REPSOL Casing Design-Normas

Drilling and Production Operations Ref: INDEX

CASING DESIGN MANUAL Issue: Feb 2000

INDEX Page 1 of 1

Introduction CDES 01

Casing Material and Properties CDES 02

Design Concepts CDES 03

Design Preparation CDES 04

Casing Seat Selection CDES 05

Mechanical Design CDES 06

Pressure Testing CDES 07

Special Cases CDES 08

Casing Design Report CDES 09

Example Casing Design CDES 10

References CDES 11

Drilling and Production Operations Ref: CDES 01


SECTION 1 INTRODUCTION Page 1 of 4

TABLE OF CONTENTS

1. INTRODUCTION.................................................................................................... 2

1.1 GENERAL ........................................................................................................ 2

1.2 OBJECTIVES................................................................................................... 2

1.3 SCOPE............................................................................................................. 2

1.4 READERSHIP.................................................................................................. 3

1.5 DISTRIBUTION................................................................................................ 3

1.6 REVISIONS...................................................................................................... 3

1.6.1 Process of Manual Revision and Amendment ............................................ 3

1.6.2 Revision, Review and Reissue ................................................................... 3

1.7 ACKNOWLEDGEMENT................................................................................... 4

INTRODUCTION Page 2 of 4

1. INTRODUCTION

1.1 GENERAL

The purpose of this manual is to provide guidance on Repsol’s preferred CasingDesign methods. This manual should be read in conjunction with the other manuals inthe Drilling and Production Operations Manuals suite.

The latest edition of the relevant American Petroleum Institute (API) standards,recommended practices and bulletins must also be available to casing designers.

This manual is not intended to provide a complete rulebook universally applicable in allcircumstances and operating environments. It must not replace sound judgementbased on a thorough knowledge of well design principles or a detailed knowledge of aparticular situation or specific field. Users of this manual are reminded that nopublication of this type can be complete, nor can any written document be substitutedfor qualified engineering analysis. It should be stressed that certain operations willrequire detailed and frequently site specific operational procedures. This manual is notintended to replace more detailed procedures and vendor manuals, which remain thesource of reference for technical specialists.

Nevertheless, it is recommended that the manual should be adopted as standardpractice and deviations should be employed only in special circumstances that havebeen carefully considered and approved by management.

1.2 OBJECTIVES

The objective of this manual is to reduce the cost of Repsol’s casing designs whilstensuring that well integrity is not compromised.

1.3 SCOPE

This manual covers the design of all casing strings from large diameter conductors tosmall diameter production liners. Failure modes discussed include burst, collapse,tension and buckling. Triaxial (Von Mises) analysis is also included for critical wells.Subjects such as temperature effects, casing wear and the effects of hostile gases arealso reviewed. A section is included that introduces basic metallurgy, mechanicalproperties, casing manufacture, connections and casing inspection. As casing designis at the core of well design, a number of casing and well design checklists areincluded to ensure that all the relevant data has been considered.

Test strings and completions are not addressed in this manual.


1.4 READERSHIP

This document is aimed at:

� Drilling Engineers involved in designing and planning Repsol’s wells

� Other disciplines who may be involved in these activities

It will acquaint the new engineer with the various aspects of casing design. It willprovide the more experienced engineer with a comprehensive range of informationwhich will enable casing strings to be designed to meet the operational requirements.

1.5 DISTRIBUTION

Distribution of the manual is controlled to ensure that revisions in circulation arecurrent. The manual is prepared in both printed and electronic form. The manual isavailable either on local area networks or CD-ROM for locations without networks.Paper extracts can be printed from CD, although their circulation should be restrictedas these copies will be uncontrolled.

1.6 REVISIONS

1.6.1 Process of Manual Revision and Amendment

The custodian of this manual is the Head of Drilling Engineering in Madrid. Allsuggestions for revision to this manual should be addressed to this person. Theproposal should include the exact changes suggested, a justification for the changesand the details of the person making the suggestion.

1.6.2 Revision, Review and Reissue

Incorporation of authorised revisions to the manual will be co-ordinated by Repsol inMadrid.

Repsol Madrid will also instigate regular formal reviews of the manual using internaland external expertise.

Repsol Madrid will administer the relevant documentation including:

� Processing of amendment suggestions

� Revision of the relevant sections

� Maintaining a record of amendments

� Preparation of revised copies of the manual


1.7 ACKNOWLEDGEMENT

This manual was prepared by Allomax Engineering and published both in paper andCD format by Offshore Design Limited (ODL), both of Aberdeen, Scotland.



SECTION 2 CASING MATERIAL AND PROPERTIES Page 1 of 38

TABLE OF CONTENTS

2. CASING MATERIAL AND PROPERTIES.............................................................. 3

2.1 SPECIFICATION FOR CASING (API 5CT)...................................................... 3

2.1.1 Outside Diameter (OD) (in)......................................................................... 3

2.1.2 Nominal Unit Weight (lb/ft).......................................................................... 3

2.1.3 API Steel Grades........................................................................................ 5

2.1.4 Connection Types....................................................................................... 6

2.1.4.1 API Connections ........................................................................................ 6

2.1.4.2 Non-API Connections ................................................................................ 7

2.1.4.3 Large Diameter Connections ..................................................................... 7

2.1.4.4 Connector Assessment.............................................................................. 8

2.1.5 Range Length ............................................................................................. 8

2.1.6 Manufacturing Process............................................................................... 9

2.1.7 Inspection ................................................................................................. 10

2.1.7.1 Defects/Imperfections .............................................................................. 10

2.1.7.2 Pipe Inspection ........................................................................................ 11

2.2 ENGINEERING DEFINITIONS, METALLURGY AND PROPERTIES............ 15

2.2.1 Engineering Definitions............................................................................. 15

2.2.2 Steel and Steel Alloys............................................................................... 21

2.2.2.1 Steel Phases ........................................................................................... 21

2.2.3 Codes and Standards ................................................................................ 24

2.2.3.1 API Codes – General Application............................................................. 25

2.2.3.2 National Association of Corrosion Engineers(NACE Standard MR0175-99) .................................................................. 26

2.2.3.3 Institute of Petroleum............................................................................... 27

2.2.3.4 ASME/ASTM/ANSI .................................................................................. 27

2.2.3.5 International Standard Organisation (ISO) ............................................... 27

2.2.3.6 Committee for European Normalisation (CEN)......................................... 28

2.2.3.7 Co-operation between ISO, CEN and API................................................ 28

CASING MATERIAL AND PROPERTIES Page 2 of 38

2.2.4 Non-API Casing Grades/Special Materials ............................................... 29

2.2.4.1 Sour Service ............................................................................................ 29

2.2.4.2 Carbon Dioxide Service ........................................................................... 30

2.2.4.3 Carbon Dioxide/Mixed Corrosive Environments ....................................... 31

2.2.4.4 High Strength........................................................................................... 33

2.2.4.5 High Collapse .......................................................................................... 33

2.2.5 Temperature Effects on Metallic Properties .............................................. 34

2.2.5.1 High Temperature .................................................................................... 34

2.2.5.2 Arctic (Low) Temperatures....................................................................... 34

2.2.6 Effects of Gases on Materials................................................................... 35

2.2.6.1 Hydrogen Sulphide .................................................................................. 35

2.2.6.2 Hydrogen Embrittlement .......................................................................... 35

2.2.6.3 Hydrogen Induced Cracking..................................................................... 35

2.2.6.4 Sulphide Stress Cracking......................................................................... 35

2.2.6.5 Carbon Dioxide ........................................................................................ 36

2.2.7 Effects of Liquids on Materials.................................................................. 36

2.2.7.1 Chlorides/Bromides.................................................................................. 36

2.2.8 Corrosion.................................................................................................. 36

2.2.8.1 Corrosive Parameters .............................................................................. 36

2.2.8.2 Common Corrosion Types ....................................................................... 37


2. CASING MATERIAL AND PROPERTIES

2.1 SPECIFICATION FOR CASING (API 5CT)

This is covered by the American Petroleum Institute generic document API 5CTSpecification for Casing and Tubing which covers seamless and welded casing andtubing, couplings, pup joints and connectors in all grades. Processes of manufacture,chemical and mechanical property requirements, methods of test and dimensions arealso included.

Casing is usually classified in terms of the following:

� Outside diameter (OD) (in)

� Nominal unit weight (lb/ft)

� API steel grades

� Connection types

� Range length

� Manufacturing process

� Inspection

2.1.1 Outside Diameter (OD) (in)

This refers to the OD of the pipe body and for casing is +1% and -0.50%. The couplingwill be of a greater OD. Casing sizes vary from 4-1/2in to 36in diameter. Tubulars withan OD of less than 4-1/2in are normally called tubing.

2.1.2 Nominal Unit Weight (lb/ft)

The term ‘nominal unit weight’ is applied to casing and to all tubulars with threaded andcoupled or upset and threaded connections. It is not the exact measure of the weightper foot of any joint of casing. It is used primarily for ordering casing and is used in ageneral sense for determining casing weight, when designing casing strings.


For each casing size there are a range of casing weights available. For example, thereare four different weights of 9-5/8in casing:

Table 2.1 - 9-5/8in Casing Weights

WEIGHT(lb/ft)

CASING OD(in)

NOMINAL ID(in)

WALLTHICKNESS

(in)

DRIFTDIAMETER

(in)

53.5 9.625 8.535 0.545 8.379

47 9.625 8.681 0.472 8.525

43.5 9.625 8.755 0.435 8.599

40 9.625 8.835 0.395 8.679

Although there are strict tolerances on the dimensions of casing, set out by API, theactual inside diameter (ID) will vary slightly on the manufacturing process. For thisreason the drift diameter of casing is quoted in the specifications for all casing. The driftdiameter refers to the guaranteed minimum ID of the casing. This may be importantwhen deciding whether certain drilling or completion tools will be able to pass throughthe casing, eg the drift diameter of 9-5/8in 53-1/2in lb/ft casing is less than an 8-1/2inbit. If an 8-1/2in hole size is necessary, then a lower weight will be required eg 47 lb/ft.

If the 47 lb/ft casing were too weak for the particular application, then a higher grade ofcasing would be used. The nominal ID of the casing is used for calculating thevolumetric capacity of the casing.

In order to eliminate the need for odd bit sizes, (eg 5-7/8in, 8-3/8in and 12in) ‘alternatedrift’ casing is generally specified whenever possible. Standard drift sizes are given inAPI 5CT. It may be necessary to specify smaller dimensional tolerances for alternatedrift casing. For example, API 5CT cites pipe body OD tolerances for size 4-1/2in andlarger as +1.0%/-0.5%. Reduction of the pipe body tolerances to +0.75%/-0.50%reduces this issue and also improves the collapse load bearing capacity. The wallthickness tolerance is quoted as -12.5% of the nominal pipe size.


2.1.3 API Steel Grades

The chemical composition of the casing varies widely, and is dependent upon thechemical composition and treatment processes during manufacturing. As a result, thephysical properties of the steel vary widely. The resulting materials utilised forthe manufacturing processes have been classified by API into a series of grades.A summary of the grades is included in Table 2.2.

For more detailed information, refer to API 5CT.

Each grade is designated by a letter and a number. The letter refers to the chemicalcomposition of the material and the number refers to the minimum yield strength of thematerial eg N-80 has a minimum yield strength of 80,000psi and K-55 has a minimumyield strength of 55,000psi. Hence the grade of the casing provides an indication of thecasing strength; the higher the grade, the higher the strength of the casing. Theminimum yield strength is the most important physical property of steel used in casingstrings. It is used to calculate most of the minimum performance properties presentedin API 5C2.

In addition to the API grades, certain manufacturers produce their own grades ofmaterial. Both seamless and electric welded tubulars are used as casing, althoughseamless casing is the most common type of casing. API 5CT also sub divides thegrades into group grades, which defines the requirements for manufacture and heattreatment. For more detail on the API Casing Grades refer to API 5CT.

Table 2.2 - Summar y of Casing Grades and Properties

YIELD STRENGTH (PSI)GROUPGRADE

GRADE

MINIMUM MAXIMUM

MIN TENSILESTRENGTH (psi)

1 H-40 40000 80000 60000

1 J-55 55000 80000 75000

1 K-55 55000 80000 95000

1 N-80 80000 110000 100000

2 L-80 80000 95000 95000

2 C-90 90000 105000 100000

2 C-95 95000 110000 105000

2 T-95 95000 110000 105000

3 P-110 110000 140000 125000

4 Q-125 125000 150000 135000


2.1.4 Connection Types

Individual joints of casing are connected together by a threaded connection. Theseconnections are classified as: API, premium or proprietary (gastight and metal-to-metal seal).

For many years API thread connections, with or without a resilient seal ring, have beenthe standard in wellbore casing strings.

The standardised connections are:

2.1.4.1 API Connections

� API 8 Round Thread, STC (short thread coupling) or LTC (long thread coupling) forcasing: The STC thread profile is rounded with 8 threads per inch. The LTC issimilar but with a longer coupling, which provides better strength and sealingproperties than STC. Sealing is a combination of connection geometry andthread dope

� API Buttress Thread for casing: The front and back flanks of the thread profile arecut at different angles to improve the resistance to thread jump-out. Buttressthreads do not provide for a positive seal. There is a continuous void over the wholeflank of the thread on the bevelled side. Sealing is a combination of threadgeometry and thread dope

Figure 2.1 - Thread Forms

In addition to threaded and coupled connections there are also externally and internallyupset connections.

� API Extreme Line Thread for casing: This connection type is the only APIconnection that has a metal-to-metal seal at the end of the pin and externalshoulder of the connection (Figure 2.2)

Figure 2.2 - Extreme Line

BOX PIN

STA

B FLA

NK

S

LOA

D F

LAN

KS

API BUTTRESSAPI 8- ROUND

BOX

PIN

PIN B O X

METAL-TO-METAL SEAL


2.1.4.2 Non-API Connections

Over a number of years there has been a shift away from simple shallow wells tocomplicated, deeper, corrosive and high pressure/temperature wells. This has led tothe need for connections with better sealing capability than API and led to thedevelopment of Premium connections.

Premium connections are provided in a number of categories and typically include:

� Metal-to-metal seal, threaded and coupled. These include connections such as:Vallourec (New Vam), Huntings (Fox), Nippon Steel (NS-CC) Atlas Bradford(TC-4S)

� Metal-to-metal seal, upset and integral (or coupled)

� Metal-to-metal seal, formed and integral (flush)

� Weld on, upset and integral

2.1.4.3 Large Diameter Connections

Weld on large diameter connections generally incorporate the following diameterranges eg conductor (26in to 42in) and surface pipe (18-5/8in to 24-1/2in).

2.1.4.3.1 Connector Selection Issues

As part of the well design of large diameter connections for conductors and surfacecasing, the following issues should be considered prior to selection:

� Well type: land, platform, jack-up or semi-submersible

� Installation: cemented or driven by hammer

� Loading: bending moments, tension, compression and pressure as part of thewellhead system, compared to pipe body

� Fatigue: cyclic and stress concentrations

� Ease of use: stabbing

� Additional requirements: specialist equipment, technical support

� Temperature: high or Arctic low

� Water depth: deep water or shallow with subsea currents

� Anti-rotation capability (locking tabs)


2.1.4.3.2 Connector Categories

Connector types generally available for conductors fall into one of the followingcategories:

� Interference non-helical toothed connector pin and box components assembled byradial expansion of one component over the other, with good fatigue properties andhigh preload capability. (Typical types: Hunting Merlin and Talon, Vetco SR-20)

� Squnch type connector which snaps together, generally easy to assemble withgood mechanical strength but no pre-load (typical types: Vetco ST-2, ALT-2Hunting Lynx SA, Dril-Quip HD-90)

� Screw thread connector, relatively easy to assemble, with pre-load capability(Typical Types: Vetco RL-4, Dril-Quip Quick Thread H-90D and HuntingLeopard SD)

2.1.4.4 Connector Assessment

The choice of connector for the well design will require assessment in order to ensureit is not creating an undue weakness in the well design. Hence the requirement todetermine the correct technical requirements of the well operating envelope. Forexample, if planning a deep production casing string, will it require metal-to-metalsealing with gas tightness, good axial tensile strength, axial compressive strength andthe ability to maintain strength and sealing at high pressures and temperatures? Therequirements and connection characteristics may even require using a connector thathas been tested through empirical testing to prove that it is fit for purpose for itsintended use. This is known as qualification testing.

2.1.5 Range Length

The length of a casing and liner joint has been standardised and classified by the API.The following Table 2.3 is a summary which reflects the lengths of casing:

Table 2.3 - Summary of Range Lengths

Range 1 2 3

Total Range Length (ft) 16 to 25 25 to 34 34 to 48

Permissible Variation, max 6 5 6

Permissible Length, min 18 28 36

Typical Average Length (ft) 22 31 42


2.1.6 Manufacturing Process

Pipe is made either by seamless (S) or electric weld (EW) process as defined withinAPI 5CT.

Seamless pipe is defined as a wrought steel tubular product made without a weldedseam. It is manufactured by heating, followed by piercing and hot rolling a piece ofsteel called a billet.

The billet is run through a series of forming and shaping operations to make a tube.The tube may require subsequent cold finishing the hot worked tubular product toproduce the desired shape, dimensions and properties. Imperfections such aseccentricity, formed during the heating and working during manufacture may result inthe rejection of the pipe during inspection.

Figure 2.3 - Piercing

Figure 2.4 - Hot Rolling

BILLETP I E R C E R

P L U G O R M A N D R E L


Figure 2.5 - Welded (Seamed) Pipe Manufacture

Electric welded pipe is defined as pipe having one longitudinal seam formed byelectric-resistance or electric-induction welding, without the addition of filler metal,where the edges to be welded are mechanically pressed together and the heat forwelding is generated by resistance to flow of electric current. It is formed by rolling asteel plate and welding the seam. Imperfections can occur during manufacture of theplate and the welding of the seam.

2.1.7 Inspection

Inspection of casing takes place at all stages from manufacture, through delivery, tofinal inspection prior to use on the rig. Particular inspection requirements are used forrecovered, or pipe that is not new.

The purpose is to identify and remove pipe that is deemed ‘not fit for purpose’ priorto use.

Inspection after immediate manufacture will identify defects and imperfections asdefined within Section 9 of API 5CT.

An imperfection is a discontinuity, or irregularity in the product. A defect is animperfection of sufficient magnitude to warrant rejection of the product based on thestipulations of the specification.

2.1.7.1 Defects/Imperfections

Examples of imperfections and defects include:

� Eccentricity: Where the OD and ID centres are at different points, resulting in a wallthickness variation and reduction in collapse rating. This typically occurs duringmanufacture of seamless pipe

� Seams: Usually occurs during the manufacture of seamless pipe when a crevice isrolled and closed into the original steel billet. This causes a reduction in the burst ofthe pipe

� Ovality: Can occur during manufacture resulting in gauging and the drifting of thepipe. This is more of an issue on larger, thin walled pipe

CURRENT

ELECTRODES

SKELP (PLATE) FROM REEL

AFTERFORMING

WELDINGFINISHED

TUBE


2.1.7.2 Pipe Inspection

API 5CT also includes the following issues for pipe inspection:

� Non-destructive inspection of pipe body

� Non-destructive inspection of weld seam

� Ultrasonic or electromagnetic inspection of pipe body

� Magnetic particle inspection of the pipe body

� Disposition of inspection indications and additional inspection requirements forupset products

Some examples of the techniques employed for casing inspection are:

2.1.7.2.1 Detecting Imperfections and Defects

a. Magnetic Particle Inspection (MPI)

Commonly used method for finding surface and near surface flaws in ferromagneticmaterial. The item to be inspected is first cleaned and then magnetised by passingelectrical current through a magnetising device. Magnetic disturbances called‘leakage fields’ are formed around surface and near surface flaws in the test piece.

Soft iron particles are applied to the surface and the particles are attracted to theleakage field near the flaws. Particle buildups are visually identified and theimperfection or defect area is then evaluated by grinding and mechanicalmeasurement.

� Dry Visible Method: Iron powder is applied dry and the test piece is viewedunder normal light

� Wet Fluorescent Method: Iron particles are coated with fluorescent material that‘glows’ under ultraviolet light. The particles are suspended in a liquid carrier andapplied to the test piece by spraying or dipping the piece in a liquid carrier. Afterpowder application, the piece is viewed under ultraviolet (black) light

� Residual Method: Particles may be applied either wet or dry but the magnetisingcurrent is turned off before powder application. The remaining residual magneticfield in the piece is used for inspection

� AC or DC: Refers to the type of electrical current used to magnetising the piece

b. Full Length Ultrasonic Inspection (FLUT)

Early systems consisted of an immersion tank to hold a length of pipe, whichoperated transducers longitudinally, transversely and for wall thickness. Latersystems added transducers to scan obliquely around the pipe. Furthermodifications included transducers arranged in rings that scan inward, reducingthe possibility of missing defects that were not orientated correctly.


Ultrasonic techniques also include inspection of the weldline. Shear wavetransducers are positioned for a transverse scan of the weld. Either the pipe or thetransducer may be held stationary whilst the other moves manually or automaticallydown the weldline.

c. Electromagnetic Inspection (EMI)

EMI (or ‘flux leakage’ or ‘diverted flux’ inspection), is the most common used full-length inspection method in the oil industry. Typically it is used in conjunction withother methods.

A strong energising DC field creates leakage around the flaws (similar to MPI),except the method of detecting the leakage employs a conductor (coil) or someother device such as a Hall-Effect sensor, passing through the field. A voltage isgenerated as it moves through a magnetic field. The voltage generated by the coilcutting the flux is amplified and displayed by a voltmeter. Should the voltage exceeda certain amount known as the threshold level, the operator investigates to see if aflaw is present. (Tubing and casing are usually inspected for longitudinal andtransverse defects.)

EMI has its limitations. For instance wall thickness can normalise instrumentresponse when inspecting internally pitted pipe. Also, there is limited precision ofthe EMI method due to factors not under the control of the operator eg flaworientation, size, depth and shape. As a result EMI signal amplitude cannot bedirectly related to flaw severity.

d. Liquid Penetrant Inspection (LPI)

This is of limited usefulness as it can only used when the defects are at surface.The process is complex, time and temperature sensitive. As a result it is used forinspecting threaded ends of corrosion resistant alloys (CRA) pipe and couplingsthat were not inspected ultrasonically before threads were cut on the pipe.

e. Visual Thread Inspection (VTI)

Visual thread inspection is normally performed at the rig location prior to running ofthe casing. It is important to ensure that no damage has occurred duringtransportation or storage. Particular points to note are that the threads are initiallywell greased, that there is no rusting or other corrosion in the thread form and thatthere are no sharp edges. Minor surface defects may be cleaned off prior to runningbut any significant damage should lead to the joint being rejected and being sent offfor specialist repair.

f. Visual Tube Inspection (VTT)

As with visual thread inspection, visual tube inspection should be performed at thewell site prior to running in the hole. Joints, which are bent, show evidence ofimpact damage or of excessive corrosion (internal or external) should be rejected.All tubulars, which arrive at the well site, should be permanently marked to indicatethe size, weight, grade and manufacturer. Any joints, which are not adequatelymarked, should be rejected since the wrong weight or grade of casing may lead tototal well loss.


2.1.7.2.2 Measuring Dimensions

a. Ultrasonic Wall Thickness Measurement (UWTM)

Ultrasonic techniques have the advantage of being able to find flaws in thick walledpipe. The technique does not require magnetisation and so works well on non-magnetic corrosion resistant alloy casing as well as basic steel pipe. Ultrasonicinspection is a non-destructive method in which pulses of high frequency soundwaves are used to measure wall thickness, or detect flaws in pipe.

A sound pulse is sent into the pipe wall perpendicular to the pipe surface. As thesound travels through the wall, it bounces off the inside and returns to thetransducer. The thickness gauge measures the time elapsed between the pulseand returning echo. A software package within the tool then calculates and displaysthe wall thickness. If the ultrasonic wall thickness instrument is calibrated and usedproperly, it is capable of measuring the pipe wall in the field to within a fewthousandths of an inch.

The unit is calibrated using a wall thickness standard with accurately machinedsteps. The standard must have the same acoustic velocity as the pipe to be tested.

Limitations: wall thickness gauges should not be used to measure remaining wallunder sharp-bottomed pits or other such irregularities as much of the sound isreflected away from the transducer and lost. Thus, the echo returns over a longertime, indicating more distance (wall thickness) than is actually present.

The unit comprises four primary components:

� Transducer � Display

� Signal conditioning unit � Thread gauging (TG)

All tubular threads are manufactured to close tolerance with some acceptablevariation due to allow for inaccuracies in the manufacturing process. Occasionallythe manufacturing process will produce a thread in which all of the toleranceallowances add up to produce a thread which is out of specification. In order to testfor this, special thread gauges are used which are manufactured to a closertolerance than the threads. Both male and female thread forms are available whichcan be made up to the ends of the casing. Particular points to check are that thethread gauge makes up to the correct depth, that there is no free play in theconnection and that if there are metal-to-metal seals that these are capable ofmaking up.

b. Gamma Ray Wall Thickness Measurement (GRWT)

These systems can give a reliable measurement of wall thickness, provided theyare calibrated properly. They are usually linked as part of a four function EMI unitand measure the pipe body wall thickness.

A beam from a gamma-ray source is focused to pass through the wall of the pipe.As the beam is attenuated and reflected, a measure of wall thickness can beinferred. In order to cover more area of the pipe, the unit rotates around the pipe asit passes through the beam.


Several techniques are available:

� Single Wall/Centre Receiver: A GR sensor is positioned inside the pipe tomeasure the amount of radiation passing through the wall. Intensity of thebeam is inversely proportional to wall thickness

� Single Wall/Chord: The radiation beam is directed through a chord of the pipecircumference. As with the single wall technique, the amount of radiation thatpenetrates the pipe wall is inversely proportional to the wall thickness

� Single Wall Reflection (backscatter): A scintillation counter is used to measurethe intensity of the beam reflected from the metal. Reflected radiation, while asmall part of the total, is proportional to the pipe wall thickness

� Double Wall Attenuation: The same principles apply as for single wallattenuation, except that the radiation is transmitted and measured through twowalls and averaged. These measurements are made with the counter placedoutside the pipe. Since double wall units are not capable of picking upeccentricity, this method is not suitable for inspecting seamless pipe

A limitation of GR systems is they usually do not cover the complete pipe surface.However, the systems are quite capable of measuring gross wall thickness andconditions such as eccentricity, rod wear, thin wall and casing wear. However, thesystems discussed cannot accurately measure the remaining wall for small-localised defects, nor can they detect a flaw or condition unless a significant volumeof metal is missing. Thus, they cannot detect flaws such as seams, or cracks andshould not be used for detecting small defects.

2.1.7.2.3 Additional Methods

Under API this includes hydrotesting (pressure), measurement of the materialhardness and material grade verification.

a. Hydrotesting

All API casing is hydrotested plain end at the mill with pressure for a five-secondtest, prior to thread coupling the pipe.

b. Hardness Testing

This includes the three primary methods; Rockwell, Brinell and Vickers.

� The Rockwell Test: Performed using a conical diamond indenter and the depthof the indent is measured by initially applying a 10kg minor load, followed by a150kg major load


Various scales are used, designated by a letter. However, the ‘C’ scale iscommonly used for casing and tubing.

� The Brinell Test: Performed using a small hardened steel ball and applying a3000kg load. The load is applied and the size of the indent is measured acrossthe corners

� The Vickers Test: Performed using a pyramidal diamond indenter and applyingloads as low as 100g (microhardness) and high as 120kg (macrohardness). Theindent is measured across the corners and is proportional to the load applied bythe area of the indentation. The Vickers scale can cover a range ofmicrohardness and macrohardness with the same indenter

c. Grade Verification

A grade verifier, or grade comparator is usually packaged as one of the systems ina four system EMI (electromagnetic inspection) package. Its use and accuracy areregarded as limited, as there is no reliable relationship between the propertiesmeasured (magnetic permeability and mass) and yield strength. Most gradeverifiers work on the principle of eddy currents within the steel. An AC coilsurrounds the pipe. By use of Ohm’s Law, the current is used to measure thechanges in coil inductance, which will vary with magnetic permeability.

d. Inspection Summary

It is the responsibility of the Drilling Engineer to ensure that the functionalspecification of the casing pipe and selected connections to be used are ‘fit for theintended use’ for the proposed well design. The Drilling Engineer must alsoevaluate and state what inspection level is required as part of the pipe purchaseorder and ensure this is specified for each phase. For example third party at themill, at the end of the pipe mill run and delivery to the pipe yard. API providesguidance on this for the various phases.

2.2 ENGINEERING DEFINITIONS, METALLURGY AND PROPERTIES

2.2.1 Engineering Definitions

Casing design can be summarised as a problem in stress analysis. Prior to examiningstress analysis techniques a number of mechanical engineering definitions areexplained to assist the reader, prior to conducting a well design.

a. Load

The term load is used to describe the effect on the casing of its operatingenvironment. The loads may be static or dynamic. Static loads may consist ofweight in air, pressure, temperature, point loads, bending and drag. Dynamic loadsmay include shock and drag.


b. Force

A force within the casing is a result of a load.

c. Stress (��)

Stress is the force per unit area exerted by one of the adjacent parts of a body uponthe other across an imaginary plane of separation. When the forces are parallel tothe plane, the stress is a shear stress (��When the forces are normal to the planethe stress is a normal stress (�) and is either compressive, when acting inwards ortensile when acting outwards.

d. Principal Stress (��)

Through any point in a stressed body pass three mutually perpendicular planes, thestress on each of which is purely normal, ie there are no shear stresses. Thestresses on these principal planes are the principal stresses: �� Whenone of the principal stresses is zero, the condition is one of biaxial stress, wheretwo principal stresses are zero, the condition is one of uniaxial stress.

e. Strain (�)

Strain is the deformation resulting from imposed loads. Elongation (positive) orcontraction (negative) is caused by normal forces and is measured in terms of thechange in length per unit of original length (see Figure 2.6).

Shear forces cause a shear strain measured, for small strains, in terms ofthe change in angle (radians) between two lines originally at right angles(see Figure 2.6b).

f. Elasticity

Elasticity is the ability of a material to sustain stress without permanentdeformation. For linearly elastic materials a proportionate relationship existsbetween stress and strain (Hooke’s Law).

g. Plastic Deformation

Plastic deformation is the permanent deformation of the material occurring atstresses above the elastic limit.

h. Elastic Limit

The elastic limit is the least stress that will cause a permanent deformation(see Figure 2.7). This will occur at a total strain of between 0.12% and 0.2%,depending on steel grade, ie the yield strength.


Figure 2.6 - Elongation Strain and Shear Strain

L1

ZZ26323.056

L2

OriginalLength

DeformedLength

dL

Elongation Strain = =L2 - L1

L1

dL

L1=

A

3

OriginalAngle

DeformedAngle

Shear strain = �xy = �/2

�

B


Figure 2.7 - Stress/Strain Relationship in Casing Material

Brittle ZoneDuctile Zone

E lasticDeform ation

P lastic Hardening P lastic Softening

Perm anent Deform ation

E lastic lim it(onset of yielding)

U ltim ateTensile S trength

Nom

inal

str

ess

(bas

ed o

n or

igin

al d

imen

sion

s)

TotalS train

i. Ductility

Ductility is the ability to sustain appreciable plastic deformation without rupture.A ductile material can flow, stretch, change its permanent form and remain in onepiece. Non-ductile materials are referred to as being brittle.

j. Elongation

In tensile testing the extension of a test-piece when stressed to fracture, usuallyexpressed as a percentage of a specified gauge length. This is a measure of theductility of the material.

k. Modulus of Elasticity, or Young’s Modulus (E)

The modulus of elasticity is the rate of change of stress with strain in an uniaxialcondition within the elastic limit. In general, the modulus of elasticity is the same intension and compression. For isotropic materials, such as steel, E is the same in alldirections. A value of 30 x 106psi is usually used for tubular steel. At yield strengththe actual value will be lower than the published value, but this is usually ignoredin calculations.

l. Poisson’s Ratio (�)

Poisson’s ratio is the ratio of lateral strain to longitudinal strain under uniform,uniaxial longitudinal stress within the elastic limit. For steel a value of 0.3 isusually taken.


m. Yield Strength or Yield Stress (�y)

The yield strength or yield stress is the uniaxial stress at which the material exhibitsa specific deformation (see Figure 2.8). The yield stress is taken as a measure ofthe maximum allowable stress for most engineering applications, includingcasing design.

Figure 2.8 - API Yield Strength Definition (Valid to 95kpsi)

API YieldStrength

Nom inalStress,

Strain,

0.5%

�

�

Ideal elastic/plastic behaviour, valid up to 95,000 psi

API Spec 5CT [10] defines the yield strength as uniaxial nominal stress occurring at0.5% total strain for materials up to 95,000psi minimum yield strength, at 0.6% totalstrain for 110,000psi minimum yield strength, and at 0.65% total strain for125,000psi minimum yield strength. In many other engineering applications a 0.2%permanent deformation is used to establish the yield strength, and this willsometimes be found in non-API publications on tubular performance.

Yield strength is temperature dependent. For steel, the yield strength decreases astemperature increases. For some low strength easing grades (J55) yield strengthwill initially decrease as temperature increases, but as temperature furtherincreases, the yield strength will rise to a level above that evident at roomtemperature.

A typical yield strength temperature correction applied to casing is: 0.03% above68�F (20�C). This typically results in a 10% reduction in the yield strength for acasing string with a bottom hole temperature of c. 330�F.

Specific data on temperature correction applications can be obtained from thecasing manufacturers.


n. Ultimate Tensile Strength (�UTS)

The ultimate tensile strength is the maximum nominal stress that a material cansustain under axial loading. It is calculated on the basis of the ultimate load and theoriginal unrestrained dimensions.

o. Fatigue

Fatigue is the tendency of materials to fracture under repeated loading to a stressbelow the ultimate tensile strength. The fracture process is usually progressive, bytaking place over a number of load cycles and is normally referred to as CyclicFatigue.

p. Second Moment of Area (Moment of Inertia I)

The second moment of area, with respect to an axis in the plane of that area, is thesum of the products obtained by multiplying each element of the area by the squareof its distance from the axis. For an annular ring with outer diameter d0 and innerdiameter di

)dd(64

I 4i

4o �

�

�

q. Coefficient of Thermal Expansion (�)

The coefficient of thermal expansion defines the (linear) relationship between atemperature change and the resulting thermal strain in a homogeneous bodysubjected uniformly to that temperature change, ie

= � = ��T

A value of 6.9 x 10-6/�F is usually taken for tubular steel.

r. Volume Thermal Expansion (CT)

Volume thermal expansivity of a fluid is the expansion per unit of original volumecaused by a unit increase in temperature.

s. Volume Compressibility (Cp)

Volume compressibility of a fluid is the compression per unit of original volumecaused by a unit increase in pressure.

t. Hardness

Hardness is the resistance of a material to penetrate its surface. Hardness isexpressed by comparing the tested material to some arbitrary hardness scale, suchas the Rockwell ‘C’, Brinell, or Vickers Scales. These scales are used to specify themechanical requirements for steel when ordering casing. For example, an L-80material may require a Rockwell ‘C’ number of 23 to reduce the risk of sulphidestress cracking for a well design.


u. Toughness

The ability of a material to absorb energy and deform plastically before fracturing.One method of measuring this is the Charpy Impact Resistance test.

This provides an indication of the fracture toughness of the material by carrying outan impact test in which a notched bar sample, fixed at both ends, is struck by afalling pendulum.

The energy absorbed as determined by the subsequent rise of the pendulum, is ameasure of the impact strength or notch toughness.

2.2.2 Steel and Steel Alloys

2.2.2.1 Steel Phases

Steel exits in a number of phases based on the heat treatment and chemicalcomposition of the material.

The primary phases are:

a. Austenite

A high temperature non-magnetic phase of iron which normally exists as a face-centred cubic crystallographic structure. In steels, the solute is generally carbon.Austenite is not generally stable at room temperature, in plain carbon steels,it is not stable below 723�C (1333�F). However, it can be stabilised by alloying,eg austenitic stainless steel, in which nickel is the stabilising alloying element.

b. Ferrite

Iron or solid solution alloy of iron, which has a body, centred cubic crystallographicstructure. In steels, the solute is generally carbon. Carbon has a very low solubilityin ferrite, being only some 0.02% weight.

c. Cementite

A compound of iron and carbon, eg Fe3C. When a steel is cooled from hightemperatures the solubility of carbon decreases. The carbon that is thus pushed outof solution reacts with iron to form iron carbide. Carbon steels often contain aproportion of iron carbide as a result of the very low solubility of carbon in ferrite.

d. Pearlite

A metastable lamellar aggregate of ferrite and cementite produced by slow coolingaustenite in carbon, low alloy steels. Pearlite will only begin to be formed when theaustenite contains a certain carbon content, c. 0.87% wt for a Fe-C alloy. Therefore,most plain carbon steels when cooled slowly contain a mixture of ferrite andpearlite.


e. Martensite

If steels are cooled rapidly by quenching, there is insufficient time for the carbon tobe pushed out of solution to produce large carbide particles/platelets. Therefore, ametastable transitional constituent is produced known as ‘martensite’. Thistransformation product is very hard/strong but very brittle. In most cases, it isnecessary to re-introduce some ductility by tempering. Tempered martensite canwithstand fatigue.

2.2.2.1.1 Heat Treatment

After initial pipe manufacture but before threading, the next phase of the manufacturingprocess is to heat treat the pipe to reach the required mechanical properties.

a. Austenising

The steel is heated above its critical temperature in the range of 1340 to 1675�F,subject to the content of the carbon. This treatment allows time for the structure totransform from its normal room temperature ferritic structure to austenite.

b. Normalising

An annealing heat treatment followed by still air-cooling to produce a pearlite-ferriticstructure. The purpose is to refine the grain size, homogenise the structure andremove strains induced by mechanical working.

c. Quenching

A process of rapidly cooling a metal from an elevated temperature by contact withthe liquids, solids or gases to form a hard martensitic structure. Typically, liquidsare used, either aqueous or oil based. Carbon and low alloy steels are quenched toform martensite.

d. Tempering

A heat treatment to which steels, especially low alloy steels, are subjected in orderto produce changes in the mechanical properties and structure. This processgenerally follows quenching, which produces a steel that is often too hard andbrittle to be of practical use. In tempering, the steel is heated to a suitabletemperature at which structural changes will occur, which relieve internal stresses,reduce hardness (strength) and increase toughness. This is followed by cooling at asuitable rate. When martensite is tempered, it gradually decomposes, with ironcarbide ejected from the solid solution. The result of full tempering is a structureconsisting of ferrite in which the iron carbide is dispersed as fine particles.

e. Stress Relief Heat Treatment

A heat treatment designed to reduce internal stresses in metals that have beeninduced by casting, quenching, welding, and cold working. The metal is soaked at asuitable temperature for sufficient time to allow readjustments in stresses, thenslowly cooled. Stress relieving does not normally involve any structural changeswithin the steel.


f. Cold Working

This is the plastic deformation of a metal at a temperature low enough to causepermanent strain hardening. The hardness and tensile strength are progressivelyincreased with the amount of cold work, but the ductility and impact strength(toughness) are reduced. Cold working is the technique often used to improve thestrength in corrosion resistant alloys (CRA), eg Duplex stainless steel and as arepair process for bent tubes during manufacture. It should not be used formaterials expecting hydrogen sulphide.

2.2.2.1.2 Alloy Steels

Adding elements (alloying) to the steel during its liquid molten stage is often used tomodify and improve the properties of the pipe. Alloying the steel is used in conjunctionwith heat treatment to set the final steel properties. For example, adding nickel canincrease the hardness/strength by modifying the ferrite/pearlite zone of the carbonsteel. This makes the quenching and tempering.

Treatments more effective by converting to the martensite at a specific cooling rate.This is important when heat-treating thick walled components.

It is also important to understand the differences of alloy steels relative to carbon steelsand to ensure casing design accessories and equipment are compatible with thecasing pipe in terms of mechanical requirements, when ordering material for the welldesign. This may be influenced by the anticipated constituents of the well such ascarbon dioxide and hydrogen sulphide.

a. Austenitic Stainless Steel

A stainless steel in which the austenite is the stable phase at room temperature.These normally contain chromium in the range 16 to 26% and nickel in the range6 to 20%. These alloys can contain some ferrite (c. up to 5%) which can adverselyaffect their corrosion resistance and weldability. These steels cannot be hardenedby quenching but can only be strengthened by cold work.

b. Duplex Stainless Steels

These are stainless steels in which there is a two-phase structure of ferrite andaustenite. These are normally present in balanced or near balanced quantities.Typically these steels contain 22 to 25% chromium and 5 to 7% nickel.

c. Ferritic Stainless Steel

These are low carbon steels that contain between 16 and 30% chromium and arerarely used as downhole tubulars.

d. Martensitic Stainless Steels

A group of hardenable stainless steels containing from 11 to 14% chromium and0.15 to 0.45% carbon. These steels harden readily on air cooling from about1750�F. It is usually to re-introduce some ductility by tempering.


e. Monel

A non-magnetic alloy containing nickel and copper. Historically, this was used fornon-magnetic drill collars (NMDC). Hence NMDCs are also known as ‘monel’collars. However, this material has been superseded for NMDCs by highly alloyedaustenitic stainless steels, beryllium-copper alloys etc.

f. Precipitation-hardening Stainless Steels

Some materials will harden on cooling by the subsequent precipitation of aconstituent from a supersaturated solid solution. This produces materials that canbe hardened by heat treatment.

One such group of materials is the precipitation-hardening stainless steels,eg 17-4PH which contain 17% chromium and 4% nickel.

g. Stainless Steel

A corrosion resistant alloy steel, which contains a minimum of 12% chromium.Chromium is the major element in a steel that provides an ability to resist corrosion.This effect is attributed to the formation of a thin protective oxide on the metalsurface. Corrosion resistance can be increased by the addition of other alloyingelements, eg nickel, molybdenum and copper. The main types of stainless steel areaustenitic, ferritic, martensitic, duplex and precipitation hardening.

2.2.3 Codes and Standards

Codes and standards utilised for casing tubulars are wide ranging and include manyorganisations on an international basis. A Drilling Engineer needs to be aware that thegeneration of a well design and specification of the tubulars may require the use andstudy of a variety of codes, standards and guidelines. He should also ensure that themost up-to-date documentation is available, as all codes, standards and guidesundergo periodic review and updates.

They include, but are not limited to the following:

� American Petroleum Institute (API)

� National Association of Corrosion Engineers (NACE)

� Institute of Petroleum (IP)

� American Society of Mechanical Engineers (ASME)

� American Society for Testing and Materials (ASTM)

� American National Standards Institute (ANSI)

� International Standard Organisation (ISO)

� Committee for European Normalisation (CEN)


2.2.3.1 API Codes – General Application

The most universally used standards relating to the specification of oilfield tubulargoods has been and still is API.

API Committee 5 – Tubular Goods Specifications and Publications

The API appointed a committee, named Committee 5, on Standardisation of TubularGoods which publishes, and continually updates, a series of Specifications, Standards,Bulletins and Recommended Practices covering the manufacture, performance andhandling of tubular goods. They also license manufacturers to use the A-PI Monogramon material that meets their published specifications, so that field personnel canidentify materials that comply with the standards. Their pronouncements are almostuniversally accepted as the basis for discussions on the properties of tubulars.However, this does not mean that everyone accepts the published performance dataas the best theoretical representation of the parameters. The forum consists both ofusers and manufacturers.

API documents covering casing are grouped into three categories.

2.2.3.1.1 Specifications

These documents govern the manufacture, material properties and dimensions of OilCountry Tubular Goods (OCTG), threads and equipment. They are generallyconsidered binding between buyer and seller if referred to in purchase orders. Theywould assist in specifying a well design.

2.2.3.1.2 Recommended Practices (RPs)

These publications provide recommended (but not necessarily binding) actions whichshould be followed when performing such activities as inspection. RPs are oftenutilised in the industry but are not generally considered binding upon the seller unlessthey were included as part of the purchase order.

2.2.3.1.3 Bulletins

These documents are published primarily for information purposes, though they maybecome part of a commercial contract if they relevant.

2.2.3.1.4 API Committee 5 Documents

The documents published by API relevant to casing design are:

1. API SPEC 5CT, ‘Specification for Casing and Tubing’.

Covers seamless and welded casing and tubing, couplings, pup joints andconnectors in all grades. Processes of manufacture, chemical and mechanicalproperty requirements, methods of test and dimensions are included.


2. API STD 5B, ‘Specification for Threading, Gauging, and Thread Inspection forCasing, Tubing, and Line Pipe Threads’.

Covers dimensional requirements on threads and thread gauges, stipulations ongauging practice, gauge specifications and certifications, as well as instrumentsand methods for the inspection of threads of round-thread casing and tubing,buttress thread easing, and extreme-line casing, and drillpipe.

3. API RP 5A5, ‘Recommended Practice for Field Inspection of New Casing, Tubing,and Plain-End Drill Pipe’.

Provides a uniform method of inspecting tubular goods.

4. API RP 5B1, ‘Recommended Practice for Thread Inspection on Casing, Tubing andLine Pipe’.

The purpose of this recommended practice is to provide guidance and instructionson the correct use of thread inspection techniques and equipment.

5. API RP 5C1, ‘Recommended Practice for Care and Use of Casing and Tubing’.

Covers use, transportation, storage, handling, and reconditioning of casing andtubing.

6. API RP 5C5, ‘Recommended Practice for Evaluation Procedures for Casing andTubing Connections’.

Describes tests to be performed to determine the galling tendency, sealingperformance and structural integrity of tubular connections.

7. API BULL 5C2, ‘Bulletin on Performance Properties of Casing and Tubing’.

Covers collapsing pressures, internal yield pressures, and joint strengths of casingand tubing and minimum yield load for drill pipe.

8. API BULL 5C3, ‘Bulletin on Formulae and Calculations for Casing, Tubing, DrillPipe and Line Pipe Properties’.

Provides formulae used in the calculations of various pipe properties, alsobackground information regarding their development and use.

All of the above documents should be checked to ensure their validity and that theyare the most up-to-date editions available.

2.2.3.2 National Association of Corrosion Engineers(NACE Standard MR0175-99)

This standard covers the materials requirements for all oilfield equipment, includingdownhole tubulars and production equipment. The NACE Standard MR0175-99 isentitled ‘Standard Material Requirements – Sulphide Stress Cracking Resistant MetallicMaterials for Oilfield Equipment’.


The NACE standard is only concerned with the resistance of materials to sulphidestress cracking in sour conditions. However, there are other failure mechanisms thatmay occur in the presence of hydrogen sulphide and need to be taken intoconsideration, when selecting materials for sour service.

The first step in applying the NACE methodology is to determine whether ‘sourconditions’ as defined by NACE MR0175-99 exist. The standard defines sourenvironments as fluids containing water as a liquid together with hydrogen sulphide ata level exceeding certain criteria.

The Drilling Engineer will need to use the NACE standard to determine the partialpressure of hydrogen sulphide in the gas phase (if present) and thus assess materialrequirements.

2.2.3.3 Institute of Petroleum

There are two documents the Drilling Engineer should be aware of for well design.

The first is a Model Code of Safe Practice Part 17 Well Control during the Drilling andTesting of High Pressure Offshore Wells, a set of guidelines on issues to consider forhigh pressure, high temperature (HPHT) wells.

The second is a set of ‘Guidelines for Routine and Non-routine Subsea Operationsfrom Floating Vessels’ and should be used to consider issues associated withconductor and surface casing design as part of the wellhead system.

2.2.3.4 ASME/ASTM/ANSI

These standards are utilised as part of the various API standards. For example,mechanical tensile testing on longitudinal testing, using ASTM A370 underAPI Spec 5CT.

2.2.3.5 International Standard Organisation (ISO)

ISO describes itself as ‘the specialised international agency for standardisation’. Itsmembers are the national standards organisations of 91 countries. ISO publishesinternational standards emanating from several technical committees andsub-committees. A technical board comprising one representative from each nationalbody governs ISO. The Central Secretariat co-ordinates ISO operations, administersvoting and approval procedures, maintains and interprets the directives that set out theprocedures and rules, and publishes the international standards. ISO is responsible forall fields of international standardisation except electrical and electronic.

ISO Technical Committee 67 (ISOITC 67) – Oil Industry Matters

ISO/TC 67 was reactivated in 1988, because the international upstream industry wasincreasingly recognising the need for good international standards that could beaccepted and applied worldwide.


As part of the reactivation, the scope of ISO/TC 67 was extended to the standardisationof the materials, equipment and offshore structures used in drilling, production, refiningand the transport by pipelines of petroleum and natural gas. The work programmedeveloped was primarily in the fields of drilling and production but also includesmachinery and equipment used in refining and petrochemicals.

2.2.3.6 Committee for European Normalisation (CEN)

CEN is the European counterpart of ISO. It consists of the members of the nationalstandards organisations of the EC countries.

It aims to achieve the goal of the EC, ie to improve the international competitiveposition of European industry.

One of the methods to achieve this is the removal of technical trade barriers by:

� Harmonising Standards (with emphasis on health, safety and environment) intoEuropean Norms (ENs)

� Introducing Directives (which will become law at national level, referring torelevant ENs)

� Harmonising Certification

� Testing and Certification in Europe

2.2.3.7 Co-operation between ISO, CEN and API

As all CEN members are also ISO members, a close co-operation exists. Theco-operation between ISO and CEN has been formulated as follows:

‘It is declared policy of the community that whenever possible CEN/CENELEC shallimplement international standards in a uniform way but where international standardshave not yet been developed or where existing standards need to be adapted toEuropean situations, CEN and CENELEC will develop ENs in anticipation ofinternational ones.’

As part of the Harmonisation Legislation for Europe 1992 the EEC commissionrequested the CEN to introduce ENs. As the upstream oil and gas industry isdominated by API standards, the CEN requested the ISO to investigate the feasibility ofconverting API standards into ISO standards and subsequently into ENs.

It was decided to divide the API standards into three classes:

� Class 1: API standards to be circulated by the ISO central secretariat under the‘fast-track’ procedure, meaning 1 to 2 years

� Class 2: API standards to be further discussed to modify them prior to submittal tothe ISO

� Class 3: API standards requiring significant study prior to moving forward asinternational standards


In 1988 API offered more than 70 of its standards to ISO, to he the basis ofinternational standards. In 1989 an ISO Advisory Group classed several of these assuitable for adoption without technical modification and ISOICS agreed to ‘fast-track’these to become international standards. ‘Fast-track’ means that the API document isgiven an ISO Number, front cover and foreword but is otherwise presented as-is. So farAPI Bull. 5C3, API RP5C1 and API Std 5B have been ‘fast-tracked’.

The ISO foreword addresses issues such as equivalent references to Americannational references, certification and the API Monogram.

The industry is now well established regarding the process of ‘transferring’ APIstandards. It is no longer seen as appropriate that all the A-PI standards offered shouldbecome ISO standards. Some may be better left with API because the helpful anddiscursive style of many (RPs and bulletins in particular) is lost when re-formatted tocomply with ISO directives.

An example of the API/ISO convergence process is API 5C3 Bulletin on Formulae andCalculations for Casing, Tubing Drill Pipe and Line Pipe Properties. This contains therequirements of ISO 10400 Petroleum and Natural Gas Industries – Formulae andCalculations for Casing, Tubing, Drill Pipe and Line Pipe Properties.

2.2.4 Non-API Casing Grades/Special Materials

API 5CT acts as a datum for a number of casing grades utilised in well design.However, over a number of years there has been a shift away from simple shallowwells to complicated, deeper, corrosive and HPHT wells. As a result, well requirementscall for manufacturers to provide higher specifications materials for well designs. Thishas led to the development of non-API casing grades, or ‘proprietary grades’ from thepipe manufacturers.

Proprietary grade casing/specialist materials may be required to address the followingsubjects:

2.2.4.1 Sour Service

Material Selection for Sour Service

Tubulars gain their resistance to sour service from a combination of alloy design andheat treatment. Materials with strengths less than API 5CT L80 are inherently resistantto the principal failure mechanisms sulphide stress corrosion cracking (SSCC).

Tubes with the strength of L80 or higher need to be quenched and tempered to give atempered martensite microstructure. L80 is a simple carbon-manganese steel,although minor additions of other alloying elements are normal (for example boron,chromium or molybdenum). Higher strengths need another steel type with morealloying elements to increase the hardenability and the temper resistance. API 5CTC90, T95 and a proprietary grade ST-95, are made from carbon-manganese-chromium-molybdenurn steels. The chromium content is usually about 1.2% and themolybdenum content 0.20% to 0.75%. There may also be a boron addition.


In order to reduce tubular weights and dimensions, higher strength grades have beendeveloped. These rely on modified types of steel but they are still quenched andtempered. A proprietary grade with a minimum yield strength of 110ksi can be suppliedwith guaranteed resistance to sour service: ST-110. Steel grades available are:

� API 5CT L80

� API 5CT C90

� API 5CT T95

� ST-95

� ST-110

2.2.4.2 Carbon Dioxide Service

Material selection for carbon dioxide service may be required where carbonic acid maybe present resulting in accelerated corrosion.

Carbon dioxide corrosion occurs in the presence of water by general and pittingcorrosion. Carbon-manganese steels can corrode very rapidly and perforate in only afew days by pitting. The martensitic stainless steels containing 9% and 13% Cr arevery resistant to this type of corrosion over a wide range of conditions.

The new generation of martensitic stainless steels, the ‘Super’ 13% Cr steels, maintaintheir corrosion resistance to higher temperatures in more adverse conditions. They aresupplied in higher strengths than standard 80,000psi strength API 13% Cr and can alsobe considered for conditions where API 13% Cr would be suitable, but where theengineering design demands a higher strength tubing. TISL proprietary grades typicallyavailable are:

� Super 13% Cr-95 (95,000psi strength)

� Super 13% Cr-110 (110,000psi strength)

High temperature can limit the use of the martensitic grades. In higher temperaturewells more highly alloyed stainless steels, such as the duplex stainless steels, must beused. These steels contain 22% or 25% chromium together with nickel, molybdenumand nitrogen. Both these grades can be used in the softened condition with minimumspecified yield strengths of 60ksi to 80ksi. Alternatively they can be strengthened bycold working up to relatively high strengths eg 140ksi minimum yield strength. In thesoftened condition these alloys are more corrosion resistant than in the coldworked condition.


The normal limit of application of the duplex stainless steels is about 200�C. Above thistemperature and up to 300�C super-austenitic alloys are used. These are nickel-chromium alloys having significant additions of molybdenum as well as other lesseralloying additions and are invariably used in the cold worked condition for OCTG.Typical examples of these alloys are:

� 28% Cr

� 32% Ni

� 3.5% Mo

� 25% Cr

� 35% Ni

� 3% Mo

Examples of steel and alloy grades available:

� API 5CT L8O 9 Cr

� API 5CT L8O 13 Cr

� S 13Cr-95 or S 13Cr-110

� 22% Cr Duplex Stainless Steel, 65 grade




� Nickel-chromium, Super-austenitic Alloys

2.2.4.3 Carbon Dioxide/Mixed Corrosive Environments

Steels and alloys used for OCTG resistance to carbon dioxide and mixed corrosiveenvironments including small concentrations of hydrogen sulphide may consist of thefollowing material types.

Part 1: Martensitic Stainless Steels

Standard martensitic stainless steels contain either chromium or chromium andmolybdenum as the principal alloying elements. Both types are used for grade L80 toprovide resistance to carbon dioxide corrosion. The most commonly used gradecontains 13% Cr and is an air-hardening steel usually supplied in the air-quenched andtempered condition. The other variety contains 9% Cr and 1% Mo and is heat-treatedby water quenching and tempering.


‘Super’ martensitic stainless steels have enhanced corrosion resistance imparted byextra alloying elements in the form of molybdenum and nickel. They have improvedcorrosion resistance at higher temperatures and higher chloride concentrations thanstandard martensitic steels. They can offer a cost elective alternative to duplexstainless steels or can be used in higher strength grades than API 5CT L8O 13 Cr.

Table 2.4 - Steels and Alloys used for OCTG

The steel and alloy compositions given here are indicative and do not constitutespecifications. Only the principal alloying elements are quoted.

STEEL TYPE CARBON MANGANESE CHROMIUM MOLYBDENUM NICKEL

Martensitic SS9% Cr

0.08 to0.15

0.30 to 0.60 8.0 to 10.0 0.90 to 1.10 –

Martensitic SS13% Cr*

0.15 to0.22

0.20 to 1.00 12.0 to 14.0 – 0.50 max

SuperMartensiticSS*

<0.05 to0.10

0.20 to 1.00 11.5 to 14.0 0.50 to 3.00 3.00 to5.00

* Controlled nitrogen contents are usual.

Part 2: Duplex Stainless Steels and Super-austenitic Alloys

Duplex stainless steels are used in either the solution annealed or the annealed andcold-worked condition. These steels are not hardenable by heat-treatment, but requirethe application of cold work to strengthen them. Common varieties are:

� 22% Cr

� 5% Ni

� 3% MO

� 25% Cr

� 6% Ni

� 3% Mo

These steels are used for resistance to carbon dioxide in higher concentrations or athigher temperatures. They will tolerate small concentrations of hydrogen sulphide; thesolution annealed condition being more resistant to sour conditions.

Super-austenitic alloys are nickel-chromium alloys and are used in the solutionannealed and cold-worked conditions. The alloys are very resistant to carbon dioxideand hydrogen sulphide at high temperatures and pressures. They can be supplied inhigh strength grades up to 140ksi specified minimum yield strength.


Table 2.5 - Steels and Alloys used for OCTG

The steel and alloy compositions given here are indicative and do not constitutespecifications. Only the principal alloying elements are quoted.

STEEL TYPE CARBON MANGANESE CHROMIUM MOLYBDENUM NICKEL

DuplexStainless,22% Cr*

0.03%max

2.00% max 21.0 to 23.0 2.50 to 3.50 4.50 to6.50

DuplexStainless,25% Cr*

0.03%max

2.00% max 24.0 to 26.0 2.50 to 4.00 4.50 to7.50

Super-austenitic,28% Cr*

0.03%max

2.00% max 26.0 to 29.0 3.00 to 4.50 29.0 to32.0

* Controlled Nitrogen contents are usual.

2.2.4.4 High Strength

Material selection for high strength casing has an influence for example on HPHTapplications.

Where higher strength casing is required, manufacturers provide proprietary grades aswell as API 5CT Q125. Proprietary grade QR-125 has a restricted yield strength range,which makes this high strength casing compatible with NACE requirements andsuitable for sour service at temperatures above 80�C.

For higher strengths a manufacturer grade XT-155 has a high minimum yield strength(155ksi) combined with good low temperature toughness.

2.2.4.5 High Collapse

High collapse service materials may be required in environments where movement offormations, such as salt sequences are anticipated.

Carbon manganese steels in the quenched and tempered condition are commonlyused to produce API Specification 5CT grades C95 and HC110. The collapseperformance of these grades has been established by statistical treatment of collapsedata from a wide range of sources and defines the minimum performance that can beexpected from any pipe meeting API minimum properties. Manufacturers produce highcollapse grades with 95 and 110ksi minimum yield strength ranges that are guaranteedto have higher collapse properties than API standard products, typically 15% to 30%higher. Careful management of the important factors affecting collapse ratingsachieves this improved performance. Pipe ovality and thickness are controlled to limitsspecified in internal specifications drawn up after a comprehensive researchprogramme; residual stresses are kept to a minimum by hot straightening.


The potential for collapse improvement depends on the pipe D/t ratio and for somesizes the increase is not significant. Table 2.6 below from TISL provides arepresentative sample of HC95 and HC110 collapse performance properties forvarious sizes.

Table 2.6 - TISL Comparison for High Collapse Versus API Casing Grades

DIAMETER(in)

WEIGHT(lb/ft)

API C95COLLAPSE

RATING(psi)

HC95COLLAPSE

RATING(psi)

API P110COLLAPSE

RATING(psi)

HC110COLLAPSE

RATING(psi)

7 29 7,840 10,480 8,530 10,800

9-5/8 47 5,090 7,420 5,300 7,490

9-5/8 53.5 7,340 10,050 7,950 10,240

13-3/8 68 2,340 3,160 2,330 3,160

13-3/8 72 2,830 3,900 2,880 3,900

2.2.5 Temperature Effects on Metallic Properties

2.2.5.1 High Temperature

For low alloy steels up to and including Q125, a recommended yield strengthtemperature de-rating factor of 0.03% per �F with de-rating starting at 68�F. This isgenerally recognised as a guide for de-rating the yield strength of a material andcorresponds to a 9.72% reduction in yield strength at 200�C (392�F).

For CRA, particularly duplex stainless steel, temperature effects can be considerablygreater and should be taken into consideration.

Temperature has an influence improving the resistance of certain materials to sulphidestress cracking (SSC) by allowing the absorbed hydrogen to diffuse out of the materialand form molecular hydrogen at a higher rate. Higher temperature generally causescorrosion rates to increase and result in an increase risk to SCC.

2.2.5.2 Arctic (Low) Temperatures

Low temperature environments have the effect of changing the metallurgy of a materialin a number of ways. Lower temperatures change the internal molecular structure sothat it does not allow the internal stresses to release, resulting in a harder more brittlematerial. Impact resistance is therefore reduced and failure can occur from shock load,localised flaws or even scratches.

Pipe manufacturers produce casing materials that are all quenched and tempered andfeature high tensile strength as well as good ductility at low temperature.


2.2.6 Effects of Gases on Materials

2.2.6.1 Hydrogen Sulphide

Hydrogen sulphide can produce many forms of corrosion:

� General attack

� Pitting

� Hydrogen embrittlement (HE)

� Hydrogen induced cracking (HIC)

� Sulphide stress cracking (SSC)

The last three relate to the diffusion of hydrogen into the metal lattice.

2.2.6.2 Hydrogen Embrittlement

Hydrogen atoms generated by galvanic action at a metal surface can absorb into thestructure of the metal where they increase the strain in the lattice. This reduces theductility and the metal can fail in a brittle manner, failure often originating at stressconcentrations. For high strength steels, high alloy materials are generally moreresistant to SSC than similar strength carbon-manganese steels but can be susceptibleto hydrogen embrittlement when, for example, hydrogen charging results from galvaniccorrosion.

2.2.6.3 Hydrogen Induced Cracking

Hydrogen atoms absorbed into a metal lattice can collect in areas of inclusions forminggas molecules. Over time the gas pressure can rise until it is great enough to cause thegrains to part and cracks to initiate (generally parallel to the metal wall). Crackpropagation along and particularly through the wall (step wise cracking) which can thenlead to failure.

2.2.6.4 Sulphide Stress Cracking

Stress corrosion cracking requires a high level of applied or residual stress in acorrosive environment. High strength carbon-manganese steels are particularlyvulnerable to this type of attack in an H2S environment. Hydrogen diffusion embrittlesthe material in the area of stress concentrations at crack tips, which then propagate inthe corrosive environment. SSC is less likely to occur at temperatures permanentlyabove about 150�F (65�C).


2.2.6.5 Carbon Dioxide

When CO2 dissolves in water it leads to the attack of carbon steel through a series ofcomplex reactions. Temperature of exposure and the partial pressure of CO2 play animportant part in determining the degree of corrosion. The presence of acid gases inwater such as CO2 all increase corrosion rates and the risk of cracking by lowering thepH. The degree of CO2 corrosion can be estimated through the use of variousproprietary software programmes.

2.2.7 Effects of Liquids on Materials

2.2.7.1 Chlorides/Bromides

The major adverse effects of increased levels of chlorides or bromides in the fluids incontact with the casing are to increase the likelihood of pitting and chloride-inducedstress corrosion cracking. These mechanisms are made worse through an increase intemperature. This is particularly important for CRAs, where it is often necessary torestrict the temperature and/or chloride/bromide levels, under which the alloys canbe used.

2.2.8 Corrosion

In terms of well design, corrosion can have a significant impact on the short andlong-term well integrity by reducing the ability of the casing to withstand design loadsthrough loss of wall thickness and its capacity to withstand those design loads, byattacking the metallurgy and by reducing the mechanical strength of the casing.

For casing design there are three general areas that require consideration:

� Internal casing corrosion due to the reservoir constituents of the well

� External corrosion due to formation fluids, reservoir fluids, acquifers and seawaterat the wellhead surface

� Internal and external casing corrosion as a result of the drilling/completion fluids

2.2.8.1 Corrosive Parameters

Factors that can have an influence on material selection for a well design, for corrosiontypically include:

� Life of well: exploration or development

� Reservoir constituents: oil, gas, condensate etc

� Partial pressure due to CO2 and/or H2S

� Anticipated pressures: static and flowing


� Anticipated temperatures: high or low

� Anticipated flowrates of reservoir and regimes

� Risk of sand production

� Liquid chemistry: scaling, chloride/bromide levels, pH, bicarbonate levels, organicacids etc

� Potential for water cut ingress during production

� Potential change of wellbore use during life of well, eg from producer to injector

2.2.8.2 Common Corrosion Types

Examples of common corrosion mechanisms are summarised below.

a. General Corrosion

A reaction between a metal and corrosive fluid. This results in a metal loss acrossthe surface of the material. Leads to a reduction in load carrying capacity to containpressure, tension and collapse.

b. Galvanic Corrosion

The preferential corrosion that can occur to one of the materials, when twodissimilar metals are electrically coupled in a corrosive environment in anelectrolyte which contains a corrosive agent. The potential differences create acathode-anode pair, with one of the metals acting as an anode, corroding at anenhanced rate. The other material acts as a cathode providing some protection.

c. Pitting Corrosion

Uneven corrosion in a material where small perforations occur due to localisedattack by the electrolyte, resulting in high localised stress concentrations. Thisreduces the load carrying capacity of the material. The pitting process is stronglyaffected by temperature.

d. Crevice Corrosion

This is localised damage that can occur at a gap (crevice) between two adjacentcomponents. This may be similar materials, or dissimilar materials in which galvaniccorrosion has an influence. Crevice corrosion is influenced by the size of the gapand can accelerate due to high temperatures.


e. Erosion Corrosion

Caused by high velocity downhole fluids removing the protective oxide, sulphide, orcarbonate layer from the material. This results in the exposed layer reacting tocreate a new protective layer. The mechanism repeats itself to create moreerosion/corrosion.

f. Intergranular Corrosion

Can occur due to the heat treatment during the manufacturing process, wheremetallurgical changes result in a lower corrosion resistance at the material grainboundaries compared to the main material matrix. Intergranular attack then takesplace from local galvanic reactions, due to contact with a corrosive environment.



SECTION 3 DESIGN CONCEPTS Page 1 of 28

TABLE OF CONTENTS

3. DESIGN CONCEPTS............................................................................................. 3

3.1 OBJECTIVES OF CASING DESIGN................................................................ 3

3.1.1 Technical .................................................................................................... 3

3.1.2 Commercial ................................................................................................ 3

3.1.3 Safety ......................................................................................................... 4

3.2 DEFINITIONS................................................................................................... 4

3.2.1 Well Types ................................................................................................. 4

3.2.1.1 Exploration................................................................................................. 4

3.2.1.2 Appraisal.................................................................................................... 4

3.2.1.3 Development.............................................................................................. 5

3.2.2 Tubular Definitions...................................................................................... 5

3.2.2.1 Conductor .................................................................................................. 5

3.2.2.2 Surface Casing .......................................................................................... 5

3.2.2.3 Intermediate Casing................................................................................... 6

3.2.2.4 Production Casing...................................................................................... 6

3.2.2.5 Liners......................................................................................................... 6

3.2.2.6 Tiebacks .................................................................................................... 6

3.2.3 Mechanical Properties of Engineering Materials ......................................... 7

3.2.3.1 Concepts and Definitions. .......................................................................... 8

3.2.4 Analysis Methods ..................................................................................... 10

3.2.4.1 Analysis Types......................................................................................... 10

3.2.4.2 Primary Analysis Equations ..................................................................... 11

3.2.4.3 Von Mises Yield Criterion......................................................................... 13

3.2.4.4 Hooke ...................................................................................................... 19

3.2.4.5 Incorporation of Service Factors .............................................................. 21

DESIGN CONCEPTS Page 2 of 28

3.2.5 Leak Off Tests and Interpretation ............................................................. 26

3.2.5.1 Introduction.............................................................................................. 26

3.2.5.2 Formation Integrity Test (FIT) .................................................................. 28

3.2.5.3 Leak Off Test Pressure (LOP).................................................................. 28

3.2.5.4 Formation Breakdown Pressure (FBP)..................................................... 28

3.2.5.5 Fracture Propagation Pressure (FPP) ...................................................... 28

3.2.5.6 Instantaneous Shut-in Pressure (ISIP)..................................................... 28

3.2.5.7 Fracture Closure Pressure (FCP)............................................................. 28


3. DESIGN CONCEPTS

3.1 OBJECTIVES OF CASING DESIGN

3.1.1 Technical

When drilling and completing a well, it is generally not possible to drill through all of theformations from surface to target or total depth (TD) in one single pass. The well isdrilled in sections, with each section reducing in size, as it is drilled deeper. The wallsof each section are lined with pipe, called casing, and sealed with cement prior todrilling the next section.

The purpose of the casing is to:

� Prevent and contain unstable formations collapsing into the wellbore

� Protect and contain weak formations from higher mud weights required forsubsequent sections, as the mud weights may fracture weaker zones

� Isolate zones with abnormally high pore pressures from deeper formations that maybe normally pressured

� Seal off lost circulation zones

� Confine the produced fluids from the wellbore in terms of pressure, volume andtemperature

� Act as a means of controlling well fluid influxes

� Provide a conduit for wellbore tools and completion equipment and allow access forproduction/injection of fluids to and from the well

� Provide structural support for the wellhead and casing strings

� Act as a structural support for the blowout preventers and production xmas tree/welltest equipment

Each casing string design must accurately define and evaluate the anticipated loadsthat may occur during the life cycle of the well; during construction, production and finalabandonment.

3.1.2 Commercial

The cost of the casing strings required can amount to a significant part of the total wellcost, in the order of 10 to 30%. Therefore, the number of strings required should beminimised in order to obtain a design that is ‘fit for purpose’ for all of the anticipatedloads during the life of the well.

Commercial considerations on the choice of tubulars will be driven by many factors,including the risks and complexity of the well design. Logistics, access and bulk buyingcontracts will also influence the choice of tubulars available to the well designer.


All of these factors must be taken into consideration to optimise the number of casingstrings required for a well, as this in turn leads to efficiencies in the drilling process.

3.1.3 Safety

Casing design is a balance of risk relative to the consequence of an incident. Safety isimplicit for casing designers, as it is an integral part of the well design process tocontain pressure and volume, during the life of the well. A casing design can beregarded as a vertical pressure vessel in the same way as a chemical plant.

For example, a development well can result in a design with a high degree ofconfidence, as risks are better understood to reduce cost. In an exploration wellhowever, the risk may be assessed as higher due to minimal offset data and willrequire a higher safety margin when assessing the anticipated loads. A well drilled inan area with higher pressures or temperatures, will usually require more casing strings,than one drilled in a normally pressured environment.

Local government legislation and differing drilling practices in operating regions aroundthe world could also require specific criteria as part of well design. This may limit theoptions of the well designer to prepare alternative designs.

3.2 DEFINITIONS

3.2.1 Well Types

There are three distinct well types with different design requirements for casing design.The decision on well definition is based upon how well the anticipated loads can bedetermined.

3.2.1.1 Exploration

These are classified as wells with minimal offset data, including geological, pore andfracture pressure data. The anticipated loads cannot be accurately defined and so mayhave a higher error bar.

3.2.1.2 Appraisal

These are classified as wells where there is some offset data within the area, includinggeological, pore and fracture pressure data. They may not have sufficient data to befully considered for development well load cases and would therefore fall underexploration wells. The Drilling Engineer will need to assess the quantity and quality ofthe data sources for appraisal wells, to determine if they should be considered as anexploration, or development well.


3.2.1.3 Development

These are classified as wells with good clearly defined, offset data, includinggeological, pore and fracture data. The anticipated loads can be fully defined, as thereis a good history of production and drilling data to assist the well designer.

There may be circumstances, where a well drilled into an unexplored area of a field willneed to be defined under an ‘exploration load’, due to the uncertainty of the offset data.

This should be considered on a well-by-well basis.

Additionally, there may be justification in defining the upper portion of a well under a‘development load’ definition, if the upper formations are consistent with the offset datafor the field.

The lower sections would be treated as ‘exploration well’ status for design purposes.

3.2.2 Tubular Definitions

3.2.2.1 Conductor

The conductor is the first string to be run and has the largest diameter. It providesstructural support for the wellhead, subsequent casing strings, blowout preventer(BOP) and xmas tree and may be drilled and cemented, jetted, or driven to coverunconsolidated formations at shallow depths. Surface formations may have lowfracture strengths which could be exceeded by the hydrostatic pressure of the drillingfluid and equivalent circulating density of the fluid/cuttings. For offshore drilling from asemi-submersible where the BOP is on the seafloor, it serves as a circulation systemfor the drilling fluid and to guide the drilling and casing strings into the hole.

Where formation conditions are favourable, the conductor may be driven, or drilledand driven into the formation (eg land, offshore platform or jack-up) and is known as astove pipe.

Subject to the well design, gas diversion for well control may be fitted to divert potentialshallow gas zones.

3.2.2.2 Surface Casing

The surface casing is run after the conductor and seals off weak formations, losszones, fresh water sands or potential shallow gas zones. Subject to the well design, itmay provide gas diversion for well control, or it may be the first casing string to whichthe BOP is fitted to provide a closed well control and circulation system. It is normallycemented to surface, or inside the conductor string.

The setting depth is important in any area where abnormally high pressures areexpected. If the casing is set too high, the formations below the casing may not havesufficient strength to allow the well to be shut in (should a gas influx occur while drillingthe next hole section).


3.2.2.3 Intermediate Casing

The intermediate (protection) casing may be a full casing string or liner, set after thesurface casing and prior to the production casing. Its purpose is to isolate weakformations, loss/sloughing zones, squeezing salts or reservoir formations. The numberof intermediate strings will depend on the amount of problems anticipated, orencountered for a well. It can be set in abnormally pressured transition zones toprovide adequate well control, by upgrading the strength of the well. Cementationheight may vary depending upon the zones requiring isolation.

3.2.2.4 Production Casing

The casing, or liners that are installed to separate productive zones from otherreservoir formations, for the completion tubing or test string.

The production casing is usually run through the pay zone, or set just above the payzone. Depending upon the well design the casing may be cemented with a minimalheight, or back inside the intermediate casing.

3.2.2.5 Liners

A liner is a string of casing that does not extend all the way to the surface. Liners maybe installed either as a drilling liner to allow deeper drilling, to separate productivezones from other formations, or as a production liner. Liners are generally cemented tothe liner hanger.

The differences between a drilling and production liner are:

� Drilling Liner: Allows deeper drilling by casing off unstable formations, reducescasing costs, provides a competent casing shoe for deeper drilling, reduces tensionloads for long casing strings and minimises the effect of hydraulics restrictions

� Production liner: Allows a larger completion design, minimises tension loads forlong strings and reduces well casing costs

3.2.2.6 Tiebacks

A tieback is a casing string that is installed back to surface by stabbing into the existingliner hanger. A tieback string may be required to protect the previous casing string frompressures that will be encountered when the well is in production, to be able to conducta drill stem test (DST), or to isolate a well with damaged casing.

A tieback can be:

� A casing string that connects a liner with the wellhead or surface

� A casing string that connects a subsea wellhead with the surface (eg on a jack-upor platform)


O F F S H O R E A LT E R N AT I V E O F F S H O R E

L A N D ALTERNATIVE LAND

30"

20"

13 3/8"

9 5/8"

7"

700 '

1500 '

6000 '

13000 '

15000 '

14000 ' 7 5/8"

10 3/4"3500 '

16"1500 '

30"600 '

13 3/8""250 '

10 3/4"4,000'

9,000' 7 5/8"

5 1/2"13,000 ' 23,000 ' 5"

7 5/8"18,000 '

10 3/4"15,500 '

13 3/8"4,500'

20"100 'S

ome

Typi

cal

Cas

ing

Str

ing

Con

figu

rati

ons

C

S

I

P

L

LL

L

P

PP

I

I I

S

S

S

S

C

C =

Con

duct

or

S =

Sur

face

Cas

ing

I =

Int

erm

edia

te C

asin

g

P

= P

rodu

ctio

n C

asin

g

L

= L

iner

r


3.2.3 Mechanical Properties of Engineering Materials

3.2.3.1 Concepts and Definitions

Stress When a force is applied to an object, that force is distributed over thewhole cross-sectional area of the object. Stress is defined as theforce per unit area of cross section. Units of stress are force per unitarea (psi). The standard abbreviation for stress is: �.

Example: If a square bar, 2in on each side, is subjected to a tensileforce of 40,000 lb, the induced stress = force/area = 40,000/(2 x 2) = 10,000psi.

Strain Application of a force to an object causes the object to deform. Forexample, stress in a rod may cause it to increase or decrease inlength. The amount of deformation, for a given stress, is related tothe length of material, which is free to expand or contract. Strain isdefined as the proportional (or fractional) deformation. It is calculatedas the ratio of the change in length to the original length. Since this isthe ratio of two lengths, strain has no units (ie it is non-dimensional).

Example: If a rod of a certain material, of length 3ft, increases to alength of 3.25ft under tension the strain is (change in length)/originallength) = 0.25/3 = 0.07667.

Direct Stress If a force is applied directly to an object then that object, unlessrestrained, will simply move and no stresses will be set up. In orderfor stresses to be applied then an equal and opposite force must actagainst the original force. If the direction of each of these forcespasses through the line joining them then this is defined as being adirect stress.

Shear Stress If the directions of the two forces applied to an object do not passthrough the line joining them then there is a rotational component tothe stress. This component is called the shear stress. The standardabbreviation for shear stress is: s.


Young’s If an object, made of a particular material, is subjected to a stressModulus then it will deform to produce a strain. If an identical object, made

from a different material, is subjected to the same stress then thestrain produced will be different. The ratio of the stress to the straindepends only on the material and is called the Young’s Modulus forthat material. Young’s Modulus is calculated by dividing the appliedstress by the resulting strain. Since strain has no units then the unitsof Young’s Modulus are the same as those of stress (psi). Thestandard abbreviation for Young’s Modulus is: E.

Poisson’s Ratio When an object is stressed,the strain occurs in thedirection of the direct stress.At the same time, a lengthchange occurs in thedimensions at right-anglesto this direction. (When arod of material is placed intension the length will increase but there is a reduction in roddiameter.) The lateral strain is defined, as with longitudinal strain, asthe ratio of the dimension change to the original dimension. Forany material, the ratio of lateral to longitudinal strain is constantand is known as the Poisson’s Ratio for that material. Standardabbreviation: ��

Example: A square specimen of steel is 1ft long and 1in square (area = 1sqin).A force of 30,000 lb is applied resulting in a new length of 12.012inand a section width of 0.9997in.

Stress = 30,000/1 = 30,000psi

Longitudinal strain = 0.012/12 = 0.001

Young’s Modulus = 30,000/0.001 = 30 x 106psi

Lateral strain = 0.0003/1 = 0.0003

Poisson’s Ratio = 0.0003/0.001 = 0.3

Original

Deformed


3.2.4 Analysis Methods

The analysis required for a well design involves a variety of engineering equations withdiffering degrees of complexity and may include a number of additional loads, due tothe in-service requirements, or service factors of the well.

3.2.4.1 Analysis Types

The three principal analysis types include uniaxial, biaxial and triaxial design.

3.2.4.1.1 Uniaxial Analysis

Uniaxial stress analysis looks at each individual loading as a single solution andcalculates separately the total loading as the sum of each individual load(ie one dimensional).

For example, burst, collapse and tension would be defined and assessed individuallyfor the various anticipated load cases. Uniaxial designs are easily performed by handcalculations but generally lead to over-designed solutions, ie well design safety factorscan be too high.

The uniaxial approach is very effective in rapidly approaching optimised well designsand is based on the formulae published API Bulletin 5C3.

3.2.4.1.2 Biaxial Analysis

Stresses applied to a material do not act in isolation. Internal burst pressures not onlyproduce radial and hoop stresses but also tend to reduce the length of a casing string,increasing the axial stresses. External collapse pressures reduce axial stresses. For abiaxial stress the tension reduces the collapse rating and increases the burst rating ofthe pipe. Biaxial stress analysis is a method of combining load factors two at a time(ie in two dimensions). The biaxial approach is more complex than uniaxial but lessrigorous than a triaxial design, so is now rarely used in practice. Biaxial stress analysiswas the stepping stone for triaxial analysis.


3.2.4.1.3 Triaxial Analysis

Triaxial stress analysis is a combination of various loads in all directions on a casingstring and consist of axial, internal and external loads. In reality triaxial stresses aregenerated, rather than uniaxial or biaxial stresses, as stated in the API BulletinFormulae. Therefore, the three principal stresses for a casing string are:

Axial (�a), Radial (�r), and Tangential (�t) as highlighted below.

Triaxial stress analysis considers these loads through analysis, using a combination ofthe three primary equation sets:

� Lamé

� Hooke’s Law

� Von Mises Yield Criterion

However, with the increasing use of triaxial stress analysis for casing design, variouscommercial software packages are available to assist the well designer and performthe iterative calculations required for all three principal stress, load case combinations.

3.2.4.2 Primary Analysis Equations

Casing stress analysis requires the determination of the stresses that exist within acasing wall. These stresses are the axial stress (�a), tangential (hoop) stress (�t), theradial stress (�r) and the three shear stresses �. The three primary analysis equationsused for well design are: Lamé, Von Mises and Hooke.

In terms of sign convention for mechanical engineering, tension, elongation and fluidpressure are positive.

t�

t�

r�

r�

a�

a�


3.2.4.2.1 Lamé

The Lamé equations are derived from the differential equation of equilibrium, thecompatibility equation and the boundary conditions expressed in polar co-ordinates.For a hollow cylinder submitted to uniform pressure on the inner and outer surfaces,the radial and tangential stresses within the cylinder walls are given by:

AAAA

)P(PA

APAP

s

ieei

s

eeiir ��

��

AAAA

)PP(A

APAP

s

ieei

s

eeiit ��

��

Where:

Pi = Internal PressurePe = External Pressure

Ai = Internal Cross-sectional Area(di = Internal Pipe Diameter)

Ae = External Cross-sectional Area(de = External Pipe Diameter)

As = Wall Cross-sectional Area ��

��

�

��

4dd

22ie = Ae – Ai

A = the cross-sectional area at the diameter d at which the stress is being evaluated

These are known as Lamé equations. It should be noted that �r and �t are not afunction of the axial stress �a. It also follows that the sum of �r and �t is constant overthe wall thickness.

In the case of a cylinder subjected to equal internal and external pressure, P, the radialand tangential stresses are:

� �P-

AAA

Ps

eir �

��

� �P-

AAA

Ps

eit �

��

Thus the radial and tangential stress are equal and are constant through the casingwall. It is also important to note that radial and tangential stresses still exist in theabsence of a differential pressure. They will only be zero when both Pi and Pe are zero.

��

�

�

��

�

� �

4d 2

i

��

�

�

��

�

� �

4

d 2e


If a cylinder is subjected to external pressure Pe only, the radial and tangential stressesare:

�r = -Pe at A = Ae (outer surface)

�t = 0 at A = Ai (at inner surface)

� �

s

ieet A

AAP-

�� at A = Ae

� �

s

eet A

A2P-�� at A = Ai

Additionally, for a cylinder subjected only to internal pressure Pi the stresses are:

�r = 0 at A = Ae

�r = -Pi at A = Ai

� �

s

ieit A

A2P

�� at A = Ae

� �

s

ieet A

AAP

�� at A = Ai

There are two observations to be noted here. First, the normalised value of �t is alwayslargest at the inner surface of the casing wall (A = Ai). Second, the tangential stress ismuch larger than the radial stress. To simplify stress analysis, the radial stress is oftenignored.

Note : In order to simplify manipulation of the Lamé equations, it is best to work inareas, ie Ae, Ai, As rather than a diameter or radius.

3.2.4.3 Von Mises Yield Criterion

Casing design is based on all stresses remaining below the yield strength and byassuming an ideal elastic/plastic material behaviour (see Figure 3.1). The API yieldstrength is taken as a measure of the maximum allowable stress. This is a simplifiedassumption of actual material behaviour. However, in reality, exceeding the yield stressdoes not necessarily lead to failure of the material and in certain circumstances yieldcan be tolerated or even designed for.


Figure 3.1 - Stress v Strain

API YieldStrength

N om inalS tress,

S train,

0.5%

�

�

Ideal e lastic/plastic behav iour

The yield strength, or yield stress is derived from uniaxial tests. To relate this uniaxialyield stress to the three-dimensional stress system that exists in reality, the concept of‘strain energy of distortion’ is used. The yield of ductile material such as steel occurs ata critical value of this strain energy of distortion.

The strain energy of distortion per unit volume of material UD is expressed as:

� � � � � � � �� 213

232

221D E6

1U ��

��

Where ��,��,��3 are the three principal normal stresses (in any order).

For steel, it is usually assumed that yielding is defined by the Von Mises yield criterion.This criterion states that yielding starts when UD reaches a critical value.


Figure 3.2 - Principal Stresses

This critical value of UD is determined from the uniaxial test in which �� y at yieldand all other stresses are zero, so that:

� � � �2yD 2

E61

U ��

�

Therefore for a three-dimensional system, the yield locus is:

� � � � � �� 213

232

221

2y2 ��

The above equation, known as the Von Mises yield criterion, can be represented as acylindrical yield envelope, passing through the origin of the ��,��,�� co-ordinatesystem and being inclined at equal angles to the three axes. See Figure 3.3. Pointscalculated to represent the stresses within a material, that lie inside the cylinder havenot reached yield, whereas yielding has occurred for all points that are calculated to fallon the surface of the cylinder.

It should be noted that yield occurs as a result of differences between the principalstresses, not as a result of their absolute values.

t�

t�

r�

r�

a�

a�


Figure 3.3 - Cylindrical Failure Envelope

With particular reference to casing string analysis, the normal stresses �a,��t, �r andshear stresses, �at, �tr and �ra must be included in the Von Mises yield criterion.

It can be derived that the Von Mises yield criterion expressed in these stresses is:

This can be rewritten as:

� � � � � � 21

2

ra

2

tr

2

at

2

ar

2

rt

2

ta666

2

1vme ��

��

y�

1�

2�

3�

von Mises cyl indr ical fai lure envelope

von Mises Fai lureEll ipse


Thus, for determining whether a material has a sufficient yield strength to withstand thestresses induced in the material by imposed loads, the Von Mises Equivalent (VME)stress, �VME is calculated and compared to the yield stress.

Therefore:

� � � � � �� 21

2ra

2tr

2at

2ar

2rt

2tay 666

2

1��

Since the shear stresses �tr and �ra are usually negligible compared to the otherstresses, thus the common expression for the VME stress equation is:

� � � � � �� 21

2at

2ar

2rt

2tavme 6

2

1��

In terms of units, if the stresses are quoted, or entered as psi then the final Von Misesstresses will also be in psi.

A triaxial stress design factor is defined as:

VMEVME

sY

DF�

�

Where:

DFVME is the triaxial design factor and a value of 1.25 is regarded as the typical industryvalue to consider.

Ys is the API yield strength of the casing material.

�VME is the Von Mises equivalent stress.

According to the Von Mises theory, an axial stress can increase the tangentialstress capacity before first yield of casing and vice versa. This is shown in Figure 3.4,a diagram similar to those produced by computer casing/tubular analysis programmes.


Figure 3.4 - Triaxial Load Capacity Diagram

The triaxial design process requires the calculation of the VME stress at the top andbottom of each casing interval, of a single weight and grade and at each particularpoint of interest. For the �VME to be calculated, axial (�a), radial (�r), and tangential(�t) stresses are required. It should be noted that a triaxial equivalent stress is not atrue stress but is a theoretical stress that permits a generalised three dimensionalstress state, to be compared with the yield strength.

The triaxial load capacity diagram is normalised to allow for a two-dimensional plot ofthe triaxial stress and is not used directly for analysis calculations. However, thediagram does provide a picture of the triaxial stress ellipse as compared to the currentAPI rating window for a typical casing. As shown in the compression/internal pressurequadrant (top left corner), the API burst rating can exceed the triaxial stress allowableof the casing and if so, the triaxial criterion will govern the design. For thetension/internal pressure quadrant (top right corner), the triaxial stress allowable mayexceed the uniaxial burst allowable and here the latter will govern the design.

Inte

rnal

Pre

ssur

e

Compression +Burst

Compression +Collapse

API Collapse Line

AxialTension

AxialCompression

Ext

erna

lP

ress

ure

API Burst Line

Triaxial ell ipse for Pi=0

API AxialTension Line

API AxialCompression Line

Triaxial ell ipse for Pe=0

Tension +Burst

Tension +Collapse

Tri-axial l imit not applicablein collapse region


The collapse region of the diagram is more difficult to apply to all casings and shouldbe used with caution. The API recognises the biaxial (tension) effect on the reduction ofcollapse rating as shown in the axial tension/external pressure quadrant (bottom rightcorner). However, in the axial compression/external pressure quadrant (bottom leftcorner), the API does not increase the rating of collapse due to compression.

One of the issues to be aware of is the effect of OD/t ratio on the collapse mechanism.API Bulletin 5C3 clarifies the collapse pressure formulae for the various collapseconditions and should be referred to when considering collapse well design. For anOD/t ratio of �15 (ie thicker walled casing) triaxial stress is a relevant design criterion,where OD = diameter of pipe body and t = wall thickness of pipe.

Elastic instability is an increasingly significant contribution to collapse as the OD/t ratioincreases and triaxial analysis becomes irrelevant and unconservative in relation tocollapse ratios for OD/t > 15. The effect of this is that it is necessary to satisfy both thetriaxial stress versus yield and API uniaxial collapse requirements (bending is assumedto not affect the API collapse resistance).

Triaxial analysis is generally recommended for wells that are deemed as not typical, orhave unusual loading conditions. For example, this may typically include issuessuch as:

� High bottom hole pressures

� Temperatures in excess of c. 250�F bottom hole static

� Simultaneous axial compression and burst loading

� H2S service

� Ratio of OD/t < 15

� Buckling is anticipated

� Ice loading

To summarise, the primary purpose of the triaxial design factor is to avoid localyielding, particularly during buckling, which may lead to subsequent failure.

3.2.4.4 Hooke

For small strains, steel behaves as a linearly elastic material. This means that Hooke’sLaw relates the components of stress to the components of strain. This law states thatfor a uniaxial stress, the magnitude of the unit elongation of an element is given by:

Ea

a

��

Where E is Young’s Modulus.


Extension in the axial direction is also accompanied by lateral contractions in the radialand tangential directions. For isotropic materials, E is the same in all directions andtherefore:

Ea

r

�� and

Ea

t

��

Where � is Poisson’s Ratio and is 0.30 for steel.

If the element is simultaneously subjected to normal stresses axial stress �a, tangential(hoop) stress �t, the radial stress �r. The resultant components of strain can beobtained by superimposing the strain components produced by each of the threestresses.

� �� traa E1

��

� �� ratt E1

��

� �� tarr E1

��

The strain component of particular interest for casing design is in the axial direction.

The strains in the above formula apply to unit length (per ft). For a casing string (orextended length) the total strains have to summed over the whole free length.

Thus for the total axial strain the sum of the radial and tangential stresses, following theLamé equations becomes:

It then follows that for any point along the pipe:

� �

s

eeiir A

APAP2 ��

� ��

��

� ��

s

eeiiaa A

APAP2E1


Therefore, for a suspended casing with a free-moving casing shoe, the totalelongation is:

� �ds

AAPAP2

E1

Ls

eeiia

L

o��

��

� ��

For an axially constrained, ie cemented casing, �L = 0. Hence, a relation betweenthe change in pressures and change in axial tension results. This leads to the linkbetween the change in radial, tangential and axial stresses in a casing, which isaxially constrained.

3.2.4.5 Incorporation of Service Factors

A casing design will be influenced by the operating environment with respect to timeand must be considered accordingly for the anticipated life cycle of the well as apressure vessel.

A number of service factors will therefore need to be considered as part of a casingdesign, including casing wear, corrosion, temperature and fatigue.

3.2.4.5.1 Casing Wear

Casing wear is caused by the formation of a localised groove cut by a rotating drillstring forced against a casing internal surface. The combination of high side-wall forcesand extended drillstring to casing contact around the kick-off section of a well profilecan generate wear but localised doglegs can cause severe wear whenever they occur.Wear due to tripping and wire-line operations has a limited influence on the overall totalwear, compared to drillpipe rotating in the casing.

Casing wear ultimately leads to failure as the burst, collapse and axial strengths aredirectly related to wall thickness and hence are reduced by wear.

Casing wear is assessed by identifying the functions for drilling/production conditionsand estimating the wear/erosion on the casing wall. It will primarily be an issue ondirectional wells, or hole sections with high a dogleg severity.

As part of a well design, casing wear should be estimated by consideration ofthe following:

� Type of drillpipe hardbanding

� Mud type (oil based or water based)

� Estimation of drillstring side-loads based on well profile

� Estimation of total rotating hours expected inside the casing string and plannedrotating speed

� Life of well based on exploration (single well drilling cycle) or development (multiplewell re-entries)


The data should then estimate a wear factor for the well and ultimately determine anestimated % reduction in strength for the casing strings.

Well design for casing wear should be based on the following:

� Design the casing string

� Evaluate casing wear using proprietary casing wear software/techniques

� Calculate the burst, collapse, axial and triaxial capacities of the worn casing andcompare to anticipated loads

� Check if the worn casing is adequate to withstand the design loads

� Modify well design if required

In the event that casing wear will not be significant to justify an increase in wallthickness, or adopt alternative use of drilling methods, a wear monitoring programmeshould be implemented while drilling.

3.2.4.5.2 Corrosion

Corrosion can reduce the ability of the casing to perform its functions in two ways.Firstly, metal loss will reduce the wall thickness of the casing and hence its capacity towithstand the design loads. Secondly, corrosion can weaken the material such that it isunable to withstand the design loads (see Section 2 for corrosion).

However, in terms of well design, corrosion is assessed for material selection at thedesign stage, in particular the yield strength in conjunction with temperature. Somecommon issues to consider are for H2S (NACE MR 0175-99) and CO2.

Forms of corrosion can lead to sudden and rapid failure including, for example:

� Sulphide stress cracking (SSC)

� Hydrogen embrittlement (HE)

� Chloride stress cracking (CSC)

These will have an effect on the mechanical properties such as burst, collapse andtension.

For many corrosive environments, particularly those involving gaseous components,the critical factor is not the percentage (or parts per million, ppm) of H2S or CO2 whichare the units normally given. More important is the relative amount of thesecomponents in the gas stream. This is often quoted in terms of the ‘partial pressure’ ofthe component in the gas stream, the pressure that would be left if all othercomponents of the gas were removed. To a reasonable degree of accuracy this maybe calculated by multiplying the known pressure by the fraction of the stream, which isthe corrosive gas. (Example: If a gas stream has 3% CO2 and at some point the totalpressure is 4500psi then the partial pressure of CO2 is 4500 x 3/100 = 135psi.)


Temperature also plays an important role: H2S rich gases become less corrosive athigher temperature while CO2 gases become more corrosive. The two charts belowgive a general indication of the materials required for different corrosive environments.These should be used only as a general guide and steel manufacturers should beapproached for more specific information.

Corrosion well design issues are generally a concern for development wells where thereservoir constituents, internal/external fluids (muds/brines) and life of the well couldinfluence the long-term well integrity. Temporary exposure to H2S (hydrogen sulphide)is the exception that can affect all well types, as rapid catastrophic failure can occurdue to the material acting in a brittle manner. Hence, it is now routine to typicallyspecify L-80 yield materials (improved ductility and lower maximum yield) for casingdesign, as opposed to N-80.

Tubing, or casing exposed to corrosive produced fluids, may demand the use ofcorrosion resistant alloys (CRA) for well design requirements.

The NACE standard is an important document for assessing the crossover point ontemperatures for casing material assessment eg for geothermal temperatures below175�F and with H2S partial pressure of 0.05psi you cannot use steel with a hardnessgreater than HRC 22 (Rockwell). Hence, the need to check the material specificationwithin API 5CT and manufacturers’ non-proprietary grades.

Corrosion well design should consider the issues for exploration (short-term) in adifferent manner for development (long-term) by focusing on the drilling mud pH > 10 inorder to neutralise hydrogen sulphide, use of chemical sulphide scavengers and reviewthe casing materials relative to temperature for H2S (NACE) requirements.

Development wells should endeavour to contain the corrosive produced fluids withinthe production tubing by correct selection/corrosion resistance of the annulus fluid. Anypart of the casing string that is likely to be exposed to produced fluids for a significantlength of time should be designed to withstand such an environment.

3.2.4.5.3 Temperature

Temperature can affect casing design in a number of ways.

High temperatures leading to a reduction in yield strength; extreme low temperatures,at or near surface, leading to a change in material structure and brittle fracture.

Additionally, increases in temperature cause the casing to increase in length and theability of the casing to move to accommodate this change determines the resultingstresses. This can lead to buckling and compressive failure, due to a change in theaxial stress.

Finally, the wellbore temperature gradient also has an influence in determining suitablematerial selection and crossover points relative to NACE requirements for H2S.


Figure 3.5 - Application of Various Materials to thePrevention of Sour Service Corrosion

0.00

1

0.01 0.1 1 10 100

1000

Partial pressure of hydrogen sulphide, bar

0.01

0.1

1

10

100

1000

ANYG RADE

SOUR SE RV ICE RES IS TAN TCARBON AND LOW ALLOY ST E EL GRADE S

Par

tial p

ress

ure

of c

arbo

n di

oxid

e, b

ar

SUPER-AUS TE NIT IC ALLOYS

SOLUTION ANNE ALE D

OR HIG H S T RENGT H

DUPLE XST AINLES S

S TE ELSOLUTIONANNE ALE D

M ARTE NSIT IC

ST AINLES S

S TE EL

DUPLE XS TAINLE SS S TEE L -

HIG H S TRE NGTH

TE M PERATURES UP TO 150 deg C

0.00

1

0.01

0.1 1 10 100

1000

Partial pressure of hydrogen sulph ide, bar

0.01

0.1

1

10

100

1000

ANYG RADE

S OUR S ER V ICE RE SIS TANTCARBON AND LOW ALLOY S TE E L GRADE S

Par

tial p

ress

ure

of c

arbo

n di

oxid

e, b

ar

S UPE R-AUT EN IT IC ALLOYS

S OLUT ION AN NEALE D

OR HIG H S T RENG TH

TE M PE RATURE S OV E R 200 deg C

SUPER-AUSTENI T I C ALLOYS

SOLUTI ON ANNEALED

OR HI GH STRENGTH


For high temperature casing design, a yield strength correction factor is typicallyused to modify the material properties; as yield strength decreases, the temperatureincreases. A typical yield strength temperature derating factor is 0.03% per �F above68�F and relates to a c. 9.7% reduction in yield strength for a high temperature well at392�F (200�C). When design yield strength has a critical influence on weight, or gradeselection, it is necessary to ensure that the yield strength at elevated temperatures atleast matches the assumptions in the well design and that the manufacturer canachieve the required properties.

Extreme changes in temperature should also be considered. For example, whendisplacing a hot mud from a high pressure, high temperature (HPHT) well to coldseawater for a DST, temperature cycling may occur, leading to rapid changes in axialstresses from compression (hot condition) to tension (cold condition). This needs to betaken into consideration for axial stresses.

3.2.4.5.4 Fatigue

Casing failure can have various causes. Casing may fail after one single loadexceeding the ultimate tensile or compressive strength, but also after repeated loadcycles below the ultimate tensile or compressive strength. This phenomenon is knownas fatigue, and practically all materials are subject to it.

The effects of surface condition, corrosion, temperature, etc on fatigue properties aredocumented and in recent years the microscopic mechanism of fatigue damage beenidentified as cyclic plastic deformation of the material at the source of a fatigue crack(crack initiation), or at the tip of an existing fatigue crack (crack propagation).

Most data concerning the number of cycles to failure are presented in the form of anS/N curve where the cyclic stress amplitude is plotted on log-log paper versus thenumber of cycles to failure. Where S = the magnitude of stress and N = the numberof cycles.

Ferrous metals in air show a lower limit to the stress amplitude called the fatigue limit,or endurance limit. This generally occurs after 105 to 107 stress-reversal cycles. Stressreversals below this limit will not cause failure, regardless of the number of repetitions.Ferrous metals in seawater, however, do not show this cut-off. S tends to zero withincreasing N.

An example of where fatigue has an influence for the long term is wellhead design aspart of the casing design, in particular due to the interaction of the BOP and marineriser system for subsea wells. External loads from wave and current and soil loadsshould therefore be considered.

Fatigue can be influenced by a number of issues and include the following:

� Stress history

� Stress concentrations

� Residual stress

� Corrosion fatigue


Casing fatigue failure can be related to casing dimensions, material properties, numberof load cycles and types of load amplitudes exerted on the casing. The last two aredependent on several parameters, for example, movement and mechanical propertiesof the components connected to the casing.

Figure 3.6 - Schematic of an S/N curve

ST

RE

SS

, S

N um ber o f cyc les o f s tress , N104 106 108

F a tigue L im it

T yp ica l S - N C urve fo rS tee ls

3.2.5 Leak Off Tests and Interpretation

3.2.5.1 Introduction

Leak off and limit tests are carried out during the drilling phase of the well. The BOP isclosed around the drillpipe, and the well is slowly pressured up, using mud. At the firstsign of fluid leak off into the formation, the pumping is stopped. Leak off tests arecarried out until leak off is observed; limit tests are carried out until a predeterminedtest pressure is reached.

Leak off and limit tests are carried out to:

� Confirm the strength of the cement bond around the casing shoe and to ensurethat no flow path is established to formations above the casing shoe or to theprevious annulus


� Investigate the capability of the wellbore to withstand additional pressure below thecasing shoe in order to assess the competence of the well to handle an influx, andto allow proper well design with regard to the safe drilling depth of the nexthole section

� Collect regional data on formation strength for the future planning of fracturegradient profiles for casing design

The tests are sometimes called: casing seat, formation strength or formationintegrity tests.

The pressures exerted during a limit or leak off test should never exceed the maximumburst pressure of the casing and surface equipment.

Figure 3.7 shows a typical formation fracture graph that could be expected for a wellformation.

Figure 3.7 - T ypical Formation Fracture Graph

Pum p R ate (C onstant)

Leak-offP ressure, LO P

Form ation Breakdow nPressure, FBP

Fracture P ropagationPressure, FPP

Fracture C losurePressure, FCP

Instantaneous Shut-inPressure, IS IP

T im e

Dow

nhol

e P

ress

ure

F ITL im it

The primary terms are summarised below. However, it is worth noting that formationbreakdown during a limit or leak off test should be prevented, as a fracture maypermanently impair the capability of the wellbore to withstand pressure. If breakdowndoes occur it should be treated as an opportunity to obtain formation strength data asthis is in effect a fracture.

Results should be plotted and interpreted on a large scale of volume (or time) versuspressure plot (for a formation integrity test (FIT) test) or time (or volume) versuspressure (for a LOT).


3.2.5.2 Formation Integrity Test (FIT)

In a successful formation integrity test no leak off is observed, when the initial staticpressure reaches the surface limit pressure. This is confirmed as the pressure increaseversus volume pumped is straight, with no deviation on the graph. This confirms thewellbore is strong enough to hold this additional pressure without formation breakdown.

3.2.5.3 Leak Off Test Pressure (LOP)

Leak off can be defined by the first deviation from the trend of the pressure line.Generally it can be identified if two points on the curve deviate from the trend line. Thesurface leak off pressure is the interpolated value of the pressure at the first indicationof leak off.

3.2.5.4 Formation Breakdown Pressure (FBP)

The formation breakdown pressure is indicated by a sharp pressure drop on surface.The highest pressure recorded immediately before the pressure drop is the surfacebreakdown pressure.

3.2.5.5 Fracture Propagation Pressure (FPP)

The fracture propagation pressure is the constant pressure required to propagate afracture out into the formation.

3.2.5.6 Instantaneous Shut-in Pressure (ISIP)

The instantaneous shut-in pressure is the value recorded immediately when pumping isstopped.

3.2.5.7 Fracture Closure Pressure (FCP)

Once pumping is stopped, the pressure decay is recorded. Fracture closure isindicated by the stabilisation of the pressure decay curve to a constant pressure value.The results may be used to determine the in-situ stress.



SECTION 4 DESIGN PREPARATION Page 1 of 15

TABLE OF CONTENTS

4. DESIGN PREPARATION....................................................................................... 3

4.1 DATA RESEARCH........................................................................................... 3

4.1.1 Pre Drill Data Package (PDDP) .................................................................. 3

4.1.2 Offset Data ................................................................................................. 4

4.2 DESIGN CONSIDERATIONS........................................................................... 5

4.2.1 Hole Size: Evaluation.................................................................................. 5

4.2.1.1 Logging...................................................................................................... 5

4.2.1.2 Coring ........................................................................................................ 5

4.2.1.3 Test Tools.................................................................................................. 5

4.2.1.4 Completion ................................................................................................ 5

4.2.1.5 Formation Damage .................................................................................... 5

4.2.2 Hole Size: Drilling ....................................................................................... 5

4.2.2.1 Drill String/BHA Sizes ................................................................................ 5

4.2.2.2 Fishing Equipment ..................................................................................... 5

4.2.2.3 Well Control ............................................................................................... 6

4.2.2.4 Hydraulics .................................................................................................. 6

4.2.3 Completion Sizing....................................................................................... 6

4.2.3.1 Down Hole Safety Valves........................................................................... 6

4.2.3.2 Slotted Liners/Sandscreens ....................................................................... 6

4.2.3.3 Production Tubulars................................................................................... 6

4.2.3.4 Production Packers.................................................................................... 6

4.2.3.5 Artificial Lift ................................................................................................ 6

4.2.3.6 Subsea Systems........................................................................................ 7

4.2.3.7 Multiple Completions.................................................................................. 7

4.2.4 Special Service Conditions ......................................................................... 7

4.2.4.1 Blowout...................................................................................................... 7

4.2.4.2 Air, Foam, Aerated Drilling......................................................................... 7

4.2.4.3 High Pressure, High Temperature.............................................................. 8

4.2.4.4 Deepwater ................................................................................................. 9

4.2.4.5 Injection ..................................................................................................... 9

DESIGN PREPARATION Page 2 of 15

4.2.4.6 Gas Lift .................................................................................................... 10

4.2.4.7 Stimulation............................................................................................... 10

4.2.4.8 Mobile Formations ................................................................................... 10

4.2.4.9 Steam ...................................................................................................... 11

4.2.4.10 Reservoir Compaction.............................................................................. 12

4.2.4.11 Horizontal/High Angle............................................................................... 12

4.2.4.12 Corrosion.................................................................................................. 12

4.2.5 Contingencies........................................................................................... 13

4.2.5.1 Sidetrack(s) ............................................................................................. 13

4.2.5.2 Well Deepening During Drilling ................................................................ 13

4.2.5.3 Well Conversions..................................................................................... 14

4.3 WELL DESIGN CHECKLIS T ......................................................................... 14

4.4 WELL DESIGN DATA SUMMARY SHEET.................................................... 15


4. DESIGN PREPARATION

4.1 DATA RESEARCH

4.1.1 Pre Drill Data Package (PDDP)

The geology/geophysics team or Asset Group should ensure that a PDDP is preparedfor each well. The PDDP should clearly state the well objectives for the project andcontain the required detail for the optimum casing design. The PDDP may not alwaysresult in a well design that provides minimum cost, hence the need for the objectives tobe agreed with the various disciplines, prior to the commencement of detailed wellplanning. The group responsible for the well will prepare the PDDP with input from thevarious disciplines, including the Drilling Engineer. It should be approved by the WellOwner and used as a datum document for all team members, associated with thewell design.

This may require feasibility studies with various conceptual well designs prior toproceeding further. Early involvement by the drilling engineer as part of the well teamensures an efficient, cost effective design is achieved. An overview of this process isshown below.

A template for a PDDP is included in Section 2.2 of the Well Design Manual. Thispromotes a formal audit trail of the well design process for data provided by otherdisciplines eg Geologist, Petroleum Engineer, Reservoir Engineer, Geophysics,Surveying, Environmental, Safety, Subsea, Production and Completion Engineers, etc.

Data Collection

Casing SchemeSelection

Detailed Design


Subjects within the PDDP that impact on casing design, include, but are not limited to:

� Well location, total depth, water depth, and objective depths

� Pore and fracture pressures

� Deviation of well (directional or vertical)

� Exploration or development (probability of completing as a development impactscasing design and material selection)

� Timing requirements (impact on rig availability/logistics for remote locations)

� Evaluation requirements (logging, coring, and testing) has an impact on hole size

� Testing or production rates required impacts size of tubing and production casing

� Hydrocarbon composition: gas or oil. If corrosion anticipated from H2S/CO2/Climpacts material selection, cost and lead time for tubulars

� Environmental issues, hydrocarbon leakage, abandonment constraints, surfaceacquifers, wave forces, ice, shipping collision

� Anticipated use, life, and potential well intervention, with regard to well design

4.1.2 Offset Data

The PDDP will identify the relevant offset wells which should be researched by theDrilling Engineer. This data required includes the following items:

� Pore pressure and fracture gradient profiles (overpressures, depleted zonescompaction)

� Geological lithology information (formation tops, faults, structure maps etc)

� Shallow gas assessments

� Offset drilling well data (casing programmes, geological tie-ins, mud weights,operational problems such as loss zones or over-pressured zones)

� Temperature profiles

� Hazard identification and constraints (shallow gas, faults, lease line restrictions,capability of rig, anti-collision, blowout preventer (BOP) size, wellheadconfiguration, casing inventories)

� Hydrocarbons data (constituents of reservoir, gas/oil ratio (GOR), H2S, CO2)

� Tubing and down hole completion component sizes for casing design

� Annulus communication on development wells, bleed-off and monitoring policies


4.2 DESIGN CONSIDERATIONS

The following list summarises topics to consider for well design, as part of the PDDP:

4.2.1 Hole Size: Evaluation

4.2.1.1 Logging

May determine where casing shoe is set as a function of geology. Requirement forcased hole logging tools must be discussed with production eg links for inclusion ofradioactive pipe marker pup joints, as part of casing for future logging tools.

4.2.1.2 Coring

Availability of equipment relative to hole and casing size. Minimum core size requiredfor analysis to be agreed and balanced against minimum hole size for well design.

4.2.1.3 Test Tools

If exploration well, size of test string and OD of tools required for well. Size of DSTpacker relative to liner size and setting depth for flow and well kill purposes.

4.2.1.4 Completion

Minimum tubing size and completion component requirements as a function ofoptimum flowrates and productivity index. (Making the liner part of the completioneg monobore system.)

4.2.1.5 Formation Damage

Optimising casing seat depths to minimise formation/skin damage, as a function ofmud overbalance and time exposure.

4.2.2 Hole Size: Drilling

4.2.2.1 Drill String/BHA Sizes

Optimising hole sizes, well depth and casing seat, relative to drillstring availability andcapabilities. Includes well survey profile, torque and drag analysis eg extended reachdrilling (ERD) and horizontal wells.

4.2.2.2 Fishing Equipment

Optimising hole/casing sizes based on ability to access and fish: drillstrings/BHAs/teststrings/coring BHAs/fracture stimulation strings etc.


4.2.2.3 Well Control

Lack of contingencies for additional hole sections if utilising slimhole/reduced ODdesigns, lack of structural support for BOPs and subsequent casing strings if reducingcasing/hole size after conductor set, reduction in kick tolerance margins for small holesizes in reservoir sections.

4.2.2.4 Hydraulics

Limitations on rig equipment/pressure capabilities for reduced casing/hole sizes.Consideration on use of casing liners as part of wellbore hydraulics, optimisation ofcasing seats/hole sizes relative to drillpipe sizing and BHAs.

4.2.3 Completion Sizing

This includes drill stem testing as well as completion design. A strong link is required atthe conceptual stage, between the drilling, petroleum, production and completionengineers to ensure all iterations and sizing issues are discussed, for initial installationand well interventions.

4.2.3.1 Down Hole Safety Valves

Diameter may dictate a composite production casing string, to accommodate the valve,eg 10-3/4in/9-5/8in production string.

4.2.3.2 Slotted Liners/Sandscreens

Requires careful placement of production casing shoe, optimise in order to access wellfor future uncemented production operations.

4.2.3.3 Production Tubulars

Optimising the completion tubular design to maximise the well inflow (ProductivityIndex) from the reservoir relative to the flow rates through the completion system.

4.2.3.4 Production Packers

The completion design may be installed with a permanent packer, which would dictatea minimum casing size, or liner overlap length. Alternatively, it may be installed as partof the monobore system, by stabbing directly into the production liner.

4.2.3.5 Artificial Lift

Addressed as part of well design due to impact on minimum casing size, completionsize and sand control issues. Systems include electric submersible pumps (ESPs), gaslift (side pocket mandrels), jet pumps, beam pumps etc. May require composite casingstrings, eg 10-3/4in/9-5/8in. The issues are generally related to annular clearanceand access.


4.2.3.6 Subsea Systems

Issues affecting casing design generally relate to well access and ID of casing eg dualbore tubing hangers for annulus monitoring capability, or downhole gauges. Alsostructural integrity of conductor/surface casings, as part of well design onwellhead/xmas tree system. Also subsea xmas trees and production systems can applyhigh cyclic loads to the wellhead and shallow casings. Tubular fatigue life should beconsidered and the tubular specifications, cement tops and wellhead design should beoptimised to meet the well life objectives.

4.2.3.7 Multiple Completions

Multiple completions impose restraints on casing internal diameters, with the need torun two or more tubing strings in parallel. Additionally, for wells completed with bothproduction and injection strings, the casing analysis must consider all ranges ofpressure and temperature resulting from one or both of the tubing strings being shut in,or failing.

4.2.4 Special Service Conditions

There are a number of special service conditions that the Drilling Engineer needs to beaware of and consider for casing design.

4.2.4.1 Blowout

If the casing is to cater for a blowout scenario during drilling for collapse, fullevacuation of the string to atmospheric pressure must be assumed for the internalpressure profile. This condition represents a blowout where the open hole formationbridges and the gas is allowed to bleed to zero at surface. Similarly for burst, the worstcondition is a shut-in full reservoir column at surface, or the subsea wellhead for theproduction casing string.

4.2.4.2 Air, Foam, Aerated Drilling

When air drilling is used, the wellbore pressure could become atmospheric in the eventof equipment failure. Similarly, foam drilling is subject to the hazard that the foam canlose stability and the liquid phase can drop out. If these scenarios are likely, the casingshould be designed to withstand full internal evacuation, unlike the base case, whereevacuation is likely to be partial.

For aerated drilling, the designer should consider the internal evacuation level that canbe expected, based on the pore-pressure profile in the event of equipment failurepreventing fluid supply.

Production casing string designed for blowout as above.


4.2.4.3 High Pressure, High Temperature

In such environments, high differential pressures lead to the use of high strength, thick-walled and non-standard casings. High temperatures compound the design byreducing the yield strength of the steel. This causes thermal linear expansion of thesteel and generates high pressures in sealed annuli, due to thermal expansion of thefluid. The following issues should be considered based on the loads experienced by thecasing and the capacity of the casing to resist loads. A triaxial stress analysis is therecommended approach for such wells.

a. Casing Loads

High tensile, or compressive axial forces on the casing affect the ability to resistcollapse and burst pressures. This is more significant in high pressure, hightemperature (HPHT) wells due to the high pressures involved. Also a buildup ofannulus pressures due to thermal expansion of fluid in sealed annuli which cannotbe bled off eg subsea wells should be considered. Annular pressures that may behigh during production, should be estimated with iterative computer simulations.High buckling potential occurs due to linear expansion from large temperatureincreases during deeper drilling and testing/production. The increase in drilling fluiddensity during deeper drilling, adds to this buckling potential.

Testing programmes should ensure the casing is capable of withstanding theanticipated burst loads and needs careful design when combination strings areplanned. The axial loads resulting from retrievable test packers, eg pressure testingand tubing leak at surface, should be checked as part of well design analysis.

b. Casing Specifications

Due to the high pressures anticipated, the partial pressure for H2S that defines sourconditions (0.05psia) in the NACE standard, is achieved at relatively low H2Sconcentrations. Because of the lower temperatures, sour service tubulars areusually required at shallow depths. NACE requires the use of relatively low yieldsteel (eg L-80, C-90 or T-95 as specified in API 5CT) in these wells, in the upper(lower temperature) sections. In order to meet the burst design requirements, thismay require the use of thicker wall, non-standard tubulars. This can have an effecton the design due to annular clearance restrictions and lead to long delivery timesfor specialist casing sizes.

The need for gas-tight connections operating at high temperatures and differentialpressures requires careful consideration. Only suitably qualified connections thathave evidence to retain a gas-tight seal and connection should be used.

The effects of dimensional tolerances on casing performance also influencescasing selection. The required casing rating may be achieved by a tightening of themanufacturer’s API tolerances, rather than use non-standard casing. Reduction ofthe casing material yield strength at high temperatures requires down-rating asdiscussed within earlier sections, based on the anticipated downhole temperature.Several drilling liners may be required to allow deeper drilling, as the mud weightsrequired for high pore pressure transition zones may be close to the formationbreakdown gradient.


4.2.4.4 Deepwater

Deepwater wells present a number of issues for casing design; casing setting depthand environmental loads above the seabed.

First, these regions have lower fracture gradients than equivalent depths for land, oroffshore wells in shallow water. As the water depth increases, fracture gradients aresignificantly different (weaker) particularly in the shallow sections of the well. Selectionof the casing setting depths should take the reduced fracture gradients into account.

Secondly, wave and current loads can result in direct and indirect loads on the marineconductor and subsea wellhead system. Fatigue loads from these conditions should beassessed.

Cementation of the conductor to the seabed and centralisation should take intoaccount the transfer of loads between the conductor and surface casing.

There is a tendency for surface formations to show fluid tendencies and as a resultdrilling/driving of the conductor/surface casing may be required.

4.2.4.5 Injection

Injection includes a number of areas to consider for well design; development wells,DST activities and cuttings re-injection of mud slurries into casing annuli:

a. Injection Wells

For development wells the maximum injection pressures anticipated assumingbridging should be considered, as the surface equipment will experience thehighest loads.

Consideration should be given to annular pressures and stresses on the casing,due to initial start-up injection with cold liquids.

Some formations may require consideration for injection wells on a developmentwhere cross-flow, communication, or recharging could occur on surrounding wells.

b. DST Activities

Exploration wells should consider maximum pressures required to operate DSTtools, tubing conveyed perforating systems and maximum pressures required forbull-heading down the string as part of the well kill.

c. Cuttings Re-injection

This is a mechanism of disposing of the oily drilling cuttings generated ondevelopment wells, in terms of satisfying environmental legislation.

The design of casing strings that are to be utilised as cuttings re-injection routesmust take into account all of the anticipated combinations of temperature,pressures and erosion that the annulus may encounter during its operational life.Typically, this may have an impact on the design of the intermediate and productioncasings.


4.2.4.6 Gas Lift

Casing designs for gas-lift completions are based on different design loads fromstandard wells. They should be treated differently from standard wells in two respects:

� Definition of the possible pressure profiles within the ‘live’ tubing/production casingannulus (‘A’ Annulus)

� Design of the intermediate casing to withstand the consequence of a leak in theproduction casing for subsea wells

Pressure profiles for the production phase in the ‘A’ annulus should therefore beconsidered for:

� Kick-off zone (casing wear)

� Gas lift

� Closed in and assuming a leaking gas lift valve (burst issue)

� Evacuation to un-pressured injection gas (collapse issue)

4.2.4.7 Stimulation

Casing design for stimulation (fracture, acids) needs to be considered in terms ofadditional burst loads, axial loads and corrosion. In particular, fracture stimulationscreen-out leading to excessive pressures on the wellbore and the potential breakdownof formations at the weak point.

4.2.4.8 Mobile Formations

When hole sections are drilled through plastic, mobile salt formations, the saltgradually moves and can make contact with the casing. Problems due to salt plasticitycan be major for casing strings run through a salt formation, especiallyafter installation.

In most sedimentary rocks it is unusual for the formation pressures to equal theoverburden due to the element of support provided by the grain to grain contact withinthe rock matrix. However, the homogeneous crystalline nature of salt coupled with itsplastic properties, allows the material to transmit lateral loads equivalent to theoverburden pressure.

These can take the form of non-uniformly, or uniformly distributed loads. The effects ofthese are different and tend to result from different rates of salt movement:


a. Non-uniform

Caused by washed-out hole sections and/or unevenly cemented casing annuli. Thiswill cause one side of the casing to be exposed to the full overburden gradient,while the other side is completely unsupported. This type of point loading results inhigh shear stresses, which can cause casing failure at much lower loads than whenapplied uniformly. It is possible (even if the casing does not collapse immediately),that it may start to bend into the washed out section opposite. The resultingincrease in axial stress on one side of the casing may lead to a reduced collapsepressure, or fail due to the bending stresses alone.

b. Uniform

This is a result of the salt transmitting the overburden pressure in a completeuniform manner (ie 360�) over a considerable length of the casing. This can beeffectively modelled by substituting the overburden pressure at any depth for thehydrostatic pressure. The most important criteria to reduce collapse loading on asalt section is to minimise hole enlargement during drilling and successfullycomplete the cementation with a concentric uniform sheath. This will assist indistributing the collapse load in a uniform manner.

The salt loads can induce an external pressure load equal to the formationoverburden pressure (or 1psi/ft if the pressure data is not well defined). As a result,the collapse loads, whether designing for full, or partial evacuation, will beextremely high.

The phenomenon is time dependent, such that during the drilling phase, increasedexternal loading due to the moving salt may be small. However, for a developmentwell during production, salt loading may be quite significant.

Following this, casing should be designed to withstand a concentrically uniformpressure, equivalent to the overburden pressure at the depth of the salt formation.

4.2.4.9 Steam

Casing in conventional wells is designed to resist burst, collapse, tensile andcompressive loads within the elastic range of the casing material.

However, the design of steam wells is complicated as the axial stress can exceed theyield strength in compression during heating and/or exceeds the yield strength intension during subsequent cooling. This can lead to cyclic stresses and ultimatelyfatigue failure. Thus the design needs to consider post yield behaviour of both casingand connections.

Computer simulations should form part of the design for such wells in terms of the axialloads, cementation tops, collapse loads, burst loads, temperature yield strengthreduction and selection of qualified connectors.


4.2.4.10 Reservoir Compaction

Production of the reservoir fluids will eventually lead to a partial reduction in reservoirpore pressure if the pressure is not fully maintained by a drive mechanism. Theresulting increase in effective stress leads to reservoir compaction and deformation ofthe overburden.

The vertical strain caused by compaction of the producing interval is transferred to acertain extent to the casing string(s) set across that interval. The casing will undergoaxial deformation and in deviated wells, lateral deformation such as bending,ovalisation or crushing. These lateral loads are comparable in type to squeezing saltformations but less in magnitude and severity. Excessive overburden deformation canlead to localised slip across faults and bedding planes, leading to a shearing ofthe casing.

Such issues if anticipated in a field, may require the co-operation and the analysis bygeotechnical and structural engineering specialists.

4.2.4.11 Horizontal/High Angle

Horizontal wells include high angle wells and multi-lateral wells that branch off the mainhost well.

For the horizontal section, the stability of the formation must be determined, in order toassess if the casing has to withstand full overburden formation pressure. This is thenlinked to the casing loads and casing selection for collapse.

For short radius buildup sections, bending stresses can be significant. For particularlyhigh build rates, localised bending stress concentrations can occur near casingcouplings due to the difference in outer diameter of casing and coupling. All casingsthat pass through high doglegs must be designed to withstand the bending stressesgenerated.

Due to high contact forces between casing and borehole wall in highly deviatedsections of the well, dynamic drag and torque loads will be high. Drag loads may besuch that once the casing string passes a given depth, the total axial force required topull the string upwards exceeds the axial capacity of the pipe. Therefore drag, torqueand wellbore profile may have an influence on the approach to the casing design.

Liners set in horizontal sections are often pre-drilled, or slotted to avoid the need forcomplicated perforating operations. The reduction in axial capacity (and various holingpatterns configuration) will need to be considered. This can be achieved by calculatingthe stress concentration factor that results from the presence of the hole andcomparing the resulting stress with the casing material yield stress.

4.2.4.12 Corrosion

The characteristics and chemistry of the formation fluids, water levels andtemperatures should be considered, to ensure that corrosion problems will not occurduring the life of the well.


4.2.5 Contingencies

Casing design should consider the well on a life cycle basis, not just on initial use butanticipated use and alternative loads. This should take into account modifications thatmay occur as part of the well design and unplanned incidents, due to operationalconstraints.

4.2.5.1 Sidetrack(s)

All well designs should consider if it is robust to accept the load conditions for asidetrack, whether it is a vertical exploration, or high angle development well. Theassumptions and potential pressure regimes should be checked to ensure the designis fit for purpose for all anticipated loads. This will provide flexibility and assurance interms of technical, safety and commercial requirements, for the overall well plan.

Sidetrack scenarios may be planned as part of the casing design eg multi-laterals,multi-objective exploration wells, or assessing a development plan for future access tohydrocarbon pockets. This will have an impact on directional well profiles, torque/draganalysis, casing seat optimisation, review of casing weights/grades and ultimate holesize for drilling.

Well deepening sidetracks may also occur as a well re-entry to a new objective from anexisting well. This could be a new target objective, or pressure regime.

Unplanned sidetracks due to operational problems will require re-assessment duringthe drilling phase eg to check that buckling, or deepening does not become an issue.

4.2.5.2 Well Deepening During Drilling

Geological prognosis are only approximations based on offset data and seismicsurveys. Consequently there is a degree of variance in the depth at which anexploration well will be terminated.

This has an impact in terms of well design, as the operating envelope for the originaldesign may change; in terms of pressure (high/low), temperature, loss zones,secondary reservoir objectives, or absence of geological formations.

It is important for the Drilling Engineer to discuss depth confidence with thegeophysicist and geologist. In some situations depth masking can occur (salts/carbonates/unconformities) which makes depth estimation difficult and can demandlarge casing design contingencies.


4.2.5.3 Well Conversions

During its life cycle a well may be changed to an alternative use. The well designerneeds to ensure that the operating envelope addresses such scenarios at the WellSpecification Sheet stage.

Examples of well conversions are:

� Artificial lift ESP to gas lift

� Producer to water injector

� Gas injector to gas producer

� Water injection to cuttings re-injection

� Suspended well to producer eg subsea tieback to platform

The Well Design Data Summary Chart shown in Section 4.4 is a schematic for theDrilling Engineer. Its purpose is to bring together all of the data collated from the PDDPon a single template. It acts as a formal document for the well designer. It must besigned off by: the Geological and Geophysical, and Drilling teams.

4.3 WELL DESIGN CHECKLIST

When the entire well design process is complete (not just the casing design) the designprocess should be documented on the Well Design Checklist shown in Section 2.6 ofthe Well Design Manual.

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......./......./.......



SECTION 5 CASING SEAT SELECTION Page 1 of 13

TABLE OF CONTENTS

5. CASING SEAT SELECTION.................................................................................. 2

5.1 KICK TOLER ANCE ......................................................................................... 2

5.1.1 Concepts .................................................................................................... 2

5.1.2 Design Requirements ................................................................................. 2

5.1.3 Kick Tolerance Requirements..................................................................... 4

5.1.4 Kick Tolerance Calculations ....................................................................... 4

5.1.5 Rig/Well Types ........................................................................................... 4

5.1.6 How to Calculate Kick Tolerance................................................................ 5

5.2 CASING SETTING DEPTHS............................................................................ 8

5.2.1 Principles.................................................................................................... 8

5.2.2 Bottom Up/Top Down ................................................................................. 8

5.2.3 Setting Depth Guidelines ............................................................................ 9

5.2.4 Additional Considerations ......................................................................... 10

5.2.5 Provisional Setting Depths........................................................................ 11

5.2.6 Casing Setting Depth Summary................................................................ 13

CASING SEAT SELECTION Page 2 of 13

5. CASING SEAT SELECTION

5.1 KICK TOLERANCE

5.1.1 Concepts

The concept of kick tolerance and its detailed application are covered in the WellControl Manual and will not be covered here in detail in the Casing Design Manual.However, the basic kick tolerance equation, its use relative to casing design and why itrequires regular calculation, are summarised within this document.

In terms of casing design, kick tolerance is an estimate of the volume of a gas influxat bottom hole conditions that can safely be shut in and circulated out of the well.Unless ample data is available to support an alternative gas gradient based on gascomposition data from a known area, a gas gradient of 0.1psi/ft should be used downto 10,000ft true vertical depth (TVD). Thereafter, use 0.15psi/ft to the total depth.

5.1.2 Design Requirements

For casing design setting depth requirements in most cases, the maximum pressurethat the casing shoe will be exposed to will occur when the top of the gas influxreaches the shoe depth. Gas is used as the influx criterion, as it represents theworst scenario for casing design safety. For example, gas caps in a reservoir andgas condensate.

The initial setting depth assessment will determine if the well is able to take a minimumof a 100bbl limited gas kick displacement for the production hole section and for theintermediate and surface casing strings.

There may be circumstances however, where intermediate and surface casings canjustify an influx gradient that is not a dry gas, for a known, non hydrocarbon-bearingzone. This will require rigorous assessment, detailed local offset data and adispensation by the appropriate drilling management, in order to adopt this approachfor the principle of casing design setting depths.


Thus for design purposes, the criteria should in principle, be based on:

� Production Hole Section: Ability to shut in and circulate out aminimum 100bbl limited gas kick back tothe previous shoe.

� Intermediate String Hole Section: Ability to shut in and circulate out aminimum 100bbl limited gas kick back tothe previous shoe.

� Surface Casing: Ability to shut in and circulate out aminimum 100bbl limited gas kick (if BOPequipment installed). These criteria maybe relaxed where it is known that thereare no hydrocarbons and the surfacestring is set in a competent formation.

� Conductor Casing: No well control equipment installed, notdeemed as a pressure vessel.

The worst design scenario occurs when there is no trip margin (mud weight balancesformation pore pressure). Therefore the kick tolerance is calculated, based on theprovisional setting depth.

If the criteria for a 100bbl gas kick tolerance proves to be too onerous (ie resulting inexcessive number of casing strings with short hole sections), consideration will have tobe given to obtaining the appropriate written dispensation for the casing design. Thistype of policy relaxation may be required on wells that are prognosed to encounterabnormal pressures with a rapid change in pore pressure over a relatively shorttransition zone (eg high pressure, high temperature (HPHT) wells). If a lower kicktolerance is used, all relevant programmes, procedures and meetings should recordand highlight this information.

One of the basic objectives of casing design is to ensure the casing is strongerthan the open hole formations. In a well control situation, it is better to have anopen hole formation failure/underground blowout, than to have a casing failure andsurface blowout.

It should be noted that kick tolerances that are acceptable for casing seat selection(under the limited kick criteria) are not an acceptable basis for mechanical burstdesign; ie the casing string must always be stronger than the maximum anticipatedpressures at the casing shoe, while circulating out a gas influx. However, there may becircumstances where this is not possible eg in granite/dolomite formations.


5.1.3 Kick Tolerance Requirements

The kick tolerance within a well must be constantly re-evaluated as the well is drilled. Itis not acceptable to calculate the kick tolerance purely at the design stage, or at thecurrent position in a well while drilling. It should also be calculated for conditions thatare anticipated, as the hole section is drilled.

The following summarises when the kick tolerance should be calculated:

� After a leak off test (LOT) and throughout the hole section, calculate the kicktolerance for a range of likely mud weights and pore pressures and plot on a graphto check impact and sensitivity on kick tolerance size

� For hole sections containing rapid pore pressure increases, at intervals across thearea of increasing pressure

� When there are changes within the wellbore, such as mud weight that may affectthe kick tolerance as the hole section is drilled

� When there are changes in the bottom hole assembly (BHA) configuration, theyshould be plotted for various BHA lengths to check how sensitive they are to thekick tolerance

5.1.4 Kick Tolerance Calculations

When calculating a kick tolerance during design or drilling conditions, the DrillingEngineer should check whether the worst condition is at initial shut in, or with theexpanded circulated influx beneath the identified weak point. For most cases this willgenerally be the casing shoe. However, there may be a weaker zone at a depthbeneath the casing shoe; this would then dominate the design (eg weaker permeablenon hydrocarbon-bearing sandstone).

In calculating the kick tolerance requirements, the designer should consider:

� Additional pressures caused by displacing the influx from the wellbore

� The maximum allowable pressure at the open hole weak point

� The safety margin to be utilised on the fracture gradient/LOT data for thecasing design

5.1.5 Rig/Well Types

Kick tolerance criteria and volumes for casing design will be influenced by the type ofwell and the rig type to be used. For example, a normally pressured development landwell may allow a lower kick tolerance design criteria. Whereas HPHT wells may requiredispensation for a reduced kick tolerance, due to the close margin between porepressure and fracture gradients. Attention should also be drawn to the variance of rigcrew capability with respect to shutting in the well, when considering reduced kicktolerance criteria.


5.1.6 How to Calculate Kick Tolerance

Outlined below is a summary of how the kick tolerance equations should be used forcasing design and for checking that the casing string remains fit for purpose during thedrilling of the well.

This assumes the provisional initial casing setting depths have been selected forthe well.

1. Determine the safety margin to be applied to the LOT or leak off pressure, at theidentified open hole weak point.

The safety margin will include back pressure during well control circulation from:annular friction, errors and choke line losses. The values used will requireassessment by the Drilling Engineer, to determine the total safety margin to besubtracted from the leak off pressure at the open hole weak point.

Pmax = Pleakoff – Pannular losses – Pchoke line losses – Pchoke error

2. Determine the maximum allowable static weak point pressure.

The safety margin is subtracted from the weak point pressure and provides themaximum weak point pressure allowed prior to circulation.

Pmax = Plo – the safety margin (psi).

Pmax = Maximum allowable pressure at weak point (psi).

Plo = Actual leak off pressure at open hole weak point (psi)(measured or estimated).

3. Calculate the maximum allowable height of influx in open hole.

gg)MW052.0(

052.0MWDTD)PP(H

wpfmax

��

��

�

��

�

�

� �

��

�

Where:

H = height of influx (ft)

Pmax = maximum allowable pressure at open hole weak point (psi)

MW = mud weight in hole (ppg)

gg = gas gradient (psi/ft)

TD = bit depth (ft)

Pf = formation pressure at TD (psi)

Dwp = depth of shoe or weak point (ft)

Note : All depths are vertical depths at this stage.


4. Calculate Volume that height corresponds to at initial shut-in conditions.

Note: If the well is deviated, the H calculated in 3. above must be converted to anactual measured or along-hole depth at the influx point.

At initial shut-in this equates to an influx volume of:

V1 = H x C1 (bbl)

Where:

V1 = kick tolerance for initial influx (bbl)

C1 = annular capacity at BHA (bbl/ft)

Note: C1 must be determined based on the various dimensions of the BHA and ifH > than the BHA, ie take into account capacity of drillpipe/open hole anddrill collar/open hole.

5. Calculate the volume that this height corresponds to when the top of influx iscirculated to the open hole weak point. Again, for a deviated well, convert theH value in 3. above to an actual measured or along-hole depth at the open holeweak point.

Vwp = H x C2 (bbl)

Where:

Vwp = kick tolerance at weak point (bbl)

C2 = annular capacity below weak point (bbl/ft)

Note: C2 must be determined based on the hole dimensions immediately belowthe open hole weak point, relative to height of influx.

6. Calculate what Vwp (as calculated in step 5) would be at the initial shut-inconditions.

Using Boyle’s Law to convert this volume to its original volume at initialshut-in conditions:

P1 x V1 = P2 x V2 or in this case:

Pf x V2 = Pmax x Vwp

V2 =f

wpmax

P

VP �


7. The kick tolerance to use is the lower value of V1 and V2.

An example of how the kick tolerance calculation is used for well design isoutlined below, assuming a vertical well:

Bit depth: 13,000ft

Estimated pore pressure at 13,000ft and MW: 13.2ppg

Last casing shoe: 8,800ft

Leak off test EMW: 14.3ppg at shoe

Current hole size: 12-1/4in

BHA length/OD 600ft/8in

Annulus backpressure: 70psi

Safety margin for choke operations error: 150psi

Gas Gradient: 0.1psi/ft

footperbbls4.1029PipeODHoleDiam

CapacityAnnular22

��

a. Estimate safety margin to be applied to leak off pressure at open-holeweak point.

Total safety margin on leak off = 70 + 150 = 220psi

b. Calculate maximum allowable static weak point pressure (Pmax)

Maximum allowable static pressure at casing shoe:

Pmax = (14.3 x 8800 x 0.052) – 220= 6324psi= 13.82ppg EMW

Formation pressure at bit depth:

Pf = 13000 x 13.2 x 0.052 = 8923psi

c. Calculate maximum allowable height of influx in open hole section.

� � � ��

ft1052.02.13

052.02.1388001300089236324H

��

��

H = 484ft

d. Calculate the volume that height corresponds to above the bit depth.

V1 = 484 x 0.08361 (bbl)= 40.5bbl


e. Calculate volume that this height corresponds to when top of influx at open holeweak point.

Vwp = 484 x 0.12149 (bbl)= 58.8bbl

f. Calculate what this volume would be at initial shut-in conditions.

bbl67.418923

8.586324V2 �

��

Therefore, the kick tolerance is V1 (40.5bbl) as this is the lower of the two calculatedvalues V1 and V2.

5.2 CASING SETTING DEPTHS

5.2.1 Principles

The purpose of casing seat selection is to achieve the well target(s), safely with theoptimum number of casing and liner strings. The minimum casing shoe setting depthsare driven by many considerations, which are summarised within this section. Theprimary consideration is to prevent failure of the formation below the casing shoe andto ensure the open hole section remains intact for all of the anticipated load conditions.

5.2.2 Bottom Up/Top Do wn

The selection of casing setting depths is based on the anticipated pore pressure andthe fracture gradient profiles. The Drilling Engineer should ensure that the offset datahas been taken into consideration for the final estimation of the pore and fracturegradients, including reduction in fracture strength as a result of the hole angle (forexample: high angle or horizontal wells).

The final depth of the well and setting depth of the production casing or liner, is drivenby the requirements for logging, testing and completion design. The casing shoe mustbe set deep enough to give an adequate sump for running casing, logging, perforatingand testing activities. Hence, the philosophy of starting from the bottom up, withdefinition of a minimum hole/casing size.

Why is it necessary to start an initial casing setting depth selection from the bottom up?This is to allow the next hole section to be drilled to total depth (TD) with the maximummud weight required (including overbalance and equivalent circulating density (ECD))without breaking down the formation at the previous casing shoe.

Figure 5.1 describes a graphical schematic for generating the initial setting depths.


Figure 5.1 - Initial Casing Setting Depths

0

1 0 00

2 0 00

3 0 00

4 0 00

5 0 00

6 0 00

7 0 00

8 0 00

9 0 00

1 00 0 0

1 10 0 0

1 20 0 0

8 1 0 1 2 1 4 1 6 1 8 2 0

D

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In te rm ediateC asing

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F rac tu reG rad ien t

Design F rac tu reGradient Including K ickand Cem en ting M arg in

Mud W eightCurve

P ore PressureG rad ien t

Equivalent Mud Weight, ppg

Tru

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ertic

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epth

(T

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No

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5.2.3 Setting Depth Guidelines

The process for estimating the initial casing shoe setting depths requires thepreparation of the pore pressure and fracture gradient profiles by the following method:

� First draw the mean pore pressure and anticipated fracture gradient profiles on achart with TVD in feet, versus the equivalent mud weight (EMW) in ppg. If possible,draw the curve against a geological column and include intervals which may causepotential problems such as shallow gas zones, differential sticking, loss zones,overpressured zones, depleted zones, hole stability, aquifers and mobile salt zones

� Next draw the mud weight curve. This should include the mud weight trip margin;the value of this trip margin will be based on the overbalance and riser margin foroffshore mobile rigs. Be aware that the maximum mud weight required may not befor pore pressure requirements, but borehole stability considerations

� Then draw a design fracture gradient. This should include a reduction to take intoaccount the requirements for well control and ECD during drilling and cementing

� Include if relevant, offset mud weights and LOT data from the pre-drilling data packon a separate profile chart, to provide a check of the pore pressure/fracturegradient predictions


Once the pore pressure, fracture gradient and mud weight curves are drawn, proceedto the next stage of the process:

� Enter the highest mud weight required at TD Point A

� Draw a vertical line up to Point B ; this determines the initial estimated setting depthfor the production casing, in order to drill the hole to TD

� Next move across to Point C ; this identifies the maximum mud weight allowed forthe production casing setting depth

� Draw a vertical line up to Point D ; this determines the setting depth for theintermediate casing

� Next, move across to Point E ; this determines the maximum mud weight allowedfor the intermediate casing

This process is repeated for all of the remaining casing strings. However, the conductoris the exception, this is based on the shallowest setting depth at which bottom holepressure created by the mud being circulated (ECD) during the drilling of the nextsection, is equal to the fracture pressure of the formation.

5.2.4 Additional Considerations

In practice, a number of other factors are taken into consideration when picking theoptimum casing shoes for a well. These include:

� Shallow Gas Zones: The well may be drilled riserless from a semi-submersible untilthrough the zone of seismic uncertainty, or the surface casing may be set slightlyshallower to allow the installation of a blowout preventer (BOP) system prior todrilling the seismic uncertainty (subject to fracture strength at the proposed shoe)

� Lost Circulation/Weak Zones: May require isolation prior to entering a higherpressure formation, such as limestones and dolomites with a weak fracture gradientand/or vugular void loss zones. This also includes depleted hydrocarbon zones,where losses are anticipated when drilling into the reservoir

� Differential Sticking: Zones such as a porous, non hydrocarbon-bearing sandstonewith a weak fracture gradient may require isolation due to increased differentialpressure between formation and wellbore with high mud weights. High formationpermeabilities and increasing fluid loss, or thicker mud cakes can worsen thesituation

� Formation Hole Stability: Formations with reactive/unstable shales which may besensitive to exposure time, mud weight, deviation and stress at the wellbore wall,react with some mud systems

� Overpressured Zones: Formations with a rapid increase in pore pressure such astransition zones in high pressure wells may require isolation, prior to drilling into theoverpressured transition zone


� Aquifers: Regulatory legislation may require isolation of shallow fresh water sands(drinking water) to prevent contamination

� Mobile Salt Sections: May require a casing shoe at, or prior to entering a salt zone

� Cement Tops: The top of cement depths for each casing should be defined, as thisinfluences the axial loads and external pressure profiles used during detaileddesign. There may also be regulatory requirements for zonal isolation

5.2.5 Provisional Setting Depths

Once all of the above issues have been taken into consideration with the initial ‘quicklook’ casing setting depths, redefine the casing shoes to ensure that they are set incompetent formations. This should also take into account the uncertainty (error bars) inthe depth of the formation, when setting a casing shoe close to a permeable formation.If the kick tolerance design criteria is unable to be achieved after detailed review,dispensation may be required subject to evaluation of the risks and consequence of aninflux occurring.

The next stage is to determine the kick tolerance associated with each respectivecasing shoe. Start from TD up to the surface string to determine the kick tolerance andpreferred setting depth for each casing. A series of iterations and adjustments may berequired in order to come up with the optimum casing shoe, with the correct kicktolerance in a competent formation.

For the conductor, the setting depth should provide sufficient strength at the shoe toallow circulation of the heaviest anticipated mud weight for the next hole section, andsupport the loads from the wellhead, BOP and additional casing strings. This assumesno hydrocarbons are present in the next interval and should take into consideration themaximum mud weight, ECD and additional density due to cuttings in the annulus.

A schematic outlining the method for determining the minimum setting depth for aconductor is shown overleaf in Figure 5.2.

This can be illustrated by an example with a jack-up or platform, where the rotary table(RT) is a significant height from the mean sea level (MSL). The fracture pressure is lowas the seawater column dominates it. Whereas, the mud pressure is high, due to thelength of the mud hydrostatic column and the additional ECD from high rates ofpenetration (ROPs) and cuttings loading. This results in a minimum setting depth thatis so deep, that it cannot be achieved due to hole problems, or the small windowbetween fracture pressure and the mud ECD. One common solution is to insert a holein the conductor just above MSL and take returns to the sea at this level. This reducesthe mud hydrostatic column in the riser. The ROP is also restricted to reduce theimpact of cuttings loading on the mud ECD. The Engineer should re-plot the conductorsetting depth diagram for this scenario, to assess the impact.


Figure 5.2 - Minimum Setting Depth for Conductor

SeaBed

M ea n Sea Leve l

D a tum - R ota ry T ab le

Sea W a ter G ra d ien t

F ractu reG rad ien t

E ffec tive M ud G ra d ien t (N ext ho le section )(EC D + F lu id D en sity due to M W and d rilled so lids)

M inimum C asing Se tting D ep th(W here the fracture gra dien t is e qua lto the effe ctive mu d density fo r the

next section )

P ressure

0

Dep

th (

Bel

ow R

otar

y T

able

- B

RT

)

Additionally, lost circulation below a conductor shoe can be potentially dangerousdue to:

� Possible wash out of the conductor at the shoe and within the annulus, causingbroaching to surface, thus losing its foundation strength

� Wash out and broaching to surface within the conductor annulus, thusde-stabilising the seabed (JU leg problems, platform piles etc)

� Broaching across to an adjacent conductor and losing conductor support onproducing, or completed wells


5.2.6 Casing Setting Depth Summary

To summarise, the complete casing setting depth process can be listed as:

� Define well objectives through the PDPP

� Research and prepare the offset data, as part of the PDPP

� Capture all of the key data on a well design data summary sheet

� Draw the pore pressure, fracture gradient and mud weight profiles on a schematic.Include safety margins on pore and fracture curves for trip, ECD and kick margins

� Perform a quick look bottom up casing setting depth analysis, based on maximummud weights anticipated for each hole section

� Revise the setting depths for each casing, ensuring the additional considerationsare catered for; including a competent formation for the casing shoe

� Calculate kick tolerances for each casing shoe and hole section based on the kicktolerance criteria. If required, redefine each casing shoe to satisfy kick tolerances

Define the conductor setting depth by checking that the maximum pressure exerted bythe mud for the next hole section, is less than the fracture pressure of the formations.



SECTION 6 MECHANICAL DESIGN Page 1 of 60

TABLE OF CONTENTS

6. MECHANICAL DESIGN......................................................................................... 3

6.1 BACKGROUND ............................................................................................... 3

6.2 DEFINITIONS................................................................................................... 4

6.2.1 Burst (Internal Yield)................................................................................... 4

6.2.2 Collapse ..................................................................................................... 4

6.2.3 Tensile (Axial)............................................................................................. 4

6.2.4 Compression .............................................................................................. 5

6.2.5 Biaxial (Combined Loads)........................................................................... 5

6.2.6 Joint Strength ............................................................................................. 5

6.3 FORMULAE AND CALCULATIONS................................................................ 6

6.3.1 Burst (Internal Yield Pressure).................................................................... 6

6.3.2 Collapse ..................................................................................................... 7

6.3.2.1 Yield Strength Collapse ............................................................................. 9

6.3.2.2 Plastic Collapse ......................................................................................... 9

6.3.2.3 Transition Collapse .................................................................................. 10

6.3.2.4 Elastic Collapse ....................................................................................... 10

6.3.2.5 Collapse Pressure under Axial Tension Stress ........................................ 11

6.3.2.6 Constants for Collapse Equations ............................................................ 11

6.3.2.7 Critical D/t Ratios for Collapse Equations................................................. 12

6.3.2.8 Procedure for Collapse Strength under Axial Tension.............................. 13

6.3.2.9 Collapse: Combined Effect of Internal and External Pressure .................. 13

6.3.3 Tensile (Axial)........................................................................................... 14

6.3.4 Joint Strength (Connectors)...................................................................... 15

6.3.5 Buckling.................................................................................................... 15

6.4 REPSOL MINIMUM DESIGN FACTORS.......................................................... 15

6.4.1 Burst Design Factor ................................................................................... 16

6.4.2 Collapse Design Factor ............................................................................. 16

6.4.3 Tension Design Factor............................................................................... 16

6.4.4 Compression Design Factor ...................................................................... 17

MECHANICAL DESIGN Page 2 of 60

6.4.5 Triaxial Design Factor ................................................................................ 17

6.4.6 Design Factor Summary ............................................................................ 17

6.5 MINIMUM DESIGN FACTORS ......................................................................... 18

6.5.1 Conductor................................................................................................. 18

6.5.2 Surface Casing......................................................................................... 19

6.5.3 Intermediate Casing/Liners....................................................................... 20

6.5.4 Production Casing/Liners.......................................................................... 22

6.5.5 Design Factor Information ........................................................................ 24

6.5.5.1 Liner Laps................................................................................................ 24

6.5.5.2 Load Criteria: General Notes.................................................................... 25

6.5.6 Special Load Cases................................................................................... 26

6.5.6.1 Mobile Salts (Collapse) ............................................................................ 26

6.5.6.2 Annular Fluid Expansion .......................................................................... 26

6.5.6.3 Thermal Loads and Temperature Effects ................................................. 29

6.5.6.4 Buckling ................................................................................................... 30

6.5.7 Design Load Definitions ............................................................................. 34

6.5.7.1 Tension.................................................................................................... 34

6.5.7.2 Burst ........................................................................................................ 38

6.5.7.3 Collapse................................................................................................... 54


6. MECHANICAL DESIGN

6.1 BACKGROUND

The mechanical design of a well is a three-part puzzle that consists of the following:

� The external, internal and axial loads on the casing (data and assumptions)

� The load cases for installation, drilling and service

� The Repsol casing design factors

The basis of this section will be written for an API analysis for single stress effects andso will not include information, or calculations, on a triaxial analysis for combinedstress effects.

The standards applicable to Mechanical Casing Design for this section are thus:

� API 5CT Latest Edition, Specification for Casing and Tubing

� API Bulletin 5C3, Latest Edition, Formulae and Calculations for Casing, Tubing,Drillpipe, and Line Pipe Properties

� API Bulletin 5C2, Latest Edition, Performance Properties of Casing, Tubing andDrillpipe

In order to describe a mechanical design, the criteria will be summarised from theabove API documents only. However, the detailed listing of all the relevant standards,codes and guidelines are contained within Section 11. The use of biaxial effects as aresult of axial tension will be explained relative to the API specification.

Biaxial effects should typically be used for wells that are:

� Depth > 12,000ft

� High mud weights (eg > 14ppg)

� High dogleg severity (bending, eg > 8�/100ft)

Individually, these depth, mud weight and dogleg severity figures are a useful guidelineto the need for a biaxial stress analysis. The casing designer must consider theparticular stresses to be encountered. If these, either singly or in combination,approach the guideline figures then biaxial analysis should be applied.

The biaxial adjustment of the collapse resistance due to the application of axial(tensile) loads is typically performed by computer software. Generally, wells thatfall within these criteria are validated by a triaxial analysis, via a computersoftware package.


6.2 DEFINITIONS

To perform a mechanical design of a casing string, we need to know the minimumrequired strength of the pipe for the anticipated load conditions. We then calculatethe optimum mechanical properties of the casing. For a uniaxial design the strengthof the pipe includes:

� Burst (Internal Yield)

� Collapse (Pipe Body)

� Tensile (Axial)

� Biaxial (Collapse and Tension)

� Joint Strength (Primarily Axial)

6.2.1 Burst (Internal Yield)

If a casing string is subjected to an internal pressure that is greater than the externalpressure, the casing is exposed to a burst pressure . This is the normal condition andis only a concern if the burst pressure exceeds yield limits. This can be caused by wellcontrol incidents, pressure tests and stimulation or squeeze cementing operations.

6.2.2 Collapse

If a casing string is subjected to an external pressure that is greater than an internalpressure, the casing is exposed to a collapse pressure . This can occur due to loss ofhydrostatic pressure inside the casing (well evacuation), excessive increase in externalpressure outside the casing (cementing) or mechanical loads such as mobile saltformations.

6.2.3 Tensile (Axial)

If a casing string is subjected to an axial load or pull that is greater than the tensilerating of either the pipe body or of the connection, failure may take place. This canoccur as a result of excessive string length, pulling of stuck pipe, thermal contraction orpressure testing.


6.2.4 Compression

If a casing string is subjected to a compressive axial load or push that is greater thanthe elastic limit of the pipe body, failure can take place. This may be due to thermalexpansion, excessive dogleg severity and excessive set-down weight during running.

A casing string design needs to consider two aspects for compression, or buckling:

a. If a casing string is subjected to thermal or pressure loads, the initial configurationmay become unstable. The casing, confined within the open hole or casing, maydeform into a second stable configuration, usually helical or coil (in a vertical hole)or ‘S’ shaped (in a deviated hole). This is acceptable, provided that it remains inthe elastic phase and does not create subsequent drillstring, tubular orcompletion tool access problems. However, if this becomes a frequent cyclic load,it can induce high stresses and fatigue.

b. If a casing string is subjected to loads as described above but enters the plasticphase due to a high local dogleg, the configuration may remain unstable, leadingto a stress concentration factor at the dogleg, potentially leading on to cyclicstresses and ultimately fatigue failure.

6.2.5 Biaxial (Combined Loads)

This is based on combined collapse and tension. If a casing is subjected to acombination of an external pressure plus axial load that is greater than the adjustedtensile rating of the pipe body or connection, failure can occur at lower load conditionsthan from either factor separately. The collapse regime may change on application ofan axial load as the Diameter/Wall Thickness constants (D/t) may change. Thus as thetensile load increases for the pipe, the resistance to collapse pressure decreases.The biaxial effect becomes more important for long casing strings, high mud weightsand high dogleg severity.

6.2.6 Joint Strength

If a casing connection is subjected to a load(s) that is/are greater than the axial tensionor compression rating of the connection, failure can occur. Additionally, if the internalyield pressure (burst) is greater than the burst rating of the connection, failure canoccur. API Specification 5B discusses the dimensional requirements for APIconnections. API Bulletin 5C2 discusses the mechanical properties of not only the pipebody, but also the API connections for internal yield pressure (burst) and joint strength.

The majority of casing failures occur at the connections. It is therefore important thatthe design checks both pipe body and connection for each string, to determine theweaker component of the design. For non-API connections, manufacturers shouldprovide all of the mechanical properties with the pipe data sheet, in order that thedesigner can confirm the connection is (if possible) ‘pipe body matched’.


6.3 FORMULAE AND CALCULATIONS

The formulae and calculations for an API design are contained within API 5C3,Formulae and Calculations for Casing, Tubing, Drillpipe and Line Pipe Properties.In order to perform a working stress mechanical design, it is necessary for the readerto understand the basic principles of the formulae used and how they are applied.

6.3.1 Burst (Internal Yield Pressure)

The API burst rating can be determined from the published tables of casing propertieswithin API Bulletin 5C2.

The internal yield pressure for plain end pipe is given by the API Bulletin 5C3 formula:

��

��

�

D

tY2875.0P p

Where:

P = Minimum Internal Yield Pressure (psi)

Yp = Specified Minimum Yield Strength (psi)

D = Nominal Outside Diameter (in)

t = Nominal Wall Thickness (in)

This is commonly known as the Barlow equation and calculates the internal pressure atwhich the tangential (or hoop) stress at the inner pipe wall reaches the yield strength ofthe material.

A burst failure will not actually occur until after the stress exceeds the ultimate tensilestrength (UTS). As a result, yield strength as a measure of burst strength is a generallyconservative assumption, particularly for lower yield materials.

The API burst pressure is based on internal pressure only, with zero external pressure.As the wellbore pressures increase, the use of the API rating becomes lessconservative, because the effect of radial compressive stresses at the inner wall isnot considered.

The factor 0.875 appearing in the equation above allows for the minimum wallthickness tolerance of -12.5% allowed on API for manufacture of the pipe. This valuecan be modified for special inspection requirements, for example if the wall tolerancehas been specified as 90% minimum wall thickness for a special material order (thiswould result in a higher burst rating for the pipe).


6.3.2 Collapse

The API collapse rating can be determined from the published tables within API Bulletin5C2, Performance Properties of Casing, Tubing and Drillpipe.

The following notes provide an overview of the approach to adopt for collapsepressure ratings.

However, the casing designer needs to check the mode of collapse (eg elastic,transition, plastic or yield) because if the failure mode is identified as elastic, the designmay be conservative.

If the failure mode is plastic, it will still be acceptable but the designer needs to beaware that some permanent deformation may take place. Figure 6.1 shows thestress/strain diagram with the elastic and yield limits.

Figure 6.1 - Stress/Strain Diagram

Collapse strength is primarily a function of the material’s yield strength and itsslenderness ratio, D/t. The collapse strength criteria within API Bulletin 5C3 consist offour collapse regimes that are determined on the basis of yield strength andslenderness ratio. For low D/t ratios, failure is governed by yield on the inner surface ofthe casing. For intermediate D/t ratios, collapse occurs by plastic instability. For highD/t ratios, it is governed by elastic instability. There is a fourth regime called transitioninstability, which is a fictitious mechanism linked to plastic collapse.

Proportional Limit(End of straight line, stressno longer proportional to

strain)

Elastic Limit(Point beyond which increasing

strain will lead to permanentdeformation)

Yield Point(Increase in strain gives

minimal increase in stress)

Ultimate Tensile Stress(Maximum stress

achieved)

STRAIN

ST

RE

SS


They are shown schematically in Figure 6.2 for Collapse Strength as a function of D/t.

Figure 6.2 - Collapse Strength

As explained within API 5C3, this is a pictorial representation of the four collapsemodes which are: elastic, transition, plastic and yield. The collapse of the material isnot only a function of the yield strength, but also depends upon the slenderness ratio(D/t). This is similar to the design of steel columns in general mechanical engineering,in which the failure mode is a function of the material, height and the width.

The Actual Collapse Behaviour (dotted line), is based on the empirical data from aseries of tests on K-55, N-80 and P-110 casing.

The Drilling Engineer must be aware of which collapse mode the pipe is likely toexperience in operation.

YP

Material Yield

Theoretical Elastic Instabil it y

Actual Colla p se Behaviour

Yield Stren g th Colla p sePlastic

Col la p seTransit ionColla p se

ElasticCol la p se

15+/- 25+/-

Slenderness Ratio, D/t

�� at ID


6.3.2.1 Yield Strength Collapse

This is based on yield at the inner wall using the Lame thick-wall elastic criteria. It doesnot represent a true ‘collapse’ pressure and represents a D/t ratio for thick-walledpipes < ±15. The tangential stress will exceed the yield strength of the materialbefore a collapse instability failure occurs. Nominal dimensions are used in thecollapse equations.

� ��

��

��

� 2pp t/D

1t/DY2PY

Where:

PYp = External Yield Pressure (psi)




6.3.2.2 Plastic Collapse

This is based on empirical data from a series of tests on K-55, N-80 and P-110seamless casing. No analytical expression has been derived that accurately modelscollapse behaviour in this regime. Regression analysis results in a 95% confidencelevel that 99.5% of all pipes manufactured to API specifications will fail at a collapsepressure higher than the plastic collapse pressure.

The D/t ranges for plastic collapse are listed within API Bulletin 5C3.

The minimum collapse pressure for the plastic range of collapse is calculated by thefollowing:

CBt/D

AYP Pp �

�

��

�

Where:

Pp = External Plastic Pressure (psi)




A, B and C are formula factors for various grades that are calculated from formulaelisted within API Bulletin 5C3.

It is worth noting that most oilfield tubulars generally experience collapse in the plasticand transition regimes.


6.3.2.3 Transition Collapse

This is obtained by a numerical curve fit between the plastic and elastic regimes.

The minimum collapse pressure for the plastic to elastic transition zone is given by:

��

��

� G

t/DF

YP pT

Where:

PT = External Transition Pressure (psi)



YP = Specified Minimum Yield Strength (psi)

F and G are formula factors for various grades that are calculated from formulae listedwithin API Bulletin 5C2.

The D/t ranges for transition collapse are listed within API Bulletin 5C3.

6.3.2.4 Elastic Collapse

This is based on theoretical elastic instability failure. This criterion is independent ofyield strength and applicable to thin wall pipe with a D/t ratio > 25±.

The minimum collapse pressure for the elastic range of collapse is given by:

� � � �� 2

6

E1t/Dt/D

1095.46P

�

Where:

PE = External Elastic Pressure (psi)



The D/t ranges for elastic collapse are listed within API Bulletin 5C3.

The elastic collapse regime should not be reduced due to axial tension loads (biaxialeffect). This is of particular note for large diameter casings. Elastic stability analysisshows that elastic collapse is unaffected by axial load (ie returns to natural condition,with no permanent deformation).


6.3.2.5 Collapse Pressure under Axial Tension Stress

For collapse the addition of axial tension to the casing has the same effect as reducingthe yield stress of the material, ie as the axial tension increases, the available collapsestrength reduces. This results in a modified yield strength (Ypa) of an axial stressequivalent grade. Thus the collapse resistance of casing in the presence of an axialstress is calculated by modifying the yield stress to an axial stress equivalent grade.

This is given by the equation from API Bulletin 5C3:

pp

a

2

p

apa Y

YS

5.0YS

75.01Y��

�

�

��

�

�

��

�

��

�

�

Where:

Sa = Axial Stress (psi) (Tension is positive)

Yp = Minimum Yield Strength of Pipe at zero load (psi)

Ypa = Yield Strength of Axial Stress equivalent grade(ie adjusted yield strength) (psi)

With the exception of elastic collapse, the collapse strength is directly proportional tothe yield strength of the material for transition, plastic and yield failure modes.

This equation is useful as it allows the engineer to determine, in conjunction with theother collapse equations, the reduced collapse strength of the casing under axialtension.

6.3.2.6 Constants for Collapse Equations

The constants A, B, C, F and G are calculated from formulae given in API 5C3as follows:

A = 2.8762 + 0.10679 x 10-5 Yp + 0.21301 x 10-10 Yp2 – 0.53132 x 10-16 YP

3

B = 0.026233 + 0.50609 x 10-6 YP

C = -465.93 + 0.030867 YP – 0.10483 x 10-7 YP2 + 0.36989 x 10-13 YP

3

� ��

� ��

� ��

2

P

3

6

AB2A

B31A

B

AB2A

B3Y

AB2A

B310x95.46

F

��

�

��

�

�

�

��

�

��

�

�

�

��

�

��

�

�

�

� �ABFG


6.3.2.7 Critical D/t Ratios for Collapse Equations

Calculate the critical ratios using the equations summarised below from API 5C3 usingthe appropriate collapse strength equation based on where the casing D/t ratio falls.

� � � �

��

�

��

�

��

��

�

��

�

��

�

��

�

P

P

2

YP

YC

B2

2AYC

B82A

tD

� �� GBYC

FAYtD

P

P

PT �

�

��

�

� �AB3

AB2

tD

TE

��

��

�

Where:

YPtD

�

��

�= intersection point Yield – Plastic

PTtD

�

��

�= intersection point Plastic – Transition

TEtD

�

��

�= intersection point Transition – Elastic


6.3.2.8 Procedure for Collapse Strength under Axial Tension

The summarised procedure for determining the collapse strength of the casing isas follows:

1. Estimate the real total tension or compression of the casing string at the point ofinterest. This is primarily the weight of the casing in air below the point of interest,minus the buoyancy of that section, but may also include other effects (plug bump,overpull, ballooning etc).

2. Determine the axial stress (Sa) carried by the casing under tension. This is the realtension divided by the cross-sectional area of the pipe.

3. Determine the adjusted axial stress equivalent grade (Ypa) using the aboveequation for Ypa in Section 6.3.2.5.

4. Calculate the constants A, B, C, F and G within API 5C3 (you must calculate A, Band C first, before you can calculate F and G).

5. Find the critical diameters and where the casing D/t lies.

6. Use the appropriate API design collapse equation (yield, plastic, transition orelastic) to calculate the new collapse strength.

7. Calculate the design factor from the collapse load.

8. Check the calculated design factor against the minimum design factor.

6.3.2.9 Collapse: Combined Effect of Internal and External Pressure

In practice, casing strings experience internal and external pressures from the wellborefluids. The effect of internal pressure on collapse is summarised by the followingformula from API Bulletin 5C3. The internal pressure provides a resistance to theexternal collapse pressures.

Pe = Po – (1 – 2/(D/t))Pi

Where:

Pe = Equivalent External Pressure (psi)

Po = External Pressure (psi)

Pi = Internal Pressure (psi)



This is based on the internal pressure acting on the inside diameter and the externalpressure acting on the outside diameter.


In practical terms, because internal and external pressures act in opposite directions,they tend to nullify or compensate each other. The total effect is the difference of thetwo (this may finalise as a collapse or burst pressure). If, for example, excessivecollapse pressures were anticipated, then increasing internal pressures would reducethis potential for collapse.

For values D/t greater than the ratio for yield strength collapse (typically casings 9-5/8inupwards), then D/t becomes very large and 2/(D/t) very small.

The above equation then simplifies to:

Pc = Pe – Pi

Where:

Pc = Nett Collapse Pressure (psi)

Pe = External Pressure (psi)

Pi = Internal Pressure (psi)

6.3.3 Tensile (Axial)

For API tubulars, the pipe body tensile rating, or yield strength is defined fromAPI Bulletin 5C3 as:

� � p22

y YdD4

P �

Where:

Py = Pipe Body Yield Strength (psi)

D = Specified Outside Diameter (in)

d = Specified Inside Diameter (in)


This can be simplified to:

Py = Yp x As

Where:

As = Pipe body cross-sectional area (sq in)

For all tensile calculations, true vertical depth (TVD) should be used. Note the tensilerating of the design may be limited to the joint (connection) rating, rather than thepipe body.


6.3.4 Joint Strength (Connectors)

The joint or connection strength should be assessed in the same manner as the pipebody, in particular for axial and burst strength. API Bulletin 5C3 discusses thesesubjects and provides formulae for the internal yield pressure for couplings (burst andleakage) and joint strengths. The main issue to note is that API 5C3 lists the equationsassociated for API designated connections only (short round, buttress and extreme-linecasing). The leak resistance of API connections can be improved through the use oftighter tolerances and coatings.

Ultimately, the main driver for mechanical design is to ensure the strength of theconnectors are greater than or equal to the pipe body. This may not always bepossible, so the designer must identify the weakest point as part of the assessment.

The designer should refer to the pipe and connection manufacturers for data on theconnections and identify (if possible) ‘pipe body matching’ for the connector. Thereader should also be aware that the casing design may require the use of slimline, orspecial clearance connections. This will result in reduced mechanical properties, suchas the tensile rating.

6.3.5 Buckling

A limited amount of buckling is acceptable. However, excessive buckling can lead to anunstable condition, which if it exceeds the localised yield strength of the material, maylead to permanent deformation or failure. The mechanical design should considerbuckling, as it generates bending stresses, casing movement and release ofcompressive loads.

6.4 REPSOL MINIMUM DESIGN FACTORS

The design factors for uniaxial casing design are defined on values used throughoutthe world over a number of years. Summaries of the respective values are detailedbelow for burst, collapse, tension and compression design. They are based on theAPI Bulletin 5C2 Performance on Properties of Casing, Tubing and Drillpipe, plusAPI Bulletin 5C3 Formulae and Calculations for Casing, Tubing, Drillpipe and Line PipeProperties. It is worth noting that the design factors take into account the uncertaintiesin the manufacturing process and tolerances. However, they do not include anallowance for issues such as casing wear and corrosion. The design factors quoted willbe utilised for exploration, appraisal and development wells.


6.4.1 Burst Design Factor

Burst design loads have evolved and now typically include annular fluid behaviour andthermal effects. However, in terms of an API Bulletin 5C3 uniaxial design, the burstcapacity of casing is related only to the yield strength of the material. A degree ofconservatism is built into the values for the tables in API Bulletin 5C2, since the initialyield under burst-loading conditions will not lead to failure, even if the API conditionsare exceeded. Failure does not actually occur until the ultimate tensile strength (UTS)is reached. When calculating the burst capacity of the casing, downrating for wear,corrosion etc is required before the design factor is utilised.

The failure of a casing will generally occur at or near the surface. As a result, theconsequences are more severe in terms of wellbore safety.

Based on this probability a uniaxial burst design factor of 1.1 will be used forburst design.

6.4.2 Collapse Design Factor

The reliability of casing collapse capacities is high as a function of the tightly controlledmanufacturing processes, coupled with studies that indicate these values areoccasionally conservative.

Based on this premise and the fact that downrating from wear and tension should betreated separately, a uniaxial collapse design factor of 1.0 will be used for collapsedesign.

6.4.3 Tension Design Factor

Tension utilises two design factors. Most axial tension arises from the weight of thecasing itself during the running of the pipe. The top joint of the string is generally theweakest point, as it carries the total weight of the casing string. As there are a numberof factors to take into consideration for tensile (axial) loads, the design factors havetended to be split into two factors.

For running casing, a uniaxial tensile design factor of 1.6 will be used, as it includesbuoyancy and bending loads. For most wells, installation loads will dominate the axialdesign and occurs when the joint is picked up out of the slips after it is made up.

For service (post running) conditions such as cementing, landed with overpull andpressure testing, a uniaxial tensile design factor of 1.4 will be used. This capturescementing and casing pressure testing operations, which are generally performedunder controlled conditions.


6.4.4 Compression Design Factor

Casing failure due to compressive loading will be due mainly as a result of elastic orplastic instability (helical buckling). Pure compression failure, ie squashing the casingis unlikely to occur. Casing resistance against buckling can be improved by rigidlysupporting the casing through centralisation.

Thus a uniaxial compression design factor of 1.0 will be used if performing analysisassociated with compression. However, compression is generally associated withthermal, nodal points from cementation tops, extended reach drilling (ERD) wells,HPHT wells and shared compression loads of conductor and surface casings. If highcompression loads exist, the connection may be the weak point. As a result, issuesrelating to compression require translation of three-dimensional stress states andtypically fall under a triaxial analysis by computer software.

6.4.5 Triaxial Design Factor

The increasing acceptance of triaxial stress analysis results in a requirement for atriaxial design factor. Various computer packages allow translation of the various loadconditions into a three-dimensional stress state. Comparison of the three dimensionalstress state with the corrected temperature, yield strength value of the uniaxial isachieved via the Von Mises criterion, which has been extensively used within theindustry. The direct comparison of this Von Mises equivalent (VME) stress to the yieldstrength of the material then provides a single design factor.

Based on field experience with triaxial analysis and various computer packages in usethroughout the industry, a triaxial design factor of 1.25 will be used for casing designanalysis.

Because of the benefits, a triaxial analysis should ideally be performed for wells whichexperience high bottomhole pressures and temperatures (HPHT wells), H2S service,potential buckling, D/t ratios of < 15 (thick wallpipe), combined axial compressionand burst conditions. The accuracy of a triaxial analysis relies on an accuraterepresentation of the conditions that the casing will experience during installationand use.

6.4.6 Design Factor Summary

The following design factors are thus applicable for a Repsol casing design and will beused for exploration, appraisal and development wells.

� Uniaxial burst design factor: 1.1

� Uniaxial collapse design factor: 1.0

� Uniaxial tension design factor: 1.6 (running)

� Uniaxial tension design factor: 1.4 (post-running/service)

� Uniaxial compression design factor: 1.0

� Triaxial design factor: 1.25


6.5 MINIMUM DESIGN FACTORS

Note: A detailed explanation of these load cases follows after the tables.

6.5.1 Conductor

A. CONDUCTOR EXPLORATION DEVELOPMENT

DESIGN LOAD CRITERIA

MINIMUMDESIGN

FACTORS INTERNALPRESSURE

EXTERNALPRESSURE

INTERNALPRESSURE

EXTERNALPRESSURE

1. TENSION LOADS

a. Install

1. Ft = Fair – Fbuoy + Fbend 1.6 MW MW MW MW

2. Ft = Fair – Fbuoy + Fbend +Fshock

1.4 MW MW MW MW

3. Ft = Fair – Fbuoy + Fbend +Foverpull (Running andOverpull)

1.4 MW MW MW MW

4. Ft = Fair – Fbuoy + Fbend +Fplug (Tension CementingWet)

1.4 MW + Psurf MW + CMT MW + Psurf MW + CMT

2. BURST LOADS

a. Install

1. Cement Displacement: MW +Cement + Psurface in Casing

1.1 MW + CMT +Psurf

MW MW + CMT +Psurf

MW

(No other loads apply for burst)

3. COLLAPSE LOADS

a. Install

1. Casing Column Cement:Conventional

1.0 MW MW + CMT MW MW + CMT

2. DP Column Cement:Stab-in + Annulus BridgePressure

1.0 MW MW + CMT +BRIDGE P

MW MW + CMT+BRIDGE P

b. Drilling

1. To Atmospheric: FullEvacuation

1.0 AIR MW TO SETCSG

AIR MW TO SETCSG

2. To Atmospheric: Partial MudEvacuation (to balance losszone)

1.0 FW/SW TOBALANCE

MW TO SETCSG

FW/SW TOBALANCE

MW TO SETCSG

c. Service (No loads apply)

Note: In the table above and in all subsequent tables, the assumption has been madeof using seawater (SW) for cement mixing. For land wells particularly, this mayneed to be replaced with fresh water (FW). The appropriate liquid density mustbe used.


6.5.2 Surface Casing

B. SURFACE CASING EXPLORATION DEVELOPMENT


MINIMUMDESIGN

FACTORS INTERNALPRESSURE

EXTERNALPRESSURE

INTERNALPRESSURE

EXTERNALPRESSURE

1. TENSION LOADS

a. Install



1.4 MW MW MW MW


1.4 MW MW MW MW



2. BURST LOADS

a. Install


1.1 MW + CMT +Psurf

MW MW + CMT +Psurf

MW

2. Bumping Cement Plug: Psurf+ Mud Hydrostatic

1.1 MW + Psurf MW + WETCMT

MW + Psurf MW + WETCMT

b. Drilling Service

1. Casing Pressure Test afterWOC: Psurf + MudHydrostatic

1.1 MW + Psurf SW MW + Psurf PORE

2. Casing Pressure Test afterWOC, LOT + 0.5ppg: Psurf +Mud Hydrostatic

1.1 MW + Psurf SW MW + Psurf PORE

3. Gas Kick: 100bbls Minimum(Circulate out by Driller’sMethod)

1.1 GAS KICKPROFILE

SW GAS KICKPROFILE

PORE


3. COLLAPSE LOADS

a. Install



2. DP Column Cement: Stab-in +Annulus Bridge Pressure


MW MW + CMT +BRIDGE P

b. Drilling


1.0 AIR MW TO SETCASING

AIR MW TO SETCASING


1.0 FW/SW TOBALANCE

MW TO SETCASING

FW/SW TOBALANCE

MW TO SETCASING



6.5.3 Intermediate Casing/Liners

C. INTERMEDIATE CASING/LINERS

EXPLORATION DEVELOPMENT


MINIMUMDESIGN

FACTORSINTERNALPRESSURE

EXTERNALPRESSURE

INTERNALPRESSURE

EXTERNALPRESSURE

1. TENSION LOADS

a. Install



1.4 MW MW MW MW


1.4 MW MW MW MW



5. Ftbase = Fair – Fbuoy +Fbend + Fpretension (Tensionafter WOC)

1.4 MW MW + SW MW MW + PORE

2. BURST LOADS

a. Install


1.1 MW + CMT +Psurf

MW MW + CMT +Psurf

MW

2. Bumping Cement Plug:Psurface + Mud Hydrostatic



b. Drilling

1. Casing Pressure Test afterWOC: Psurface + MudHydrostatic

1.1 MW + Psurf MW TO TOC+ SW

MW + Psurf MUD TOTOC + PORE

BELOW



MW + Psurf MUD TOTOC + PORE

BELOW

3. Gas Kick: 100 bbls Minimum(Circulate out by Driller’sMethod)

1.1 GAS KICKPROFILE

MW TO TOC+ SW

GAS KICKPROFILE

MUD TOTOC + PORE

BELOW

c. Service

1. Well re-entry: CasingPressure Test after WOC

1.1 N/A N/A MW + Psurf DEGRADEDMUD TO

TOC + POREBELOW


C. INTERMEDIATE CASING/LINERS



MINIMUMDESIGN


EXTERNALPRESSURE

INTERNALPRESSURE

EXTERNALPRESSURE

3. COLLAPSE LOADS

a. Install



2. DP Column Cement: Stab-in +Annulus Bridge Pressure


MW MW + CMT +BRIDGE P

b. Drilling



AIR MW TO SETCASING


1.0 FW/SW TOBALANCE

MW TO SETCASING

FW/SW TOBALANCE

MW TO SETCASING



6.5.4 Production Casing/Liners

D. PRODUCTION CASING/ LINERS



MINIMUMDESIGN


EXTERNALPRESSURE

INTERNALPRESSURE

EXTERNALPRESSURE

1. TENSION LOADS

a. Install



1.4 MW MW MW MW


1.4 MW MW MW MW



5. Ftbase = Fair – Fbuoy +Fbend + Fpretension (AfterWOC)

1.4 MW MW + SW MW MW + PORE

2. BURST LOADS

a. Install

1. Cement Displacement: MW +Cement in Casing + Psurface

1.1 MW + CMT +Psurf

MW MW + CMT +Psurf

MW

2. Bumping Cement Plug: Psurf+ Mud Hydrostatic



b. Drilling

1. Casing Pressure Test afterWOC: Psurf + MudHydrostatic


MW + Psurf MUD TO TOC+ POREBELOW



MW + Psurf MUD TO TOC+ POREBELOW

3. Gas Kick: 100 bbls Minimum(Circulate out by Driller’sMethod)

1.1 GAS KICKPROFILE

MW TO TOC+ SW

GAS KICKPROFILE

MUD TO TOC+ POREBELOW

c. Service

1. Well Re-entry: CasingPressure Test after WOC

1.1 N/A N/A MW + Psurf DEGRADEDMUD TO TOC

+ POREBELOW

2. Shut-in Tubing Pressure:Leak at surface on productionpacker fluid weight

1.1 SITHP +PACKER

FLUIDWEIGHT

MW TO TOC+ SW

SITHP +PACKERWEIGHT

DEGRADEDMUD TO TOC

+ POREBELOW

3. Full Gas to Surface: Pressureat wellhead

1.1 GAS TOSURFACE

MW TO TOC+ SW

GAS TOSURFACE

DEGRADEDMUD TO TOC

+ POREBELOW

4. DST Operations: Activation ofDST Tools/Press. Leak + MW

1.1 DST PRESS+ MW

MW TO TOC+ SW

DST PRESS+ MW

DEGRADEDMUD TO TOC

+ POREBELOW


D. PRODUCTION CASING/ LINERS



MINIMUMDESIGN


EXTERNALPRESSURE

INTERNALPRESSURE

EXTERNALPRESSURE

3. COLLAPSE LOADS

a. Install



b. Drilling



AIR MW TO SETCASING


1.0 FW/SW TOBALANCE

MW TO SETCASING

FW/SW TOBALANCE

MW TO SETCASING

c. Service

1. Above Packer: Gas Lift, FullEvacuation

1.0 FULL EVAC MW TO TOC+ SW

FULL EVAC MUD TO TOC+ POREBELOW

2. Below Packer: FullEvacuation (pluggedperforations, depletedreservoir)

1.0 FULL EVAC MW TO TOC+ SW

FULL EVAC MUD TO TOC+ POREBELOW


6.5.5 Design Factor Information

The design factor tables presented are for exploration and development wells, basedon a number of assumptions and require other issues to be considered, prior tocalculating the final design factors.

It should be noted that appraisal wells fall between exploration and development,therefore the well designer must consider how much confidence there is in the drillingdata for the well design in order to determine if the load cases are exploration ordevelopment. The design may justify a mix of exploration and load cases, subject tothe complexity of the design. As a result, the well designer will need to make anassessment of the risk and data reliability with the geological and geophysical team.

Casing Wear is NOT included or accounted for in the casing loads and designfactors. This must be calculated as a percentage of the wall thickness for eachindividual well, based on anticipated service life. The API burst, collapse and tensileyield must be reduced accordingly, prior to calculating the design factors for each load.

Temperature de-rating is NOT included or accounted for in the casing loads anddesign factors. This must be calculated for each individual well based on anticipatedservice life. The API burst, collapse and tensile yield must be reduced accordingly,prior to calculating the design factors for each load.

Thermal loads and buckling are not included within the design factor tables andmay require calculation depending on well type (exploration or development) and loadconditions (dogleg severity, TOCs, subsea or platform).

6.5.5.1 Liner Laps

The pressure behind the liner lap is dependent on the pressureseen at the previous casing shoe. The casing/liner lap assemblyacts as a U-tube.

Exploration Well

This is the sum of the following external loads: Mud weight downto TOC plus SW from TOC to previous casing shoe minus theSW hydrostatic from the previous casing shoe to the top of theliner lap (see schematic).

Development Well

This is the sum of the following external loads: Pore pressure atthe previous casing shoe minus the SW hydrostatic from theprevious casing shoe to the top of the liner lap (see schematic).

Mu

dC

em

en

t

Ce

me

nt

L iner Lap


6.5.5.2 Load Criteria: General Notes

Burst (for calculation purposes)

� For exploration wells (sealed or open annuli): use mud weight (MW) down to top ofcement (TOC) and then seawater (SW) to the casing shoe if the cement has set, orcement density if it has not set (ie plug bump/wet pressure testing) as the externalpressure (Pe)

� For development wells (sealed or open annuli): use mud weight down to TOC if theannulus mud is in reasonable condition and then pore pressure to the casing shoeif the cement has set, or cement density if it has not set (ie plug bump/wet pressuretesting) as the external pressure (Pe)

� For development wells (open annuli): undergoing service loads a considerable timeafter the annulus mud was left in place, use degraded mud down to TOC, then porepressure to casing shoe

Notes: (1) A sealed annulus is sealed at surface and cemented above the previouscasing shoe (ie a trapped annulus).

An open annulus is sealed at surface and cemented below the previouscasing shoe (ie cement shortfall below shoe).

(2) Degraded mud for oil based mud (OBM) assumes the oil has separatedout of the mud system to the base value of circa 6 to 7ppg at surface,followed by mixwater and then mud solids below. Degraded water basedmud (WBM) assumes the water has separated out of the system to mixwater at surface, with mud solids below. For an open annulus the mudwould then possibly leak away to balance the pore pressure down to theTOC. Above this point would be a column of degraded mud/water ordegraded mud/water/base oil.

(3) OBM can vary considerably in the oil:water ratio. In the absence of wellspecific data, assume either a water or base oil gradient for load cases,to identify the worst case scenarios.

Generally, if limited information is available or there is doubt on the quality of theinformation, use the lowest external pressures as backup for burst loads. For example,if the pore pressure data is limited or the design is critical, the external back-uppressure may need to be reduced to a seawater gradient (offshore wells) or afreshwater gradient (land wells).

When considering use of degraded mud in annuli for external pressures on adevelopment well, look at the life of field application for the well. During the drillingphase of a development well, use the mud weight as the external pressure backupload. For well re-entries, use a degraded mud profile. This should be discussed with aSenior Engineer as part of the casing design process.


Collapse

Generally, if limited information is available or there is doubt on the quality of theinformation, use the highest external collapse loads pressures that could occur.

6.5.6 Special Load Cases

A number of special load conditions that are not listed in the design factor tables mayrequire consideration and assessment for well design.

6.5.6.1 Mobile Salts (Collapse)

Use a uniform overburden external pressure (Pe) of 1.0psi/ft if drilling through a mobilesalt formation, based on full evacuation for collapse.

6.5.6.2 Annular Fluid Expansion

For wells with sealed annuli, fluid temperature increases during production willcause fluid expansion, culminating in higher fluid pressures. A sealed container thatexperiences a minor increase in temperature can result in significant additionalpressures. This is offset by the elasticity and ballooning of the casings and formations,which reduces the pressures. The effects of annular fluid expansion (AFE) require anumber of iterative calculations and are a concern for production operations and HPHTwells. If this is highlighted as a design issue, the analysis is typically performed bycomputer software and will involve production and petroleum engineering disciplinesto assist the Drilling Engineer.

AFE loads may be minimised by designing casing strings with a cement shortfall belowthe casing shoe, to allow thermal bleed-off, modifying weights and grades and ifnecessary perforating casing strings.

For tension, the load analysis for a trapped annulus would be:

Ft = Ftbase + Fball + Ftemp

Where:

Ftbase = Fair – Fbuoy + Fbend + Fpretension(After WOC ie cement has set)

Fball = 2 � (Ai x �Pi – Ao x �Pe)

� = Poisson’s Ratio (0.30 for Steel)

Ai = Inside Casing Area, based on the ID

Ao = Outside Casing Area, based on the OD


�Pi = Average change in internal pressure (psi) eg mud weight change(average differential pressure of mud weight change) or an appliedinternal pressure over the whole length

�Pe = Average change in external pressure (psi) eg mud weight change(average differential pressure of degraded mud weight) or anapplied external pressure over the whole length

Fpretension = Overpull in lbs, after WOC completed, to pretension a casing string

Ftemp = - � x E x (As) x (�T)

This last formula can be simplified by combining the two constants, � and E to obtainFtemp as:

Ftemp = -200 x (As) x (�T)

Where:

� = Coefficient of Thermal Expansion for steel, 6.67 x 10-6

E = Young’s Modulus, 30 x 106psi

As = Ao – Ai (in2)

�T = Point (for casing below TOC) or average (for pipe above TOC) change in temperature (�F)

A change in temperature from the ‘as cemented’ base case (Ftbase) will eitherincrease or decrease the total axial load, depending on the temperature change. Abovethe top of cement, the average �T is used since the pipe can move, resulting in thesame force everywhere; below the top of cement it cannot move axially, so the forcedepends on the localised temperature.


Ballooning Force

Figure 6.3 - Ballooning

If a tension is applied to a piece of metal it will normally increase in length in thedirection of the force but reduce in the direction at right angles to the applied load.Similarly, if the load is compressive, the section will decrease in length but increase(bulge) at right angles. If these lateral movements are prevented then the potentialmovement is converted into a force. The ratio of the applied force to the lateral force iscalled ‘Poisson’s Ratio’ for the metal (for steel this is 0.3).

If a casing (or other tubular) experiences an internal pressure increase (compared tothe external pressure) it will expand in diameter (balloon) and, if unrestrained, willshorten in length (this can create potential problems in, for instance, tubing strings).If the casing is not free to shorten, because it is fixed at top and bottom, then thepotential movement will be converted into an additional tensile load.

If the pressure change is a reduction in internal pressure (or increase in externalpressure) then the casing will decrease in diameter and attempt to increase in length.If restrained, this potential length increase will be converted to a compressive force.This process is called reverse ballooning .

Hig

her

Pre

ssur

e

Low

er P

ress

ure

Hig

her

Pre

ssur

e

Low

er P

ress

ure

Ballooning ReverseBalloning

Cem

ent

Cem

ent

Cem

ent

Cem

ent

Tension

Tension

Com

pres

sion

Compress ion


6.5.6.3 Thermal Loads and Temperature Effects

For most normally pressured shallow wells, temperature has a secondary effect on welldesign. However, for complex, higher temperature wells, loads induced by temperaturecan dominate the design. Temperature increases that take place after casinginstallation in sealed annuli can produce extremely high pressure loads as describedpreviously. For land or platform wells with annular access that allows bleed-off this maynot be a problem, provided the well operational procedures address the issue.However, for subsea wells the annuli may not allow access, thus resulting in highpressures from the temperature increases which influence the axial loads fromballooning effects.

Temperature changes will increase or decrease the axial tension due to the thermalcontraction and expansion, respectively. Additionally, changes in axial loads caused bypumping of cool fluids into the well during fracture stimulation or drill stem test (DST)operations, may dominate the axial design. Expansion during production from thermalloads can induce buckling and compressive loads at the wellhead. A well mayexperience extremes of temperature, to very high values during long-term productionand to very low values during injection or stimulation. However, any loads due tothermal change must be calculated as deviations from the original static (datum)condition. Such issues are addressed by computer software, after the initial well designhas been prepared.

Thermal growth at the wellhead is also an issue that requires consideration. In hotwells with long uncemented casings near surface, expansion of the inner strings cancause the wellhead to ‘grow’ and rise by a short distance. This can cause problems forproduction flowlines and wellhead clearances. If a slip type hanger is used, the casingmoves past the slips. When the well is shut in and cools down, the slips bite causing avery high tensile load in the string(s). This only occurs if the casing hangers are notlocked down. If they are locked down, the expansion of the steel can cause buckling ofthe confined casing. The issue of how much pretension needs to be left in the stringsneeds to be addressed so that the operating stresses are controlled. For example, ifthe analysis identifies that the free casing will lengthen by 6in under long-termproduction, then it may be feasible to pre-stretch the casing by greater than 6in duringinstallation. The expansion will be absorbed by a reduction in stretch and so thewellhead will not lift.

Temperature profiles are recommended for high temperature casing designs. Yieldde-rating has been discussed previously in terms of reducing the casing strength.However, for wells experiencing high temperatures/thermal loads, temperature profilesare required for each casing string based on the following:

Static Temperature = Tstat (this is the surface temperature, plus the averagegeothermal temperature gradient depth, supplied by theGeologist).

Cemented Temperature = Tcmt (temperatures resulting from cementing operations,generally obtained from the cementing company).

Drilling Circulation = Tdcirc (the drilling temperatures whilst drilling the wellTemperature are based on the mud temperature as a function of the

geothermal gradient).


Producing Temperature = Tprod (the producing temperature of the reservoirconstituents from the reservoir to surface; obtained fromthe Petroleum/Production Dept).

To summarise, changes in temperature can result in length changes of theunrestrained casing; this is normally held at the wellhead and by the cement to TOC,so that movement is restrained. This can result in excessive axial forces beinggenerated for a casing due to change in temperatures. Alternative designs may berequire to be analysed, based on the outcome of temperature simulations by software.

6.5.6.4 Buckling

Buckling can result from a change in service loads relative to the ‘as cemented’ basecase, or from high compressive loading during installation. Primary factors whichpromote buckling are:

Increased MW and temperatures and reduced internal pressure, during drilling andproduction.

The equations to use to determine buckling conditions are:

Feff = Ft + (Pe x Ao – Pi x Ai)

Where:

Feff = Effective Tension (lbf). If it is positive, no buckling can occur. If negative, buckling may occur

Ft = Total Axial Load at point of interest (psi)

Pe = External Pressure at point of interest (psi)

Ao = Casing X-sectional Area at OD (in2)

Pi = Internal Pressure at point of interest (psi)

Ai = Casing X-sectional Area at ID (in2)

and

Fc = )lbf(loadbucklingcriticalC

)asin(EIq22-

21

��

��

�

Where:

Fc = Critical Buckling Load (lbf)

E = Young’s Modulus, 30 x 106psi

I = Second Moment of Area: �(OD4 – ID4)/64

q = Buoyed Weight per Unit Length (lbf/in) (Note: lbs per inch.)

C = Radial Clearance between hole and casing= (Hole Diameter – OD casing)/2 (in)

a = Hole Angle from vertical (use 1° for a nominally vertical well)


If Feff > Fc no buckling occurs and no further analysis is required.

If Feff < Fc then helical buckling analysis is required to assess impact on service loads.

Generally, if detailed buckling is required, this is performed using the appropriatecomputer software.

6.5.6.4.1 Buckling: Worked Example

An example is included to demonstrate the principles involved for thebuckling equations.

A 13,000ft vertical string of 9-5/8in 47 lb/ft L-80 New Vam casing was run in 12ppg mudand cemented with 3,000ft of 16.0ppg slurry back to 10,000ft. The cement plug wasbumped with 12ppg mud. Determine if the casing will buckle while drilling ahead to17,500ft with 15ppg mud and an average �T increase of 50�F.

Assume an average open hole size of 14in diameter.

9-5/8in casing dimensions:

OD = 9.625in Ao = 72.7in2 C = 2.2in for 14in hole

ID = 8.681in Ai = 59.2in2

I = 83in4 As = 13.5in2

Step 1

Determine the ‘as cemented’ axial load profile (base case).

For 9-/8in 47 lb/ft L-80 New Vam:

Fbuoy = (Ao x Pe) – (Ai x Pi) (At the casing shoe, assuming closed ended)= [(72.7) x (8736)] – [(59.20) x (8110)]= 154,995 lbf

Ft @ shoe = Fwt – Fbuoy= 0 – 154,995= -154,995 lbf

Ft @ 10,000ft = Fwt – Fbuoy= 3,000 x (47) – 154,995= -13,995 lbf

Ft @ 0ft = 13,000 x (47) – 154,995= 456,005 lbf


Step 2

Determine the Effective Tension Feff = Ft + ((Pe x Ao) – (Pi x Ai))

Feff @ shoe = -154,995 + 154,995 = 0

Feff @ 10,000ft = -13,995 + [(12) x (10,000) x (0.052) x (72.7) – (12) x(10,000) x (0.052) x (59.2)] = 70,245 lbf

Feff @ 0 = 456,005 + 0 = 456,005 lbf

Conclusion: No buckling will occur as Feff is positive, ie tensile for the completecasing string.

The next phase of the drilling operation is to drill to 17,500ft with 15ppg mud, theaverage temperature increasing by 50�F.

Step 3

Calculate Fball for above TOC

Fball = 2� ((�Pi x Ai) – (�Pe x Ao) )

= 2 x (0.3)[(15 – 12) x (10,000) x (0.052) x (59.2) – (0 x 72.7)] 2

= 27,700 lbf

Where:

� Pi = Average change in internal pressure

� Pi = (0.052) x (15 12) x (10,000) = 780psi 2

� Pe = Average change in external pressure

� Pe = 0psi

Step 4

Calculate Ftemp for above TOC for an average 50�F increase

Ftemp = -200 x As x �T= -200 x (13.5) x (50)= -135,000 lbf

Ft (axial load) for Drilling

Ft @ TOC 10,000ft = Ftbase + Fball +Ftemp= -13,995 + 27,700 + (-135,000)= -121,295 lbf

Ft @ Surface = 458,000 + 27,700 + (-135,000)= 350,700 lbf


Step 5

Calculate Feff for Drilling

Feff @ TOC = Ft + ((Ao x Pe) – (Ai x Pi))

= -121,295 + [(72.7) x (12) x (10,000) x (0.052) –(59.2) x (15) x (10,000) x (0.052)]

= -121,295 + [(453,648) – (461,760)]

Feff = -129,407 lbf at TOC

Thus a compression value will occur at TOC, due to the change in mud weight andtemperature.

This can be reduced a number of ways:

Increase the TOC to a shallower depth. This may introduce lost circulation andincrease cementation cost. If this approach is adopted, Fbuoy will increase due tothe added cement and so will require repeat buckling calculations.

Apply additional tension (Fpretension) after WOC to eliminate the buckling force.

If Feff is less than Fc (ie Feff more negative than Fc), then helical buckling analysis isrequired to assess the impact on service loads.

Fc =2

1

C)asin(EIq2

2- ��

��

� Critical Buckling Load (lbf)

As the well is vertical, use 1� average angle, critical buckling Fc is:

Fc = -2 [2 x (30 x 106) (83) x (3.01) x (Sin 1�)/2.2]½

= -21,810 lb

q = Is the buoyed weight of the casing per inch based on the new mudweight of 15ppg and is obtained by the following:

01.38.7

33.8158.7

x1247

gsinDensityCaDensityMudgsinDensityCa

xWeightq air ��

�

��

�

�

��

�

��

�

�

Fpretension = Fc – Feff= -21,810 – (-129,407)= 107,600 lbf

This would be the tension required to eliminate buckling. This should then be added tothe ‘as landed’ cemented weight specified under Ft for Drilling (350,700 lbf).

Landing weight after cementation would then be 350,700 + 107,600 lbf = 458,300 lb.(This should be rechecked against the Minimum DF > 1.4)

DensityCasing – DensityMud

DensityCasing


The approximate amount of stretch for pretensioning the 9-5/8in casing at the TOC of10,000ft would be:

�L = Fpt x L (in) E x As

Where:

Fpt = The Pretension Value of 107,600 lbf

L = Length of Unsupported Casing in inches

E = Young’s Modulus, 30 x 106

As = Area of Casing (in2)

�L = 107,600 x (10,000) x (12) = 31.9in (30 x 106 ) x (13.5)

6.5.7 Design Load Definitions

The design loads utilised within the design factor tables are summarised below andinclude schematics and examples where appropriate.

6.5.7.1 Tension

For calculating the total axial load (Ft) in lb at any point during installation, drilling andservice a number of load conditions must be considered. They include the followingitems utilised within the minimum design factor tables.

Ft = Total Axial Load

Fwt = Weight of Casing in Air below the point of interest

Fbuoy = Buoyancy Load calculated as an upward force on the casing

Fbend = Additional Load from bending due to hole curvature (dogleg severity)

Fpretension = Overpull applied to the casing if required, after waiting on cement(WOC)

Fshock = Load arising from acceleration/deceleration during casing running

Fop = Overpull available for pulling the casing if required during casingrunning operations

Fplug = Tensile Load created by the surface pressure used to bump thecement plug

Fball = Tensile Load created from a change in internal or external pressure


Ftemp = Tensile Load created from a change in temperature from the ‘ascemented’ base case

Ftbase = This is the ‘as cemented’ base case (after WOC) on which all othersurface life loads are superimposed (ie put on top)

The equations relating to the above tensile loads are:

6.5.7.1.1 Fwt: Weight of Casing in Air

The axial load created from the weight of the casing is based on the TVD of the well.

Fwt = W x TVD

Where:

W = Weight per Unit Length of Casing (lb/ft)

TVD = True Vertical Distance below point of interest to the bottom of the casing

6.5.7.1.2 Fbuoy: Buoyancy Load Effect

The impact of the buoyancy effect on the casing’s axial load profile is a compressiveforce acting across the bottom of the casing. The compressive force is due to thehydrostatic pressure acting across the cross-sectional area of the casing. This is alsoknown as the pressure area method and can be open ended, or closed ended, such asa float shoe for casing. This methodology applies whether the casing is verticalor inclined.

a. For Open Ended Casing:

Fbuoy = Pe x (Ao –Ai )

Where:

Pe = Pressure at the Bottom of the Casing (psi)

Ao = Area of Pipe at OD (in2)

Ai = Area of Pipe at ID (in2)

Alternatively, for open ended casing, where the internal and external fluids are identicaland of density D in ppg, Fbuoy may be calculated as:

Fbuoy = Dry Weight x (D/8.3)/7.8, where 8.3 is the density of water in ppg and 7.8is the specific gravity of steel, relative to water


b. For Closed Ended Casing:

Fbuoy = Pe x Ao – Pi x Ai

Where:

Pi = Pressure Inside Casing at the Base (psi)

Note: During casing running operations, if the casing is completely filled with mud ofthe same weight as in the hole, Pe = Pi

For tapered casing strings (stepwise tapered), Fbuoy would be calculated using thesame pressure area approach. The additional buoyancy load of the taper section atdepth of interest is added to the axial load profile.

6.5.7.1.3 Fbend: Tension Load from Bending

Bending, as a result of hole curvature, creates localised tensile and compressivestresses. For tension, the bending stress is included in the tension calculation as asimulated axial force, which produces a stress equal to the bending stress.

Fbend = 64 x DLS x OD x W

Where:

DLS = Dogleg Severity (Degrees/100ft)

OD = Outside Diameter (in)

W = Weight per Unit Length (lb/ft)

Bending only occurs where hole curvature exists, so the high Fbend associated withbuild sections need not be applied to the whole length of casing. From the tensiledesign point of view, this favours deep kick-offs over shallow kick-offs. For a verticalwell use a 2�/100ft DLS for tension calculations, unless a specific value warrantsotherwise. In directional wells, the designer should limit the DLS as part of the welldesign process.

6.5.7.1.4 Fplug: Surface Pressure to Bump Plug

This refers to the tensile load resulting from the surface pressure used to bump thecement plug and surface pressure held during WOC, if required. A plug bump axialload increases due to the pressure area method calculation, assuming the casing isfree to elongate during the cementing operation (ie not fixed or constrained).

Fplug = Psurf x Ai

Where:

Psurf = Surface Pressure to Bump Plug (psi)

Ai = Area of Pipe at ID (in2)


6.5.7.1.5 Fpretension: Overpull to Land Casing

This is a direct tension load imposed on the landed casing after WOC is complete. Thisis a method of reducing or avoiding the effects of casing buckling, particularly thoseloads caused by thermal expansion. Fpretension is part of the ‘as cemented’ basecase. Such tensioning is not possible on a subsea well or when using a mudlinesuspension system.

6.5.7.1.6 Fop: Overpull to Pull Casing

This is the surface overpull available to assist in the retrieval of stuck casing duringrunning. Typically a value of 100klb is used as a guide for design but this should not bethe limiting factor as more overpull may be available.

6.5.7.1.7 Fshock: Shock Load

This is the axial load resulting from shock loads occurring as part of the casing runninginstallation. It occurs as a result of:

� Sudden deceleration forces

� When the casing is picked up out of the slips

� Slips are installed while pipe is moving

� The casing hits a bridge or jumps off a ledge downhole

A typical value of 5ft/sec running speed is used for shock loading. The velocityassumed for Fshock during casing design should not be exceeded during casingrunning operations.

Fshock = 1780 x v x As

Where:

v = Velocity in ft/sec

As = Casing X-sectional Area (in2)

This can be simplified to:

Fshock = 8900 x As

Ftbase: ‘As Cemented’ Base Case

This is the ‘as cemented base’ case (after WOC) on which all other surface life loadsare superimposed (ie put on top). Once the casing is landed in the wellhead, cementedand cured, the casing is treated as a single string which is rigidly fixed axially at thewellhead and at the top of the cement (two nodal points).


Note: There may be circumstances where an additional tensile load is applicable, byapplying and holding a surface pressure (Fplug) while waiting on cement. If thisis the case, include the Fplug term to obtain Ftbase.

Ftbase = Fwt – Fbuoy + Fbend + Fpretension + Fplug

6.5.7.2 Burst


Pb = Pi – Pe

Where:

Pb = The Burst Pressure at any depth (psi)

Pi = Internal Pressure at depth of interest (psi)

Pe = External Pressure at depth of interest (psi) *

*Note: Refer to tables in Section 6.5 load case scenarios for the various externalpressures (Pe) for each casing string.

The three scenarios are:

Pe = MW to TOC + SW over cemented sectionExploration well

Pe = MW to TOC + Pore Pressure over cemented sectionDevelopment well

Pe = Degraded MW to TOC + Pore Pressure over cemented sectionDevelopment well (long term)

To calculate the burst design factor (DFb) the following equation is used:

DFb = API Burst Rating x Reduction for Casing Wear x Reduction for Temp De-RatingPb

DFb must be > 1.1 for all uniaxial load cases.


6.5.7.2.1 Cement Displacement

This relates to the installation phase for static pressure calculations, duringdisplacement of the cement. The external pressure Pe shall be the mud weight externalto the casing on installation. The internal pressure Pi shall assume the casing containsa cement column, then mud above the cement, together with the highest anticipatedsurface pressure during cement displacement. The surface pressure may arise fromthe mud and cement rheology, or be based on an operational estimate of pressureassociated with the annulus bridging. Refer to Figure 6.4 for this load case.

Pi = Mud Hydrostatic + Cement Hydrostatic + Spacer Hydrostatic +Surface Pressure

Pi = Pmud + Pcmt + Pspc + Psurf

Pi = (MW x dmw + CMT x dcmt + SPCR x dspcr) x 0.052 + Psurf (psi)

Where:

MW = Mud Density, ppg

CMT = Cement Density, ppg

SPCR = Spacer Density, ppg

d = Length of the Fluid Column, feet TVD

Pe = MW x (d) x (0.052)


Figure 6.4 - Cementing: Displacement

Spacer

Mud

CirculatingPressure

CEMENTING

Cement

Cement Displacement

d M W

d C M T

d S P C


6.5.7.2.2 Bumping Cement Plug

This relates to the installation phase for static pressure calculations, during thebumping of the cement plug. Refer to Figure 6.5 for this load case.

Note: This could also be used as the main casing pressure test if required and wouldbe known as a wet casing pressure test, as the casing is tested immediatelyafter plug bump. Refer also to Section 8.

Pi = Psurf + Pmud (psi)

= Psurf + MW x (d) x 0.052 (psi)

Where:

Psurf = Surface Pressure to Bump Plug (psi)

Pmud = Hydrostatic Pressure of Mud Column (psi)

d = Depth of Interest (ft)

Pe = Pmud + Pcmt (psi)= (MW) x (d) to point A + (Cmt x (d) from point A to shoe) x 0.052

Where:

Pcmt = Hydrostatic Pressure of Cement Column (psi)

Pb = Nett Burst Pressure (psi)

A = Point where mud changes to cement


Figure 6.5 - Cementing: Plug Pump

A

B

Pi

M u d

Cement

CEMENTINGBumping Plug

Psurf

Psi Psurf

Pb

Pe

Pressure

0 psi


6.5.7.2.3 Casing Pressure Test after WOC

This relates to the drilling phase and may require assessment from a number ofdifferent perspectives (see Figure 6.6), depending on the casing string to be pressuretested. This is known as a dry test, as the casing is restrained at the wellhead and overthe cemented portion of the casing. Refer also to Section 8.

Pi = Pmud + Psurf= MW x (d) x 0.052 + Psurf

Where:

Psurf = Pressure required to pressure test the casing (psi)

Note: Pe will be either SW or PP, or MW to TOC + SW or PP, or degraded MW to TOC+ PP as detailed within the tables and at the start of Section 6.5.7.2.

Example: Development Well

Pe = PP x (d) x 0.052 (psi)

(If this is the surface casing for a development well and has been cemented back tosurface.)

Where:

PP = Pore Pressure (ppg)

Or if a development well with mud, followed by cement:

Pe = MW x d x 0.052 + PP x d x 0.052

Where:

d is the Depth of Change from MW to TOC

Notes: (1) The pore pressure may contain a number of different pressure regimes,both high and low, which should be taken into consideration for theexternal pressure.

(2) The pressure test is normally performed prior to drilling out the floatequipment and should, in principle, be the highest pressure test that thecasing will experience for the well life.

(3) The pressure test will be influenced by the well designation explorationor development, as the backup will be different.

(4) The casing pressure test should exceed the maximum surface pressurefor either:

Circulating out a well control influx to surface (using a gas gradient)

The maximum anticipated LOT + the 0.5ppg test margin

(5) The casing pressure test should be < 80% of the API burst rating, asdiscussed in Section 8.


Figure 6.6 - Load Schematic for Pressure Test of Casing after Waiting on CementC

EM

EN

TM

UD

0 1000 2000 3000 4000 5000 6000 7000

Pressure - psi

0

1000

2000

3000

4000

5000

6000

7000

Dep

th -

fee

t

Surface Test Pressure P SURF (2500 psi)

External MudHydrostat ic

(12 ppg Mud)To TOC

Internal MudHydrostat ic

(12 ppg Mud)Surface to Shoe

External SWHydrostat ic(8.9 ppg )

TOC to Shoe

Net

t B

urst

Pre

ssur

e

Exploration WellLoad Case - Casing Pressure Test After

W O C

T O C

9 5/

8" 3

2 pp

f H

40 B

urst

9 5/

8" 3

6 pp

f K

-55

Bur

st


6.5.7.2.4 Casing Test after WOC: LOT + 0.5ppg

This relates to the drilling phase and will link closely to the initial setting depthassessment. It is based on the maximum anticipated surface pressure to determinethe leak-off pressure at the casing shoe; plus the 0.5ppg test margin on the fracturegradient profile, to allow for ECD while drilling and potential well control incidents(see Figure 6.7).

Figure 6.7 - Leak-off Test (LOT)

M u d

C e m e n t

Psurf

Leak Off Test(LOT) in new

hole


The liner lap pressure test is a modification of this test, as indicated in Section 8. Theonly difference is that the liner lap pressure test will be 500psi above the actual LOTachieved.

Example: Development Well

Pi = Pmud + Psurf= MW x (d) x 0.052 + Psurf

Where:

Psurf = Pressure required to pressure test the casing (psi)

Psurf = [(LOT +0.5) – MW] x (d) x (0.052)

Pe = PP x (d) x 0.052 (psi)

(If this is the surface casing and has been cemented back to surface.)

Where:

PP = Pore Pressure (ppg)

or

Pe = MW x (d) x 0.052 + PP x (d) x 0.052

Where:

d is the Change of Depth, from MW to TOC

6.5.7.2.5 Gas Kick

This relates to the drilling phase and is the maximum internal pressure at each depthwhile circulating out a gas kick using the Driller’s Method. The internal pressure profileshould be confirmed in the final stages of calculation by computer software, whichincludes both temperature and gas compressibility effects.

To illustrate this load case, an example is summarised below for a 100bbl gas kick(see Figure 6.8).

Well Data: 9-5/8in Casing

Dshoe = 7,000ft (Casing Shoe Depth)

MW = 13.0ppg (Current Mud Weight)

DTD = 10,000ft (Depth of Hole Section)

Hole Size = 8.50in

PP = Pore Pressure @ DTD = 13.50ppg

LOT @shoe = 17.50ppg


Test Margin, TM = 0.50ppg (This is the safety margin above the LOT value)

Pfg = (LOT + TM) = 18.00ppg

BHP = Bottom Hole Pressure (PP x 0.052 x DTD) (psi)

= 13.50 x 0.052 x 10,000 = 7,020psi

Psurf = Maximum Surface Pressure at top of gas bubble (psi)

Kick Volume = 100bbl (Design Kick Volume)

Influx Gradient = 0.1psi/ft (Gas Gradient of Influx)

Pinflux = Total Influx Height Hg (ft) x Influx Gas Gradient (psi/ft) (psi)

K = BHP x Kick Volume (bbl psi) If temperatureand compressibility effects are ignored

= 7,020 x 100 = 702,000

BHA = 300ft of 6-3/4in DCs (length of Drill Collars in the BHA)

VFOH-DC = 8.52 – 6.752 = 0.026bbl/ft 1029.4

VFOH-DP = 8.52 – 52 = 0.046bbl/ft 1029.4

VFCSG-DP = 8.6812 – 52 = 0.049bbl/ft 1029.4

Influx Volume DCs = 300ft x 0.026 = 7.8bbl

Influx Volume DP = 100 – 7.8 = 92.2bbl

Influx Height DP = 92.2/0.046 = 2,000ft for DP

Total Influx Height Hg = 2,000 + 300 = 2,300ft

Pinflux = 2,300 x 0.1 = 230psi

Pinitial = Annulus Surface Pressure, at initial shut-in after 100bbl gas influx enters well

Pinitial = BHP – Pinflux – MW

= (10,000 x 0.052 x 13.50) – (230) –((10,000 – 2,300) x 0.052 x 13.00)

= 7,020 – 230 – 5,205

= 1,585psi

The concept of calculating the effects of the initial shut-in pressure are explained in theRepsol Well Control Manual.


)psi(2

P VF052.0MWK

4P

Psurf initial

21

DP-CSG

2initial

��

�

�

��

�

� ��

� �)psi(

21585

049.0052.013000,702

41585

Psurf2

12

��

�

�

��

�

� ��

� � 793735,684,9056,628Psurf 21

�

Psurf = (10,312,791)½– 793 = 3,211 – 793= 2,418psi

We now check to see if the gas kick surface pressure is the dominant load versus theLOT surface test pressure on the casing.

Psurf = [(LOT + TM) – MW] x Dshoe x 0.052= [(17.5 + 0.50) – 13.0] x 7,000 x 0.052

Psurf = 1,820psi

Therefore, the 100bbl gas kick dominates the design for this particular string and thecasing must be pretested to a value in excess of 2,418psi, a rounded-up value of2,500psi being realistic. The casing weight and grade would be chosen after theappropriate reductions for casing wear and temperature. The actual design factor willthen be checked to see if it meets the minimum design factor requirements.


Figure 6.8 - Gas Kick: Example Data

D atum

4,000 ft.

7 ,000 ft

7 ,700 ft

10 ,000 ft

9 ,700 ft

Top of G as

H eightof gas(H g)

D T D

6 3/

4" D

rill

Col

lars

5" D

rill p

ipe

6 ,000 ft

Pore Pressure (Dpp)(EM W ) ppg

8.4

9.5

10.0

13.5

Gas

Influ

xM

ud

Mud

Mud

D sh o e


6.5.7.2.6 Shut-In Tubing Pressure: Leak at Surface

Example: Development Well (Service Load)

This relates to a production service load for the production casing and models a tubingleak at the wellhead on top of the production packer fluid weight (see Figure 6.9).

As this is a production load, the mud in the annulus (Pe) is assumed to have degradedto a base liquid (base oil for oil based mud or water for water based mud) down to theTOC. The highest burst pressure is typically at the production packer. However, checkthe pore pressure regimes from the TOC to the packer, as there may be depletedzones higher up.

Note: OBM can vary considerably in the oil:water ratio. In the absence of specificdata, assume either a water or base oil gradient for load cases, to identify theworst case scenarios.

Pi = SITHP + Pmud= BHP – (dRES x 0.1) + (Packer Fluid Density x dPACKER x 0.052)

Where:

BHP = The Reservoir Pressure at the perforated zone (psi)

Pe = Degraded Mud down to TOC + Pore Pressure to the Reservoir (psi)


Figure 6.9 - Tubing Leak at Surface

Degraded M

udC

ement

S ITH P

TO C

Pore P

ressure

P acker

Com

pletion / Packer F

luid

Com

pletion / Packer F

luid


6.5.7.2.7 Full Gas to Surface


This represents a service load based on a wellbore full of gas (0.1psi/ft) to surface fromthe reservoir. This could be a drilling load or the workover of an existing well that has‘unloaded’ (see Figure 6.10).

Pi = BHP – (dRES) x 0.1 (psi)

Pe = Degraded mud down to TOC + Pore Pressure to the reservoir across cemented section (psi)

Note: OBM can vary considerably in the oil:water ratio. In the absence of specificdata, assume either a water or base oil gradient for load cases, to identify theworst case scenarios.

or

Example: Exploration Well (Service Load)

The only difference is the criterion for the external pressure (Pe):

Pe = MW to TOC + Seawater (SW) across cemented section

6.5.7.2.8 DST Operations


These represent service loads for DST activities, including annulus pressure operationof DST tools, or a pressure leak (high pressure gas) at the wellhead with mud in theannulus.

Pi = DST Pressure (Max) + MW (psi)

This is either:

� Maximum applied surface pressure required to operate the DST circulating valve +the hydrostatic mud column (psi)

� Shut-in tubing head pressure + the hydrostatic mud column (psi)

Pe = Degraded mud down to TOC + Pore Pressure to the reservoir acrosscemented section (psi)

Example: Exploration Well (Service Load)

Pe = MW to TOC + Seawater (SW) across cemented section for an exploration well (psi)

Both of these load cases should be checked for, as either could dominate the design.


Figure 6.10 - Full Gas to Surface

Per

fora

tions

Deg

rade

d M

ud

B H P

T O C

Dep

th

P ressure

Gas

Fill

ed H

ole

B H P

T D

Gas

gra

dien

t 0.1

psi

/ f

t


6.5.7.3 Collapse


Pc = Pe – (1 – (2t/D)) Pi

When using thin-walled pipes, as in most casing designs, t/D is a very small numberand the equation approximates to:

Pc = Pe – Pi

Where:

Pc = The Nett Collapse Pressure at any depth (psi)

Pe = External Pressure at depth of interest (psi)

Pi = Internal Pressure at depth of interest (psi)

This is the collapse load due to the effects of internal and external pressures (psi).

From the formula given in Section 6.3.2.5 we can derive the following formula, whichgives the percentage of full collapse pressure or PFCP due to a tensile.

100YS

5.0YS

75.01100Y

YP xx

p

a

2

p

a

p

paFCP

��

�

�

��

�

�

��

�

��

�

�

Sa = Axial Stress (psi)

Yp = Minimum Yield Strength of Pipe at Zero Load (psi)

Ypa = Yield Strength of Axial Stress Equivalent Grade,the Adjusted Yield Strength (psi)

To calculate the collapse pressure (Pc) for a given design factor (DFc), the followingequation is used:

Pc � API Collapse Rating x PFCP x Reduction for Casing WearDFc

Where:

DFc = The Actual Design Factor for Collapse

API Collapse Rating = taken from API 5C2

Reduction for Casing Wear is the % Wear Allowance

DFc must be > 1.0 for all uniaxial load cases


6.5.7.3.1 Cementing: Conventional

This relates to the installation phase for conventional cementing, during displacementof the cement (see Figure 6.11). The internal pressure Pi assumes the casing is full ofmud. The external pressure Pe shall be the mud weight, cement slurry and anestimated bridge pressure assuming the hole packs off during displacement.

This type of collapse load is of concern for large diameter casings with a high D/t ratio.(eg 20in and 18-5/8in).

Pi = Pmud + Pspc (psi)

Pi = [MW x (dMW) + Spc x (dSPC)] x 0.052 (psi)

Where:

MW = Mud Density (ppg)

Spc = Spacer Density (ppg)

d = Length of the Column (feet TVD)

Pe = Pmud + Pcmt (psi)= [MW x (dmw) + Cmt x (dcmt)] x 0.052 (psi)

Where:

Cmt = Cement Density (ppg)


Figure 6.11 - Cementing: Conventional and Stab-in

Spacer

Mud

Convent ional

Cement

CEMENTING

h

T O C

TD

M u d

Stab-in Job

Cemen t

CEMENTING

h

TOC

T D


6.5.7.3.2 Cementing DP Stab-in

This relates to the installation phase for stab-in cementing, during displacement of thecement (see Figure 6.11). The internal pressure Pi assumes the casing and DP is fullof mud. The external pressure Pe shall be the mud weight, cement slurry and anestimated bridge pressure assuming the hole packs off during displacement. It shouldbe noted that the internal fluid between the casing and DP is often water and so willcreate a greater collapse differential.

Pi = Pmud (psi)

Pi = MW x (d) x (0.052) (psi)

Where:

MW is the Mud Weight (ppg) and d is the TVD depth of interest (ft)

Pe = Pmud + Pcmt + Pbridge pressure (psi). This assumes the bridge pressure is at the surface.

Pe = [MW x (dmw) + Cmt x (dcmt)] x 0.052 + Pbridge

6.5.7.3.3 Full Evacuation

This relates to the drilling phase for full evacuation of the casing. The internal pressurePi assumes the casing is atmospheric. The external pressure is based on the originalmud weight to set the casing. This load case is of particular concern for large diametercasings, such as conductor and surface casings where total losses have taken place.This load case is also applicable if drilling with air, or foam.

Pi = Atmospheric

Pe = Pmud (psi)

Pe = MW x (d) x (0.052) (psi)

Where:

MW is the original mud weight used to set the casing (ppg) and d is the TVD depth (ft)to the casing shoe.


6.5.7.3.4 Partial Evacuation

This relates to the drilling phase for partial evacuation of the casing while drilling withlost returns. The internal pressure Pi is based on the drop in the mud level using themaximum mud weight at the end of the next hole section, caused by the lost circulationzone. The fluid level in the wellbore will fall until the pressure in the wellbore equalisesto the pressure of the lost circulation zone. This is normally taken as c. 8.33ppg normalpressure at the loss zone, if limited data is available.

This is given by:

LZLZ D

MWPMW

h ��

��

�

Where:

h = Depth at top of fluid where the FW/SW balances the Loss Zone Hydrostatic Pressure (ft)

DLZ = Depth of the known Loss Zone (ft)

PLZ = Formation Pressure Gradient of Loss Zone (ppg)

MW = Mud Weight in Hole at Section TD (ppg)

Pe is then calculated at the h depth to determine the collapse pressure, based on Pi asatmospheric.

6.5.7.3.5 Gas Lift: Above Production Packer


This relates to a production service load for the production casing and models a wellwith gas lift installed that loses injection pressure (see Figure 6.12). As a result it isassumed that Pi is based on full evacuation to atmospheric. The external pressure Pe

will be the mud weight down to TOC plus pore pressure below, over the cementedsection. As it is a collapse load, it is assumed that the mud does not degrade.

If it is an exploration well, the external pressure Pe would be mud weight down to TOCplus a seawater gradient below, over the cemented section.


Figure 6.12 - Gas Lift above Production Packer

Ga

s F

ille

d A

nn

ulu

s

De

pth

P ressu re

Fu

ll E

va

cua

tion

(Ga

s g

rad

ien

t w

ith n

o s

urf

ace

pre

ssu

re)

Ga

s L

ift M

an

dre

ls


6.5.7.3.6 Full Evacuation: Below Production Packer


This relates to a production service load for the production casing or liner and models awell with a depleted reservoir or plugged perforations (see Figure 6.13). The collapseload may be a concern immediately above the perforated zone. As a result, it isassumed that Pi is based on full evacuation to atmospheric. The external pressure Pe

will be mud weight down to TOC, plus pore pressure below, over the cemented section.As it is a collapse load, it is assumed that the mud does not degrade as this models theworst case.

If it is an exploration well, the external pressure Pe would be mud weight down to TOCplus a seawater gradient below, over the cemented section.

The setting depth of the production packer may influence the external pressure if it isset above the TOC.

Figure 6.13 - Collapse Load Schematic for Running of Dr y Casing

MU

D

0 1000 2000 3000 4000 5000 6000 7000

Pressure - ps i

0

1000

2000

3000

4000

5000

6000

7000

De

pth

- f

ee

t

Ex ternal M ud Hydrostatic(12 ppg M ud) Surface To Shoe

=Nett Collapse Pressure

Exp lo ration WellLoad Case - Running Casing D ry W ith

External M ud Hydrostatic

9 5

/8"

32

pp

f H

40

Co

llap

se

9 5

/8"

36

pp

f K

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SECTION 7 PRESSURE TESTING Page 1 of 4

TABLE OF CONTENTS

7. PRESSURE TESTING ........................................................................................... 2

7.1 CRITERIA ........................................................................................................ 2

7.2 GENERAL REQUIREMENTS .......................................................................... 2

7.2.1 Plug Bumping ............................................................................................. 2

7.2.2 Casing Pressure Testing ............................................................................ 3

7.3 SPECIFIC CASING PRESSURE TESTS ......................................................... 3

7.3.1 Conductor................................................................................................... 3

7.3.2 Surface and Intermediate Casings.............................................................. 3

7.3.3 Production Casing and Liners..................................................................... 3

7.3.4 Liner Laps................................................................................................... 4

PRESSURE TESTING Page 2 of 4

7. PRESSURE TESTING

7.1 CRITERIA

The Repsol policy for casing pressure testing requires all surface, intermediate andproduction casing/liners to be pressure tested, prior to drilling out the shoe track orperforating.

7.2 GENERAL REQUIREMENTS

Casing pressure test loads must not exceed 80% of the API burst rating. This mayrequire confirmation by a triaxial analysis, that the calculated combined loads do notexceed the design factors based on the 80% pressure test criteria. This applies to bothpipe and connections.

When calculating pressure test requirements, consideration must also be given to thefollowing:

� The minimum and maximum densities of the fluid columns inside and outside thecasing, both initially and for the life of the well

� The burst rating for the weakest casing in the string if it is a combination string

� The minimum design factors utilised for the casing

� The effect of pressure testing on casing tensile (axial) loads

� Casing wear if drilling has occurred before pressure testing the casing string

� Anticipated service loads for the life of the well

There are two methods for performing casing pressure testing; both have anapplication depending upon the type of well drilled. Ideally, pressure testing (which is aburst condition) should look at the triaxial stresses for burst and axial loads.

7.2.1 Plug Bumping

If the casing pressure test is carried out during cementing (wet pressure testing) whenbumping the plug, the external (backup) load should equal the mud weight used, pluscement slurry weight to set the casing (assuming any fluid losses while cementing areall cement) or the lowest density fluids in the annulus (eg foam cement slurries).

Wet pressure testing reduces the nett differential pressure at the bottom of the casingand can provide a solution, to achieve the required pressure test of the casing atsurface.

If the burst design factor during pressure testing is close to the minimum allowed, itshould be highlighted in the drilling programme to ensure the engineer understands thesignificance of the pressure test.


This type of test increases the axial tension loads due to the casing end area effect.However, the ballooning effect does not increase the tension, as it is not fixed at thebottom. To summarise, the designer should be aware that for wet pressure testing,axial loads could be significant. The plug bump design load criteria are discussed inSection 6.

7.2.2 Casing Pressure Testing

If the casing pressure test is carried out after waiting on cement (WOC), the external(backup) load should be defined as stated in Section 6. The additional axial tension forpressure testing after the cement has set, is created by the ballooning effect above thetop of cement and this contributes to the triaxial stress. The end area effect of thecasing is not relevant in this case, as it is cemented and fixed. To summarise, thedesigner should be aware that axial loads will apply over the uncemented section of thecasing and that this type of pressure test can result in a higher nett burst pressure atthe casing shoe, over the cemented portion of the casing.

7.3 SPECIFIC CASING PRESSURE TESTS

7.3.1 Conductor

Pressure testing of the conductor is not required as it is a structural string.

7.3.2 Surface and Intermediate Casings

Where a leak-off test (LOT) is required, the minimum pressure test is defined as thesurface pressure required to provide an equivalent mud weight (EMW) at the shoeequal to the anticipated leak-off plus a 0.5ppg test margin (TM).

The maximum anticipated surface pressure for surface and intermediate casings is thegreater value of either that required for the anticipated LOT with the test margin or thePsurf for the well control burst load case.

7.3.3 Production Casing and Liners

For development wells, the minimum pressure test shall be equivalent to the shut-intubing pressure (SITP) on top of the annulus completion fluid. Unless ample data isavailable to support an alternative (gas composition and reservoir data), a gas gradientof 0.1psi/ft should be used down to 10,000ft true vertical depth (TVD), thereafter use0.15psi/ft in the calculation of surface pressure. These criteria also apply to explorationwells, for a DST string leak on top of the annulus fluid (mud).


7.3.4 Liner Laps

Liner laps must be tested to a minimum of 500psi above the formation leak-offpressure at the casing shoe, unless there is no requirement to demonstrate internalpressure integrity of the casing/liner hanger and cement. However, this test needs tobe assessed to check that the equivalent mud weight applied to the liner during thedrilling phase with mud is > (greater than) the maximum equivalent pressures duringDST or completion operations. For example, if the production packer is set as a PBR orwithin the liner, the well design should be checked to ensure for production operations,the shut-in tubing head pressure (SITHP) + the packer fluid weight is < (less than) theLOT + 500psi pressure test at the casing shoe.

In addition, a differential test must be conducted on the liner, which imposes adrawdown equivalent to or greater than that expected during the life of the well.



SECTION 8 SPECIAL CASES Page 1 of 18

TABLE OF CONTENTS

8. SPECIAL CASES................................................................................................... 3

8.1 HPHT WELLS .................................................................................................. 3

8.1.1 HPHT Definition.......................................................................................... 3

8.1.2 Type of Design ........................................................................................... 3

8.1.3 Limitations .................................................................................................. 4

8.1.4 Rig Type ..................................................................................................... 4

8.1.5 Packer Fluids.............................................................................................. 4

8.1.6 Kick Tolerance............................................................................................ 6

8.1.7 Wellhead Connector/Riser Analysis ........................................................... 6

8.1.8 Inspection Criteria....................................................................................... 6

8.1.9 Hazard Assessment ................................................................................... 6

8.2 DEEP WATER .................................................................................................... 7

8.2.1 Definition .................................................................................................... 7

8.2.2 Type of Design ........................................................................................... 7

8.2.3 Wellhead Connector/Riser Analysis ........................................................... 7

8.2.4 Fracture/Pore Pressure Margins................................................................. 7

8.2.5 Conductor Design....................................................................................... 8

8.2.6 Surface Casing Design. .............................................................................. 8

8.2.7 Operational Constraints .............................................................................. 8

8.3 CONDUCTOR/SURFACE CASING DESIGN................................................... 9

8.3.1 Well Design Issues..................................................................................... 9

8.3.2 Loads and Forces..................................................................................... 10

8.3.3 Environmental Conditions ......................................................................... 10

8.3.4 Fatigue due to Cyclic Wave Loading ........................................................ 11

8.3.5 Vortex Induced Vibration Fatigue.............................................................. 11

8.3.6 Detailed Design Analysis .......................................................................... 11

8.3.7 Subsea Wells ........................................................................................... 13

8.3.8 Mudline Suspension Wells ....................................................................... 14

SPECIAL CASES Page 2 of 18

8.4 TIEBACK DESIGN......................................................................................... 14

8.4.1 Tieback Description .................................................................................. 14

8.4.2 Design Issues........................................................................................... 14

8.4.3 Thermal Growth........................................................................................ 15

8.4.4 Equipment Loads...................................................................................... 15

8.4.5 Pretension (9-5/8in) .................................................................................. 15

8.4.6 Compression (13-3/8in) ............................................................................ 15

8.4.7 Environmental String (20in) ...................................................................... 16

8.4.8 Environmental Loads ................................................................................ 16

8.4.9 Pressure Effects ....................................................................................... 16

8.4.10 Temperature Effects ................................................................................. 17

8.4.11 Operational Issues.................................................................................... 17

8.4.12 Drilling/Structural Engineering Interface ................................................... 18


8. SPECIAL CASESA number of special cases for casing design are worthy of discussion, to provide theDrilling Engineer with an insight into various issues that may influence a design. Itshould be emphasised that the following sections represent a summary of issues to beconsidered and potential problems.

Unusual wells generally require a multi-disciplinary team approach, due to theirspecialist nature, operational constraints and the economic impact that may occur.

8.1 HPHT WELLS

High pressure, high temperature (HPHT) wells require a higher degree of engineeringeffort and preplanning for well design, due to the tighter margins between the pore andfracture gradients and the thermal loads arising from higher temperatures. The drillingengineering time required for an HPHT well design may be 5 to 10 times that requiredfor a standard well.

A specific module on the HPHT wells is contained within the Special Wells Manual andthe reader should refer to that document, in addition to this Casing Design Manual.Some of the key issues associated with casing design for HPHT wells are summarisedbelow.

8.1.1 HPHT Definition

HPHT wells are generally defined as having an anticipated surface pressure requiringpressure control equipment with a rated working pressure in excess of 10,000psi (thisis defined within IP 17, Well Control during the Drilling and Testing of High PressureOffshore Wells).

The high temperature definition is typically regarded as a well having a minimumundisturbed formation temperature of 300�F at total depth.

It should be noted that a well may not necessarily exhibit both high pressure and hightemperature. However, the approach and detailed assessment would still be the same.

8.1.2 Type of Design

Due to the special requirements associated with HPHT wells, a full triaxial VME (VonMises Equivalent) analysis should always be performed as part of the well design. Thisis important due to the large temperature effects on axial load profiles and combinedburst and compression loading. As a result of this approach, the design will beperformed by computer software and uniaxial hand calculations, to confirm the generalcomputer outputs of the software.

It is likely that a Senior Engineer, in conjunction with an independent internal reviewand third-party assessment, will design wells of this nature.


8.1.3 Limitations

A Von Mises Equivalent (VME) ellipse schematic is shown below in Figure 8.1, togetherwith an API uniaxial outline to provide guidance on the limitations of the VME ellipse.

The main emphasis of a triaxial VME analysis is to ensure that all load cases for thedesign, including thermal loads, stay within the boundaries of the VME ellipse. Thereare, however, exceptions to this general statement; primarily for collapse loads undertension, where it is necessary to satisfy both the triaxial stress and API Uniaxialcollapse requirements.

A well design for a ‘normally pressured well’ with a standard temperature profile will notrequire detailed analysis when compared to an HPHT well. Basic assumptions utilisedfor a standard well may not be appropriate for HPHT wells because of the significantadditional impact on the well design from thermal loads. This requires an iterativeapproach to the well design, as the output design factors will be sensitive to changes ina particular load.

8.1.4 Rig Type

The choice of drilling unit for HPHT wells will have an impact on the casing design.These may include – fixed rig structures (land, offshore platform, jack-up) and floatingrig structures (semi-submersible, drill ship or floating tension leg platforms).

For offshore wells, a jack-up will allow higher temperatures and flow rates to surface.Conversely, a semi-submersible will have temperature limitations at the wellhead/blowout preventer (BOP) connection and require greater engineering effort for a drillstem test (DST) or subsea completion.

Additionally, a jack-up allows access to all annuli and the capability to bleed off annuluspressures in a controlled manner. A jack-up rig also significantly reduces the sensitivityof weather to critical operations, such as drilling into high pressure transition zones anddisplacing to underbalanced fluids, relative to emergency disconnect procedures for asemi-submersible.

8.1.5 Packer Fluids

Due to the high mud weights associated with HPHT wells, performing a DST orcompletion operations has a significant impact on the design philosophy. For example,there is a general industry trend to move toward non-kill weight packer/completionfluids, to minimise the nett burst loads and annular fluid expansion (AFE) pressures.Designing a DST/completion with a low weight packer fluid may allow the elimination ofa production tieback string. Additionally, low packer densities (and viscosities) promotefaster heat dissipation through casings, due to higher thermal capacities and increasedthermal diffusion, compared to a high weight, high solids mud.

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Page 5 of 18

Figure 8.1 - V

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Triaxial Stress Check (von Mises Equivalent (VME) Check)

COMPRESSION AND BURSTThis region is most important forVME check . - Corkscrewing - high comp., lowhoop st ress - Burst - Low comp., h igh hoopstress

TENSION AND BURST(Tension helps burst)

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COMPRESSION ANDCOLLAPSE

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TENSION AND COLLAPSECol lapse is a buckl ing addit ion requir ing an

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stress so i t is not appl icable.

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Intercept: Burst DF = 1.10 Triaxial DF = 1.25(For 12.5% wal l th ickness tolerance in severalcomputer design programs).

(HIGH COMP. AND LOW COLLAPSE)(Fai lure by buckl ing)

Combined stress can exceed elast ic l imi t

VME very Applicable

General ly connect ionshave a much loweraxia l compressive

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8.1.6 Kick Tolerance

Due to the low safety margins between the pore pressure and fracture gradient profiles,kick tolerance values may be significantly reduced when compared to standard wells.HPHT wells may not have the comfort of allowing the inclusion of a hydrostatic risermargin as part of the mud weight overbalance. This has an impact for calculating thetotal overbalance on the formation with the drilling fluids.

8.1.7 Wellhead Connector/Riser Analysis

It is normal practice to consider the capabilities of the riser and wellhead connectorsystem for HPHT wells, since the complete system may experience higher pressuresfor a well control incident than for a normal pressured well. This can affect theoperational working envelope for the well design in terms of the anticipated bendingloads on the conductor and the minimum riser tension for the rig, if a semi-submersibleis used. A specific document has been generated by the Institute of Petroleum (IP) toaddress these issues and is titled Guidelines for ‘Routine’ and ‘Non-Routine’ SubseaOperations from Floating Vessels (August 1995). This document should be used todetermine if the conductor and riser system requires detailed analysis. This is achievedby filling out a template checklist of questions within the IP document and highlights ifadditional detailed analysis is required.

8.1.8 Inspection Criteria

Due to the risks and tighter margins associated with HPHT wells, the inspection criteriafor specification and order will be to a higher level than normally used for API tubulars.The consequence of tubular and/or connection failure requires much more focus at thespecification stage, to minimise this risk. This is also discussed within Section 4.2.4.3for casing loads and casing specifications.

8.1.9 Hazard Assessment

Well designs such as HPHT will require the use of HAZOP/HAZAN techniques as partof the well design process due to the close design margins and the consequences offailure. To assist the well designer, HAZOP comes first by identifying the hazards fromthe design and means Hazard and Operability study. It is qualitative and performed bya team from a cross-section of various disciplines, not just drilling personnel. Thehazards are identified and the team then decides how to address them. The HAZAN(Hazard Analysis study) process follows and may include techniques such as riskassessment or quantified risk assessment (QRA) ie what is the likelihood that anincident or failure will occur and the consequence should it occur.

It is important that casing seat selection is firmly determined and assessed, for issuessuch as entering the HPHT transition zone. The mechanical design of the tubulars(pressure vessel) can remove many of the potential risks by designing them out. Thiswill be based on agreeing the operational envelope of the well with all parties andensuring that ‘what if’ load cases for the big issues are addressed within the design.


8.2 DEEP WATER

Deep water wells require greater focus on the upper section of the well, from thesurface casing upward (including the conductor, wellhead and riser system). Inprinciple, well design below the surface casing down is similar to a standard welldesign. A specific module on deep water wells is contained within the Special WellsManual and the reader should refer to that document, in addition to the CasingDesign Manual.

8.2.1 Definition

Deep water can be defined as areas with a water depth in the order of greater thanc.1,500ft. This is because from this depth onward (subject to metocean conditions) theequipment and well design change.

8.2.2 Type of Design

Deep water well design may be based on benign pore and fracture gradient profiles. Asa result, the well design may be uniaxial, with an additional focus on the rig risersystem, conductor, surface casing and wellhead connector.

8.2.3 Wellhead Connector/Riser Analysis

The choice and availability of the wellhead connector will define the size of conductorand the diameter of the drilling rig riser. For example, the initial well design should bebased on a generic 21in drilling riser and 18-3/4in wellhead system. The capability ofthe wellhead connector in terms of bending and axial rating will link firmly to the riseranalysis. This in turn defines the bending and axial capabilities of the conductor pipeand connectors. These issues can be minimised by use of a pre-locked wellheadsystem which provides additional support and anchoring, and reduces movement andbending below the wellhead and fatigue on the surface casing (just below the highpressure housing).

As for HPHT wells, the IP Guidelines for Subsea Operations from Floating Vesselsshould be used as part of the well design, to determine the well operational envelope.

8.2.4 Fracture/Pore Pressure Margins

An increase in water depth has the effect of decreasing the margin between porepressure and fracture gradient, reducing the operating margin for mud weights. Lostcirculation may occur at a mud weight equal to the pore pressure, after taking accountof the ECD (equivalent circulating density). A slight reduction in the mud weight maycause a water flow and kick due to highly water-saturated formations.


A reduction in the offshore overburden gradient will dramatically decrease the fracturegradient, particularly with deep water and a shallow well depth. Thus the primary focusfor deep water well design will be for the conductor and the surface casing strings.

8.2.5 Conductor Design

This will require a detailed engineering analysis and link directly to the capability of thedrilling rig, riser diameter and wellhead connector, soil strength analysis of the seabedformations and the metocean data set. The principal purpose of the conductor is toprovide a stable foundation for all subsequent casing strings. As the surface fracturegradients are lower, soil strength analysis and frictional support for the conductorbecome important factors. This affects the size of the conductor (bigger is better as itprovides more contact area and improved structural rigidity) and the installationtechnique (jetting rather than cementing, to maintain frictional support and axial loadrequirements for the BOP and subsequent casings).

The conservative approach is to select a conductor design that has the capacity tomaintain strength when subjected to both bending and axial loading during drilling,without considering the additional rigidity provided by the inner strings. This seems areasonable approach as sharing of the axial loads between the conductor and surfacecasing may not be achieved due to the cementation of the surface string not reachingthe seabed between the two strings. Additionally, the bending contribution of thesurface casing is usually relatively small.

Conductor design should also focus on the bending capability of the connectors, toensure they are not the limiting factor for the conductor.

8.2.6 Surface Casing Design

The surface casing will require a detailed analysis as part of the conductor design. Inparticular, emphasis is placed on obtaining a minimum depth to achieve the pressureintegrity for the next hole section and to allow the installation of the BOPs and riser.Centralisation, pipe yield, cement slurry design and connector capability will beinfluential factors for surface casing design.

8.2.7 Operational Constraints

The main issues requiring consideration are the open water operations associated withrunning the conductor and surface casing. This can induce high bending loads fromsubsea currents, due to the stiffness of the casing string. This should be assessed aspart of the design, to determine if failure could occur.


8.3 CONDUCTOR/SURFACE CASING DESIGN

Certain aspects of conductor and surface casing design should be highlighted, in orderthat the Drilling Engineer is aware of the issues and is able to identify where specialistadvice is required.

8.3.1 Well Design Issues

When considering a conductor and surface casing design, the following issues need tobe clarified and ranked in order to determine the depth of analysis required.

� Is the well exploration or development?

� Is the well on land or offshore?

� Is it normally pressured or an HPHT well?

� Will the well experience high thermal loads as a result of production operations?

� Is it a platform well with significant height above sea level for the conductor?

� Is it a deep water environment?

� Is ice anticipated (fixed or flowing)?

� Is the well planned for offshore using a jack-up rig, in water depths requiring apretension system and/or additional wall thickness, to minimise buckling?

� Are the metocean conditions liable to produce additional loads on theconductor system?

� If it is planned as an offshore subsea well, will the conductor experience fishingtrawler snag bending loads over the conductor and wellhead?

� Do the soil analysis conditions require special cementation slurries, or a minimumnumber of joints, or installation techniques to ensure a stable foundation?

� Does the conductor consider the possibility of submarine traffic, requiring subseaprotection systems from trawlers (contact local military if relevant)?

� Does the conductor require a confirmed cementation top to minimise bending loads(point of fixity)?

� Will the conductor, in conjunction with the surface casing, require a centralisationanalysis to increase the rigidity of both strings in terms of bending and compressiveloading?

� Will there be deep/heavy casing strings, with potential to transfer loads to thesurface casing and conductor (special running procedures eg hold in tension untilcement set)?


The engineer will need to assess the above list and use this in conjunction with thebasis of design checklists, highlighted at the end of Section 4.

For example, if the well is exploration, onshore, shallow and is normally pressured,then an assessment can be reached quickly that this type of well does not require adetailed analysis and that a basic conductor system may be adequate. However, if thewell is offshore, from a jack-up with relatively deep water and active subsea currentswith an HPHT well profile, then it is certain that specialist marine conductor engineeringanalysis will be required as part of the well design, above the mudline.

The following sections expand on issues associated with a marine conductor designabove the mudline and assume an offshore jack-up well .

8.3.2 Loads and Forces

Conductors are subjected to a number of internal and external loads, which combine tocause bending, compression, buckling and fatigue. Loads can arise from:

� Wave/current loading

� Internal casing weight/pretension

� Weight of conductor

� Mud weight

� Wellhead/BOP weight

Wave and current loads deflect the conductor and apply cyclic bending forces, whichare normally greatest in the wave zone. Internal casings, wellhead/BOP and mudweight forces accumulate to give a compressive load which reaches a maximum atsome point below the mudline. These combined compressive and bending forces tendto cause buckling or conductor slump (although the load from the internal casingstrings is not normally considered to contribute to buckling).

8.3.3 Environmental Conditions

Extreme design wave and current conditions are normally based on a 10 year returnperiod for permanent installations. In some operating regions this may require thatfixed structures are designed for 50 year return conditions. However, jack-upconductors for exploration wells are not permanent installations, so a shorter returnperiod is generally acceptable (in shallow water, conductors may be left in place for anumber of years and are subject to high wave loads).

In tropical climates that are subject to hurricanes or typhoons, there is a largedifference between the 10 year hurricane and the 10 year non-tropical storm. The timeof year during which the well is drilled is also an influential factor.


Scatter diagrams, or wave exceedance data are required to determine fatigue due tocyclic wave loading. For example, fatigue damage can be significantly worse during thewinter than summer period. Current exceedance data is also necessary to determinefatigue damage due to vortex induced vibration.

Although pure axial and bending stresses must be within the allowable limits, thelimiting factor in jack-up conductor design is typically buckling. In deep water the limit isa combination of dynamic bending and buckling. API RP2A gives buckling criteriabased on an interaction ratio, which combines axial and bending forces. Since thecalculations required for assessment of such forces must include dynamic wave andinertia effects, it is recommended that a storm check design is performed and analysedby a specialist with the appropriate knowledge and computer software.

8.3.4 Fatigue due to Cyclic Wave Loading

For a given wave climate over the duration of the well, a fatigue analysis that considersthe dynamic response of the conductor to cyclic wave loading must be performed.A simple mechanistic analysis will normally be adequate. In many areas the design ofthe conductor will not be greatly influenced by fatigue. However, in areas such as theGulf of Mexico, fatigue is critical during the winter. During this period, maximum waveand currents are generally low. Under these conditions, the design will be entirelyinfluenced by wave cyclic fatigue or wave induced vortex vibrations.

8.3.5 Vortex Induced Vibration Fatigue

The major cause of fatigue damage and failure in jack-up marine conductors is vortexinduced vibration (VIV). This occurs when one or more natural conductor frequenciesare excited by current velocities or by large waves with reduced velocities.

If a conductor design is susceptible to current induced vortex induced vibration andcurrent statistics are available, detailed computer analysis should be carried out todetermine the minimum fatigue life. If there are no reliable current statistics or if vortexinduced vibrations are expected to be caused by waves, then the assessment offatigue is more complex. In such circumstances a full bathymetric and metoceansurvey may be required to gather the necessary information (more pertinent fordevelopments). Useful sources of information are often local military, the US or BritishNavy or the British Maritime Association.

8.3.6 Detailed Design Analysis

If a detailed design analysis is necessary, it is generally performed by a specialiststructural engineer and would typically include:

� Analysis of the environmental conditions

� Static analysis


� Dynamic analysis

� Fatigue analysis

Assessment of the environmental criteria will establish maximum current, wave heightand current direction. The drag coefficient is also important and will vary according tocurrent velocity, conductor diameter and roughness due to marine growth. Specificgeotechnical information at the location is required.

A static analysis provides a datum stability check and can be used as a reference pointto determine the effect of rig offset. The dynamic analysis with extreme wave andcurrent conditions is used to evaluate maximum stresses and perform thedesign check.

Fatigue analysis should consider both cyclic wave loading and vortex induced vibration,to determine the minimum fatigue life at critical locations. Based on these variousfactors, a design can be established which provides an operating envelope forthe conductor.

A typical conductor for a jack-up may require a conductor above the mudline of30in x 1.0in weight. However, if the design is not adequate, other options forconsideration are:

� Heavier wall pipe

� Large diameter pipe

� Use of a vortex suppression device

� Use of a tensioning system

The use of heavier wall or larger diameter pipe should be the first consideration,regardless of whether the limiting factor is buckling or fatigue. Some jack-ups have aconductor tensioning system to prevent buckling, although the top tension mayincrease the dynamic and fatigue stresses. It also reduces the available deck load forthe rig.

To conclude, marine conductor design is focused toward ocean/structural engineering.This is recognised as an area requiring the use of specialists, with input from theDrilling Engineer.


8.3.7 Subsea Wells

Conductor and surface casing design for a subsea well from a semi-submersible or ajack-up subsea well that is suspended/completed, requires a strong link with thewellhead design.

Specific issues that require consideration and assessment are:

� Use of 1-1/2in or heavier wall 30in wellhead extension conductor and connectorsimmediately below the wellhead (typically 40-80ft). This improves the bending loadcapability and strength, in terms of trawler load capability (typically 65 MT) and‘point of fixity’ below the seabed, as a fulcrum bending point

� Use of thicker wall material such as 0.812in wt material for the wellhead extensionand high strength connectors below the wellhead to improve the bendingload capability

� Planned use of cementation top-ups for the 30in conductor, to minimise potentialfailure or movement of the conductor during the drilling phase after the subsea BOPis installed

� Assessment of the cumulative time that a drilling unit riser and BOP system may beinstalled on the well. If it is anticipated that this could exceed 1 year for the well,then specialist studies may be required (these are highlighted as a ‘Non-Routine’case in the IP Guidelines for Subsea Operations from Floating Vessels). This mayhave an impact on the cumulative stress cycles on the wellhead/conductor system,in terms of cyclic fatigue

� Thermal loads as a result of production. In particular, HPHT wells where wellheadgrowth may identify compressive loads as an issue from thermal analysis. Thesame analysis also requires a check for wellhead/casing shrinkage when the wellcools down, leading to changes from axial compression to tension

� Thermal analysis for subsea production wells that are linked to flow lines andpipelines. This can cause movement and bending at the connection/turning pointsof the well flow lines, which in turn creates additional stresses

� Analysis of cumulative conductor and surface casing loads arising from additionalcasing strings, the wellhead, the riser and the BOP system

This last item depends on the analysis technique adopted; single string v multi-stringanalysis. Single string analysis models an individual string in terms of the pressure,axial and temperature loads and being the most pessimistic type of analysis generatesa conservative conductor design. Multi-string analysis models all casing strings as asystem, taking into account the pressures, temperatures and fluids in all annuli. Theloads of all casing strings are shared proportionally onto the conductor. This allows anaccurate assessment of wellhead growth and movement of flow lines etc.


For example, a single string analysis assumes the conductor absorbs all additionalcasing string weights on a direct cumulative basis, whereas multi-string is based on thecasing strings retaining some of the axial load and partially transferring the remainderto the conductor. This has an impact when assessing the total compressive loads onthe conductor and surface casing. This type of assessment generally requires aniterative computer analysis, by a Structural Engineer.

8.3.8 Mudline Suspension Wells

These wells are normally drilled from a jack-up rig and ensure that casing loads aretransferred from the rig to the seabed via the conductor and surface casing. Similarconditions apply in that the actual casing loads may be distributed through all of thecasing strings (as detailed above). Mudline suspension wells require that the designerconsiders the casings from the seabed to the rig connection as part of the marineconductor system. For example, the outer marine conductor is regarded as theenvironmental string, the surface casing may (subject to design) act as a diverterstring, the intermediate and production casings will act as high pressure conduits fromthe mudline, to the rig Texas deck.

8.4 TIEBACK DESIGN

This section is focused toward tieback from a fixed platform to a subsea wellhead ormudline suspension system.

8.4.1 Tieback Description

Subsea wells may be drilled using a template, above which a production platform islater installed. Such subsea wellheads can be tied back to the platform and completed.The tieback enables the casings to be run up to the platform. A typical tieback mayconsist of a 20in conductor with 13-3/8in and 9-5/8in casings. The 20in conductor(environmental string) may be free-standing, supported at the seabed by the subseawellhead and laterally (nodal points) by platform bracing guides. The 13-3/8in casingsupports the wellhead at the platform and the 9-5/8in is the production string.

8.4.2 Design Issues

The design of the tieback should consider all anticipated combinations of temperature,pressure and environmental loads, for the final ‘as installed’ condition and duringinstallation. As with a conventional production well, the tieback production casing willhave to contain the wellhead pressure if the production tubing leaks. Casing design willconsider burst, tension and collapse as with any other design but there are furtherissues to examine.


8.4.3 Thermal Growth

For a production well, the average temperature of the tubing and casing will be higherwhile producing, than when installed or shut in. Thermal expansion of the tubing andcasing will result in the surface wellhead moving upward. Also, water injection wellsgenerally exhibit downward movement owing to temperature decrease. The degree ofwellhead movement caused by thermal pressure effects is critical information fordesign of the platform topsides production piping.

8.4.4 Equipment Loads

Thermal and pressure effects can generate extreme forces on the wellhead equipmentand large changes from initial installation loads. For example, a production well withuncemented 9-5/8in casing below the subsea wellhead will normally be in tension.A large temperature increase may change this to compression, producing increasedstresses below the seabed wellhead, causing buckling or an upward motion of the9-5/8in at the seabed wellhead if a positive mechanical lockdown system is used. Thedegree of allowable buckling and stresses, if present, will require checking.

8.4.5 Pretension (9-5/8in)

The 9-5/8in production casing is generally pretensioned to ensure buckling does notoccur within the 13-3/8in and minimise motion at critical sealing surfaces. Pretensiondoes not reduce thermal growth. The extent of wellhead motion is substantiallyunaffected by the pretension but it may change the datum from where themotion starts.

Pretension is not always required, as buckling may not necessarily result in excessivebending stresses, nor prevent use of the various wellbore access tools. Reducing oreliminating pretension can also reduce centralisation requirements for the 13-3/8in(compressive load considerations). The amount of pretension needs to be based onservice conditions of the well and equipment limits.

8.4.6 Compression (13-3/8in)

The 13-3/8in casing usually supports much of the tubing weight, the 9-5/8in casing, thepretension and the weight of the production equipment. Compression will normallyoccur once installation is complete, and it is at this point buckling may occur.

The extent to which the 13-3/8in can buckle is limited externally by the 20in conductor.The internal strings, when in tension, will exercise a stabilising influence on the13-3/8in once they contact the 13-3/8in internal wall. Generally, buckling of the 13-3/8inwill result in unacceptable bending stresses, exceeding yield even within the confinesof the 20in and inner strings. The 13-3/8in is prevented from buckling by using rigidcentralisers, which provide lateral support from the 20in. Lateral supports from the 20inplatform guide frames (nodal points) and local deflections from the environmentalloads, both affect the 13-3/8in. This requires a detailed evaluation by a StructuralEngineer to determine the optimum centralisation spacing.


8.4.7 Environmental String (20in)

The main purpose of the 20in conductor is to act as the environmental string and thusisolate the 13-3/8in casing from direct environmental loads. However, it can also beconsidered as an additional compression string. By using the 20in as a compressionstring, rather than just a free-standing environmental barrier between the 13-3/8in anddirect wave loading, some of the pretension applied to the 9-5/8in string can beabsorbed. The greater vertical stiffness of the 20in and 13-3/8in acting together meansthat less overpull is required to achieve the same residual tension in the 9-5/8in. If it isnecessary to pretension the 9-5/8in, it may be possible to reduce the number ofcentralisers required for the 13-3/8in by also pretensioning the 13-3/8in. This assumesthat the 20in has spare compressive load capacity. In general, it is preferable tominimise or eliminate the need for any pretensioning. Rigidly connecting the 13-3/8inand 9-5/8in to the 20in at surface will reduce thermal growth in producing wells.However, it will tend to increase the compressive loads in the 9-5/8in due totemperature rise. This requires detailed evaluation by a Structural Engineer, todetermine and optimise the effects of all lateral and compressive loads.

8.4.8 Environmental Loads

The following items are loads that should be considered when analysing maximumstatic extremes and potential cumulative fatigue damage.

� Direct wave forces and wind or ice loads on the conductor

� Platform displacements which are imposed on the conductor by its guides

� Vibration potential from vortex shedding

� Limiting environmental conditions for conductor installation

� Service life loads eg water injection, production, gas lift, cuttings reinjection,workover, well kill. The contribution to fatigue damage of wellhead components andcasing connections associated with these service life loads is likely to be small.However, it should be assessed using a conservative estimate of operational cyclesper year

8.4.9 Pressure Effects

Pressure changes from the ‘as installed’ condition also contribute to wellheadmovement and forces in the casing strings and so should be considered for a tiebackdesign. For example, estimation and use of pressure tests for the anticipated loads andin situ production loads.


8.4.10 Temperature Effects

The temperature changes for each string should be calculated as the differencesexperienced during the set condition, ie both ends fixed whilst under the variousservice life conditions. The axial and radial temperature distributions have a majoreffect on forces in the various strings. The best estimates of these changes should beobtained by using computer software packages.

8.4.11 Operational Issues

Operational issues that require consideration are:

� Sizing: Use standard casing sizes where possible. Possible future access andassociated well control requirements should be considered in the sizing

� Platform Wellhead: Attempt to make the tieback wellhead design similar to theplatform wellhead/casing design to maximise interchangeability and to simplify wellmaintenance

� Equipment Interfaces: Ensure the vendors of subsea and surface equipment areclearly identified, including crossovers. Additionally, the design of the variousinterface components should recognise the amount of casing stretch that can occurif pretension is applied

� Procurement: Issues such as casing ovality should be assessed to ensure passageof tieback tools. The OD of special drift casing must be checked for tolerances andinternal drifts should be examined, to ensure correct sizing

� Centralisers: Rigid centralisers should assist with the installation and alignment forthe 9-5/8in (perform centraliser analysis)

� Alignment: The tieback design should be considered in conjunction with theplatform installation, construction tolerances and the verticality of the seabedwellhead/mudline system


8.4.12 Drilling/Structural Engineering Interface

The work associated with a tieback design is such that the various loads andcomponent interfaces require the input of a Structural Engineer at the start of thedesign. It is important that the Drilling Engineer accurately describes the variouscomponents and issues of the tieback to the Structural Engineer. This should bediscussed for each phase of the installation process, not just the final configuration.

The Drilling Engineer should prepare an outline estimated tieback programme. This willallow the Structural Engineer to question assumptions, magnitude and direction offorces and the capabilities of components. The Structural Engineer will also needinformation on the following issues in order to perform an adequate analysis:

� Identify casing nodal points eg existing cement tops

� Identify interfaces, which provide restrictions to the movement of the casings andtubing, eg locking mechanisms in wellhead systems and completion details

� Clarify how the interfaces should behave for both directions of relative movement,eg magnitude of free travel, manufacturer’s stated load capability and acceptabilityof load reversal at sealing surfaces

� Identify load paths in the stacked components

� Establish, review and agree the outline sequence as supplied initially, ensuring itprovides a full definition of the final configuration and the loads which thecomponents will experience at each stage of installation

� Clarify and identify the containment equipment to be used for the various pressuretests on installation of the tieback strings, eg testing against packers in the casingor against test plugs at the wellhead

� Establish and define the well life-cycle service loads

It is important that the boundary conditions and assumptions of any structural modelare discussed between the Structural and Drilling Engineers. The Structural Engineershould establish which boundary conditions are independent of loads and which maychange. Finally, the key points where forces are to be calculated to establishcomponent suitability should be discussed at an early stage with the Drilling Engineer.



SECTION 9 CASING DESIGN REPORT Page 1 of 7

TABLE OF CONTENTS

9. CASING DESIGN REPORT ................................................................................... 2

9.1 CONTENTS OF CASING DESIGN REPORT................................................... 2

9.1.1 Introduction................................................................................................. 2

9.1.2 Casing Design Method ............................................................................... 2

9.1.3 External Pressure Assumptions.................................................................. 2

9.1.4 Internal Pressures ...................................................................................... 2

9.1.5 Wellbore Geometry..................................................................................... 3

9.1.6 Temperature Criteria .................................................................................. 3

9.1.7 Temperature De-rating ............................................................................... 3

9.1.8 Pressure Enclosed Annuli........................................................................... 3

9.1.9 Design Factors ........................................................................................... 3

9.1.10 Reservoir Data............................................................................................ 3

9.1.11 Kick Tolerance Data ................................................................................... 4

9.1.12 Casing Setting Depth Chart ........................................................................ 4

9.1.13 Geology ...................................................................................................... 4

9.1.14 Contingencies............................................................................................. 4

9.1.15 Casing Design Summary ............................................................................ 5

9.1.16 Load Cases ................................................................................................ 6

9.1.17 Casing Design Ratings ............................................................................... 6

9.1.18 Dispensations............................................................................................. 6

9.1.19 Approvals ................................................................................................... 7

CASING DESIGN REPORT Page 2 of 7

9. CASING DESIGN REPORT

9.1 CONTENTS OF CASING DESIGN REPORT

The final casing design report should be able to act as a stand-alone document, toenable an independent engineer or review to identify the principles, processes andassumptions used in generating the final casing design. It should be noted that muchof the information included within the report will have been prepared and verified duringthe design and will include the following documents:

� Pre Drill Data Package (PDDP)

� Well Design Data Summary Sheet

� Well Design Check List (WDCL)

A suggested format is included below, to enable a systematic approach to an audit trailfor the casing design.

9.1.1 Introduction

Briefly explain the type of well, where it is, location and co-ordinates, for example,vertical exploration well or subsea directional development well. Link this informationto the PDPP and the WDCL. Highlight key issues, such as sour service, high pressure,high temperature (HPHT), deep water, open/sealed annuli, etc. The purpose of theintroduction should be to set the scene for the reviewer and final authority.

9.1.2 Casing Design Method

Explain how the design was performed. For example, API hand calculations, and/orprimarily performed by a computer software package, due to the requirement ofproduction loads and anticipated high thermal loads.

9.1.3 External Pressure Assumptions

Highlight the source of data and assumptions used in generating the pore pressureand fracture profiles. List specific concerns or safety issues, such as loss zones,overpressured or depleted zones. List the best offset control wells for the designassumptions.

9.1.4 Internal Pressures

List the minimum and maximum mud weights and packer fluids to be utilised for thedesign. Note the mud type: oil based or water based mud. This is important, as it hasan influence on the external back-up pressures to be utilised if a development well forlong-term load assessment (eg degraded base oil or water gradient).


9.1.5 Wellbore Geometry

Briefly discuss the wellbore profile; including specific areas of high dogleg severityand potential casing wear. Highlight the allowances adopted for casing wear andkey methods of prevention. Summarise, if necessary, impact on wellbore safetyif anticipated casing wear limits could be breached. This section may requireadditional information or actions. For example, if re-entering an old well that hasbeen drilled through a number of times, the casing string may need a datum casingwear/corrosion caliper.

9.1.6 Temperature Criteria

Summarise the temperature predictions/profile. Identify where the profile was obtainedand any implications for the well design. For example, production thermal loadsimpact on temperature to material selection, particularly if a corrosive environmentis anticipated.

9.1.7 Temperature De-rating

Highlight if the casing strings have been de-rated for temperature as part of the welldesign and by how much.

9.1.8 Pressure Enclosed Annuli

Explain impact of potential trapped and sealed annuli on the design. For example,thermal loads on subsea wells during production. Link to production policyrequirements if required.

9.1.9 Design Factors

List the standard Repsol design factors applicable to the casing design. For example, ifthe design was carried out based on API hand calculations, triaxial and compressionmay not apply. If however, a full computer software design was performed includingtriaxial and compression, include the actual design factors.

9.1.10 Reservoir Data

Highlight the assumptions used for the reservoir data, including gradients andtemperature. This will be linked to the PDDP.


9.1.11 Kick Tolerance Data

List as a table, the maximum calculated kick tolerance for each casing string. List anyassumptions made, including:

� LOT requirements

� BHAs

� Kick influx data (this may require revision and re-assessment during the drilling ofthe well and have an impact on the casing design)

Record, if applicable, a blowout scenario summary for HPHT wells (refer to IP 17 forinformation and guidance on this issue).

9.1.12 Casing Setting Depth Chart

Provide the finalised casing setting depth chart, developed from the initial casing shoesetting depths. Summarise the rationale of moving casing shoes up or down relative tothe final design. For example, requirement to case off a permeable loss zone prior, toentering an increasing pore pressure regime.

9.1.13 Geology

Summarise the key geological data relative to the casing design. Examples could be:

� Conductor depth will be 6 joints, based on weak formations, to allow drilling tosetting depth for surface casing

� Borehole stability may identify azimuth control as an issue. Drilling a developmentwell at a certain azimuth may cause borehole collapse

� The seismic error bars for certain formations may be large, having an influence ona casing shoe and kick tolerance

9.1.14 Contingencies

Confirm if the casing design is valid for a sidetrack contingency, planned or unplanned.For example, highlight if the design of an exploration well is valid as a potentialproducer. List constraints on the design, which may alter its the use from the initialplanned requirement. Confirm if the pressure regime and well objectives would be validif a sidetrack was performed.


9.1.15 Casing Design Summary

List as a table the final casing design for the well. Use the following example as aguide only:

HO

LES

IZE

(inch

es)

CA

SIN

GS

IZE

(inch

es)

INS

IDE

PIP

ED

IAM

ET

ER

(inch

es)

INT

ER

VA

LS

ET

: FR

OM

-T

O (

feet

)

GR

AD

EW

EIG

HT

(lb/ft

)C

ON

NE

CT

ION

CO

NN

EC

TIO

NID

(in

ches

)T

OP

OF

CE

ME

NT

(fee

t)

CA

SIN

GP

RE

SS

UR

ET

ES

T (

psi)

MIN

IMU

MLO

TR

EQ

UIR

ED

(ppg

)

36in

30in

27in

300f

t to

340f

tX

5245

7R

L-4

26.9

7in

Sea

bed

N/A

N/A

36in

30in

28in

340f

t to

540f

tX

5231

0R

L-4

27.5

0in

Sea

bed

N/A

N/A

26in

20in

18.7

5in

300f

t to

2,00

0ft

X56

129

SR

-20

18.6

3in

Sea

bed

1,00

011

.0

17-1

/2in

13-3

/8in

12.4

15in

300f

t to

5,00

0ft

N-8

068

AP

I But

tres

s12

.415

in2,

000f

t3,

000

13.0

12-1

/4in

9-5/

8in

8.68

1in

300f

t to

9,00

0ft

L-80

47P

rem

ium

New

Vam

Che

ck w

ithm

anuf

actu

rer

8.95

7in

7,50

0ft

4,50

014

.0

8-1/

2in

7in

6.18

4in

8,50

0 to

10,

000

L-80

29P

rem

ium

New

Vam

Che

ck w

ithm

anuf

actu

rer

6.35

0in

8,50

0ft

0.5p

pg o

ver

LOT

N/A


Include a Casing Design Schematic with water depth (if offshore); cement tops,anticipated LOTs, casing weights/grades and minimum bit drift diameter.

List the inspection criteria required for the casing relative to the purchase order. Forexample, will all of the casing strings be ordered to API standards and if so, which onesapply? Will there be special requirements on the order? An example could be, the APIwall thickness will be a tighter specification to 0.90 as opposed to 0.875 minimum wallthickness.

9.1.16 Load Cases

Discuss the load cases for each casing string. Highlight unusual load cases that wereused for the well design. Link the load cases to the required Design factors. Examplescould be:

� Use of high collapse casing to combat mobile salt zone based on full evacuation,with maximum overburden gradient of 1.0psi/ft

� 9-5/8in casing will be pressure tested (wet test) to full requirement, immediatelyafter confirmation of cement plug bump. Impacts design by increasing axial loads

� Calculated collapse rating for the 20in is 0.99 but is justified, based on the fact thatit assumes total evacuation; offset data suggests the likelihood of total losses andfull evacuation is low risk and casing hydrostatic can be maintained with seawater

9.1.17 Casing Design Ratings

List the actual ratings obtained for all casing strings, for each load case relative to theRepsol design factors. They should be tabulated where possible and will provide acheck that the load cases satisfy the Minimum design factors. This should includeBurst, Collapse, Tension and, if appropriate, Compression and Triaxial. The objectiveof this section is to confirm that the calculated ratings for all load cases are > (greaterthan) the Repsol Minimum design factors.

9.1.18 Dispensations

List and record any dispensations or issues that may be required for the casing design.Include specific file notes and confirmation of acceptance by senior managementshould certain issues be outside the Repsol policies.

If no dispensations are required, then record the section as ‘None Required’. However,the designer should be aware that during the drilling of the well, the casing designmight change or encounter loads outside the approved design.


9.1.19 Approvals

Approval of the final design will depend on the Repsol drilling management structure inplace for an operating region. However, as a guide, it will be along the lines ofthe following:

Name (Signature)

Originated by: /

Checked/ Reviewed by:

Approved by:

Appendices:

The Casing Design Report should include a number of documents as part of the welldesign because it must act as a stand-alone document. The additional information willdepend upon the complexity of the well. However, as a guide the report should includethe following:

� Pre Drill Data Package (PDDP)

� Well Design Data Summary Sheet

� Actual Casing Design, Well Design Check List (WDCL)

� Pipe Manufacturer Specification Data Sheets, including Connection Data(API and non-API)

� Calculations/Computer Printouts

Additional reports of specialist studies (eg Conductor Analysis, Thermal Simulations,HPHT third party design on computer software).



SECTION 10 EXAMPLE CASING DESIGN Page 1 of 66

TABLE OF CONTENTS

10. EXAMPLE CASING DESIGN................................................................................. 3

10.1 PRELIMINARY DESIGN ................................................................................. 3

10.1.1 Input Data ................................................................................................ 3

10.2 DETAILED DESIGN........................................................................................ 8

10.2.1 20in Conductor......................................................................................... 8

10.2.1.1 Tension Loads............................................................................................ 8

10.2.1.2 Collapse Load ............................................................................................ 9

10.2.1.3 Burst Loads .............................................................................................. 10

10.2.2 13-3/8in Intermediate Casing ................................................................. 10

10.2.2.1 Tension Loads.......................................................................................... 11

10.2.2.2 Burst Loads .............................................................................................. 13

10.2.2.3 Collapse Loads......................................................................................... 16

10.2.3 9-5/8in Production Casing...................................................................... 17

10.2.3.1 Tension Loads.......................................................................................... 18

10.2.3.2 Burst Loads .............................................................................................. 20

10.2.3.3 Collapse Loads......................................................................................... 27

10.2.4 7in Liner ................................................................................................. 28

10.2.4.1 Tension Loads.......................................................................................... 29

10.2.4.2 Burst Loads .............................................................................................. 31

10.2.4.3 Collapse Loads......................................................................................... 35

10.3 FINAL CASING DESIGN............................................................................... 37

10.4 FINAL DESIGN CHECK................................................................................ 37

10.4.1 20in Conductor....................................................................................... 37

10.4.2 13-3/8in Intermediate Casing ................................................................. 38

10.4.2.1 Tension Loads.......................................................................................... 38

10.4.2.2 Burst Loads .............................................................................................. 40

10.4.2.3 Collapse Loads......................................................................................... 44

EXAMPLE CASING DESIGN Page 2 of 66

10.4.3 9-5/8in Production Casing...................................................................... 45

10.4.3.1 Tension Loads.......................................................................................... 46

10.4.3.2 Burst Loads .............................................................................................. 49

10.4.3.3 Collapse Loads......................................................................................... 56

10.4.4 7in Liner ................................................................................................. 57

10.4.4.1 Tension Loads.......................................................................................... 58

10.4.4.2 Burst Loads .............................................................................................. 60

10.4.4.3 Collapse Loads......................................................................................... 63


10. EXAMPLE CASING DESIGN

10.1 PRELIMINARY DESIGN

Preliminary design consists of four individual stages:

� Examination of the geological data and offset data

� Investigation of the well objectives

� Examination of additional constraints

� Fitting of a suitable casing scheme to the well requirements

The first two of these items are provided directly by the operating company.

The third item, additional constraints, may come from the operating company,governmental departments, regulatory bodies or may be imposed by physical oreconomic conditions. For an offshore well, such conditions may require that the well bedrilled from an existing structure, requiring some form of directional profile. For anonshore well, the surface location directly above the target may be in the middle of atown, lake, swamp or other physical restriction. There may be an existing drilling facilityfrom which the well can (or must) be drilled. Surface facilities, including road and rail,electrical power supply, water, oil and gas pipelines, and communications can all play apart in surface location positioning and of the well path.

The well objectives will primarily control the size of the casing through the reservoir.For a purely exploration well and in general, the smaller the hole diameters to bedrilled, the better. Smaller hole sizes, for the same hole depth, require lower rateddrilling rigs, less lifting and rotating power, smaller mud systems, less cuttings volumeremoval, smaller (and hence cheaper) casing strings. (Against these must be set thepossible requirement to change out drillstring components for different sections, BHAcomponent and logging tool availability, and increased risk with reduced kicktolerance.) For a production well the final casing (or liner) size will be determined by theestimated production profile and the completion required.

Once all of the requirements and constraints have been examined, a well course andpreliminary casing design may be determined.

10.1.1 Input Data

Figure 10.1 shows an example of a Well Design Data Summary Sheet, as may beproduced for a particular well. The main information contained on this, from the basis ofcasing design, are the Pore Pressure and Fracture Gradient curves.

EX

AM

PLE

CA

SIN

G D

ES

IGN

Page 4 of 66

Figure 10.1 - D

esign Data S

umm

ary Sheet

WELL SUMMARY PROGNOSIS AND RESULTS WELL: AA12 (Example) COMPANY: Repsol DATE:..01/01/2000

DEPTH PROGNOSIS COMMENTSPORE PRESSURES, MW, LOT DATA

PREDICTIONS

Originator

......./......./.......

Superv isor Checked and Agreed

......./......./......

Or ig inator

......./......./.......

Dr i l l ing Engineer

......./......./.......

Genera lRefe rence Datum

Chr

ono

Str

at

For

mat

ions

Tra

ject

ory

Tar

gets

Cas

ing

Lith

olog

yan

d F

ault

s

Hyd

roca

rbon

s

Markers(2 way t ime. depth -accuracyof predict ion. Faul ts)andC o m m e n t s(source rocks,structural dips)

Decis ions /Pol icy

Remarks / CommentsTo be dr i l led as explorat ion wel l but may possiblybe completed for product ion i f tests show longterm potent ia l

TD / Abandonment Dec is ion

Wel l s i te geologist

Pore pressures and f racture data based on of fsetwel ls : - BGF3 (dr i l led 1995) and NJHY2 (dr i l led1997)

Side Wal l Samples / Di tch Cut t ings

R F T

Dri l l Stem Tests / Product ion TestsA dr i l l s tem test using annular pressure operatedtools wi l l be performed on any potent ia l lyproduct ive zone.

Mud logg ing / MWD

V S P

Logg ing

4,0002,000

PSI

5000

10000

5000

1000

0

T V D

Ft m Pre

dict

ed

Act

ual

1000

2000

3000

4000

Well Design Data Summary Sheet

6,000 8,000 10,000

FractureGradient

PorePressureGradient

Sha

leLi

mes

tone

Sha

leIn

terb

edde

dS

and

and

Sha

le


Additional information required for the design (and the assumptions used for thisexample) are:

� A vertical land well

� Target depth: 12,000ft TVD

� The geothermal gradient: 18�F per 1,000ft – surface temperature 60�F x bottomhole temperature = 276�F

� Bottom hole pressure (Shut-in) = 8,600psi (13.78ppg EMW)

� The final casing or liner size: 7in (based on possible production and the availabilityof DST tools)

� Use of a liner over the reservoir section, with a 500ft overlap

� 5in liner as contingency, in case the 7in has to be set high

� The cement mix water has a density of 9.0ppg

� Although the well is vertical, a bending load of 2�/100ft has been assumed forFbend, to allow for deviations from verticality

Once the data described above is analysed, the first requirement is to convert the PorePressure and Fracture Gradients to equivalent mud weights versus depth and to plotthese, as shown in the schematic in Figure 10.2, for the equivalent mud weight profiles.

Parallel to the Pore Pressure Gradient, we draw the minimum weight line, offset bythe trip margin (commonly either 500psi or 0.5ppg mud equivalent). Parallel to theFracture Gradient, we can draw a ‘Design’ Fracture Gradient, allowing a safe marginfor additional cementing loads and a possible gas kick.

These two lines control the acceptable load ranges, both maximum and minimum,which can be safely imposed on the formation at any depth. The segmented sectionindicates the load lines for casing shoe location. This indicates that, with the linershoe at 12,000ft, the production casing shoe must be deeper than ±7900ft, and theintermediate casing shoe must be deeper than ±3800ft. The conductor string must beset sufficiently deep to be able to support any mechanical drilling, or casing loadsimposed on it. For the sake of this example we will assume a conductor setting depthof 400ft but such depth would depend on the nature of the near-surface formations.Similarly, the surface BOP stack dimensions and availability, plus any additionalexternal loads, would determine the actual diameter of the conductor. For this examplewe will assume a 20in, H-40, 94 lb/ft conductor.

The remaining part of the casing design process is to calculate the forces for eachof the potential loads and select appropriate weights and grades of casing, withinacceptable safety margins. It is possible, under extreme circumstances, that during thedesign process no combination of weight and grade exists which will be acceptable, orthat such a combination is available but creates mechanical difficulties for anothercasing string. In such a case, the load cases should be examined in order to determineif an alternate casing design is necessary. Senior personnel must ultimately make suchdecisions.

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IGN

Page 6 of 66

Figure 10.2 - M

ud Weight E

quivalent Profiles

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

8 10 12 14 16 18 20

A

ProductionLiner

ProductionCasing

IntermediateCasing

Conductor

Fracture Gradient

Design Fracture GradientIncluding Kick andCementing Margin

Mud Weight Curve

Pore PressureGradient

Equivalent Mud Weight, ppg

True

Ver

tical

; Dep

th (

TVD

), f

t

E


Note that the casing design has started ‘Bottom Up’ to allow for production constraints.The detailed design proceeds from the top down. This system is referred to as ‘TopDown, Bottom Up’ design.

We have thus determined that the desired casing strings are as follows:

PR

OP

OS

ED

CA

SIN

G S

CH

EM

ED

EP

TH

–T

VD

(fee

t)

CE

ME

NT

TO

P T

VD

(fee

t)H

OLE

SIZ

E(in

ches

)

MA

XIM

UM

MU

DW

EIG

HT

S(p

pg)

PO

RE

PR

ES

SU

RE

EM

W(p

pg)

FR

AC

TU

RE

PR

ES

SU

RE

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10.2 DETAILED DESIGN

10.2.1 20in Conductor

20in H-40, 94 lb/ft casing has the following minimum mechanical properties (as definedin API Bulletin 5C2):

� Collapse Resistance = 520psi

� Internal Yield Pressure = 1,530psi

� Body Yield Strength = 1,077 x 103 lb

� Joint Yield Strength = 581 x 103 lb (for short, round threaded(SRT) and coupled connection)

� Outer Diameter = 20in

� Nominal Inside Diameter = 19.124in

� Drift Diameter = 18.936in

10.2.1.1 Tension Loads

Fwt: String Weight (in air) = 94 x 400 = 37,600 lb

Mud weight for running casing = 9.5ppg

10.2.1.1.1 Installation: Running Casing

Fbuoy: Buoyancy Load = Pe (Ao – Ai) (Based on open ended pipe,as casing is filled during running operations.Therefore, mud pressures inside and outsideare the same).

Fbuoy: Buoyancy Load = 9.5 x 400 x 0.052 x ((� x 202/4) – (� x 19.1242/4))� -5,346 lb

Note: Buoyancy has been calculated as a negative load force throughout thisexample.

Fbend: Bending Load = 64 x 2 x OD x W = 64 x 2 x 20in x 94 lb/ft= 1240,640 lb


Fshock: Shock Load is unknown, so a Design Factor of 1.6 will be used.

Ft: Total Installation Load = (String Weight + Buoyancy Load + Bending Load + Shock Load) x Design Factor

= (37,600 – 5,346 +240,640 + 0) = 272,894 x 1.6 = 436,630 lb

(This is < 581,000 lb of the SRT joint strength) SAFE

Actual Design Factor = 581,000/272,894= 2.12

10.2.1.2 Collapse Load

10.2.1.2.1 Cementing (Stab-in)

Assume cementing with 15.0ppg cement. Cement displaced up the annulus backto surface.

Pe: External Pressure at shoe = Hydrostatic of cement column = 400 x 15 x 0.052= 310psi

Pi: Internal Pressure at shoe = Hydrostatic of mud column = 400 x 9.5 x 0.052 = 200psi

Design Factor = 1.0

Pc: Differential (Collapse)pressure = (310 – 200) x 1 = 110psi

Actual Design Factor = 520/110 = 4.72 (This is < 520psi the collapse resistance)SAFE

10.2.1.2.2 Full Evacuation to Air

Pi: Internal Pressure = 0psi

Pe: External Pressure = Hydrostatic mud column (using mud weight prior to cementing)

= 400 x 9.5 x 0.052= 200psi

Design Factor = 1.0

Pc: Differential (Collapse)pressure at shoe = (200 – 0) x 1 = 200psi

(This is < 520psi, the collapse resistance)SAFE

Actual Design Factor = 520/200= 2.60


10.2.1.3 Burst Loads

10.2.1.3.1 Cementing (Stab-in)

No burst loads are imposed on the casing during stab-in cementing.

10.2.1.3.2 Bumping Cement Plug (to, say 500psi)

Burst loads are imposed on the stab-in drillstring, not the casing.

10.2.1.3.3 Casing Pressure Test after WOC

No pressure test is planned for this string, as it is a conductor.

However, if required, it could withstand an internal pressure of c.1,200psi. This wouldbe much less than the 80% pressure testing criteria. (Burst rating is 1,530psi.)

10.2.2 13-3/8in Intermediate Casing

The 13-3/8in intermediate casing will be set at 4,500ft and cemented back to surface.After cementing and pressure testing, the shoe will be drilled out and the casing will besubjected to the drilling and well control loads encountered during the drilling of thenext section. We must consider each of these loads separately. Many of these loads,however, are tensile loads which depend on the casing weight. In order to calculatethese loads we must start by assuming a realistic casing weight, which may later beamended, as we progress with the detailed analysis.

As an initial start, we will assume the 13-3/8in casing to be K-55 material and61 lb/ft weight.

13-3/8in, K-55, 61 lb/ft casing has the following minimum mechanical properties (asdefined in API Bulletin 5C2):

� Collapse Resistance = 1,540psi


� Body Yield Strength = 962 x 103 lb

� Joint Yield Strength (SRT) = 633 x 103 lb

� Outer Diameter = 13-3/8in





10.2.2.1.1 Installation: Running

Fwt: Dry Weight = 4,500 x 61= 274,500 lb

Fbuoy: Buoyancy(with 10.0ppg mud) = 10 x 4,500 x 0.052 ((� x 13.3752/4) –

(� x 12.5152/4))= -40,950 lb

(Open ended pipe as casing filled with 10ppg mud, Pe and Pi same)

Fbend: Bending Force = 64 x DLS x OD x W = 64 x 2 x 13-3/8 x 61= 104,432 lb

Fshock: Shock Load = 0 lb (shock load not calculated)

Design Factor(no shock load correction) = 1.6

Ft: Total Load = Dry Weight + Buoyancy + Bending =(274,500 – 40,950 + 104,432) x 1.6

= 540,771 lb(This is < the SRT Joint Strength)SAFE

Casing body yield strength is 962,000 lb, and SRT casing is 633,000 lb. Buttress is1,169,000 lb. SAFE.

10.2.2.1.2 Installation: Running and Overpull

Fop: Assume an overpull of 100,000 lb.

Design Factor = 1.4

Ft: Total Load = (Dry Weight + Buoyancy + Bending + Overpull) x 1.4 = (274,500 – 40,950 +104,432 + 100,000) x 1.4

= 613,175 lb(This is < SRT Joint Strength)SAFE


10.2.2.1.3 Plug Bump after Cement Displacement

Fplug: Plug bump to 2,000psi.

Cement is to surface and is still wet. Assume 16.0ppg cement.

Design Factor = 1.4

Fbuoy = 16ppg cement outside to surface and 10ppg mud inside

Ft: Total Load = Fwt – Fbuoy + Fbend + Fplug

Fbuoy = (Pe x Ao) – (Pi x Ai) = Pe x (� x 13.3752/4) – Pi x(� x 12.5152/4)(Closed end pipe)

Fbuoy = (16 x 4,500 x 0.052 x 140.50) – (10 x 4,500 x 0.052 x 123)= 526,032 – 287,820= - 238,212 lb)

Note: This is a negative value.

Fplug = Psurf x Ai = 2,000 x 123 = 246,000 lb

Ft: Total Load = 274,500 – 238,212 + 104,432 + 246,000= 386,720 x 1.4= 541,408 lb

(This is < the SRT Joint Strength)SAFE

10.2.2.1.4 Installation: Pretension after Waiting on Cement

The string will be cemented back to surface, so this does not apply.



Cemented to surface with 16.0ppg cement. Hole drilled with 10.0ppg mud.

10.2.2.2.1 Installation: Cement Displacement

Psurf: Assume cement displacement pressure of 1,000psi.

External Volume = (4,100 x 0.1237) + (400 x 0.1814)= 580bbl

Total cement pumped(with 10% excess) = 580 x 1.1

= 638bbl

Equivalent height in13-3/8in, 61 lb/ft casing = 638/0.1521

= 4,195ft

Pe: External Pressure = Mud Hydrostatic = 4,500 x 10 x 0.052= 2,340psi

Pi: Internal Pressure = Cement Hydrostatic + Mud Hydrostatic +Displacement Pressure

= (4,195 x 16 x 0.052) + (305 x 10 x 0.052) + 1,000= 4,649psi

Design Factor = 1.1

Pb: Differential(Burst) Pressure = (4,649 – 2,340) x 1.1

= 2,309psiSAFE(The internal yield pressure of 13-3/8in, K-55, 61 lb/ft casing is 3,090psi)

10.2.2.2.2 Installation: Plug Bump

Psurf: Plug bump to 2,000psi after installation.

Pe: External Pressure = Wet Cement Hydrostatic= 16 x 4,500 x 0.052= 3,744psi

Pi: Internal Pressure = Mud Hydrostatic + Plug Bump= (10 x 4,500 x 0.052) + 2,000= 4,340psi

Design Factor = 1.1


= 656psiSAFE(This is < the burst rating of the casing, 3,090psi)


10.2.2.2.3 Drilling: Casing Pressure Test after WOC

Psurf: Test Pressure = 2,000psi

Pe: External Pressure = Cement Mix Water Hydrostatic= 4,500 x 9.0 x 0.052= 2,106psi

Pi: Internal Pressure = Mud Hydrostatic + Test Pressure= (10 x 4,500 x 0.052) + 2,000= 4,340psi

Design Factor = 1.1


= 2,457psiSAFE(This is < the burst rating of the casing, 3,090psi)

10.2.2.2.4 Drilling: Leak-off Test after Drilling Out Shoe

13-3/8in Leak-off test to 12.5ppg equivalent mud weight, with 10.0ppg mud left inthe hole.

Test Margin(safety margin on LOT) = 0.5ppg. Therefore, maximum value is 13.0ppg

Psurf: Surface TestPressure = (12.5 + 0.5 - 10) x 4,500 x 0.052

= 702psi

Pe: External Pressure = Cement Mix Water Hydrostatic= 9.0 x 4,500 x 0.052= 2,106psi

Pi: Internal Pressure = Mud Hydrostatic + 702= (10 x 4,500 x 0.052) + 702= 3,042

Design Factor = 1.1

Pb: Differential(Burst) pressure = (3,042 – 2,106) x 1.1

= 1,030psiSAFE(This is < the burst rating of the casing, 3,090psi)


10.2.2.2.5 Drilling: 100bbl Gas Kick from the 12-1/4in Casing Shoe

Depth of Hole (next shoe) = 8,000ft in 12-1/4in hole

Mud Weight = 11.4ppg

Pore Pressure atnext shoe = 10.87ppg EMW

LOT at this shoe+ 0.5ppg Test Margin = 13.0ppg EMW

BHP at next shoe = 10.87 x 8,000 x 0.052= 4,522psi

Kick Volume = 100bbl

K (BHP x Kick Volume) = 452,200

Influx Gradient = 0.1psi/ft

Assuming 300ft of 6-3/4in drill collars, and the remainder 5in drill pipe.

Height of Influx = 793ft

Initial Shut-in Pressure S = BHP � (Mud Hydrostatic + Gas Hydrostatic)= 4,522 – (11.4 x 7,207 x 0.052) + (793 x 0.1)= 329psi

Where definitions of the terms are given in Section 6 of the Casing Design Manual:

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Note: Additional calculation indicates a maximum kick volume approximately 100bbl,above which failure would occur at the shoe. Refer to Well Control Manual forappropriate calculation details. The 100bbl kick load could dominate the burst,so the test pressure for the casing will be 2,000psi.


10.2.2.3 Collapse Loads

10.2.2.3.1 Cementing

Pe: External Load = Cement Hydrostatic to Surface= 16 x 4,500 x 0.052= 3,744psi

Pi: Internal Load = Mud Hydrostatic= 4,500 x 10 x 0.052= 2,340psi

Design Factor = 1.0

Pc: Differential(Collapse) Load = (3,744 – 2,340) x 1.0

= 1,404psiSAFE(Collapse resistance of 13-3/8in, K-55, 61 lb/ft casing is1,540psi)

10.2.2.3.2 Drilling: Full Evacuation to Air

Pe: External Pressure = Hydrostatic Pressure of mud used when cementing casing

= 10 x 4,500 x 0.052= 2,340psi

Pi: Internal Pressure = 0psi (Air)

Design Factor = 1.0

Pc: Differential(Collapse) Pressure = (2,340 – 0) x 1.0

= 2,340psiFAIL(For 13-3/8in, K-55, 61 lb/ft casing collapse is 1,540psi)

Once a casing string design has failed for a particular load condition then there aretwo options:

� Consider load case and assess probability/risk of occurrence. If risk is low thensome relaxation of the load criteria may be acceptable, provided that managementapproves this

� Upgrade casing to a grade and weight which can pass the particular load condition

For this particular example, there is no higher weight of casing of the same grade thatwill pass the full evacuation criteria, so we need to increase both the weight and grade.


Our second choice of casing is therefore 13-3/8in, C-75, 72 lb/ft casing with a pipebody yield strength of 1,558klb, an internal yield pressure of 5,040psi and collapseresistance of 2,590psi. The buttress joint strength is 1,598klb, which is greater than thepipe body strength and so will be utilised as the connector.

Since all of these parameters are higher than the previous design calculations, thecasing will pass each of the load tests. It is not necessary, at this stage, to recalculatethe load cases but it will need to be done later to determine the final actual designfactors for the casing string.

10.2.3 9-5/8in Production Casing

The 9-5/8in production casing will be set at 8,000ft and cemented back into the13-3/8in casing. After cementing and pressure testing, the shoe will be drilled out andthe casing will be subjected to the drilling and well control loads encountered during thedrilling of the next section. We must consider each of the loads separately. Many ofthese loads, however, are tensile loads which depend on the casing weight. In order tocalculate the loads we must start by assuming a realistic casing weight which may laterbe amended as we progress with the detailed analysis.

As an initial start, we will assume the 9-5/8in casing is C-75 material and 47 lb/ft weightand cemented back to 4,000ft (500ft above the 13-3/8in shoe, with 16.0ppg cement).

9-5/8in C-75 material and 47 lb/ft weight casing has the following minimum mechanicalproperties (as defined in API Bulletin 5C2):




� Joint Yield Strength (Buttress) = 1,098 x 103 lb








Fbuoy: Buoyancy(with 11.4 ppgmud) = Pe (Ao – Ai)

= 11.4 x 8,000 x 0.052 ((� x 9.6252/4) – (� x 8.6812/4))(Open ended pipe)

Fbuoy = 4,742 (72.8 – 59.2)= -64,491 lb

(Based on Pe and Pi the same, as the casing is filled completely when run)

Fbend: Bending Force = 64 x DLS x OD x W= 64 x 2 x 9.625 x 47= 57,904 lb

Fshock: Shock Load = 0 lb (Shock load not calculated)


Ft: Total Load = Dry Weight + Buoyancy + Bending= (376,000 – 64,491 + 57,904) x 1.6= 591,061 lb

SAFE

Casing body yield strength is 1,018klb, and Buttress threaded casing is 1,098klb.SAFE.



Design Factor = 1.4

Ft: Total Load = (Dry Weight + Buoyancy + Bending + Overpull) x 1.4= (376,000 – 64,491 + 57,904 + 200,000) x 1.4= 797,178 lb

SAFE

Casing body yield strength is 1,018klb, and Buttress threaded casing is 1,098klb.SAFE.




Cement top is to 4,000ft (500ft inside the 13-3/8in shoe and is wet slurry). Assume16.0ppg cement.

Design Factor = 1.4

Fbuoy: = 11.4ppg mud down to 4,000ft plus 16ppg cement to casing shoe outside and 11.4ppg mud inside


Fbuoy = (Pe x Ao) – (Pi x Ai)= Pe (� x 9.6252/4) – Pi (� x 8.6812/4) (Closed end pipe)= ((11.4 x 4,000 x 0.052) + (16 x 4,000 x 0.052)) x 72.8) –

(11.4 x 8,000 x 0.052 x 59.2)= ((2,371+ 3,328) x 72.8) – (4,742 x 59.2)= 414,887 – 280,726= -134,161 lb


Fplug = Psurf x AI

= 2,000 x 59.2= 118,400 lb

Ft: Total Load = 376,000 – 134,161 + 57,904 + 118,400= 418,143 x 1.4= 585,400 lb

(Casing body yield strength is 1,018klb, Buttress threadedcasing is 1,098klb)

SAFE


This is the ‘as cemented’ base case Ftbase.

Ftbase = Fwt – Fbuoy + Fbend + Fpretension

Fpretension = Pretension of 60,000 lb

Design Factor = 1.4

Ft: Total Load = (Dry weight + Buoyancy + Bending + Pretension) xDesign Factor

Ft: Total Load = (376,000 – 134,161 + 57,904 + 60,000)= 359,743 x 1.4= 503,640 lb

(Casing body yield strength is 1,018klb, Buttressthreaded casing is 1,098klb)SAFE



Cemented back to 4,000ft with 16.0ppg cement. Hole drilled with 11.4ppg mud.



External volume tobe cemented(9-5/8 shoe to 4,500ft) = (4,000 x 0.0558) + (500 x 0.0580)

= 252bbl


= 277bbl


= 3,784ft

Pe: External Pressure = Mud Hydrostatic= 8,000 x 11.4 x 0.052= 4,742psi


= (3,784 x 16.0 x 0.052) + (4,216 x 11.4 x 0.052) + 1,000= 6,648psi

Design Factor = 1.1


= 2,097psiSAFE(Internal Yield Pressure of 9-5/8in, C-755,47 lb/ft casing is 6,440psi)


10.2.3.2.2 Installation: Plug Bump to 2,000psi

Pe: External Pressure = Cement Hydrostatic + Mud Hydrostatic= (4,000 x 16.0 x 0.052psi) + (4,000 x 11.4 x 0.052)= 5,699psi

Pi: Internal Pressure = Mud Hydrostatic + Plug Bump= (11.4 x 8,000 x 0.052) + 2,500= 6,742psi

Design Factor = 1.1


= 1,147psiSAFE(Internal Yield Pressure of 9-5/8in, C-755,47 lb/ft casing is 6,440psi)


Test Pressure = 3,500psi

Pe: External Pressure = Cement Mix Water Hydrostatic + Mud Hydrostatic= (4,000 x 9 x 0.052) + (4,000 x 11.4 x 0.052)= 4,243psi

Pi: Internal Pressure = Mud Hydrostatic + Test Pressure= 11.4 x 8,000 x 0.052 + 3,500= 8,242psi

Design Factor = 1.1


= 4,399psiSAFE(Internal Yield Pressure of 9-5/8in, C-75, 47 lb/ft casingis 6,440psi)



Leak-off Test to 15.0ppg, equivalent mud weight. With 11.4ppg mud in hole.

Test Margin(safety margin on LOT) = 0.5ppg

Surface Test Pressure = (15.0 + 0.5 - 11.4) x 8,000 x 0.052= 1,706psi


Pi: Internal Pressure = Mud Hydrostatic + 1,750= (11.4 x 8,000 x 0.052) + 1,706= 6,448psi

Design Factor = 1.1

Pb: Differential(Burst) Pressure = (6,448 – 4,243) x 1.1 = 2,426psi

SAFE(Internal Yield Pressure of 9-5/8in, C-75, 47 lb/ft casingis 6,440psi)

10.2.3.2.5 Drilling: 100bbl Gas Kick from Next Casing Shoe




LOT at this shoe +Test Margin = 15.5ppg EMW






Assuming 300ft of 6-3/4in drill collars, and the remainder 5in drill pipe.

Height of Influx = 2,800ft

Initial Shut-in Pressure S = BHP � (Mud Hydrostatic + Gas Hydrostatic)= 8,600 – (14.3 x 9,200 x 0.052 + 2,800 x 0.15)= 1,339psi

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Pressure of influx at surface for initial shut-in (using formula of design manual)= 3,005psi.SAFE (provided that casing previously tested above this value).

10.2.3.2.6 Drilling/Testing/Production: Gas to Surface

Pe: External Load = Cement Mix Water Hydrostatic + Mud Hydrostatic= (4,000 x 9 x 0.052) + (4,000 x 11.4 x 0.052)= 4,243psi

Pi: Internal Load = Formation Pressure (8,600psi) – Gas Gradient(0.15psi/ft)

= 6,800psi at Surface

Note: This is the anticipated maximum Shut-in Tubing Head Pressure (SITHP).

= 7,925psi at 7,500ft (Liner top)

Pb: Differential(Burst) Pressure (Surface) = (6,800 – 0) x 1.1

= 7,480psiFAIL(The burst for 9-5/8in C-75, 47 lb/ft is 6,440psi)

Pb: Differential(Burst) Pressure (7,500ft) = (7,925 – 4,243) x 1.1

= 4,050psiSAFE


Casing requires upgrading due to this burst load case.

Note: 9-5/8in, C-75, 53.5 lb/ft casing has the following minimum mechanical properties(as defined in API Bulletin 5C2).








Note: Order as special drift for an 8.50in bit.

In terms of a uniaxial burst design, this would possibly be acceptable, as it is so closeto the required DF of 1.1 (in this case it is 1.093 based on 7,430/6,800).

However, the complete well design does not include allowances for casing wear andtemperature effects. This will require final assessment, once all strings are tabulatedand may require further casing upgrade.

10.2.3.2.7 Testing/Production: SITHP on Packer Fluid

This is based on a DST with the 14.3ppg drilling mud as the packer fluid and the DSTstring leaks at surface into the 9-5/8in x test string annulus. This results in a full gas tosurface shut-in tubing head pressure, on top of the mud and has an impact on thedifferential burst pressure at the casing shoe.

Assume the test string has a 7in DST retrievable packer, set at 10,000ft TVD.

Pi: Internal Load SITHP + Mud Hydrostatic from surface to Packer Setting Depth.

Pi = 6,800 + (14.3 x 10,000 x 0.052)= 6,800 + 7,436= 14,236psi

Pe: External Load = Mud Hydrostatic to TOC + Cement Mix Water Hydrostatic to Packer Setting Depth of 10,000ft

Pe: = (4,000 x 11.4 x 0.052) + (6,000 x 9.0 x 0.052)= 2,371 + 2,808= 5,179psi


= 9,963psiFAIL


This is an unrealistic load condition, as it dominates the burst design for the well andimposes an abnormal load condition on the liner top, due to the DST packer depth inthe 7in liner.

A practical approach based on risk assessment and performing a HAZOP, would be todisplace the well to a 9.0ppg unweighted packer fluid, prior to setting the completionpacker and carrying out perforation operations. Repeating the calculation for Pi using a9.0ppg packer fluid results in the following results:

Pi = 6,800 + (9.0 x 10,000 x 0.052)= 6,800 + 4,680= 11,480psi

Pb Differential(Burst) Pressure (10,000ft) = (11,480 – 5,179) x 1.1

= 6,931psiSAFE(As the 9-5/8 C-75in casing has a burst rating of7,430psi)

Therefore, using an unweighted 9.0ppg packer fluid for a DST/completion would beacceptable subject to conducting a HAZOP for the design and well programme.

10.2.3.2.8 Casing Wear/Temperature Effects

Assessing the results of the load cases, we can see that an area of concern is the9-5/8in burst load, for Full Gas to Surface. This has an actual burst design factor of1.093 excluding casing wear and temperature effects. This justifies an upgrade to aslightly higher specification casing string from 53-1/2 lb/ft Grade C-75 to 53-1/2 lb/ftGrade L-80. This improves the burst resistance from 7,430psi to 7,930psi, animprovement of 500psi (6.7%). This seems a reasonable approach to adopt to take intoaccount potential casing wear, especially at surface near the wellhead area. If bothcasing wear and temperature de-rating are taken into consideration above an ambienttemperature of 68�F, then the 9-5/8in casing may require further upgrading.

However, if we assess the load cases of Gas to Surface and the SITHP on top of thepacker fluid, we still require a pressure test at some point on the 9-5/8in casing to6,800psi. Referring to the Casing Design Manual Section 7, we require a pressure testto 80% of the burst rating.


The optimum design should now look at upgrading the 9-5/8in from Grade L-80 toC-Grade 90, weight 53-1/2 lb/ft. Checking the properties of this grade in API Bulletin5C2 provides the following minimum mechanical properties:

9-5/8in C-90, 53-1/2in Casing


� Internal Yield Pressure (Body) = 8,920psi






This pipe can satisfy all DST burst loads using an unweighted packer fluid and alsoprovide a margin of safety for casing wear and temperature de-rating. A pipe bodymatched premium connection should be specified for all of the mechanical properties,such as New Vam.

80% of the burst rating for the Grade C-90 (53-1/2 lb/ft) is: (8,920 x 0.8) = 7,136psi.

Pi: Maximum Gas to Surface from reservoir = 6,800psi.

Final checks should be performed on burst and axial loads for the complete string,based on this pressure test at plug bump.

A final revised table should be produced for the definitive sizes, grades and weights forall loads for the casing strings as part of the design. It should specify that the 9-5/8inC-90 53-1/2 lb/ft casing requires manufacture and special drift, for an 8-1/2in bit.However, in terms of the example, we will continue to use the original grade and weightC75, 47 lb/ft to demonstrate the casing design principles.




Pe: External Load = Cement Hydrostatic, shoe to 4,000ft + Mud Hydrostatic, 4,000ft to surface

= 16.0 x 4,000 x 0.052 + 14.3 x 4,000 x 0.052= 6,302psi

Pi: Internal Load = Mud Hydrostatic= 8,000 x 14.3 x 0.052= 5,949psi

Design Factor = 1.0


= 353psiSAFE(Collapse resistance of 9-5/8in, C-75, 47lb/ft casing is 4,630psi)

10.2.3.3.2 Drilling: Full Evacuation Pressure

Pe: External Pressure = Hydrostatic Pressure of mud used when cementing casing

= 14.3 x 8,000 x 0.052= 5,949psi


Design Factor = 1.0

Pc: Differential

(Collapse) Pressure = (5,949 – 0) x 1.0= 5,949psi

FAIL

(For 9-5/8in, C-75, 47 lb/ft casing collapse resistance is4,630psi)

As designed previously, with the 13-3/8in casing, we have the two options. Theprobability of a full 8,000ft of casing being drawn down to atmospheric pressure isextremely low and it would probably be justifiable to reduce the load condition. Onceagain, we will select a higher grade or casing weight, to use with the existing criteria.


Our second choice of casing is 9-5/8in, C-75, 53-1/2 lb/ft casing, with the followingproperties:




� Joint Yield Strength = 1,257 x 103 lb




Note: As an 8-1/2in hole is required, order the pipe to 8.5in special drift.

Since all of these parameters are higher than the previous design calculations, thecasing will pass each of the load tests. It is not necessary, at this stage, to recalculatethe load cases but it will need to be done later to determine the actual design factorsthat will exist.

However, the final 9-5/8in casing choice will be C-90, 53-1/2 lb/ft due to the serviceburst loads, for Full Gas to Surface and an SITHP leak at surface.

10.2.4 7in Liner

The 7in production liner will be set at 12,000ft with the liner lap at 7,500ft (500ft abovethe 9-5/8in shoe). The liner will be cemented from the shoe back to the liner lap.

As an initial start, we will assume the 7in liner to be C-75 material, 32 lb/ft weight(as defined within API Bulletin 5C2) and cemented with 16.0ppg cement.


� Internal Yield Pressure (Pipe) = 8,490psi

� Internal Yield Pressure (SRT) = 8,490psi






Note: If specification allows, order pipe as special drift for a 6in bit.




Casing run with 14.3ppg mud.


Fbuoy: Buoyancy(with 14.3ppg mud) = Pe (Ao – Ai)

= 14.3 x 4,500 x 0.052 ((� x 72/4) – (� x 6.0942/4))

Fbuoy = 3,346 (38.48 – 29.17)= -31,151 lb

(Based on Pe and Pi the same, open ended, as thecasing is filled when run)

Fbend: Bending Force = 64 x DLS x OD x W= 64 x 2 x 7 x 32= 28,672 lb




SAFE

Casing body yield strength is 699klb, and buttress threaded casing is 779klb. SAFE.


Assume an overpull of 100,000 lb

Design Factor = 1.4

Ft: Total Load = (Dry Weight + Buoyancy + Bending + Overpull) x 1.4= (144,000 – 31,151 + 28,672 + 100,000) x 1.4= 338,129 lb (Casing yield 669klb)

SAFE



Plug bump to 2,000psi.

Cemented with 16ppg slurry to the liner top at 7,500ft.

Design Factor = 1.4


Fbuoy = (Pe x Ao) – (Pi x Ai) (Closed end pipe)

= Pe (� x 72/4) – Pi (� x 6.0942/4)= Pe (38.49) – Pi (29.17)

= ((16 x 4,500 x 0.052) + (14.3 x 7,500 x 0.052)) x 38.49) –(14.3 x 12,000 x 0.052 x 29.17)

= (3,744 + 5,577) x 38.49 – 260,290= 358,765 – 260,290= 98,475 lb (negative value)

Fbend = 64 x 2 x OD x W= 64 x 2 x 7 x 32= 28,672 lb

Fplug = Psurf x AI

= 2,000 x 29.17= 58,340 lb

Ft: Total Load = (144,000 – 98,475 + 28,672 + 58,340) x 1.4 Design Factor= 185,552 lb

(Casing body yield strength is 699klb, and buttress joint is 779klb)SAFE


Not Applicable.





Assume cement displacement pressure of 1,000psi.

External volume to becemented (12,000 to 7,500) = (4,000 x 0.0185) + (500 x 0.0231)

= 86bbl


= 103bbl

Equivalent height in 7in,32 lb/ft casing = 103/0.036

= 2,861ft



= (2,861 x 16.0 x 0.052) +(1,639 x 14.3 x 0.052) + 1,000

= 4,600psi

Design Factor = 1.1


= 1,379psiSAFE(Internal yield pressure of 7in, C-75, 32 lb/ft casing is 8,490psi)



Pe: External Pressure = Cement Hydrostatic= (4,500 x 16.0 x 0.052psi)= 3,744psi


Design Factor = 1.1


= 2,862psiSAFE(Internal yield pressure of 7in, C-75, 32 lb/ft casing is8,490psi)



Note: Based on a bottom hole pressure of 8,600psi at TD and using a gas gradient of0.15psi/ft, the gas to surface load after the liner is installed would result inthe following:

Gas to surface = 8,600 – (12,000 x 0.15 )= 8,600 – 1,800= 6,800psi

Gas pressure at 7inliner top = 8,600 – ((12,000 – 7,500) x 0.15)

= 8,600 – 675= 7,925psi

For a 500psi test above the 9-5/8in LOT 15ppg, this equates to a hydrostatic pressureat the liner top of (7,500 x 15 x 0.052) + 500 = 6,350psi.

Assuming a mud weight of 14.3ppg in the well after installation, this equates to ahydrostatic pressure at the liner top of 14.3 x 7,500 x 0.052 = 5,577psi.

We can see that the full gas to surface case results in the higher pressure at the 7inliner top. Therefore the minimum pressure test required using the 14.3ppg mud is7,925 – 5,577psi. This yields a minimum pressure test requirement of 2,348psi fordrilling load cases. Therefore pressure test the 7in liner lap and casing to 2,500psi withthe 14.3ppg mud.


However, we will need to check the liner also satisfies the DST/completion load casefor an SITHP leak at surface, on top of the mud column during DST assuming thepacker is set in the 7in liner. The DST packer will be set in the 9-5/8in casing (see loadcase 10.2.4.2.5).

Pe: External Pressure = Cement Mix Water Hydrostatic (from liner shoe to TOC 9-5/8in) + Mud Hydrostatic (TOC 9-5/8in to surface)

= (8000 x 9 x 0.052) + (4,000 x 11.4 x 0.052)= 6,115psi

Pi: Internal Pressure = Mud Hydrostatic + Test Pressure= (14.3 x 12,000 x 0.052) + 2,500= 11,423psi

Design Factor = 1.1


= 5,939psiSAFE(Internal Yield Pressure of 7in, C-75, 32lb/ft casing is 8,490psi)

Note: LOT test and Kick Tolerance are not required for the final string. However, iffurther drilling below the liner were ever considered, then the load cases mustbe calculated.


This is based on a DST with the 14.3ppg drilling mud as the packer fluid and the DSTstring leaks at surface into the 9-5/8in x test string annulus. This results in a full gas tosurface shut-in tubing head pressure, on top of the mud and has an impact on thedifferential burst pressure at the 9-5/8in casing shoe and 7in liner top.



Pi = 6,800 + (14.3 x 10,000 x 0.052)= 6,800 + 7,436= 14,236psi

Pe: External Load = Mud Hydrostatic to TOC + Cement Mix WaterHydrostatic to Packer Setting Depth of 10,000ft

Pe: = (4,000 x 11.4 x 0.052) + (6,000 x 9.0 x 0.052)= 2,371 + 2,808= 5,179psi

Pb: Differential (Burst)Pressure (10,000ft) = (14,236 – 5,179) x 1.1 = 9,963psi

(This is > the burst rating of the 9-5/8in casing)FAIL


This is an unrealistic load condition, as it dominates the burst design for the completewell and also imposes an abnormal load condition on the liner top, due to the settingdepth of the DST packer in the 7in liner.

A practical approach based on risk assessment and performing a HAZOP would be todisplace the well to a 9.00ppg unweighted packer fluid, prior to setting the packer andcarrying out perforation operations. Repeating the calculation for Pi using a 9.0ppgpacker fluid results in the following results:

Pi = 6,800 + (9.0 x 10,000 x 0.052)= 6,800 + 4,680= 11,480psi

Pb Differential (Burst)Pressure (10,000ft) = (11,480 – 5,179) x 1.1

= 6,931psi(This is < the burst rating of the 9-5/8in C-90, 53-1/2incasing)SAFE

Therefore, using an unweighted 9.0ppg packer fluid for a DST/completion would beacceptable subject to performing a HAZOP.

10.2.4.2.5 7in Liner Lap Test (9-5/8in shoe LOT + 500psi)

9-5/8in shoe LOT to 15.0ppg EMW.

Pi: Required Pressure atliner lap (7,500ft) for test = (15.0 x 7,500 x 0.052) + 500

= 6,350psi(16.3ppg EMW)

Mud in Hole = 14.3ppg

Required Surface Pressure = 6,350 – (14.3 x 7,500 x 0.052)= 773psi

Pe: External Load(at liner lap) = Cement Mix Water Hydrostatic + Mud Hydrostatic

= (3,500 x 9 x 0.052) + (4,000 x 11.4 x 0.052)= 4,009psi


= 2,575psi(This is < than the burst rating of the 9-5/8 casing and7in liner)SAFE


However, we need to check the maximum pressure that could be exerted on the top ofthe liner, based on the load case above for an SITHP leak on top of the packer fluid,assuming the DST packer is set at 10,000ft inside the 7in liner.

Pi = 6,800 + (9.0 x 7,500 x 0.052) = 6,800 + 3,510 = 10,310psi (26.44ppg EMW).

This is not a realistic load case, as the probability of a full tubing leak at surface on topof the packer fluid can be assessed in terms of risk. The practical solution is to utilise a9-5/8in DST packer just above the 7in liner lap. This will require a longer tailpipe for theDST string and will also affect the eventual well kill. However, these options can beassessed in terms of risk and cost with the well test Petroleum Engineer.

Therefore, the 9-5/8in DST packer should be set just above the 7in liner top and themaximum pressure the liner top may see is the gas to surface shut-in pressure of7,925psi. We can now return to the original load case for the pressure test of the liner,Section 10.2.4.2.3.



Pe: External Load = Cement Hydrostatic, shoe to 7,500ft + Mud Hydrostatic,7,500 to surface

= (16.0 x 4,500 x 0.052) + (14.3 x 7,500 x 0.052)= 9,321psi


Design Factor = 1.0


= 398psiSAFE(Collapse resistance of 7in, C-75, 32 lb/ft casing is 8,230psi)


10.2.4.3.2 Drilling: Full Evacuation

This is based on full evacuation with the 14.3ppg drilling mud outside.

Pe: External Pressure = Hydrostatic Pressure of mud used when cementing casing= 14.3 x 12,000 x 0.052 = 8,923psi


Design Factor = 1.0


= 8,923psiFAIL(For 7in, C-75, 32 lb/ft casing, collapse resistance is8,200psi)

Therefore, the 7in liner should be upgraded to C-75, 35 lb/ft liner and re-assessed.

The mechanical properties of 7in Grade C-75, weight 35 lb/ft are:



� Internal Yield Pressure (SRT) = 8,660psi






Note: Order pipe as special drift for a 6in bit.

Having finished the main analysis and determined the optimum casing string design,each string requires final recalculation.


10.3 FINAL CASING DESIGN

The final selected casing strings for the well design are:

FINALCASINGSCHEME

MATERIAL/GRADE

WEIGHT(lb/ft)

CONNECTION NOMINALID

(in)

DRIFT ID(in)

20in H-40 94 Short RoundThread

19.124 18.936

13-3/8in C-75 72 Short RoundThread

12.347 12.25(Special

Drift)

9-5/8in C-90 53-1/2 Premium NewVam

8.535 8.50(Special

Drift)

7in C-75 35 Premium NewVam

6.004 6.0(Special

Drift)

10.4 FINAL DESIGN CHECK

10.4.1 20in Conductor

The detailed design showed that the 20in conductor was acceptable, so no furthercalculations are necessary.

20in H-40, 94 lb/ft casing has the following minimum mechanical properties (as definedin API Bulletin 5C2):

� Collapse Resistance = 520psi



� Joint Yield Strength = 581 x 103 lb (For short, round threaded (SRT) and coupled connection)




Note: As the 20in is a conductor string, a stronger connection than SRT could beselected if required, to allow for bending moments and compression. This wouldnormally be carried out as a separate engineering analysis.


10.4.2 13-3/8in Intermediate Casing

The detailed design showed that the 13-3/8in casing required upgrading to grade C-75,weight 72 lb/ft.

13-3/8in, C-75, 72 lb/ft casing has the following minimum mechanical properties (asdefined in API Bulletin 5C2):



� Internal Yield Pressure (Buttress) = 4,930psi






(This has a standard drift size of 12.191in. Therefore, order as special drift to 12.259for a 12-1/4in bit.)


10.4.2.1.1 Installation : Running

Ft: Total Load = Fwt – Fbuoy + Fbend + Fshock


Fbuoy: Buoyancy(with 10.0ppg mud) = 10 x 4,500 x 0.052 ((� x 13.3752/4) – (� x 12.3472/4))

= -48,602 lb(Open ended pipe as casing filled with 10ppg mud, Pe and Pi same)

Fbend: Bending Force = 64 x DLS x OD x W= 64 x 2 x 13-3/8 x 72= 123,264 lb



Ft: Total Load = Dry Weight + Buoyancy + Bending + Shock= (324,000 – 48,602 + 123,264) x 1.6= 637,859 lb

(This is < the pipe body and joint strength)SAFE

Actual Design Factor = 1,558,000/398,662= 3.90



Fop: Assume an overpull of 100,000 lb

Design Factor = 1.4

Ft: Total Load = (Dry Weight + Buoyancy + Bending + Overpull)) x 1.4= (324,000 – 48,602 +123,264 + 100,000) x 1.4= 698,127 lb

SAFE



Fplug: Bump to 2,000psi.

Cement is to surface and is still wet. Assume 16.0ppg cement.

Design Factor = 1.4

Fbuoy = 16ppg cement outside to surface and 10ppg mud inside


Fbuoy = (Pe x Ao) – (Pi x Ai)= Pe x (� x 13.3752/4) – Pi x (� x 12.3472/4)

(Closed end pipe)

Fbuoy = (16 x 4,500 x 0.052 x 140.50) – (10 x 4,500 x 0.052 x 119.73)

= 526,032 – 280,175= -245,857 lb


Fplug = Psurf x AI

= 2,000 x 119.73= 239,460 lb

Ft: Total Load = 324,000 – 245,857 + 123,264 + 239,460= 440,867 x 1.4= 617,214 lb (This is < the buttress joint strength)

SAFE



The string will be cemented back to surface so this does not apply. SAFE



Cemented to Surface with 16.0ppg cement. Hole drilled with 10.0ppg mud.



External Volume = (4,100 x 0.1237) + (400 x 0.1814)= 580bbl

Total Cement Pumped(with 10% excess) = 580 x 1.1

= 638bbl


= 4,311ft

Pe: External Pressure = Mud Hydrostatic= 4,500 x 10 x 0.052= 2,340psi

Pi: Internal Pressure = Cement Hydrostatic + Mud Hydrostatic + Displacement Pressure

= (4,311 x 16 x 0.052) + (189 x 10 x 0.052) + 1,000= 4,685psi

Design Factor = 1.1


= 2,580psi(This is < the minimum burst rating of the connector, 4,930psi)SAFE




Pe: External Pressure = Cement Hydrostatic= 16 x 4,500 x 0.052= 3,744psi

Pi: Internal Pressure = Mud Hydrostatic + Plug Bump= 10 x 4,500 x 0.052 + 2,000= 4,340psi

Design Factor = 1.1


= 656psi(This is < the minimum burst rating of the connector, 4,930psi)SAFE

Actual Design Factor = 4,930/596= 8.27


Psurf: Test Pressure = 2,000psi

Pe: External Pressure = Cement Mix Water Hydrostatic= 4,500 x 9 x 0.052= 2,106psi

Pi: Internal Pressure = Mud Hydrostatic + Test Pressure= (10 x 4,500 x 0.052) + 2,000= 4,340psi

Design Factor = 1.1


= 2,457psi(This is < the minimum burst rating of the connector, 4,930psi)SAFE

Actual Design Factor: = 4,930/2,234= 2.20



13-3/8in Leak-off Test to 12.5ppg equivalent mud weight. With 10.0ppg mud in hole.

Test Margin(Safety margin on LOT) = 0.5ppg. Therefore, maximum value is 13.0ppg

Surface Test Pressure = (12.5 + 0.5 - 10) x 4,500 x 0.052= 702psi

Pe: External Pressure = Cement Mix Water Hydrostatic= 9 x 4,500 x 0.052= 2,106psi

Pi: Internal Pressure = Mud Hydrostatic + 702= (10 x 4,500 x 0.052) + 702= 3,042psi

Design Factor = 1.1


= 1,030psi(This is < the minimum burst rating of the connector,4,930psi)SAFE






Pore Pressure at next shoe = 10.87ppg EMW






Assuming 300ft of 6-3/4in drill collars, and the remainder 5in drillpipe.

Height of Influx = 793ft

Initial Shut-in Pressure S = BHP � (Mud Hydrostatic + Gas Hydrostatic)= 4,582 – (11.4 x 7,207 x 0.052) + (793 x 0.1)= 329psi

Where definitions of terms are given in Section 6 of the Casing Design Manual:

2S

VF052.0MWK

4S

Psurf2

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��

�

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� �2

3291278.0

052.04.11200,4524

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21

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� � psi293,15.164529,097,2060,27Psurf 21

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Pe: External Load = Cement Hydrostatic to Surface= 16 x 4,500 x 0.052= 3,744psi

Pi: Internal Load = Mud Hydrostatic= 4,500 x 10 x 0.052= 2,340psi

Design Factor = 1.0


= 1,404psi(This is < the collapse resistance, 2,590psi)SAFE



Pe: External Pressure = Hydrostatic Pressure of mud when cementing casing= 10 x 4,500 x 0.052= 2,340psi


Design Factor = 1.0


= 2,340psi(This is < the collapse resistance, 2,590psi)SAFE

Actual Design Factor = 2,590/2,340 = 1.1


10.4.3 9-5/8in Production Casing

9-5/8in, C-90 material and 53-1/2 lb/ft weight casing has the following minimummechanical properties (as defined in API Bulletin 5C2 and New Vam data sheet):



� Internal Yield Pressure (Joint) = 8,920psi


� Joint Yield Strength = 1,399 x 103 lb




Note: As an 8-1/2in hole is required, order the pipe to 8.5in special drift.

The casing will be cemented back to 4,000ft (500ft above the 13-3/8in shoe, with16.0ppg cement).




Ft: Total Load = Fwt – Fbuoy + Fbend

Fwt: Dry Weight = 8,000 x 53.5= 428,000 lb


= 11.4 x 8,000 x 0.052 ((� x 9.6252/4) – (� x 8.5352/4))(Open ended pipe)

Fbuoy = 4,742 (72.8 – 57.2)= -73,975 lb

(Based on Pe and Pi the same, as the casing is filled completely when run)

Fbend: Bending force = 64 x DLS x OD x W= 64 x 2 x 9.625 x 53.5= 65,912 lb



Ft: Total Load = Dry Weight + Buoyancy + Bending= (428,000 – 73,975 + 65,912)= 419,937 x 1.6= 671,899 lb

SAFE

Pipe Body Yield Strength = 1,399,000 lb. Therefore, SAFE




Fop: Assume an overpull of 200,000 lb

Ft: Total Load = Fwt – Fbuoy + Fbend + Fop

Design Factor = 1.4

Ft: Total Load = (Dry Weight + Buoyancy + Bending + Overpull) x 1.4= (428,000 – 73,975 + 65,912 + 200,000)= 619,937 x 1.4= 867,912 lb

SAFE

Pipe Body Yield Strength = 1,399,000 lb. SAFE




Cement top is to 4,000ft (500ft inside the 13-3/8in shoe and is wet slurry).Assume 16.0ppg cement.

Design Factor = 1.4

Fbuoy: = 11.4ppg mud down to 4,000ft plus 16ppg cement to casing shoe outside and 11.4ppg mud inside


Fbuoy = (Pe x Ao) – (Pi x Ai)= Pe (� x 9.6252/4) – Pi (� x 8.5352/4)

(Closed end pipe)= ((11.4 x 4,000 x 0.052) + (16 x 4,000 x 0.052)) x 72.8)

– (11.4 x 8,000 x 0.052 x 57.2)= ((2,371 + 3,328) x 72.8) – (4,742 x 57.2)= 414,887 – 271,242= -143,645 lb


Fplug = Psurf x AI

= 2,000 x 57.2= 114,400 lb

Ft: Total Load = 428,000 – 143,645 + 65,912 + 114,400= 464,667 x 1.4= 650,534 lb

(Casing body yield strength is 1,399klb)SAFE



However, as the casing requires a pressure test to 6,800psi to confirm integrity forFull Gas to Surface, the test will be performed on plug bump with upgraded floatequipment, prior to the cement setting and prior to drillout. Therefore, the tensile loadnow becomes:


Fplug = Psurf x AI

= 6,800 x 57.2= 388,960 lb

Ft: Total Load = 428,000 –143,645 + 65,912 + 388,960= 739,227 x 1.4= 1,034,918 lb




This is the ‘as cemented’ base case Ftbase.

Ftbase = Fwt – Fbuoy + Fbend + Fpretension

Fpretension: Pretension of 60,000 lb.

Design Factor = 1.4

Ft: Total Load = (Dry weight + Buoyancy + Bending + Pretension) xDesign Factor

Ft: Total Load = (428,000 – 143,645 + 65,912 + 60,000)= 410,267 x 1.4= 574,374 lb








External Volume to beCemented(9-5/8 shoe to 4,500ft) = (4,000 x 0.0558) + (500 x 0.0580)

= 252bbl

Total Cement Pumped(with 10% excess) = 252 x 1.1

= 277bbl

Equivalent Height in9-5/8in, 53.5 lb/ft Casing = 277/0.0707

= 3,920ft



= (3,920 x 16.0 x 0.052) + (4,080 x 11.4 x 0.052) + 1,000= 6,648psi

Design Factor = 1.1


= 2,097psi(Casing internal yield pressure of 9-5/8in C-90,53-1/2 lb/ft is 8,920psi)SAFE






Design Factor = 1.1




However, as the casing requires a pressure test to 6,800psi to confirm integrity forFull Gas to Surface, the test will be performed on plug bump with upgraded floatequipment, prior to the cement setting and prior to drillout. Therefore, the differentialburst load now becomes:



Design Factor = 1.1









Design Factor = 1.1




Note: This 9-5/8in pressure test is greater than that required for the 7in liner lap test.


Leak-off test to 15.0ppg equivalent mud weight 11.4ppg mud in hole.

Test Margin(Safety margin on LOT) = 0.5ppg

Surface Test Pressure = (15.0 + 0.5 – 11.4) x 8,000 x 0.052= 1,706psi


Pi: Internal Pressure = Mud Hydrostatic + 1,750= (11.4 x 8,000 x 0.052) +1,706= 6,448psi

Design Factor = 1.1

Pb: Differential(Burst) Pressure = (6,448 – 4,243) = 2,205 x 1.1

= 2,426psi.(Casing internal yield pressure 9-5/8in C-90,53-1/2 lb/ft is 8,920psi)SAFE












Assuming 300ft of 6-3/4in drill collars, and the remainder 5in drillpipe.

Height of Influx = 2,800ft

Initial Shut-in Pressure = BHP � (Mud Hydrostatic + Gas Hydrostatic)= 8,600 – (14.3 x 9,200 x 0.052 + 2,800 x 0.15)= 1,339psi

2S

VF052.0MWK

4S

Psurf2

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339,1049.0

052.03.14000,8604

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Pressure of gas top when at surface (using formula of Design Manual) = 3,005psi.SAFE (provided that casing previously tested above this value).



10.4.3.2.6 Testing/Production: Gas to Surface

Pe: External Load = Cement Mix Water Hydrostatic + Mud Hydrostatic= (4,000 x 9 x 0.052) + (4,000 x 11.4 x 0.052)= 4,243psi

Pi: Internal Load = Formation Pressure (8,600psi) – Gas Gradient (0.15psi/ft)

= 6,800psi at surface

Note: This is the anticipated maximum shut-in tubing head pressure (SITHP).

= 7,925psi at 7,500ft (Liner top)

Pb: Differential (Burst)Pressure (Surface) = (6,800 – 0) x 1.1

= 7,480psi(Casing internal yield pressure, 9-5/8in C-90,53-1/2 lb/ft is 8,920psi)SAFE



Actual Design Factor(Surface) = 8,920/6,800

= 1.31



This is based on a DST with the 14.3ppg drilling mud as the packer fluid and the DSTstring leaks at surface into the 9-5/8in x test string annulus. This results in a full gas tosurface SITHP on top of the mud and has an impact on the differential burst pressureat the casing shoe.



Pi = 6,800 + (14.3 x 10,000 x 0.052)= 6,800 + 7,436= 14,236psi

Pe: External Load = Mud Hydrostatic to TOC + Cement Mix Water Hydrostatic to Packer Setting Depth of 10,000ft

Pe = (4,000 x 11.4 x 0.052) + (6,000 x 9.0 x 0.052)= 2,371 + 2,808= 5,179psi

Pb: Differential(Burst) Pressure (10,000ft) = (14,236 – 5,179) 9,057 x 1.1

= 9,963psiFAIL

This is an unrealistic load condition, as it dominates the burst design and also imposesan abnormal load condition on the liner top, due to the setting depth of the DST packerin the 7in liner.

A practical approach based on risk assessment and performing a HAZOP, would be todisplace the well to a 9.00ppg unweighted packer fluid, prior to setting the completionpacker and carrying out perforation operations. Repeating the calculation for Pi using a9.0ppg packer fluid results in the following results:

Pi = 6,800 + (9.0 x 10,000 x 0.052)= 6,800 + 4,680= 11,480psi

Pb Differential(Burst) Pressure (10,000ft) = (11,480 – 5,200) 6,280 x 1.1



Therefore, using an unweighted 9.0ppg packer fluid for a DST/completion would beacceptable.


10.4.3.2.8 7in Liner Lap Test (9-5/8in shoe LOT + 500psi)

9-5/8in shoe LOT to 15.0ppg EMW.

Pi: Required Pressure atliner lap (7,500ft) for test = (15.0 x 7,500 x 0.052) + 500

= 6,350psi(16.28ppg EMW)

Mud in Hole = 14.3ppg

Required Surface Pressure = 6,350 – (14.3 x 7,500 x 0.052)= 773psi

Pe: External Load(at liner lap) = Cement Mix Water Hydrostatic + Mud Hydrostatic

= (3,500 x 9 x 0.052) + (4,000 x 11.4 x 0.052)= 4,009psi

Pb: Differential (Burst)Pressure (7,500ft) = (6,350 – 4,009)

= 2,341 x 1.1= 2,575psi

(Casing internal yield pressure, 9-5/8in C-90,53-1/2 lb/ft is 8,920psi)SAFE


However, we need to check the maximum pressure that could be exerted on the top ofthe liner, based on the load case above for an SITHP leak on top of the packer fluid.

PI = 6,800 + (9.0 x 7,500 x 0.052)= 6,800 + 3,510= 10,310psi (26.44ppg EMW)

This is not a realistic load case, as the probability of a full tubing leak at surface on topof the packer fluid can be assessed in terms of risk. Secondly, using a 7in liner lappacker at installation can reduce the potential risk of damaging the liner lap andeventual 9-5/8in shoe. Or if this is deemed as unacceptable, utilise a 9-5/8in DSTpacker just above the 7in liner lap. This will require a longer tailpipe for the DST stringand will also affect the eventual well kill. However, these are options that can beassessed in terms of risk and cost with the well test Petroleum Engineer.




Pe: External Load = Cement Hydrostatic, shoe to 4,000ft + Mud Hydrostatic,4,000ft to surface

= (16.0 x 4,000 x 0.052) + (14.3 x 4,000 x 0.052)= 6,302psi


Design Factor = 1.0

Pc: Differential(Collapse) Load = (6,302 – 5,949) x 1.0 Design Factor

= 353psi(Casing collapse resistance, 9-5/8in C-90,53-1/2 lb/ft is 7,120psi)SAFE



Pe: External pressure = Hydrostatic Pressure of mud used when cementing casing

= 14.3 x 8,000 x 0.052= 5,949psi


Design Factor = 1.0

Pc: Differential(Collapse) Pressure = (5,949 – 0) x 1.0 Design Factor

= 5,949psi(Casing collapse resistance, 9-5/8in C-90, 53-1/2 lb/ft is 7,120psi)SAFE



10.4.4 7in Liner

The 7in liner will be C-75, 35 lb/ft with the following minimum properties, as defined inAPI Bulletin 5 C2 and the New Vam data sheet:



� Internal Yield Pressure (New Vam) = 9,340psi


� Joint Yield Strength (New Vam) = 679 103 lb




Note: Order pipe as special drift for a 6in bit.

The liner will be cemented back to 7,500ft (500ft inside the 9-5/8in shoe, with 16.0ppgcement).




Ft Total Load: Fwt – Fbuoy + Fbend + Fshock.



= 14.3 x 4,500 x 0.052 ((� x 72/4) – (� x 6.0042/4))

Fbuoy = 3,346 (38.48 – 29.31)= -30,683 lb

(Based on Pe and Pi the same, open ended, as the casing is filled when run)

Fbend: Bending Force = 64 x DLS x OD x W= 64 x 2 x 7 x 35= 31,360 lb




(This is < the 7in connection body yield, 679klb)SAFE




Design Factor = 1.4

Ft: Total Load = (Dry Weight + Buoyancy + Bending + Overpull) x 1.4= (158,000 – 30,683 + 31,360 + 100,000)= 258,677 x 1.4= 362,148 lb

(This is < the 7in connection yield, 679klb)SAFE





Cemented up to the liner top at 7,500ft with a 16.0ppg cement slurry.

Design Factor = 1.4


Fbuoy = (Pe x Ao) – (Pi x Ai) (Closed end pipe)= Pe (� x 72/4) – Pi (� x 6.0042/4)= Pe (38.49) – Pi (29.31)

= ((16 x 4,500 x 0.052) + (14.3 x 7,500 x 0.052))x 38.49) – (14.3 x 12,000 x 0.052 x 29.31)

= (3,744 + 5,577) x 38.49 – 261,539 = 358,765 –261,539 = 97,226 lb(Negative value)

Fbend = 64 x 2 x OD x W= 64 x 2 x 7 x 35= 31,360 lb

Fplug = Psurf x AI

= 2,000 x 29.31= 58,620 lb

Ft: Total Load = (158,000 – 97,226 + 31,360 + 58,620 ) x 1.4Design Factor

= 211,056 lb (Casing connection yield strengthis 679klb)SAFE



Not applicable.





External volume to becemented (12,000 to 7,500) = (4,000 x 0.0226) + (500 x 0.0231)

= 102bbl


= 122bbl

Equivalent height in 7in,35 lb/ft casing = 122/0.035

= 3,486ft



= (3,486 x 16.0 x 0.052) +(1,014 x 14.3 x 0.052) + 1,000

= 4,654psi

Design Factor = 1.1

Pb: Differential = (4,654 – 3,346)(Burst) Pressure = 1,308 x 1.1

= 1,439psi(This is < the 7in body burst rating of 9,340psi)SAFE

Actual Design Factor = 9,340/1,308 = 7.14



Pe: External Pressure = Cement Hydrostatic= (4,500 x 16.0 x 0.052psi)= 3,744psi


Design Factor = 1.1

Pb: Differential = (6,346 – 3,744)= 2,602 x 1.1= 2,862.2psi

(Burst) Pressure (This is < the 7in body burst rating of 9,340psi)SAFE



Psurf: Pressure Test = 2,500psi

Note: Based on a bottom hole pressure of 8,600psi at TD and using a gas gradient of0.15psi/ft, the gas to surface load after the liner is installed would result inthe following:

Gas to Surface = 8,600 – (12,000 x 0.15 )= 8,600 – 1,800= 6,800psi

Gas pressure at7in liner top = 8,600 – (12,000 – 7,500) x 0.15

= 8,600 – 675= 7,925psi

For a 500psi test above the 9-5/8in LOT 15ppg, this equates to a hydrostatic pressureat the liner top of (7,500 x 15 x 0.052) + 500 = 6,350psi.

Assuming a mud weight of 14.3ppg in the well after installation, this equates to ahydrostatic pressure at the liner top of 14.3 x 7,500 x 0.052 = 5,577psi.

We can see that the full gas to surface case results in the higher pressure at the 7inliner top. Therefore the minimum pressure test required using the 14.3ppg mud is7,925 to 5,577psi. This yields a minimum pressure test requirement of 2,348psi fordrilling load cases. Therefore, pressure test the 7in liner lap and casing to 2,500psi withthe 14.3ppg mud.


However, we will need to check the liner also satisfies the DST/completion load casefor an SITHP leak at surface, on top of the mud column during DST assuming thepacker is set in the 7in liner. The DST packer will be set in the 9-5/8in casing.

Pe: External Pressure = Cement Mix Water Hydrostatic(from liner shoe to TOC 9-5/8in)) +Mud Hydrostatic (TOC 9-5/8in to surface)

= (8000 x 9 x 0.052) + (4,000 x 11.4 x 0.052)= 6,115psi


Design Factor = 1.1

Pb: Differential(Burst) Pressure = (11,423 – 6,115)

= 5,308 x 1.1= 5,939psi.

(Internal yield pressure of 7in, C-75, 35 lb/ftcasing is 9,340psi)SAFE


Note: LOT test and kick tolerance are not required for the final string. However, iffurther drilling below the liner were ever considered, then the load cases mustbe calculated.

Design Factor = 1.1

Pb: Differential (Burst) Pressure = (13,000 – 6,130) x 1.1= 7,600psi

SAFE




Pe: External Load = Cement Hydrostatic, shoe to 7,500ft + Mud Hydrostatic, 7,500 to surface

= (16.0 x 4,500 x 0.052) + (14.3 x 7,500 x 0.052)= 9,321psi


Design Factor = 1.0


= 398psi(This is < the collapse resistance of the 7in C-75,35 lb/ft casing, 9,670psi)SAFE



Pe: External Pressure = Hydrostatic Pressure of mud used when cementing casing= 14.3 x 12,000 x 0.052= 8,923psi


Design Factor = 1.0


= 8,923psi(This is < the collapse resistance of the 7in C-75,35 lb/ft casing, 9,670psi)SAFE


Note: 7in 35 lb/ft has a drift diameter of 5.879in. Therefore the clean-out assembly,perforating guns and test tools would need to take this minimum diameter intoconsideration if it was not possible to obtain the liner to 6.0in special drift.


CASING/LINER

LOAD CASE ACTUALLOAD

CASINGSTRENGTH

ACTUALDF

MINIMUMDF

Tension Installation(Running)

272,894 lb 581,000 C 2.13 1.6

Collapse Cementing(Stab-in)

110psi 520psi 4.70 1.0

Collapse Fullevacuation

200psi 520psi 2.60 1.0

Burst Cementing(Stab-in)

0psi 1,530psi N/A 1.1

Burst Bump plug 0psi 1,530psi N/A 1.1

20in, H-40,94 lb/ft

Burst Pressure testafter WOC

0psi 1,530psi N/A 1.0

Tension Installation(Running)

398,662 lb 1,558,000 lb C 3.90 1.6

Tension Installation(Run +Overpull)

408,662 lb 1,558,000 lb C 3.80 1.4

Tension Bump plug to2,000psi

440,867 lb 1,558,000 lb C 3.53 1.4

Burst Cementdisplacement

2,345psi 4,930psi C 2.10 1.1

Burst Bump plug to2,000psi

596psi 4,930psi C 8.27 1.1

Burst Pressure testafter WOC(2,000psi)

2,234psi 4,930psi C 2.20 1.1

Burst LOT afterdrilling shoe

936psi 4,930psi C 5.26 1.1

Burst 100bbl kickfrom next shoe

1,293psi 4,930psi C 3.81 1.1

Collapse Cementing 1,404psi 2,590psi 1.84 1.0

13-3/8in,C-75, 72 lb/ft(SpecialDrift)


2,340psi 2,590psi 1.10 1.0

Tension Running 419,937 lb 1,399,000 lb 3.33 1.6

Tension Running +Overpull

619,937 lb 1,399,000 lb 2.25 1.4

9-5/8in, C-90,53.5 lb/ft(SpecialDrift)


464,667 lb 1,399,000 lb 3.00 1.4


CASING/LINER


CASINGSTRENGTH

ACTUALDF

MINIMUMDF


739,277 lb 1,399,000 lb 1.89 1.4

Tension Pre-tension to60klb

410,267 lb 1,399,000 lb 3.40 1.4

Burst Cementdisplacement

1,906psi 8,920psi 4.68 1.1

Burst Plug bump to2,000psi

1,043psi 8,920psi 8.55 1.1

Burst Plug bump to6,800psi

5,843psi 8,920psi 1.52

Burst Pressure testafter WOC to3,500psi

3,999psi 8,920psi 2.23 1.1

Burst LOT afterdrilling shoe

2,205psi 8,920psi 4.04 1.1

Burst 100bbl gaskick from nextshoe

3,005psi 8,920psi 2.96 1.1

Burst Gas to surface(surface burst)

6,800psi 8,920psi 1.31 1.1

Burst Testing/Production:SITHP onpacker fluidat 10,000ft

6,280psi 8,920psi 1.42 1.1

Burst 7in Liner laptest at 7,500ft

2,341psi 8,920psi 3.81 1.1

Collapse Cementing 353psi 7,120psi 20.1 1.0

9-5/8in, C-90,53.5 lb/ft(SpecialDrift)


5,949psi 7,120psi 1.19 1.0

Tension Running 158,677 lb 679,000 lb C 4.28 1.6

Tension Running +Overpull

258,677 lb 679,000 lb C 2.62 1.4

7in, C-75,35 lb/ft Liner(SpecialDrift)


150,754 lb 679,000 lb C 4.50 1.4


CASING/LINER


CASINGSTRENGTH

ACTUALDF

MINIMUMDF

Burst Cementdisplacement(1,000psi)

1,308psi 9,340psi 7.14 1.1

Burst Bump plug to3,000psi

2,602psi 9,340psi 3.59 1.1

Burst Pressure testafter WOC to2,500psi

5,308psi 9,340psi 1.76 1.1

Collapse Cementing 398psi 9,340psi 24.30 1.0

7in, C-75,35 lb/ft Liner(SpecialDrift)


8,923psi 9,340psi 1.08 1.0



SECTION 11 REFERENCES Page 1 of 5

TABLE OF CONTENTS

11. REFERENCES....................................................................................................... 2

REFERENCES Page 2 of 5

11. REFERENCES(1) API: Specification 5CT. Casing and Tubing (U.S. Customary Units).

(2) API: Specification 5CTM. Casing and Tubing (Metric Units).

(3) API: Specification 5L. Line Pipe.

(4) API: Specification 5B. Threading, Gauging and Thread Inspection ofCasing, Tubing and Line Pipe Threads.

(5) API: RP-5A3. Thread Compounds for Casing, Tubing, and Line Pipe(supercedes Bulletin 5A2).

(6) API: RP 5A5 and S1. Filed Inspection of New Casing, Tubing andPlain End Drill Pipe.

(7) API: RP 5B1. Threading, Gauging and Thread Inspection of Casing,Tubing and Line Pipe Threads.

(8) API: RP 5C1. Care and Use of Casing and Tubing.

(9) API: RP 5C5. Evaluation Procedures for Casing and TubingConnections.

(10) API: RP-5C6. Welding Connections to Pipe.

(11) API: Bulletin 5C2. Performance Properties of Casing, Tubing and DrillPipe.

(12) API: Bulletin 5C3 and S1. Formulae and Calculations for Casing,Tubing, Drill Pipe and Line Pipe Properties.

(13) ISO 10422: Petroleum and Natural Gas Industries � Threading, Gauging andThread Inspection of Casing, Tubing and Line Pipe Threads.

(14) ISO 10405: Petroleum and Natural Gas Industries � Care and Use of Casingand Tubing.

(15) ISO 10400: Petroleum and Natural Gas Industries � Formulae andCalculations for Casing, Tubing, Drill Pipe and Line PipeProperties.

(16) ISO 11960: Petroleum and Natural Gas Industries � Steel Pipes for Use AsCasing or Tubing for Wells.

(17) Institute of Petroleum – Model Code of Safe Practice Part 17 WellControl during the Drilling and Testing of High Pressure OffshoreWells.

(18) Institute of Petroleum – Guidelines for ‘Routine’ and ‘Non-Routine’Subsea Operations from Floating Vessels.

(19) NACE: Standard MR0175-99.

Note: Check that the API documents and other standards/codes are the most up-to-date edition, prior to use.


The web address for the most up-to-date listing of all API documents is:http://www.api.org/cat/pubcat.cgi

The various codes and API standards can be obtained from:

TSSL (Technical Standards Services Limited), Hitchin, EnglandTel +44 1462 453211Fax +44 1462 457714Web http://www.techstandards.co.ukEmail [email protected]

(20) TISL Materials Capability File.

(21) Vallourec Steel Tubes Manufacturing Processes.

(22) NKK Oil Country Tubular Goods.

(23) Allomax Engineering Casing Design Manual.

(24) Hill, Tom H and Roger P Allwin Casing Fundamentals, Prentice and Hill,First Edition.

(25) Higgens, RA Properties of Engineering Materials, SecondEdition.

(26) Moore, Preston L Drilling Practices Manual. 1974 and SecondEdition 1986.

(27) Economides, Michael J Petroleum Well Construction, Wiley 1998.Watters Larry T, Dunn NormanShari

(28) Rabia H Fundamentals of Casing Design. 1987Graham and Trotman.

(29) Fraser Ken Managing Drilling Operations. 1991 ElsevierScience Limited.

(30) Selley, Richard C Elements of Petroleum Geology. 1985Freeman.

(31) Adams, Neal Well Control Problems and Solutions. 1980Petroleum Publishing Company.

(32) Benham, PP and Warnock FV Mechanics of Solids and Structures. Pitman.

(33) Hearn, EJ Metallurgy of Materials. Pergamon.

(34) Rollason, EC Metallurgy for Engineers. Arnold.

(35) Urry, SA and Turner, PJ Solutions of Problems in Strength ofMaterials and Mechanics of Solids. Pitman.

http://www.api.org/cat/pubcat.cgi

http://www.techstandards.co.uk

[email protected]


(36) SPE Papers. The web address for the Society of Petroleum Engineers is:http://www.spe.org

PAPERNUMBER

AUTHOR(S) TITLE

29232 Patillo PD,Moschovidis ZA,Manohar Lal

An Evaluation of Concentric Casing forNon-uniform Load Applications

28710 Rocha LA,Bourgoyne AT

A Simple Method to Estimate Fracture PressureGradient

51188 Abbassian F andParfitt SHL

A Simple Model for Collapse and Post-collapseBehaviour of Tubulars With Application toPerforated and Slotted Liners

26738 Oudeman P andBacarezza LJ

Field Trial Results of Annular PressureBehaviour in a High Pressure/High TemperatureWell

25694 Halal AS andMitchell RF

Casing Design for Trapped Annular PressureBuildup

23923 Marshall DW,Hitoshi Asahi andMasakatsu Ueno

Revised Casing Design Criteria for ExplorationWells Containing H2S

36447 Adams AJ andHodgson T

Calibration of Casing/Tubing Design Criteria byUse of Structural Reliability Techniques

29462 Mitchell RF Effects of Well Deviation on Helical Buckling

20900 Krus H and PrieurJ-M

High Pressure Well Design

19991 Redmann KP Understanding Kick Tolerance and itsSignificance in Drilling Planning and Execution

22217 Wessel M andTarr BA

Underground Flow Well Control: The Key toDrilling Low-Kick-Tolerance Wells Safely andEconomically

20909 Walters JV Internal Blowouts, Cratering, Casing SettingDepths, and the Location of Subsurface SafetyValves

21908 Payne ML, AsbillWT, Davis HL andPattillo PD

Joint Industry Qualification Test Program forHigh-Clearance Casing Connections

http://www.spe.org


PAPERNUMBER

AUTHOR(S) TITLE

18776 Maruyama K,Tsuru E,Ogasawara Y andEJ Peters

An Experimental Study of Casing PerformanceUnder Thermal Cycling Conditions

13431 Hackney RM A New Approach to Casing Design for SaltFormations

28327 Kuriyami Y A New Formula for Elasto-Plastic CollapseStrength of Thick Walled Casing

22547 Pascay PR andCernocky EP

Bending Stress Magnification in ConstantCurvature Doglegs with Impact on Drillstring andCasing

12361 Klementich EFand Jellison MJ

A Service Life Model for Casing Strings

20328 Klementich EFand Jellison MJ

An Expert System for Casing String Design

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