification sheets and operating parameters of all autofill components to all parties including the liner vendor, float equipment vendor, and Unocal DSM.

Ball-in-place autofill equipment should be sized so that it activates at high flow rates to prevent the float from tripping prematurely.




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Inner StringIf you are running an inner string while a cement placement technique is decided upon, consider the following:

• Additional time is required to run and pull an inner string.

• The total hook load for the casing and inner string must be known to ensure that the hoisting equipment has sufficient capacity.

• The landing and wellhead running string must have the capacity to handle the full weight of casing.

• Stab-in seal assemblies, if applicable, must be fit-for-purpose.

• Use screw-in, stab-in equipment to run and land casing with the drill pipe. Landing casing with this type of equipment allows mandrel hangers to pass through surface restrictions easier since the casing at the top is free to have lateral motion through surface restrictions.

• Check wellhead assemblies for pressure integrity and mechanical reliabil-ity prior to job execution.

• Every effort should be made to ensure that the casing is full to the well-head with the designed fluid before beginning the cement job.

Before beginning the inner string cement job, ensure that the casing is full to the wellhead with the designed fluid.

Liner Hanger AssembliesTable ofC

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Liner Hanger AssembliesThe strength of the hanger and the material of the running tool must be con-sidered. It is not uncommon for the liner length to be determined by the load rating of the liner running tool or the hanging capacity of the liner hanger.

Liner HangersThe liner hanger design and installation procedures must meet all the objec-tives for the total life of the well. A ported hanger body is an example of a liner hanger design in which the entire life of the well must be considered. A hydraulic hanger has a port hole designed in the body for activating the hanger. This port hole in the hanger body is isolated by elastomers which, with time and exposure to downhole conditions, will deteriorate and possibly leak.

• Liner hangers can be hydraulically or mechanically set. Hydraulically set hangers are preferred because they are more reliable; however, it must be taken into account that the pressure ratings are lower.

• The top of the liner hanger setting depth should be spaced out in base pipe (not across a coupling) above the previous casing shoe track.

• For certain size assemblies, an integral liner hanger/packer assembly is available. These tools are shorter than conventional tools and can provide a higher differential pressure rating.

• All applicable pre-job information should be documented between the Unocal Drilling Engineer and liner hanger vendor. Any revised data based on actual conditions must be highlighted and communicated to the rig site.

Pressure LimitationsThe collapse and burst ratings of most liner hanger systems larger than 7 in. are lower than the liner itself. Consider the burst and collapse pressure ratings of the hanger and tieback sleeve that may be run on a given well in the early phase of initial well design.

• The setting pressure of the hydraulic liner hanger must be sized or pinned within an appropriate range in accordance with other pressure dependent tools and operations, so that the liner hanger can be set when planned.

• The liner hanger company should provide (on location) a calculation pro-gram for pressure ratings based on actual conditions.

• Perform a thorough review of ball dropping and ball sizing procedures on every job.

Consider the burst and collapse pressure ratings of the hanger and tieback sleeve in the early phases of the initial well design.

Liner Hanger AssembliesTable ofC

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Introduction

• Consider the strategy and conditions for setting liner hangers by bumping plugs in lieu of using setting balls and landing collar.

Liner Top PackersLiner top packers can be quickly set to provide liner top isolation once cementing operations are complete. Careful consideration should be given to isolation on production liners with long lifespan requirements because they may leak or degrade over time.

The liner top packer test pressure should be greater than or equal to the planned leak-off test/formation integrity test after drilling out.

Liner Tieback SleeveThe length of a liner tieback sleeve and stem should be carefully selected when running and cementing a tieback string of casing.

• It is a good practice to design the tieback system to avoid pulling the tie-back stem all the way out of the tieback sleeve in order to circulate the cement around the tieback string of casing.

• The length of the tieback sleeve must be compatible with the seal assem-bly being run and the length and number of seals required for the life of the well.

• If the tieback is not being cemented, a “tube move” program must be run to determine the length and number of seals for the life of the well.

• It is advisable to also use tieback sleeves in the event a liner top packer does not set. Then, a second packer with a seal assembly can be run.

Running Tool SelectionIn general, the simplest and most reliable running tool for a liner system should be used, but it must have the necessary features required for the appli-cation.

• When using liner hangers, you must consider specific running conditions requiring special features such as the need to rotate the liner (either while running in the hole or cementing), right-hand release, and wellbore condi-tions.

• If the liner needs to be rotated, a rotatable liner running tool must be used.

• In some well applications, it is necessary to have the ability to rotate the casing. To accomplish this, a running tool must be able to lock into a pro-file in the top of the liner to provide a means to apply torque and rotate the liner without exceeding the makeup torque of each component.

When using liner hangers, consider specific running conditions requiring special features such as the need to rotate the liner, right-hand release, and wellbore conditions.

Casing Accessories



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Casing AccessoriesThis section provides recommendations for the selection and application of centralizers, guide shoes, and float equipment. Use equipment from reputable vendors, and before procuring any equipment of unproven performance, inspect quality and fit-for-purpose design, accessing technical resources as necessary.

Centralizer Planning and SelectionIt is important to select a type of centralizer specific to the application that provides effective centralization, mitigates any problems in the running of casing, and is cost effective. Numerous types of centralizers are available including bow spring, rigid, solid body, and integral. Each design has its own advantages and disadvantages depending upon the intended application.

• Run a centralizer calculation program to accurately determine the number and placement of centralizers necessary to achieve the recommended standoff once actual well deviation surveys are input. For liner jobs in which cement is to be brought into the lap, it is advisable to include cen-tralizers in the lap area to aid the placement of cement uniformly around the casing perimeter.

• Prevent damage of centralizers when running through existing liner tops or downhole components such as wellhead housings by assessing job risks and choosing the appropriate type of centralizer.

• Pre-install stop collars and centralizers prior to running casing when pos-sible.

• Avoid using fixed-end (held by set screws on the end ring), bow-spring centralizers.

• In general, do not use any of the slip-on type centralizers on flush joint casing with stop collars since they have a tendency to “stack.”

Carefully select centralizers for specific well conditions and fit-for-purpose applications.

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Bow-Spring CentralizersBow-spring centralizers are designed for over-gauge holes; however, they can be used in other hole conditions to provide effective centralization. Bow-spring centralizers compensate for over gauge, open hole sections with flexi-ble bows designed to have an outside diameter slightly larger than bit size.

• Refer to API specifications for running and restoring forces when eval-uating and selecting bow-spring centralizers.

• Bow-spring centralizers may be used in high-angle holes; however, other types of centralizers may be more appropriate.

• It is always best to place bow-spring and rigid centralizers over collars or stop rings so that they are pulled into the well or pulled from the well to prevent them from collapsing upon themselves.

• Limit pipe movement to reciprocation since rotation is likely to damage the bow springs.

• Physical dimensional checks should be made to confirm that centralizers will fit over collars.

Rigid Centralizers• Inside previous casing strings or open hole sections that are in gauge,

rigid centralizers provide adequate centralization.

• This type of centralizer with non-flexible bows should be run with an out-side diameter slightly smaller than the smallest diameter in the well (the OD must be checked to ensure that they will not collapse).

• Double bow-spring centralizers are classified as rigid centralizers. The benefit of this type of centralizer is that it has some flexibility, which allows it to pass through tight spots or dog legs.

• It is always best to place rigid centralizers over collars or stop rings so that they are pulled into the well or pulled from the well to prevent them from collapsing upon themselves.

Solid Body Centralizers• Solid body centralizers are used when the wellbore is highly deviated,

horizontal, or when the annular space is very limited.

• This type of centralizer is most conducive to pipe movement, especially rotation, since it provides an effective bearing support for the casing, lim-its contact with the wellbore, and has less running force than pipe alone.

• Stand-off, which can be achieved using this type of centralizer, is limited to its outside diameter. When used in any wellbore greater than gauge,

Place bow-spring and rigid centralizers over collars or stop rings so that they are pulled into the well or pulled from the well to prevent them from collapsing upon themselves.

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optimal centralization may not be achieved, and therefore pipe movement is recommended when using solid body centralizers.

• To aid in situations requiring the casing to be worked down, use spiral blade, solid body centralizers.

Bow-Spring Centralizer SubsTight clearances and holes drilled with bi-center bits may require the use of bow-spring centralizer subs. The bow spring collapses to the pipe OD if nec-essary, allowing the casing to run freely in the well. The upsets on the central-izer sub pull the centralizer bow into the well and out of the well as the casing is run, preventing it from collapsing on itself.

Quick Reference for Centralizer Selection and Installa-tion

Application Centralizer InstallationSurface, intermediate, or long string casing. Typical API sizes like 13 3/8-in. casing in a 17 1/2-in. hole or 9 5/8-in. casing in a 12 1/4-in. hole, where the actual size is over gauge.

Bow-Spring Centralizer Hinged Type

Install over casing couplings. If there is tight clearance or more than one per joint, install over stop rings.

Low risk and low-cost applications such as in liner laps.

Bow-Spring Centralizer Slip-On Type

Install over stop ring, placing just above couplings to minimize damage.

Inside previous casing with normal clearances (9 5/8-in. casing in a 13 3/8-in. casing).

Rigid Centralizer Install over casing couplings in larger diameter casing and over stop ring in lower clearance conditions.

Where clearance prevents standard bow or rigid centralizers from being used, i.e., 11 3/4-in. liner in 13 3/8-in. casing, and in flush joint casing applications that require the mitigation of centralizer “stacking.”

Integral Centralizer Sub Place across shoe track and any critical points.

High angle sections, especially for larger casing sizes, and for applications in which it is difficult to get casing to bottom.

Solid Body Centralizer Install between coupling and stop collar.

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Examples of Centralizer Types

* Centralizers with set screws on the bottom band are not recommended because if you pull up on the casing and the upper band contacts a ledge or previous casing, it can compress or collapse and dam-age the centralizer.

Solid Body Centralizer(spiral blades, free floating)

Solid Body Centralizer(spiral blades, set screwed)

Low Torque Centralizer

Bow-Spring Centralizer(hinged type)

Bow-Spring Centralizer (slip-on type, fixed end)

Not Recommended *

Bow-Spring Centralizer (double bow)

Rigid Centralizer (slip-on type)

Not Recommended *

Integral Centralizer Sub Solid Body Centralizer(straight blades)

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Guide Shoes and Float Equipment Planning and SelectionGuide shoes and float equipment are necessary to guide the casing to depth, reinforce the lower end of the casing, hold cement in place, and prevent con-tamination of the cement at the shoe. Planning and selection of these devices is critical to ensure that the appropriate system is used and that it is fit-for-purpose. Depending on the specific casing size and type of operation, these systems will range from a simple guide shoe with float collar, to a stab-in type system, to a double-valve float shoe and float collar with anti-rotation design.

• Use float devices (a float shoe or float collar) to prevent the u-tubing of the cement back into the casing when displacement is completed and hydrostatic pressure of the annular fluids exceeds the hydrostatic pressure of the displacement fluids.

• Float shoes are preferred as the primary back flow prevention valve when cement displacement is completed.

• An eccentric nose design on the float or guide shoe can aid navigating ledges or other downhole obstructions.

• Reamer shoes should be considered in high-angle holes or if ledges are present or anticipated.

• It is generally best to use guide shoes or float shoes with side ports to pre-vent the assembly from being plugged should the casing stick on bottom or if a liner hanger fails.

• It is recommended to have a minimum of two float valves in a string.

• If you are using a float shoe and a float collar, the float collar acts as a backup and a landing point for the plug, and provides a shoe track to cap-ture contaminated cement.

• For inner string applications, float collars should be chosen to accept either stab-in or screw-in inner string adapters.

• Orifices in the guide and float equipment must be sufficiently large if it is necessary to pass tripping balls, orifice tubes, and debris out of the casing.

It is recommended that there be a minimum of two float valves in a string.

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Quick Reference for Guide Shoe and Float Equipment Selection

Application EquipmentOperations in which a double-valve float collar is to be used to provide a shoe track.

Guide Shoe

For holes with restriction or ledges. Reamer ShoeFor applications in which single-valve float shoes are run.

Single-Valve Float Collar

For application in which a single-valve float collar is run.

Single-Valve Float Shoe

For low cement-in-place differentials or if casing can be shut-in if floats do not hold. When there is a concern of casing becoming hydraulically locked.

Single-Valve Float Shoe with side jets

For quicker drill-out times. Anti-Plug Rotation FeatureFor applications with high differentials or liners in which additional mitigation is desired to prevent flowback after cement displacement or when guide shoes are run.

Double-Valve Float Collar

In tight clearance hole conditions in which there is a low risk of having a well control incident. In deepwater when the casing can be picked up before entering the stack, and on shelf when there is a very low risk of the well flowing when picking up the casing.

Autofill Float Collar with ball in place and no bypass ports. It requires pumping to activate floats.

When running autofill float collar with ball in place and the ability to pump while picking up casing and liner equipment without activating the floats is needed.

Autofill Float Collar with bypass ports with high flow conversion rates

When running tieback string and need to sting seal into receptacle without becoming hydraulically locked with floats in the string and need ability to bleed back to sting into the receptacle.

Orifice Float Collar

In large diameter casing strings (i.e., 16-in. and larger casing strings). Casing run and hung conventionally.

Stab-In Float Collar

When using stab-in float collars and also to land casing via threads in the top of the float collar on screw-in versions.

Screw-In/Stab-In Adapter

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Examples of Casing AccessoriesRefer to the Global Best Practices for Cementing document for additional information on these casing accessories.

In large diameter casing strings (i.e., 16-in. and larger), or casing strings when casing is to be run on drill pipe.

Screw-In/Stab-In Float Collar

In tight clearance conditions and when running casing or liner with premium threads, or to avoid having to order both a float shoe and an integral centralizer sub with premium threads.

Combination Float Collar/Bow-Spring Centralizer

Application Equipment

Guide Shoe Reamer Shoe Float Collar (single valve)

Float Shoe (single valve)

Float Shoe(single valve

with side jets)

Float Shoe(double valve with side jets)

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Float Collar (double valve, anti-

rotation profile, pump to activate)

Autofill Float Collar (no bypass

ports)

Autofill Float Collar (ball in place, with bypass ports)

Ball Seated (high flow

conversion rates)

Pressure and Conversion

Converted

Orifice Collar Float Collar(stab-in with

latch-in wiper)

Float Collar (stab-in/screw-in)

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Float Shoe(stab-in, double

valve)

Stab-In Stinger Screw-In Stinger

Comb. Float Shoe(in-line centralizer)

Comb. Float Shoe(in-line centralizer,

anti-rotation profile)

Bottom Wiper Plug

Top Wiper Plug

Top and Bottom Wiper Plugs

(anti-rotation profile)

Liner Hanger Plug Set

Engineering and Field Planning SummaryTable ofC

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Introduction

Engineering and Field Planning SummaryThe following information is provided to assist the engineer or DSM in the thought processes that are involved in engineering and field planning proce-dures and should be used as examples of the types of things that should be considered in job planning. This list is not comprehensive; engineering and field plans should include information that is applicable to the specific situa-tion.

Engineering Planning• Ensure that liner hangers and the liner/casing running tools are designed

for the combined loads of liner weight, mud weight differential, and pres-sure tests.

• Determine from torque and drag modeling whether rotation may be required to get the liner to bottom.

• In choosing a setting pressure on the liner hanger, determine whether dif-ferential pressures could be created during execution that could accidentally set the liner hanger.

• The liner hanger systems should be designed with a tieback sleeve length allowing the bottom of the tieback stem to be partially stung into the tie-back sleeve when cementing the tieback casing.

• For liners on directional wells with relatively high torque and drag, estab-lish a way to determine, using pressure, if the liner has been released from the running tool.

• Determine if the spotting of heavy mud/loss circulation material on bot-tom prior to pulling out of hole to run the liner will affect the setting pres-sures of the liner hanger and liner top packer.

• If multiple vendors are employed, it is imperative that the Unocal Drilling Engineer coordinating the operation ensures that good communication exists between all parties and that equipment compatibility issues are addressed.

• Determine if heavy weight drill pipe is needed in the running string based on torque and drag modeling.

• Drillpipe wiper darts and balls must be able to pass through HWDP.

• Determine if non-rotating wiper plugs should be utilized for the liner/cas-ing application.

If multiple vendors are employed, the Unocal Drilling Engineer must ensure that good communication exists between all parties and that equipment compatibility issues are addressed.


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Introduction

• Ensure that wiper plugs and float equipment are PDC drillable, if PDC bits are to be used.

• Assess hole conditions for the applicability of autofill equipment.

• Ball-in-place autofill equipment should be sized so that it activates at high flow rates to prevent the float from tripping prematurely.

• Conventional ball-activated autofill equipment has a low flow entry area, which may lead to solids buildup and plugging. When available, use large-bore, ball activated autofill equipment to eliminate this problem.

• In wellbores with severe dog legs, consider the use of a specialized guide shoe to guide the bottom off of any ledges encountered.

• The float or guide shoe should have side ports to prevent it from becom-ing plugged.

• A minimum of two floats is recommended.

• Determine if float equipment is to be installed on shore or at the rig site.

• Determine if backup float equipment is needed.

• Determine whether a Unocal representative needs to witness the assembly and inspection of equipment for quality control purposes prior to ship-ment.

• Determine if centralizers will be run in the liner lap if cement is to be brought into the liner lap.

• The design of the centralizers should prevent stacking as the casing is run into the wellbore.

• Determine whether only a preliminary integrity test is required after set-ting the liner top packer (LTP) followed by a full pressure test after the cement sets.

• The LTP test pressure should be greater than or equal to the planned LOT/FIT after drilling out.

• When a pack-off bushing is being used, make sure that an isolated back side test can be performed.

• The packoff bushing and seal assembly length must be long enough and compatible (including safety margin) to allow the required pipe move-ment during operations and to avoid pulling seals out of seal bore.


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Introduction

Contingency PlanningA contingency plan for each of the following circumstances should be dis-cussed in advance of actual job execution as applicable.

• Communication of overall liner execution objectives including

• Getting liner to bottom• Minimizing mud losses• Getting a primary cement job• Releasing the running tool• Getting a test on the backside

• Casing or liner fails to get to required depth

• Severe loss circulation encountered while running or cementing

• Premature or failed release of drill pipe or liner wiper plugs

• Wiper plug does not bump

• Float equipment failure

• Hydraulic liner hanger does not set

• Liner top packer fails to hold required pressure

Field Planning• Ensure that adequate communication of critical issues has been performed

between major vendors, Unocal employees, and rig crews.

• Ensure that the procedure is detailed enough and understood for success-ful job executions including contingencies.

• Determine the maximum over pull on the drill pipe and liner that can be performed based on actual well conditions.

• Ensure that the drill pipe has been rabbited or gauged for the largest drill plug wiper dart dimension to be pumped.

• Understand the setting pressure on a hydraulic hanger.

• Understand the consequences of swab/surge parameters based on a well-bore’s geometry, mud properties, and planned running speeds to verify acceptable conditions.

• Calculate liner running speeds and surge pressures.

• Determine how many joints can be run without filling and not exceeding defined pressure differentials.

A contingency plan for possible well circumstances should be discussed before the job.

Ensure that adequate communication of critical issues has been performed between major vendors, Unocal employees, and rig crews.


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Introduction

• Ensure the liner is full before making up the liner tool.

• Determine if circulation will be established at shoe prior to open hole, and how much mud will be circulated.

• Determine if hole conditions or previous losses necessitate a slow pump start-up speed.

• Ensure that sufficient mud is on location for expected losses while run-ning liner, plus the volume required to displace cement without returns.

• Understand the rate and pressure needed to convert autofill float equip-ment.

• Determine when autofill float equipment will be activated if no losses occur.

• Determine in advance key milestone depths based on joint numbers such as the following:

• Where the shoe enters a diameter change• Where the shoe enters the open hole• Where the shoe passes troublesome zones (shales, faults, permeable

interval)• Where the shoe enters or exits high dog legs• Where the liner hanger passes any downhole diameter change• Compare string loads and over pull to rig hoisting capacity and num-

ber of lines strung• Where to change elevators if required

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Pipe HandlingSafe handling of pipe is important to preventing damage to the pipe. The fol-lowing text provides recommendations for safe handling and transport of pipe.

Pre-Run Preparation• Pipe should be ordered and delivered to the location early enough to be

off-loaded in a safe manner, drifted, tallied, and visually inspected off the critical path.

• All items to be run downhole should be dimensionally checked (drifted, OD measured, length measured, etc.) for compatibility with hole diame-ter, downhole or wellhead minimum ID restrictions, and OD of all con-centric tools to be used during the completion process.

• Enough additional joints of pipe should be ordered to allow for joints found to be defective (joints with possible thread damage, joints damaged during the delivery process, or joints which will not drift).

• In some cases, additional couplings, seal rings, and pup joints (if needed for spacing) should also be ordered early enough to be drifted, tallied, and visually inspected.

Vessel-to-Rig Pipe RackTo ensure that casing is handled properly, adhere to the following guidelines:

1. After the vessel transporting the casing is secured alongside the rig, lift the casing from the vessel’s deck to the rig's pipe racks. Ensure that casing protectors are in place.

2. Ensure that the proper slings, hooks, or clamps are used and that each sling is equipped with a tag line. Casing hooks must have a blunt end to prevent them from digging into plastic protectors and damaging the threads. Slings, shackles, and hooks must have current inspection and loading certificates. Ensure that there will be sufficient light and that visi-bility is good when moving tubulars. Ensure that there is clear communi-cation between the rigger and the crane operator.

3. Ensure that slings used are able to handle the expected loads. Refer to the business unit’s lifting procedures/guidelines for additional information.

4. Transfer the casing to the pipe rack and lay the casing out evenly. If possi-ble, have the box end a little bit higher than the pin end to prevent clean-ing fluid residue to accumulate in the box end.

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5. Remove box and pin protectors and drift the casing with the proper size drift for the size casing being used. Discard any joints that do not drift. Mark them and send them back to the warehouse. Ensure that the type of defect is noted on the joint, painted in red, and mentioned in the shipping manifest.

6. Clean threads with a nontoxic solvent, soap, and high-pressure wash gun. Thoroughly dry and inspect threads. Check the location of the white band marking them. The bottom of the white band must be on the bottom of the buttress triangle. Install clean dry protectors or quick-release protectors.

7. Measure and record the first row of casing (measurements from top of box to bottom of triangle on the pin end for buttress thread connection).

8. Prior to adding the second row of casing, put planking down on top of the first row directly above the load bearing areas on the pipe racks to avoid buckling or bending the joints. (Cover pin and box with plastic sheets/tar-paulin to avoid contamination from cleaning upper layers).

Casing Handling from Rig Pipe Rack to Rotary TableTo ensure that the casing is handled properly from the pipe rack to the rotary table, adhere to the following recommendations:

1. Ensure the loads are properly slung and that an experienced rigger is directing the crane operator on the high line.

2. Visually inspect the casing when it is landed in the stopper on the V-Door. Remove any damaged joints.

3. Pick up the casing shoe joint with the main elevator. Position the joint of casing above the rotary table. The first joint will have the float shoe installed (float shoe thread locked onto the pin).

4. Test the float shoe by running it into the well. If it is okay, fill the joint with the fluid being used (fluid should drop until equilibrium is reached). Raise the joint about 15 feet with the blocks and run into the slip area (the joint should have drained).

5. Clean, dry, and thread-lock joints 1 and 2 up to the float collar, or to the estimated top of cement inside the pipe. This will help prevent problems during drill out, including the casing backing off.

6. The remaining boxes of casing joints should be properly doped with rec-ommended API casing dope that complies with API 5A2 requirements and a friction factor of 1.

7. Ensure that proper rotary slips, pick-up, and running elevators are used. Use a safety clamp on the casing in the rotary until the weight of the cas-ing is enough to hold it in place in the slips.

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Making Up and Running Casing—Slip to SlipAlignment is critical in the process of making up the casing. Even small errors in the alignment of tubing and casing during make-up can lead to con-nection damage.

• For premium connections or to avoid seal damage, use a stab-in guide.

• Power and backup tongs are to be properly aligned and with load cell and snub line at 90 degrees to tong. Pre-calibrate torque gauges and check snub lines for proper length. Once the make-up torque has been deter-mined (manufacturer's recommended make-up or base of triangle in the case of buttress thread connection), the dump valve on the power tong should be set at optimum value and compensated for over torque depend-ing on speed of make up. Dump valve settings will be determined by the Unocal DSM.

Proper alignment is critical in the process of making up the casing. Even small errors in the alignment can lead to connection damage.

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Contacts

Lawrence Weber, Consulting Drilling EngineerTel.: (281) 287-5224Fax: (281) 287-5390e-mail: [email protected]

Casing, Liner Running, and Cementing Network

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Central Drilling Group

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Unocal CorporationCentral Drilling Group14141 Southwest FreewaySugar Land, TX 77478 USA

June 2004

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GBP Casing and Liner Running

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