EP_2000-9073_Shell_Casing_and_Tubing_Design_Guide_Vol_1 rev Jan 2008.pdf

Restricted to Shell Personnel Only EP 2000-9073

Shell Casing and Tubing Design Guide

Volume 1

Issued by the Well Engineering Forum

Sponsor: Well Engineering Forum

Date of issue: October 2000

Revision: Revised 15 Jan 2008

Period of work: Through October 2000

ECCN number: EAR99

The information in this document is shared under the Research Agreement between SIRM and Shell Oil Company dated

January 1, 1960, as amended unless indicated otherwise above.

This version supersedes the previous version (EP 92-2000).

This document is classified as Restricted to Shell Personnel Only. 'Shell Personnel' includes all staff with a personal

contract with the Shell Group of Companies, designated Associate Companies and Contractors working on Shell projects

who have signed a confidentiality agreement with a Shell Group Company. Issuance of this document is restricted to staff

employed by the Shell Group of Companies. Neither the whole nor any part of this document may be disclosed to

Non-Shell Personnel without the prior written consent of the copyright owners.

Copyright 2000 SIEP, Inc.

SHELL INTERNATIONAL EXPLORATION AND PRODUCTION INC., HOUSTON

EP 2000-9073 ii Restricted to Shell Personnel Only

Summary

The Shell Casing and Tubing Design Guide presents updated guidelines for the design of

well casing and tubing to all Shell Operating Companies.

The Guide facilitates establishing the right balance between fundamental requirements for

well integrity, the use of best practices and a common design philosophy across Shell and the

need for operating companies to customize designs on the basis of local geological settings

and local experiences as well as the need for innovation in a changing business environment.

Through prudent management of risk, the most effective design over the total lifetime of a

well through to abandonment can be achieved. The layered design practice presented in the

manual allows for prudent adaptation of well designs to the level of maturity of local

knowledge, experience, and competencies.

While these guidelines are based on a common philosophy within the Group, the

responsibility for a specific well design remains within the individual Operating Company.

The updated guide was compiled by a Global Virtual Team consisting of a large number of

experienced Well Engineers, representing most Operating Companies in the Shell Group.

The Well Engineering Forum sponsored the compilation of the manual and has endorsed its

content.

Acknowledgement

This Design Guide is an update built on top of the good earlier editions that have preceded it,

and this release would not have been possible were it not for the good work done by the

authors of earlier editions of the Guide. This release represents the collective work and

contributions from many people, particularly those listed below. It is a collective effort not

authored by any one single person. In addition to contributions by the people listed below,

workshops were held at several Operating Companies in order to capture the needs and best

practices espoused by experienced drilling and production engineers group-wide. As such,

this Guide is a compilation of Shells philosophy, experience, and know-how. This release

brings forth new formalizations of design practices and the Shell design philosophy and

presents new technologies.

EP 2000-9073 iii Restricted to Shell Personnel Only

Keywords

casing design, tubing design, tubulars design, guideline, design philosophy, design level,

design factor, casing seat selection, casing size, tubing size, pipe resistance, burst, burst

resistance,

thin-wall eccentricity, casing wear, pipe toughness, collapse, collapse resistance,

tensile resistance, connection resistance, load (force), friction, frictional drag, pressure test,

annulus pressure, surface pressure, gas-lift well, leak, well shut-in, corroded pipe, tensile

strength, overpull, evacuated tubing, well stimulation, erosion, retrievable packers, axial load,

thermal load, drilling (well), subsea completion, production (well), pull-out, casing running,

pressure gradient, casing connection, tubing connection, pipe connection, well operation,

design software,

quality assurance, keeper well, disposable well, expendable well, connection qualification,

compression, product-line qualification, industry standard, Wellcat, Stresscheck, inspection,

risk, risk assessment, blowout (well), specialty well design, HPHT well, high pressure,

high temperature, cemented tubing, single-barrier well, extended-reach well, horizontal well,

multilateral well, deepwater well, ultra-deepwater well, slim-hole well, injection well,

disposal well, through-salt well, steam injection, permafrost, gravity structure, gas-lift well,

running casing, corrosion, mechanical behavior, setting depth, leak-off test, limit test,

rock mechanics, reservoir compaction, pressure buildup, shallow water flow, expandable

tubulars, buoyancy, buckling, fatigue failure, stress formulas, impact loading, residual stress,

completion accessories, cementing casing, design examples

EP 2000-9073 iv Restricted to Shell Personnel Only

List of Co-Authors and Technical Contributors

to the Design Guide

WEF Focal Point Hans Flikkema

Editor Paul Cernocky

NAM Production Focal Point Nigel Snaith

NAM Drilling Focal Point Rob Reijngoud

EXPRO Focal Point Peter Clarke

SEPCO Focal Point Joe dAgostino

SPDC Focal Point Isaac Iyamu

PDO Focal Point Jules Borm

PDO Focal Point Chris Hopkins

SDS Focal Point Landale Cranfield

BSP Focal Point Mike Ward

WOODSIDE Focal Point Ed Antczak

BAPETCO Focal Point Harrie Krus

Training Focal Point Paul WefersBettink

Drilling Specialist Bob Worrall

Drilling Specialist Jose Solano

Production Specialist Rod Fors

Production Specialist David Stewart

Drilling Specialist Jim Peterson

Materials Specialist Tony Cole

Technology Specialist Paul Paslay

Technology Specialist Andrew Tallin

Production Specialist David Hartgill

Multilateral Specialist Wes Moore

Drilling Specialist John Gradishar

Drilling Specialist Chris Hakulin

Drilling Specialist Ian Park

Production Specialist Mike Konopczynski

Technology Specialist Frans Klever

Connection Specialist Gloria Valigura

Technology Specialist Afif Halal

IT & Media Specialist Mei Choate

Quality Assurance Specialist Randy Mc Gill

Technology Specialist Randy Wagner

Technology Specialist Marc Amory

Technology Specialist Serge Roggeband

EP 2000-9073 v Restricted to Shell Personnel Only

Version Information

Date Version

21 Dec 2000 First version published on sww

02 Jan 2001 Additional load case for production casing added (section 3.7.2)

15 Jan 2008 Chapter 4 revised;

sww URLs updated in chapters 3, 10, and appendices 1-1, 1-9, 3, 25 and 26

EP 2000-9073 1-1 Restricted to Shell Personnel Only


Chapter 1

Shell Design Philosophy

Shell Design Philosophy.............................................................................................................2


1. SHELL DESIGN PHILOSOPHY

Shell wells share the foundation of being designed and constructed based upon historicaloperating experience and a long tradition of operating and producing integrity in many differentparts of the world. This shared philosophy has resulted in Shell being recognized for itscompetency in well design but also being criticized for conservatism and risk aversion in the past.Future wells will be designed and built based upon maintaining this commitment to competencyand integrity, but will use risk-balanced innovation and adaptation to be able to cope with moredemanding well designs in a cost-leadership environment.

The well will be designed around three factors: the needs of the completion to provide optimumproduction over its lifetime; the need for reliable pressure containment over the life of the well;and the cycle time required to put various design options into production. Completionrequirements and production schedules should be defined early and drive both the tubing and thecasing design. Technology should be used aggressively to accommodate the well completioninstead of compromising on the completion design by assuming what can be accommodated basedon past practice. The completion concept forms the basis for the overall well design from theinside out.

The new well design taps into both historical learnings and recent innovations through sharing ofbest practices with global staff having decades of experience through the use of networks such asthe Wells Global Network and training programs. Reliance on historical learnings does not meanthat new designs copy past wells. Instead this means that past learning experiences should be afoundation for the innovation of each new well design. This Design Guide is intended to fosterthe creation of new casing and tubing design opportunities which link to both historical andcontemporary learnings. The latter is to be achieved through a commitment to keeping this Guideevolutionary. Risk assessment will ensure that design integrity is maintained.

The basic design process will still be the same all across Shell. In principle, two Shell engineersworking with the same well conditions in different parts of the world will come up with the samebasic well design. However, in the end, their detailed well designs may differ, taking account ofhistorical learnings, local expertise, and local innovation of the particular operating company.This is the reason that Shell has introduced the layered design process discussed later in theGuide.

The engineer doing casing or tubing design should have awareness of general trends in industrywell design, but the engineer also should keep well abreast of and leverage the innovations andnew learnings being generated by Shell. When new technologies, innovative ideas, or newbusiness conditions demand and enable innovative new well designs, the design of casing andtubing should be taken to the cutting edge at which well and operating integrity can be maintainedthrough prudent management of risk. However, the innovation of casing and tubing designshould not reflect the initiative of an individual engineer; it should reflect the consistentevolution of local design practices within an operating company.


Shell wells must make more rapid use of new and evolving technologies. This is supported bythe large annual investment in technology, and part of the responsibility of the well engineer is tokeep abreast of the new technology and rapidly exploit the technology for the benefit of increasedproduction or reduced cost at managed risk. The aggressive use of new enabling technologyshould not be done at the expense of prudent risk management incorporating historical learnings.Shell will innovate faster than its competition, but will use prudent risk management to do this.The Guide can be used to help rationalize changes in design practice specific to the conditions oflocal operating companies. The casing and tubing should be designed to provide well integrityand innovation at the lowest possible cost while always managing risk. Risk should not beavoided in an absolute sense, but instead risk should be managed by evaluating the likelihood ofevents occurring, the likely consequences, and their impact over the total lifetime of a well.

Risk management should include both the risks to well control over pressures and fluids and therisks to competitive cost and position. Design changes should evolve either by taking a series ofincremental evolutionary steps linked by well successes, or by taking large leaps forward with theguidance of a risk assessment and hazard evaluation that supports the large step change. Everylarge change in well design should be accompanied by a risk assessment that is documented bythe engineer. This risk assessment can be either qualitative or quantitative. The risk assessmentcould entail a comprehensive study, but it also could involve just the engineer making anddocumenting (1) a subjective evaluation of the likelihood that events will happen; (2) thelikelihood that particular consequences will occur; and (3) the acceptability of this combination oflikely events and consequences. Shell wells therefore must be designed with the documentedmanagement of risks, not with the avoidance of risks.

Casing and tubing design should be done as a marriage between design concepts and operatingskills. This is one reason that Shell has introduced tiers for design practice. The basic design caserepresents the most conservative option for design possibilities and for control of the well.Designs with higher but still prudent risk represent the next tiers up in well design. These higher-risk designs are desirable for their benefit to well efficiency, and these should be implemented onan OU level. However, they should only be implemented when risk assessment indicates thatadequate controls are in place to manage safety and maintain well integrity; and only when thehighest well control skills are in place to manage the higher-risk well.

Where innovative design leads to the use of new equipment, part of the risk assessment should beto consider the value brought by the new equipment, the likely start-up performance of the newequipment, and the likely consequences of unforeseen issues with the new equipment. Newequipment should be used when the risk assessment suggests that the risk is acceptable in light ofthe added value.

A Shell well should be a quality design and should use quality equipment in order to make thedesign both optimized and fit for its purpose. Shell has a commitment to quality in well designand equipment, because the risks of an innovative well design can be managed only through aquality process. Quality does not necessarily mean use of the most expensive equipment. Instead,quality means use of the right equipment for the application. Quality in the well design may bebased on historical experience with equipment (that is, field-proven or grandfathered equipment),or quality may be based on testing a design concept and qualifying the equipment for the service.For either of these approaches, the equipment must be shown to be fit for the application.


Like pipe and connections, Shell also provides quality stress analysis through the use of designsoftware to Shell standards. Delivery of the quality well is achieved partly through the Shell useof design software. The well design will be based on triaxial stress design and use of the samesoftware shared by all operating companies across Shell. Software expertise is one of the keycore competencies of Shell engineers. Shell uses its historical experience and large number ofwells drilled annually to share design best practices among different operating companies. Thecommonality of design software is one of the vehicles for this sharing of best practices.

Shell operating companies take responsibility for ownership of the tubing and casing design. Thetubulars design is not contracted out to third parties. Where support calculations are provided bycontractors, the work is supervised and owned by Shell engineers. This is done because of theimpact that tubulars design has on lifetime well reliability, cost, risk, and delivery. This approachis part of what makes the well a Shell well.

Tubing design should seek to maximize through-tubing accessibility to the reservoir. Industry-wide emphasis on lifecycle cost saving has raised awareness of the benefits of performingoperations such as perforation optimization, production logging, selective stimulation, zonalabandonment, and improved wellbore clean-out at reservoir level through the tubing. For fullflexibility and increased reliability in these operations, it is important not to inhibit the passageand operation of the tools involved. This requires the elimination of unnecessary restrictions inwell completions, i.e., maximizing the completion through-bore, together with a suitable matchingof the tubing and production liner sizes in cases where tiebacks are not used. A directconsequence of this is the desire for simplified well completions. The completion shouldemphasize overall life cycle production optimization, operational simplicity with respect to wellmonitoring, well servicing, and future workover requirements.



Chapter 2

Shell Levels of Casing and Tubing Design Practice

2. SHELL LEVELS OF CASING AND TUBING DESIGN PRACTICE ...............................2

2.1 Specifics of the Design Levels.......................................................................................22.1.1 Level One ................................................................................................................22.1.2 Level Two................................................................................................................32.1.3 Level Three..............................................................................................................4

2.2 How to Change Design Practice from Level One to Level Two or LevelThree ........................................................................................................................5

2.3 Limitations on Export of Level Two and Level Three Design Practices ......................5

2.4 Examples of Level Two and Level Three Designs........................................................6


2. SHELL LEVELS OF CASING AND TUBING DESIGN PRACTICE

This design guide makes the distinction of three different levels of casing and tubing designpractice within the Shell operating companies. Each Shell operating company has its owngovernance over which level or combination of levels of design practice it chooses to use. Theload paradigms and design factors of Level One design practice are the same for all the operatingcompanies, but the specific details of the Level Two and Level Three design practices can bedifferent for the different operating companies. The three levels come about because ofdifferences in

The amount of conservatism in the design The functional specifications for the design The level of staff experience and competency needed to carry out the design The sophistication of rig kick-detection equipment used to drill the well The amount of experience applying the design to a particular type of reservoir The speed of innovation and amount of step change from traditional design practice

2.1 Specifics of the Design Levels2.1.1 Level OneThe first, most basic, and most conservative design practice is called Level One. Thecharacteristics of this design practice are:

It is the default design practice described in Chapter 3. It is based on the most conservative design premises about kick burst pressures and collapse

evacuation depths.

It assumes that the engineering staff have basic competency with design principles,knowledge of the Level One Shell load cases, and understanding of the use of the Shell designsoftware.

It does not assume that the engineering staff have extensive understanding of the historicalwell design practices and well control experiences characteristic of the local operatingcompany.

It makes no assumptions about the competency of the operating staff to respond with bestpractices during well control events.

It makes no prerequisite for the sophistication of the geological data used to design the well.It is broadly applicable to any geological well conditions including unknown conditions.

It is well suited to new ventures and wildcat exploratory wells. It seeks to avoid risk wherever possible. Level One requires two production barriers: a tubing and a production casing. It requires the use of quality pipe and connections. It uses a conservative triaxial burst design factor. It makes no assumption about the quality of rig kick-detection systems (KDS).


All non-production casing strings are designed for kicks taking full evacuation to gas. Long-term pressures inside and outside the casing for burst and collapse design are based on

the most conservative possible combinations of fluid pressure gradients. In burst design, thepressure gradient from mud and cement outside the casing is assumed to revert to the basedensity of the mud and the mixwater density of the cement. In collapse design, the pressuregradient from mud and cement is assumed to be the initial mud and cement gradients.

2.1.2 Level TwoLevel Two design practice has the following characteristics: Level Two is experience based. It represents the operating companys specialization of casing

and tubing design practices based on its own local experiences in particular types of reservoirformations.

It requires the operating companys formal documentation of the basis for its own designpractices.

It requires more extensive geological data, indicating that the planned well will have reservoir,mud, and drilling characteristics sufficiently similar to historical wells.

Because it is formalized at the level of the local operating company, it does not represent thedesign variances executed from time to time by different engineers on different wells.Instead, it represents the trend by the operating company to put in place a consistent designpractice tailored to local operating conditions.

It assumes the presence of state-of-the-art kick-detection equipment at the rig. It assumes that the rig operating staff have the experience and competency required to handle

consistently the well control events that are part of the design premise. Furthermore, thiscompetency is based on demonstrated experience in conservatively handling previous wellcontrol events within the staff and facility infrastructure of the operating company. Forexample, if design is based on controlling kicks to have limited volume or on bullheadingkicks into the formation, then the operating company should have documentation ofsuccessful experiences using this practice.

The design paradigms are intended to manage risk rather than to avoid risk. It does not require two production barriers (tubing and production casing), based on

experience, although the choice may be to keep two production barriers. The design is not locked into the most conservative set of loads and design factors. Instead, it

makes use of the option to adjust the loads and design factors based on experience. However,the design factors tend to have one single, common set of values across the OpCo based onthe experience of the OpCo.

The engineer capable of executing Level Two design practice has all of the competenciesrequired for Level One design practice. In addition, the engineer has thorough understandingof the historical design and operating experiences which form the basis of the operatingcompanys Level Two design practice. The engineer knows the premises and limitations (ifany) of the operating companys Level Two design practice and why and where these arehistorically justified.

The Level Two design uses burst design factors based on the historical experience of theoperating company. These may be smaller (usually) or larger than the design factors used inLevel One practice.


Burst design of surface and intermediate casing can be based on limited kick volume andlimited kick intensity set by the experience of the local operating company. The basis for thelimited kick design is experience data, including successful management of past kicks. Thebasis for the design practice is not the competency of a particular engineer, but instead thedemonstrated competency across the operating company.

For collapse design of surface and intermediate casing, the evacuation depth of the fluidcolumn can be based on experience and can be less than the depth used in Level One designpractice.

Fluid gradients for design pressures inside and outside the casing and tubing can be the sameas in Level One, or they can be based on operating experience.

There is a historical ability to predict pore pressures and fracture pressures with good accuracyin the region of interest. This historical experience reduces the uncertainty in pore andfracture pressures.

2.1.3 Level ThreeLevel Three design practice has the following characteristics:

The third level is the least prescriptive and most sophisticated. It encourages the operatingcompany to adopt a new technology, design, or operating policy based on a detailed examinationof the potential gains and losses as measured through risk assessment.

It is the method of rapidly innovating and evolving well casing and tubing design through alarge step change rather than through many smaller, incremental changes over time.

Level Three design relies heavily on risk assessment as a tool for making the step change fromLevel One or Level Two design practices.

Introduction of a new Level Three design requires an external review of both the proposeddesign practice and the risk assessment conducted to support it, prior to implementation of theLevel Three design. The external review or peer assist should be provided by Shell engineersfrom SEPTAR or from other Shell operating companies. Ultimately, the operating companyproposing to implement the new Level Three design has governance over the decisionwhether or not to accept the finding of the external review, and whether or not to implementthe Level Three design.

Level Three design practice requires the operating companys formal documentation of thebasis for its own design practice.

Level Three does not require two production barriers (tubing and production casing), basedon risk assessment, although the choice may be to keep two production barriers.

Level Three design requires the same competencies from the engineering and operations staffas required by Level Two design practice.

In addition, the engineer who can do Level Three design practice is capable of leading thestep change and development to Level Three design from Level One or Level Two designpractices. The engineer is capable of understanding and leading the use of risk assessment toguide the step changes in design.

Level Three design requires staff with the highest judgement, expertise, and experience.


It encourages use of a design factor calibrated to the assessment of risk and smaller than thedesign factor required in Level One design. Level Three design essentially customizes thedesign factor to the specific type of reservoir and geology. The design factor is adjustedthrough use of the risk assessment. Instead of having one, experience-based design factor,there can be an unlimited number of design factors where each is based on the risk assessmentof a particular type of well and reservoir.

Burst design of surface and intermediate casing can be based on limited kick volume andlimited kick intensity calibrated by risk assessment.

Fluid gradients for design pressures inside and outside the casing and tubing can be the sameas in Level One design, or they can be based on a combination of experience (Level Two) plusrisk assessment.

A design based on variance and executed by an engineer is not necessarily a Level Two orLevel Three design. Instead, it becomes a Level Two or Level Three design when the operatingcompany standardizes on the design practice and documents the basis for the design.

The uncertainty in pore pressures and fracture pressures can be estimated and effectivelymanaged.

2.2 How to Change Design Practice from Level One to Level Two or Level Three Change from Level One to Level Two is based on experience data. It requires small and

manageable changes in well designs while data are accumulated and analyzed over timesufficiently for the operating company to standardize on the evolving design practices.Initially, the designs are variances requiring the highest care and expertise. As the operatingcompany gains experience and matures the design, the operating company evolves the designinto its own, Level Two practice, and the design practice becomes more commonly usedacross the operating company.

Change can be made directly from Level One to Level Three; it is not necessary to stop atLevel Two while evolving to Level Three.

Change from Level Two to Level Three or from Level One to Level Three is based on riskassessment and can be made very quickly.

Over time and at the option of the operating company, a design practice can change fromLevel Three to Level Two as it becomes based more on experience and less on the riskassessment originally done to implement the change.

2.3 Limitations on Export of Level Two and Level Three Design PracticesIn general, Level Two and Level Three design practices should not be exported from oneoperating company to another operating company. Indeed, sometimes the design levels shouldnot be exported to different types of reservoir assets within the same OpCo if the geologicalconditions, rig equipment, or staff skills are substantially different between these assets. This isbecause the Level Two design is customized based on the specific experiences of the local OpCo.Likewise, the Level Three design is customized based on a risk assessment which accounts forwell conditions, rig conditions, and staff competency characteristic of the local OpCo. Theseconditions do not apply when the location of the well is moved to a different OpCo. In general,the approach taken toward developing a particular Level Two or Three design practice can beexported and copied, but the actual results and specifics of the practice cannot be copied.


2.4 Examples of Level Two and Level Three DesignsSome examples of Level Two and Level Three design practices are the following:

Level Two SEPCOs kick-burst design of intermediate casing in the Gulf of Mexico basedon historical experience with limited kick volumes.

Level Two SEPCOs experienced-based burst and collapse design of cemented-tubing, gaswells in South Texas.

Level Three SEPCO single-barrier (Brutus) riser based on risk assessment. Level Three PDO Ara salt deep gas exploratory wells, with casing, BOP, and rig based on

risk assessment (SPE 63130).

Level Three PDO cemented-tubing, gas wells eliminating SCSSVs based on risk assessment. Level Three WOODSIDE well designs, Perseus field.



Chapter 3

Shell Level One Casing and Tubing Design

3. SHELL LEVEL ONE CASING AND TUBING DESIGN ...................................................3

3.1 Overall Casing and Tubing Design ....................................................................................3

3.1.1 Definitions and Terms ................................................................................................3

3.1.2 Parameters Controlling the Design .............................................................................5

3.1.3 How Tubulars Design Works .....................................................................................6

3.2 Casing Seat Selection and CasingTubing Sizes................................................................7

3.3 Pipe Resistance in Tubulars Design ...................................................................................8

3.3.1 Pipe Burst Resistance..................................................................................................8

3.3.2 Accounting for Pipe Thin-Wall Eccentricity in Burst ................................................9

3.3.3 Accounting for Casing Wear in Burst.......................................................................10

3.3.4 Accounting for Pipe Toughness in Burst ..................................................................10

3.3.5 Pipe Collapse Resistance ..........................................................................................11

3.3.6 Not Accounting for Pipe Thin-Wall Eccentricity in Collapse ..................................11

3.3.7 Accounting for Casing Wear in Collapse .................................................................12

3.3.8 Pipe Tensile Resistance ............................................................................................12

3.3.9 Connection Resistance..............................................................................................12

3.4 General Discussion of Load Cases for Casing and Tubing ..............................................12

3.4.1 Use of Frictional Drag in Load Cases.......................................................................12

3.4.2 Tubing Initial Conditions..........................................................................................13

3.4.3 Tubing Pressure Tests...............................................................................................13

3.4.4 Annulus Tests ...........................................................................................................14

3.4.5 Production Conditions ..............................................................................................14

3.4.6 Maximum Allowable Annulus Surface Pressure ......................................................15

3.4.7 Gas-Lifted Production...............................................................................................15

3.4.8 Tubing Leak Impact on Tubing ................................................................................16

3.4.9 Trapped Annular Pressure ........................................................................................16

3.4.10 Shut-In Conditions..................................................................................................17

3.4.11 Burst and Collapse of Corroded Tubing and Casing ..............................................17

3.4.12 Burst Resistance of Corroded Pipe .........................................................................17

3.4.13 Collapse Resistance of Corroded Pipe....................................................................17


3.4.14 Tensile Strength of Corroded Pipe..........................................................................17

3.4.15 Overpull Cases........................................................................................................17

3.4.16 Pump In to Kill the Well.........................................................................................18

3.4.17 Evacuated Tubing ...................................................................................................19

3.4.18 Stimulation..............................................................................................................19

3.4.19 Erosion of Tubing after Proppant Stimulation........................................................20

3.4.20 Space-Out of the Completion when Using Hydraulic Set Packers .........................21

3.4.21 Retrievable Packers.................................................................................................22

3.5 Axial Loads and Thermal Loads Applied to Casing and Tubing ......................................23

3.5.1 Temperature Loading of Surface and Intermediate Casing During Drilling ............23

3.5.2 Subsea, Long-Term Temperature Loading for Surface and Intermediate

Casing......................................................................................................................24

3.5.3 Temperature Loading of Production Casing.............................................................24

3.5.4 Temperature Loading of Tubing...............................................................................24

3.5.5 Running and Pull-Out Loads ....................................................................................24

3.5.6 Axial Loads for Surface, Intermediate, and Production Casing ...............................25

3.6 Pressure Gradients Applied to Casing and Tubing ............................................................25

3.6.1 Burst Pressure Gradients for Surface and Intermediate Casing................................25

3.6.2 Burst Pressure Gradients for Production Casing ......................................................28

3.6.3 Burst Loads for Tubing.............................................................................................29

3.6.4 Collapse Loads for Surface and Intermediate Casing...............................................30

3.6.5 Collapse Loads for Production Casing .....................................................................32

3.6.6 Collapse Loads for Tubing .......................................................................................32

3.6.7 Burst and Collapse Loads on Connections ...............................................................32

3.7 Well Operations to Use for Design....................................................................................35

3.7.1 Well Operations to Use for Design of Tubing ..........................................................36

3.7.2 Well Operations to Use for Design of Production Casing ........................................37

3.7.3 Well Operations to Use for Design of Surface and Intermediate Casing .................38

3.8 Pressure Testing.................................................................................................................39

3.9 Use of Design Software .....................................................................................................39

3.10 Pipe and Connection Quality Assurance in Keeper and Disposable Wells...................39

3.11 When the Well Does Not Meet the Designed Intent..........................................................40

3.12 Other Design Considerations Special Cases..................................................................40

3.13 References ........................................................................................................................40


3. SHELL LEVEL ONE CASING AND TUBING DESIGN

3.1 Overall Casing and Tubing Design

Guidance is provided in this chapter for the most basic, conservative, and streamlined set of

principles for casing and tubing design. This is called Shell Design Level One. Other options for

casing and tubing design exist under the concept of Level Two and Level Three design practice as

explained in Chapter 2. This Level One design practice should apply unless the operating

company has formalized putting in place its own Level Two or Level Three practices.

For the benefit of increased productivity and minimum cost, the wells should be designed from

the inside out by first estimating the flow requirements of the tubing and the related diameter of

the tubing. The casing should be built around the needs of the tubing. The immediate need both

to run and to complete the tubing should be considered, and the potential long-term needs for

fishing and workovers also should be considered.

Where possible, innovative designs and technologies should be used to streamline the size of the

well to reduce cost and also to accelerate delivery of the well to production. Tradeoffs between

tubing and casing diameters and delivery time to obtain or qualify specific sizes of tubulars and

connections should be considered for their impact on well delivery and well cost. The design and

delivery of the well tubulars should be executed in three cycles: first an estimate of production

and drilling requirements leading to design of the well, procurement of materials, and scheduling

for well delivery. Second, the design should be updated and fine tuned while the well is under

construction, based on the actual pressures and reservoir characteristics encountered both in

drilling the particular well and in observing the performance of other new wells between the time

when the well was planned and the time when it is near completion. Third, the well that actually

is delivered should be reviewed and documented for compliance or variance with the design that

was planned. If the delivered well differs significantly from the design requirements of the

intended well, this should be dealt with within the scope of both Shells global Pressure Control

Manual and the local practices of the specific operating company.

The Level One design is required to have two production barriers: a tubing and a production

casing. The production strings have design requirements different from the surface and

intermediate strings. Diligence should be applied to the seal at the liner top, the seal at the packer,

and the wellhead seals. Without these seals, the well would revert to a single production barrier.

3.1.1 Definitions and Terms

The nominal yield strength of the pipe is the specified minimum yield strength of the product

at room temperature.

The yield strength of the pipe is the actual yield strength at whatever depth the engineer is

looking, i.e., at any given point along the string. As such, for design purposes the yield

strength is equal to the pipe specified minimum yield strength derated for the effect of

elevated temperature corresponding to the depth of interest. As depth increases along the well

the temperature increases, and deep in the well this can lead to very significant reductions in

the pipe yield strength compared with the nominal yield strength. Furthermore, when the well

is put on production, the temperature from deep in the well is carried to the surface, and the

entire string of tubing and production casing can reach temperatures close to the bottomhole


temperature. Because of this changing temperature, the yield strength also refers to the actual

yield strength of the pipe at the depth, temperature, and time of interest. Time here is an

important parameter because it links the value of yield strength to the particular well operation

at hand, whether running the tubular, shut in, producing, or injecting. The yield strength of

the pipe at any depth along the string will have a different value depending on which

operation the well is experiencing. Appendix 6 provides information and typical values for

the amount of temperature adjustment of the yield strength. The change of yield strength

affects both burst and collapse capacities of the pipe.

The design factor is the specified (input) requirement for the minimum distance between a

service stress or service pressure and the defined limit of the capability of the pipe or

connection. We refer to a design factor on the pipe and where appropriate, a design factor on

the connection (Chapter 4).

In burst design, the triaxial burst design factor is the minimum required value specified for

the ratio of the pipe yield strength to the von Mises equivalent stress evaluated for the pipe

given the particular well operation at hand. Appendices 6 and 19 explain the concept of

equivalent stress. This design factor is used for loadings which are believed to apply internal

pressure greater than external pressure. Within the context of Level One design, the design

factor is a constant independent of the temperature, the depth, the location in the string, the

choice of string, or the phase of well operation. Regardless of these different points, the pipe

is required to provide at least this minimum margin, or more, when compared with the actual

load applied in the well. For other (Level Two or Level Three) design practice, the design

factor might be different for different strings in the well, but for Level One the design factor is

the same for all strings. See Chapter 5 for the purpose, role, and specifics of the design

factors.

In collapse design, the collapse design factor is the minimum value specified for the ratio

between the collapse pressure rating of the pipe and the actual collapse service pressure acting

on the pipe. For Level One design practice, the collapse design factor is constant for all

strings and all well operations.

The tensile design factor is the minimum value specified for the ratio between the pipe yield

strength and the axial stress acting on the pipe in a purely tensile loading.

The safety factor is the resulting (output) actual distance between a service stress or service

pressure and the defined limit of capability of the pipe during a particular operation of the

well. The safety factor compares the actual capacity of the pipe with the actual working stress

or pressure which is applied to the pipe. The safety factor is not the same as the design factor.

The safety factor is required to equal or exceed the design factor. The design factor is the

minimum requirement that is specified, while the safety factor is the actual result that occurs

once a particular pipe is chosen. Because pipe cannot vary continuously with pressure along

the well, the pipe has to be chosen to meet the load requirements at some depths and thus will

significantly exceed the load requirements at other depths.


The triaxial burst safety factor is the ratio of the actual yield strength at a given point along

the pipe to the actual (von Mises) equivalent stress calculated at the same point based on

pressure, tensile, and thermal loads acting at that point on the pipe. The triaxial burst safety

factor will be temperature dependent because both the value of the equivalent stress and the

value of yield stress will depend on the temperature. Similarly, the triaxial burst safety factor

will vary along the pipe because the working equivalent stress will change with pressure along

the pipe and because the yield strength will vary with temperature along the pipe. Finally, the

triaxial burst safety factor will be different for different modes of operation of the well (shut in

before production, production, shut in after production, etc.) because pressures and

temperatures will be different in the different operations of the well.

The collapse safety factor is the ratio of the actual collapse rating of the pipe to the actual

service pressure acting on the pipe at a location of interest. The collapse safety factor is

required to meet or exceed the value specified for the collapse design factor. The collapse

rating of the pipe will vary with depth because of the variation of tensile and compressive

stress along the pipe. The actual service pressure acting on the pipe also will vary with depth.

Therefore, the collapse safety factor will vary with depth. The collapse strength depends on

the yield strength of the pipe, so the collapse safety factor will be temperature dependent and

operation dependent. Often pipe is chosen based on availability or based on meeting the

demand of a different well operation or a different type of loading (e.g., burst loading), and

this leads to a high safety factor for the other type of loading. For example, when pipe is

chosen to meet the requirements of burst loading (burst is dominant), the collapse safety factor

will tend to exceed significantly the requirement specified by the collapse design factor.

Similarly, when collapse dominates the design of the pipe, the triaxial burst safety factor will

be high compared with the burst design factor. For an efficiently balanced design, the pipe

will cross over to different weights and grades so that burst dominates at some depths,

collapse dominates at other depths, and none of the safety factors will greatly exceed the

corresponding design factors. As a practical matter, this is seldom done because of the time

and risks involved with managing the placement of different weights and grades of casing to

be run in a single string.

The tensile safety factor is the ratio of the actual pipe yield strength and the axial stress acting

on the pipe in a purely tensile loading. This varies with temperature and well operation.

Pipe resistance is the capacity of the pipe to withstand a force or pressure. The term

resistance will be adopted here, since it is useful for later discussion of design factors.

3.1.2 Parameters Controlling the Design

The design of both the tubing and the casing is controlled by the following parameters:

Temperature: the yield strength of the pipe must be derated for elevated temperature (see

Appendix 6). For software calculations, this can be done using the yield strength

corresponding to the temperature, while the temperature varies with depth and type of

operation. For hand calculations, use the maximum temperature for the depth you are looking

at or use the bottomhole temperature to be overconservative. The effect of elevated

temperature also must be considered for the performance of the connection, but this usually is

not done by any de-rating. Instead this is done by qualifying the connection to the high

service temperature (Chapter 4 on connection qualification).


Temperature change leads to compressive thermal stresses and buckling during heating and

tensile thermal stresses during cooling. Temperature change needs to be included in the

design stress calculations of tubing, production casing, and intermediate casing. This is done

almost automatically using the design software. To deal with temperature change, it is

necessary to define the initial temperature state at the time that the tubular is run.

Equivalent stress must be kept a prescribed amount or more below the yield stress of the pipe.

This includes adjustment of the yield stress for temperature. This is done by requiring that the

equivalent stress times the design factor be less than the yield stress of the pipe. Chapter 5

discusses the design factors, and Appendix 6 discusses equivalent stress.

The pressures, loads, and temperatures must be inside the qualified service envelope of the

connection. Chapter 4 discusses connections and qualification of a connection to a service

envelope of pressures, loads, and maximum temperature.

In addition, for tubing the inner diameter needs to be chosen in order to meet the flow

requirements of the production rate and pressure drawdown at the wellhead.

For tubing, consideration usually should be given to clearances inside the casing and the

ability to fish over the tubing and accessories if something goes wrong. This also represents a

marriage between casing and tubing, since the issue of work-through ability applies to the

production casing.

Toughness is critical for the burst design of pipe. More than any other single parameter, good

pipe toughness is important to achieving predictable and reliable burst strength from casing

and tubing. The possession of adequate yield and rupture strength by the pipe is predicated on

the pipe behaving in a ductile (i.e., not brittle) manner. Having good toughness as

characterized by SR16 in API 5CT or ISO 11960 is necessary to ensure that the equations

governing yield will apply. Pipe also needs to have good toughness in order to avoid having

undue burst sensitivity to imperfections which are small enough to pass through the gate of

the inspection system. If a pipe does not have good toughness, then it should be considered

brittle and the yield-based formulations used in burst design should be considered not to

apply. A pipe with low (non-SR16) toughness might be used for structural service or for

collapse loading, but should not be used where burst loading controls the design of the pipe.

In general, if the triaxial burst safety factor is less than 1.5, then the pipe should have good

toughness. See Chapter 7 on Quality Assurance and Inspection.

Link to API 5CT and ISO 11960, SR16

http://sww.shell.com/standards (External Standards on the Shell Web)

Resistance to corrosion: The pipe and connections need to maintain their toughness and

cross-sectional geometry and strength. Where a corrosive environment is suspected, the pipe

and connections need to be designed with choice of material to prevent or minimize the

occurrence of corrosion. See Appendix 5 for this case.

3.1.3 How Tubulars Design Works

To execute tubulars design, it is necessary to compare the resistance (i.e., strength or capacity) of

the pipe with the load (from force or pressure) which acts on the pipe during different operations

of the well. This means that it is necessary to differentiate three elements of tubulars design:

http://sww.shell.com/standards


The capacity (resistance) of the pipe

The loads caused by weight, fluid pressures, and temperatures and, sometimes, additional loads caused by reservoir compaction or salt movement.

The operations of the well which cause certain combinations of loads to occur

The sections below explain the requirements for these elements of tubulars design under Level One design practice.

3.2 Casing Seat Selection and CasingTubing Sizes

Appendix 7 explains the issues involved with casing seat selection. The maximum casing-shoe setting depth is usually driven by several considerations:

To isolate overlying unstable formations

To isolate overlying shallow hydrocarbons

To isolate overlying lost-circulation zones

To isolate overlying freshwater horizons

To prevent borehole failure by time-dependent chemical instability from prolonged exposure to drilling fluid

To prevent failure of formations by induced circulating pressures during drilling operations such as circulating, drilling, and tripping

To prevent failure of formations by induced circulating pressures during well control operations when closing in and circulating out an influx

The first four considerations depend on local OpCo procedures and are location specific. During the last two events, the wellbore below the actual casing shoe under consideration will be subjected to several different types of pressure loads. These pressure loads have to be compared to the capacity of the wellbore to contain these pressures or, in the event of wellbore failure, to be able not to result in uncontrollable fracture propagation . A comparison of the greatest loading on the wellbore with the wellbore strength will lead to the determination of the maximum casing setting depth.

The primary consideration in Level One design is to prevent failure of the formation at the casing shoe and along the open-hole section below it under all realistic load conditions. Additionally, if the wellbore fails, the well design should allow a stable situation to exist for the damaged well. These two requirements can be expressed as a relation among the pressures in the well, the load, and the strength of the wellbore:

The estimated Formation Breakdown Pressure (FBP) of any formation below the casing shoe should not be exceeded during normal operating conditions.

The mud weight gradient required to balance the anticipated pore pressures in the open-hole section should never be higher than the estimated equivalent mud gradient of the Fracture Closure Pressure (FCP) in any of the formations in the open-hole section.

If these requirements are met, the wellbore will not fracture, and the well will not experience uncontrolled losses under design conditions. These design conditions relate to the maximum influx that can be closed in and circulated out and to the maximum circulating rate and trip speed to be experienced. In addition, if the formation accidentally fractures and a loss or kick/loss situation develops, it will be possible to return the damaged well to a stable situation without significant gains or losses once the well has been circulated to mud. This procedure should be followed for any casing string, usually starting at the total depth (TD) and working upwards.


The well should be designed around three factors: the needs of the completion to provide optimum production over its lifetime; the need for reliable pressure containment over the life of the well; and the cycle time required to put various design options into production. Completion requirements and production schedules should be defined early and drive both the tubing and the casing design. Consideration should be given to designing the well from the inside out by first meeting the production requirements of the tubing and then sizing the successive casing strings. However, in some offshore cases, this is not realistic because of the large diameters generated for the outer strings. Considerations should also be given to the lifetime servicing requirements and the trade-offs for the ability to fish over the tubing and accessories.

3.3 Pipe Resistance in Tubulars Design

3.3.1 Pipe Burst Resistance

Pipe burst strength for design purposes is determined by the (triaxial) von Mises equivalent stress and its proximity to the yield stress. Appendices 6 and 19 give formulas for the calculation of individual stresses and equivalent stress. The loads which are applied to the pipe cause hoop, axial, and radial stresses which in turn contribute to the equivalent stress. Yielding occurs only from the combination of stresses in the equivalent stress. From the loads and individual stress components, the equivalent stress is calculated, multiplied by the burst design factor, and compared with the yield strength of the pipe. The difference between the actual yield strength of the pipe and the equivalent stress provides the burst safety factor which is required to exceed the burst design factor. Using the Wellcat and Stresscheck software or programming a spreadsheet, it is straightforward to ensure that the equivalent stress is adequately below the yield strength of the pipe.

All Level One burst design should be based on the triaxial design formula:

e x DF < y (1)

where e is the von Mises equivalent stress (Appendix 6),

DF is the triaxial burst design factor, and

y is the (temperature derated) yield strength.

Equation (1) gives the pressure to yield the pipe for a given axial constraint through the Lam stress formulas relating hoop and radial stress (Appendix 6) to internal and external pressure.

There is no longer a basis for using the one-dimensional (Barlow) formula to rate the burst design pressure (burst resistance) of the pipe as a function of yield strength and pipe geometry. That is, do not use the old historical formula:

P = 0.875 x (2t/D) x y (2)

where t is the pipe wall thickness and D is the pipe outer diameter. Equation (2) is inadequate and outdated for rating the burst resistance of pipe, because Equation (2) does not account for axial stress, which can have a large impact on equivalent stress and the pressure needed to yield the pipe. Equation (2) also is the formula used by API in Bulletin 5C3 to rate the resistance of pipe. This is soon to be revised and updated to three-dimensional (triaxial) yielding as in Equation (1) when API 5C3 is replaced by ISO 10400 (currently under development). Equation (2) provides a convenient and easy calculation for comparing the resistance of different pipes, and the formula is suitable for this purpose. However, the formula is not adequate for design where axial stresses will be present. Thirty years ago, it was necessary to use such a formula for design because of the absence of computational tools to assist the calculation of equivalent stress. However, now the software tools make the calculation in Equation (1) easy.


Link to Standards/API 5C3

http://sww.shell.com/standards (External Standards on the Shell Web)

For Level Two and Level Three design practices, it may be necessary and appropriate to examine

the margin of difference between the onset of yield and the actual rupture of the pipe. This is not

appropriate for Level One design practice, but it is a resource that can help the Level Two and

Level Three practices. Appendix 6 provides information on the rupture limit state.

3.3.2 Accounting for Pipe Thin-Wall Eccentricity in Burst

Burst design of pipe must account for thin-wall eccentricity in the manufacturing process. Pipe is

manufactured and delivered with a round cross section which is eccentrically off center from the

axis of the pipe outer diameter. While the inner diameter meets specifications, this causes the

wall thickness to be low (thin) on one side of the pipe and excessive on the opposite side of the

pipe. The net cross-sectional area is essentially preserved. The thin-wall thickness increases the

hoop stress, and hence also the equivalent stress and the proximity to yielding.

Average carbon pipe is delivered with about 93% of nominal wall thickness, and it is very likely

that a large number of joints will include a pipe with minimum allowed wall thickness. Per API

manufacturing specifications (Bulletin 5CT), the minimum allowed wall thickness for delivery of

carbon pipe is 87.5% of nominal. Typically, the minimum allowed wall thickness for delivery of

CRA tubing is 90% of nominal. Because this is a real (reduced) wall thickness of the pipe, all

casing and tubing must be designed in burst using the minimum allowed wall thickness (which for

carbon equals 87.5% of nominal). In the Wellcat software, this can be done by setting the triaxial

wall factor to 87.5%. This should not be done using the actual dimensions of the pipe in the

inventory of the software, since this would increase the inner diameter and lead to large error in

the collapse calculations. For the Stresscheck software, there presently is no direct way in the

software to account for pipe thin-wall eccentricity, and this is being addressed by Landmark

Graphics as a development item. If one tries to create a pipe with artificial geometry, this will

throw off the collapse calculations in Stresscheck. The only approach that can be used at present

is to increase the minimum design factor used by Stresscheck by multiplying the design factor by

1.143 (i.e., by 1.0/0.875).

Strictly speaking, the adjustment for thin-wall eccentricity should be accomplished by applying

the 87.5% factor to the wall thickness in the Lam calculation of hoop stress and radial stress

(Appendix 6), but not in the calculation of axial stress since the pipe does meet its nominal axial

cross section. However, for practical coding of the software, it may be necessary to apply the

87.5% factor equally to all three stresses. HPHT case studies have shown that when this is done,

there appears to be negligible difference between using the 87.5% term on all three stresses and

on only the hoop and radial stresses in those cases where the burst safety factor is small and burst

is controlling the design.

http://sww.shell.com/standards


3.3.3 Accounting for Casing Wear in Burst

Appendix 3 explains the mechanics of casing wear and the approach to take to account for wear-induced wall loss. Casing wear must be considered in the design of surface and intermediate casing. It also must be considered in the design of any production casing which will be drilled through. This does not mean that a penalty for casing wear has to be applied. This does mean that the engineer executing the design must make and document an allowance for wear. The engineer may decide that wear will not occur or will be negligible because of drilling practices to be used, because of particular tool joint hardfacing, or because of the distance, deviation, dogleg severity, and drillstring weight which will be used for the next drilling interval. In that case, the allowance would be zero and still should be documented. Likewise, the engineer may decide based on past local experience with offset wells or based on logging to make an allowance for a particular amount of casing wear. In this case, the wear allowance should be documented and built into the burst and collapse designs of the well. In burst, the allowance for wear is very similar to the allowance for thin-wall eccentricity except for the following:

The depth of wear often can be greater than the depth of thin-wall eccentricity.

The effect of wear is in addition to thin-wall eccentricity and is not covered by the 87.5% factor used to address thin-wall eccentricity. For thin-wall eccentricity, the wall thickness is reduced locally, but the cross-sectional D/T ratio for collapse design does not change, and the ID of the pipe does not change from nominal. However, for casing wear, the ID of the pipe increases and cross-sectional D/T ratio increases.

To account for the wall loss from wear, the geometry of the pipe should be adjusted with the decrease of wall thickness and increase of inner diameter. That is, instead of a scaling of the equivalent stress, the pipe geometry should be adjusted. This is different from the approach to eccentricity, because the impact of wear on pipe ID and D/T ratio should be made through the geometry in order to impact the collapse resistance simultaneously.

If intermediate casing will be turned into production casing (that is, if the production casing will have been drilled through), then a log must be run through the production casing to quantify the amount of casing wear. If the log is mechanical, assume that the wear occurs on top of a pipe which is at maximum thin-wall eccentricity. That is, reduce the wall to 87.5% of nominal to account for thin-wall eccentricity and reduce the wall further by the depth of the casing wear. This is necessary because casing is delivered with eccentricity, and because when a mechanical caliper is used, one knows the ID of the casing and the OD of the casing but not the eccentric off-axis shift of the ID. If the log is sonic, the measured wall thickness of the casing is available. In this case, use the minimum measured wall thickness in the geometry of the custom joints of pipe. This wall thickness is measured and covers the combined effects of eccentricity and wear. Because this wall thickness has been measured, there is no need to account for further additional eccentricity for this joints or for other worn joints which use the measured minimum wall thickness. Therefore, for worn joints with wall thickness measured using sonic logs, do not apply the usual de-rating of pipe wall for thin-wall eccentricity. Use 100% of the measured wall thickness to calculate the ID (that is, apply the thin wall all the way around the pipe, and use this ID with no thin-wall de-rating factor in the pipe inventory of the software and in the calculation of pipe mechanical properties.

3.3.4 Accounting for Pipe Toughness in Burst

As explained above, if the triaxial burst safety factor is less than 1.5, then pipe should meet or exceed the specifications of API SR16.


3.3.5 Pipe Collapse Resistance

Pipe collapse strength is determined by formulas in API 5C3. The formulas are based on a combination of analytical formulas for elastic instability, formulas for yielding, and a large amount (2000+) of empirical collapse test data on full-size pipes. The theory and data are combined into four different modes of collapse resistance:

Yield

Plastic

Transition

Elastic

The choice of which mode applies to determine the pipe collapse resistance depends on the D/T ratio and yield strength of the pipe. The yield strength is adjusted for both temperature and axial loading (triaxial stress) in tension, so temperature and axial tension impact collapse strength. Axial tension significantly decreases collapse strength, while axial compression has no impact on collapse strength within the accuracy of the standard for rating collapse capacity (see API 5C3). The plastic and transition modes are linked to the empirical data. In general, tubing and most production casing has a D/T ratio corresponding to plastic or yield collapse. Most intermediate casing has a D/T ratio corresponding to plastic and transition collapse, and most large-diameter surface casing has a D/T ratio corresponding to elastic collapse. The elastic collapse rating of pipe is independent of the grade.

Through use of the test data, the API collapse resistance ratings have a statistical basis. That is, collapse design is probabilistic, and this impacts the choice of the design factor in Chapter 6. Specifically, the present API collapse design already has built into it a target collapse reliability based on the condition that no more than 0.5% of joints will fail when subjected to the rated collapse pressure of the pipe. For a lower pressure, the collapse probability would be lower, and for a higher pressure, the collapse probability would be higher. In general, collapse design could include a choice of the target collapse reliability. For Level One design, the target collapse reliability is 0.5%.

Engineers sometimes need to consider using non-API pipe which has a manufacturers claim of proprietary collapse strength greater than the value set forth in the API collapse ratings. This sometimes is referred to as high collapse pipe. Most high collapse pipe has been shown not to provide any higher collapse strength than that of API pipe. However, some high collapse pipe does provide higher mean and minimum collapse strength, usually through the use of consistently sharp stressstrain behavior (no cold straightening), higher minimum yield strength, lower D/T ratio, or lower maximum ovality of the product. When high collapse pipe is considered, it is necessary to compare the mean product performance with the mean (not minimum) API collapse rating and to compare the minimum product performance with the minimum (probabilistic) API collapse rating. When pipe collapse strength is reviewed, the strength must be based on tests of pipes with length-to-diameter (L/D) ratios of 7 or 8 (8 is preferred, but 7 is acceptable). Evidence of pipe collapse strength should never be based on tests of specimens with L/D less than 7, since this artificially inflates the measured collapse pressure beyond what would be experienced for a full joint of pipe.

3.3.6 Not Accounting for Pipe Thin-Wall Eccentricity in Collapse

Thin-wall eccentricity should not be considered for collapse design of pipe. This is because the basis for the collapse design guidelines (API 5C3) is collapse test data which already capture the natural collapse resistance of pipes including their thin-wall eccentricity.


3.3.7 Accounting for Casing Wear in Collapse

Casing wear introduces an unusual wall loss which is not the same as the thin-wall eccentricity of the pipe. Casing wear has to be accounted for by decreasing the wall thickness and increasing the ID of the casing. The approach to use is the same as for burst: introduce joints of pipe in the Stresscheck or Wellcat model with wall thickness reduced in proportion to the depth of wear. See Reference 1 for good test data on the reduction of collapse strength from casing wear.

3.3.8 Pipe Tensile Resistance

During loading with combined pressure and axial load, the effect of axial load is captured in the burst and collapse design. Examination of pipe tensile resistance is made under purely axial loading. This occurs while the pipe is being run and when the pipe is pulled out of the hole. In terms of well operations, the dominant operation for tensile resistance occurs when the pipe is being pulled out of the hole. Certainly, the tensile pull-out option applies to tubing. However, because problems can occur while running casing, it is necessary to plan the well for the contingency to pull the casing out of the well. A margin for tensile overpull should be built into the pipe (see the loads and operations below). During pull-out, the tensile capacity of the pipe is determined by the yield strength of the pipe times the cross-sectional area of the pipe.

3.3.9 Connection Resistance

The pressure and load resistance of a connection are based upon the testing originally done to qualify the connection for well service (see Chapter 4 on connection qualification). The process of qualifying the connection establishes an envelop of pressures and loads where the connection can be used reliably. The qualified service envelope is based on testing at elevated temperature, so the connection resistance is not derated for elevated temperature in the well. See the list of Shell-qualified connections.

Link to list of Shell-Qualified Connections

http://swwep-w.shell.com/threads/.

3.4 General Discussion of Load Cases for Casing and Tubing

3.4.1 Use of Frictional Drag in Load Cases

There is no capability of applying drag or tubing-to-casing friction specifically to individual load cases. Friction has to be used or not used for all the load cases. In production load cases where heating induces buckling, the stresses and strains will be reduced if tubing-to-casing friction is applied. This is not conservative and not accurate in terms of well operations, so friction should not be used for these load cases.

In principle, in hanging, running, and pull-out load cases, the stresses and strains should be increased if tubing-to-casing friction is included. However, there is a problem with the drag calculations made by Wellcat. Just as with drillstring, substantial drag will occur when casing or tubing is run into or pulled out of a dogleg. The drag comes from the weight of the string pushing or pulling it up against the curves side of the hole. Even when the friction calculation is turned on, Wellcat does not account for the frictional drag that would decrease the hook load running or increase the hook load pulling. This simply is not included within the calculations that Wellcat makes. This is a very unfortunate deficiency of the software. Given this limitation, it is best always to run Wellcat with friction turned off. The pullout load case can be run in Wellcat and will be valid, except that frictional drag through doglegs will be neglected. For cases of wells with doglegs when the safety factors are unusually small or for wells with large doglegs, it is

http://sww.siep.shell.com/threadshttp://swwep-w.shell.com/threads/


prudent to use one of the many torquedrag programs available to Shell (Wellplan, Stuck, Mtd) to calculate the hook load in a worst-case pullout with friction. Then, apply this pullout load to the top of the same string using the Wellcat software.

3.4.2 Tubing Initial Conditions

This load case is required, as all other loads are calculated relative to this one. If the initial load

case is incorrect, all other loads will also be incorrect. Therefore it is important to get the

pressures and temperatures correct at the time of setting the packer. When the computer programs

asks for initial conditions, this means the conditions prior to pressuring up the tubing for setting

the packer (for hydraulic set packers). The actual surface pressure at the time the packer slips bite

the casing is specified separately in the packer sections. Note that initial conditions should not be

confused with the term packer fluid. The packer fluid is assumed to be the fluid in the tubing

casing annulus after the packer has been set. The initial conditions and the packer fluid will

normally (but not always) be the same fluid.

Drag is an important consideration in getting the initial load condition correct. If there is

excessive drag when running the completion in and the packer is then set, then it is likely that

compression will be introduced into the completion. This compression can be modelled within

Wellcat neglecting the frictional drag loads, but the amount of compression to include is best

calculated using a torque/drag simulator to account for frictional drag. The alternative to this

compression is that tension will be introduced. This can be caused by picking up the tubing to get

the packer into the correct position. This often happens when the packer is set and the hanger is

not installed. Tension can also be introduced by performing a pressure test prior to setting the

packer. The pressure test will extend the tubing, and because of drag, not all of this extension will

be released when the pressure is released. In order to get around these problems, there needs to be

good integration between the completion program and the stress analysis. The completion

program should state how the packer is being set and any reference positions (e.g., up-weight,

down-weight or mid-weight). The implications of this drag on the position of the packer should

also be addressed to avoid the packer being set across a casing coupling.

If your loads on a pinned PBR (for example) are excessive and close to limits, then consider what

effect any circulating will have prior to setting a packer. This may cool (or heat) the completion

and therefore put residual compression or tension into the string. Such modeling can be done

using Wellcat.

3.4.3 Tubing Pressure Tests

Pressure testing is not required as part of Level One design practice. However, it is recognized

that pressure testing may be part of the operating policy of the individual operating company. At

the extreme, the pressure test of tubing and production casing can apply the full wellhead pressure

that is planned for the well kill operation. This pressure is the lesser of 1,000 psi or 10% above

the shut-in pressure of the tubing. However, this high test pressure should not be applied to the

tubing unless the same completion fluid is present both inside and outside the tubing. This test

pressure should not be applied to the production casing unless the same mud gradient is present

both inside and outside the casing.

The pressure test will be either before or after the packer has been set. Often, both tests are

performed. Normal operation loads should be lower than test loads. Savings in material can be

made if test pressures are limited. Shell Expro stipulate that the tubing pressure test should be to


110% of the maximum tubing-head pressure. Dispensation is required if pressure tests are going

to be lower than this.

Be very careful about the position of any plugs during testing. For example, if an expansion

device is included in the completion and a pressure test takes place without a plug, the piston

effect will compress the string. If the same test is performed with a plug above the expansion

device, there will be no upward piston force, but a downward piston force at the plug. The tubing

will therefore try to move downwards.

If a pressure test with a plug is included in the analysis, consider the effects of the plug leaking

and pressure being applied below the plug. Under certain circumstances, this will go unnoticed

and may pose high loads on the completion.

3.4.4 Annulus Tests

The main purpose of this test is to test packers or tubing hangers. Ideally, the test pressure should

be to the same criteria as tubing tests (particularly if packers are being tested only from above). It

is often possible to test packers and hangers without a separate annulus test, and therefore it is not

normally necessary for this load case to be a limiting condition on the tubing. Alternatives to a

separate annulus test include an annulus test with backup pressure on the tubing.

3.4.5 Production Conditions

The production multiphase calculations in many stress analysis programs are highly simplistic.

However, they are usually conservative and therefore are a useful first pass.

Considerations are as follow:

1. A high flowrate gives high temperatures (therefore compression) but lower pressures

(therefore collapse). It is therefore prudent to consider the worst case of a high flowrate with

the highest possible drawdown.

2. The highest temperatures may be generated not with the highest flowrate, but with high water-

cuts. Water, having a high specific heat capacity and little in the way of JouleThomson

cooling, will transmit temperatures well, and a low-flowrate well with a high water-cut may

generate higher surface temperatures than would a higher-flowrate well with low water-cuts.

Therefore, some sensitivity to water-cut should be included. For example, an early-life

production case and a late-life production case.

3. The highest flowrate and lowest pressure will be generated by using the minimum wellhead

flowing pressure. This should be the lowest possible pressure that the well will be flowed,

whether to a bulk or test separator or to a separate well test package.

4. A production shut-in case should be included in the analysis as a separate load case.

Therefore, it is not normally necessary to examine production loads involving high surface

pressures.

5. What are the likely annulus pressures? High annulus pressures, coupled with high

drawdowns, with or without reservoir depletion, can produce large collapse loads. The

appropriate annulus pressure to use will depend on the well procedures and equipment

designed to limit annulus pressures (i.e., the regular monitoring and bleeding down of annulus

pressures, or the inclusion of a gas lift valve). If a high-drawdown case coupled with high


annulus pressures creates a potential collapse condition, then this warning must be passed on

and the maximum safe annulus pressure included in the well operations procedures.

3.4.6 Maximum Allowable Annulus Surface Pressure

It is important that the maximum allowable annulus surface pressure (MAASP) is calculated

correctly and used in the tubing stress analysis (particularly the production cases). The

A annulus MAASP should be defined by the following:

1. The burst rating of the production casing, accounting for any fluids behind the casing and

their change over time (e.g., barite settling).

2. The collapse potential of the production tubing with the lowest possible fluid pressure inside

the tubing. This pressure may be full evacuation or may be limited by the type of fluids that

will be inside the tubing (e.g., water during water injection).

3. Any limitations imposed by the liner lap; if the packer or seal is positioned with access to the

liner lap through the A annulus, then this may be a limitation.

4. Any limitation governed by pressure differentials across the packer. This limitation need not

necessarily be the same as the annulus pressure test, as the pressures inside the tubing will be

different during test and production conditions.

5. The pressure test of the A annulus. This should be examined at the base and the top of the

string.

6. The limit to which the annulus pressure can be controlled during production. For example, if

a pressure increase in the A annulus could be observed after shutdown of a subsea water

injector and this pressure increase could not be controlled (as the well was shut-in), the

maximum allowable pressure during normal injection would have to be the rating of the

annulus minus this theoretical pressure increase.

It is important that the A annulus MAASP figure be used and adhered to. During production or

injection shutdown conditions, the A annulus pressure can rise quickly. The A annulus should

therefore be alarmed where possible or monitored to such an extent that the MAASP is not

exceeded.

3.4.7 Gas-Lifted Production

For tubing pressures, these can be calculated as per normal, but accounting for the change in

conditions due to the injected gas. The lift in the annulus will also have a thermal insulation

effect on the temperatures and this should be addressed. The A annulus should be pressurized to

the maximum lift-gas injection pressure. It is also worth considering the effect if the lift gas is

partially or completely bled off (with or without an annular safety valve). This may generate high

burst loads on the tubing during a production shut-in case or high collapse loads on the production

casing. Level One design practice requires two pressure barriers. Hence, the B annulus must

withstand the maximum injection pressure on top of the mud column in the event that the

A annulus leaks to the B annulus.


3.4.8 Tubing Leak Impact on Tubing

This load case is often of great significance with regard to casing design. Sometimes, however, it

also is important for tubing design. The rationale is that if a high-pressure, low-density fluid in

the tubing leaks into the annulus, this pressure will be transmitted down the annulus and at the

base of the A annulus wi

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EP_2000-9073_Shell_Casing_and_Tubing_Design_Guide_Vol_1 rev Jan 2008.pdf

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