hasa casing design

Casing Design Manual

_____________________________________________________________________________________February 1996 of 3 Table of Contents

Table of Contents

Chapter 1Overview and Purpose

Overview ………………………………………………… 2Purpose ………………………………………………… 2

Chapter 2Quick Reference

Conductor and Surface Casing ………………………… 2Intermediate Casing and Liner ………………………… 3Production Casing and Liner ………………………… 4

Chapter 3Introduction to Casing Design

Casing Types and Functions ………………………………… 2Design Methodology ………………………………………… 3Required Information ………………………………………… 4

Chapter 4Preliminary Design

Introduction ………………………………………………… 2Mud Program ………………………………………………… 2Shoe Depths and Number of Strings ………………………… 3Hole and Pipe Sizes ………………………………………… 5Top of Cement Depths ………………………………………… 6Directional Plan ………………………………………………… 8

Chapter 5Design Loads

Introduction ………………………………………………… 2Construction of Load Lines ………………………………… 2Burst and Collapse Loads ………………………………… 5Conductor and Surface Casing ...........………………… 5Intermediate Casing and Liner ......................………………… 12Production Casing and Liner ......................………………… 20Intermediate and Production Tiebacks ......................………… 25Axial Load Cases ………………………………………… 25

Chapter 6Design Factors

Basis ………………………………………………………… 2Relationship Between Design Loads and Factors ………… 2

NOTE

NOTICE All information contained in this publication is confidential and proprietary property of Halliburton Company. Any reproduction or use of these instructions, drawings, or photographs without the express written permission of an officer of Halliburton is forbidden. Acrobat version (c) Copyright 1996, Halliburton Company All rights reserved.


_____________________________________________________________________________________Table of Contents of 3 February 1996

Table of Contents(Continued)

Chapter 7Pipe Ratings

Burst Strength ………………………………………………… 2Collapse Strength ………………………………………… 3Collapse Strength Equations .....................………………… 4The Effect of Tension on Collapse Resistance .....................… 5The Effect of Internal Pressure on Collapse Resistance ... 5Axial Strength ………………………………………………… 6Reduced Wall vs. Nominal Dimensions ………………… 7Deration of Yield Strength With Temperature ………… 7

Chapter 8Triaxial Design

Theory ………………………………………………………… 2Practice ………………………………………………………… 5Combined Burst and Compression Loading .....................… 6Combined Burst and Tension Loading ………….......... 7Inappropriate Criteria for Collapse Loading …..................... 7Nominal Dimensions and Design Factor ..........………… 7Summary ...........………………………………………… 8

Chapter 9Special Considerations

Connections ………………………………………………… 2Design Limits ...........………………………………………… 3API Connection Ratings ...........………………………… 4Design Factors for API Connections ......................………… 7Use of Premium Connections ...........………………… 8Service Loads and Buckling ………………………………… 8Temperature Effects ………………………………………… 11Wear ………………………………………………………… 12Corrosion ………………………………………………… 13

Chapter 10Design Example Using Stress Check

Well Description ………………………………………… 2Design Example ………………………………………… 2Preliminary Design Input ………………………….......... 3Detailed Design Criteria Input ................................... 9Performing Design ..........………………………………… 16


_____________________________________________________________________________________February 1996 of 3 Table of Contents

Table of Contents(Continued)

Appendix ALoad Case Equations

Burst Loads ………………………………………………… 2Collapse Loads ………………………………………………… 7Axial Loads ………………………………………………… 9


February 1996 Page 1 of 2 Overview and Purpose

Chapter 1 - Overview And Purpose

Contents

1.1 Overview

1.2 Purpose


Overview and Purpose Page 2 of 2 February 1996

1.1 Overview

The design engineer has three major responsibilities when performing casing design:

• Ensure the well’s mechanical integrity by providing a design basis which accounts forall the anticipated loads that can be encountered during the life of the well.

• Design strings to optimize well costs over the life of the well.

• Provide clear documentation of the design basis to operational personnel at thewellsite. This will help ensure that the designed operating envelope is not exceeded byapplying loads not considered in the original design.

This manual is provided as a tool to help the engineer perform these responsibilities in asystematic fashion. It reviews the casing design process, provides a consistent and sounddesign basis, includes theoretical as well as practical discussion, and highlights specialconsiderations.

1.2 Purpose

The scope and the size of this manual have been purposely limited so that it can morereadily serve as a practical guide to casing design. An engineer armed with this manual andan appropriate software tool such as StressCheck will be able to perform an efficient casingdesign on most wells. It is not the intent of this manual to give detailed instruction onevery design issue. In critical situations such as deep, hot and sour wells, the manualhighlights the issues only, and the engineer is expected to obtain expert assistance from aknowledgeable third party.

Much of the text has been written in bullet style to facilitate quick and easy access to thedesired information. A quick reference section is also provided in Chapter 2 to allow anengineer familiar with the casing design process to very quickly perform a design based onsound principles.

In addition to providing a standard set of design criteria to be used on a corporate basis, avariety of widely used alternative criteria are also included. This acknowledges the factthat there is no one standard method of performing design. Many clients will request thattheir own design criteria be used. However, if alternative criteria are used in a design, thedesign should also be checked against the standard criteria to ensure suitability.


February 1996 Page 1 of 4 Quick Reference

Chapter 2 - Quick Reference

Contents

2.1 Conductor and Surface Casing

2.2 Intermediate Casing and Liner

2.3 Production Casing and Liner


Quick Reference Page 2 of 4 February 1996

2.1 Conductor And Surface Casing

Standard Design LoadsDesignFactor Comments

Burst

Gas Kick 1.2 Suggested parameters include a kick intensity of 0.5 ppgabove the mud weight, and a kick volume of 70 bbls fordevelopment wells and 100 bbls for exploration wells.

Lost Returns with Water 1.1 Use if the recommended kick tolerance is not met or a riskof lost returns otherwise exists. Represents a watergradient extending upwards from the fracture pressure atthe shoe.

Pressure Test 1.1 Use if a pressure test is performed. A conductor casingwith a diverter stack only requires this load case (using theleak-off test pressure).

External Pressure Profile Mud weight from surface to TOC. Cement mix-watergradient from TOC to prior shoe. Pore pressure incemented interval exposed to open hole.

Collapse 1.0

Cementing Collapse load with cement slurry in place.

Lost Returns w/Mud Drop Partial evacuation based on mud column equilibratingwith pore pressure.

Full Evacuation Use for air or foam drilling.

External Pressure Profile Mud gradient from surface to shoe. If salt loads areanticipated, they should be superimposed onto this profile.

Axial 1.3

Running in Hole Includes shock loads based on a suggested 2 -3 ft/secaverage running speed and bending loads.

Overpull While Running Suggest 100,000 lbs overpull force. Includes bendingloads.

Green Cement PressureTest

Large piston force at float collar due to applied pressureafter bumping plug often dictates axial design.

Service Loads Axial loads due to combined loading in burst and collapseload cases.

Triaxial 1.25

All burst and axial loads Not the appropriate criterion for collapse loads becausethe collapse stability failure will normally occur before thetriaxial stress exceeds the yield strength.


February 1996 Page 3 of 4 Quick Reference

2.2 Intermediate Casing And Liner


Burst

Gas Kick 1.2 Suggested parameters include a kick intensity of 0.5 ppgabove the mud weight, and a kick volume of 70 bbls fordevelopment wells and 100 bbls for exploration wells.

Lost Returns with Water 1.1 Use if the recommended kick tolerance is not met or a riskof lost returns otherwise exists. Represents a watergradient extending upwards from the fracture pressure atthe shoe.

Pressure Test 1.1 Use if a pressure test is performed.


Collapse 1.0


Lost Returns w/Mud Drop Partial evacuation based on mud column equilibratingwith pore pressure.

Full Evacuation Use for air or foam drilling.


Axial 1.3






Triaxial 1.25



Quick Reference Page 4 of 4 February 1996

2.3 Production Casing And Liner


Burst 1.1

Tubing Leak A surface pressure applied on top of the completion fluiddue to a leak near the hanger. Should be considered forboth production and injection operations.

Pressure test Typically based on the anticipated shut-in tubing pressureplus a suitable safety margin (e.g., 500 psi).

Injection Down Casing Applicable to wells which experience casing fracs.


Collapse 1.0


Full Evacuation Above the packer, applies to gas lift wells. Below thepacker, applies to wells which will be severely depleted orhave low permeability.

Partial Evacuation Represents a fluid column equilibrating with a depletedreservoir pressure (typically during a workover).

Fluid Gradient Represents zero surface pressure applied to a low fluidgradient resulting in a depleted or drawn-down pressure atthe perforations.


Axial 1.3






Triaxial 1.25



February 1996 Page 1 of 4 Introduction to Casing Design

Chapter 3 - Introduction To Casing Design

Contents

3.1 Casing Types and Functions

3.2 Design Methodology

3.3 Required Information


Introduction to Casing Design Page 2 of 4 February 1996

3.1 Casing Types And Functions

Casing is commonly classified into the following categories:

Conductor The first string set below the structural casing (i.e., drive pipe or marineconductor). The conductor isolates unconsolidated formations and watersands and protects against shallow gas. Usually the string onto which thecasing head is installed. A diverter or a BOP stack may be installed ontothis string. Typically cemented to the surface or the mudline.

Surface Casing set to provide blowout protection, isolate water sands and preventlost circulation. It also often provides adequate shoe strength to drill intohigher pressure transition zones. In deviated wells, the surface casing maycover the build section to prevent keyseating of the formation duringdeeper drilling. Typically cemented to the surface or the mudline.

Intermediate Casing set to isolate unstable hole sections, lost circulation zones, lowpressure zones and production zones. Often set in the transition zone fromnormal to abnormal pressure. The cement top must isolate anyhydrocarbon zones. Some wells require multiple intermediate strings.Some intermediate strings may also be production strings if a liner is runbeneath them.

Production Casing used to isolate production zones and contain formation pressures inthe event of a tubing leak. May also be exposed to injection pressures fromfracture jobs down casing, gas lift or the injection of inhibitor oil. A goodprimary cement job is much more critical for this string.

Liner A casing string which does not extend back to the wellhead, but instead ishung from another casing string. Liners are used in lieu of full casingstrings to reduce cost, improve hydraulic performance when drilling deeper,allow the use of larger tubing above the liner top, and not represent atension limitation for a rig. Liners can be either intermediate andproduction strings. Typically cemented over their whole length.

Tieback A casing string which provides additional pressure integrity from the linertop to the wellhead. An intermediate tieback is used to isolate a casingstring which cannot withstand possible pressure loads if drilling iscontinued (usually due to excessive wear or higher than anticipatedpressures). Similarly, a production tieback isolates an intermediate stringfrom production loads. Tiebacks can be uncemented or partially cemented.


February 1996 Page 3 of 4 Introduction to Casing Design

3.2 Design Methodology

The objective of successful casing design is to provide sufficient mechanical integrity in thewell bore to allow all drilling, completion, production and workover objectives to be metover the life of the well. This objective should be obtained: (1) while maintaining anacceptable level of safety at all times and (2) at the minimum practical cost.

In order to efficiently meet this objective, the casing design process should be divided intotwo distinct tasks:

Preliminary Design The preliminary design encompasses the data gathering andinterpreting phase and the selection of casing sizes and shoe depths.The quality of the gathered data will have a large impact on theappropriate choice of casing sizes and shoe depths and whether thecasing design objective is successfully met. The largestopportunities for saving money are present while performing thistask. Savings can be achieved principally by reducing the size ofthe casing strings and/or the number of strings required.

Detailed Design The detailed design phase consists of selecting the pipe weights,grades and connections for each casing string. The selectionprocess consists of comparing pipe ratings with design loads andapplying minimum acceptable safety standards (i.e., design factors).A cost effective design meets all the design criteria using the leastexpensive available pipe. Cost effective designs can be achievedmuch more efficiently through the use of a computing tool such asthe StressCheck program which is provided in the Halliburtondrilling engineering toolkit.


Introduction to Casing Design Page 4 of 4 February 1996

3.3 Required Information

The following checklist includes data required to perform both the preliminary and detaileddesign.

Formation Properties

Pore pressureFormation strength (fracture pressure)Temperature profileLocation of squeezing salt and shale zonesLocation of permeable zonesRegions where formation stability is sensitive to mud chemistry, weight and exposuretimeLost circulation zonesShallow gasLocation of fresh water sandsPresence of H2S and/or CO2

Directional Data

Surface locationGeologic target(s)Well interference data

Minimum Diameter Requirements

Minimum hole size required to meet drilling objectives.Logging tool ODTubing size(s)Packer requirementsSubsurface safety valve OD (offshore well)Completion requirements

Production Data

Packer fluid densityProduced fluid compositionWorst case loads which may occur during completion, production and workoveroperations

Other

Available inventoryRegulatory requirementsRig equipment limitations


February 1996 Page 1 of 8 Preliminary Design

Chapter 4 - Preliminary Design

Contents

4.1 Introduction

4.2 Mud Program

4.3 Shoe Depths and Number of Strings

4.4 Hole and Pipe Sizes

4.5 Top of Cement Depths

4.6 Directional Plan


Preliminary Design Page 2 of 8 February 1996

4.1 Introduction

The preliminary design generally consists of establishing values or estimates for each of theparameters discussed in this chapter. However, not every parameter is relevant to everydesign. The process is essentially linear, although the results of any particular step may beiteratively adjusted based on the results of other steps and based on the results of thedetailed design (designing the weight, grade and connection for each OD). It is beyond thescope of this manual to fully discuss all the considerations used to establish a preliminarydesign; however, the major points are highlighted below.

Several points of particular importance should be noted when performing preliminarycasing design:

• The establishment of a well-engineered, cost-effective preliminary design is highlydependent on the quality of the input data, most particularly the formation properties.As a result, the same level of effort should be made to obtain accurate input data as toperform the subsequent engineering design.

• Safely eliminating a casing string while meeting design objectives can have a substantialimpact on the overall well cost. Since the required number of strings is principally afunction of formation properties (see Section 4.3), this is a strong argument forobtaining accurate input data.

• Reducing the casing diameters can have even a larger impact on well costs. However,the minimum required pipe diameters are typically a function of evaluation, completionor production requirements. Paying particular attention to these requirements anddesigning the casing from the inside outward can often result in significant cost benefits(see Section 4.4).

4.2 Mud Program

The most important mud design parameter used in casing design is the mud weight as afunction of depth. The mud weight is used during preliminary design to determine shoedepths and during detailed design to calculate pressures used in load cases. The completemud program is determined from:

• Pore pressure• Formation properties• Hole integrity and stability• Casing shoe depths• Hole cleaning and cuttings transport capability• Potential formation damage and drilling rate• Formation evaluation requirements



4.3 Shoe Depths And Number Of Strings

The appropriate selection of shoe depths and consequently, the required number of stringsis critical to the well design. Too conservative a design will result in significant increases inthe cost of the well due to the larger diameter of conductor, surface and intermediatecasing required to accommodate the additional string(s). However, the consequences of anon-conservative design can be much worse, including the inability to reach the wellobjective.

General guidelines are given here for the selection of shoe depths. Local practices andexperience should also be used to fine-tune this process. To determine an initial estimateof shoe depths, first construct a pore pressure/fracture gradient/mud weight graph asfollows (see Figure 4.3.1):

• Draw the predicted pore pressure with depth expressed as an equivalent mud weight(EMW). If lithological information is available, it should also be noted.

• Similarly, draw the predicted fracture gradient profile. Draw a design fracture gradientprofile which is offset to the left of the predicted curve by a prescribed amount toroughly account for kick tolerance and the increased ECD during cementing. Arecommended offset value is 0.3 ppg.

• Draw the mud weight profile based on the pore pressure and fracture gradient data. Ingeneral, the mud weight profile should be offset to the right of the pore pressure curveby 0.5 ppg to provide a sufficient overbalance for trips.

• If mud weight and leak-off test (LOT) information is available from offset wells,include it on the graph for reference. If large disparities exist between the offset wellinformation and the predicted values, further investigation and discussion is highlyrecommended.



0

2000

4000

6000

8000

10000

12000

14000

8.00 9.00 10.00 11.00 12.00 13.00 14.00 15.00 16.00 17.00 18.00 19.00

EMW, ppg

Dep

th, f

t

A

BC

D

16"

11.75"

7.625"

9.625"

Pore Pressure

Mud WeightFracture Gradient

Design Fracture Gradient

Figure 4.3.1 - Casing Shoe Selection Graph

The initial shoe depth determination is made as follows (see Figure 4.3.1):

• Starting at the mud weight at the well TD (point A), draw a vertical line upwards untilit intersects the design fracture gradient curve (point B). This is the approximate shoedepth of an intermediate casing.

• Draw a horizontal line from point B leftwards until it intersects the mud weight curve(point C) and then upward until it intersects the design fracture gradient curve(point D). This represents the approximate shoe depth of the next casing string.

• Repeat this process until all shoe depths dictated by mud weight and fracture gradientconstraints have been established.

After the preliminary shoe depths have been established. An additional check should bemade based on kick tolerance. The kick tolerance is the maximum size kick that can becirculated out of the hole without causing the formation to fracture in the open hole section(often near the shoe). As a guide, kick tolerances of 100 bbls and 70 bbls arerecommended for exploration and development wells, respectively. The kick modelledshould be based on the same parameters as those used in the gas kick load case describedin Section 5.3.1.

It is not required to use the recommended kick tolerance. In some higher pressure wellswith a small margin between the mud weight and the fracture pressure, the recommendedkick tolerance is nearly impossible to achieve. However, if a kick tolerance less than the



recommended volume is used, the lost returns with water load case should be included inthe burst design basis (see Section 5.3.1). This will help ensure sufficient burst strengthnear the surface.

There are numerous other factors which affect the design of shoe depths. These factorsinclude:

• Regulatory requirements. Applicable local regulations should always be obtainedbefore beginning the design.

• Hole stability. This can be a function of mud weight, deviation and stress at thewellbore wall or can be chemical in nature. Often, hole stability problems exhibit timedependent behavior (making shoe selection a function of penetration rate). The plasticflowing behavior of salt zones also needs to be considered.

• Differential sticking. The probability of becoming differentially stuck increases withincreasing differential pressure between the wellbore and formation, increasingpermeability of the formation, and increasing fluid loss of the drilling fluid (i.e., thickermud cake).

• Zonal isolation. Shallow fresh water sands need to be isolated to preventcontamination. Lost circulation zones need to be isolated before a higher pressureformation is penetrated.

• Directional drilling concerns. A casing string is often run after an angle buildingsection has been drilled. This avoids keyseating problems in the curved portion of thewellbore due to the increased normal force between the wall and the drillpipe.

• Uncertainty in predicted formation properties. Exploration wells often requireadditional strings to compensate for the uncertainty in the pore pressure and fracturegradient predictions.

4.4 Hole And Pipe Diameters

The selection of pipe diameters has the largest impact on well costs of any process in bothpreliminary and detailed casing design. Hole and pipe diameters should be designed to bethe smallest possible which meet all design requirements, well objectives, and safety andenvironmental requirements. The final hole or casing diameter is generally determined byevaluation, completion or production requirements. Because of this, casing sizes should bedetermined from the inside outward.

Hole and casing diameters are based on the following requirements:

• Evaluation - logging interpretation requirements and tool diameters.

• Production - production equipment requirements including tubing, subsurface safetyvalve, submersible pump and gas lift mandrel size, completion requirements (e.g.,gravel packing), and weighing the benefits of increased tubing performance of largertubing against the higher cost of larger casing over the life of the well.



• Drilling - minimum bit diameter for adequate directional control and drillingperformance, available downhole equipment, rig specifications, and available BOPequipment.

Figure 4.4.1 is a handy tool to help the design engineer select casing and hole sizes. Simplyby moving downward through the chart, you can arrive at a design using standard casingand bit sizes. If the route taken involves a path designated by a dashed line, low clearanceconsiderations should be made. This may require special consideration of or modificationto connection ODs, mud properties, cementing operations, and doglegs in the wellboreprofile.

4.5 Top Of Cement Depths

Top of cement (TOC) depths for each casing string should be selected in the preliminarydesign phase because this selection will influence axial load distributions and externalpressure profiles used during the detailed design phase. TOC depths are typically based onthe following considerations:

• Zonal isolation• Regulatory requirements• Prior shoe depths• Formation strength• Buckling

Buckling calculations are not performed until the detailed design phase. Hence, the TOCdepth may be adjusted as a result of the buckling analysis to help reduce buckling in somecases.



Casing and Hole Size Selector

Figure 4.4.1

11¾117⁄8

Hole size, in.

Casing size, in.

Hole size, in.

Casing size, in.

Hole size, in.

Casing size, in.

Hole size, in.

Casing size, in.

Casing size, in.

Hole size, in.

Standard

Low Clearance

14¾

16 185⁄8 20 24 30

16 17½ 20 24 26

133⁄8

1416 185⁄8 20

3¾ 4 4¾

4 4½ 5 5½

4¾ 6 6½61⁄857⁄8 77⁄8

65⁄8 7 75⁄8

7¾85⁄8

95⁄8

97⁄8

77⁄8 8½ 8¾ 9½ 105⁄8 12¼

85⁄895⁄8

97⁄810¾ 11¾

117⁄8133⁄8

14

105⁄8 12¼ 14¾ 16 17½



4.6 Directional Plan

For casing design purposes, establishing a directional plan consists of determining thewellpath from the surface to the geological targets. The directional plan will influence allaspects of casing design including mud weight selection for hole stability, shoe seatselection, casing axial load profiles, casing wear, bending stresses, and buckling. It is basedon the following factors:

• Geological targets• Surface location• Interference from other wellbores• Torque and drag considerations• Casing wear considerations (see Section 9.4)• BHA and bit performance in the local geological setting

The directional plan should be optimized using these programs available in the Halliburtondrilling engineering toolkit:

• Torque/Drag program• Casing Wear program

The following additional considerations are suggested when performing the detailed designbased on the directional plan:

• When calculating the effect of bending on tubular stress, the doglegs used in theanalysis should be double the planned well curvature (e.g., if a build rate of 2°/100’ isplanned, a dogleg of 4°/100’ should be used). This will account for the variance fromthe planned build, drop and turn rates which occur due to the bottom hole assembliesused and operational practices employed.

• A minimum 2°/100’ dogleg should be superimposed over the whole wellbore for bothdeviated and straight holes when calculating the effect of bending. This will accountfor the general hole tortuosity which occurs in all wells.


February 1996 Page 1 of 27 Design Loads

Chapter 5 - Design Loads

Contents

5.1 Introduction

5.2 Construction of Load Lines

5.3 Burst and Collapse Load Cases

5.3.1 Conductor and Surface Casing

5.3.2 Intermediate Casing and Liner

5.3.3 Production Casing and Liner

5.3.4 Intermediate and Production Tiebacks

5.4 Axial Load Cases


Design Loads Page 2 of 27 February 1996

5.1 Introduction

Load cases and their corresponding design factors are the criteria used to judge thesuitability of a casing in a design. Dividing the rating of a pipe by a corresponding loadresults in a safety factor. If the safety factor is greater than the design factor, then the pipeis acceptable for use with that load.

The standard load cases listed in this chapter represent Halliburton's normal design basis.Alternate load cases are also listed because they represent frequently used load cases in theindustry and may be required by a client. If a design is based on criteria other than thestandard load cases, it must be checked against the standard load cases also. If the designdoes not meet the standard criteria, the client and appropriate HES management should beinformed of this discrepancy with Halliburton's normal practices and the engineeringconsequences should be discussed.

The burst and collapse load cases are presented in sections based on the casing type. Loadcases for conductor, surface and intermediate casing are essentially the same. The loadcriteria for production casing are quite different and more varied. Engineering judgmentmust be used in determining which standard production load cases are applicable. Theaxial load cases are the same for all strings.

It is important to note the following:

• If a production liner is run below an intermediate casing string and no productiontieback is run, the intermediate casing will be exposed to both drilling and productionloads; however, the production loads will dominate the design.

• Burst and collapse criteria will typically dictate the design. Axial criteria becomeimportant in long intermediate and production casing strings.

• Severe tensile, pressure and buckling loads can result from changes in temperature dueto production and injection operations. These loads can dictate the design in deep hotwells. See Chapter 9 for further discussion of these special cases.

• Drilling riser loads, wellhead loads, structural loading of the conductor, conductorinteraction with a subsea BOP stack, and shared axial loads between strings are notaddressed by the design loads in this Chapter and are outside the scope of this manual.

5.2 Construction Of Load Lines

Rather than compare each load case's profile to the pipe's rating on an individual basis, theapproach taken for conventional burst, collapse and axial design is to combine load casesof the same type (e.g., burst or collapse) into one load line of maximum load as a functionof depth. Figure 5.2.1 shows two burst load cases being combined into a burst load line.



500 1000 1500 2000 2500 3000 3500 4000 4500 5000

0

1500

3000

4500

6000

7500

9000

10500

12000

Differential Burst (psig)

Displacement to Gas

Tubing Leak

A load line consisting of themaximum differentialpressure with depth isformed from the two loadcases.

Figure 5.2.1 - Constructing a Burst Load Line

In order to make a direct graphical comparison between the load line and the pipe's ratingline, the design factor must be taken into account. Recall that:

DF SF SF= ≤ =minpipe rating

applied load(5.2.1)

Where:

DF = design factor (the minimum acceptable safety factor).SF = safety factor.

It follows that:

( )DF × ≤applied load pipe rating (5.2.2)

Hence, by multiplying the load line by the DF, a direct comparison can be made with thepipe rating. As long as the rating is greater than or equal to the modified load line (whichwe will call the design load line), the design criteria has been satisfied. Note that dividingthe rating by the DF yields the same results; however, this is not recommended becauseyou may wish to use different DFs with different load cases. It is easier to make all thecorrections on the load line and keep the rating line constant. The relationship shown inEquation 5.2.2 for burst is shown graphically in Figure 5.2.2.



2400 2800 3200 3600 4000 4400 4800 5200 5600 6000

0

1500

3000

4500

6000

7500

9000

10500

12000

Burst Pressure (psig)

Design Load LineActual Load Line

Multiplying the actual load line by theburst design factor results in thedesign load line.

1500 3000 4500 6000 7500 9000 10500 12000 13500 15000

0

1500

3000

4500

6000

7500

9000

10500

12000

Burst Pressure (psig)

Design Load LineRating Line

The burst rating of 9-5/8” 40 ppf N-80pipe exceeds the burst load line at alldepths. Hence, the burst design criteriahas been satisfied for the productioncasing.

Figure 5.2.2 - Example of Graphical Burst Design

Two other effects which impact design are taken into account in graphical casing design byincreasing the design load line:

• The reduction of collapse strength due to tension. This biaxial effect is discussed inSection 7.2.2. The load line is increased as a function of depth by the ratio of theuniaxial collapse strength to the reduced strength.

• The deration of material yield strength due to temperature. This effect is discussed inSection 7.5. Like the effect of tension on collapse, the load line is increased by theratio of the standard rating to the reduced rating.

If a computing tool such as StressCheck is used during the detailed design phase, all theseadjustments are calculated automatically.



5.3 Burst And Collapse Load Cases

5.3.1 Conductor And Surface Casing

Standard Burst Load Cases

Note: A conductor casing on which a diverter stack is installed only requires a pressuretest as a burst load criterion.

Gas KickReduce kick volume ifpressure profileexceeds the fracturepressure at the shoe.

Influx depthInternal Casing Pressure

Envelope of maximumpressures experiencedwhile circulating gas kickout of the hole.

This load case models an internal pressure profile which reflects themaximum pressures experienced by the casing while circulating out a gaskick using the driller's method. It should represent the worst-case kick towhich the current casing can be exposed while drilling a deeper interval.Typically, this means taking a kick at the TD of the next hole section.This load case is not required for a conductor casing on which a diverterstack is installed.

If the kick intensity or volume cause the fracture pressure at the casingshoe to be exceeded, the kick volume should be reduced to the maximumvolume which can be circulated out of the hole without exceeding thefracture pressure at the shoe. If the kick volume is reduced to a value lessthan the recommended kick tolerance volume (see Section 4.3), the LostReturns With Water load case should also be used to ensure sufficientburst strength at the surface.

The maximum pressure experienced at any casing depth occurs when thetop of the gas bubble reaches that depth. See Well Control Manualdecision tree options and special well control issues for more informationon kick control.

Warning: If a well control situation develops where a significant volumeof gas is circulated into the casing while losing returns in the open holeinterval, a casing string designed using the gas kick criteria may nothave sufficient burst resistance to withstand the higher resultantpressures. This could result in a casing failure at a shallow depth (see



Alternate Burst Load Cases below).

Suggested load case parameters (which may be altered based onlocal/regional practices and experience):

Kick Intensity: 0.5 ppg above the mud weight in the hole when thekick occurs. In exploration wells where the porepressure uncertainty is greater, this value may beincreased. Typically, this is not an issue in shallowhole.

Kick Volume: 70 bbls for development wells and 100 bbls forexploration wells.

Frac Error Margin: Between 0.5 ppg for a development well and 2.0ppg for a rank wildcat. The larger the frac errormargin, the greater the pressure to which the casingcan be exposed without exceeding the fracturepressure.

Lost ReturnsWith Water

Internal Casing Pressure

Fracture pressureat the shoeFresh water

gradient

This load case models an internal pressure profile which reflects pumpingwater down the annulus to reduce surface pressure during a well controlsituation where lost returns are occurring. The pressure profile representsa fresh water gradient applied upward from the fracture pressure at theshoe depth. A water gradient is used assuming that the rig's barite supplyhas been depleted during the well control incident. This load case may ormay not dominate the burst design when compared to the gas kick loadcase, depending on the annular volume between the casing and thedrillpipe, and the kick volume.

This load case should be considered if the recommended kick tolerancediscussed in Section 4.3 is not met or a risk of lost returns otherwiseexists. It is not required for a conductor casing on which a diverter stackis installed.

Suggested load case parameters:

Frac Error Margin: Between 0.5 ppg for a development well and 2.0



ppg for a rank wildcat.

Pressure Test(If Performed)


Applied surfacepressure

Mud gradient

This load case models an internal pressure profile which reflects a surfacepressure applied to a mud gradient. The test pressure typically is basedon the maximum anticipated surface pressure determined from the otherselected burst load cases plus a suitable safety margin (e.g. 500 psi). Thisload case may or may not dominate the burst design depending on themud weight in the hole at the time the test occurs. The pressure test isnormally performed prior to drilling out the float equipment. For aconductor casing on which a diverter stack is installed, the appliedpressure should represent the desired pressure during the leak-off test (ifperformed).

BurstExternalPressureProfile

External Casing Pressure

Mud gradient

Mix-watergradient

Pore pressure

The external pressure profile used for all the standard burst load casesshould reflect the following parameters:

• Mud weight from the surface to the top of cement (TOC).

• If the TOC is above the prior shoe, a cement mix-water gradient fromthe TOC to the depth of the prior shoe.

• Pore pressure in the cemented portion exposed to open hole.

If a mud with poor long-term solids suspensions properties (e.g., apolymer mud or some oil-base muds) is above the TOC or the local holeangle is greater than 30°, a fluid gradient based on the base fluid of themud should be considered. Most conductor and surface strings arecompletely cemented; hence, mud weight won't typically be an issue. Thisexternal pressure profile can be modelled in StressCheck using theAbove/Below TOC profile.



Alternate Burst Load Cases

Displacementto Gas

Limit load caseby the fracturepressure at theshoe.


Gas gradient

Pore pressure

Fracture pressureat shoe

This load case models an internal pressure profile consisting of a gasgradient extending upward from a formation pressure in a deeper holeinterval or from the fracture pressure at the casing shoe. It physicallyrepresents a well control situation where gas from a kick has completelydisplaced the mud out of the drilling annulus from the surface to thecasing shoe. This is the worst-case drilling burst load that a conductor orsurface string could experience, and if the fracture pressure at the shoe isused to determine the pressure profile, it ensures that the weak point inthe system is at the casing shoe and not the surface. This, in turn,precludes a burst failure of the casing near the surface during a severewell control situation.

The safety aims of this burst load criterion which has wide use in theindustry are laudable; however, a casing string meeting this criterion canbe over-designed. Depending on the casing diameter, shoe depth andfracture pressure at the shoe, the gas kick load case may result in a verysimilar load (e.g., the specified kick volume will displace all the mud outof the casing as the gas bubble is circulated out of the hole).

SurfaceProtection(BOP)


Fracture pressureat the shoe

Fresh water gradient

Gasgradient

This load case is less severe than the displacement to gas criteria andrepresents a moderated approach to preventing a surface blowout during



a well control incident. The same surface pressure calculated in the LostReturns With Water load case is used, but in this load case, a gas gradientfrom this surface pressure is used to generate the rest of the pressureprofile. This load case represents no actual physical scenario; however,when used with the gas kick criterion, it ensures that the casing weakpoint is not at the surface. Typically, the gas kick load case will controlthe design deep and the surface protection load case will control thedesign shallow, leaving the string's weak point somewhere in the middle.

AlternateExternalPressureProfiles

There are numerous external pressure profiles used in the industry. SeeStressCheck's on-line help or User's Guide for descriptions of several ofthese. One very common and conservative external pressure assumptionused in burst design is to assume a normal pressured gradient (e.g., 0.465psi/ft) over the entire length of the casing string regardless of the mudweight used, the TOC depth, or the pore pressure. Another commonassumption is to model a drop in the mud level based on the mudhydrostatic column equilibrating with the pore pressure at the TOC depth.

Standard Collapse Load Cases

Cementing

Casing Pressures Cement slurry

Mud gradient

Slurry gradient

Displacement fluid gradient

This load case models an internal and external pressure profile whichreflects the collapse load imparted on the casing after the plug has beenbumped during the cement job and the pump pressure bled off. Theexternal pressure considers the mud hydrostatic column and differentdensities of the lead and tail cement slurries. If a light displacement fluidis used, the cementing collapse load can be significant.



Lost ReturnsWith MudDrop

Mud drop due tohydrostatic columnequilibrating withpore pressure

Lost circulation zoneInternal Casing Pressure

Mud gradient

Pore pressure

This load case models an internal pressure profile which reflects a partialevacuation or a drop in the mud level due to the mud hydrostatic columnequilibrating with the pore pressure in a lost circulation zone. Theheaviest mud weight used to drill the next hole section should be usedalong with a pore pressure and depth which result in the largest muddrop. This depth and pressure will be determined automatically ifStressCheck is being used.

For exploration wells where data is limited, many operators assume thelost circulation zone to be at the TD of the next hole section and benormally pressured (e.g., a 0.465 gradient). This can result in anexcessive collapse load for high pressure wells which require high mudweights. This is typically not an issue for surface and conductor strings.

FullEvacuation(Air or FoamDrilling)

This load case should be considered if drilling with air or foam.

CollapseExternalPressureProfile


Mud gradient

TOC depth

Prior shoe

The external pressure profile used for all the standard collapse load cases(except Cementing which calculates an external pressure profileconsidering the cement slurry densities) should be a mud gradient fromthe surface to the casing shoe. This profile assumes that poor cement



displacement has resulted in channeling so that a mud gradient is seenbelow the TOC. This external pressure profile can be modelled inStressCheck using the Above/Below TOC profile.

Salt Loads


Salt zone

Mud gradient

Overburden gradient

If a formation which exhibits plastic behavior such as a salt zone is to beisolated by the current string, an equivalent external collapse load(typically taken to be the overburden pressure) should be superimposedupon all of the collapse load cases (except Cementing) from the top to thebase of the salt zone.

Alternate Collapse Load Cases

WaterGradient

For wells with a sufficient water supply, an internal pressure profileconsisting of a fresh water or seawater gradient is sometimes used as acollapse criterion. This assumes a lost circulation zone that can onlywithstand a water gradient.

FullEvacuation

A full evacuation is a potentially severe drilling collapse criterion. If theconductor or surface string is short and a long hole section is drilledbeneath it, a full evacuation may result from the Lost Returns load casediscussed above. A full evacuation can also occur if the casing is notfilled up as it is run in the hole.

AlternatePartialEvacuation

Not all companies use the Lost Returns With Mud Drop methodology todetermine a partial evacuation depth. Another common method is toassume a percentage of the open hole TD (typically 33%) as themaximum evacuation depth.


There are numerous external pressure profiles used in the industry. SeeStressCheck's on-line help or User's Guide for descriptions of several ofthese.



5.3.2 Intermediate Casing And Liner


Gas KickReduce kick volume ifpressure profileexceeds the fracturepressure at the shoe.


Envelope of maximumpressures experiencedwhile circulating gas kickout of the hole.

This load case models an internal pressure profile which reflects themaximum pressures experienced by the casing while circulating out a gaskick using the driller's method. It should represent the worst-case kick towhich the current casing can be exposed while drilling a deeper interval.Typically, this means taking a kick at the TD of the next hole section.

If the kick intensity or volume cause the fracture pressure at the casingshoe to be exceeded, the kick volume should be reduced to the maximumvolume which can be circulated out of the hole without exceeding thefracture pressure at the shoe. If the kick volume is reduced to a value lessthan the recommended kick tolerance volume (see Section 4.3), the LostReturns With Water load case should also be used to ensure sufficientburst strength at the surface.

The maximum pressure experienced at any casing depth occurs when thetop of the gas bubble reaches that depth. See Well Control Manualdecision tree options and special well control issues for more informationon kick control.

Warning: If a well control situation develops where a significant volumeof gas is circulated into the casing while losing returns in the open holeinterval, a casing string designed using the gas kick criteria may nothave sufficient burst resistance to withstand the higher resultantpressures. This could result in a casing failure at a shallow depth (seeAlternate Burst Load Cases below).

Suggested load case parameters (which may be altered based onlocal/regional practices and experience):

Kick Intensity: 0.5 ppg above the mud weight in the hole when thekick occurs. In exploration wells where the pore



pressure uncertainty is greater, this value may beincreased. Typically, this is not an issue in shallowhole.

Kick Volume: 70 bbls for development wells and 100 bbls forexploration wells.

Frac Error Margin: Between 0.5 ppg for a development well and 2.0ppg for a rank wildcat. The larger the frac errormargin, the greater the pressure to which the casingcan be exposed without exceeding the fracturepressure.

Lost ReturnsWith Water


Fracture pressureat the shoeFresh water

gradient

This load case models an internal pressure profile which reflects pumpingwater down the annulus to reduce surface pressure during a well controlsituation where lost returns are occurring. The pressure profile representsa fresh water gradient applied upward from the fracture pressure at theshoe depth. A water gradient is used assuming that the rig's barite supplyhas been depleted during the well control incident. This load case willtypically dominate the burst design when compared to the gas kick loadcase because a water gradient is usually less (e.g., steeper) than thepressure profile resulting from circulating a gas bubble out of the holewith mud.

This load case should be considered if the recommended kick tolerancediscussed in Section 4.3 is not met or a risk of lost returns otherwiseexists.

Suggested load case parameters:

Frac Error Margin: Between 0.5 ppg for a development well and 2.0ppg for a rank wildcat.



Pressure Test



Mud gradient

This load case models an internal pressure profile which reflects a surfacepressure applied to a mud gradient. The test pressure typically is basedon the maximum anticipated surface pressure determined from the otherselected burst load cases plus a suitable safety margin (e.g. 500 psi). Thisload case may or may not dominate the burst design depending on themud weight in the hole at the time the test occurs. The pressure test isnormally performed prior to drilling out the float equipment.



Mud gradient

Mix-watergradient

Pore pressure





If a mud with poor long-term solids suspensions properties (e.g., apolymer mud or some oil-base muds) is above the TOC or the local holeangle is greater than 30°, a fluid gradient based on the base fluid of themud should be considered. This external pressure profile can be modelledin StressCheck using the Above/Below TOC profile.




Displacementto Gas

Limit load caseby the fracturepressure at theshoe.


Gas gradient

Pore pressure


This load case models an internal pressure profile consisting of a gasgradient extending upward from a formation pressure in a deeper holeinterval or from the fracture pressure at the casing shoe. It physicallyrepresents a well control situation where the well has been shut in afterallowing gas from a kick to completely displace the mud out of thedrilling annulus from the surface to the casing shoe. This is the worst-case drilling burst load that an intermediate string could experience, and ifthe fracture pressure at the shoe is used to determine the pressure profile,it ensures that the weak point in the system is at the casing shoe and notthe surface. This, in turn, precludes a burst failure of the casing near thesurface during a severe well control situation.

The safety aims of this burst load criterion which has wide use in theindustry are laudable; however, a casing string meeting this criterion canbe over-designed.

MaximumLoad Concept


Fracturepressure atthe shoe

Gas gradient

Mud gradient

This load case is a variation of the displacement to gas load case that haswide usage in the industry and is taught in several popular casing designschools. It has been used historically because it results in an adequatedesign (though typically quite conservative, particularly for wells deeperthan 15000') and it is simple to calculate. The load case consists of a gasgradient (typically 0.1 psi/ft) extending upward from the fracture pressureat the shoe up to a mud/gas interface and then a mud gradient to the



surface.

The mud/gas interface is calculated in a number of ways, the mostcommon being the "fixed endpoint" method. The interface is calculatedbased on a surface pressure typically equal to the BOP rating and thefracture pressure at the shoe and assuming a continuous pressure profile.The interface can also be based on a specific gas volume or a percentageof the open hole TD.

For this load case to actually occur during drilling operations, gas musthave been allowed to enter the casing after returns were lost in the openhole interval. The preferred approach is to use the gas kick load case.

SurfaceProtection(BOP)


Fracture pressureat the shoe

Fresh water gradient

Gasgradient

This load case is less severe than the displacement to gas criteria andrepresents a moderated approach to preventing a surface blowout duringa well control incident. It is not applicable to liners. The same surfacepressure calculated in the Lost Returns With Water load case is used, butin this load case, a gas gradient from this surface pressure is used togenerate the rest of the pressure profile. This load case represents noactual physical scenario; however, when used with the gas kick criterion,it ensures that the casing weak point is not at the surface. Typically, thegas kick load case will control the design deep and the surface protectionload case will control the design shallow, leaving the string's weak pointsomewhere in the middle.

GasMigration(Subsea wells)

Protective Casing Internal Pressure

Mudgradient

Gasbubble


Reservoirpressure

This load case models bottomhole pressure applied at the wellhead(subject to fracture pressure at the shoe) from a gas bubble migrating



upward behind the production casing with no pressure bled off at thesurface. The load case only has application in subsea wells where theoperator has no means of accessing the annulus behind the productioncasing.


There are numerous external pressure profiles used in the industry. SeeStressCheck's on-line help or User's Guide for descriptions of several ofthese. One very common and conservative external pressure assumptionused in burst design is to assume a normal pressured gradient (e.g., 0.465psi/ft) over the entire length of the casing string regardless of the mudweight used, the TOC depth, or the pore pressure. In high pressurereservoirs, this can result in a very conservative design. Another commonassumption is to model a drop in the mud level based on the mudhydrostatic column equilibrating with the pore pressure at the TOC depth.

Standard Collapse Load Cases

Cementing


Mud gradient

Slurry gradient





Lost ReturnsWith MudDrop

Mud drop due tohydrostatic columnequilibrating withpore pressure

Lost circulation zoneInternal Casing Pressure

Mud gradient

Pore pressure

This load case models an internal pressure profile which reflects a partialevacuation or a drop in the mud level due to the mud hydrostatic columnequilibrating with the pore pressure in a lost circulation zone. Theheaviest mud weight used to drill the next hole section should be usedalong with a pore pressure and depth which result in the largest muddrop. This depth and pressure will be determined automatically ifStressCheck is being used.

For exploration wells where data is limited, many operators assume thelost circulation zone to be at the TD of the next hole section and benormally pressured (e.g., a 0.465 gradient). This can result in anexcessive collapse load for high pressure wells which require high mudweights. A partial evacuation of more than 5000' due to lost circulationduring drilling will normally not be seen.

FullEvacuation(Air or FoamDrilling)

This load case should be considered if drilling with air or foam.



Mud gradient

TOC depth

Prior shoe

The external pressure profile used for all the standard collapse load cases(except Cementing which calculates an external pressure profileconsidering the cement slurry densities) should be a mud gradient from



the surface to the casing shoe. This profile assumes that poor cementdisplacement has resulted in channeling so that a mud gradient is seenbelow the TOC. This external pressure profile can be modelled inStressCheck using the Above/Below TOC profile.

Salt Loads


Salt zone

Mud gradient

Overburden gradient



WaterGradient

For wells with a sufficient water supply, an internal pressure profileconsisting of a fresh water or seawater gradient is sometimes used as acollapse criterion. This assumes a lost circulation zone that can onlywithstand a water gradient.

FullEvacuation

A full evacuation is a severe drilling collapse criterion and has applicationwith air or foam drilling.

AlternatePartialEvacuation

Not all companies use the Lost Returns With Mud Drop methodology todetermine a partial evacuation depth. Another common method is toassume a percentage of the open hole TD (typically 33%) as themaximum evacuation depth.





5.3.3 Production Casing And Liner


Tubing Leak


Produced fluid(gas) gradient

Completionfluid gradient

Reservoir pressure

This load case applies to both production and injection operations andrepresents a high surface pressure on top of the completion fluid due to atubing leak near the hanger. A worst case surface pressure is usuallybased on a gas gradient extending upward from reservoir pressure at theperforations. If the proposed packer location has been determined whenthe casing is designed, the casing below the packer can be assumed toexperience a pressure based on the produced fluid gradient and reservoirpressure only.

Pressure Test



Fluidgradient

This load case models an internal pressure profile which reflects a surfacepressure applied to a mud gradient. The test pressure typically is basedon the anticipated shut-in tubing pressure plus a suitable safety margin(e.g. 500 psi). This load case may or may not dominate the burst designdepending on the fluid weight in the hole at the time the test occurs.



InjectionDown Casing



Fluidgradient

This load case applies to wells which experience high pressure annularinjection operations such as a casing fracture stimulation job. The loadcase models a surface pressure applied to a static fluid column. This isanalogous to a screen-out during a frac job.



Mud gradient

Mix-watergradient

Pore pressure





If a mud with poor long-term solids suspensions properties (e.g., apolymer mud or some oil-base muds) is above the TOC or the local holeangle is greater than 30°, a fluid gradient based on the base fluid of themud should be considered. This external pressure profile can be modelledin StressCheck using the Above/Below TOC profile.



There are numerous external pressure profiles used in the industry. SeeStressCheck's on-line help or User's Guide for descriptions of several ofthese. One very common and conservative external pressure assumptionused in burst design is to assume a normal pressured gradient (e.g., 0.465psi/ft) over the entire length of the casing string regardless of the mudweight used, the TOC depth, or the pore pressure. In high pressure



reservoirs, this can result in a very conservative design. Another commonassumption is to model a drop in the mud level based on the mudhydrostatic column equilibrating with the pore pressure at the TOC depth.

Standard Collapse Load Cases (General)

Cementing


Mud gradient

Slurry gradient





Mud gradient

TOC depth

Prior shoe

The external pressure profile used for all the standard collapse load casesshould be a mud gradient from the surface to the casing shoe. This profileassumes that poor cement displacement has resulted in channeling so thata mud gradient is seen below the TOC. This external pressure profile canbe modelled in StressCheck using the Above/Below TOC profile.



Salt Loads


Salt zone

Mud gradient

Overburden gradient


Standard Collapse Load Cases (Above Packer)

Note: The collapse design criteria for production collapse load cases are quite variedand highly dependent upon the productive life of the well, artificial lift methods, andproduction zone characteristics. All these issues should be discussed thoroughly with theclient's production engineering representative.

FullEvacuation


Gas filledannulus

Full evacuation (gasgradient with nosurface pressure)

0

This severe load case has the most application in gas lift wells. It isrepresentative of a gas filled annulus which loses injection pressure.

PartialEvacuation

Fluid drop due tohydrostatic columnequilibrating withreservoir pressure


Completion fluidgradient

Depleted reservoirpressure

This load case is based on a hydrostatic column of completion fluidequilibrating with depleted reservoir pressure during a workover



operation. In StressCheck, this is modelled using the Above/BelowPacker load case with the mud drop option enabled.

Standard Collapse Load Cases (Below Packer)

FullEvacuation

This load case applies to severely depleted reservoirs or a largedrawdown of a low permeability reservoir. It is the best load case to useif not much information is known about the production reservoir. InStressCheck, this is modelled using the Above/Below Packer load case orFull Evacuation load case (depending upon what you are modelling abovethe packer).

FluidGradient

This load case assumes zero surface pressure applied to a fluid gradient.It is a less conservative criterion for formations which will never bedrawn down to zero. In StressCheck, this is modelled using theAbove/Below Packer load case.


FullEvacuation

Some companies assume a full evacuation over the whole length of casingin all cases. This is a conservative criterion.

CompletionFluidGradientAbove Packer

Some companies assume a completion fluid gradient above the packerwith no fluid drop. This is a non-conservative criterion. In StressCheck,this is modelled using the Above/Below Packer load case with the muddrop option disabled.



GasMigration(Subsea wells)

Production Casing External Pressure

Mudgradient

GasbubbleFracture pressure

at prior shoe

Reservoirpressure

This load case models bottomhole pressure applied at the wellhead(subject to fracture pressure at the prior shoe) from a gas bubblemigrating upward behind the production casing with no pressure bled off



at the surface. The load case only has application in subsea wells wherethe operator has no means of accessing the annulus behind the productioncasing.

5.3.4 Intermediate And Production Tiebacks

Burst andCollapse LoadCases

Same as the corresponding casing load cases already described in thischapter.

ExternalPressureProfile

External Tieback Pressure

Mud gradient

TOC depth

Mix-water gradient

Tieback

A mud hydrostatic column to the top of cement and a cement mix-watergradient below should be used. In StressCheck, this is modelled using theMud Cement Mix-Water load case.

For burst loads only, if a mud with poor long-term solids suspensionsproperties (e.g., a polymer mud or some oil-base muds) is above the TOCor the local hole angle is greater than 30°, a fluid gradient based on thebase fluid of the mud should be considered.

5.4 Axial Load Cases

Standard Axial Load Cases

Running InHole

This installation load case represents the maximum axial load that anyportion of the casing string experiences when running the casing in thehole. It includes the following effects:

• Self weight.• Buoyancy forces at the end of the pipe and at each cross-sectional

area change.• Wellbore deviation.• Bending loads superimposed in dogleg regions.• Shock loads based on an instantaneous deceleration from a velocity

50% greater than the average running speed (typically 2-3 ft/sec).

No drag forces are considered. Typically, the maximum axial loadexperienced by any joint in the casing string is the load when the joint ispicked up out of the slips after being made up.



OverpullWhileRunning

This installation load case models an incremental axial load applied at thesurface while running the pipe in the hole. Casing designed using thisload case should be able to withstand an overpull force applied with theshoe at any depth if the casing becomes stuck while running in the hole.The following effects are considered:


area change.• Wellbore deviation.• Bending loads superimposed in dogleg regions.• The applied overpull force.

An overpull force of 100,000 lbs is recommended.

GreenCementPressure Test

This installation load case models applying surface pressure after bumpingthe plug during the primary cement job. Since the cement is still in itsfluid state, the applied pressure will result in a large piston force at thefloat collar and often results in the worst case surface axial load. Thefollowing effects are considered:


area change.• Wellbore deviation.• Bending loads superimposed in dogleg regions.• Piston force due to differential pressure across float collar.

The applied pressure should be based on operational practices. A worstcase test pressure should be based on the maximum anticipated surfacepressure dictated by the burst load cases for this string.

Service Loads For most wells, the three installation loads described above will controlaxial design. However, in wells with uncemented sections of casing andwhere large pressure or temperature changes will occur after the casing iscemented in place, changes in the axial load distribution due to the burstand collapse design load cases can be important. The following effectsare considered:

• Self weight.• Buoyancy forces.• Wellbore deviation.• Bending loads.• Changes in internal or external pressure (ballooning).• Temperature changes.



• Buckling.

Service loads and their effect on buckling are discussed in more detail inChapter 9.

Alternate Axial Load Cases

Air Weight ofCasing Only

This axial load criterion has been used historically because it is an easycalculation to perform and it normally results in adequate designs. It stillenjoys significant usage in the industry today. Because a large number offactors are not considered, it is typically used with a high axial designfactor (e.g., 1.6+).

BuoyedWeight PlusOverpull Only

Like the Air Weight criterion, this load case has wide usage because it isan easy calculation to perform. Because a large number of factors are notconsidered, it is typically used with a high axial design factor (e.g., 1.6+).


February 1996 Page 1 of 3 Design Factors

Chapter 6 - Design Factors

Contents

6.1 Basis

6.2 Relationship Between Design Loads and Factors


Design Factors Page 2 of 3 February 1996

6.1 Basis

A design factor is defined as the minimum acceptable safety factor. A safety factor is theload resistance (or pipe rating) divided by the applied load. An acceptable design results inall safety factors at all depths being greater than or equal to the design factors for thecorresponding design loads. The design factors used as a basis for Halliburton’s casingdesign are summarized in Table 6.1.1.

Table 6.1.1Design Factors

Criterion Design Factor Comments

Burst

Gas Kick Load Case

All Other Load Cases

1.2

1.1

The burst design factors correspond to a12.5% wall loss. The higher designfactor for the gas kick load case isdiscussed in Section 6.2.

Collapse 1.0 The collapse design factor corresponds tonominal dimensions.

Axial

Pipe body

API Connections

Premium Connections

1.3

See Section 9.1.3

See Section 9.1.4

The axial design factors correspond tonominal dimensions. API connectionaxial design factors are greater than thepipe body factor by the ratio of theultimate tensile strength to the yieldstrength.

Triaxial 1.25 The triaxial design factor corresponds tonominal dimensions.

The rationale for using a reduced wall section for burst analysis and nominal dimensions forcollapse and axial analysis is discussed in Chapter 7. Similarly, Chapter 8 discusses whynominal dimensions are used in triaxial analysis.

6.2 Relationship Between Design Loads And Factors

Recent work using a statistical approach to structural reliability to provide a method ofdesigning casing based on acceptable risk1 has emphasized the relationship between thedesign method and the design factors. In general, the more conservative the designassumptions, the lower the design factor should be to result in the same acceptable level ofrisk and vice versa. Also influencing the design factor value is the uncertainty associatedwith a load case. The higher the uncertainty, the greater the design factor (e.g., all elsebeing equal, exploration wells should be designed using higher design factors thandevelopment wells).

1 Adams, Adrian, et. al., “Casing System Risk Analysis Using Structural Reliability”, SPE/IADC 25693,Proc. 1993 SPE/IADC Drilling Conference, February 1993, pp. 169-178.


February 1996 Page 3 of 3 Design Factors

The three most important aspects of the design method that will have a direct effect on theappropriate design factor value are:

• Selection of load cases and the assumptions used with the load cases (e.g., use of alimited kick criterion vs. a full displacement to gas, the kick volume and intensity used,whether bending due to doglegs or shock loads are considered, etc.).

• The assumptions used to calculate the pipe’s load resistance or rating (e.g., whether anominal or minimum wall section is used and whether yield stress is derated as afunction of temperature). Pipe ratings are discussed in Chapter 7.

• How wear and corrosion are considered in the design. This is discussed in Chapter 9.

Historically, design load cases have been selected for use based on two criteria: (1) theyreflected worst-case loads and (2) they were easy to calculate. If the standard load casedid not consider all the loads which would be experienced by the casing, the design factorwas increased accordingly (e.g., a high 1.6 design factor used in tension with the buoyedweight axial load distribution which does not consider the effects of bending and shockloads). This led to the “maximum load” design concept2 which still enjoys wide usagetoday. In general, design factors became accepted over time based on the small number offailures associated with their use. When failures did occur, the design basis was examinedand design factors or load cases were made more conservative to prevent the failure fromreoccurring. This dictated that design assumptions would be typically based on worst-casescenarios. With the computing tools available to today’s design engineer, many complexloading scenarios can easily be evaluated instead of relying on one simple “worst-case”scenario. In addition, risk-calibrated design factors can be used to arrive at an equally safeyet more economic design.

The design factors specified in Section 6.1 are intended to be used with the standard loadcases described in Chapter 5. If other load cases are used, different design factors will berequired to result in a design with the same reliability. For example, if the displacement togas load case is used as a drilling burst criterion, a design factor of 0.8-0.9 would result ina comparable reliability as using the gas kick criterion with a 1.2 design factor. Regardlessof how conservative their load case assumptions are, most operators are unwilling to usedesign factors less than 1.0.

If different load cases or design factors are used, the resulting design must be checkedagainst Halliburton’s standard design assumptions (see Section 5.1).

The higher design factor of 1.2 used with the gas kick load case reflects the fact that this isnot the most conservative design criterion available and that there is more uncertaintyassociated with a gas kick than the other burst design loads. The same design factor isused for both development and exploration wells because the influx volume used withdevelopment wells is 70 bbls vs. 100 bbls for exploration wells.

2 Prentice, Charles M., ‘"Maximum Load" Casing Design’, Journal of Petroleum Technology, July 1970,pp. 805-811.


February 1996 Page 1 of 8 Pipe Ratings

Chapter 7 - Pipe Ratings

Contents

7.1 Burst Strength

7.2 Collapse Strength

7.2.1 Collapse Strength Equations

7.2.2 The Effect of Tension On Collapse Resistance

7.2.3 The Effect of Internal Pressure On Collapse Resistance

7.3 Axial Strength

7.4 Reduced Wall vs. Nominal Dimensions

7.5 Deration of Yield Strength With Temperature


Pipe Ratings Page 2 of 8 February 1996

7.1 Burst Strength

The burst strength of the pipe body is determined by the internal yield pressure formulafound in API Bulletin 5C3.

PY tD

p=

08752

. (7.1.1)

Where:

P = minimum internal yield pressure.Yp = minimum yield strength.

t = nominal wall thickness.D = nominal outside diameter.

Equation 7.1.1, commonly known as the Barlow Equation, calculates the internal pressureat which the tangential (or hoop) stress at the inner wall of the pipe reaches the yieldstrength (YS) of the material. The expression can be derived from the Lamé equation fortangential stress by making the thin wall assumption that D/t >> 1. Most casing used in theoilfield has a D/t ratio between 15 and 25. The factor of 0.875 appearing in the equationrepresents the allowable manufacturing tolerance of -12.5% on wall thickness specified inAPI Specification 5CT (see Section 7.4).

Since a burst failure will not occur until after the stress exceeds the ultimate tensile strength(UTS), using a yield strength criterion as a measure of burst strength is an inherentlyconservative assumption. This is particularly true for lower grade materials such H-40,K-55 and N-80 whose UTS/YS ratio is significantly greater than that of higher gradematerials such as P-110 and Q-125.

This burst criterion has three major deficiencies:

1. For thick wall pipes with a D/t ratio < 12, the thin wall assumption is non-conservative.

2. The effect of axial load is ignored. This is a non-conservative assumption if the pipe isin compression, a conservative assumption for low to moderate tensile loads, and anon-conservative assumption for high tensile loads.

3. Instead of accounting for the external pressure as a separate variable, the appliedinternal pressure is taken to be the differential pressure, Pi − Po. This is a conservativeassumption.

If a triaxial stress check is performed after an axial design has been established, all three ofthese deficiencies can be quantified and the design modified, if necessary. See Chapter 8for a discussion of triaxial design. Figure 7.1.1 compares an API burst rating with anellipse representing the triaxial yield criterion. The first two deficiencies can be plainly seenin this plot.



0

50

100

150

-100 -50 0 50 100 150

Percentage of Pipe Body Yield Strength

Per

cen

tag

e o

f A

PI B

urs

t R

atin

g

API Burst Rating

Triaxial Rating

Thin wall assumption is non-conservative for thick wall pipes.

TensionCompression

API rating is non-conservative in compression

API rating is conservative for most tensile loads

Figure 7.1.1 - API Burst Rating vs. Triaxial Rating

7.2 Collapse Strength

In API Bulletin 5C3, different equations are given to characterize collapse strength in fourregions based on the pipe's D/t ratio and yield strength. To account for some non-conservative combined loading effects, equations are also given for the effect of tensionand internal pressure on collapse strength.

Many manufacturers market “high collapse” casing which they claim has collapseperformance properties which exceed the ratings calculated using the formulae in APIBulletin 5C3. This improved performance is achieved principally by using bettermanufacturing practices and stricter quality assurance programs to reduce ovality, residualstress and eccentricity. High collapse casing was initially developed for use in the deepersections of high pressure wells. The use of high collapse casing has gained wideacceptance in the industry, but its use remains controversial among some operators.1

Unfortunately, all manufacturers’ claims have not been substantiated with the appropriatelevel of qualification testing. If high collapse casing is deemed necessary in a design,appropriate expert advice should be obtained to evaluate the manufacturer’s qualificationtest data.

1 Klementich, Erich F., “A Rational Characterization of Proprietary High Collapse Casing Grades”,SPE 30526, Proc. 1995 SPE Conference, October 1995.



7.2.1 Collapse Strength Equations

For thin wall pipes (D/t > 25±), the equation given in API 5C3 is based on a theoreticalequation describing an elastic instability failure of the wall which occurs before the yieldstrength of the material is reached.

( )P

D t D tE =

×

−

46 95 10

1

6

2

.

/ /(7.2.1)

Where:

PE = elastic collapse pressure.t = nominal wall thickness.

D = nominal outside diameter.

However, for thick wall pipes (D/t < 15±), the equation given in API 5C3 is based on theLamé equation for tangential stress reaching the yield strength at the inner wall of the pipebefore the instability failure occurs.

( )( )

P YD t

D tY pp=

−

21

2

/

/(7.2.2)

Where:

PYp= yield strength collapse pressure.

Yp = minimum yield strength.

The majority of the pipes used in the oilfield have a slenderness ratio in the range15 < D/t < 25 and do not exhibit collapse behavior which can be described by eitherEquation 7.2.1 or 7.2.2. The failure mechanism here appears to be an inelastic stabilityfailure for which no satisfactory theoretical expression has been derived. Overapproximately half of this range, the API collapse criterion is based on 2488 collapse testsperformed on K-55, N-80 and P-110 seamless casing. A regression analysis wasperformed using this data to arrive at the “plastic” collapse pressure equation. Between theplastic and elastic regions, a numerical curve fit was used to characterize “transition”collapse pressure. The plastic and transition equations are not repeated here, but can befound in API Bulletin 5C3.



In summary, the collapse equations used in API Bulletin 5C3 shown in order of increasingD/t ratio are:

Yield strength collapse Not a collapse pressure at all, but the pressure at which the pipebegins to yield at the inner wall based on the Lamé thick wallelastic equation.

Plastic collapse Based on empirical data from 2488 tests.

Transition collapse A numerical curve fit between the plastic and elastic regions.

Elastic collapse Based on theoretical elastic collapse, this criterion isindependent of yield strength and applicable to thin wall pipe.

7.2.2 The Effect Of Tension On Collapse Resistance

As casing is subjected to increasing axial stress due to tension, its collapse resistance willdecrease. This effect is calculated in API Bulletin 5C3 by decreasing the apparent yieldstrength of the material.

YSY

SY

Ypaa

p

a

pp= −

−

1 075 052

. . (7.2.3)

Where:

Ypa = reduced yield strength of axial stress equivalent grade.Sa = axial stress.Yp = minimum yield strength.

This reduced yield strength is then used with the appropriate collapse equation to calculatea reduced collapse resistance. Equation 7.2.3 is based on the Hencky-von Mises maximumstrain energy of distortion theory of yielding. This is the theory used to derive the triaxialor von Mises equivalent (VME) stress. In this case, the radial stress is assumed to benegligible (a thin wall assumption).

Equation 7.2.3 is a biaxial effect which only applies to elastic yield failure (i.e., the yieldcollapse region). However, it is applied to all of the collapse regions discussed in Section7.2.1. This is a conservative assumption since with increasing D/t ratios, the effects ofelastic instability reduce the amount of correction required.

It should also be noted that for low and moderate levels of negative axial load orcompression, the collapse resistance is increased. This increased resistance is not normallyconsidered in collapse design.

7.2.3 Resistance

In the identical fashion as with increasing tension, casing subjected to increasing internalpressure will have its collapse resistance decreased. Instead of reducing the collapse



resistance as a function of internal pressure, the API has chosen to increase the apparentapplied collapse pressure as a function of internal pressure and D/t.

( )P P

D tPe o i= − −

1

2/

(7.2.4)

Where:

Pe = equivalent external pressure.Po = external pressure.Pi = internal pressure.

Note that Pe is always greater than or equal to the differential pressure, Po - Pi. Thisrelationship can be derived from Lamé and von Mises if higher order terms are ignored.To provide a more intuitive understanding of this relationship, Equation 7.2.4 can berewritten as

P D P D Pde o i= − (7.2.5)

Where:

d = nominal inside diameter.

Here it can be seen that the equation is based on the external pressure acting on the outsidediameter and the internal pressure acting on the inside diameter.

7.3 Axial Strength

The axial strength of the pipe body is determined by the pipe body yield strength formulafound in API Bulletin 5C3.

( )F D d Yy p= −4

2 2 (7.3.1)

Where:

Fy = pipe body axial strength (units of force).Yp = minimum yield strength.D = nominal outer diameter.d = nominal inner diameter.

Note that the axial strength is the product of the cross-sectional area and the yield strengthand that the formula is based on nominal dimensions. The manufacture of seamless pipeper API Specification 5CT allows for much greater variances in wall thickness due toeccentricity (see Section 7.4) than variances in the nominal diameters. Hence, the use ofnominal dimensions is not a bad assumption. Axial strengths less than the nominal valuecalculated using Equation 7.3.1 are accounted for in the design process by using a designfactor of 1.3 (see Section 6.2).



7.4 Reduced Wall Vs. Nominal Dimensions

The use of a minimum wall section when calculating the burst rating of casing is practicallyuniversal in the oilfield. The minimum section represents a permissible 12.5% wall loss dueto acceptable tolerances in the piercing and rolling process of manufacturing seamless pipe(see Figure 7.4.1). This is consistent with the internal yield pressure equation used in APIBulletin 5C3 to characterize burst resistance.

Similarly, the use of a wall section based on nominal dimensions to calculate collapse andaxial resistance is nearly as widespread. Most collapse failures in the oilfield are inelasticstability failures for which no standard theoretical equation has been derived. Theexpression for “plastic” collapse used in API Bulletin 5C3 is based on a statisticalregression analysis on empirical data. The statistical analysis accounts for dimensionaltolerances; hence, nominal dimensions should be used with this collapse equation. Nominaldimensions should also be used when calculating axial ratings because the piercing processduring manufacture may result in non-uniform wall thickness, but the cross-sectional areaof the pipe will remain constant (see Figure 7.4.1). The equation used in API Bulletin 5C3to define the axial rating is based on the product of the cross-sectional area and the yieldstrength.

87.5% of nominal pipethickness.

Pipe cross-sectionalarea remains constanteven when the thick-ness is non-uniformdue to eccentricity.

Figure 7.4.1 - Reduced Wall Section

7.5 Deration Of Yield Strength With Temperature

Both the burst and axial ratings are proportional to the yield strength of the material andthe collapse rating may or may not be a strong function of the yield strength. Minimumyield strength values for standard grades are provided in API Specification 5CT and shouldbe used as a starting point when calculating the pipe strength. However, yield strength istemperature dependent. In most grades of low alloy steel used in the oilfield, thisdependence is approximately linear and can be characterized as a reduction of 0.03% per°F. There is a large amount of scatter in the yield strength reduction data provided by



casing manufacturers, but 0.03% per °F is a representative mean value. Table 7.5.1illustrates this dependence using a correction factor.

Table 7.5.1Deration of Yield Strength

Temperature Yield Strength°F °C Correction Factor68 20 1.000

122 50 0.983212 100 0.956302 150 0.929392 200 0.902

In most wells, the effect of yield strength deration is small, but this is not true for wellswith temperatures exceeding 250°F. The effect of temperature on yield strength shouldalways be considered using anticipated temperatures associated with the selected loadcases.


February 1996 Page 1 of 8 Triaxial Design

Chapter 8 - Triaxial Design

Contents

8.1 Theory

8.2 Practice

8.2.1 Combined Burst and Compression Loading

8.2.2 Combined Burst and Tension Loading

8.2.3 Inappropriate Criteria For Collapse Loading

8.2.4 Nominal Dimensions and Design Factor

8.2.5 Summary


Triaxial Design Page 2 of 8 February 1996

8.1 Theory

With the exception of the combined loading effects on collapse discussed in Section 7.2, allthe pipe strength equations given in Chapter 7 are based on a uniaxial stress state (i.e., astate where only one of the three principal stresses is non-zero). This idealized situationessentially never occurs in oilfield applications since pipe in a wellbore is always subjectedto combined loading conditions.

The fundamental basis of casing design is that if stresses in the pipe wall exceed the yieldstrength of the material, a failure condition exists. Hence, the yield strength is a measure ofthe maximum allowable stress. The yield strength is defined as the nominal uniaxial stressat which the material exhibits a specific deformation based on tensile testing. APISpecification 5CT defines the yield strength as the stress which occurs at 0.5% total strainfor materials up to 95,000 psi yield strength, at 0.6% total strain for 110,000 psi yieldstrength, and at 0.65% total strain for 125,000 psi yield strength. Since actual materialfailure is not imminent until the stress reaches the ultimate tensile strength, use of the yieldstrength as the maximum allowable stress is an inherently conservative assumption.

Figure 8.1.1 - Stress-Strain Relationship of Ductile Material

Triaxial stress analysis provides a convenient method of comparing a generalized three-dimensional stress state with the yield strength (i.e., the uniaxial failure criterion). It isbased on the Hencky-von Mises "strain energy of distortion" theory given in most strengthof materials textbooks.

( ) ( ) ( ) ( )[ ]UED =

+− + − + −

16 1 2

22 3

23 1

2 (8.1.1)



Where:

UD = strain energy of distortion per unit volume.= Poisson's ratio.

E = modulus of elasticity or Young's modulus.1, 2, 3 = principal stresses.

During tensile testing, the onset of yielding occurs when the axial stress reaches the yieldstrength. Since this is a uniaxial test, 1 = Yp and 2 = 3 = 0. In this case, Equation 8.1.1becomes

( )[ ]UE

YD p=+16

2 2 (8.1.2)

Where:

Yp = yield strength.

Solving Equations 8.1.1 and 8.1.2 simultaneously results in the triaxial or von Mises failurecriterion.

( ) ( ) ( )[ ]Yp VME≥ = − + − + −12 1 2

22 3

23 1

2 1 2/(8.1.3)

Where:

VME = the von Mises equivalent stress or triaxial stress.

As long as the yield strength of the material is greater than or equal to the calculatedtriaxial stress, the triaxial failure criterion is met. It is important to note that if the yieldstrength of the casing has been reduced due to temperature in the wellbore, the reducedyield strength should be used when performing triaxial analysis (see Section 7.5).

The triaxial stress can approach the yield strength only if the differences between theprincipal stresses are large. The absolute value of all the principal stresses can be verylarge, but if they are all equal, the triaxial stress will be zero indicating that the principalstresses are not contributing to material yield at all. This situation occurs when casing issubjected to hydrostatic forces only.

When performing casing design, the principal stresses are expressed in cylindricalcoordinates as follows.

( ) ( ) ( )[ ]VME z r r z= − + − + −12

2 2 2 1 2/(8.1.4)

Where:

z = axial stress.= tangential or hoop stress.

r = radial stress.

Principal stresses in a tube expressed in cylindrical coordinates are shown in Figure 8.1.2.



σσr

σσθθ

σσz

Figure 8.1.2 - Principal Stresses in Tubular Analysis

The calculated axial stress at any point along the cross sectional area should include theeffects of self-weight, buoyancy, pressure loads, bending, shock loads, frictional drag, pointloads, temperature loads, and buckling loads. Except for bending and buckling loads, axialloads are normally considered to be constant over the entire cross-sectional area.

The tangential and radial stresses are calculated using the Lamé equations for thick wallcylinders.

=+

−−

+−

r r r rr r

Pr r r r

r rPi i o

o ii

o i o

o io

2 2 2 2

2 2

2 2 2 2

2 2

/ / (8.1.5)

ri i o

o ii

o i o

o io

r r r rr r

Pr r r r

r rP=

−−

−−

−

2 2 2 2

2 2

2 2 2 2

2 2

/ / (8.1.6)

Where:

Pi = internal pressure.Po = external pressure.ri = inner wall radius.ro = outer wall radius.r = radius at which the stress occurs.

It is important to note that the absolute value of is always greatest at the inner wall ofthe pipe and that for burst and collapse loads where |Pi − Po| >> 0, then | | >> | r|. Forany Pi and Po combination, the sum of the tangential and radial stresses is constant at allpoints in the casing wall.

The maximum triaxial stress usually occurs at the inner wall of the pipe. However, whenbending and/or torque is applied, the maximum stress can occur either at the ID or OD.Both need to be checked when performing a triaxial analysis.



Assuming that z and >> r, Equation 8.1.4 becomes

[ ]VME z z= − +2 2 1 2/(8.1.7)

This is the biaxial criterion used in API Bulletin 5C3 to account for the effect of tension oncollapse (see Section 7.2). It is also often used to characterize the effect of axial load onthe API burst resistance (the biaxial Barlow method).

If shear stresses resulting from formation compaction or torque are considered, Equation8.1.4 can be expressed as

( ) ( ) ( )[ ]VME z r r z z r rz= − + − + − + + +12

6 6 62 2 2 2 2 21 2/

(8.1.8)

Where:

z , r, rz = shear stresses.

Normally, the shear stresses r and rz are negligible in oilfield applications. The torsionalshear stress due to torque is given by

( )z

o i

Tr

r r=

−2

4 4(8.1.9)

Where:

T = torque.

8.2 PRACTICE

In the past, detailed triaxial analyses were performed on a limited basis when designingcasing because of the tedious effort required to calculate all the loads and resultant stressesat numerous depths by hand. This effort was typically reserved for high pressure, hightemperature wells which required thick wall pipe and for which a consideration of thecombined stress state was critical to the design. With the computing tools available to thedesign engineer today, very little effort is now required to perform triaxial analysis.Because of this, a triaxial check should be performed on all designs.

The triaxial yield criterion can be represented by a cylindrical yield envelope. Stresses inthe material which lie within the cylinder will not cause the material to yield while thosethat fall outside will. The portion of the yield envelope which intersects the plane of zeroradial stress forms an ellipse. This ellipse can be directly compared with the uniaxial burstand axial ratings and the biaxial collapse rating defined in API Bulletin 5C3.



Figure 8.2.1 - Design Limit Plot

In some cases, triaxial analysis will indicate that a design can be made less conservative. Inothers, it will expose non-conservative designs. In still other situations, the triaxialcriterion does not apply to the design at all. These issues are discussed in the followingsections.

8.2.1 Combined Burst And Compression Loading

Combined burst and compression loading corresponds to the upper left-hand quadrant ofFigure 8.2.1. This is the region where triaxial analysis is most critical because reliance onthe uniaxial criteria alone would not predict several possible failures.

For high burst loads (i.e., high tangential stress) and moderate compression, a burst failurecan occur at a differential pressure less than the API burst pressure. For high compressionand moderate burst loads, the failure mode is permanent corkscrewing (i.e., plasticdeformation due to helical buckling).

This combined loading typically occurs when a high internal pressure is experienced (due toa tubing leak or a build up of annular pressure) after the casing temperature has beenincreased due to production. The temperature increase in the uncemented portion of thecasing causes thermal growth which can result in significant increases in compression andbuckling. The increase in internal pressure also results in increased buckling.



8.2.2 Combined Burst And Tension Loading

Combined burst and tension loading corresponds to the upper right-hand quadrant ofFigure 8.2.1. This is the region where reliance on the uniaxial criteria alone can result in adesign which is more conservative than necessary.

For high burst loads and moderate tension, a burst yield failure will not occur until after theAPI burst pressure has been exceeded. As the tension approaches the axial limit, a burstfailure can occur at a differential pressure less than the API value. For high tension andmoderate burst loads, pipe body yield will not occur until a tension greater than the uniaxialrating is reached.

Taking advantage of the increase in burst resistance in the presence of tension represents agood opportunity for the design engineer to save money while maintaining wellboreintegrity. Similarly, the designer might wish to allow loads which fall between the uniaxialand triaxial tension ratings. However, great care should be taken in the latter case becauseof the uncertainty of what burst pressure may be seen in conjunction with a high tensileload (an exception to this is the green cement pressure test load case discussed in Section5.4). Also, connection ratings may limit your ability to design in this region.

8.2.3 Inappropriate Criteria For Collapse Loading

For most pipes used in the oilfield, collapse is an inelastic stability failure or an elasticstability failure independent of yield strength. The triaxial criterion is based on elasticbehavior and the yield strength of the material and hence, should not be used with collapseloads. The one exception is for thick wall pipes with a low D/t ratio which have an APIrating in the yield strength collapse region. This collapse criterion along with the effects oftension and internal pressure (which are triaxial effects) result in the API criterion beingessentially identical to the triaxial method in the lower right-hand quadrant of the triaxialellipse for thick wall pipes.

For high compression and moderate collapse loads experienced in the lower left-handquadrant of Figure 8.2.1, the failure mode is permanent corkscrewing due to helicalbuckling. It is appropriate to use the triaxial criterion in this case. This load combinationtypically only can occur in wells which experience a large increase in temperature due toproduction. The combination of a collapse load which causes reverse ballooning and atemperature increase both act to increase compression in the uncemented portion of thestring.

8.2.4 Nominal Dimensions And Design Factor

Section 7.4 discusses the use of a minimum wall for burst calculations and nominaldimensions for collapse and axial calculations. Arguments can be made for using eitherassumption in the case of triaxial design. In this design manual, nominal dimensions havebeen recommended for use in triaxial analysis. Of more importance than the choice ofdimensional assumptions is that the results of the triaxial analysis should be consistent withthe uniaxial ratings with which they may be compared.



Sections 8.2.2 and 8.2.3 indicate that a triaxial analysis provides the most value whenevaluating burst loads. Hence, it makes sense to calibrate the triaxial analysis to becompatible with the uniaxial burst analysis. This can be done easily by the appropriateselection of a design factor. Since the triaxial result nominally reduces to the uniaxial burstresult when no axial load is applied, the results of both of these analyses should beequivalent here. Since the burst rating is based on 87.5% of the nominal wall thickness, atriaxial analysis based on nominal dimensions should use a design factor which is equal tothe burst design factor multiplied by 8/7. This reflects the philosophy that a lessconservative assumption should be used with a higher design factor. Hence, for a burstdesign factor of 1.1, a triaxial design factor of 1.25 should be used.

8.2.5 Summary

Figure 8.2.2 graphically summarizes the triaxial, uniaxial and biaxial limits that should beused in casing design along with the appropriate design factors.

Figure 8.2.2 - Governing Design Limits


February 1996 Page 1 of 14 Special Considerations

CHAPTER 9 - SPECIAL CONSIDERATIONS

Contents

9.1 Connections

9.1.1 Design Limits

9.1.2 API Connection Ratings

9.1.3 Design Factors for API Connections

9.1.4 Use of Premium Connections

9.2 Service Loads and Buckling

9.3 Temperature Effects

9.4 Wear

9.5 Corrosion


Special Considerations Page 2 of 14 February 1996

9.1 CONNECTIONS

The selection of an appropriate connection is the most important special consideration incasing design. Connections must be selected to withstand the same load cases used todesign the pipe body. However, it is the experience of the industry that a large majority ofall casing failures occur at connections. These failures can be attributed to:

• Improper design or exposure to loads exceeding the rated capacity• Failure to comply with make-up requirements• Failure to meet manufacturing tolerances• Damage during storage and handling• Damage during production operations (corrosion, wear, etc.)

Connection failure can be broadly classified into two categories:

• Leakage• Structural failure

Galling during make-upYielding due to internal pressureJump-out under tensile loadFracture under tensile loadSplit box due to excessive torque during make-up or subsequent operations

Avoiding connection failure is not only dependent upon selection of the correct connection,but is strongly influenced by other factors including:

• Manufacturing tolerances• Storage

Storage thread compoundThread protector

• TransportationThread protectorHandling procedures

• Running proceduresSelection of thread compoundApplication of thread compoundAdherence to correct make-up specifications and procedures

The overall mechanical integrity of a correctly designed casing string is dependent upon aquality assurance program which ensures damaged connections are not used and thatoperations personnel adhere to the appropriate running procedures.



9.1.1 DESIGN LIMITS

The design limits of a connection are not only dependent upon its geometry and materialproperties but are influenced by the following factors:

• Surface treatmentPhosphatingMetal plating (copper, tin or zinc)Bead blasting

• Thread compound• Make-up torque• Use of a resilient seal ring (many companies do not recommend this practice)• Fluid to which connection is exposed (mud, clear brine, or gas)• Temperature and pressure cycling• Large doglegs (e.g., medium or short radius horizontal wells)

Because these factors are quite varied, it is nearly impossible to provide detailed designlimits for every connection. Manufacturer's test data should be compared with anticipatedoperating conditions with particular attention given to combined loading and load cycling.Extrapolation of test data to heavier pipe weights can yield questionable results and shouldbe avoided. In the most critical situations, additional qualification testing should beconsidered.

The leak resistance values for API connections as given in API Bulletin 5C3 should be usedwith caution. In production applications when exposed to a clear brine or gas, APIconnections may leak before the burst differential pressure reaches the API leak resistancevalue (see Section 9.1.2).

A few general guidelines are given in Table 9.1.1 to assist the design engineer.



Table 9.1.1Design Limit Guidelines

ConnectionType

Temperature Pressure Comments

API:STCLTCBTC

< 250°F If only exposed to drillingmud, up to API leakresistance considering burstdesign factor (DF)

If exposed to clear brine, thelesser of 5000 psi and APIleak resistance w/DF

If exposed to gas, the lesserof 4000 psi and API leakresistance w/DF

The leak resistance ofAPI connections can beimproved by metalplating or using aresilient seal ring.

8 round connections(STC and LTC) typicallyhave an axial mechanicalefficiency < 100%.

Premium withmetal-to-metalseal

> 250°F > API connection limitationgiven above

Consult connectionmanufacturer for specificperformance ratings.

Modified APIor premiumwith torqueshoulder

Use if casing rotationrequired while running inthe hole or during theprimary cement job.

9.1.2 API CONNECTION RATINGS

The equations used to calculate performance properties for 8 round (STC and LTC) andbuttress (BTC) connections are given in API Bulletin 5C3. They represent minimumperformance values recommended by the API. They can be used as a starting point whenevaluating a connection, but should not be used in lieu of the design limitations specified inSection 9.1.1 or test data available from the manufacturer.

Internal Yield Pressure for Couplings

The internal yield pressure is the pressure which will initiate yield at the root of thecoupling thread.

P YW d

Wc=−

1 (9.1.1)

Where:

P = minimum internal yield pressure.Yc = minimum yield strength of coupling.W = nominal outside diameter of coupling.



d1 = diameter at the root of the coupling thread in the power tight position. Thisdimension is based on data given in API Specification 5B and other threadgeometry data.

Equation 9.1.1 is another form of the Barlow Equation (Equation 7.1.1) used to calculatepipe body yield. The pressure calculated using Equation 9.1.1 is typically greater than thepipe body internal yield pressure.

Internal Pressure Leak Resistance

The internal pressure leak resistance is based on the interface pressure between the pipeand coupling threads due to makeup.

( )P

E T N p W E

E Ws

s

=−2 2

22(9.1.2)

Where:

P = internal pressure leak resistance.E = modulus of elasticity.T = thread taper.N = a function of the number of thread turns from hand tight to power tight

position as given in API Specification 5B.p = thread pitch.

Es = pitch diameter at plane of seal given in API Specification 5B.

It is important to note that Equation 9.1.2 only accounts for the contact pressure on thethread flanks as a sealing mechanism and ignores the long helical leak paths which exist inall API connections. In round threads, two small leak paths exist at the crest and root ofeach thread. In buttress threads, a much larger leak path exists along the stabbing flankand at the root of the coupling thread. API connections rely on thread compound to fillthese gaps and provide leak resistance. The leak resistance provided by the threadcompound is less than the API internal leak resistance value, particularly for buttressconnections. The leak resistance can be improved by using API connections with smallerthread tolerances (and hence, smaller gaps), but it typically will not exceed 5000 psi withany long-term reliability. Tin or zinc plating will also result in smaller gaps and improveleak resistance.

Round Thread Casing Joint Strength

The round thread casing joint strength is given as the lesser of the fracture strength of thepin and the jump-out strength.

Fracture strength:

F A Uj jp p= 0 95. (9.1.3)

Jump-out strength:

F A LD U

L DY

L Dj jpp p=

++

+

−

0 950 7405 014 014

0 59

... . .

.

(9.1.4)



Where:

Fj = minimum joint strength (units of force).Ajp = cross-sectional area of the pipe wall under the last perfect thread.

= π/4[(D − 0.1425)2 − d2]D = nominal outside diameter of pipe.d = nominal inside diameter of pipe.L = engaged thread length given in API Specification 5B.

Yp = minimum yield strength of pipe.Up = minimum ultimate tensile strength of pipe.

Equations 9.1.3 and 9.1.4 are based on tension tests to failure on 162 round thread testspecimens. Both are theoretically derived and adjusted using statistical methods to matchthe test data. Note that for standard coupling dimensions, round threads are pin weak (i.e.,the coupling is non-critical in determining joint strength).

When performing casing design, it is very important to note that the API joint strengthvalues are a function of the ultimate tensile strength. This is a different criterion than thatused to define the axial strength of the pipe body which is based on the yield strength (seeSection 7.3). If care is not taken, this approach can lead to a design which inherently doesnot have the same level of safety for the connections as the pipe body. This is not the mostprudent practice, particularly in light of the fact that most casing failures occur atconnections. This discrepancy is countered by using a higher design factor whenperforming connection axial design as discussed in Section 9.1.3.

Buttress Thread Casing Joint Strength

The buttress thread casing joint strength is given as the lesser of the fracture strength of thepipe body (the pin) and the coupling (the box).

Pipe thread strength:

( )[ ]F A U Y U Dj p p p p= − −0 95 1008 0 0396 1083. . . . / (9.1.5)

Coupling thread strength:

F A Uj c c= 0 95. (9.1.6)

Where:

Uc = minimum ultimate tensile strength of coupling.Ap = cross-sectional area of plain-end pipe.Ac = cross-sectional area of coupling.

= π/4(W2 − d12)

Equations 9.1.4 and 9.1.5 are based on tension tests to failure on 151 buttress thread testspecimens. They are theoretically derived and adjusted using statistical methods to matchthe test data. Similar to the round thread equations, they are based on the ultimate tensilestrength instead of the yield strength which is used in pipe body axial strength calculations.This discrepancy is countered by using a higher design factor when performing connectionaxial design as discussed in Section 9.1.3.



9.1.3 DESIGN FACTORS FOR API CONNECTIONS

If API connection axial strengths calculated using the formulae in API Bulletin 5C3 are thebasis of a design, the designer should use higher design factors for their connection axialanalysis. This is because the pipe body yield equation is based on the yield strength whilethe joint strength equations are based on the ultimate tensile strength (see Section 9.1.2).Since tensile failure is not imminent until the axial stress reaches the ultimate tensilestrength (see Figure 8.1.1), a criterion based on yield strength implicitly has some "extrasafety" associated with it since additional plastic deformation will occur as the material isloaded past the yield strength to the ultimate tensile strength. A design procedure whichuses the same design factor for both the pipe body and connection criteria is inconsistentand can easily result in a design which is more connection critical than intended.

The logical basis for the higher design factor is the ratio of the minimum ultimate tensilestrength to the minimum yield strength. These values are given in API Specification 5CTfor standard grades and are shown in Table 9.1.2 for reference. The design factors shownin the table correspond to a 1.3 design factor for the pipe body.

Table 9.1.2API Connection Axial Design Factors by Grade

Grade Yp, psi Up, psi Up/Yp Axial DF

H-40 40,000 60,000 1.50 1.95

J-55 55,000 75,000 1.36 1.77

K-55 55,000 95,000 1.73 2.25

N-80 80,000 100,000 1.25 1.63

L-80 80,000 95,000 1.19 1.54

C-90 90,000 100,000 1.11 1.44

C-95 95,000 105,000 1.11 1.44

T-95 95,000 105,000 1.11 1.44

P-110 110,000 125,000 1.14 1.48

Q-125 125,000 135,000 1.08 1.40

There is no need to use a different burst design factor for API connections since:

• The internal yield pressure for connections is based on the same yield criteria as thepipe body calculation; and

• The leak resistance pressure is not considered if it exceeds 5000 psi and at lowerpressures there has been no compelling field evidence to treat this criterion anydifferently than the yield criterion.



9.1.4 USE OF PREMIUM CONNECTIONS

While API connections remain the standard in the oilfield, their inability to achieve areliable gas tight seal limits their application. The low leak resistance of API connectionsin general and buttress connections in particular results from their reliance on threadcompound in the thread form as the primary sealing mechanism. Two common ways ofaddressing this problem are to modify the API coupling by zinc or tin plating or to includea resilient seal ring which is typically made of Teflon. However, even modified APIconnections cannot always be relied upon to maintain a seal at pressures in excess of 5000psi. This has led to the development of a wide variety of "premium" connections.

Premium connections are used primarily to achieve gas tight sealing reliability and 100%connection efficiency under more severe well conditions including:

• High pressures• High temperatures• Sour environments• Exposure to gas production• High pressure gas lift• Steam wells

To achieve these aims, premium connections typically have one or more of these featuresnot found in API connections:

• More complex thread forms• Resilient seals• Torque shoulders• Metal-to-metal seals

When selecting a premium connection with a metal-to-metal seal for use in a high pressureenvironment, performance test data should be audited to ensure the connection isappropriate for use in your environment. Combined loading data is particularly relevant.

When requesting tensile performance data, make sure that the manufacturer indicateswhether quoted tensile capacities are based on the ultimate tensile strength (i.e., the load atwhich the connection will fracture and commonly called the parting load) or the yieldstrength (commonly called the joint elastic limit). If possible, use the joint elastic limitvalues in your design so that you can maintain consistent design factors for both pipe bodyand connection analysis. If only parting load capacities are available, a higher design factorshould be used for connection axial design as described in Section 9.1.3.

9.2 SERVICE LOADS AND BUCKLING

Service loads are those loads imposed after the casing string has been cemented in place.These loads are typically those loads used as burst and collapse criteria in casing design.However, these loads also represent a combined stress environment which includes theeffects of:



• internal and external pressure changes (ballooning effects due to Poisson's ratio andpressure forces at area changes)

• temperature changes• bending loads• buckling loads• point loads• self weight• static friction loads

Service loads are normally calculated assuming a fixed wellhead and zero strain incemented intervals. For offshore platform wells where the wellhead is not fixed, the fixedwellhead assumption is conservative (except when considering axial load distribution onthe outer casing strings due to landing inner strings of casing).

In order to correctly calculate the magnitude of service loads, the initial (as cemented)conditions need to be accurately modelled as well as the applied load condition. This isbecause it is principally the change in applied temperatures and pressures which result insignificant service loads. Over the free length of the casing above the top of cement, thesechanges in temperatures and pressures will have the largest effect on the ballooning andtemperature load components. The incremental forces due to these effects are given inEquations 9.2.1 and 9.2.2.

( ) ( )∆ ∆ ∆ ∆ ∆F p A p A L A Abal i i o o i i o o= − + −2 (9.2.1)

Where:

∆Fbal = incremental force due to ballooning.= Poisson's ratio (0.30 for steel).

∆pi = change in surface internal pressure.∆po = change in surface external pressure.

Ai = cross-sectional area associated with casing ID.Ao = cross-sectional area associated with casing OD.L = free length of casing.

∆ρi = change in internal fluid density.∆ρo = change in external fluid density.

∆ ∆F EA Ttemp s= − (9.2.2)

Where:

∆Ftemp = incremental force due to temperature change.= thermal expansion coefficient (6.9 x 10-6 °F-1 for steel).

E = Young's modulus (3.0 x 107 psi for steel).As = cross-sectional area of pipe.

∆T = average change in temperature over free length.



All service loads should be evaluated for changes in the axial load profile, triaxial stress(see Chapter 8), and the onset and degree of buckling. Buckling will occur if the bucklingforce, Fb, is greater than a threshold force, Fp, known as the Paslay buckling force.1

F F p A p Ab a i i o o= − + − (9.2.3)

Where:

Fb = buckling force.Fa = actual axial force (tension positive).pi = internal pressure.po = external pressure.

F w EI rp = 4 (sin ) (9.2.4)

Where:

Fp = Paslay buckling force.w = distributed buoyed weight of casing.

= hole angle.EI = pipe bending stiffness.

r = radial annular clearance.

Buckling criteria are summarized in Table 9.2.1.

Table 9.2.1Buckling Criteria

Buckling Force Magnitude Result

Fb < Fp No buckling

Fp < Fb < √2Fp Lateral (s-shaped) buckling

√2Fp < Fb < 2√2Fp Lateral or helical buckling

2√2Fp < Fb Helical buckling

An increase in internal pressure will act on the buckling force in two ways: (1) increase Fa

due to ballooning which will tend to decrease buckling, and (2) increase the piAi term inEquation 9.2.3 which will tend to increase buckling. The second effect is much greater;hence, an increase in internal pressure will result in an increase in buckling.

From Equation 9.2.2, a temperature increase will result in a reduction in the axial tension(or increase in the compression). From Equation 9.2.3, this reduction in tension will resultin an increase in buckling.

Equation 9.2.4 indicates that the onset and type of buckling is a function of hole angle.Due to the stabilizing effect of the lateral distributed force of a casing lying on the low side

1 Mitchell, R. F., "Effects of Well Deviation on Helical Buckling", SPE 29462, Proc. 1995 ProductionOperations Symposium, April 1995, pp. 189-198.



of the hole in an inclined wellbore, a greater force is required to induce buckling. In avertical well, Fp = 0 and helical buckling will occur at any Fb > 0.

Buckling should be avoided in drilling operations to minimize casing wear. This can beachieved by applying a pickup force before landing the casing. In production operations,casing buckling is not normally a critical design issue. However, a large amount ofbuckling can occur due to increased production temperatures in some wells. A checkshould be made to ensure that plastic deformation or corkscrewing will not occur. Thischeck is possible using triaxial analysis. Corkscrewing will only occur if the triaxial stressexceeds the yield strength of the material (see Chapter 8).

9.3 TEMPERATURE EFFECTS

In shallow normal pressured wells, temperature typically will have a secondary effect onthe casing design. In other situations, loads induced by temperature can be the governingcriteria in the design. Temperature can affect casing design in the following ways:

• Increases in temperature during drilling and especially production can cause thermalexpansion of fluids in sealed annuli. This can result in significant burst and collapseloads. Most of the time, these loads do not need to be included in the design becausethe pressures can be bled off. However, in subsea wells, the outer annuli cannot beaccessed after the hanger is landed. In this case, these loads must be considered in thedesign. The pressure increases will also influence the axial load profiles of the casingstrings exposed to the pressures due to ballooning effects (see Section 9.2). For burstloads, this may result in increased buckling and excessive tensile loads. For collapseloads, this may result in compression at the casing hanger.

• Changes in temperature will increase or decrease tension in the casing string due tothermal contraction and expansion, respectively. The increased axial load due topumping cool fluid into the wellbore during a stimulation job can be the load casewhich controls axial design. In contrast, the reduction in tension during production dueto thermal expansion can increase buckling and in a worst case scenario, result incompression at the wellhead.

• Changes in temperature not only affect loads but also influence the load resistance.Since the material's yield strength is a function of temperature, higher wellboretemperatures will reduce the burst, collapse, axial and triaxial ratings of the casing.This is discussed further in Section 7.5.

• In sour environments, operating temperatures can determine what materials can be usedat different depths in the wellbore. This is discussed in Section 9.5.

• Produced temperatures in gas wells will influence the gas gradient inside the tubingsince gas density is a function of temperature and pressure. This will have a secondorder effect on the pressure used in the tubing leak burst load case (see Section 5.3).



9.4 WEAR

The primary cause of casing wear is the rotation of the drillstring against the casing wall.The resultant wall loss can have a major detrimental effect on the mechanical integrity ofcasing systems and must be included in the design premise.

Casing wear will increase with:

• Increasing contact force between the drillstring and the casing. Particular regions ofconcern are build and drop sections in deviated wells (particularly those in the shallowregions of the wellbore), localized doglegs, and buckled sections of casing. Anoptimized wellpath selection can significantly reduce casing wear.

• Increasing contact time. Of particular concern are sections exposed to slowpenetration rates, long hole intervals, and multiple hole intervals cased off withintermediate liners.

• Increasing roughness of drillpipe tool joints.• Decreasing mud weight. Barite is a very effective wear reducer.

The localized wall loss due to casing wear will have a significant effect on the burst andcollapse resistance of the pipe. Reduced burst and collapse ratings should be calculatedbased on the minimum wall section resulting from wear. The effect on the axial rating willbe much less since the localized wear will reduce the cross-sectional area only nominally.This is shown in Figure 9.4.1.

Local wear will have alarge effect on the burstand collapse resistance ofthe pipe but will reduce theoverall cross-sectional areaonly nominally. This willresult in only a smallreduction in the axialrating.

Figure 9.4.1 - Effect of Wear on Wall Cross-Section

The following steps should be included in the design process to account for casing wear:

1. Perform the casing design and calculate the allowable wear based on burst and collapsedesign loads. The allowable wear is calculated automatically if StressCheck is used toperform the design.



2. Estimate the anticipated wear based the deviation profile, mud program and drillingpractices. A casing wear program is available in the Halliburton toolkit to perform anaccurate estimate of wear.

3. If the estimated wear is greater than the allowable, either modify the directionalprogram or drilling practices to reduce the wear or increase the wall thickness in thewear interval to increase the allowable wear.

9.5 CORROSION

Like wear, corrosion can have a major detrimental effect on the mechanical integrity ofcasing systems and must be included in the design premise. Corrosion can attack themechanical integrity of casing in two ways:

1. Metal loss will reduce the wall thickness of the casing and will lead to a correspondingreduction in its load resistance. This represents a similar effect as casing wear exceptthat corrosion wall loss typically occurs in the production phase instead of the drillingphase and often is only a design issue for production casing. Control of externalcorrosion due to contact with formation fluids can most effectively be localized byisolating the offending formation with a good cement job.

2. The remaining casing material can be weakened so that it can no longer withstandoperating loads. The most severe forms of this type of corrosion are sulfide-stress-corrosion cracking (SSCC), chloride-stress-corrosion cracking (SCC), and hydrogenembrittlement. All three of these lead to sudden and often catastrophic failure of thematerial. SCC requires the presence of a corrosive agent such as oxygen and is morelikely to occur in austenitic stainless steels such as AISI 316. This makes this morelikely to be a wellhead issue instead of a casing design concern. In the presence of H2S,the casing design must account for SSCC and hydrogen embrittlement.

Criteria used to define sour environments (i.e., containing corrosive H2S) along withmaterial requirements are given in NACE Standard MR0175-95 which is published by theNational Association of Corrosion Engineers. This standard should be used for materialselection in sour environments.

NACE MR0175 defines a sour gas environment to be one with a total pressure of at least65 psia and a partial pressure of H2S greater than 0.05 psia. The partial pressure iscalculated by multiplying the mole fraction of the H2S in the gas by the total systempressure. All casing strings which can be exposed to such an environment must meet theNACE material requirements.

The risk of SSCC increases with:

• increasing H2S partial pressure• increasing material hardness (and consequently strength)• increasing tensile stress• increasing exposure time• decreasing pH of the environment• decreasing temperature



A number of proprietary grades and CRA (corrosion resistant alloy) materials are suitablefor use in a sour environment and are described in NACE MR0175. Before one of thesematerials is selected, further advice should be sought from the casing manufacturer.Standard grades which are suitable for use in sour environments are shown in Table 9.5.1.

Table 9.5.1Acceptable API Spec 5CT Grades in Sour Service

Operating Temperatures

All Temperatures >> 150°F >> 175°F >> 225°F

J-55K-55L-80 (Type 1)C-90T-95

N-80 (Q&T)C-95

N-80P-110

Q-125 (Q&T) madeof Cr-Mo alloy witha max. yieldstrength of 150 ksi

Using Table 9.5.1 as a guide, different materials can be used at different depths in thewellbore based on the undisturbed temperature profile. The undisturbed profile is usedbecause it represents a conservative representation of the minimum steady-statetemperature the pipe could experience while exposed to the sour environment.


February 1996 Page 1 of 19 Design Example

CHAPTER 10 - DESIGN EXAMPLE USING StressCheck

Contents

10.1 Well Description

10.2 Design Example

10.2.1 Preliminary Design Input

10.2.2 Detailed Design Criteria Input

10.2.3 Performing Design


Design Example Page 2 of 19 February 1996

10.1 WELL DESCRIPTION

To illustrate a detailed casing design procedure using the StressCheck software, amoderately deep, geopressured exploration well located in shallow water in the Gulf ofMexico has been chosen. A jack-up rig will be used to drill the well and the wellhead willbe supported by a 48” drive pipe. The well is deviated and requires a departure of 4300’from the surface location at TD because the objective lies beneath a shipping fairway. Thewell is anticipated to be a gas producer.

The preliminary design is summarized in Figure 10.1.1.

0

2000

4000

6000

8000

10000

12000

14000

8.00 9.00 10.00 11.00 12.00 13.00 14.00 15.00 16.00 17.00 18.00 19.00

EMW, ppg

Dep

th, f

t

A

BC

D

16"

11.75"

7.625"

9.625"

Pore Pressure

Mud WeightFracture Gradient

Design Fracture Gradient

Figure 10.1.1 - Preliminary Design

The 9-5/8” and 7-5/8” strings are intermediate liners. If a discovery is made or a well testis required, a 5” production liner will be run and then tied back to surface. A 20”conductor string will also be run at 1000’.

10.2 DESIGN EXAMPLE

The StressCheck design example is presented in this section by displaying the input dialogboxes and spreadsheets and the graphical and tabular results as they would be encounteredin a StressCheck session. Brief explanations in the accompanying text further explain thedesign process. This design example presentation assumes that the reader already has aworking knowledge of the StressCheck program.

In this example, only the 11-3/4” intermediate casing will be designed.



10.2.1 PRELIMINARY DESIGN INPUT

Figure 10.2.1 - General Dialog

This dialog enables data to be entered in the Offshore dialog and the 2D Build/Tangentspreadsheet if the Deviated and Offshore options are selected. The well TD of 14460’corresponds to a TVD of 13370’. The MD/TVD relationship will be established when thedeviation information is specified. The elevation is the height of the RKB reference pointabove mean sea level (MSL).

Figure 10.2.2 - Offshore Dialog

Even though this well is being drilled from a jack-up rig instead of a platform, the“platform well” type in StressCheck implies that all the casing strings extend upward to awellhead above sea level. In this case, the wellhead will be supported by a free-standing48” drive pipe. With a 100’ elevation and a 70’ water depth, the RKB depth of themudline is 170’.



Figure 10.2.3 - Pore Pressure Spreadsheet

This pore pressure profile is typical of a geopressured well in the western Gulf of Mexico.The large increase in pressure over a small depth interval in the geopressure transition zonemakes the correct selection of the intermediate casing shoe depth critical to the success ofthe well.

Figure 10.2.4 - Fracture Pressure Spreadsheet

The fracture pressure profile is entered next. The small margin between the pore pressureand the fracture pressure in the lower section of the well complicates the preliminary casingdesign.



Figure 10.2.5 - Undisturbed Temperature Dialog

The undisturbed temperature is linear and represents a 1.64°F/100’ gradient from themudline to the well TD.

Figure 10.2.6 - 2D Build/Tangent Spreadsheet

To reach its geological objective underneath the shipping fairway, the well’s plannedtrajectory builds angle at 2°/100’ from a kick-off point at 1200’ until a tangent angle of 20°is reached. To account for deviations from the planned build rate, a 4°/100’ dogleg will besuperimposed over the build interval. This will increase the bending stress.



Figure 10.2.7 - Deviation Profile Table and Section View Plot

Based on the one line of input in the 2D Build/Tangent spreadsheet, the deviation profileshown in Figure 10.2.7 is used.

Figure 10.2.8 - Dogleg Overrides Spreadsheet

In order to include the natural variation from the ideal smooth wellpath that is present in allactual wells, a dogleg of 2°/100’ is superimposed over the whole wellbore. This doglegwill be considered in bending calculations.



Figure 10.2.9 - Casing Scheme Spreadsheet

The results of the preliminary design are entered on the Casing Scheme spreadsheet. Afterthese data are specified, a well schematic as shown in Figure 10.2.10 can be displayed.

Figure 10.2.10 - Well Schematic Plot



Figure 10.2.11 - Formation Plots

Before specifying the detailed design criteria for the 11-3/4” casing, it is useful to reviewthe formation data graphically to ensure it was correctly specified. The pore pressure,fracture gradient and mud weight plot shown in the lower left-hand window pane ofFigure 10.2.11 is especially useful to verify data consistency.



10.2.2 Detailed Design Criteria Input

Figure 10.2.12 - Design Parameters Dialog

The design factors are entered on the Design Parameters dialog. You will need to specifyan alternate burst design factor of 1.2 for the gas kick load case when working with theBurst Loads dialog.

Figure 10.2.13 - Cementing and Landing Dialog

The cementing and landing data are used to define the initial stress state of the casing afterit has been cemented in place. This, in turn, will be used to calculate combined loads andtriaxial stress for all the specified service loads. The applied surface pressure field in thisdialog represents holding pressure while waiting on cement (e.g., to pre-tension a string ina subsea well). The pressure used to bump the plug is specified on the Axial Loads dialog.



Figure 10.2.14 - Burst Loads Dialog Select Tab

Initially, the gas kick load case was selected as the burst criteria. However, asFigure 10.2.15 shows, only a kick tolerance of 6.5 bbls is possible when taking a kick atTD while drilling the 6.75” hole interval. The low kick tolerance dictates the use of thelost returns with water load case (see Chapter 5). The burst design factor for the gas kickload case should be changed to 1.2 from the Options tab.

Figure 10.2.15 - Burst Loads Dialog Edit Tab

Because of relatively good control of fracture pressures deep based on offset information, afracture margin of error of 1.0 ppg is used. Even with this error margin, only a kicktolerance of 6.5 bbls is possible because of the slim margin between the pore pressure andthe fracture pressure in the lower portion of the hole. The StressCheck programautomatically calculates the maximum kick tolerance if it is less than the initial input value.




By modeling a water gradient from the fracture pressure at the shoe of the 7-5/8” liner, thisload case will dominate the burst design.


By enabling the pore pressure in open hole option, the standard burst external pressureprofile will be used.



Figure 10.2.18 - Collapse Loads Dialog Select Tab

The cementing and lost returns w/mud drop load cases should be selected as the collapsedesign criteria.

Figure 10.2.19 - Collapse Loads Dialog Edit Tab

The worst case partial evacuation will occur while drilling the 10-5/8” hole interval due tothe mud column equilibrating with the pore pressure at the 11-3/4” casing shoe. Thisresults in an evacuation depth of approximately 2000’.



Figure 10.2.20 - Collapse Loads Dialog Edit Tab

The collapse external pressure profile assumes a mud column from the hanger to the shoe.This is consistent with the assumption that a channel exists in the cement and a mudgradient is also seen below the TOC.

Before continuing with the axial load case entry, it is prudent to check the burst andcollapse load cases graphically.

Figure 10.2.21 - Burst and Collapse Loads Plots

Note that the lost returns with water load case dominates the burst design while bothcollapse load cases contribute to the collapse design at different depths.



Figure 10.2.22 - Axial Loads Dialog

The standard axial load cases are selected form the Axial Loads dialog. In this case, thegreen cement pressure test will dominate the axial design over the upper portion of theintermediate casing and the combined loading due to the service loads will serve as theaxial load criteria in the lower section.

Note that the axial loads cannot be calculated or viewed graphically until after a design hasbeen established. This is because a pipe weight must be specified in order to calculate theaxial load distribution.



Figure 10.2.23 - Inventory Spreadsheet

The Inventory spreadsheet which is accessed from the Tubular menu dictates which pipeswill be considered in the current design. In this case, since there are no sour serviceconcerns for the intermediate casing, all the C and L grades were deleted from theinventory. Also, since the P-105 grade is normally not available for 11-3/4” casing, it wasalso deleted.

Note that the 10.625” drift diameter used with the 60 and 65 lb/ft casing is a commonalternate drift diameter used by the industry.



10.2.3 Performing Design

Figure 10.2.24 - Burst and Collapse Design Plots

The plots displayed in Figure 10.2.24 represent the initial design determined usingStressCheck’s minimum cost algorithm. In this case, the design reflects the more severeburst criteria. In order to view the selected pipe from these plots, place the mouse pointeron the rating line and depress the left button. This will cause the selected pipe’s OD,weight and grade to be displayed on the status bar in the lower left corner of the window.

Figure 10.2.25 - Axial Design and Triaxial Load Line Plots

The axial and triaxial criteria are also met with the current design as seen in Figure 10.2.25.



Figure 10.2.26 - String Sections and Connections Spreadsheets

The String Sections spreadsheet shown in the upper window pane of Figure 10.2.26indicates that an 11-3/4” 60 lb/ft P-110 pipe as been selected. If a buttress connection ischosen, note that the API leak resistance of the connection is not sufficient to meet theburst criteria (a 1.1 design factor). If a buttress connection is to be used in lieu of apremium connection, one or more of the following should be performed to increase theconnection’s leak resistance:

• Tin plate the couplings.

• Add a Teflon seal ring to the coupling.

• Use torque/turn monitoring equipment when making up the connections in the field toensure the correct amount of thread interference. Also, if a seal ring is used, themonitoring equipment will help detect if a seal ring as been damaged during the make-up.



Figure 10.2.27 - Maximum Allowable Wear Table

After the design has been established, check the wear allowance. The allowable wearrepresents the amount of wear which will result in the burst or collapse safety factor to beequal to the corresponding design factor. If the approximately 20% allowable wear in thecritical region near the kick-off point at 1200’ is acceptable, the design process for theintermediate casing is complete.



Figure 10.2.28 - String Summary Table

A summary of the current design is displayed in the String Summary. You may wish tofurther optimize the design by taking advantage of the increased burst resistance due totension (see Section 8.2.2). This can be done by violating the uniaxial burst criteria whilestill meeting the collapse, axial and triaxial criteria. The results of this optimization processare shown in Figure 10.2.29.

Figure 10.2.29 - String Summary Table

The design using 11-3/4” 65 lb/ft N-80 casing represents sound engineering practicebecause the triaxial criteria are still met. Before this design is used, it should also bechecked for casing wear allowance. Note the $25,000 savings based on the currentinventory prices.


February 1996 Page 1 of 11 Appendix A

Appendix A - Load Case Equations

Contents

A.1 Burst Loads

A.2 Collapse Loads

A.3 Axial Loads


Appendix A Page 2 of 11 February 1996

A.1 BURST LOADS

Gas Kick Profile

During the kick simulation a constant bottomhole pressure is maintained:

Pbh = g∗(ρmud + kick intensity)∗TVDinflux depth

The gas bubble expands with falling pressure as it is circulated out of the hole. Variationsin gas density with pressure and temperature are modeled based on the Redlich-Kwongequation of state. The temperature profile is based on the API circulating temperature andthe undisturbed temperature profile. The linear temperature profile used in this load caseintersects the API circulating temperature at the influx depth and the midpoint of theundisturbed temperature profile.

Calculation depths are defined by annulus geometry and well deviation. Calculations occurat each change of annular cross-sectional area and at depths used to define the welldeviation. Pressure profiles as a function of depth are retained for each calculation depth.After calculating the pressure profile with the gas bubble at each location including thesurface, a locus of maximum pressures at each depth is used as the internal pressure profile.

The following assumptions are made:

• The kill mud weight is assumed to be the same as the original mud weight. This resultsin conservative annular pressures.

• The mud density does not vary with temperature and pressure.

• Annular frictional pressure losses are ignored. This is consistent with a normal killprocedure characterized by a slow pump rate.

• The gas bubble is not distributed (i.e., a single bubble model is used).

PVT Behavior of Gas Bubble

The PVT behavior of the gas bubble is modeled by the Redlich-Kwong (RK) equation ofstate which is a cubic equation in volume or in Z (compressibility factor), and can beexpressed as:

Z3 - Z2 + (A - B2 - B) Z - A B = 0

where

A = Ωa Pr / Tr2.5

B = Ωb Pr / Tr

Tr is the reduced temperature equal to T/Tc and Pr is the reduced pressure equal to P/Pc .Tc and Pc are the critical temperature and pressure, respectively. Ωa and Ωb are purenumbers equal to [(9) (21/3 - 1)]-1 and (21/3 - 1)/3, respectively.



The pseudo critical properties of the gas (characterized by its gas gravity) required in theabove equations are estimated using the following empirical correlations:

Tc = 173.5 + 310.0 G

Pc = 695.7 - 38.0 G - e-7.0 + 7.6 G

where Tc is in R, Pc is in psia, and G is the gas gravity.

As the bubble location changes, the bubble temperature and pressure also change whichcause the molar volume (or compressibility factor) of the bubble to vary as describedabove. This variation in molar volume is nonlinear and requires an iterative solution todetermine an equilibrium pressure consistent with the bubble volume.

In this model, the mud hydrostatic head is based on a constant density independent ofpressure and temperature. However, the pressure head within the gas bubble is determinedby integrating the variable gas density from the bubble base to its top thus allowing localvariations in the compressibility factor with depth.

Mud Weight Kick Intensity Exceed Frac Gradient

If the mud weight plus the kick intensity exceed the fracture gradient anywhere in the openhole interval above the influx depth, a kick of any volume will necessarily result in the flowof gas from the influx depth into the formation where the fracture gradient has beenexceeded. In this case the kick cannot be conventionally circulated out of the hole until thefracture is sealed off. If this occurs, the internal pressure profile is determined from thefracture pressure at the fracture depth and the mud density:

Pinternal = Pfrac − g∗ρmud∗(TVDfrac − TVD)

This modification can only occur if the Limit to Frac at Shoe option is enabled.

Frac Gradient At The Shoe Is Exceeded

If the fracture pressure at the shoe is exceeded at any time while circulating the gas bubbleout of the hole and the Limit to Frac at Shoe option is enabled, the specified kick volumewill be reduced to the largest volume which will not exceed the fracture pressure at theshoe.

Lost Returns With Water

In addition to just using a water gradient to calculate this load case, a water/mud interfacecan be specified at a depth above the shoe.

From the hanger to the water/mud interface:

Pwater/mud = Pfrac − g∗ρmud∗(TVDshoe above open hole TD − TVDwater/mud)

Pinternal = Pwater/mud − g∗ρwater∗(TVDwater/mud − TVD)

From the water/mud interface to the shoe:

Pinternal = Pfrac − g∗ρmud∗(TVDshoe above open hole TD − TVD)



If just a water gradient is considered, this methodology can be simplified to:

Pinternal = Pfrac − g∗ρwater∗(TVDshoe above open hole TD − TVD)

The circulating temperature is based on the shoe depth where losses are occurring.

Pressure Test

A plug depth may optionally be specified when defining this load case.

From the hanger to the plug depth:

Pinternal = Ptest + g∗ρmud∗TVD

From the plug depth to the shoe:

Pinternal = g∗ρmud∗TVD

Displacement to Gas

The internal pressure at the shoe above the open hole TD due to the pore pressure and thegas gradient is given by:

Pshoe above open hole TD = Ppore − g∗ρgas∗(TVDinflux depth − TVD)

If this pressure exceeds the fracture pressure at that depth, Pfrac, and the Limit to Frac atShoe option is enabled, then the pressure from the hanger to the shoe is given by:

Pinternal = Pfrac − g∗ρgas∗(TVDshoe above open hole TD − TVD)

Otherwise, the internal pressure is given by:

Pinternal = Ppore − g∗ρgas∗(TVDinflux depth − TVD)

The circulating temperature is based on the influx depth. The worst-case temperatureprofile based on this temperature is used to calculate a gas density profile based on atemperature- and pressure-dependent compressibility factor if a gas gravity is specified.See the Gas Kick topic above for a description of the PVT behavior of gas.

Maximum Load Concept

This load case is modeled in StressCheck by selecting the Displacement to Gas load caseand specifying a mud/gas interface.

The internal pressure at the shoe above the open hole TD due to the pore pressure and thegas gradient is given by:

Pshoe above open hole TD = Ppore − g∗ρgas∗(TVDinflux depth − TVD)

If this pressure exceeds the fracture pressure at that depth, Pfrac, and the Limit to Frac atShoe option is enabled, then the pressure at the mud/gas interface is given by:

Pmud/gas = Pfrac − g∗ρgas∗(TVDshoe above open hole TD − TVDmud/gas)

Otherwise, the pressure at the mud/gas interface is given by:



Pmud/gas = Ppore − g∗ρgas∗(TVDinflux depth − TVDmud/gas)

From the mud/gas interface to the shoe:

Pinternal = Pmud/gas + g∗ρgas∗(TVD - TVDmud/gas)

From the hanger to the mud/gas interface:

Pinternal = Pmud/gas - g∗ρmud∗(TVDmud/gas - TVD)

The circulating temperature is based on the influx depth. The worst-case temperatureprofile based on this temperature is used to calculate a gas density profile based on atemperature- and pressure-dependent compressibility factor if a gas gravity is specified.See the Gas Kick topic above for a description of the PVT behavior of gas.

Surface Protection (BOP)

From the hanger to the shoe:

Phanger = Pfrac − g∗ρwater∗(TVDshoe above open hole TD − TVDhanger)

Pinternal = Phanger + g∗ρgas∗(TVD − TVDhanger)

The circulating temperature is based on the TD of the deepest hole section to which thecurrent string is exposed.

Gas Migration (Burst)

The internal pressure at the shoe due to reservoir pressure and annulus fluid hydrostatichead is given by:

Pshoe = Preservoir + g∗ρannulus fluid∗(TVDshoe − TVDprod casing hanger)

If Pshoe exceeds the fracture pressure at the shoe, Pfrac , and the Limit to Frac at Shoe optionis enabled, then from the hanger to the shoe:

Pinternal = Pfrac − g∗ρannulus fluid∗(TVDshoe − TVD)

Otherwise, from the hanger to the shoe:

Pinternal = Preservoir + g∗ρannulus fluid∗(TVD − TVDprod casing hanger)

Tubing Leak

This load case models a pressure profile due to a tubing leak during production. If packerand perforation depths have not been defined, they are both assumed to be at the shoe.

From the hanger to minpacker, shoe:

Pprod casing hanger = Preservoir − g∗ρreservoir fluid∗(TVDperforation − TVDprod casing hanger)

Pinternal = Pprod casing hanger + g∗ρpacker fluid∗(TVD − TVDhanger)

If the shoe is deeper than the packer, then from the packer to minperforation, shoe:



Pinternal = Preservoir − g∗ρreservoir fluid∗(TVDperforation − TVD)

If the shoe is deeper than the perforation, then from the perforation to the shoe:

Pinternal = Preservoir + g∗ρpacker fluid∗(TVD − TVDperforation)

Stimulation Surface Leak

This load case models a pressure profile due to a tubing leak during an injection operation.If the packer depth has not been defined, it is assumed to be at the shoe.

From the hanger to minpacker, shoe:

Phanger = Pinjection + g∗ρinjection fluid∗TVDprod casing hanger

Pinternal = Phanger + g∗ρpacker fluid∗(TVD − TVDprod casing hanger)

If the shoe is deeper than the packer, then from the packer to the shoe:

Pinternal = Pinjection + g∗ρinjection fluid∗TVD

Injection Down Casing


Pinternal = Pinjection + g∗ρinjection fluid∗TVD

This is the only production load case which uses a worst-case injection temperature profile.

External Pressure Profile

The standard burst external pressure profile is specified in StressCheck by selecting theAbove/Below TOC profile.

From the hanger to the TOC:

Pexternal = g∗ρmud∗TVD

If the TOC lies in cased hole, then from the TOC to the prior shoe:

PTOC = g∗ρmud∗TVDTOC

Pexternal = PTOC + g∗ρmix-water∗(TVD − TVDTOC)

With the Pore Pressure In Open Hole option enabled, then from max TOC, prior shoe tothe current shoe:

Pexternal = Pore pressure profile

A.2 COLLAPSE LOADS

Cementing

The internal pressure profile is given by:



Pinternal = g∗ρdisplacement fluid∗TVD

From the hanger to the TOC, the external pressure profile is given by:


From the TOC to the top of the tail slurry:

PTOC = g∗ρmud∗TVDTOC

Pexternal = PTOC + g∗ρlead slurry∗(TVD − TVDTOC)

From the top of the tail slurry to the shoe:

Ptail slurry top = PTOC + g∗ρlead slurry∗(TVDtail slurry top − TVDTOC)

Pexternal = Ptail slurry top + g∗ρtail slurry∗(TVD − TVDtail slurry top)

The circulating temperature is based on the current string's shoe depth.

Lost Returns With Mud Drop

Let the pore pressure in the open hole interval which generates the maximum mud drop bePpore at the depth TVDpore. Then, from the hanger to the shoe:

Pinternal = max Patm, Patm + Ppore − g∗ρmud∗(TVDpore − TVD)

The mud level is given by:

TVDmud level = TVDpore − Ppore/(g∗ρmud)

Both the default values for Ppore and TVDpore can be modified, if desired.

The circulating temperature is based on the depth at which the lost returns are occurring.

Full/Partial Evacuation

If a full evacuation is desired, the mud level should be specified to be the shoe depth (thedefault behavior).

From the hanger to the mud level:

Pinternal = Patm

From the mud level to the shoe of the current string:

Pinternal = Patm + g∗ρmud∗(TVD − TVDmud level)

The circulating temperature is based on the next open hole TD.

Above/Below Packer

This load case can be used to model several of the production collapse loads discussed inChapter 5. If the Fluid Drop Above Packer option is enabled, a partial evacuation ismodeled. If a fluid density below the packer of 0.0 ppg is specified, a full evacuationbelow the packer is modeled.



If the Fluid Drop Above Packer option is disabled, then from the hanger to the packer:

Pinternal = g∗ρfluid∗TVD

If the Fluid Drop Above Packer option is enabled, then from the hanger to the packer:

Pinternal = max Patm, Patm + Pperf − g∗ρfluid∗(TVDperf − TVD)

When this option is enabled, the fluid level is given by:

TVDfluid level = TVDperf − Pperf/(g∗ρfluid)

If the shoe of the current string lies below the packer, the internal pressure profile belowthe packer is based on either full evacuation or a selected fluid density.

For full evacuation, from the packer to the shoe:

Pinternal = Patm

Otherwise, from the packer to the shoe:

Pinternal = g∗ρfluid∗TVD

Gas Migration (Collapse)

The internal pressure profile from the hanger to the shoe is given by:

Pinternal = g∗ρpacker fluid∗TVD

The external pressure at the previous string's shoe due to reservoir pressure and mudhydrostatic head is given by:

Pprior shoe = Preservoir + g∗ρmud∗(TVDprior shoe − TVDprod casing hanger)

If Pprior shoe exceeds the fracture pressure at the prior shoe, Pfrac , and the Limit to Frac atShoe option is enabled, then from the hanger to the shoe:

Pexternal = Pfrac − g∗ρmud∗(TVDprior shoe − TVD)

Otherwise, from the production casing hanger to the shoe:

Pexternal = Preservoir + g∗ρmud∗(TVD − TVDprod casing hanger)

External Pressure Profile

The standard collapse external pressure profile is specified in StressCheck by selecting theAbove/Below TOC profile.



The Pore Pressure In Open Hole option should not be enabled for collapse loads. If saltloads have been specified, they will be superimposed onto this external pressure profile.



A.3 AXIAL LOADS

Running In Hole

This axial load profile does not represent a load distribution seen by the pipe at oneparticular time. Instead, it is constructed by calculating the maximum tension seen at eachpoint on the pipe while running the casing in the hole. Normally, the maximum tensionexperienced by a joint of casing is the tension when picking up out of the slips immediatelyafter making up the joint. The following factors are considered:

• Self weight.

• Buoyancy forces at the end of the pipe and at each cross-sectional area change due tothe mud hydrostatic pressure.

• Wellbore deviation, if applicable.

• Any bending due to specified doglegs. These loads are superimposed on the axial loaddistribution as a local effect using the following formulation:

Fbending = (E∗π/360)∗D∗(α/L)∗As

where

Fbending = axial force due to bending.E = elastic modulus.D = nominal OD.α/L = dogleg severity (°/unit length).As = cross sectional area of the pipe.

If you specify a non-zero average running speed, the axial profile will be modified toinclude the effect of the pipe stopping abruptly. This can occur if the pipe hits anobstruction or the slips close while the pipe is moving. The additional axial force due tothis deceleration, assuming that the peak pipe velocity is one and a half times the averagerunning speed and that the deceleration is instantaneous, is given by the following equation:

Fshock = 1.5∗Vav∗As∗(E∗ρs)½

where

Fshock = axial force due to shock loading.Vav = average running speed.As = cross sectional area of the pipe.E = elastic modulus.ρs = density of steel.

Overpull Force

If you select this load case and specify an overpull force, an axial load profile will beconstructed to consider this incremental force above the current hookload when running



the casing string in the hole. Like the Running Load profile, this axial load profile does notrepresent a load distribution seen by the pipe at one particular time while running the pipe(i.e., the overpull force is not just applied when the casing is on bottom). Instead, the caseis considered at each stage of the running operation (i.e., with the casing shoe at a range ofdepths from the surface to the setting depth). The load profile is constructed using themaximum force seen at each point on the pipe during the entire running operation. If nooverpull force is specified, this case is identical to the Running Load case with no shockloads. The following factors are considered:

• Overpull force. This force is applied at the surface with the stuck point alwaysassumed to be the bottom of the string.

• Self weight.



• Any bending due to specified doglegs. These loads are superimposed onto the axialload distribution as a local effect. The bending load formulation is included in theRunning In Hole load case description above.

Green Cement Pressure Test

If you select this option and specify a test pressure, an axial load profile will be calculatedwith the casing just off bottom and the cement in place but still in its fluid state. Thisoccurs if you bump the top plug and pressure up after displacing the cement to the landingor float collar. Since the bottom of the casing string is not fixed in place by hardenedcement, the piston force resulting from the test pressure acting on the top plug causes asignificant increase in the axial load. The following factors are considered:

• The test pressure, which is applied to the inside of the casing and acts on a cross-sectional area of the casing ID at the float collar depth.

• Self weight.



• Any bending due to specified doglegs. These loads are superimposed onto the axialload distribution as a local effect. The bending load formulation is included in theRunning In Hole load case description above.

Service Loads

This load case models axial loads caused by service loads selected as the burst and collapsecriteria and which occur after the casing string has been cemented in place. The axial force



profile represents the envelope (maximum at each depth) of the individual axial forceprofiles corresponding to the selected burst and collapse load cases. The calculationsinclude the effects of self-weight, buoyancy, intermediate and end piston, ballooning,thermal expansion or contraction due to temperature changes, bending and buckling. Theinitial conditions are calculated from the cementing and landing data and the initialtemperature profile is assumed to be the undisturbed temperature profile.

Service loads are discussed in more detail in Section 9.2.

hasa casing design

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