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• Arturo Cordova Somellera

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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

SECTION 1

Drilling and Production Operations

Ref: CDES 01

CASING DESIGN MANUAL

Issue: Feb 2000

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

1.

INTRODUCTION

1.1

GENERAL

Page 2 of 4

The purpose of this manual is to provide guidance on Repsol’s preferred Casing Design methods. This manual should be read in conjunction with the other manuals in the 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 all circumstances and operating environments. It must not replace sound judgement based on a thorough knowledge of well design principles or a detailed knowledge of a particular situation or specific field. Users of this manual are reminded that no publication of this type can be complete, nor can any written document be substituted for qualified engineering analysis. It should be stressed that certain operations will require detailed and frequently site specific operational procedures. This manual is not intended to replace more detailed procedures and vendor manuals, which remain the source of reference for technical specialists. Nevertheless, it is recommended that the manual should be adopted as standard practice and deviations should be employed only in special circumstances that have been carefully considered and approved by management.

1.2

OBJECTIVES

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

1.3

SCOPE

This manual covers the design of all casing strings from large diameter conductors to small 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 are also reviewed. A section is included that introduces basic metallurgy, mechanical properties, casing manufacture, connections and casing inspection. As casing design is at the core of well design, a number of casing and well design checklists are included to ensure that all the relevant data has been considered. Test strings and completions are not addressed in this manual.

INTRODUCTION

1.4

Page 3 of 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 will provide the more experienced engineer with a comprehensive range of information which 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 are current. The manual is prepared in both printed and electronic form. The manual is available either on local area networks or CD-ROM for locations without networks. Paper extracts can be printed from CD, although their circulation should be restricted as 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. All suggestions for revision to this manual should be addressed to this person. The proposal should include the exact changes suggested, a justification for the changes and 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 in Madrid. Repsol Madrid will also instigate regular formal reviews of the manual using internal and 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

INTRODUCTION

1.7

Page 4 of 4

ACKNOWLEDGEMENT

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

SECTION 2

Drilling and Production Operations

Ref: CDES 02

CASING DESIGN MANUAL

Issue: Feb 2000

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

2.2.3

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

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

2.2.4

Page 2 of 38

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 2.2.5.1 2.2.5.2

2.2.6

Temperature Effects on Metallic Properties .............................................. 34 High Temperature .................................................................................... 34 Arctic (Low) Temperatures....................................................................... 34

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 2.2.7.1

2.2.8

Effects of Liquids on Materials.................................................................. 36 Chlorides/Bromides.................................................................................. 36

Corrosion.................................................................................................. 36

2.2.8.1

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

2.2.8.2

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

CASING MATERIAL AND PROPERTIES

2.

CASING MATERIAL AND PROPERTIES

2.1

SPECIFICATION FOR CASING (API 5CT)

Page 3 of 38

This is covered by the American Petroleum Institute generic document API 5CT Specification for Casing and Tubing which covers seamless and welded casing and tubing, couplings, pup joints and connectors in all grades. Processes of manufacture, chemical and mechanical property requirements, methods of test and dimensions are also 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 coupling will be of a greater OD. Casing sizes vary from 4-1/2in to 36in diameter. Tubulars with an 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 and coupled or upset and threaded connections. It is not the exact measure of the weight per foot of any joint of casing. It is used primarily for ordering casing and is used in a general sense for determining casing weight, when designing casing strings.

CASING MATERIAL AND PROPERTIES

Page 4 of 38

For each casing size there are a range of casing weights available. For example, there are 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)

WALL THICKNESS (in)

DRIFT DIAMETER (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, the actual inside diameter (ID) will vary slightly on the manufacturing process. For this reason the drift diameter of casing is quoted in the specifications for all casing. The drift diameter refers to the guaranteed minimum ID of the casing. This may be important when deciding whether certain drilling or completion tools will be able to pass through the casing, eg the drift diameter of 9-5/8in 53-1/2in lb/ft casing is less than an 8-1/2in bit. 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 of casing would be used. The nominal ID of the casing is used for calculating the volumetric capacity of the casing. In order to eliminate the need for odd bit sizes, (eg 5-7/8in, 8-3/8in and 12in) ‘alternate drift’ casing is generally specified whenever possible. Standard drift sizes are given in API 5CT. It may be necessary to specify smaller dimensional tolerances for alternate drift casing. For example, API 5CT cites pipe body OD tolerances for size 4-1/2in and larger 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 wall thickness tolerance is quoted as -12.5% of the nominal pipe size.

CASING MATERIAL AND PROPERTIES

2.1.3

Page 5 of 38

API Steel Grades

The chemical composition of the casing varies widely, and is dependent upon the chemical composition and treatment processes during manufacturing. As a result, the physical properties of the steel vary widely. The resulting materials utilised for the 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 chemical composition of the material and the number refers to the minimum yield strength of the material eg N-80 has a minimum yield strength of 80,000psi and K-55 has a minimum yield strength of 55,000psi. Hence the grade of the casing provides an indication of the casing strength; the higher the grade, the higher the strength of the casing. The minimum yield strength is the most important physical property of steel used in casing strings. It is used to calculate most of the minimum performance properties presented in API 5C2. In addition to the API grades, certain manufacturers produce their own grades of material. Both seamless and electric welded tubulars are used as casing, although seamless casing is the most common type of casing. API 5CT also sub divides the grades into group grades, which defines the requirements for manufacture and heat treatment. For more detail on the API Casing Grades refer to API 5CT. Table 2.2 - Summary of Casing Grades and Properties GROUP GRADE

GRADE

1

YIELD STRENGTH (PSI)

MIN TENSILE STRENGTH (psi)

MINIMUM

MAXIMUM

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

Page 6 of 38

CASING MATERIAL AND PROPERTIES

2.1.4

Connection Types

Individual joints of casing are connected together by a threaded connection. These connections are classified as: API, premium or proprietary (gastight and metal-tometal seal). For many years API thread connections, with or without a resilient seal ring, have been the 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) for casing: The STC thread profile is rounded with 8 threads per inch. The LTC is similar but with a longer coupling, which provides better strength and sealing properties than STC. Sealing is a combination of connection geometry and thread dope




API Buttress Thread for casing: The front and back flanks of the thread profile are cut at different angles to improve the resistance to thread jump-out. Buttress threads do not provide for a positive seal. There is a continuous void over the whole flank of the thread on the bevelled side. Sealing is a combination of thread geometry and thread dope

FLAN

BOX BOX

STAB

PIN

PIN

KS

API 8- ROUND

LOA D FLA NK S

Figure 2.1 - Thread Forms

API BUTTRESS

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


API Extreme Line Thread for casing: This connection type is the only API connection that has a metal-to-metal seal at the end of the pin and external shoulder of the connection (Figure 2.2) Figure 2.2 - Extreme Line METAL-TO-METAL SEAL

PIN

BOX

CASING MATERIAL AND PROPERTIES

2.1.4.2

Page 7 of 38

Non-API Connections

Over a number of years there has been a shift away from simple shallow wells to complicated, deeper, corrosive and high pressure/temperature wells. This has led to the need for connections with better sealing capability than API and led to the development 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 diameter ranges 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 surface casing, 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 the wellhead 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)

CASING MATERIAL AND PROPERTIES

2.1.4.3.2

Page 8 of 38

Connector Categories

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


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




Squnch type connector which snaps together, generally easy to assemble with good mechanical strength but no pre-load (typical types: Vetco ST-2, ALT-2 Hunting 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 Hunting Leopard SD)

2.1.4.4

Connector Assessment

The choice of connector for the well design will require assessment in order to ensure it is not creating an undue weakness in the well design. Hence the requirement to determine the correct technical requirements of the well operating envelope. For example, if planning a deep production casing string, will it require metal-to-metal sealing with gas tightness, good axial tensile strength, axial compressive strength and the ability to maintain strength and sealing at high pressures and temperatures? The requirements and connection characteristics may even require using a connector that has been tested through empirical testing to prove that it is fit for purpose for its intended 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

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

Total Range Length (ft)

CASING MATERIAL AND PROPERTIES

2.1.6

Page 9 of 38

Manufacturing Process

Pipe is made either by seamless (S) or electric weld (EW) process as defined within API 5CT. Seamless pipe is defined as a wrought steel tubular product made without a welded seam. It is manufactured by heating, followed by piercing and hot rolling a piece of steel 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 to produce the desired shape, dimensions and properties. Imperfections such as eccentricity, formed during the heating and working during manufacture may result in the rejection of the pipe during inspection. Figure 2.3 - Piercing

PIERCER BILLET

Figure 2.4 - Hot Rolling

PLUG OR MANDREL

Page 10 of 38

CASING MATERIAL AND PROPERTIES

Figure 2.5 - Welded (Seamed) Pipe Manufacture CURRENT ELECTRODES

SKELP (PLATE) FROM REEL AFTER FORMING

WELDING

FINISHED TUBE

Electric welded pipe is defined as pipe having one longitudinal seam formed by electric-resistance or electric-induction welding, without the addition of filler metal, where the edges to be welded are mechanically pressed together and the heat for welding is generated by resistance to flow of electric current. It is formed by rolling a steel plate and welding the seam. Imperfections can occur during manufacture of the plate and the welding of the seam. 2.1.7

Inspection

Inspection of casing takes place at all stages from manufacture, through delivery, to final inspection prior to use on the rig. Particular inspection requirements are used for recovered, or pipe that is not new. The purpose is to identify and remove pipe that is deemed ‘not fit for purpose’ prior to use. Inspection after immediate manufacture will identify defects and imperfections as defined within Section 9 of API 5CT. An imperfection is a discontinuity, or irregularity in the product. A defect is an imperfection of sufficient magnitude to warrant rejection of the product based on the stipulations 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 wall thickness variation and reduction in collapse rating. This typically occurs during manufacture of seamless pipe




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




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

CASING MATERIAL AND PROPERTIES

2.1.7.2

Page 11 of 38

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 for upset 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 ferromagnetic material. The item to be inspected is first cleaned and then magnetised by passing electrical 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 the leakage field near the flaws. Particle buildups are visually identified and the imperfection or defect area is then evaluated by grinding and mechanical measurement.


Dry Visible Method: Iron powder is applied dry and the test piece is viewed under 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 and applied to the test piece by spraying or dipping the piece in a liquid carrier. After powder application, the piece is viewed under ultraviolet (black) light




Residual Method: Particles may be applied either wet or dry but the magnetising current is turned off before powder application. The remaining residual magnetic field 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, which operated transducers longitudinally, transversely and for wall thickness. Later systems added transducers to scan obliquely around the pipe. Further modifications included transducers arranged in rings that scan inward, reducing the possibility of missing defects that were not orientated correctly.

CASING MATERIAL AND PROPERTIES

Page 12 of 38

Ultrasonic techniques also include inspection of the weldline. Shear wave transducers are positioned for a transverse scan of the weld. Either the pipe or the transducer may be held stationary whilst the other moves manually or automatically down the weldline. c. Electromagnetic Inspection (EMI) EMI (or ‘flux leakage’ or ‘diverted flux’ inspection), is the most common used fulllength inspection method in the oil industry. Typically it is used in conjunction with other 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 some other device such as a Hall-Effect sensor, passing through the field. A voltage is generated as it moves through a magnetic field. The voltage generated by the coil cutting the flux is amplified and displayed by a voltmeter. Should the voltage exceed a certain amount known as the threshold level, the operator investigates to see if a flaw is present. (Tubing and casing are usually inspected for longitudinal and transverse defects.) EMI has its limitations. For instance wall thickness can normalise instrument response when inspecting internally pitted pipe. Also, there is limited precision of the EMI method due to factors not under the control of the operator eg flaw orientation, size, depth and shape. As a result EMI signal amplitude cannot be directly 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 for inspecting threaded ends of corrosion resistant alloys (CRA) pipe and couplings that 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 of the casing. It is important to ensure that no damage has occurred during transportation or storage. Particular points to note are that the threads are initially well greased, that there is no rusting or other corrosion in the thread form and that there are no sharp edges. Minor surface defects may be cleaned off prior to running but any significant damage should lead to the joint being rejected and being sent off for specialist repair. f.

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

CASING MATERIAL AND PROPERTIES

2.1.7.2.2

Page 13 of 38

Measuring Dimensions

a. Ultrasonic Wall Thickness Measurement (UWTM) Ultrasonic techniques have the advantage of being able to find flaws in thick walled pipe. The technique does not require magnetisation and so works well on nonmagnetic corrosion resistant alloy casing as well as basic steel pipe. Ultrasonic inspection is a non-destructive method in which pulses of high frequency sound waves 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 the sound travels through the wall, it bounces off the inside and returns to the transducer. The thickness gauge measures the time elapsed between the pulse and returning echo. A software package within the tool then calculates and displays the wall thickness. If the ultrasonic wall thickness instrument is calibrated and used properly, it is capable of measuring the pipe wall in the field to within a few thousandths of an inch. The unit is calibrated using a wall thickness standard with accurately machined steps. 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 wall under sharp-bottomed pits or other such irregularities as much of the sound is reflected away from the transducer and lost. Thus, the echo returns over a longer time, 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 acceptable variation due to allow for inaccuracies in the manufacturing process. Occasionally the manufacturing process will produce a thread in which all of the tolerance allowances add up to produce a thread which is out of specification. In order to test for this, special thread gauges are used which are manufactured to a closer tolerance than the threads. Both male and female thread forms are available which can be made up to the ends of the casing. Particular points to check are that the thread gauge makes up to the correct depth, that there is no free play in the connection and that if there are metal-to-metal seals that these are capable of making up. b. Gamma Ray Wall Thickness Measurement (GRWT) These systems can give a reliable measurement of wall thickness, provided they are calibrated properly. They are usually linked as part of a four function EMI unit and 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 be inferred. In order to cover more area of the pipe, the unit rotates around the pipe as it passes through the beam.

CASING MATERIAL AND PROPERTIES

Page 14 of 38

Several techniques are available:


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




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




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




Double Wall Attenuation: The same principles apply as for single wall attenuation, except that the radiation is transmitted and measured through two walls and averaged. These measurements are made with the counter placed outside the pipe. Since double wall units are not capable of picking up eccentricity, 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 and conditions such as eccentricity, rod wear, thin wall and casing wear. However, the systems discussed cannot accurately measure the remaining wall for smalllocalised defects, nor can they detect a flaw or condition unless a significant volume of metal is missing. Thus, they cannot detect flaws such as seams, or cracks and should not be used for detecting small defects. 2.1.7.2.3

Additional Methods

Under API this includes hydrotesting (pressure), measurement of the material hardness and material grade verification. a. Hydrotesting All API casing is hydrotested plain end at the mill with pressure for a five-second test, 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 depth of the indent is measured by initially applying a 10kg minor load, followed by a 150kg major load

CASING MATERIAL AND PROPERTIES

Page 15 of 38

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


The Brinell Test: Performed using a small hardened steel ball and applying a 3000kg load. The load is applied and the size of the indent is measured across the corners




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

c. Grade Verification A grade verifier, or grade comparator is usually packaged as one of the systems in a four system EMI (electromagnetic inspection) package. Its use and accuracy are regarded as limited, as there is no reliable relationship between the properties measured (magnetic permeability and mass) and yield strength. Most grade verifiers work on the principle of eddy currents within the steel. An AC coil surrounds the pipe. By use of Ohm’s Law, the current is used to measure the changes in coil inductance, which will vary with magnetic permeability. d. Inspection Summary It is the responsibility of the Drilling Engineer to ensure that the functional specification of the casing pipe and selected connections to be used are ‘fit for the intended use’ for the proposed well design. The Drilling Engineer must also evaluate and state what inspection level is required as part of the pipe purchase order and ensure this is specified for each phase. For example third party at the mill, at the end of the pipe mill run and delivery to the pipe yard. API provides guidance 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 examining stress analysis techniques a number of mechanical engineering definitions are explained 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 operating environment. The loads may be static or dynamic. Static loads may consist of weight in air, pressure, temperature, point loads, bending and drag. Dynamic loads may include shock and drag.

CASING MATERIAL AND PROPERTIES

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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 upon the other across an imaginary plane of separation. When the forces are parallel to the plane, the stress is a shear stress (When the forces are normal to the plane the stress is a normal stress (
) and is either compressive, when acting inwards or tensile when acting outwards. d. Principal Stress (



) Through any point in a stressed body pass three mutually perpendicular planes, the stress on each of which is purely normal, ie there are no shear stresses. The stresses on these principal planes are the principal stresses:



 When one of the principal stresses is zero, the condition is one of biaxial stress, where two principal stresses are zero, the condition is one of uniaxial stress. e. Strain () Strain is the deformation resulting from imposed loads. Elongation (positive) or contraction (negative) is caused by normal forces and is measured in terms of the change in length per unit of original length (see Figure 2.6). Shear forces cause a shear strain measured, for small strains, in terms of the 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 permanent deformation. For linearly elastic materials a proportionate relationship exists between stress and strain (Hooke’s Law).

g. Plastic Deformation Plastic deformation is the permanent deformation of the material occurring at stresses 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.

Page 17 of 38

CASING MATERIAL AND PROPERTIES

Figure 2.6 - Elongation Strain and Shear Strain L1

Original Length

A dL L2

Deformed Length

Elongation Strain = 3

=

L2 - L1

dL

=

L1

L1 ZZ26323.056

Original Angle

B  Deformed Angle

Shear strain =


xy

=

/

2

CASING MATERIAL AND PROPERTIES

Page 18 of 38

Figure 2.7 - Stress/Strain Relationship in Casing Material

N om inal stress (based on original dim ensions)

U ltim ate Tensile S trength

E lastic lim it (onset of yielding)

B rittle Zone

D uctile Zone

P lastic H ardening E lastic D eform ation

i.

P lastic S oftening

Total S train

P erm anent D eform ation

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 one piece. Non-ductile materials are referred to as being brittle.

j.

Elongation In tensile testing the extension of a test-piece when stressed to fracture, usually expressed as a percentage of a specified gauge length. This is a measure of the ductility 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 uniaxial condition within the elastic limit. In general, the modulus of elasticity is the same in tension and compression. For isotropic materials, such as steel, E is the same in all 6 directions. A value of 30 x 10 psi is usually used for tubular steel. At yield strength the actual value will be lower than the published value, but this is usually ignored in 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 is usually taken.

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CASING MATERIAL AND PROPERTIES

m. Yield Strength or Yield Stress (
y) The yield strength or yield stress is the uniaxial stress at which the material exhibits a specific deformation (see Figure 2.8). The yield stress is taken as a measure of the maximum allowable stress for most engineering applications, including casing design. Figure 2.8 - API Yield Strength Definition (Valid to 95kpsi)

N om inal Stress,


AP I Yield Strength

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 at 0.5% total strain for materials up to 95,000psi minimum yield strength, at 0.6% total strain for 110,000psi minimum yield strength, and at 0.65% total strain for 125,000psi minimum yield strength. In many other engineering applications a 0.2% permanent deformation is used to establish the yield strength, and this will sometimes be found in non-API publications on tubular performance. Yield strength is temperature dependent. For steel, the yield strength decreases as temperature increases. For some low strength easing grades (J55) yield strength will initially decrease as temperature increases, but as temperature further increases, the yield strength will rise to a level above that evident at room temperature. A typical yield strength temperature correction applied to casing is: 0.03% above 68F (20C). This typically results in a 10% reduction in the yield strength for a casing string with a bottom hole temperature of c. 330F. Specific data on temperature correction applications can be obtained from the casing manufacturers.

CASING MATERIAL AND PROPERTIES

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n. Ultimate Tensile Strength (
UTS) The ultimate tensile strength is the maximum nominal stress that a material can sustain under axial loading. It is calculated on the basis of the ultimate load and the original unrestrained dimensions. o. Fatigue Fatigue is the tendency of materials to fracture under repeated loading to a stress below the ultimate tensile strength. The fracture process is usually progressive, by taking place over a number of load cycles and is normally referred to as Cyclic Fatigue. 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 the sum of the products obtained by multiplying each element of the area by the square of its distance from the axis. For an annular ring with outer diameter d0 and inner diameter di I



64

( d o 4  di 4 )

q. Coefficient of Thermal Expansion () The coefficient of thermal expansion defines the (linear) relationship between a temperature change and the resulting thermal strain in a homogeneous body subjected uniformly to that temperature change, ie ==

 T -6

A value of 6.9 x 10 /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 volume caused by a unit increase in temperature. s. Volume Compressibility (Cp) Volume compressibility of a fluid is the compression per unit of original volume caused by a unit increase in pressure. t.

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

CASING MATERIAL AND PROPERTIES

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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 out an impact test in which a notched bar sample, fixed at both ends, is struck by a falling pendulum. The energy absorbed as determined by the subsequent rise of the pendulum, is a measure 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 chemical composition of the material. The primary phases are: a. Austenite A high temperature non-magnetic phase of iron which normally exists as a facecentred 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 723C (1333F). 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 crystallographic structure. In steels, the solute is generally carbon. Carbon has a very low solubility in ferrite, being only some 0.02% weight. c. Cementite A compound of iron and carbon, eg Fe3C. When a steel is cooled from high temperatures the solubility of carbon decreases. The carbon that is thus pushed out of solution reacts with iron to form iron carbide. Carbon steels often contain a proportion 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 cooling austenite in carbon, low alloy steels. Pearlite will only begin to be formed when the austenite 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 and pearlite.

CASING MATERIAL AND PROPERTIES

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e. Martensite If steels are cooled rapidly by quenching, there is insufficient time for the carbon to be pushed out of solution to produce large carbide particles/platelets. Therefore, a metastable transitional constituent is produced known as ‘martensite’. This transformation product is very hard/strong but very brittle. In most cases, it is necessary to re-introduce some ductility by tempering. Tempered martensite can withstand fatigue. 2.2.2.1.1

Heat Treatment

After initial pipe manufacture but before threading, the next phase of the manufacturing process 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 1675F, subject to the content of the carbon. This treatment allows time for the structure to transform from its normal room temperature ferritic structure to austenite. b. Normalising An annealing heat treatment followed by still air-cooling to produce a pearlite-ferritic structure. The purpose is to refine the grain size, homogenise the structure and remove strains induced by mechanical working. c. Quenching A process of rapidly cooling a metal from an elevated temperature by contact with the liquids, solids or gases to form a hard martensitic structure. Typically, liquids are used, either aqueous or oil based. Carbon and low alloy steels are quenched to form martensite. d. Tempering A heat treatment to which steels, especially low alloy steels, are subjected in order to produce changes in the mechanical properties and structure. This process generally follows quenching, which produces a steel that is often too hard and brittle to be of practical use. In tempering, the steel is heated to a suitable temperature at which structural changes will occur, which relieve internal stresses, reduce hardness (strength) and increase toughness. This is followed by cooling at a suitable rate. When martensite is tempered, it gradually decomposes, with iron carbide ejected from the solid solution. The result of full tempering is a structure consisting 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 been induced by casting, quenching, welding, and cold working. The metal is soaked at a suitable temperature for sufficient time to allow readjustments in stresses, then slowly cooled. Stress relieving does not normally involve any structural changes within the steel.

CASING MATERIAL AND PROPERTIES

f.

Page 23 of 38

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

2.2.2.1.2

Alloy Steels

Adding elements (alloying) to the steel during its liquid molten stage is often used to modify and improve the properties of the pipe. Alloying the steel is used in conjunction with heat treatment to set the final steel properties. For example, adding nickel can increase the hardness/strength by modifying the ferrite/pearlite zone of the carbon steel. 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 steels and to ensure casing design accessories and equipment are compatible with the casing pipe in terms of mechanical requirements, when ordering material for the well design. This may be influenced by the anticipated constituents of the well such as carbon 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 range 6 to 20%. These alloys can contain some ferrite (c. up to 5%) which can adversely affect their corrosion resistance and weldability. These steels cannot be hardened by 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 and austenite. 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 are rarely used as downhole tubulars. d. Martensitic Stainless Steels A group of hardenable stainless steels containing from 11 to 14% chromium and 0.15 to 0.45% carbon. These steels harden readily on air cooling from about 1750F. It is usually to re-introduce some ductility by tempering.

CASING MATERIAL AND PROPERTIES

Page 24 of 38

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

Precipitation-hardening Stainless Steels Some materials will harden on cooling by the subsequent precipitation of a constituent from a supersaturated solid solution. This produces materials that can be 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 metal surface. Corrosion resistance can be increased by the addition of other alloying elements, eg nickel, molybdenum and copper. The main types of stainless steel are austenitic, ferritic, martensitic, duplex and precipitation hardening. 2.2.3

Codes and Standards

Codes and standards utilised for casing tubulars are wide ranging and include many organisations on an international basis. A Drilling Engineer needs to be aware that the generation of a well design and specification of the tubulars may require the use and study of a variety of codes, standards and guidelines. He should also ensure that the most up-to-date documentation is available, as all codes, standards and guides undergo 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)

CASING MATERIAL AND PROPERTIES

2.2.3.1

Page 25 of 38

API Codes – General Application

The most universally used standards relating to the specification of oilfield tubular goods 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 Tubular Goods which publishes, and continually updates, a series of Specifications, Standards, Bulletins and Recommended Practices covering the manufacture, performance and handling of tubular goods. They also license manufacturers to use the A-PI Monogram on material that meets their published specifications, so that field personnel can identify materials that comply with the standards. Their pronouncements are almost universally accepted as the basis for discussions on the properties of tubulars. However, this does not mean that everyone accepts the published performance data as the best theoretical representation of the parameters. The forum consists both of users 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 Oil Country Tubular Goods (OCTG), threads and equipment. They are generally considered binding between buyer and seller if referred to in purchase orders. They would assist in specifying a well design. 2.2.3.1.2

Recommended Practices (RPs)

These publications provide recommended (but not necessarily binding) actions which should be followed when performing such activities as inspection. RPs are often utilised in the industry but are not generally considered binding upon the seller unless they were included as part of the purchase order. 2.2.3.1.3

Bulletins

These documents are published primarily for information purposes, though they may become 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 and connectors in all grades. Processes of manufacture, chemical and mechanical property requirements, methods of test and dimensions are included.

CASING MATERIAL AND PROPERTIES

Page 26 of 38

2. API STD 5B, ‘Specification for Threading, Gauging, and Thread Inspection for Casing, Tubing, and Line Pipe Threads’. Covers dimensional requirements on threads and thread gauges, stipulations on gauging practice, gauge specifications and certifications, as well as instruments and 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 and Line Pipe’. The purpose of this recommended practice is to provide guidance and instructions on 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 and tubing. 6. API RP 5C5, ‘Recommended Practice for Evaluation Procedures for Casing and Tubing Connections’. Describes tests to be performed to determine the galling tendency, sealing performance 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 casing and tubing and minimum yield load for drill pipe. 8. API BULL 5C3, ‘Bulletin on Formulae and Calculations for Casing, Tubing, Drill Pipe and Line Pipe Properties’. Provides formulae used in the calculations of various pipe properties, also background information regarding their development and use. All of the above documents should be checked to ensure their validity and that they are 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, including downhole tubulars and production equipment. The NACE Standard MR0175-99 is entitled ‘Standard Material Requirements – Sulphide Stress Cracking Resistant Metallic Materials for Oilfield Equipment’.

CASING MATERIAL AND PROPERTIES

Page 27 of 38

The NACE standard is only concerned with the resistance of materials to sulphide stress cracking in sour conditions. However, there are other failure mechanisms that may occur in the presence of hydrogen sulphide and need to be taken into consideration, when selecting materials for sour service. The first step in applying the NACE methodology is to determine whether ‘sour conditions’ as defined by NACE MR0175-99 exist. The standard defines sour environments as fluids containing water as a liquid together with hydrogen sulphide at a level exceeding certain criteria. The Drilling Engineer will need to use the NACE standard to determine the partial pressure of hydrogen sulphide in the gas phase (if present) and thus assess material requirements.

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 and Testing of High Pressure Offshore Wells, a set of guidelines on issues to consider for high pressure, high temperature (HPHT) wells. The second is a set of ‘Guidelines for Routine and Non-routine Subsea Operations from Floating Vessels’ and should be used to consider issues associated with conductor 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 under API Spec 5CT.

2.2.3.5

International Standard Organisation (ISO)

ISO describes itself as ‘the specialised international agency for standardisation’. Its members are the national standards organisations of 91 countries. ISO publishes international standards emanating from several technical committees and sub-committees. A technical board comprising one representative from each national body governs ISO. The Central Secretariat co-ordinates ISO operations, administers voting and approval procedures, maintains and interprets the directives that set out the procedures and rules, and publishes the international standards. ISO is responsible for all 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 was increasingly recognising the need for good international standards that could be accepted and applied worldwide.

CASING MATERIAL AND PROPERTIES

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As part of the reactivation, the scope of ISO/TC 67 was extended to the standardisation of the materials, equipment and offshore structures used in drilling, production, refining and the transport by pipelines of petroleum and natural gas. The work programme developed was primarily in the fields of drilling and production but also includes machinery 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 national standards organisations of the EC countries. It aims to achieve the goal of the EC, ie to improve the international competitive position 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) into European Norms (ENs)




Introducing Directives (which will become law at national level, referring to relevant 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. The co-operation between ISO and CEN has been formulated as follows: ‘It is declared policy of the community that whenever possible CEN/CENELEC shall implement international standards in a uniform way but where international standards have not yet been developed or where existing standards need to be adapted to European situations, CEN and CENELEC will develop ENs in anticipation of international ones.’ As part of the Harmonisation Legislation for Europe 1992 the EEC commission requested the CEN to introduce ENs. As the upstream oil and gas industry is dominated by API standards, the CEN requested the ISO to investigate the feasibility of converting 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 to the ISO




Class 3: API standards requiring significant study prior to moving forward as international standards

CASING MATERIAL AND PROPERTIES

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In 1988 API offered more than 70 of its standards to ISO, to he the basis of international standards. In 1989 an ISO Advisory Group classed several of these as suitable for adoption without technical modification and ISOICS agreed to ‘fast-track’ these to become international standards. ‘Fast-track’ means that the API document is given an ISO Number, front cover and foreword but is otherwise presented as-is. So far API Bull. 5C3, API RP5C1 and API Std 5B have been ‘fast-tracked’. The ISO foreword addresses issues such as equivalent references to American national references, certification and the API Monogram. The industry is now well established regarding the process of ‘transferring’ API standards. It is no longer seen as appropriate that all the A-PI standards offered should become ISO standards. Some may be better left with API because the helpful and discursive style of many (RPs and bulletins in particular) is lost when re-formatted to comply with ISO directives. An example of the API/ISO convergence process is API 5C3 Bulletin on Formulae and Calculations for Casing, Tubing Drill Pipe and Line Pipe Properties. This contains the requirements of ISO 10400 Petroleum and Natural Gas Industries – Formulae and Calculations 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 shallow wells to complicated, deeper, corrosive and HPHT wells. As a result, well requirements call for manufacturers to provide higher specifications materials for well designs. This has led to the development of non-API casing grades, or ‘proprietary grades’ from the pipe manufacturers. Proprietary grade casing/specialist materials may be required to address the following subjects:

2.2.4.1

Sour Service

Material Selection for Sour Service Tubulars gain their resistance to sour service from a combination of alloy design and heat treatment. Materials with strengths less than API 5CT L80 are inherently resistant to 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 a tempered 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 more alloying elements to increase the hardenability and the temper resistance. API 5CT C90, T95 and a proprietary grade ST-95, are made from carbon-manganesechromium-molybdenurn steels. The chromium content is usually about 1.2% and the molybdenum content 0.20% to 0.75%. There may also be a boron addition.

CASING MATERIAL AND PROPERTIES

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In order to reduce tubular weights and dimensions, higher strength grades have been developed. These rely on modified types of steel but they are still quenched and tempered. A proprietary grade with a minimum yield strength of 110ksi can be supplied with 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 may be present resulting in accelerated corrosion. Carbon dioxide corrosion occurs in the presence of water by general and pitting corrosion. Carbon-manganese steels can corrode very rapidly and perforate in only a few days by pitting. The martensitic stainless steels containing 9% and 13% Cr are very resistant to this type of corrosion over a wide range of conditions. The new generation of martensitic stainless steels, the ‘Super’ 13% Cr steels, maintain their corrosion resistance to higher temperatures in more adverse conditions. They are supplied in higher strengths than standard 80,000psi strength API 13% Cr and can also be considered for conditions where API 13% Cr would be suitable, but where the engineering design demands a higher strength tubing. TISL proprietary grades typically available 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 temperature wells more highly alloyed stainless steels, such as the duplex stainless steels, must be used. These steels contain 22% or 25% chromium together with nickel, molybdenum and nitrogen. Both these grades can be used in the softened condition with minimum specified yield strengths of 60ksi to 80ksi. Alternatively they can be strengthened by cold working up to relatively high strengths eg 140ksi minimum yield strength. In the softened condition these alloys are more corrosion resistant than in the cold worked condition.

CASING MATERIAL AND PROPERTIES

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The normal limit of application of the duplex stainless steels is about 200C. Above this temperature and up to 300C super-austenitic alloys are used. These are nickelchromium alloys having significant additions of molybdenum as well as other lesser alloying 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




22% Cr Duplex Stainless Steel, 140 grade




25% Cr Duplex Stainless Steel, 80 grade




25% Cr Duplex Stainless Steel, 140 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 corrosive environments including small concentrations of hydrogen sulphide may consist of the following material types. Part 1: Martensitic Stainless Steels Standard martensitic stainless steels contain either chromium or chromium and molybdenum as the principal alloying elements. Both types are used for grade L80 to provide resistance to carbon dioxide corrosion. The most commonly used grade contains 13% Cr and is an air-hardening steel usually supplied in the air-quenched and tempered condition. The other variety contains 9% Cr and 1% Mo and is heat-treated by water quenching and tempering.

Page 32 of 38

CASING MATERIAL AND PROPERTIES

‘Super’ martensitic stainless steels have enhanced corrosion resistance imparted by extra alloying elements in the form of molybdenum and nickel. They have improved corrosion resistance at higher temperatures and higher chloride concentrations than standard martensitic steels. They can offer a cost elective alternative to duplex stainless 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 constitute specifications. Only the principal alloying elements are quoted. STEEL TYPE

CARBON

MANGANESE

CHROMIUM

MOLYBDENUM

NICKEL

Martensitic SS 9% Cr

0.08 to 0.15

0.30 to 0.60

8.0 to 10.0

0.90 to 1.10

–

Martensitic SS 13% Cr*

0.15 to 0.22

0.20 to 1.00

12.0 to 14.0

–

0.50 max

Super Martensitic SS*

15. The effect of this is that it is necessary to satisfy both the triaxial stress versus yield and API uniaxial collapse requirements (bending is assumed to not affect the API collapse resistance). Triaxial analysis is generally recommended for wells that are deemed as not typical, or have unusual loading conditions. For example, this may typically include issues such as:


High bottom hole pressures




Temperatures in excess of c. 250F 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 local yielding, 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’s Law relates the components of stress to the components of strain. This law states that for a uniaxial stress, the magnitude of the unit elongation of an element is given by: 

a





a E

Where E is Young’s Modulus.

DESIGN CONCEPTS

Page 20 of 28

Extension in the axial direction is also accompanied by lateral contractions in the radial and tangential directions. For isotropic materials, E is the same in all directions and therefore: r  

 a

E

and

t  

 a

E

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 be obtained by superimposing the strain components produced by each of the three stresses. a 

1 a  
r   t  E

t 

1  t  
a  r  E

r 

1 r  
a   t  E

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 (or extended 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 the Lamé equations becomes: It then follows that for any point along the pipe: r   

a 

2
Pi A i  Pe A e  As

1 2
Pi A i  Pe A e    a   E As 

DESIGN CONCEPTS

Page 21 of 28

Therefore, for a suspended casing with a free-moving casing shoe, the total elongation is: L 

1L  2
Pi A i  Pe A e     a   ds Eo  As 

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

3.2.4.5

Incorporation of Service Factors

A casing design will be influenced by the operating environment with respect to time and must be considered accordingly for the anticipated life cycle of the well as a pressure vessel. A number of service factors will therefore need to be considered as part of a casing design, 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 drill string forced against a casing internal surface. The combination of high side-wall forces and extended drillstring to casing contact around the kick-off section of a well profile can 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 total wear, compared to drillpipe rotating in the casing. Casing wear ultimately leads to failure as the burst, collapse and axial strengths are directly related to wall thickness and hence are reduced by wear. Casing wear is assessed by identifying the functions for drilling/production conditions and estimating the wear/erosion on the casing wall. It will primarily be an issue on directional wells, or hole sections with high a dogleg severity. As part of a well design, casing wear should be estimated by consideration of the 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 planned rotating speed




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

DESIGN CONCEPTS

Page 22 of 28

The data should then estimate a wear factor for the well and ultimately determine an estimated % 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 and compare 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 wall thickness, or adopt alternative use of drilling methods, a wear monitoring programme should 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 to withstand the design loads. Secondly, corrosion can weaken the material such that it is unable to withstand the design loads (see Section 2 for corrosion). However, in terms of well design, corrosion is assessed for material selection at the design stage, in particular the yield strength in conjunction with temperature. Some common 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 and tension. 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 which are the units normally given. More important is the relative amount of these components in the gas stream. This is often quoted in terms of the ‘partial pressure’ of the component in the gas stream, the pressure that would be left if all other components of the gas were removed. To a reasonable degree of accuracy this may be calculated by multiplying the known pressure by the fraction of the stream, which is the corrosive gas. (Example: If a gas stream has 3% CO2 and at some point the total pressure is 4500psi then the partial pressure of CO2 is 4500 x 3/100 = 135psi.)

DESIGN CONCEPTS

Page 23 of 28

Temperature also plays an important role: H2S rich gases become less corrosive at higher temperature while CO2 gases become more corrosive. The two charts below give a general indication of the materials required for different corrosive environments. These should be used only as a general guide and steel manufacturers should be approached for more specific information. Corrosion well design issues are generally a concern for development wells where the reservoir constituents, internal/external fluids (muds/brines) and life of the well could influence 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 occur due to the material acting in a brittle manner. Hence, it is now routine to typically specify L-80 yield materials (improved ductility and lower maximum yield) for casing design, as opposed to N-80. Tubing, or casing exposed to corrosive produced fluids, may demand the use of corrosion resistant alloys (CRA) for well design requirements. The NACE standard is an important document for assessing the crossover point on temperatures for casing material assessment eg for geothermal temperatures below 175F and with H2S partial pressure of 0.05psi you cannot use steel with a hardness greater than HRC 22 (Rockwell). Hence, the need to check the material specification within API 5CT and manufacturers’ non-proprietary grades. Corrosion well design should consider the issues for exploration (short-term) in a different manner for development (long-term) by focusing on the drilling mud pH > 10 in order to neutralise hydrogen sulphide, use of chemical sulphide scavengers and review the casing materials relative to temperature for H2S (NACE) requirements. Development wells should endeavour to contain the corrosive produced fluids within the production tubing by correct selection/corrosion resistance of the annulus fluid. Any part of the casing string that is likely to be exposed to produced fluids for a significant length 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 the ability of the casing to move to accommodate this change determines the resulting stresses. This can lead to buckling and compressive failure, due to a change in the axial stress. Finally, the wellbore temperature gradient also has an influence in determining suitable material selection and crossover points relative to NACE requirements for H2S.

Page 24 of 28

DESIGN CONCEPTS

Figure 3.5 - Application of Various Materials to the Prevention of Sour Service Corrosion T E M PER AT U R ES U P T O 15 0 de g C

D U PLE X S T AIN LE SS S T EE L H IG H S T R E N G T H

P artial pressure of carbon dioxide, bar

1 0 00

100 D U PLE X ST AINL ES S S T E EL SO LU T IO N AN N E ALE D

10

SU PER -AUS T E N IT IC AL LO YS SO LU T IO N AN N E ALE D OR H IG H S T R EN G T H

M AR T E N SIT IC ST AINL ES S S T E EL 1

0 .1

AN Y G RAD E

SO U R SE R V ICE R ES IS T AN T CAR BON AN D LOW ALLOY ST E EL G R AD E S

100

1 0 00

100

1000

10

1

0 .1

0 .0 1

0 .0 0 1

0 .0 1

Partial pres sure of hydrogen sulphide, bar T E M PE R AT U R E S OV E R 2 0 0 de g C

100

SSUP E R-AUS E NI AL L OY U PE R -AU TTEN ITTICI CALLO YS S OL UT I ON AN ANNE AL EDD S OLU T ION N EALE OR HHIIGGH H SSTTRRE ENNGT G T HH

10

1

0 .1

AN Y G RA D E

S OU R S ER V IC E R E SIS T AN T C AR BO N AN D LO W ALLO Y S T E E L G R AD E S

10

1

0 .1

0 .01

0 .01 0 .0 0 1

P artial pressure of carbon dioxide, bar

1000

Partial pres sure of hydrogen sulphide, bar

DESIGN CONCEPTS

Page 25 of 28

For high temperature casing design, a yield strength correction factor is typically used to modify the material properties; as yield strength decreases, the temperature increases. A typical yield strength temperature derating factor is 0.03% per F above 68F and relates to a c. 9.7% reduction in yield strength for a high temperature well at 392F (200C). When design yield strength has a critical influence on weight, or grade selection, it is necessary to ensure that the yield strength at elevated temperatures at least matches the assumptions in the well design and that the manufacturer can achieve the required properties. Extreme changes in temperature should also be considered. For example, when displacing a hot mud from a high pressure, high temperature (HPHT) well to cold seawater for a DST, temperature cycling may occur, leading to rapid changes in axial stresses from compression (hot condition) to tension (cold condition). This needs to be taken into consideration for axial stresses. 3.2.4.5.4

Fatigue

Casing failure can have various causes. Casing may fail after one single load exceeding the ultimate tensile or compressive strength, but also after repeated load cycles below the ultimate tensile or compressive strength. This phenomenon is known as fatigue, and practically all materials are subject to it. The effects of surface condition, corrosion, temperature, etc on fatigue properties are documented and in recent years the microscopic mechanism of fatigue damage been identified 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 an S/N curve where the cyclic stress amplitude is plotted on log-log paper versus the number of cycles to failure. Where S = the magnitude of stress and N = the number of cycles. Ferrous metals in air show a lower limit to the stress amplitude called the fatigue limit, 5 7 or endurance limit. This generally occurs after 10 to 10 stress-reversal cycles. Stress reversals 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 with increasing N. An example of where fatigue has an influence for the long term is wellhead design as part of the casing design, in particular due to the interaction of the BOP and marine riser system for subsea wells. External loads from wave and current and soil loads should therefore be considered. Fatigue can be influenced by a number of issues and include the following:


Stress history




Stress concentrations




Residual stress




Corrosion fatigue

Page 26 of 28

DESIGN CONCEPTS

Casing fatigue failure can be related to casing dimensions, material properties, number of load cycles and types of load amplitudes exerted on the casing. The last two are dependent on several parameters, for example, movement and mechanical properties of the components connected to the casing. Figure 3.6 - Schematic of an S/N curve

S TR E S S , S

T yp ica l S - N C u rve fo r S te e ls

F a tig u e L im it

1 04

3.2.5

3.2.5.1

1 06 N u m be r o f cycle s o f stre ss, N

108

Leak Off Tests and Interpretation

Introduction

Leak off and limit tests are carried out during the drilling phase of the well. The BOP is closed around the drillpipe, and the well is slowly pressured up, using mud. At the first sign of fluid leak off into the formation, the pumping is stopped. Leak off tests are carried out until leak off is observed; limit tests are carried out until a predetermined test 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 ensure that no flow path is established to formations above the casing shoe or to the previous annulus

Page 27 of 28

DESIGN CONCEPTS




Investigate the capability of the wellbore to withstand additional pressure below the casing shoe in order to assess the competence of the well to handle an influx, and to allow proper well design with regard to the safe drilling depth of the next hole section




Collect regional data on formation strength for the future planning of fracture gradient profiles for casing design

The tests are sometimes called: casing seat, formation strength or formation integrity tests. The pressures exerted during a limit or leak off test should never exceed the maximum burst pressure of the casing and surface equipment. Figure 3.7 shows a typical formation fracture graph that could be expected for a well formation. Figure 3.7 - Typical Formation Fracture Graph Form ation B reakdow n P ressure, FB P

D ow nhole P ressure

Leak-off P ressure, LO P

Fracture P ropagation P ressure, FP P Instantaneous S hut-in P ressure, IS IP

FIT Lim it Fracture C losure P ressure, FC P

P um p R ate (C onstant)

T im e

The primary terms are summarised below. However, it is worth noting that formation breakdown during a limit or leak off test should be prevented, as a fracture may permanently impair the capability of the wellbore to withstand pressure. If breakdown does occur it should be treated as an opportunity to obtain formation strength data as this is in effect a fracture. Results should be plotted and interpreted on a large scale of volume (or time) versus pressure plot (for a formation integrity test (FIT) test) or time (or volume) versus pressure (for a LOT).

DESIGN CONCEPTS

3.2.5.2

Page 28 of 28

Formation Integrity Test (FIT)

In a successful formation integrity test no leak off is observed, when the initial static pressure reaches the surface limit pressure. This is confirmed as the pressure increase versus volume pumped is straight, with no deviation on the graph. This confirms the wellbore 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. The surface leak off pressure is the interpolated value of the pressure at the first indication of 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 surface breakdown pressure.

3.2.5.5

Fracture Propagation Pressure (FPP)

The fracture propagation pressure is the constant pressure required to propagate a fracture 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 is stopped.

3.2.5.7

Fracture Closure Pressure (FCP)

Once pumping is stopped, the pressure decay is recorded. Fracture closure is indicated 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

Drilling and Production Operations

Ref: CDES 04

CASING DESIGN MANUAL

Issue: Feb 2000

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

4.2.4

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

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 CHECKLIST ......................................................................... 14

4.4

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

DESIGN PREPARATION

4.

DESIGN PREPARATION

4.1

DATA RESEARCH

4.1.1

Pre Drill Data Package (PDDP)

Page 3 of 15

The geology/geophysics team or Asset Group should ensure that a PDDP is prepared for each well. The PDDP should clearly state the well objectives for the project and contain the required detail for the optimum casing design. The PDDP may not always result in a well design that provides minimum cost, hence the need for the objectives to be agreed with the various disciplines, prior to the commencement of detailed well planning. The group responsible for the well will prepare the PDDP with input from the various disciplines, including the Drilling Engineer. It should be approved by the Well Owner and used as a datum document for all team members, associated with the well design. This may require feasibility studies with various conceptual well designs prior to proceeding further. Early involvement by the drilling engineer as part of the well team ensures an efficient, cost effective design is achieved. An overview of this process is shown below.

Data Collection

Casing Scheme Selection

Detailed Design

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

DESIGN PREPARATION

Page 4 of 15

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 impacts casing 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/Cl impacts material selection, cost and lead time for tubulars




Environmental issues, hydrocarbon leakage, abandonment constraints, surface acquifers, 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 the Drilling Engineer. This data required includes the following items:


Pore pressure and fracture gradient profiles (overpressures, depleted zones compaction)




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, wellhead configuration, 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

DESIGN PREPARATION

4.2

Page 5 of 15

DESIGN CONSIDERATIONS

The following list summarises topics to consider for well design, as part of the PDDP: 4.2.1

4.2.1.1

Hole Size: Evaluation

Logging

May determine where casing shoe is set as a function of geology. Requirement for cased hole logging tools must be discussed with production eg links for inclusion of radioactive 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 required for 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 DST packer 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 of optimum flowrates and productivity index. (Making the liner part of the completion eg monobore system.)

4.2.1.5

Formation Damage

Optimising casing seat depths to minimise formation/skin damage, as a function of mud overbalance and time exposure. 4.2.2

4.2.2.1

Hole Size: Drilling

Drill String/BHA Sizes

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

4.2.2.2

Fishing Equipment

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

DESIGN PREPARATION

4.2.2.3

Page 6 of 15

Well Control

Lack of contingencies for additional hole sections if utilising slimhole/reduced OD designs, lack of structural support for BOPs and subsequent casing strings if reducing casing/hole size after conductor set, reduction in kick tolerance margins for small hole sizes 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 of casing 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 at the conceptual stage, between the drilling, petroleum, production and completion engineers to ensure all iterations and sizing issues are discussed, for initial installation and 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 well for future uncemented production operations.

4.2.3.3

Production Tubulars

Optimising the completion tubular design to maximise the well inflow (Productivity Index) 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 dictate a minimum casing size, or liner overlap length. Alternatively, it may be installed as part of 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, completion size and sand control issues. Systems include electric submersible pumps (ESPs), gas lift (side pocket mandrels), jet pumps, beam pumps etc. May require composite casing strings, eg 10-3/4in/9-5/8in. The issues are generally related to annular clearance and access.

DESIGN PREPARATION

4.2.3.6

Page 7 of 15

Subsea Systems

Issues affecting casing design generally relate to well access and ID of casing eg dual bore tubing hangers for annulus monitoring capability, or downhole gauges. Also structural integrity of conductor/surface casings, as part of well design on wellhead/xmas tree system. Also subsea xmas trees and production systems can apply high cyclic loads to the wellhead and shallow casings. Tubular fatigue life should be considered and the tubular specifications, cement tops and wellhead design should be optimised to meet the well life objectives.

4.2.3.7

Multiple Completions

Multiple completions impose restraints on casing internal diameters, with the need to run two or more tubing strings in parallel. Additionally, for wells completed with both production and injection strings, the casing analysis must consider all ranges of pressure 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 be aware 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, full evacuation of the string to atmospheric pressure must be assumed for the internal pressure profile. This condition represents a blowout where the open hole formation bridges and the gas is allowed to bleed to zero at surface. Similarly for burst, the worst condition is a shut-in full reservoir column at surface, or the subsea wellhead for the production casing string.

4.2.4.2

Air, Foam, Aerated Drilling

When air drilling is used, the wellbore pressure could become atmospheric in the event of equipment failure. Similarly, foam drilling is subject to the hazard that the foam can lose stability and the liquid phase can drop out. If these scenarios are likely, the casing should be designed to withstand full internal evacuation, unlike the base case, where evacuation is likely to be partial. For aerated drilling, the designer should consider the internal evacuation level that can be expected, based on the pore-pressure profile in the event of equipment failure preventing fluid supply. Production casing string designed for blowout as above.

DESIGN PREPARATION

4.2.4.3

Page 8 of 15

High Pressure, High Temperature

In such environments, high differential pressures lead to the use of high strength, thickwalled and non-standard casings. High temperatures compound the design by reducing the yield strength of the steel. This causes thermal linear expansion of the steel and generates high pressures in sealed annuli, due to thermal expansion of the fluid. The following issues should be considered based on the loads experienced by the casing and the capacity of the casing to resist loads. A triaxial stress analysis is the recommended approach for such wells. a. Casing Loads High tensile, or compressive axial forces on the casing affect the ability to resist collapse and burst pressures. This is more significant in high pressure, high temperature (HPHT) wells due to the high pressures involved. Also a buildup of annulus pressures due to thermal expansion of fluid in sealed annuli which cannot be bled off eg subsea wells should be considered. Annular pressures that may be high during production, should be estimated with iterative computer simulations. High buckling potential occurs due to linear expansion from large temperature increases during deeper drilling and testing/production. The increase in drilling fluid density during deeper drilling, adds to this buckling potential. Testing programmes should ensure the casing is capable of withstanding the anticipated burst loads and needs careful design when combination strings are planned. The axial loads resulting from retrievable test packers, eg pressure testing and 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 sour conditions (0.05psia) in the NACE standard, is achieved at relatively low H2S concentrations. Because of the lower temperatures, sour service tubulars are usually required at shallow depths. NACE requires the use of relatively low yield steel (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, this may require the use of thicker wall, non-standard tubulars. This can have an effect on the design due to annular clearance restrictions and lead to long delivery times for specialist casing sizes. The need for gas-tight connections operating at high temperatures and differential pressures requires careful consideration. Only suitably qualified connections that have evidence to retain a gas-tight seal and connection should be used. The effects of dimensional tolerances on casing performance also influences casing selection. The required casing rating may be achieved by a tightening of the manufacturer’s API tolerances, rather than use non-standard casing. Reduction of the casing material yield strength at high temperatures requires down-rating as discussed within earlier sections, based on the anticipated downhole temperature. Several drilling liners may be required to allow deeper drilling, as the mud weights required for high pore pressure transition zones may be close to the formation breakdown gradient.

DESIGN PREPARATION

4.2.4.4

Page 9 of 15

Deepwater

Deepwater wells present a number of issues for casing design; casing setting depth and environmental loads above the seabed. First, these regions have lower fracture gradients than equivalent depths for land, or offshore wells in shallow water. As the water depth increases, fracture gradients are significantly different (weaker) particularly in the shallow sections of the well. Selection of 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 marine conductor and subsea wellhead system. Fatigue loads from these conditions should be assessed. Cementation of the conductor to the seabed and centralisation should take into account the transfer of loads between the conductor and surface casing. There is a tendency for surface formations to show fluid tendencies and as a result drilling/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 assuming bridging should be considered, as the surface equipment will experience the highest 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 development where cross-flow, communication, or recharging could occur on surrounding wells. b. DST Activities Exploration wells should consider maximum pressures required to operate DST tools, tubing conveyed perforating systems and maximum pressures required for bull-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 on development wells, in terms of satisfying environmental legislation. The design of casing strings that are to be utilised as cuttings re-injection routes must 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 production casings.

DESIGN PREPARATION

4.2.4.6

Page 10 of 15

Gas Lift

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


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




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

Pressure profiles for the production phase in the ‘A’ annulus should therefore be considered 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 of additional burst loads, axial loads and corrosion. In particular, fracture stimulation screen-out leading to excessive pressures on the wellbore and the potential breakdown of formations at the weak point.

4.2.4.8

Mobile Formations

When hole sections are drilled through plastic, mobile salt formations, the salt gradually moves and can make contact with the casing. Problems due to salt plasticity can be major for casing strings run through a salt formation, especially after installation. In most sedimentary rocks it is unusual for the formation pressures to equal the overburden due to the element of support provided by the grain to grain contact within the rock matrix. However, the homogeneous crystalline nature of salt coupled with its plastic properties, allows the material to transmit lateral loads equivalent to the overburden pressure. These can take the form of non-uniformly, or uniformly distributed loads. The effects of these are different and tend to result from different rates of salt movement:

DESIGN PREPARATION

Page 11 of 15

a. Non-uniform Caused by washed-out hole sections and/or unevenly cemented casing annuli. This will 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 in high shear stresses, which can cause casing failure at much lower loads than when applied 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 resulting increase in axial stress on one side of the casing may lead to a reduced collapse pressure, or fail due to the bending stresses alone. b. Uniform This is a result of the salt transmitting the overburden pressure in a complete uniform manner (ie 360) over a considerable length of the casing. This can be effectively modelled by substituting the overburden pressure at any depth for the hydrostatic pressure. The most important criteria to reduce collapse loading on a salt section is to minimise hole enlargement during drilling and successfully complete the cementation with a concentric uniform sheath. This will assist in distributing the collapse load in a uniform manner. The salt loads can induce an external pressure load equal to the formation overburden 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 be extremely high. The phenomenon is time dependent, such that during the drilling phase, increased external loading due to the moving salt may be small. However, for a development well during production, salt loading may be quite significant. Following this, casing should be designed to withstand a concentrically uniform pressure, 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 and compressive loads within the elastic range of the casing material. However, the design of steam wells is complicated as the axial stress can exceed the yield strength in compression during heating and/or exceeds the yield strength in tension during subsequent cooling. This can lead to cyclic stresses and ultimately fatigue failure. Thus the design needs to consider post yield behaviour of both casing and connections. Computer simulations should form part of the design for such wells in terms of the axial loads, cementation tops, collapse loads, burst loads, temperature yield strength reduction and selection of qualified connectors.

DESIGN PREPARATION

4.2.4.10

Page 12 of 15

Reservoir Compaction

Production of the reservoir fluids will eventually lead to a partial reduction in reservoir pore pressure if the pressure is not fully maintained by a drive mechanism. The resulting increase in effective stress leads to reservoir compaction and deformation of the overburden. The vertical strain caused by compaction of the producing interval is transferred to a certain extent to the casing string(s) set across that interval. The casing will undergo axial deformation and in deviated wells, lateral deformation such as bending, ovalisation or crushing. These lateral loads are comparable in type to squeezing salt formations but less in magnitude and severity. Excessive overburden deformation can lead to localised slip across faults and bedding planes, leading to a shearing of the casing. Such issues if anticipated in a field, may require the co-operation and the analysis by geotechnical 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 main host well. For the horizontal section, the stability of the formation must be determined, in order to assess if the casing has to withstand full overburden formation pressure. This is then linked to the casing loads and casing selection for collapse. For short radius buildup sections, bending stresses can be significant. For particularly high build rates, localised bending stress concentrations can occur near casing couplings due to the difference in outer diameter of casing and coupling. All casings that pass through high doglegs must be designed to withstand the bending stresses generated. Due to high contact forces between casing and borehole wall in highly deviated sections of the well, dynamic drag and torque loads will be high. Drag loads may be such that once the casing string passes a given depth, the total axial force required to pull the string upwards exceeds the axial capacity of the pipe. Therefore drag, torque and 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 for complicated perforating operations. The reduction in axial capacity (and various holing patterns configuration) will need to be considered. This can be achieved by calculating the stress concentration factor that results from the presence of the hole and comparing the resulting stress with the casing material yield stress.

4.2.4.12

Corrosion

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

DESIGN PREPARATION

4.2.5

Page 13 of 15

Contingencies

Casing design should consider the well on a life cycle basis, not just on initial use but anticipated use and alternative loads. This should take into account modifications that may occur as part of the well design and unplanned incidents, due to operational constraints.

4.2.5.1

Sidetrack(s)

All well designs should consider if it is robust to accept the load conditions for a sidetrack, whether it is a vertical exploration, or high angle development well. The assumptions and potential pressure regimes should be checked to ensure the design is fit for purpose for all anticipated loads. This will provide flexibility and assurance in terms 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 to hydrocarbon pockets. This will have an impact on directional well profiles, torque/drag analysis, casing seat optimisation, review of casing weights/grades and ultimate hole size for drilling. Well deepening sidetracks may also occur as a well re-entry to a new objective from an existing well. This could be a new target objective, or pressure regime. Unplanned sidetracks due to operational problems will require re-assessment during the 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 seismic surveys. Consequently there is a degree of variance in the depth at which an exploration well will be terminated. This has an impact in terms of well design, as the operating envelope for the original design 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 the geophysicist and geologist. In some situations depth masking can occur (salts/ carbonates/unconformities) which makes depth estimation difficult and can demand large casing design contingencies.

DESIGN PREPARATION

4.2.5.3

Page 14 of 15

Well Conversions

During its life cycle a well may be changed to an alternative use. The well designer needs to ensure that the operating envelope addresses such scenarios at the Well Specification 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 the Drilling Engineer. Its purpose is to bring together all of the data collated from the PDDP on a single template. It acts as a formal document for the well designer. It must be signed 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 design process should be documented on the Well Design Checklist shown in Section 2.6 of the Well Design Manual.

4.4

m

Lithology and Faults

Hydrocarbons

Casing

Formations

Chrono Strat

Actual

Ft

Predicted

General Reference Datum

TV

COMPANY:

P RO G N O S I S Trajector y Targets

DEPTH

WELL:

DATE:......./....../...... PORE PRESSURES, MW, LOT DATA PREDICTIONS

COMMENTS

Mar kers (2 way time. depth accuracy of prediction. Faults) and Comments (source rocks, structural dips)

Decisions / Policy PSI 2,000

4,000

6,000

8,000

10,000

Remarks / Comments

Coring

5000

SWS / Ditch Cuttings

2000

5000

RFT

3000

10000

Drill Stem Tests / Production Tests

Mudlogging / MWD

DESIGN PREPARATION

1000

TD / Abandonment Decision

WELL DESIGN DATA SUMMARY SHEET

Well Design Data Summary Sheet WELL SUMMARY PROGNOSIS AND RESULTS

10000 1.0 PSI / Ft

WST / VSP

4000

Logging

0.435 PSI / Ft

Drilling Engineer Originator

G & G Super visor Checked and Approved

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

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

Senior Drilling Engineer Approved:

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

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

Page 15 of 15

G & G Originator

SECTION 5

Drilling and Production Operations

Ref: CDES 05

CASING DESIGN MANUAL

Issue: Feb 2000

CASING SEAT SELECTION

Page 1 of 13

TABLE OF CONTENTS 5.

CASING SEAT SELECTION.................................................................................. 2 5.1

KICK TOLERANCE ......................................................................................... 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

5.

CASING SEAT SELECTION

5.1

KICK TOLERANCE

5.1.1

Concepts

Page 2 of 13

The concept of kick tolerance and its detailed application are covered in the Well Control 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 it requires regular calculation, are summarised within this document. In terms of casing design, kick tolerance is an estimate of the volume of a gas influx at 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 gas composition data from a known area, a gas gradient of 0.1psi/ft should be used down to 10,000ft true vertical depth (TVD). Thereafter, use 0.15psi/ft to the total depth. 5.1.2

Design Requirements

For casing design setting that the casing shoe will reaches the shoe depth. worst scenario for casing gas condensate.

depth requirements in most cases, the maximum pressure be exposed to will occur when the top of the gas influx Gas is used as the influx criterion, as it represents the design safety. For example, gas caps in a reservoir and

The initial setting depth assessment will determine if the well is able to take a minimum of a 100bbl limited gas kick displacement for the production hole section and for the intermediate and surface casing strings. There may be circumstances however, where intermediate and surface casings can justify an influx gradient that is not a dry gas, for a known, non hydrocarbon-bearing zone. This will require rigorous assessment, detailed local offset data and a dispensation by the appropriate drilling management, in order to adopt this approach for the principle of casing design setting depths.

CASING SEAT SELECTION

Page 3 of 13

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


Production Hole Section:

Ability to shut in and circulate out a minimum 100bbl limited gas kick back to the previous shoe.




Intermediate String Hole Section:

Ability to shut in and circulate out a minimum 100bbl limited gas kick back to the previous shoe.




Surface Casing:

Ability to shut in and circulate out a minimum 100bbl limited gas kick (if BOP equipment installed). These criteria may be relaxed where it is known that there are no hydrocarbons and the surface string is set in a competent formation.




Conductor Casing:

No well control equipment installed, not deemed as a pressure vessel.

The worst design scenario occurs when there is no trip margin (mud weight balances formation pore pressure). Therefore the kick tolerance is calculated, based on the provisional setting depth. If the criteria for a 100bbl gas kick tolerance proves to be too onerous (ie resulting in excessive number of casing strings with short hole sections), consideration will have to be given to obtaining the appropriate written dispensation for the casing design. This type of policy relaxation may be required on wells that are prognosed to encounter abnormal pressures with a rapid change in pore pressure over a relatively short transition zone (eg high pressure, high temperature (HPHT) wells). If a lower kick tolerance is used, all relevant programmes, procedures and meetings should record and highlight this information. One of the basic objectives of casing design is to ensure the casing is stronger than the open hole formations. In a well control situation, it is better to have an open hole formation failure/underground blowout, than to have a casing failure and surface 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 burst design; ie the casing string must always be stronger than the maximum anticipated pressures at the casing shoe, while circulating out a gas influx. However, there may be circumstances where this is not possible eg in granite/dolomite formations.

CASING SEAT SELECTION

5.1.3

Page 4 of 13

Kick Tolerance Requirements

The kick tolerance within a well must be constantly re-evaluated as the well is drilled. It is not acceptable to calculate the kick tolerance purely at the design stage, or at the current position in a well while drilling. It should also be calculated for conditions that are 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 kick tolerance for a range of likely mud weights and pore pressures and plot on a graph to check impact and sensitivity on kick tolerance size




For hole sections containing rapid pore pressure increases, at intervals across the area of increasing pressure




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




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

5.1.4

Kick Tolerance Calculations

When calculating a kick tolerance during design or drilling conditions, the Drilling Engineer should check whether the worst condition is at initial shut in, or with the expanded circulated influx beneath the identified weak point. For most cases this will generally be the casing shoe. However, there may be a weaker zone at a depth beneath the casing shoe; this would then dominate the design (eg weaker permeable non 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 the casing design

5.1.5

Rig/Well Types

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

CASING SEAT SELECTION

5.1.6

Page 5 of 13

How to Calculate Kick Tolerance

Outlined below is a summary of how the kick tolerance equations should be used for casing design and for checking that the casing string remains fit for purpose during the drilling of the well. This assumes the provisional initial casing setting depths have been selected for the well. 1. Determine the safety margin to be applied to the LOT or leak off pressure, at the identified 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 require assessment by the Drilling Engineer, to determine the total safety margin to be subtracted 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 the maximum 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. (P H

max

  P )   TD  D MW  0.052 f wp    (0.052  MW )  gg

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.

CASING SEAT SELECTION

Page 6 of 13

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 an actual 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 if H > than the BHA, ie take into account capacity of drillpipe/open hole and drill collar/open hole. 5. Calculate the volume that this height corresponds to when the top of influx is circulated to the open hole weak point. Again, for a deviated well, convert the H value in 3. above to an actual measured or along-hole depth at the open hole weak 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 below the open hole weak point, relative to height of influx. 6. Calculate what Vwp (as calculated in step 5) would be at the initial shut-in conditions. Using Boyle’s Law to convert this volume to its original volume at initial shut-in conditions: P1 x V1

= P2 x V2 or in this case:

Pf x V2

= Pmax x Vwp

V2

=

Pmax  Vwp Pf

CASING SEAT SELECTION

Page 7 of 13

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 is outlined 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

Annular Capacity 

HoleDiam2  PipeOD2 bbls per foot 1029.4

a. Estimate safety margin to be applied to leak off pressure at open-hole weak 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. H H


6324  8923   
13000  8800  13.2  0.052 ft 
13.2  0.052  1 = 484ft

d. Calculate the volume that height corresponds to above the bit depth. V1

= 484 x 0.08361 (bbl) = 40.5bbl

CASING SEAT SELECTION

Page 8 of 13

e. Calculate volume that this height corresponds to when top of influx at open hole weak point. Vwp f.

= 484 x 0.12149 (bbl) = 58.8bbl

Calculate what this volume would be at initial shut-in conditions. V2 

6324  58.8  41.67 bbl 8923

Therefore, the kick tolerance is V1 (40.5bbl) as this is the lower of the two calculated values 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 the optimum number of casing and liner strings. The minimum casing shoe setting depths are driven by many considerations, which are summarised within this section. The primary consideration is to prevent failure of the formation below the casing shoe and to ensure the open hole section remains intact for all of the anticipated load conditions. 5.2.2

Bottom Up/Top Down

The selection of casing setting depths is based on the anticipated pore pressure and the fracture gradient profiles. The Drilling Engineer should ensure that the offset data has been taken into consideration for the final estimation of the pore and fracture gradients, including reduction in fracture strength as a result of the hole angle (for example: high angle or horizontal wells). The final depth of the well and setting depth of the production casing or liner, is driven by the requirements for logging, testing and completion design. The casing shoe must be set deep enough to give an adequate sump for running casing, logging, perforating and testing activities. Hence, the philosophy of starting from the bottom up, with definition 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 maximum mud 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.

Page 9 of 13

CASING SEAT SELECTION

Figure 5.1 - Initial Casing Setting Depths 0

N o rm a l P re s s u re

C o n du c tor 1 0 00

2 0 00

3 0 00

T rue Vertical; Depth (T VD), ft

4 0 00

Su rfa c e C a sing F ra c tu re G rad ien t

M u d W eig ht C u rv e

In te rm e diate C a sing D e sign F ra c tu re G ra die nt In clu din g K ick a nd C e m en tin g M a rg in

E D

5 0 00

6 0 00 P ro d uc tio n C a sing

P o re Pre ss ure G rad ien t

7 0 00

C

8 0 00

B 9 0 00

1 00 0 0 P ro d uc tio n L in e r 1 10 0 0

A

1 20 0 0 8

10

12

14

16

18

20

Equivalent Mud Weight, ppg

5.2.3

Setting Depth Guidelines

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


First draw the mean pore pressure and anticipated fracture gradient profiles on a chart 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 cause potential 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 for offshore mobile rigs. Be aware that the maximum mud weight required may not be for pore pressure requirements, but borehole stability considerations




Then draw a design fracture gradient. This should include a reduction to take into account 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 pack on a separate profile chart, to provide a check of the pore pressure/fracture gradient predictions

CASING SEAT SELECTION

Page 10 of 13

Once the pore pressure, fracture gradient and mud weight curves are drawn, proceed to 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 depth for the production casing, in order to drill the hole to TD




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




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




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

This process is repeated for all of the remaining casing strings. However, the conductor is the exception, this is based on the shallowest setting depth at which bottom hole pressure created by the mud being circulated (ECD) during the drilling of the next section, 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 the optimum casing shoes for a well. These include:


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




Lost Circulation/Weak Zones: May require isolation prior to entering a higher pressure formation, such as limestones and dolomites with a weak fracture gradient and/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 sandstone with a weak fracture gradient may require isolation due to increased differential pressure between formation and wellbore with high mud weights. High formation permeabilities and increasing fluid loss, or thicker mud cakes can worsen the situation




Formation Hole Stability: Formations with reactive/unstable shales which may be sensitive 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 as transition zones in high pressure wells may require isolation, prior to drilling into the overpressured transition zone

CASING SEAT SELECTION

Page 11 of 13




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 this influences the axial loads and external pressure profiles used during detailed design. 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 ‘quick look’ casing setting depths, redefine the casing shoes to ensure that they are set in competent formations. This should also take into account the uncertainty (error bars) in the 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 an influx occurring. The next stage is to determine the kick tolerance associated with each respective casing shoe. Start from TD up to the surface string to determine the kick tolerance and preferred setting depth for each casing. A series of iterations and adjustments may be required in order to come up with the optimum casing shoe, with the correct kick tolerance in a competent formation. For the conductor, the setting depth should provide sufficient strength at the shoe to allow circulation of the heaviest anticipated mud weight for the next hole section, and support the loads from the wellhead, BOP and additional casing strings. This assumes no hydrocarbons are present in the next interval and should take into consideration the maximum mud weight, ECD and additional density due to cuttings in the annulus. A schematic outlining the method for determining the minimum setting depth for a conductor 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 low as the seawater column dominates it. Whereas, the mud pressure is high, due to the length of the mud hydrostatic column and the additional ECD from high rates of penetration (ROPs) and cuttings loading. This results in a minimum setting depth that is so deep, that it cannot be achieved due to hole problems, or the small window between fracture pressure and the mud ECD. One common solution is to insert a hole in the conductor just above MSL and take returns to the sea at this level. This reduces the mud hydrostatic column in the riser. The ROP is also restricted to reduce the impact of cuttings loading on the mud ECD. The Engineer should re-plot the conductor setting depth diagram for this scenario, to assess the impact.

CASING SEAT SELECTION

Page 12 of 13

Figure 5.2 - Minimum Setting Depth for Conductor 0

D a tu m - R ota ry T a b le

M ea n S e a L e ve l S e a W a ter G ra d ien t

D epth (B elow R ota ry T able - B R T )

Sea Bed

F ra ctu re G ra d ie n t

E ffe c tive M u d G ra d ie n t (N e xt h o le se ctio n ) (E C D + F lu id D e n sity du e to M W a n d d rille d so lid s)

M inimu m C a sin g S e ttin g D e p th (W h e re th e fra cture gra dien t is e q u a l to the effe ctiv e mu d d e n sity fo r th e n e xt se ctio n )

P ressure

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


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




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




Broaching across to an adjacent conductor and losing conductor support on producing, or completed wells

CASING SEAT SELECTION

5.2.6

Page 13 of 13

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 maximum mud weights anticipated for each hole section




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




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

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

SECTION 6

Drilling and Production Operations

Ref: CDES 06

CASING DESIGN MANUAL

Issue: Feb 2000

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 6.5.6.1

Special Load Cases................................................................................... 26 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

MECHANICAL DESIGN

6.

MECHANICAL DESIGN

6.1

BACKGROUND

Page 3 of 60

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 and so will not include information, or calculations, on a triaxial analysis for combined stress 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 and Drillpipe

In order to describe a mechanical design, the criteria will be summarised from the above 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 a result 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 guideline to the need for a biaxial stress analysis. The casing designer must consider the particular 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 that fall within these criteria are validated by a triaxial analysis, via a computer software package.

MECHANICAL DESIGN

6.2

Page 4 of 60

DEFINITIONS

To perform a mechanical design of a casing string, we need to know the minimum required strength of the pipe for the anticipated load conditions. We then calculate the optimum mechanical properties of the casing. For a uniaxial design the strength of 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 external pressure, the casing is exposed to a burst pressure. This is the normal condition and is only a concern if the burst pressure exceeds yield limits. This can be caused by well control 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 internal pressure, the casing is exposed to a collapse pressure. This can occur due to loss of hydrostatic pressure inside the casing (well evacuation), excessive increase in external pressure outside the casing (cementing) or mechanical loads such as mobile salt formations. 6.2.3

Tensile (Axial)

If a casing string is subjected to an axial load or pull that is greater than the tensile rating of either the pipe body or of the connection, failure may take place. This can occur as a result of excessive string length, pulling of stuck pipe, thermal contraction or pressure testing.

MECHANICAL DESIGN

6.2.4

Page 5 of 60

Compression

If a casing string is subjected to a compressive axial load or push that is greater than the elastic limit of the pipe body, failure can take place. This may be due to thermal expansion, 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 configuration may become unstable. The casing, confined within the open hole or casing, may deform 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 in the elastic phase and does not create subsequent drillstring, tubular or completion 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 plastic phase due to a high local dogleg, the configuration may remain unstable, leading to a stress concentration factor at the dogleg, potentially leading on to cyclic stresses and ultimately fatigue failure.

6.2.5

Biaxial (Combined Loads)

This is based on combined collapse and tension. If a casing is subjected to a combination of an external pressure plus axial load that is greater than the adjusted tensile rating of the pipe body or connection, failure can occur at lower load conditions than from either factor separately. The collapse regime may change on application of an axial load as the Diameter/Wall Thickness constants (D/t) may change. Thus as the tensile load increases for the pipe, the resistance to collapse pressure decreases. The biaxial effect becomes more important for long casing strings, high mud weights and 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 tension or compression rating of the connection, failure can occur. Additionally, if the internal yield pressure (burst) is greater than the burst rating of the connection, failure can occur. API Specification 5B discusses the dimensional requirements for API connections. API Bulletin 5C2 discusses the mechanical properties of not only the pipe body, 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 that the design checks both pipe body and connection for each string, to determine the weaker component of the design. For non-API connections, manufacturers should provide all of the mechanical properties with the pipe data sheet, in order that the designer can confirm the connection is (if possible) ‘pipe body matched’.

MECHANICAL DESIGN

6.3

Page 6 of 60

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 reader to 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 properties within API Bulletin 5C2. The internal yield pressure for plain end pipe is given by the API Bulletin 5C3 formula:  2Yp t    D 

P 0.875  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 at which the tangential (or hoop) stress at the inner pipe wall reaches the yield strength of the material. A burst failure will not actually occur until after the stress exceeds the ultimate tensile strength (UTS). As a result, yield strength as a measure of burst strength is a generally conservative 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 less conservative, because the effect of radial compressive stresses at the inner wall is not considered. The factor 0.875 appearing in the equation above allows for the minimum wall thickness tolerance of -12.5% allowed on API for manufacture of the pipe. This value can be modified for special inspection requirements, for example if the wall tolerance has been specified as 90% minimum wall thickness for a special material order (this would result in a higher burst rating for the pipe).

MECHANICAL DESIGN

6.3.2

Page 7 of 60

Collapse

The API collapse rating can be determined from the published tables within API Bulletin 5C2, Performance Properties of Casing, Tubing and Drillpipe. The following notes provide an overview of the approach to adopt for collapse pressure 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 design may be conservative. If the failure mode is plastic, it will still be acceptable but the designer needs to be aware that some permanent deformation may take place. Figure 6.1 shows the stress/strain diagram with the elastic and yield limits. Figure 6.1 - Stress/Strain Diagram Ultimate Tensile Stress (Maximum stress achieved)

STRESS

Elastic Limit (Point beyond which increasing strain will lead to permanent deformation) Yield Point (Increase in strain gives minimal increase in stress)

Proportional Limit (End of straight line, stress no longer proportional to strain)

STRAIN

Collapse strength is primarily a function of the material’s yield strength and its slenderness ratio, D/t. The collapse strength criteria within API Bulletin 5C3 consist of four collapse regimes that are determined on the basis of yield strength and slenderness ratio. For low D/t ratios, failure is governed by yield on the inner surface of the casing. For intermediate D/t ratios, collapse occurs by plastic instability. For high D/t ratios, it is governed by elastic instability. There is a fourth regime called transition instability, which is a fictitious mechanism linked to plastic collapse.

Page 8 of 60

MECHANICAL DESIGN

They are shown schematically in Figure 6.2 for Collapse Strength as a function of D/t. Figure 6.2 - Collapse Strength

Theoretical Elastic Instability



at ID YP

Material Yield Actual Collapse Behaviour

Plastic Collapse

Yield Strength Collapse 15+/-

Transition Collapse

Elastic Collapse 25+/-

Slenderness Ratio, D/t

As explained within API 5C3, this is a pictorial representation of the four collapse modes which are: elastic, transition, plastic and yield. The collapse of the material is not 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 a series 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 to experience in operation.

MECHANICAL DESIGN

6.3.2.1

Page 9 of 60

Yield Strength Collapse

This is based on yield at the inner wall using the Lame thick-wall elastic criteria. It does not represent a true ‘collapse’ pressure and represents a D/t ratio for thick-walled pipes < ±15. The tangential stress will exceed the yield strength of the material before a collapse instability failure occurs. Nominal dimensions are used in the collapse equations. 
D / t  1 2  
D / t  

PYp 2Yp  Where: PYp

=

External Yield Pressure (psi)

D

=

Nominal Outside Diameter (in)

t

=

Nominal Wall Thickness (in)

Yp

=

Specified Minimum Yield Strength (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-110 seamless casing. No analytical expression has been derived that accurately models collapse behaviour in this regime. Regression analysis results in a 95% confidence level that 99.5% of all pipes manufactured to API specifications will fail at a collapse pressure 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 the following: 

B C  D / t  A

Pp YP  Where: Pp

= External Plastic Pressure (psi)

D

= Nominal Outside Diameter (in)

t

= Nominal Wall Thickness (in)

Yp

= Specified Minimum Yield Strength (psi)

A, B and C are formula factors for various grades that are calculated from formulae listed within API Bulletin 5C3. It is worth noting that most oilfield tubulars generally experience collapse in the plastic and transition regimes.

MECHANICAL DESIGN

6.3.2.3

Page 10 of 60

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:  F

PT Yp 

D / t



G 

Where: PT

= External Transition Pressure (psi)

D

= Nominal Outside Diameter (in)

t

= Nominal Wall Thickness (in)

YP

= Specified Minimum Yield Strength (psi)

F and G are formula factors for various grades that are calculated from formulae listed within 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 of yield 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: PE

46.95  10 6
D / t  
D / t  1 2

Where: PE

= External Elastic Pressure (psi)

D

= Nominal Outside Diameter (in)

t

= Nominal Wall Thickness (in)

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 (biaxial effect). This is of particular note for large diameter casings. Elastic stability analysis shows that elastic collapse is unaffected by axial load (ie returns to natural condition, with no permanent deformation).

Page 11 of 60

MECHANICAL DESIGN

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 reducing the yield stress of the material, ie as the axial tension increases, the available collapse strength reduces. This results in a modified yield strength (Ypa) of an axial stress equivalent grade. Thus the collapse resistance of casing in the presence of an axial stress is calculated by modifying the yield stress to an axial stress equivalent grade. This is given by the equation from API Bulletin 5C3: 



2

S  S Ypa  1 0.75 a 0.5 a  Yp Y Y 



p

p



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 to the 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 the other collapse equations, the reduced collapse strength of the casing under axial tension.

6.3.2.6

Constants for Collapse Equations

The constants A, B, C, F and G are calculated from formulae given in API 5C3 as follows: -5

A = 2.8762 + 0.10679 x 10 Yp + 0.21301 x 10

-10

2

Yp – 0.53132 x 10

-16

-6

B = 0.026233 + 0.50609 x 10 YP -7

2

C = -465.93 + 0.030867 YP – 0.10483 x 10 YP + 0.36989 x 10


 
 F  3
B   3
B   A A
B  1

Y  A   2 
B  2 
B  A A 

  3 B A 46.95 x 10  2  B A 

3

6

P


A

G F B

2

-13

3

YP

3

YP

MECHANICAL DESIGN

6.3.2.7

Page 12 of 60

Critical D/t Ratios for Collapse Equations

Calculate the critical ratios using the equations summarised below from API 5C3 using the appropriate collapse strength equation based on where the casing D/t ratio falls. 


A 22  8  B 

D   t YP



C  
A 2  YP

 C 2  B  Y P 

YP
A F  D   t PT C  YP
B G B

2 D A  3 B  t TE


A

Where: D   t YP

=

intersection point

Yield – Plastic

D   t PT

=

intersection point

Plastic – Transition

D   t TE

=

intersection point

Transition – Elastic

MECHANICAL DESIGN

6.3.2.8

Page 13 of 60

Procedure for Collapse Strength under Axial Tension

The summarised procedure for determining the collapse strength of the casing is as follows: 1.

Estimate the real total tension or compression of the casing string at the point of interest. 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 real tension divided by the cross-sectional area of the pipe.

3.

Determine the adjusted axial stress equivalent grade (Ypa) using the above equation 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, B and 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 or elastic) 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 wellbore fluids. The effect of internal pressure on collapse is summarised by the following formula from API Bulletin 5C3. The internal pressure provides a resistance to the external collapse pressures. Pe = Po – (1 – 2/(D/t))Pi Where: Pe

=

Equivalent External Pressure (psi)

Po

=

External Pressure (psi)

Pi

=

Internal Pressure (psi)

D

=

Nominal Outside Diameter (in)

t

=

Nominal Wall Thickness (in)

This is based on the internal pressure acting on the inside diameter and the external pressure acting on the outside diameter.

MECHANICAL DESIGN

Page 14 of 60

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 the two (this may finalise as a collapse or burst pressure). If, for example, excessive collapse pressures were anticipated, then increasing internal pressures would reduce this potential for collapse. For values D/t greater than the ratio for yield strength collapse (typically casings 9-5/8in upwards), 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 from API Bulletin 5C3 as: Py



4


D

2

d

2

Y

p

Where: Py

= Pipe Body Yield Strength (psi)

D

= Specified Outside Diameter (in)

d

= Specified Inside Diameter (in)

Yp

= Specified Minimum Yield Strength (psi)

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 tensile rating of the design may be limited to the joint (connection) rating, rather than the pipe body.

MECHANICAL DESIGN

6.3.4

Page 15 of 60

Joint Strength (Connectors)

The joint or connection strength should be assessed in the same manner as the pipe body, in particular for axial and burst strength. API Bulletin 5C3 discusses these subjects and provides formulae for the internal yield pressure for couplings (burst and leakage) and joint strengths. The main issue to note is that API 5C3 lists the equations associated for API designated connections only (short round, buttress and extreme-line casing). The leak resistance of API connections can be improved through the use of tighter tolerances and coatings. Ultimately, the main driver for mechanical design is to ensure the strength of the connectors are greater than or equal to the pipe body. This may not always be possible, 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 the connections and identify (if possible) ‘pipe body matching’ for the connector. The reader should also be aware that the casing design may require the use of slimline, or special clearance connections. This will result in reduced mechanical properties, such as the tensile rating. 6.3.5

Buckling

A limited amount of buckling is acceptable. However, excessive buckling can lead to an unstable condition, which if it exceeds the localised yield strength of the material, may lead to permanent deformation or failure. The mechanical design should consider buckling, as it generates bending stresses, casing movement and release of compressive loads.

6.4

REPSOL MINIMUM DESIGN FACTORS

The design factors for uniaxial casing design are defined on values used throughout the world over a number of years. Summaries of the respective values are detailed below for burst, collapse, tension and compression design. They are based on the API Bulletin 5C2 Performance on Properties of Casing, Tubing and Drillpipe, plus API Bulletin 5C3 Formulae and Calculations for Casing, Tubing, Drillpipe and Line Pipe Properties. It is worth noting that the design factors take into account the uncertainties in the manufacturing process and tolerances. However, they do not include an allowance for issues such as casing wear and corrosion. The design factors quoted will be utilised for exploration, appraisal and development wells.

MECHANICAL DESIGN

6.4.1

Page 16 of 60

Burst Design Factor

Burst design loads have evolved and now typically include annular fluid behaviour and thermal effects. However, in terms of an API Bulletin 5C3 uniaxial design, the burst capacity of casing is related only to the yield strength of the material. A degree of conservatism is built into the values for the tables in API Bulletin 5C2, since the initial yield under burst-loading conditions will not lead to failure, even if the API conditions are 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, the consequences are more severe in terms of wellbore safety. Based on this probability a uniaxial burst design factor of 1.1 will be used for burst design. 6.4.2

Collapse Design Factor

The reliability of casing collapse capacities is high as a function of the tightly controlled manufacturing processes, coupled with studies that indicate these values are occasionally conservative. Based on this premise and the fact that downrating from wear and tension should be treated separately, a uniaxial collapse design factor of 1.0 will be used for collapse design. 6.4.3

Tension Design Factor

Tension utilises two design factors. Most axial tension arises from the weight of the casing itself during the running of the pipe. The top joint of the string is generally the weakest point, as it carries the total weight of the casing string. As there are a number of factors to take into consideration for tensile (axial) loads, the design factors have tended to be split into two factors. For running casing, a uniaxial tensile design factor of 1.6 will be used, as it includes buoyancy and bending loads. For most wells, installation loads will dominate the axial design 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 and pressure testing, a uniaxial tensile design factor of 1.4 will be used. This captures cementing and casing pressure testing operations, which are generally performed under controlled conditions.

MECHANICAL DESIGN

6.4.4

Page 17 of 60

Compression Design Factor

Casing failure due to compressive loading will be due mainly as a result of elastic or plastic instability (helical buckling). Pure compression failure, ie squashing the casing is unlikely to occur. Casing resistance against buckling can be improved by rigidly supporting the casing through centralisation. Thus a uniaxial compression design factor of 1.0 will be used if performing analysis associated with compression. However, compression is generally associated with thermal, nodal points from cementation tops, extended reach drilling (ERD) wells, HPHT wells and shared compression loads of conductor and surface casings. If high compression loads exist, the connection may be the weak point. As a result, issues relating to compression require translation of three-dimensional stress states and typically 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 a triaxial design factor. Various computer packages allow translation of the various load conditions into a three-dimensional stress state. Comparison of the three dimensional stress state with the corrected temperature, yield strength value of the uniaxial is achieved via the Von Mises criterion, which has been extensively used within the industry. The direct comparison of this Von Mises equivalent (VME) stress to the yield strength of the material then provides a single design factor. Based on field experience with triaxial analysis and various computer packages in use throughout the industry, a triaxial design factor of 1.25 will be used for casing design analysis. Because of the benefits, a triaxial analysis should ideally be performed for wells which experience high bottomhole pressures and temperatures (HPHT wells), H2S service, potential buckling, D/t ratios of < 15 (thick wallpipe), combined axial compression and burst conditions. The accuracy of a triaxial analysis relies on an accurate representation of the conditions that the casing will experience during installation and use. 6.4.6

Design Factor Summary

The following design factors are thus applicable for a Repsol casing design and will be used 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

Page 18 of 60

MECHANICAL DESIGN

6.5

MINIMUM DESIGN FACTORS

Note: A detailed explanation of these load cases follows after the tables. 6.5.1

Conductor A. CONDUCTOR

DESIGN LOAD CRITERIA

MINIMUM DESIGN FACTORS

EXPLORATION

DEVELOPMENT

INTERNAL PRESSURE

EXTERNAL PRESSURE

INTERNAL PRESSURE

EXTERNAL PRESSURE

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 and Overpull)

1.4

MW

MW

MW

MW

4.

Ft = Fair – Fbuoy + Fbend + Fplug (Tension Cementing Wet)

1.4

MW + Psurf

MW + CMT

MW + Psurf

MW + CMT

2.

BURST LOADS

1.1

MW + CMT + Psurf

MW

MW + CMT + Psurf

MW

a.

Install

1.

Cement Displacement: MW + Cement + Psurface in Casing

(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 Bridge Pressure

1.0

MW

MW + CMT + BRIDGE P

MW

MW + CMT+ BRIDGE P

b.

Drilling

1.

To Atmospheric: Full Evacuation

1.0

AIR

MW TO SET CSG

AIR

MW TO SET CSG

2.

To Atmospheric: Partial Mud Evacuation (to balance loss zone)

1.0

FW/SW TO BALANCE

MW TO SET CSG

FW/SW TO BALANCE

MW TO SET CSG

c.

Service (No loads apply)

Note: In the table above and in all subsequent tables, the assumption has been made of using seawater (SW) for cement mixing. For land wells particularly, this may need to be replaced with fresh water (FW). The appropriate liquid density must be used.

Page 19 of 60

MECHANICAL DESIGN

6.5.2

Surface Casing B. SURFACE CASING

DESIGN LOAD CRITERIA

MINIMUM DESIGN FACTORS

EXPLORATION

DEVELOPMENT

INTERNAL PRESSURE

EXTERNAL PRESSURE

INTERNAL PRESSURE

EXTERNAL PRESSURE

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 and Overpull)

1.4

MW

MW

MW

MW

4.

Ft = Fair – Fbuoy + Fbend + Fplug (Tension Cementing Wet)

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

2.

Bumping Cement Plug: Psurf + Mud Hydrostatic

1.1

MW + Psurf

MW + WET CMT

MW + Psurf

MW + WET CMT

b.

Drilling Service

1.

Casing Pressure Test after WOC: Psurf + Mud Hydrostatic

1.1

MW + Psurf

SW

MW + Psurf

PORE

2.

Casing Pressure Test after WOC, LOT + 0.5ppg: Psurf + Mud Hydrostatic

1.1

MW + Psurf

SW

MW + Psurf

PORE

3.

Gas Kick: 100bbls Minimum (Circulate out by Driller’s Method)

1.1

GAS KICK PROFILE

SW

GAS KICK PROFILE

PORE

c.

Service (No loads apply)

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 Bridge Pressure

1.0

MW

MW + CMT + BRIDGE P

MW

MW + CMT + BRIDGE P

b.

Drilling

1.

To Atmospheric: Full Evacuation

1.0

AIR

MW TO SET CASING

AIR

MW TO SET CASING

2.

To Atmospheric: Partial Mud Evacuation (to balance loss zone)

1.0

FW/SW TO BALANCE

MW TO SET CASING

FW/SW TO BALANCE

MW TO SET CASING

c.

Service (No loads apply)

Page 20 of 60

MECHANICAL DESIGN

6.5.3

Intermediate Casing/Liners C. INTERMEDIATE CASING/LINERS

DESIGN LOAD CRITERIA

MINIMUM DESIGN FACTORS

EXPLORATION

DEVELOPMENT

INTERNAL PRESSURE

EXTERNAL PRESSURE

INTERNAL PRESSURE

EXTERNAL PRESSURE

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 and Overpull)

1.4

MW

MW

MW

MW

4.

Ft = Fair – Fbuoy + Fbend + Fplug (Tension Cementing Wet)

1.4

MW + Psurf

MW + CMT

MW + Psurf

MW + CMT

5.

Ftbase = Fair – Fbuoy + Fbend + Fpretension (Tension after WOC)

1.4

MW

MW + SW

MW

MW + PORE

2.

BURST LOADS

a.

Install

1.

Cement Displacement: MW + Cement + Psurface in Casing

1.1

MW + CMT + Psurf

MW

MW + CMT + Psurf

MW

2.

Bumping Cement Plug: Psurface + Mud Hydrostatic

1.1

MW + Psurf

MW + WET CMT

MW + Psurf

MW + WET CMT

b.

Drilling

1.

Casing Pressure Test after WOC: Psurface + Mud Hydrostatic

1.1

MW + Psurf

MW TO TOC + SW

MW + Psurf

MUD TO TOC + PORE BELOW

2.

Casing Pressure Test after WOC, LOT + 0.5ppg: Psurf + Mud Hydrostatic

1.1

MW + Psurf

MW TO TOC + SW

MW + Psurf

MUD TO TOC + PORE BELOW

3.

Gas Kick: 100 bbls Minimum (Circulate out by Driller’s Method)

1.1

GAS KICK PROFILE

MW TO TOC + SW

GAS KICK PROFILE

MUD TO TOC + PORE BELOW

c.

Service

1.

Well re-entry: Casing Pressure Test after WOC

1.1

N/A

N/A

MW + Psurf

DEGRADED MUD TO TOC + PORE BELOW

Page 21 of 60

MECHANICAL DESIGN

C. INTERMEDIATE CASING/LINERS DESIGN LOAD CRITERIA

3.

MINIMUM DESIGN FACTORS

EXPLORATION

DEVELOPMENT

INTERNAL PRESSURE

EXTERNAL PRESSURE

INTERNAL PRESSURE

EXTERNAL PRESSURE

COLLAPSE LOADS

a.

Install

1.

Casing Column Cement: Conventional

1.0

MW

MW + CMT

MW

MW + CMT

2.

DP Column Cement: Stab-in + Annulus Bridge Pressure

1.0

MW

MW + CMT + BRIDGE P

MW

MW + CMT + BRIDGE P

b.

Drilling

1.

To Atmospheric: Full Evacuation

1.0

AIR

MW TO SET CASING

AIR

MW TO SET CASING

2.

To Atmospheric: Partial Mud Evacuation (to balance loss zone)

1.0

FW/SW TO BALANCE

MW TO SET CASING

FW/SW TO BALANCE

MW TO SET CASING

c.

Service (No loads apply)

Page 22 of 60

MECHANICAL DESIGN

6.5.4

Production Casing/Liners

D. PRODUCTION CASING/ LINERS DESIGN LOAD CRITERIA

MINIMUM DESIGN FACTORS

EXPLORATION

DEVELOPMENT

INTERNAL PRESSURE

EXTERNAL PRESSURE

INTERNAL PRESSURE

EXTERNAL PRESSURE

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 and Overpull)

1.4

MW

MW

MW

MW

4.

Ft = Fair – Fbuoy + Fbend + Fplug (Tension Cementing Wet)

1.4

MW + Psurf

MW + CMT

MW + Psurf

MW + CMT

5.

Ftbase = Fair – Fbuoy + Fbend + Fpretension (After WOC)

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

1.1

MW + Psurf

MW + WET CMT

MW + Psurf

MW + WET CMT

b.

Drilling

1.

Casing Pressure Test after WOC: Psurf + Mud Hydrostatic

1.1

MW + Psurf

MW TO TOC + SW

MW + Psurf

MUD TO TOC + PORE BELOW

2.

Casing Pressure Test after WOC, LOT + 0.5ppg: Psurf + Mud Hydrostatic

1.1

MW + Psurf

MW TO TOC + SW

MW + Psurf

MUD TO TOC + PORE BELOW

3.

Gas Kick: 100 bbls Minimum (Circulate out by Driller’s Method)

1.1

GAS KICK PROFILE

MW TO TOC + SW

GAS KICK PROFILE

MUD TO TOC + PORE BELOW

c.

Service

1.

Well Re-entry: Casing Pressure Test after WOC

1.1

N/A

N/A

MW + Psurf

DEGRADED MUD TO TOC + PORE BELOW

2.

Shut-in Tubing Pressure: Leak at surface on production packer fluid weight

1.1

SITHP + PACKER FLUID WEIGHT

MW TO TOC + SW

SITHP + PACKER WEIGHT

DEGRADED MUD TO TOC + PORE BELOW

3.

Full Gas to Surface: Pressure at wellhead

1.1

GAS TO SURFACE

MW TO TOC + SW

GAS TO SURFACE

DEGRADED MUD TO TOC + PORE BELOW

4.

DST Operations: Activation of DST Tools/Press. Leak + MW

1.1

DST PRESS + MW

MW TO TOC + SW

DST PRESS + MW

DEGRADED MUD TO TOC + PORE BELOW

Page 23 of 60

MECHANICAL DESIGN

D. PRODUCTION CASING/ LINERS DESIGN LOAD CRITERIA 3.

MINIMUM DESIGN FACTORS

EXPLORATION

DEVELOPMENT

INTERNAL PRESSURE

EXTERNAL PRESSURE

INTERNAL PRESSURE

EXTERNAL PRESSURE

1.0

MW

MW + CMT

MW

MW + CMT

COLLAPSE LOADS

a.

Install

1.

Casing Column Cement: Conventional

b.

Drilling

1.

To Atmospheric: Full Evacuation

1.0

AIR

MW TO SET CASING

AIR

MW TO SET CASING

2.

To Atmospheric: Partial Mud Evacuation (to balance loss zone)

1.0

FW/SW TO BALANCE

MW TO SET CASING

FW/SW TO BALANCE

MW TO SET CASING

c.

Service

1.

Above Packer: Gas Lift, Full Evacuation

1.0

FULL EVAC

MW TO TOC + SW

FULL EVAC

MUD TO TOC + PORE BELOW

2.

Below Packer: Full Evacuation (plugged perforations, depleted reservoir)

1.0

FULL EVAC

MW TO TOC + SW

FULL EVAC

MUD TO TOC + PORE BELOW

MECHANICAL DESIGN

6.5.5

Page 24 of 60

Design Factor Information

The design factor tables presented are for exploration and development wells, based on a number of assumptions and require other issues to be considered, prior to calculating 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 drilling data for the well design in order to determine if the load cases are exploration or development. The design may justify a mix of exploration and load cases, subject to the complexity of the design. As a result, the well designer will need to make an assessment 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 design factors. This must be calculated as a percentage of the wall thickness for each individual well, based on anticipated service life. The API burst, collapse and tensile yield 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 and design factors. This must be calculated for each individual well based on anticipated service 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 and may require calculation depending on well type (exploration or development) and load conditions (dogleg severity, TOCs, subsea or platform). Liner Laps

The pressure behind the liner lap is dependent on the pressure seen at the previous casing shoe. The casing/liner lap assembly acts as a U-tube.

Mud

6.5.5.1

This is the sum of the following external loads: Mud weight down to TOC plus SW from TOC to previous casing shoe minus the SW hydrostatic from the previous casing shoe to the top of the liner lap (see schematic).

Cement

Exploration Well

Development Well Liner Lap

Cement

This is the sum of the following external loads: Pore pressure at the previous casing shoe minus the SW hydrostatic from the previous casing shoe to the top of the liner lap (see schematic).

MECHANICAL DESIGN

6.5.5.2

Page 25 of 60

Load Criteria: General Notes

Burst (for calculation purposes)


For exploration wells (sealed or open annuli): use mud weight (MW) down to top of cement (TOC) and then seawater (SW) to the casing shoe if the cement has set, or cement density if it has not set (ie plug bump/wet pressure testing) as the external pressure (Pe)




For development wells (sealed or open annuli): use mud weight down to TOC if the annulus mud is in reasonable condition and then pore pressure to the casing shoe if the cement has set, or cement density if it has not set (ie plug bump/wet pressure testing) as the external pressure (Pe)




For development wells (open annuli): undergoing service loads a considerable time after the annulus mud was left in place, use degraded mud down to TOC, then pore pressure to casing shoe

Notes: (1)

A sealed annulus is sealed at surface and cemented above the previous casing shoe (ie a trapped annulus). An open annulus is sealed at surface and cemented below the previous casing shoe (ie cement shortfall below shoe).

(2)

Degraded mud for oil based mud (OBM) assumes the oil has separated out 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 based mud (WBM) assumes the water has separated out of the system to mix water at surface, with mud solids below. For an open annulus the mud would then possibly leak away to balance the pore pressure down to the TOC. Above this point would be a column of degraded mud/water or degraded mud/water/base oil.

(3)

OBM can vary considerably in the oil:water ratio. In the absence of well specific 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 the information, 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-up pressure may need to be reduced to a seawater gradient (offshore wells) or a freshwater gradient (land wells). When considering use of degraded mud in annuli for external pressures on a development well, look at the life of field application for the well. During the drilling phase of a development well, use the mud weight as the external pressure backup load. For well re-entries, use a degraded mud profile. This should be discussed with a Senior Engineer as part of the casing design process.

MECHANICAL DESIGN

Page 26 of 60

Collapse Generally, if limited information is available or there is doubt on the quality of the information, 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 may require consideration and assessment for well design.

6.5.6.1

Mobile Salts (Collapse)

Use a uniform overburden external pressure (P e) of 1.0psi/ft if drilling through a mobile salt formation, based on full evacuation for collapse.

6.5.6.2

Annular Fluid Expansion

For wells with sealed annuli, fluid temperature increases during production will cause fluid expansion, culminating in higher fluid pressures. A sealed container that experiences a minor increase in temperature can result in significant additional pressures. 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 a number of iterative calculations and are a concern for production operations and HPHT wells. If this is highlighted as a design issue, the analysis is typically performed by computer software and will involve production and petroleum engineering disciplines to assist the Drilling Engineer. AFE loads may be minimised by designing casing strings with a cement shortfall below the casing shoe, to allow thermal bleed-off, modifying weights and grades and if necessary 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

Page 27 of 60

MECHANICAL DESIGN

Pi

= Average change in internal pressure (psi) eg mud weight change (average differential pressure of mud weight change) or an applied internal pressure over the whole length

 Pe

= Average change in external pressure (psi) eg mud weight change (average differential pressure of degraded mud weight) or an applied 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, Ftemp as:


and E to obtain

=

-200 x (As) x (T)



=

Coefficient of Thermal Expansion for steel, 6.67 x 10

E

=

Young’s Modulus, 30 x 10 psi

As

=

Ao – Ai (in )

T

=

Point (for casing below TOC) or average (for pipe above TOC) change in temperature (F)

Ftemp Where:

-6

6

2

A change in temperature from the ‘as cemented’ base case (Ftbase) will either increase or decrease the total axial load, depending on the temperature change. Above the top of cement, the average T is used since the pipe can move, resulting in the same force everywhere; below the top of cement it cannot move axially, so the force depends on the localised temperature.

Page 28 of 60

MECHANICAL DESIGN

Ballooning Force Figure 6.3 - Ballooning Compression

Lower Pressure

Higher Pressure

Higher Pressure

Lower Pressure

Tension

Ballooning

Cement

Compression

Cement

Cement

Cement

Tension

Reverse Balloning

If a tension is applied to a piece of metal it will normally increase in length in the direction 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 potential movement is converted into a force. The ratio of the applied force to the lateral force is called ‘Poisson’s Ratio’ for the metal (for steel this is 0.3). If a casing (or other tubular) experiences an internal pressure increase (compared to the external pressure) it will expand in diameter (balloon) and, if unrestrained, will shorten 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 the potential movement will be converted into an additional tensile load. If the pressure change is a reduction in internal pressure (or increase in external pressure) 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.

MECHANICAL DESIGN

6.5.6.3

Page 29 of 60

Thermal Loads and Temperature Effects

For most normally pressured shallow wells, temperature has a secondary effect on well design. However, for complex, higher temperature wells, loads induced by temperature can dominate the design. Temperature increases that take place after casing installation in sealed annuli can produce extremely high pressure loads as described previously. For land or platform wells with annular access that allows bleed-off this may not be a problem, provided the well operational procedures address the issue. However, for subsea wells the annuli may not allow access, thus resulting in high pressures from the temperature increases which influence the axial loads from ballooning effects. Temperature changes will increase or decrease the axial tension due to the thermal contraction and expansion, respectively. Additionally, changes in axial loads caused by pumping of cool fluids into the well during fracture stimulation or drill stem test (DST) operations, may dominate the axial design. Expansion during production from thermal loads can induce buckling and compressive loads at the wellhead. A well may experience extremes of temperature, to very high values during long-term production and to very low values during injection or stimulation. However, any loads due to thermal change must be calculated as deviations from the original static (datum) condition. Such issues are addressed by computer software, after the initial well design has been prepared. Thermal growth at the wellhead is also an issue that requires consideration. In hot wells with long uncemented casings near surface, expansion of the inner strings can cause the wellhead to ‘grow’ and rise by a short distance. This can cause problems for production flowlines and wellhead clearances. If a slip type hanger is used, the casing moves past the slips. When the well is shut in and cools down, the slips bite causing a very high tensile load in the string(s). This only occurs if the casing hangers are not locked down. If they are locked down, the expansion of the steel can cause buckling of the confined casing. The issue of how much pretension needs to be left in the strings needs to be addressed so that the operating stresses are controlled. For example, if the analysis identifies that the free casing will lengthen by 6in under long-term production, then it may be feasible to pre-stretch the casing by greater than 6in during installation. The expansion will be absorbed by a reduction in stretch and so the wellhead will not lift. Temperature profiles are recommended for high temperature casing designs. Yield de-rating has been discussed previously in terms of reducing the casing strength. However, for wells experiencing high temperatures/thermal loads, temperature profiles are required for each casing string based on the following: Static Temperature

= Tstat (this is the surface temperature, plus the average geothermal temperature gradient depth, supplied by the Geologist).

Cemented Temperature

= Tcmt (temperatures resulting from cementing operations, generally obtained from the cementing company).

Drilling Circulation Temperature

= Tdcirc (the drilling temperatures whilst drilling the well are based on the mud temperature as a function of the geothermal gradient).

MECHANICAL DESIGN

Producing Temperature

Page 30 of 60

= Tprod (the producing temperature of the reservoir constituents from the reservoir to surface; obtained from the Petroleum/Production Dept).

To summarise, changes in temperature can result in length changes of the unrestrained 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 being generated for a casing due to change in temperatures. Alternative designs may be require 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’ base case, or from high compressive loading during installation. Primary factors which promote buckling are: Increased MW and temperatures and reduced internal pressure, during drilling and production. 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 (in )

Pi

=

Internal Pressure at point of interest (psi)

Ai

=

Casing X-sectional Area at ID (in )

=

-2 

2

2

and Fc

 2EIq sin(a )   C  

1 2

critical buckling load (lbf )

Where: Fc

=

Critical Buckling Load (lbf)

E

=

Young’s Modulus, 30 x 10 psi

I

=

Second Moment of Area: (OD – ID )/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)

6

4

4

Page 31 of 60

MECHANICAL DESIGN

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 appropriate computer software. 6.5.6.4.1

Buckling: Worked Example

An example is included buckling equations.

to

demonstrate

the

principles

involved

for

the

A 13,000ft vertical string of 9-5/8in 47 lb/ft L-80 New Vam casing was run in 12ppg mud and cemented with 3,000ft of 16.0ppg slurry back to 10,000ft. The cement plug was bumped with 12ppg mud. Determine if the casing will buckle while drilling ahead to 17,500ft with 15ppg mud and an average T increase of 50F. Assume an average open hole size of 14in diameter. 9-5/8in casing dimensions: OD = 9.625in ID I

= 8.681in = 83in

4

Ao = 72.7in

2

Ai = 59.2in

2

As = 13.5in

2

C = 2.2in for 14in hole

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

MECHANICAL DESIGN

Page 32 of 60

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 complete casing string.

The next phase of the drilling operation is to drill to 17,500ft with 15ppg mud, the average temperature increasing by 50F. Step 3 Calculate Fball for above TOC =

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

 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

Fball

Where:

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

MECHANICAL DESIGN

Page 33 of 60

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 and temperature. This can be reduced a number of ways: Increase the TOC to a shallower depth. This may introduce lost circulation and increase cementation cost. If this approach is adopted, Fbuoy will increase due to the 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 is required to assess the impact on service loads.

Fc

 2EIq sin(a)  = - 2  C  

1 2

Critical Buckling Load (lbf)

As the well is vertical, use 1 average angle, critical buckling Fc is: 6

½

Fc

= -2 [2 x (30 x 10 ) (83) x (3.01) x (Sin 1)/2.2]

q

= Is the buoyed weight of the casing per inch based on the new mud weight of 15ppg and is obtained by the following:

= -21,810 lb

15    DensityCa sin g– DensityMud  47  7.8 8.33 DensityCasing x 3.01 DensityCa sin g 7 .8 DensityCasing 

12  

q Weight air x 

Fpretension = Fc – Feff = -21,810 – (-129,407) = 107,600 lbf This would be the tension required to eliminate buckling. This should then be added to the ‘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)

MECHANICAL DESIGN

Page 34 of 60

The approximate amount of stretch for pretensioning the 9-5/8in casing at the TOC of 10,000ft 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 10

As

= Area of Casing (in )

L

= 107,600 x (10,000) x (12) = 31.9in 6 (30 x 10 ) x (13.5)

6

2

6.5.7

Design Load Definitions

The design loads utilised within the design factor tables are summarised below and include 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 and service a number of load conditions must be considered. They include the following items 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 casing running operations

Fplug

= Tensile Load created by the surface pressure used to bump the cement plug

Fball

= Tensile Load created from a change in internal or external pressure

MECHANICAL DESIGN

Page 35 of 60

Ftemp

= Tensile Load created from a change in temperature from the ‘as cemented’ base case

Ftbase

= This is the ‘as cemented’ base case (after WOC) on which all other surface 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 compressive force acting across the bottom of the casing. The compressive force is due to the hydrostatic pressure acting across the cross-sectional area of the casing. This is also known as the pressure area method and can be open ended, or closed ended, such as a float shoe for casing. This methodology applies whether the casing is vertical or inclined. a. For Open Ended Casing: Fbuoy

=

Pe x (Ao –Ai )

Pe

=

Pressure at the Bottom of the Casing (psi)

Ao

=

Area of Pipe at OD (in )

Ai

=

Area of Pipe at ID (in )

Where: 2

2

Alternatively, for open ended casing, where the internal and external fluids are identical and 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 7.8 is the specific gravity of steel, relative to water

MECHANICAL DESIGN

Page 36 of 60

b. For Closed Ended Casing: Fbuoy

=

Pe x Ao – Pi x Ai

=

Pressure Inside Casing at the Base (psi)

Where: Pi

Note: During casing running operations, if the casing is completely filled with mud of the same weight as in the hole, Pe = Pi For tapered casing strings (stepwise tapered), Fbuoy would be calculated using the same pressure area approach. The additional buoyancy load of the taper section at depth 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 compressive stresses. For tension, the bending stress is included in the tension calculation as a simulated axial force, which produces a stress equal to the bending stress. Fbend

=

64 x DLS x OD x W

DLS

=

Dogleg Severity (Degrees/100ft)

OD

=

Outside Diameter (in)

W

=

Weight per Unit Length (lb/ft)

Where:

Bending only occurs where hole curvature exists, so the high Fbend associated with build sections need not be applied to the whole length of casing. From the tensile design point of view, this favours deep kick-offs over shallow kick-offs. For a vertical well use a 2/100ft DLS for tension calculations, unless a specific value warrants otherwise. In directional wells, the designer should limit the DLS as part of the well design 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 the cement plug and surface pressure held during WOC, if required. A plug bump axial load increases due to the pressure area method calculation, assuming the casing is free to elongate during the cementing operation (ie not fixed or constrained). Fplug

=

Psurf x Ai

Psurf

=

Surface Pressure to Bump Plug (psi)

Ai

=

Area of Pipe at ID (in )

Where: 2

MECHANICAL DESIGN

6.5.7.1.5

Page 37 of 60

Fpretension: Overpull to Land Casing

This is a direct tension load imposed on the landed casing after WOC is complete. This is a method of reducing or avoiding the effects of casing buckling, particularly those loads caused by thermal expansion. Fpretension is part of the ‘as cemented’ base case. Such tensioning is not possible on a subsea well or when using a mudline suspension 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 during running. Typically a value of 100klb is used as a guide for design but this should not be the 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 running installation. 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 velocity assumed for Fshock during casing design should not be exceeded during casing running operations. Fshock

= 1780 x v x As

Where: v

= Velocity in ft/sec

As

= Casing X-sectional Area (in )

2

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 loads are superimposed (ie put on top). Once the casing is landed in the wellhead, cemented and cured, the casing is treated as a single string which is rigidly fixed axially at the wellhead and at the top of the cement (two nodal points).

MECHANICAL DESIGN

Page 38 of 60

Note: There may be circumstances where an additional tensile load is applicable, by applying and holding a surface pressure (Fplug) while waiting on cement. If this is the case, include the Fplug term to obtain Ftbase. Ftbase

6.5.7.2

= Fwt – Fbuoy + Fbend + Fpretension + Fplug

Burst

The design loads utilised within the design factor tables are summarised below and include schematics and examples where appropriate. 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 external pressures (Pe) for each casing string. The three scenarios are: Pe

= MW to TOC + SW over cemented section Exploration well

Pe

= MW to TOC + Pore Pressure over cemented section Development well

Pe

= Degraded MW to TOC + Pore Pressure over cemented section Development 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-Rating Pb DFb must be > 1.1 for all uniaxial load cases.

MECHANICAL DESIGN

6.5.7.2.1

Page 39 of 60

Cement Displacement

This relates to the installation phase for static pressure calculations, during displacement of the cement. The external pressure Pe shall be the mud weight external to the casing on installation. The internal pressure Pi shall assume the casing contains a cement column, then mud above the cement, together with the highest anticipated surface pressure during cement displacement. The surface pressure may arise from the mud and cement rheology, or be based on an operational estimate of pressure associated 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)

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)

Where:

Page 40 of 60

MECHANICAL DESIGN

Figure 6.4 - Cementing: Displacement CEMENTING Cement Displacement Circulating Pressure

Mud dMW

Cement

dCMT

Spacer

dSPC

MECHANICAL DESIGN

6.5.7.2.2

Page 41 of 60

Bumping Cement Plug

This relates to the installation phase for static pressure calculations, during the bumping 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 would be known as a wet casing pressure test, as the casing is tested immediately after plug bump. Refer also to Section 8. Pi

=

Psurf + Pmud (psi)

=

Psurf + MW x (d) x 0.052 (psi)

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

Pcmt

=

Hydrostatic Pressure of Cement Column (psi)

Pb

=

Nett Burst Pressure (psi)

A

=

Point where mud changes to cement

Where:

Where:

Page 42 of 60

MECHANICAL DESIGN

Figure 6.5 - Cementing: Plug Pump CEMENTING Bumping Plug Psurf Psi

Psurf

Mud

Pb

A

Pe

B

0 psi Pressure

Cement

Pi

MECHANICAL DESIGN

6.5.7.2.3

Page 43 of 60

Casing Pressure Test after WOC

This relates to the drilling phase and may require assessment from a number of different perspectives (see Figure 6.6), depending on the casing string to be pressure tested. This is known as a dry test, as the casing is restrained at the wellhead and over the cemented portion of the casing. Refer also to Section 8. Pi

= =

Pmud + Psurf MW x (d) x 0.052 + Psurf

=

Pressure required to pressure test the casing (psi)

Where: Psurf

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 to surface.) 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 the external pressure.

(2)

The pressure test is normally performed prior to drilling out the float equipment and should, in principle, be the highest pressure test that the casing will experience for the well life.

(3)

The pressure test will be influenced by the well designation exploration or development, as the backup will be different.

(4)

The casing pressure test should exceed the maximum surface pressure for either:

(5)



Circulating out a well control influx to surface (using a gas gradient)



The maximum anticipated LOT + the 0.5ppg test margin

The casing pressure test should be < 80% of the API burst rating, as discussed in Section 8.

Page 44 of 60

MECHANICAL DESIGN

Figure 6.6 - Load Schematic for Pressure Test of Casing after Waiting on Cement Surface Test Pressure P S U R F (2500 psi)

0

Exploration Well Load Case - Casing Pressure Test After WOC Nett Burst Pressure

1000

MUD

External Mud Hydrostatic (12 ppg Mud) To TOC

3000

4000

9 5/8" 32 ppf H40 Burst

CEMENT

5000

TOC

6000

7000

0

1000

2000

Internal Mud Hydrostatic (12 ppg Mud) Surface to Shoe

9 5/8" 36 ppf K-55 Burst

Depth - feet

2000

3000 Pressure - psi

External SW Hydrostatic (8.9 ppg ) TOC to Shoe 4000

5000

6000

7000

MECHANICAL DESIGN

6.5.7.2.4

Page 45 of 60

Casing Test after WOC: LOT + 0.5ppg

This relates to the drilling phase and will link closely to the initial setting depth assessment. It is based on the maximum anticipated surface pressure to determine the leak-off pressure at the casing shoe; plus the 0.5ppg test margin on the fracture gradient profile, to allow for ECD while drilling and potential well control incidents (see Figure 6.7). Figure 6.7 - Leak-off Test (LOT) Psurf

Mud

Cement

Leak Off Test (LOT) in new hole

MECHANICAL DESIGN

Page 46 of 60

The liner lap pressure test is a modification of this test, as indicated in Section 8. The only difference is that the liner lap pressure test will be 500psi above the actual LOT achieved. 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)

=

MW x (d) x 0.052 + PP x (d) x 0.052

or Pe

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 depth while circulating out a gas kick using the Driller’s Method. The internal pressure profile should be confirmed in the final stages of calculation by computer software, which includes 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

MECHANICAL DESIGN

Page 47 of 60

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 temperature and 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

= 8.5 – 6.75 = 0.026bbl/ft 1029.4

VFOH-DP

= 8.5 – 5 = 0.046bbl/ft 1029.4

VFCSG-DP

= 8.681 – 5 = 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

2

2

2

2

2

2

= (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 the Repsol Well Control Manual.

MECHANICAL DESIGN

 P 2 K  MW  0.052  Psurf  initial   VFCSG-DP   4

1 2



Page 48 of 60

Pinitial (psi) 2


1585 2 702,000  13  0.052  Psurf    4 0.049  

1 2



1585 (psi) 2

Psurf 628,056  9,684,735 2 793 1

Psurf = =

½

(10,312,791) – 793 = 3,211 – 793 2,418psi

We now check to see if the gas kick surface pressure is the dominant load versus the LOT 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 the casing must be pretested to a value in excess of 2,418psi, a rounded-up value of 2,500psi being realistic. The casing weight and grade would be chosen after the appropriate reductions for casing wear and temperature. The actual design factor will then be checked to see if it meets the minimum design factor requirements.

Page 49 of 60

MECHANICAL DESIGN

Figure 6.8 - Gas Kick: Example Data Pore Pressure (Dpp) (EM W) ppg

M ud

M ud

M ud

Datum

8.4

5" Drill pipe

4,000 ft.

6,000 ft

9.5

7,000 ft

D shoe Top of G as

G as Influx

7,700 ft

10.0

Height of gas (Hg)

6 3/4" Drill Collars

9,700 ft

10,000 ft

D TD

13.5

MECHANICAL DESIGN

6.5.7.2.6

Page 50 of 60

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 tubing leak 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 degraded to a base liquid (base oil for oil based mud or water for water based mud) down to the TOC. The highest burst pressure is typically at the production packer. However, check the pore pressure regimes from the TOC to the packer, as there may be depleted zones higher up.

Note: OBM can vary considerably in the oil:water ratio. In the absence of specific data, assume either a water or base oil gradient for load cases, to identify the worst 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)

Page 51 of 60 MECHANICAL DESIGN

Figure 6.9 - Tubing Leak at Surface

S ITH P

C o m p le tio n / P a cke r F lu id

C o m p le tio n / P a cke r F lu id

D e g ra d e d M u d

TO C

C em ent

P o re P re ssu re

P a cke r

MECHANICAL DESIGN

Page 52 of 60

6.5.7.2.7 Full Gas to Surface Example: Development Well (Service Load) This represents a service load based on a wellbore full of gas (0.1psi/ft) to surface from the 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 specific data, assume either a water or base oil gradient for load cases, to identify the worst 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

Example: Development Well (Service Load) These represent service loads for DST activities, including annulus pressure operation of DST tools, or a pressure leak (high pressure gas) at the wellhead with mud in the annulus. 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 across cemented 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.

P e rfo ratio ns

TOC G as g radien t 0 .1 p s i / ft

G as F illed Ho le

D e grad ed M ud

D e pth

MECHANICAL DESIGN Page 53 of 60

Figure 6.10 - Full Gas to Surface

BHP BHP

TD P re s s u re

MECHANICAL DESIGN

6.5.7.3

Page 54 of 60

Collapse

The design loads utilised within the design factor tables are summarised below and include schematics and examples where appropriate. Pc

= Pe – (1 – (2t/D)) Pi

When using thin-walled pipes, as in most casing designs, t/D is a very small number and 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, which gives the percentage of full collapse pressure or PFCP due to a tensile.

PFCP

Ypa Yp

 S  x 100 1 0.75 a  Y  p 

2   0.5 Sa  x 100 Yp 



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 following equation is used: Pc



API Collapse Rating x PFCP x Reduction for Casing Wear DFc

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

MECHANICAL DESIGN

6.5.7.3.1

Page 55 of 60

Cementing: Conventional

This relates to the installation phase for conventional cementing, during displacement of the cement (see Figure 6.11). The internal pressure Pi assumes the casing is full of mud. The external pressure Pe shall be the mud weight, cement slurry and an estimated 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)

Page 56 of 60

MECHANICAL DESIGN

Figure 6.11 - Cementing: Conventional and Stab-in CEMENTING

CEMENTING

Mud

Mud

TOC TOC

h h

Spacer

Cement

Conventional

TD

Cement

Stab-in Job

TD

MECHANICAL DESIGN

6.5.7.3.2

Page 57 of 60

Cementing DP Stab-in

This relates to the installation phase for stab-in cementing, during displacement of the cement (see Figure 6.11). The internal pressure Pi assumes the casing and DP is full of mud. The external pressure Pe shall be the mud weight, cement slurry and an estimated bridge pressure assuming the hole packs off during displacement. It should be noted that the internal fluid between the casing and DP is often water and so will create 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 pressure Pi assumes the casing is atmospheric. The external pressure is based on the original mud weight to set the casing. This load case is of particular concern for large diameter casings, 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.

MECHANICAL DESIGN

6.5.7.3.4

Page 58 of 60

Partial Evacuation

This relates to the drilling phase for partial evacuation of the casing while drilling with lost returns. The internal pressure Pi is based on the drop in the mud level using the maximum mud weight at the end of the next hole section, caused by the lost circulation zone. The fluid level in the wellbore will fall until the pressure in the wellbore equalises to the pressure of the lost circulation zone. This is normally taken as c. 8.33ppg normal pressure at the loss zone, if limited data is available. This is given by:  MW PLZ  DLZ  MW 

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 as atmospheric. 6.5.7.3.5

Gas Lift: Above Production Packer

Example: Development Well (Service Load) This relates to a production service load for the production casing and models a well with gas lift installed that loses injection pressure (see Figure 6.12). As a result it is assumed 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 cemented section. 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 TOC plus a seawater gradient below, over the cemented section.

F u ll E v a c ua tion (G as g ra dien t with n o s urfac e p re s s u re)

D e pth

G a s L ift M a nd rels

G a s F illed A n nu lu s

MECHANICAL DESIGN Page 59 of 60

Figure 6.12 - Gas Lift above Production Packer

P re s s u re

Page 60 of 60

MECHANICAL DESIGN

6.5.7.3.6

Full Evacuation: Below Production Packer

Example: Development Well (Service Load) This relates to a production service load for the production casing or liner and models a well with a depleted reservoir or plugged perforations (see Figure 6.13). The collapse load may be a concern immediately above the perforated zone. As a result, it is assumed 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 the worst case. If it is an exploration well, the external pressure Pe would be mud weight down to TOC plus a seawater gradient below, over the cemented section. The setting depth of the production packer may influence the external pressure if it is set above the TOC. Figure 6.13 - Collapse Load Schematic for Running of Dry Casing 0

Exploration Well Load C ase - R unning C as ing D ry W ith E x ternal M ud H ydros tatic

100 0

E x ternal M ud H ydros tatic (12 ppg M ud) S urface T o S hoe = N ett C ollapse P ressure

500 0

600 0

700 0

0

100 0

9 5/8" 36 ppf K -55 C olla ps e

9 5/8" 32 ppf H 40 C ollaps e

400 0

9 5/8" 47 ppf C -75 C ollaps e

In ternal A ir 0 ps i / ft G radient

300 0 MUD

D epth - feet

200 0

200 0

300 0 P res s ure - ps i

400 0

500 0

600 0

700 0

SECTION 7

Drilling and Production Operations

Ref: CDES 07

CASING DESIGN MANUAL

Issue: Feb 2000

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

7.

PRESSURE TESTING

7.1

CRITERIA

Page 2 of 4

The Repsol policy for casing pressure testing requires all surface, intermediate and production casing/liners to be pressure tested, prior to drilling out the shoe track or perforating.

7.2

GENERAL REQUIREMENTS

Casing pressure test loads must not exceed 80% of the API burst rating. This may require confirmation by a triaxial analysis, that the calculated combined loads do not exceed the design factors based on the 80% pressure test criteria. This applies to both pipe and connections. When calculating pressure test requirements, consideration must also be given to the following:


The minimum and maximum densities of the fluid columns inside and outside the casing, 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 an application depending upon the type of well drilled. Ideally, pressure testing (which is a burst 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) when bumping the plug, the external (backup) load should equal the mud weight used, plus cement slurry weight to set the casing (assuming any fluid losses while cementing are all 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 casing and can provide a solution, to achieve the required pressure test of the casing at surface. If the burst design factor during pressure testing is close to the minimum allowed, it should be highlighted in the drilling programme to ensure the engineer understands the significance of the pressure test.

PRESSURE TESTING

Page 3 of 4

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 the bottom. 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 in Section 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 for pressure testing after the cement has set, is created by the ballooning effect above the top of cement and this contributes to the triaxial stress. The end area effect of the casing is not relevant in this case, as it is cemented and fixed. To summarise, the designer should be aware that axial loads will apply over the uncemented section of the casing and that this type of pressure test can result in a higher nett burst pressure at the 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 the surface pressure required to provide an equivalent mud weight (EMW) at the shoe equal to the anticipated leak-off plus a 0.5ppg test margin (TM). The maximum anticipated surface pressure for surface and intermediate casings is the greater value of either that required for the anticipated LOT with the test margin or the Psurf 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-in tubing pressure (SITP) on top of the annulus completion fluid. Unless ample data is available to support an alternative (gas composition and reservoir data), a gas gradient of 0.1psi/ft should be used down to 10,000ft true vertical depth (TVD), thereafter use 0.15psi/ft in the calculation of surface pressure. These criteria also apply to exploration wells, for a DST string leak on top of the annulus fluid (mud).

PRESSURE TESTING

7.3.4

Page 4 of 4

Liner Laps

Liner laps must be tested to a minimum of 500psi above the formation leak-off pressure at the casing shoe, unless there is no requirement to demonstrate internal pressure integrity of the casing/liner hanger and cement. However, this test needs to be assessed to check that the equivalent mud weight applied to the liner during the drilling phase with mud is > (greater than) the maximum equivalent pressures during DST or completion operations. For example, if the production packer is set as a PBR or within 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) the LOT + 500psi pressure test at the casing shoe. In addition, a differential test must be conducted on the liner, which imposes a drawdown equivalent to or greater than that expected during the life of the well.

SECTION 8

Drilling and Production Operations

Ref: CDES 08

CASING DESIGN MANUAL

Issue: Feb 2000

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

8.4

Page 2 of 18

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

SPECIAL CASES

8.

Page 3 of 18

SPECIAL CASES

A number of special cases for casing design are worthy of discussion, to provide the Drilling Engineer with an insight into various issues that may influence a design. It should be emphasised that the following sections represent a summary of issues to be considered and potential problems. Unusual wells generally require a multi-disciplinary team approach, due to their specialist 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 engineering effort and preplanning for well design, due to the tighter margins between the pore and fracture gradients and the thermal loads arising from higher temperatures. The drilling engineering time required for an HPHT well design may be 5 to 10 times that required for a standard well. A specific module on the HPHT wells is contained within the Special Wells Manual and the 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 summarised below. 8.1.1

HPHT Definition

HPHT wells are generally defined as having an anticipated surface pressure requiring pressure control equipment with a rated working pressure in excess of 10,000psi (this is defined within IP 17, Well Control during the Drilling and Testing of High Pressure Offshore Wells). The high temperature definition is typically regarded as a well having a minimum undisturbed formation temperature of 300
F at total depth. It should be noted that a well may not necessarily exhibit both high pressure and high temperature. 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 (Von Mises Equivalent) analysis should always be performed as part of the well design. This is important due to the large temperature effects on axial load profiles and combined burst and compression loading. As a result of this approach, the design will be performed by computer software and uniaxial hand calculations, to confirm the general computer outputs of the software. It is likely that a Senior Engineer, in conjunction with an independent internal review and third-party assessment, will design wells of this nature.

SPECIAL CASES

8.1.3

Page 4 of 18

Limitations

A Von Mises Equivalent (VME) ellipse schematic is shown below in Figure 8.1, together with 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 the design, including thermal loads, stay within the boundaries of the VME ellipse. There are, however, exceptions to this general statement; primarily for collapse loads under tension, where it is necessary to satisfy both the triaxial stress and API Uniaxial collapse requirements. A well design for a ‘normally pressured well’ with a standard temperature profile will not require detailed analysis when compared to an HPHT well. Basic assumptions utilised for a standard well may not be appropriate for HPHT wells because of the significant additional impact on the well design from thermal loads. This requires an iterative approach to the well design, as the output design factors will be sensitive to changes in a 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 floating rig 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 drill stem test (DST) or subsea completion. Additionally, a jack-up allows access to all annuli and the capability to bleed off annulus pressures in a controlled manner. A jack-up rig also significantly reduces the sensitivity of weather to critical operations, such as drilling into high pressure transition zones and displacing to underbalanced fluids, relative to emergency disconnect procedures for a semi-submersible. 8.1.5

Packer Fluids

Due to the high mud weights associated with HPHT wells, performing a DST or completion operations has a significant impact on the design philosophy. For example, there is a general industry trend to move toward non-kill weight packer/completion fluids, 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 of a production tieback string. Additionally, low packer densities (and viscosities) promote faster heat dissipation through casings, due to higher thermal capacities and increased thermal diffusion, compared to a high weight, high solids mud.

Triaxial Stress Check (von Mises Equivalent (VME) Check) COMPRESSION AND BURST This region is most important for VME check. - Corkscrewing - high comp., low hoop stress - Burst - Low comp., high hoop stress

Triaxial benefit of tension increasing burst value

TENSION AND BURST (Tension helps burst) VME slightly greater than uniaxial burst (for first 3/4 of tension range)

Burst

Burst Effective Internal Pressure HOOP STRESS

Corkscrewing Governing Design Limits

(HIGH COMP. AND LOW COLLAPSE) (Failure by buckling) Combined stress can exceed elastic limit Use collapse limit in this quadrant

Collapse

VME very Applicable

Compression

Uniaxial limits

Axial Force

Tension

TENSION AND COLLAPSE Collapse is a buckling addition requiring an inelastic check based on geometry. VME is an elastic check based on a yield stress so it is not applicable.

Area most important for TriAxial DF check ZZ26323.011

Page 5 of 18

COMPRESSION AND COLLAPSE Compressive strength tends to increase collapse limit - this benefit is not currently used for design purposes.

Generally connections have a much lower axial compressive value with collapse pressure than the pipe body

SPECIAL CASES

Intercept: Burst DF = 1.10 Triaxial DF = 1.25 (For 12.5% wall thickness tolerance in several computer design programs).

VME Applicable

Figure 8.1 - VME and API Envelopes

VME can give higher DF than uniaxial burst.

SPECIAL CASES

8.1.6

Page 6 of 18

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 riser margin as part of the mud weight overbalance. This has an impact for calculating the total 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 connector system for HPHT wells, since the complete system may experience higher pressures for a well control incident than for a normal pressured well. This can affect the operational working envelope for the well design in terms of the anticipated bending loads on the conductor and the minimum riser tension for the rig, if a semi-submersible is used. A specific document has been generated by the Institute of Petroleum (IP) to address these issues and is titled Guidelines for ‘Routine’ and ‘Non-Routine’ Subsea Operations from Floating Vessels (August 1995). This document should be used to determine if the conductor and riser system requires detailed analysis. This is achieved by filling out a template checklist of questions within the IP document and highlights if additional detailed analysis is required. 8.1.8

Inspection Criteria

Due to the risks and tighter margins associated with HPHT wells, the inspection criteria for 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 the specification stage, to minimise this risk. This is also discussed within Section 4.2.4.3 for casing loads and casing specifications. 8.1.9

Hazard Assessment

Well designs such as HPHT will require the use of HAZOP/HAZAN techniques as part of the well design process due to the close design margins and the consequences of failure. To assist the well designer, HAZOP comes first by identifying the hazards from the design and means Hazard and Operability study. It is qualitative and performed by a team from a cross-section of various disciplines, not just drilling personnel. The hazards are identified and the team then decides how to address them. The HAZAN (Hazard Analysis study) process follows and may include techniques such as risk assessment or quantified risk assessment (QRA) ie what is the likelihood that an incident or failure will occur and the consequence should it occur. It is important that casing seat selection is firmly determined and assessed, for issues such 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. This will be based on agreeing the operational envelope of the well with all parties and ensuring that ‘what if’ load cases for the big issues are addressed within the design.

SPECIAL CASES

8.2

Page 7 of 18

DEEP WATER

Deep water wells require greater focus on the upper section of the well, from the surface casing upward (including the conductor, wellhead and riser system). In principle, well design below the surface casing down is similar to a standard well design. A specific module on deep water wells is contained within the Special Wells Manual and the reader should refer to that document, in addition to the Casing Design Manual. 8.2.1

Definition

Deep water can be defined as areas with a water depth in the order of greater than c.1,500ft. This is because from this depth onward (subject to metocean conditions) the equipment and well design change. 8.2.2

Type of Design

Deep water well design may be based on benign pore and fracture gradient profiles. As a result, the well design may be uniaxial, with an additional focus on the rig riser system, 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 conductor and the diameter of the drilling rig riser. For example, the initial well design should be based on a generic 21in drilling riser and 18-3/4in wellhead system. The capability of the wellhead connector in terms of bending and axial rating will link firmly to the riser analysis. This in turn defines the bending and axial capabilities of the conductor pipe and connectors. These issues can be minimised by use of a pre-locked wellhead system which provides additional support and anchoring, and reduces movement and bending below the wellhead and fatigue on the surface casing (just below the high pressure housing). As for HPHT wells, the IP Guidelines for Subsea Operations from Floating Vessels should 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 pore pressure and fracture gradient, reducing the operating margin for mud weights. Lost circulation may occur at a mud weight equal to the pore pressure, after taking account of the ECD (equivalent circulating density). A slight reduction in the mud weight may cause a water flow and kick due to highly water-saturated formations.

SPECIAL CASES

Page 8 of 18

A reduction in the offshore overburden gradient will dramatically decrease the fracture gradient, particularly with deep water and a shallow well depth. Thus the primary focus for 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 the drilling rig, riser diameter and wellhead connector, soil strength analysis of the seabed formations and the metocean data set. The principal purpose of the conductor is to provide a stable foundation for all subsequent casing strings. As the surface fracture gradients are lower, soil strength analysis and frictional support for the conductor become important factors. This affects the size of the conductor (bigger is better as it provides more contact area and improved structural rigidity) and the installation technique (jetting rather than cementing, to maintain frictional support and axial load requirements for the BOP and subsequent casings). The conservative approach is to select a conductor design that has the capacity to maintain strength when subjected to both bending and axial loading during drilling, without considering the additional rigidity provided by the inner strings. This seems a reasonable approach as sharing of the axial loads between the conductor and surface casing may not be achieved due to the cementation of the surface string not reaching the seabed between the two strings. Additionally, the bending contribution of the surface casing is usually relatively small. Conductor design should also focus on the bending capability of the connectors, to ensure 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. In particular, emphasis is placed on obtaining a minimum depth to achieve the pressure integrity 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 be influential factors for surface casing design. 8.2.7

Operational Constraints

The main issues requiring consideration are the open water operations associated with running the conductor and surface casing. This can induce high bending loads from subsea currents, due to the stiffness of the casing string. This should be assessed as part of the design, to determine if failure could occur.

SPECIAL CASES

8.3

Page 9 of 18

CONDUCTOR/SURFACE CASING DESIGN

Certain aspects of conductor and surface casing design should be highlighted, in order that the Drilling Engineer is aware of the issues and is able to identify where specialist advice is required. 8.3.1

Well Design Issues

When considering a conductor and surface casing design, the following issues need to be 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 a pretension system and/or additional wall thickness, to minimise buckling?



Are the metocean conditions liable to produce additional loads on the conductor system?



If it is planned as an offshore subsea well, will the conductor experience fishing trawler snag bending loads over the conductor and wellhead?



Do the soil analysis conditions require special cementation slurries, or a minimum number of joints, or installation techniques to ensure a stable foundation?



Does the conductor consider the possibility of submarine traffic, requiring subsea protection 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 centralisation analysis to increase the rigidity of both strings in terms of bending and compressive loading?



Will there be deep/heavy casing strings, with potential to transfer loads to the surface casing and conductor (special running procedures eg hold in tension until cement set)?

SPECIAL CASES

Page 10 of 18

The engineer will need to assess the above list and use this in conjunction with the basis 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 a detailed analysis and that a basic conductor system may be adequate. However, if the well is offshore, from a jack-up with relatively deep water and active subsea currents with an HPHT well profile, then it is certain that specialist marine conductor engineering analysis will be required as part of the well design, above the mudline. The following sections expand on issues associated with a marine conductor design above 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 to cause 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, which are normally greatest in the wave zone. Internal casings, wellhead/BOP and mud weight forces accumulate to give a compressive load which reaches a maximum at some point below the mudline. These combined compressive and bending forces tend to cause buckling or conductor slump (although the load from the internal casing strings 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 return period for permanent installations. In some operating regions this may require that fixed structures are designed for 50 year return conditions. However, jack-up conductors for exploration wells are not permanent installations, so a shorter return period is generally acceptable (in shallow water, conductors may be left in place for a number of years and are subject to high wave loads). In tropical climates that are subject to hurricanes or typhoons, there is a large difference between the 10 year hurricane and the 10 year non-tropical storm. The time of year during which the well is drilled is also an influential factor.

SPECIAL CASES

Page 11 of 18

Scatter diagrams, or wave exceedance data are required to determine fatigue due to cyclic wave loading. For example, fatigue damage can be significantly worse during the winter than summer period. Current exceedance data is also necessary to determine fatigue damage due to vortex induced vibration. Although pure axial and bending stresses must be within the allowable limits, the limiting factor in jack-up conductor design is typically buckling. In deep water the limit is a combination of dynamic bending and buckling. API RP2A gives buckling criteria based on an interaction ratio, which combines axial and bending forces. Since the calculations required for assessment of such forces must include dynamic wave and inertia effects, it is recommended that a storm check design is performed and analysed by 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 considers the 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 of the conductor will not be greatly influenced by fatigue. However, in areas such as the Gulf of Mexico, fatigue is critical during the winter. During this period, maximum wave and currents are generally low. Under these conditions, the design will be entirely influenced 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 vortex induced vibration (VIV). This occurs when one or more natural conductor frequencies are excited by current velocities or by large waves with reduced velocities. If a conductor design is susceptible to current induced vortex induced vibration and current statistics are available, detailed computer analysis should be carried out to determine the minimum fatigue life. If there are no reliable current statistics or if vortex induced vibrations are expected to be caused by waves, then the assessment of fatigue is more complex. In such circumstances a full bathymetric and metocean survey may be required to gather the necessary information (more pertinent for developments). Useful sources of information are often local military, the US or British Navy or the British Maritime Association. 8.3.6

Detailed Design Analysis

If a detailed design analysis is necessary, it is generally performed by a specialist structural engineer and would typically include: 

Analysis of the environmental conditions



Static analysis

SPECIAL CASES



Dynamic analysis



Fatigue analysis

Page 12 of 18

Assessment of the environmental criteria will establish maximum current, wave height and current direction. The drag coefficient is also important and will vary according to current velocity, conductor diameter and roughness due to marine growth. Specific geotechnical information at the location is required. A static analysis provides a datum stability check and can be used as a reference point to determine the effect of rig offset. The dynamic analysis with extreme wave and current conditions is used to evaluate maximum stresses and perform the design 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 various factors, a design can be established which provides an operating envelope for the conductor. A typical conductor for a jack-up may require a conductor above the mudline of 30in x 1.0in weight. However, if the design is not adequate, other options for consideration 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 a conductor tensioning system to prevent buckling, although the top tension may increase the dynamic and fatigue stresses. It also reduces the available deck load for the 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 the Drilling Engineer.

SPECIAL CASES

8.3.7

Page 13 of 18

Subsea Wells

Conductor and surface casing design for a subsea well from a semi-submersible or a jack-up subsea well that is suspended/completed, requires a strong link with the wellhead design. Specific issues that require consideration and assessment are: 

Use of 1-1/2in or heavier wall 30in wellhead extension conductor and connectors immediately below the wellhead (typically 40-80ft). This improves the bending load capability 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 extension and high strength connectors below the wellhead to improve the bending load capability



Planned use of cementation top-ups for the 30in conductor, to minimise potential failure or movement of the conductor during the drilling phase after the subsea BOP is installed



Assessment of the cumulative time that a drilling unit riser and BOP system may be installed 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 may have 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 wellhead growth may identify compressive loads as an issue from thermal analysis. The same analysis also requires a check for wellhead/casing shrinkage when the well cools down, leading to changes from axial compression to tension



Thermal analysis for subsea production wells that are linked to flow lines and pipelines. This can cause movement and bending at the connection/turning points of the well flow lines, which in turn creates additional stresses



Analysis of cumulative conductor and surface casing loads arising from additional casing strings, the wellhead, the riser and the BOP system

This last item depends on the analysis technique adopted; single string v multi-string analysis. Single string analysis models an individual string in terms of the pressure, axial and temperature loads and being the most pessimistic type of analysis generates a conservative conductor design. Multi-string analysis models all casing strings as a system, taking into account the pressures, temperatures and fluids in all annuli. The loads of all casing strings are shared proportionally onto the conductor. This allows an accurate assessment of wellhead growth and movement of flow lines etc.

SPECIAL CASES

Page 14 of 18

For example, a single string analysis assumes the conductor absorbs all additional casing string weights on a direct cumulative basis, whereas multi-string is based on the casing strings retaining some of the axial load and partially transferring the remainder to the conductor. This has an impact when assessing the total compressive loads on the conductor and surface casing. This type of assessment generally requires an iterative 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 are transferred from the rig to the seabed via the conductor and surface casing. Similar conditions apply in that the actual casing loads may be distributed through all of the casing strings (as detailed above). Mudline suspension wells require that the designer considers the casings from the seabed to the rig connection as part of the marine conductor system. For example, the outer marine conductor is regarded as the environmental string, the surface casing may (subject to design) act as a diverter string, the intermediate and production casings will act as high pressure conduits from the mudline, to the rig Texas deck.

8.4

TIEBACK DESIGN

This section is focused toward tieback from a fixed platform to a subsea wellhead or mudline suspension system. 8.4.1

Tieback Description

Subsea wells may be drilled using a template, above which a production platform is later 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 may consist 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 subsea wellhead and laterally (nodal points) by platform bracing guides. The 13-3/8in casing supports 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 during installation. As with a conventional production well, the tieback production casing will have to contain the wellhead pressure if the production tubing leaks. Casing design will consider burst, tension and collapse as with any other design but there are further issues to examine.

SPECIAL CASES

8.4.3

Page 15 of 18

Thermal Growth

For a production well, the average temperature of the tubing and casing will be higher while producing, than when installed or shut in. Thermal expansion of the tubing and casing will result in the surface wellhead moving upward. Also, water injection wells generally exhibit downward movement owing to temperature decrease. The degree of wellhead movement caused by thermal pressure effects is critical information for design of the platform topsides production piping. 8.4.4

Equipment Loads

Thermal and pressure effects can generate extreme forces on the wellhead equipment and large changes from initial installation loads. For example, a production well with uncemented 9-5/8in casing below the subsea wellhead will normally be in tension. A large temperature increase may change this to compression, producing increased stresses below the seabed wellhead, causing buckling or an upward motion of the 9-5/8in at the seabed wellhead if a positive mechanical lockdown system is used. The degree 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 not occur within the 13-3/8in and minimise motion at critical sealing surfaces. Pretension does not reduce thermal growth. The extent of wellhead motion is substantially unaffected by the pretension but it may change the datum from where the motion starts. Pretension is not always required, as buckling may not necessarily result in excessive bending stresses, nor prevent use of the various wellbore access tools. Reducing or eliminating pretension can also reduce centralisation requirements for the 13-3/8in (compressive load considerations). The amount of pretension needs to be based on service 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, the pretension and the weight of the production equipment. Compression will normally occur 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 the 13-3/8in once they contact the 13-3/8in internal wall. Generally, buckling of the 13-3/8in will result in unacceptable bending stresses, exceeding yield even within the confines of the 20in and inner strings. The 13-3/8in is prevented from buckling by using rigid centralisers, which provide lateral support from the 20in. Lateral supports from the 20in platform guide frames (nodal points) and local deflections from the environmental loads, both affect the 13-3/8in. This requires a detailed evaluation by a Structural Engineer to determine the optimum centralisation spacing.

SPECIAL CASES

8.4.7

Page 16 of 18

Environmental String (20in)

The main purpose of the 20in conductor is to act as the environmental string and thus isolate the 13-3/8in casing from direct environmental loads. However, it can also be considered as an additional compression string. By using the 20in as a compression string, rather than just a free-standing environmental barrier between the 13-3/8in and direct wave loading, some of the pretension applied to the 9-5/8in string can be absorbed. The greater vertical stiffness of the 20in and 13-3/8in acting together means that less overpull is required to achieve the same residual tension in the 9-5/8in. If it is necessary to pretension the 9-5/8in, it may be possible to reduce the number of centralisers required for the 13-3/8in by also pretensioning the 13-3/8in. This assumes that the 20in has spare compressive load capacity. In general, it is preferable to minimise or eliminate the need for any pretensioning. Rigidly connecting the 13-3/8in and 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 to temperature rise. This requires detailed evaluation by a Structural Engineer, to determine 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 maximum static 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 and casing connections associated with these service life loads is likely to be small. However, it should be assessed using a conservative estimate of operational cycles per year

8.4.9

Pressure Effects

Pressure changes from the ‘as installed’ condition also contribute to wellhead movement and forces in the casing strings and so should be considered for a tieback design. For example, estimation and use of pressure tests for the anticipated loads and in situ production loads.

SPECIAL CASES

8.4.10

Page 17 of 18

Temperature Effects

The temperature changes for each string should be calculated as the differences experienced during the set condition, ie both ends fixed whilst under the various service life conditions. The axial and radial temperature distributions have a major effect on forces in the various strings. The best estimates of these changes should be obtained 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 and associated well control requirements should be considered in the sizing



Platform Wellhead: Attempt to make the tieback wellhead design similar to the platform wellhead/casing design to maximise interchangeability and to simplify well maintenance



Equipment Interfaces: Ensure the vendors of subsea and surface equipment are clearly identified, including crossovers. Additionally, the design of the various interface components should recognise the amount of casing stretch that can occur if pretension is applied



Procurement: Issues such as casing ovality should be assessed to ensure passage of tieback tools. The OD of special drift casing must be checked for tolerances and internal drifts should be examined, to ensure correct sizing



Centralisers: Rigid centralisers should assist with the installation and alignment for the 9-5/8in (perform centraliser analysis)



Alignment: The tieback design should be considered in conjunction with the platform installation, construction tolerances and the verticality of the seabed wellhead/mudline system

SPECIAL CASES

8.4.12

Page 18 of 18

Drilling/Structural Engineering Interface

The work associated with a tieback design is such that the various loads and component interfaces require the input of a Structural Engineer at the start of the design. It is important that the Drilling Engineer accurately describes the various components and issues of the tieback to the Structural Engineer. This should be discussed for each phase of the installation process, not just the final configuration. The Drilling Engineer should prepare an outline estimated tieback programme. This will allow the Structural Engineer to question assumptions, magnitude and direction of forces and the capabilities of components. The Structural Engineer will also need information 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 and tubing, 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 acceptability of load reversal at sealing surfaces



Identify load paths in the stacked components



Establish, review and agree the outline sequence as supplied initially, ensuring it provides a full definition of the final configuration and the loads which the components will experience at each stage of installation



Clarify and identify the containment equipment to be used for the various pressure tests on installation of the tieback strings, eg testing against packers in the casing or 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 model are discussed between the Structural and Drilling Engineers. The Structural Engineer should establish which boundary conditions are independent of loads and which may change. Finally, the key points where forces are to be calculated to establish component suitability should be discussed at an early stage with the Drilling Engineer.

SECTION 9

Drilling and Production Operations

Ref: CDES 09

CASING DESIGN MANUAL

Issue: Feb 2000

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

9.

CASING DESIGN REPORT

9.1

CONTENTS OF CASING DESIGN REPORT

Page 2 of 7

The final casing design report should be able to act as a stand-alone document, to enable an independent engineer or review to identify the principles, processes and assumptions used in generating the final casing design. It should be noted that much of the information included within the report will have been prepared and verified during the 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 trail for 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 information to 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 the introduction 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/or primarily performed by a computer software package, due to the requirement of production loads and anticipated high thermal loads. 9.1.3

External Pressure Assumptions

Highlight the source of data and assumptions used in generating the pore pressure and fracture profiles. List specific concerns or safety issues, such as loss zones, overpressured or depleted zones. List the best offset control wells for the design assumptions. 9.1.4

Internal Pressures

List the minimum and maximum mud weights and packer fluids to be utilised for the design. Note the mud type: oil based or water based mud. This is important, as it has an influence on the external back-up pressures to be utilised if a development well for long-term load assessment (eg degraded base oil or water gradient).

CASING DESIGN REPORT

9.1.5

Page 3 of 7

Wellbore Geometry

Briefly discuss the wellbore profile; including specific areas of high dogleg severity and potential casing wear. Highlight the allowances adopted for casing wear and key methods of prevention. Summarise, if necessary, impact on wellbore safety if anticipated casing wear limits could be breached. This section may require additional information or actions. For example, if re-entering an old well that has been drilled through a number of times, the casing string may need a datum casing wear/corrosion caliper. 9.1.6

Temperature Criteria

Summarise the temperature predictions/profile. Identify where the profile was obtained and any implications for the well design. For example, production thermal loads impact on temperature to material selection, particularly if a corrosive environment is anticipated. 9.1.7

Temperature De-rating

Highlight if the casing strings have been de-rated for temperature as part of the well design 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 policy requirements if required. 9.1.9

Design Factors

List the standard Repsol design factors applicable to the casing design. For example, if the design was carried out based on API hand calculations, triaxial and compression may not apply. If however, a full computer software design was performed including triaxial and compression, include the actual design factors. 9.1.10

Reservoir Data

Highlight the assumptions used for the reservoir data, including gradients and temperature. This will be linked to the PDDP.

CASING DESIGN REPORT

9.1.11

Page 4 of 7

Kick Tolerance Data

List as a table, the maximum calculated kick tolerance for each casing string. List any assumptions made, including:


LOT requirements




BHAs




Kick influx data (this may require revision and re-assessment during the drilling of the well and have an impact on the casing design)

Record, if applicable, a blowout scenario summary for HPHT wells (refer to IP 17 for information and guidance on this issue). 9.1.12

Casing Setting Depth Chart

Provide the finalised casing setting depth chart, developed from the initial casing shoe setting depths. Summarise the rationale of moving casing shoes up or down relative to the final design. For example, requirement to case off a permeable loss zone prior, to entering 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 to setting depth for surface casing




Borehole stability may identify azimuth control as an issue. Drilling a development well at a certain azimuth may cause borehole collapse




The seismic error bars for certain formations may be large, having an influence on a 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 potential producer. List constraints on the design, which may alter its the use from the initial planned requirement. Confirm if the pressure regime and well objectives would be valid if a sidetrack was performed.

CASING SIZE (inches) 30in 30in 20in 13-3/8in 9-5/8in

7in

36in 36in 26in 17-1/2in 12-1/4in

8-1/2in

6.184in

8.681in

12.415in

18.75in

28in

27in

INSIDE PIPE DIAMETER (inches)

8,500 to 10,000

300ft to 9,000ft

300ft to 5,000ft

300ft to 2,000ft

340ft to 540ft

300ft to 340ft

INTERVAL SET: FROMTO (feet)

L-80

L-80

N-80

X56

X52

X52

GRADE

29

47

68

129

310

457

WEIGHT (lb/ft)

6.350in

New Vam

8.957in Check with manufacturer

New Vam Premium

Check with manufacturer

12.415in

18.63in

27.50in

26.97in

CONNECTION ID (inches)

Premium

API Buttress

SR-20

RL-4

RL-4

CONNECTION

8,500ft

7,500ft

2,000ft

Seabed

Seabed

Seabed

TOP OF CEMENT (feet)

0.5ppg over LOT

4,500

3,000

1,000

N/A

N/A

CASING PRESSURE TEST (psi)

N/A

14.0

13.0

11.0

N/A

N/A

MINIMUM LOT REQUIRED (ppg)

9.1.15

HOLE SIZE (inches)

CASING DESIGN REPORT Page 5 of 7

Casing Design Summary

List as a table the final casing design for the well. Use the following example as a guide only:

CASING DESIGN REPORT

Page 6 of 7

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. For example, will all of the casing strings be ordered to API standards and if so, which ones apply? Will there be special requirements on the order? An example could be, the API wall thickness will be a tighter specification to 0.90 as opposed to 0.875 minimum wall thickness. 9.1.16

Load Cases

Discuss the load cases for each casing string. Highlight unusual load cases that were used for the well design. Link the load cases to the required Design factors. Examples could 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, immediately after 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 that it assumes total evacuation; offset data suggests the likelihood of total losses and full 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 the Repsol design factors. They should be tabulated where possible and will provide a check that the load cases satisfy the Minimum design factors. This should include Burst, Collapse, Tension and, if appropriate, Compression and Triaxial. The objective of this section is to confirm that the calculated ratings for all load cases are > (greater than) 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 management should 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 design might change or encounter loads outside the approved design.

Page 7 of 7

CASING DESIGN REPORT

9.1.19

Approvals

Approval of the final design will depend on the Repsol drilling management structure in place for an operating region. However, as a guide, it will be along the lines of the following: Name Originated by:

(Signature) /

Checked/ Reviewed by: Approved by:

Appendices: The Casing Design Report should include a number of documents as part of the well design because it must act as a stand-alone document. The additional information will depend upon the complexity of the well. However, as a guide the report should include the following:


Pre Drill Data Package (PDDP)




Well Design Data Summary Sheet




Actual Casing Design, Well Design Check List (WDCL)




Pipe Manufacturer Specification Data Sheets, (API and non-API)




Calculations/Computer Printouts

including

Connection

Data

Additional reports of specialist studies (eg Conductor Analysis, Thermal Simulations, HPHT third party design on computer software).

SECTION 10

Drilling and Production Operations

Ref: CDES 10

CASING DESIGN MANUAL

Issue: Feb 2000

EXAMPLE CASING DESIGN

Page 1 of 66

TABLE OF CONTENTS 10.

EXAMPLE CASING DESIGN................................................................................. 3

10.1

PRELIMINARY DESIGN ................................................................................. 3

10.1.1 10.2

Input Data ................................................................................................ 3 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

10.2.3

Collapse Loads......................................................................................... 16

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

10.4.3

Page 2 of 66

9-5/8in Production Casing...................................................................... 45

10.4.3.1

Tension Loads.......................................................................................... 46

10.4.3.2

Burst Loads .............................................................................................. 49

10.4.3.3

10.4.4

Collapse Loads......................................................................................... 56

7in Liner ................................................................................................. 57

10.4.4.1

Tension Loads.......................................................................................... 58

10.4.4.2

Burst Loads .............................................................................................. 60

10.4.4.3

Collapse Loads......................................................................................... 63

EXAMPLE CASING DESIGN

10.

EXAMPLE CASING DESIGN

10.1

PRELIMINARY DESIGN

Page 3 of 66

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 or economic conditions. For an offshore well, such conditions may require that the well be drilled from an existing structure, requiring some form of directional profile. For an onshore well, the surface location directly above the target may be in the middle of a town, lake, swamp or other physical restriction. There may be an existing drilling facility from 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 a part 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 be drilled, the better. Smaller hole sizes, for the same hole depth, require lower rated drilling rigs, less lifting and rotating power, smaller mud systems, less cuttings volume removal, smaller (and hence cheaper) casing strings. (Against these must be set the possible requirement to change out drillstring components for different sections, BHA component and logging tool availability, and increased risk with reduced kick tolerance.) For a production well the final casing (or liner) size will be determined by the estimated production profile and the completion required. Once all of the requirements and constraints have been examined, a well course and preliminary 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 be produced for a particular well. The main information contained on this, from the basis of casing design, are the Pore Pressure and Fracture Gradient curves.

Well Design Data Summary Sheet WELL SUMMARY PROGNOSIS AND RESULTS DEPTH

Lithology and Faults

Hydrocarbons

Casing

Trajectory Targets

Chrono Strat

Actual

m

Predicted

TVD

Formations

PROGNOSIS

General Reference Datum

Ft

WELL: AA12 (Example)

COMPANY: Repsol

DATE:..01/01/2000 PORE PRESSURES, MW, LOT DATA PREDICTIONS

COMMENTS

Markers (2 way time. depth accuracy of prediction. Faults) and Comments (source rocks, structural dips)

Decisions / Policy

Pore pressures and fracture data based on offset wells:- BGF3 (drilled 1995) and NJHY2 (drilled 1997)

PSI 2,000

4,000

6,000

TD / Abandonment Decision

Limestone

1000 5000

Side Wall Samples / Ditch Cuttings 5000

Fracture Gradient

Shale

2000

RFT

Pore Pressure Gradient

Drill Stem Tests / Production Tests A drill stem test using annular pressure operated tools will be performed on any potentially productive zone.

10000

Shale

3000

VSP

Interbedded Sand and Shale

10000

Mudlogging / MWD

10,000

EXAMPLE CASING DESIGN

Well site geologist

8,000

Figure 10.1 - Design Data Summary Sheet

Remarks / Comments To be drilled as exploration well but may possibly be completed for production if tests show long term potential

Originator

Supervisor Checked and Agreed

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

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

Originator

Drilling Engineer

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

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

Page 4 of 66

4000

Logging

EXAMPLE CASING DESIGN

Page 5 of 66

Additional information required for the design (and the assumptions used for this example) are:


A vertical land well




Target depth: 12,000ft TVD




The geothermal gradient: 18F per 1,000ft – surface temperature 60F x bottom hole temperature = 276F




Bottom hole pressure (Shut-in) = 8,600psi (13.78ppg EMW)




The final casing or liner size: 7in (based on possible production and the availability of 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 for Fbend, to allow for deviations from verticality

Once the data described above is analysed, the first requirement is to convert the Pore Pressure and Fracture Gradients to equivalent mud weights versus depth and to plot these, 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 by the trip margin (commonly either 500psi or 0.5ppg mud equivalent). Parallel to the Fracture Gradient, we can draw a ‘Design’ Fracture Gradient, allowing a safe margin for 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 section indicates the load lines for casing shoe location. This indicates that, with the liner shoe at 12,000ft, the production casing shoe must be deeper than ±7900ft, and the intermediate casing shoe must be deeper than ±3800ft. The conductor string must be set sufficiently deep to be able to support any mechanical drilling, or casing loads imposed on it. For the sake of this example we will assume a conductor setting depth of 400ft but such depth would depend on the nature of the near-surface formations. Similarly, the surface BOP stack dimensions and availability, plus any additional external loads, would determine the actual diameter of the conductor. For this example we will assume a 20in, H-40, 94 lb/ft conductor. The remaining part of the casing design process is to calculate the forces for each of the potential loads and select appropriate weights and grades of casing, within acceptable safety margins. It is possible, under extreme circumstances, that during the design process no combination of weight and grade exists which will be acceptable, or that such a combination is available but creates mechanical difficulties for another casing string. In such a case, the load cases should be examined in order to determine if an alternate casing design is necessary. Senior personnel must ultimately make such decisions.

0 Conductor

1000

Fracture Gradient 2000

Intermediate Casing Design Fracture Gradient Including Kick and Cementing Margin

True Vertical; Depth (TVD), ft

4000

E

5000

6000 Production Casing 7000

Pore Pressure Gradient

8000

9000

10000

EXAMPLE CASING DESIGN

Figure 10.2 - Mud Weight Equivalent Profiles

Mud Weight Curve 3000

Production Liner

A

12000 8

10

12

14

Equivalent Mud Weight, ppg

16

18

20

Page 6 of 66

11000

400 4,500 8,000 7,500 12,000

Intermediate – 13-3/8in – Shoe Production – 9-5/8in – Shoe Production Liner – 7in – Liner Top Production Liner – Shoe

DEPTH – TVD (feet) Conductor – 20in, H-40, 94 lb/ft – Shoe

PROPOSED CASING SCHEME

–

To Liner Hanger (16ppg)

4,000 (16ppg, 500 into the 13-3/8in shoe)

Surface (16ppg)

Surface (15ppg)

CEMENT TOP TVD (feet)

8-1/2

–

12-1/4

17-1/2

26

HOLE SIZE (inches)

14.30

–

11.40

10.00

9.50

MAXIMUM MUD WEIGHTS (ppg)

13.78

–

10.87

9.00

9.00

PORE PRESSURE EMW (ppg)

17.60

–

15.00

12.50

–

FRACTURE PRESSURE EMW (ppg)

EXAMPLE CASING DESIGN Page 7 of 66

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 ‘Top Down, Bottom Up’ design.

We have thus determined that the desired casing strings are as follows:

Page 8 of 66

EXAMPLE CASING DESIGN

10.2

DETAILED DESIGN

10.2.1

20in Conductor

20in H-40, 94 lb/ft casing has the following minimum mechanical properties (as defined in API Bulletin 5C2):


Collapse Resistance

= 520psi




Internal Yield Pressure

= 1,530psi




Body Yield Strength

= 1,077 x 10 lb




Joint Yield Strength

= 581 x 10 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

3

3

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 outside are the same).

Fbuoy: Buoyancy Load

= 9.5 x 400 x 0.052 x (( x 20 /4) – ( x 19.124 /4))  -5,346 lb

2

2

Note: Buoyancy has been calculated as a negative load force throughout this example. Fbend: Bending Load

= 64 x 2 x OD x W = 64 x 2 x 20in x 94 lb/ft = 1240,640 lb

EXAMPLE CASING DESIGN

Page 9 of 66

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 back to 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

10.2.1.2.2

= 520/110 = 4.72 (This is < 520psi the collapse resistance) SAFE

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

Actual Design Factor

= (200 – 0) x 1 = 200psi (This is < 520psi, the collapse resistance) SAFE = 520/200 = 2.60

EXAMPLE CASING DESIGN

10.2.1.3

Burst Loads

10.2.1.3.1

Cementing (Stab-in)

Page 10 of 66

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 would be 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 be subjected to the drilling and well control loads encountered during the drilling of the next 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 calculate these loads we must start by assuming a realistic casing weight, which may later be amended, as we progress with the detailed analysis. As an initial start, we will assume the 13-3/8in casing to be K-55 material and 61 lb/ft weight. 13-3/8in, K-55, 61 lb/ft casing has the following minimum mechanical properties (as defined in API Bulletin 5C2):


Collapse Resistance

= 1,540psi




Internal Yield Pressure

= 3,090psi




Body Yield Strength

= 962 x 10 lb




Joint Yield Strength (SRT)

= 633 x 10 lb




Outer Diameter

= 13-3/8in




Nominal Inside Diameter

= 12.515in




Drift Diameter

= 12.359in

3 3

Page 11 of 66

EXAMPLE CASING DESIGN

10.2.2.1

Tension Loads

10.2.2.1.1

Installation: Running

Fwt: Dry Weight Fbuoy: Buoyancy (with 10.0ppg mud)

= 4,500 x 61 = 274,500 lb 2

= 10 x 4,500 x 0.052 (( x 13.375 /4) – 2 ( x 12.515 /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 is 1,169,000 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

Page 12 of 66

EXAMPLE CASING DESIGN

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 13.375 /4) – Pi x 2 ( x 12.515 /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)

2

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.

EXAMPLE CASING DESIGN

10.2.2.2

Page 13 of 66

Burst Loads

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 Total cement pumped (with 10% excess) Equivalent height in 13-3/8in, 61 lb/ft casing

= (4,100 x 0.1237) + (400 x 0.1814) = 580bbl = 580 x 1.1 = 638bbl = 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

10.2.2.2.2

= (4,649 – 2,340) x 1.1 = 2,309psi SAFE (The internal yield pressure of 13-3/8in, K-55, 61 lb/ft casing is 3,090psi)

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

Pb: Differential (Burst) Pressure

= (4,340 – 3,744) x 1.1 = 656psi SAFE (This is < the burst rating of the casing, 3,090psi)

EXAMPLE CASING DESIGN

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

Pb: Differential (Burst) Pressure

10.2.2.2.4

Page 14 of 66

= (4,340 – 2,106) x 1.1 = 2,457psi SAFE (This is < the burst rating of the casing, 3,090psi)

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 in the hole. Test Margin (safety margin on LOT) Psurf: Surface Test Pressure

= 0.5ppg. Therefore, maximum value is 13.0ppg = (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 = 1,030psi SAFE (This is < the burst rating of the casing, 3,090psi)

EXAMPLE CASING DESIGN

10.2.2.2.5

Page 15 of 66

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 at next 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: S2 K MW 0.052 Psurf 

  VFCSG-DP  4 

1 2



S 2


329 2 452,200 11.4 0.052 Psurf 

  0.1278 

 4

1 2



329 2

Psurf  27,060  2,097,529 2  164.5  1,293 psi 1

Note: Additional calculation indicates a maximum kick volume approximately 100bbl, above which failure would occur at the shoe. Refer to Well Control Manual for appropriate calculation details. The 100bbl kick load could dominate the burst, so the test pressure for the casing will be 2,000psi.

EXAMPLE CASING DESIGN

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

10.2.2.3.2

Page 16 of 66

= (3,744 – 2,340) x 1.0 = 1,404psi SAFE (Collapse resistance of 13-3/8in, K-55, 61 lb/ft casing is 1,540psi)

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 = 2,340psi FAIL (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 are two options:


Consider load case and assess probability/risk of occurrence. If risk is low then some relaxation of the load criteria may be acceptable, provided that management approves 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 that will pass the full evacuation criteria, so we need to increase both the weight and grade.

EXAMPLE CASING DESIGN

Page 17 of 66

Our second choice of casing is therefore 13-3/8in, C-75, 72 lb/ft casing with a pipe body yield strength of 1,558klb, an internal yield pressure of 5,040psi and collapse resistance of 2,590psi. The buttress joint strength is 1,598klb, which is greater than the pipe body strength and so will be utilised as the connector. Since all of these parameters are higher than the previous design calculations, the casing will pass each of the load tests. It is not necessary, at this stage, to recalculate the load cases but it will need to be done later to determine the final actual design factors 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 the 13-3/8in casing. After cementing and pressure testing, the shoe will be drilled out and the casing will be subjected to the drilling and well control loads encountered during the drilling of the next section. We must consider each of the loads separately. Many of these loads, however, are tensile loads which depend on the casing weight. In order to calculate the loads we must start by assuming a realistic casing weight which may later be 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 weight and 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 mechanical properties (as defined in API Bulletin 5C2):


Collapse Resistance

= 4,610psi




Internal Yield Pressure

= 6,440psi




Body Yield Strength

= 1,018 x 10 lb




Joint Yield Strength (Buttress)

= 1,098 x 10 lb




Outer Diameter

= 9-5/8in




Nominal Inside Diameter

= 8.681in




Drift Diameter

= 8.525in

3 3

EXAMPLE CASING DESIGN

10.2.3.1

Tension Loads

10.2.3.1.1

Installation: Running

Fwt: Dry Weight Fbuoy: Buoyancy (with 11.4 ppgmud)

Page 18 of 66

= 8,000 x 47 = 376,000 lb = Pe (Ao – Ai) 2 2 = 11.4 x 8,000 x 0.052 (( x 9.625 /4) – ( x 8.681 /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)

Design Factor (no shock load correction)

= 1.6

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. 10.2.3.1.2

Installation: Running and Overpull

Fop: Assume an overpull of 200,000 lb. 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.

EXAMPLE CASING DESIGN

10.2.3.1.3

Page 19 of 66

Plug Bump after Cement Displacement

Fplug: Plug bump to 2,000psi. 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

Ft: Total Load

= Fwt – Fbuoy + Fbend + Fplug

Fbuoy

= (Pe x Ao) – (Pi x Ai) 2 2 = Pe ( x 9.625 /4) – Pi ( x 8.681 /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

Note: This is a negative value. 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 threaded casing is 1,098klb) SAFE

10.2.3.1.4

Installation: Pretension after Waiting on Cement

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) x Design 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, Buttress threaded casing is 1,098klb) SAFE

EXAMPLE CASING DESIGN

10.2.3.2

Page 20 of 66

Burst Loads

Cemented back to 4,000ft with 16.0ppg cement. Hole drilled with 11.4ppg mud. 10.2.3.2.1

Installation: Cement Displacement

Psurf: Assume cement displacement pressure of 1,000psi. External volume to be cemented (9-5/8 shoe to 4,500ft) Total cement pumped (with 10% excess) Equivalent height in 9-5/8in, 47 lb/ft casing

= (4,000 x 0.0558) + (500 x 0.0580) = 252bbl = 252 x 1.1 = 277bbl = 277/0.0732 = 3,784ft

Pe: External Pressure

= Mud Hydrostatic = 8,000 x 11.4 x 0.052 = 4,742psi

Pi: Internal Pressure

= Cement Hydrostatic + Mud Hydrostatic + Displacement Pressure = (3,784 x 16.0 x 0.052) + (4,216 x 11.4 x 0.052) + 1,000 = 6,648psi

Design Factor

= 1.1

Pb: Differential (Burst) Pressure

= (6,648 – 4,742) x 1.1 = 2,097psi SAFE (Internal Yield Pressure of 9-5/8in, C-755, 47 lb/ft casing is 6,440psi)

EXAMPLE CASING DESIGN

10.2.3.2.2

Page 21 of 66

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

Pb: Differential (Burst) Pressure

10.2.3.2.3

= (6,742 – 5,699) x 1.1 = 1,147psi SAFE (Internal Yield Pressure of 9-5/8in, C-755, 47 lb/ft casing is 6,440psi)

Drilling: Casing Pressure Test after WOC

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

Pb: Differential (Burst) Pressure

= (8,242 – 4,243) x 1.1 = 4,399psi SAFE (Internal Yield Pressure of 9-5/8in, C-75, 47 lb/ft casing is 6,440psi)

EXAMPLE CASING DESIGN

10.2.3.2.4

Page 22 of 66

Drilling: Leak-off Test after Drilling Out Shoe

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

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 + 1,750 = (11.4 x 8,000 x 0.052) + 1,706 = 6,448psi

Design Factor

= 1.1

Pb: Differential (Burst) Pressure

10.2.3.2.5

= (6,448 – 4,243) x 1.1 = 2,426psi SAFE (Internal Yield Pressure of 9-5/8in, C-75, 47 lb/ft casing is 6,440psi)

Drilling: 100bbl Gas Kick from Next Casing Shoe

Depth of Hole (next shoe)

= 12,000ft in 8-1/2in hole

Mud Weight

= 14.3ppg

Pore Pressure at next shoe

= 13.78ppg EMW

LOT at this shoe + Test Margin

= 15.5ppg EMW

BHP at next shoe

= 13.78 x 12,000 x 0.052 = 8,600psi

Kick Volume

= 100bbl

K (BHP x Kick Volume)

= 860,000

Influx Gradient

= 0.15psi/ft

EXAMPLE CASING DESIGN

Page 23 of 66

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

S2 K MW 0.052 Psurf 

  VFCSG-DP  4 

1 2



S 2


1,339 2 860,000 14.3 0.052 Psurf 

  4 0.049 



Psurf  448,230  13,050,939 2  669.5 1

1 2



1,339 2

 3,005psi

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 = 7,480psi FAIL (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 = 4,050psi SAFE

EXAMPLE CASING DESIGN

Page 24 of 66

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).


Collapse Resistance

= 6,350psi




Internal Yield Pressure

= 7,430psi




Body Yield Strength

= 1,166 x 10 lb




Joint Yield Strength (Buttress)

= 1,257 x 10 lb




Outer Diameter

= 9-5/8in




Nominal Inside Diameter

= 8.535in




Drift Diameter

= 8.379in

3 3

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 close to 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 and temperature effects. This will require final assessment, once all strings are tabulated and 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 DST string leaks at surface into the 9-5/8in x test string annulus. This results in a full gas to surface shut-in tubing head pressure, on top of the mud and has an impact on the differential 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

Pb: Differential (Burst) Pressure (10,000ft)

= (14,236 – 5,179) x 1.1 = 9,963psi FAIL

EXAMPLE CASING DESIGN

Page 25 of 66

This is an unrealistic load condition, as it dominates the burst design for the well and imposes an abnormal load condition on the liner top, due to the DST packer depth in the 7in liner. A practical approach based on risk assessment and performing a HAZOP, would be to displace the well to a 9.0ppg unweighted packer fluid, prior to setting the completion packer and carrying out perforation operations. Repeating the calculation for Pi using a 9.0ppg packer fluid results in the following results: Pi

= = =

Pb Differential (Burst) Pressure (10,000ft)

6,800 + (9.0 x 10,000 x 0.052) 6,800 + 4,680 11,480psi

= (11,480 – 5,179) x 1.1 = 6,931psi SAFE (As the 9-5/8 C-75in casing has a burst rating of 7,430psi)

Therefore, using an unweighted 9.0ppg packer fluid for a DST/completion would be acceptable 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 the 9-5/8in burst load, for Full Gas to Surface. This has an actual burst design factor of 1.093 excluding casing wear and temperature effects. This justifies an upgrade to a slightly higher specification casing string from 53-1/2 lb/ft Grade C-75 to 53-1/2 lb/ft Grade L-80. This improves the burst resistance from 7,430psi to 7,930psi, an improvement of 500psi (6.7%). This seems a reasonable approach to adopt to take into account potential casing wear, especially at surface near the wellhead area. If both casing wear and temperature de-rating are taken into consideration above an ambient temperature of 68F, 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 the packer fluid, we still require a pressure test at some point on the 9-5/8in casing to 6,800psi. Referring to the Casing Design Manual Section 7, we require a pressure test to 80% of the burst rating.

EXAMPLE CASING DESIGN

Page 26 of 66

The optimum design should now look at upgrading the 9-5/8in from Grade L-80 to C-Grade 90, weight 53-1/2 lb/ft. Checking the properties of this grade in API Bulletin 5C2 provides the following minimum mechanical properties: 9-5/8in C-90, 53-1/2in Casing


Collapse Resistance

= 7,120psi




Internal Yield Pressure (Body)

= 8,920psi




Body Yield Strength

= 1,399 x 10 lb




Joint Yield Strength (Buttress)

= 1,386 x 10 lb




Outer Diameter

= 9-5/8in




Nominal Inside Diameter

= 8.535in




Drift Diameter

= 8.379in

3 3

This pipe can satisfy all DST burst loads using an unweighted packer fluid and also provide a margin of safety for casing wear and temperature de-rating. A pipe body matched 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 for all loads for the casing strings as part of the design. It should specify that the 9-5/8in C-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 weight C75, 47 lb/ft to demonstrate the casing design principles.

EXAMPLE CASING DESIGN

10.2.3.3

Collapse Loads

10.2.3.3.1

Cementing

Page 27 of 66

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

Pc: Differential (Collapse) Load

10.2.3.3.2

= (6,302 – 5,949) x 1.0 = 353psi SAFE (Collapse resistance of 9-5/8in, C-75, 47lb/ft casing is 4,630psi)

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

Pi: Internal Pressure

= 0psi (Air)

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 is 4,630psi)

As designed previously, with the 13-3/8in casing, we have the two options. The probability of a full 8,000ft of casing being drawn down to atmospheric pressure is extremely low and it would probably be justifiable to reduce the load condition. Once again, we will select a higher grade or casing weight, to use with the existing criteria.

EXAMPLE CASING DESIGN

Page 28 of 66

Our second choice of casing is 9-5/8in, C-75, 53-1/2 lb/ft casing, with the following properties:


Collapse Resistance

= 6,380psi




Internal Yield Pressure

= 7,430psi




Body Yield Strength

= 1,166 x 10 lb




Joint Yield Strength

= 1,257 x 10 lb




Outer Diameter

= 9-5/8in




Nominal Inside Diameter

= 8.535in




Drift Diameter

= 8.379in

3 3

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, the casing will pass each of the load tests. It is not necessary, at this stage, to recalculate the load cases but it will need to be done later to determine the actual design factors that will exist. However, the final 9-5/8in casing choice will be C-90, 53-1/2 lb/ft due to the service burst 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 above the 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.


Collapse Resistance

= 8,200psi




Internal Yield Pressure (Pipe)

= 8,490psi




Internal Yield Pressure (SRT)

= 8,490psi




Body Yield Strength

= 699 x 10 lb




Joint Yield Strength (SRT)

= 633 x 10 lb




Outer Diameter

= 7in




Nominal Inside Diameter

= 6.094in




Drift Diameter

= 5.969in

3 3

Note: If specification allows, order pipe as special drift for a 6in bit.

EXAMPLE CASING DESIGN

10.2.4.1

Tension Loads

10.2.4.1.1

Installation: Running

Page 29 of 66

Casing run with 14.3ppg mud. Fwt: Dry Weight Fbuoy: Buoyancy (with 14.3ppg mud)

= 4,500 x 32 = 144,000 lb = Pe (Ao – Ai) 2 2 = 14.3 x 4,500 x 0.052 (( x 7 /4) – ( x 6.094 /4))

Fbuoy

= 3,346 (38.48 – 29.17) = -31,151 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 32 = 28,672 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 = (144,000 – 31,151 + 28,672) x 1.6 = 226,434 lb SAFE

Casing body yield strength is 699klb, and buttress threaded casing is 779klb. SAFE. 10.2.4.1.2

Installation: Running and Overpull

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

EXAMPLE CASING DESIGN

10.2.4.1.3

Page 30 of 66

Plug Bump after Cement Displacement

Plug bump to 2,000psi. Cemented with 16ppg slurry to the liner top at 7,500ft. Design Factor

= 1.4

Ft: Total Load

= Fwt – Fbuoy + Fbend + Fplug

Fbuoy

= (Pe x Ao) – (Pi x Ai) (Closed end pipe) 2

2

= Pe ( x 7 /4) – Pi ( x 6.094 /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

10.2.4.1.4

Installation: Pretension after Waiting on Cement

Not Applicable.

EXAMPLE CASING DESIGN

10.2.4.2

Page 31 of 66

Burst Loads

Cemented back to 7,500ft with 16.0ppg cement. Hole drilled with 14.3ppg mud. 10.2.4.2.1

Installation: Cement Displacement

Assume cement displacement pressure of 1,000psi. External volume to be cemented (12,000 to 7,500) Total cement pumped (with 20% excess) Equivalent height in 7in, 32 lb/ft casing

= (4,000 x 0.0185) + (500 x 0.0231) = 86bbl = 86 x 1.2 = 103bbl = =

103/0.036 2,861ft

Pe: External Pressure

= = =

Mud Hydrostatic 4,500 x 14.3 x 0.052 3,346psi

Pi: Internal Pressure

=

=

Cement Hydrostatic + Mud Hydrostatic + Displacement Pressure (2,861 x 16.0 x 0.052) + (1,639 x 14.3 x 0.052) + 1,000 4,600psi

=

1.1

=

Design Factor Pb: Differential (Burst) Pressure

= (4,600 – 3,346) x 1.1 = 1,379psi SAFE (Internal yield pressure of 7in, C-75, 32 lb/ft casing is 8,490psi)

EXAMPLE CASING DESIGN

10.2.4.2.2

Installation: Plug Bump to 3,000psi

Pe: External Pressure

= = =

Cement Hydrostatic (4,500 x 16.0 x 0.052psi) 3,744psi

Pi: Internal Pressure

= = =

Mud Hydrostatic + Plug Bump (14.3 x 4,500 x 0.052) + 3,000 6,346psi

Design Factor

=

1.1

Pb: Differential (Burst) Pressure

10.2.4.2.3

Page 32 of 66

= (6,346 – 3,744) x 1.1 = 2,862psi SAFE (Internal yield pressure of 7in, C-75, 32 lb/ft casing is 8,490psi)

Drilling: Casing Pressure Test after WOC

Test Pressure

=

3,000psi

Note: Based on a bottom hole pressure of 8,600psi at TD and using a gas gradient of 0.15psi/ft, the gas to surface load after the liner is installed would result in the following: Gas to surface

Gas pressure at 7in liner top

= = =

8,600 – (12,000 x 0.15 ) 8,600 – 1,800 6,800psi

= = =

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 pressure at 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 a hydrostatic 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 7in liner top. Therefore the minimum pressure test required using the 14.3ppg mud is 7,925 – 5,577psi. This yields a minimum pressure test requirement of 2,348psi for drilling load cases. Therefore pressure test the 7in liner lap and casing to 2,500psi with the 14.3ppg mud.

EXAMPLE CASING DESIGN

Page 33 of 66

However, we will need to check the liner also satisfies the DST/completion load case for an SITHP leak at surface, on top of the mud column during DST assuming the packer is set in the 7in liner. The DST packer will be set in the 9-5/8in casing (see load case 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

Pb: Differential (Burst) Pressure

= (11,423 – 6,115) x 1.1 = 5,939psi SAFE (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, if further drilling below the liner were ever considered, then the load cases must be calculated. 10.2.4.2.4

Testing/Production: SITHP on Packer Fluid

This is based on a DST with the 14.3ppg drilling mud as the packer fluid and the DST string leaks at surface into the 9-5/8in x test string annulus. This results in a full gas to surface shut-in tubing head pressure, on top of the mud and has an impact on the differential burst pressure at the 9-5/8in casing shoe and 7in liner top. 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

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

EXAMPLE CASING DESIGN

Page 34 of 66

This is an unrealistic load condition, as it dominates the burst design for the complete well and also imposes an abnormal load condition on the liner top, due to the setting depth of the DST packer in the 7in liner. A practical approach based on risk assessment and performing a HAZOP would be to displace the well to a 9.00ppg unweighted packer fluid, prior to setting the packer and carrying out perforation operations. Repeating the calculation for P i using a 9.0ppg 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 = 6,931psi (This is < the burst rating of the 9-5/8in C-90, 53-1/2in casing) SAFE

Therefore, using an unweighted 9.0ppg packer fluid for a DST/completion would be acceptable 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 at liner lap (7,500ft) for test

= (15.0 x 7,500 x 0.052) + 500 = 6,350psi (16.3ppg EMW)

Mud in Hole

=

Required Surface Pressure

= 6,350 – (14.3 x 7,500 x 0.052) = 773psi

Pe: External Load (at liner lap)

Pb: Differential (Burst) Pressure (7,500ft)

14.3ppg

= Cement Mix Water Hydrostatic + Mud Hydrostatic = (3,500 x 9 x 0.052) + (4,000 x 11.4 x 0.052) = 4,009psi = (6,350 – 4,009) x 1.1 = 2,575psi (This is < than the burst rating of the 9-5/8 casing and 7in liner) SAFE

EXAMPLE CASING DESIGN

Page 35 of 66

However, we need to check the maximum pressure that could be exerted on the top of the 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 top of the packer fluid can be assessed in terms of risk. The practical solution is to utilise a 9-5/8in DST packer just above the 7in liner lap. This will require a longer tailpipe for the DST string and will also affect the eventual well kill. However, these options can be assessed 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 the maximum pressure the liner top may see is the gas to surface shut-in pressure of 7,925psi. We can now return to the original load case for the pressure test of the liner, Section 10.2.4.2.3.

10.2.4.3

Collapse Loads

10.2.4.3.1

Cementing

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

Pi: Internal Load

= Mud Hydrostatic = 12,000 x 14.3 x 0.052 = 8,923psi

Design Factor

= 1.0

Pc: Differential (Collapse) Load

= (9,321 – 8,923) x 1.0 = 398psi SAFE (Collapse resistance of 7in, C-75, 32 lb/ft casing is 8,230psi)

EXAMPLE CASING DESIGN

10.2.4.3.2

Page 36 of 66

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

Pi: Internal Pressure

= 0psi (Air)

Design Factor

= 1.0

Pc: Differential (Collapse) Pressure

= (8,923 – 0) x 1.0 = 8,923psi FAIL (For 7in, C-75, 32 lb/ft casing, collapse resistance is 8,200psi)

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:


Collapse Resistance

=

9,670psi




Internal Yield Pressure (Pipe)

=

9,340psi




Internal Yield Pressure (SRT)

=

8,660psi




Body Yield Strength

=

763 x 10 lb




Joint Yield Strength (SRT)

=

703 x 10 lb




Outer Diameter

=

7in




Nominal Inside Diameter

=

6.004in




Drift Diameter

=

5.879in

3 3

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.

Page 37 of 66

EXAMPLE CASING DESIGN

10.3

FINAL CASING DESIGN

The final selected casing strings for the well design are: FINAL CASING SCHEME

MATERIAL/ GRADE

WEIGHT (lb/ft)

CONNECTION

NOMINAL ID (in)

DRIFT ID (in)

20in

H-40

94

Short Round Thread

19.124

18.936

13-3/8in

C-75

72

Short Round Thread

12.347

12.25 (Special Drift)

9-5/8in

C-90

53-1/2

Premium New Vam

8.535

8.50 (Special Drift)

7in

C-75

35

Premium New Vam

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 further calculations are necessary. 20in H-40, 94 lb/ft casing has the following minimum mechanical properties (as defined in API Bulletin 5C2):


Collapse Resistance

= 520psi




Internal Yield Pressure

= 1,530psi




Body Yield Strength

= 1,077 x 10 lb




Joint Yield Strength

= 581 x 10 lb (For short, round threaded (SRT) and coupled connection)




Outer Diameter

= 20in




Nominal Inside Diameter

= 19.124in




Drift Diameter

3

3

= 18.936in

Note: As the 20in is a conductor string, a stronger connection than SRT could be selected if required, to allow for bending moments and compression. This would normally be carried out as a separate engineering analysis.

Page 38 of 66

EXAMPLE CASING DESIGN

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 (as defined in API Bulletin 5C2):


Collapse Resistance




Internal Yield Pressure (Body)

= 5,040psi




Internal Yield Pressure (Buttress)

= 4,930psi




Body Yield Strength

= 1,558 x 10 lb




Joint Yield Strength (Buttress)

= 1,598 x 10 lb




Outer Diameter

= 13-3/8in




Nominal Inside Diameter

= 12.347in




Drift Diameter

= 12.191in

= 2,600psi

3 3

(This has a standard drift size of 12.191in. Therefore, order as special drift to 12.259 for a 12-1/4in bit.)

10.4.2.1

Tension Loads

10.4.2.1.1

Installation : Running

Ft: Total Load

= Fwt – Fbuoy + Fbend + Fshock

Fwt: Dry Weight

= 4,500 x 72 = 324,000 lb

Fbuoy: Buoyancy (with 10.0ppg mud)

2

2

= 10 x 4,500 x 0.052 (( x 13.375 /4) – ( x 12.347 /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

Fshock: Shock Load

= 0 lb (Shock load not calculated)

Design Factor (no shock load correction)

= 1.6

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

EXAMPLE CASING DESIGN

10.4.2.1.2

Page 39 of 66

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 = (324,000 – 48,602 +123,264 + 100,000) x 1.4 = 698,127 lb SAFE

Actual Design Factor

= 1,558,000/408,662 = 3.80

10.4.2.1.3

Plug Bump after Cement Displacement

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

Ft: Total Load

= Fwt – Fbuoy + Fbend + Fplug

Fbuoy

= (Pe x Ao) – (Pi x Ai) 2 2 = Pe x ( x 13.375 /4) – Pi x ( x 12.347 /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

Note: This is a negative value. 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

Actual Design Factor

= 1,558,000/440,867 = 3.53

10.4.2.1.4

Installation: Pretension after Waiting on Cement

The string will be cemented back to surface so this does not apply. SAFE

EXAMPLE CASING DESIGN

10.4.2.2

Page 40 of 66

Burst Loads

Cemented to Surface with 16.0ppg cement. Hole drilled with 10.0ppg mud. 10.4.2.2.1

Installation: Cement Displacement

Assume cement displacement pressure of 1,000psi. External Volume Total Cement Pumped (with 10% excess) Equivalent height in 13-3/8in, 72 lb/ft casing

= (4,100 x 0.1237) + (400 x 0.1814) = 580bbl = 580 x 1.1 = 638bbl = 638/0.148 = 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

Pb: Differential (Burst) Pressure

Actual Design Factor

= (4,685 – 2,340) x 1.1 = 2,580psi (This is < the minimum burst rating of the connector, 4,930psi) SAFE = 4,930/2,345 = 2.10

EXAMPLE CASING DESIGN

10.4.2.2.2

Installation: Plug Bump to 2,000psi

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

Pb: Differential (Burst) Pressure

Actual Design Factor

10.4.2.2.3

Page 41 of 66

= (4,340 – 3,744) x 1.1 = 656psi (This is < the minimum burst rating of the connector, 4,930psi) SAFE = 4,930/596 = 8.27

Drilling: Casing Pressure Test after WOC

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

Pb: Differential (Burst) Pressure

Actual Design Factor:

= (4,340 – 2,106) x 1.1 = 2,457psi (This is < the minimum burst rating of the connector, 4,930psi) SAFE = 4,930/2,234 = 2.20

EXAMPLE CASING DESIGN

10.4.2.2.4

Page 42 of 66

Drilling: Leak-off Test after Drilling Out Shoe

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

Pb: Differential (Burst) Pressure

Actual Design Factor

= (3,042 – 2,106) x 1.1 = 1,030psi (This is < the minimum burst rating of the connector, 4,930psi) SAFE = 4,930/936 = 5.26

EXAMPLE CASING DESIGN

10.4.2.2.5

Page 43 of 66

Drilling: 100bbl Gas Kick from Next Casing Shoe

Depth of Hole (next shoe)

= 8,000ft in 12-1/4in hole

Mud Weight

= 11.4ppg

Pore Pressure at next shoe

= 10.87ppg EMW

LOT at this shoe + Test Margin

= 13.0ppg EMW

BHP at next shoe

= 10.87 x 8,000 x 0.052 = 4,582psi

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 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: S2

Psurf 

 4



K MW 0.052  VFCSG-DP 

1 2



S 2


329 2 452,200 11.4 0.052 Psurf 

  0.1278   4

1 2



329 2

Psurf  27,060  2,097,529 2  164.5  1,293psi 1

EXAMPLE CASING DESIGN

10.4.2.3

Collapse Loads

10.4.2.3.1

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

Actual Design Factor

10.4.2.3.2

Page 44 of 66

= (3,740 – 2,340) x 1.0 = 1,404psi (This is < the collapse resistance, 2,590psi) SAFE = 2,590/1,404 = 1.84

Drilling: Full Evacuation Pressure

Pe: External Pressure

= Hydrostatic Pressure of mud 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

Actual Design Factor

= (2,340 – 0) x 1.0 = 2,340psi (This is < the collapse resistance, 2,590psi) SAFE = 2,590/2,340 = 1.1

EXAMPLE CASING DESIGN

10.4.3

Page 45 of 66

9-5/8in Production Casing

9-5/8in, C-90 material and 53-1/2 lb/ft weight casing has the following minimum mechanical properties (as defined in API Bulletin 5C2 and New Vam data sheet):


Collapse Resistance

= 7,120psi




Internal Yield Pressure (Body)

= 8,920psi




Internal Yield Pressure (Joint)

= 8,920psi




Body Yield Strength

= 1,399 x 10 lb




Joint Yield Strength

= 1,399 x 10 lb




Outer Diameter

= 9-5/8in




Nominal Inside Diameter

= 8.535in




Drift Diameter

= 8.379in

3 3

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, with 16.0ppg cement).

EXAMPLE CASING DESIGN

10.4.3.1

Tension Loads

10.4.3.1.1

Installation: Running

Ft: Total Load

= Fwt – Fbuoy + Fbend

Fwt: Dry Weight

= 8,000 x 53.5 = 428,000 lb

Fbuoy: Buoyancy (with 11.4ppg mud)

Page 46 of 66

= Pe (Ao – Ai) 2 2 = 11.4 x 8,000 x 0.052 (( x 9.625 /4) – ( x 8.535 /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

Fshock: Shock Load

= 0 lb (Shock load not calculated)

Design Factor (no shock load correction)

= 1.6

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

Actual Design Factor

= 1,399,000/419,937 = 3.33

EXAMPLE CASING DESIGN

10.4.3.1.2

Page 47 of 66

Installation: Running and Overpull

Fop: Assume an overpull of 200,000 lb Ft: Total Load

= Fwt – Fbuoy + Fbend + Fop

Design Factor

= 1.4

Ft: Total Load

= = = =

Pipe Body Yield Strength

= 1,399,000 lb. SAFE

Actual Design Factor

= 1,399,000/619,937 = 2.25

10.4.3.1.3

(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

Plug Bump after Cement Displacement

Fplug: Plug bump to 2,000psi. 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

Ft: Total Load

= Fwt – Fbuoy + Fbend + Fplug

Fbuoy

= (Pe x Ao) – (Pi x Ai) 2 2 = Pe ( x 9.625 /4) – Pi ( x 8.535 /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

Note: This is a negative value. 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

Actual Design Factor

= 1,399,000/464,667 = 3.0

EXAMPLE CASING DESIGN

Page 48 of 66

However, as the casing requires a pressure test to 6,800psi to confirm integrity for Full Gas to Surface, the test will be performed on plug bump with upgraded float equipment, prior to the cement setting and prior to drillout. Therefore, the tensile load now becomes: Ft: Total Load

= Fwt – Fbuoy + Fbend + Fplug

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 (Casing body yield strength is 1,399klb) SAFE

Actual Design Factor

= 1,399,000/739,227 = 1.89

10.4.3.1.4

Installation: Pretension after Waiting on Cement

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) x Design Factor

Ft: Total Load

= (428,000 – 143,645 + 65,912 + 60,000) = 410,267 x 1.4 = 574,374 lb (Casing body yield strength is 1,399klb) SAFE

Actual Design Factor

= 1,399,000/410,267 = 3.40

EXAMPLE CASING DESIGN

10.4.3.2

Page 49 of 66

Burst Loads

Cemented back to 4,000ft with 16.0ppg cement. Hole drilled with 11.4ppg mud. 10.4.3.2.1

Installation: Cement Displacement

Assume cement displacement pressure of 1,000psi. External Volume to be Cemented (9-5/8 shoe to 4,500ft) Total Cement Pumped (with 10% excess)

= (4,000 x 0.0558) + (500 x 0.0580) = 252bbl = 252 x 1.1 = 277bbl

Equivalent Height in 9-5/8in, 53.5 lb/ft Casing = 277/0.0707 = 3,920ft Pe: External Pressure

= Mud Hydrostatic = 8,000 x 11.4 x 0.052 = 4,742psi

Pi: Internal Pressure

= Cement Hydrostatic + Mud Hydrostatic + Displacement Pressure = (3,920 x 16.0 x 0.052) + (4,080 x 11.4 x 0.052) + 1,000 = 6,648psi

Design Factor

= 1.1

Pb: Differential (Burst) Pressure

Actual Design Factor

= (6,648 – 4,742) x 1.1 = 2,097psi (Casing internal yield pressure of 9-5/8in C-90, 53-1/2 lb/ft is 8,920psi) SAFE = 8,920/1,906 = 4.68

EXAMPLE CASING DESIGN

10.4.3.2.2

Page 50 of 66

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) + 2,000 = 6,742psi

Design Factor

= 1.1

Pb: Differential (Burst) Pressure

Actual Design Factor

= (6,742 – 5,699) x 1.1 = 1,147psi (Casing internal yield pressure of 9-5/8in C-90, 53-1/2 lb/ft is 8,920psi) SAFE = 8,920/1,043 = 8.55

However, as the casing requires a pressure test to 6,800psi to confirm integrity for Full Gas to Surface, the test will be performed on plug bump with upgraded float equipment, prior to the cement setting and prior to drillout. Therefore, the differential burst load now becomes: 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) + 6,800 = 11,542psi

Design Factor

= 1.1

Pb: Differential (Burst) Pressure

Actual Design Factor

= (11,542 – 5,699) x 1.1 = 6,427psi (Casing internal yield pressure of 9-5/8in C-90, 53-1/2 lb/ft is 8,920psi) SAFE = 8,920/5,843 = 1.52

EXAMPLE CASING DESIGN

10.4.3.2.3

Page 51 of 66

Drilling: Casing Pressure Test after WOC

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

Pb: Differential (Burst) Pressure

Actual Design Factor

= (8,242 – 4,243) x 1.1 = 4,399psi (Casing internal yield pressure of 9-5/8in C-90, 53-1/2 lb/ft is 8,920psi) SAFE = 8,920/3,999 = 2.23

Note: This 9-5/8in pressure test is greater than that required for the 7in liner lap test. 10.4.3.2.4

Drilling: Leak-off Test after Drilling Out Shoe

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

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 + 1,750 = (11.4 x 8,000 x 0.052) +1,706 = 6,448psi

Design Factor

= 1.1

Pb: Differential (Burst) Pressure

Actual Design Factor

= (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 = 8,920/2,205 = 4.04

EXAMPLE CASING DESIGN

10.4.3.2.5

Page 52 of 66

Drilling: 100bbl Gas Kick from Next Casing Shoe

Depth of Hole (next shoe)

= 12,000ft in 8-1/2in hole

Mud Weight

= 14.3ppg

Pore Pressure at next shoe

= 13.78ppg EMW

LOT at this shoe + Test Margin

= 15.5ppg EMW

BHP at next shoe

= 13.78 x 12,000 x 0.052 = 8,600psi

Kick Volume

= 100bbl

K (BHP x Kick Volume)

= 860,000

Influx Gradient

= 0.15psi/ft

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

S 2 K MW 0.052 Psurf 

  VFCSG-DP  4 

1 2



S 2


1,339 2 860,000 14.3 0.052 Psurf 

  4 0.049 



1 2



1,339 2

Psurf  448,230  13,050,939 2  669.5  3,005psi 1

Pressure of gas top when at surface (using formula of Design Manual) = 3,005psi. SAFE (provided that casing previously tested above this value). Actual Design Factor

= 8,920/3,005 = 2.96

EXAMPLE CASING DESIGN

10.4.3.2.6

Page 53 of 66

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).

Pb: Differential (Burst) Pressure (Surface)

Pb: Differential (Burst) Pressure (7,500ft)

Actual Design Factor (Surface)

=

7,925psi at 7,500ft (Liner top)

= =

(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

= (7,925 – 4,243) x 1.1 = 4,480psi (Casing internal yield pressure, 9-5/8in C-90, 53-1/2 lb/ft is 8,920psi) SAFE = =

8,920/6,800 1.31

EXAMPLE CASING DESIGN

10.4.3.2.7

Page 54 of 66

Testing/Production: SITHP on Packer Fluid

This is based on a DST with the 14.3ppg drilling mud as the packer fluid and the DST string leaks at surface into the 9-5/8in x test string annulus. This results in a full gas to surface SITHP on top of the mud and has an impact on the differential 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

Pb: Differential (Burst) Pressure (10,000ft)

= (14,236 – 5,179) 9,057 x 1.1 = 9,963psi FAIL

This is an unrealistic load condition, as it dominates the burst design and also imposes an abnormal load condition on the liner top, due to the setting depth of the DST packer in the 7in liner. A practical approach based on risk assessment and performing a HAZOP, would be to displace the well to a 9.00ppg unweighted packer fluid, prior to setting the completion packer and carrying out perforation operations. Repeating the calculation for Pi using a 9.0ppg packer fluid results in the following results: Pi

Pb Differential (Burst) Pressure (10,000ft)

Actual Design Factor

= = =

6,800 + (9.0 x 10,000 x 0.052) 6,800 + 4,680 11,480psi

= (11,480 – 5,200) 6,280 x 1.1 = 6,908psi (Casing internal yield pressure, 9-5/8in C-90, 53-1/2 lb/ft is 8,920psi) SAFE = =

8,920/6,280 1.42

Therefore, using an unweighted 9.0ppg packer fluid for a DST/completion would be acceptable.

EXAMPLE CASING DESIGN

10.4.3.2.8

Page 55 of 66

7in Liner Lap Test (9-5/8in shoe LOT + 500psi)

9-5/8in shoe LOT to 15.0ppg EMW. Pi: Required Pressure at liner lap (7,500ft) for test

= (15.0 x 7,500 x 0.052) + 500 = 6,350psi (16.28ppg EMW)

Mud in Hole

=

Required Surface Pressure

= 6,350 – (14.3 x 7,500 x 0.052) = 773psi

Pe: External Load (at liner lap)

Pb: Differential (Burst) Pressure (7,500ft)

Actual Design Factor

14.3ppg

= = =

Cement Mix Water Hydrostatic + Mud Hydrostatic (3,500 x 9 x 0.052) + (4,000 x 11.4 x 0.052) 4,009psi

= = =

(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

= =

8,920/2,341 3.81

However, we need to check the maximum pressure that could be exerted on the top of the 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 top of the packer fluid can be assessed in terms of risk. Secondly, using a 7in liner lap packer at installation can reduce the potential risk of damaging the liner lap and eventual 9-5/8in shoe. Or if this is deemed as unacceptable, utilise a 9-5/8in DST packer just above the 7in liner lap. This will require a longer tailpipe for the DST string and will also affect the eventual well kill. However, these are options that can be assessed in terms of risk and cost with the well test Petroleum Engineer.

EXAMPLE CASING DESIGN

10.4.3.3

Collapse Loads

10.4.3.3.1

Cementing

Pe: External Load

Page 56 of 66

= 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

Pc: Differential (Collapse) Load

Actual Design Factor

10.4.3.3.2

= (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 = 7,120/353 = 20.1

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

Pi: Internal Pressure

= 0psi (Air)

Design Factor

= 1.0

Pc: Differential (Collapse) Pressure

Actual Design Factor

= (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 = 7,120/5,949 = 1.19

EXAMPLE CASING DESIGN

10.4.4

Page 57 of 66

7in Liner

The 7in liner will be C-75, 35 lb/ft with the following minimum properties, as defined in API Bulletin 5 C2 and the New Vam data sheet:


Collapse Resistance

= 9,670psi




Internal Yield Pressure (Pipe)

= 9,340psi




Internal Yield Pressure (New Vam)

= 9,340psi




Body Yield Strength

= 763 x 10 lb




Joint Yield Strength (New Vam)

= 679 10 lb




Outer Diameter

= 7in




Nominal Inside Diameter

= 6.004in




Drift Diameter

= 5.879in

3

3

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 16.0ppg cement).

EXAMPLE CASING DESIGN

10.4.4.1

Tension Loads

10.4.4.1.1

Installation: Running

Page 58 of 66

Ft Total Load: Fwt – Fbuoy + Fbend + Fshock. Fwt: Dry Weight Fbuoy: Buoyancy (with 14.3ppg mud)

= 4,500 x 35 = 158,000 lb = Pe (Ao – Ai) 2 2 = 14.3 x 4,500 x 0.052 (( x 7 /4) – ( x 6.004 /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

Fshock: Shock Load

= 0 lb (Shock load not calculated)

Design Factor (no shock load correction)

= 1.6

Ft: Total Load

= Dry Weight + Buoyancy + Bending = (158,000 – 30,683 + 31,360) x 1.6 = 253,867 lb (This is < the 7in connection body yield, 679klb) SAFE

Actual Design Factor

= 679,000/158,677 = 4.28

10.4.4.1.2

Installation: Running and Overpull

Fop: Assume an overpull of 100,000 lb. Design Factor

= 1.4

Ft: Total Load

= = = =

Actual Design Factor

= 679,000/258,677 = 2.62

(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

EXAMPLE CASING DESIGN

10.4.4.1.3

Page 59 of 66

Plug Bump after Cement Displacement

Fplug: Plug bump to 2,000psi. Cemented up to the liner top at 7,500ft with a 16.0ppg cement slurry. Design Factor

= 1.4

Ft: Total Load

= Fwt – Fbuoy + Fbend + Fplug

Fbuoy

= (Pe x Ao) – (Pi x Ai) (Closed end pipe) 2 2 = Pe ( x 7 /4) – Pi ( x 6.004 /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 1.4 Design Factor = 211,056 lb (Casing connection yield strength is 679klb) SAFE

Actual Design Factor

= 679,000/150,754 = 4.50

10.4.4.1.4

Installation: Pretension after Waiting on Cement

Not applicable.

EXAMPLE CASING DESIGN

10.4.4.2

Burst Loads

10.4.4.2.1

Installation: Cement Displacement

Page 60 of 66

Psurf: Assume cement displacement pressure of 1,000psi. External volume to be cemented (12,000 to 7,500) Total cement pumped (with 20% excess) Equivalent height in 7in, 35 lb/ft casing

= (4,000 x 0.0226) + (500 x 0.0231) = 102bbl = 102 x 1.2 = 122bbl = =

122/0.035 3,486ft

Pe: External Pressure

= = =

Mud Hydrostatic 4,500 x 14.3 x 0.052 3,346psi

Pi: Internal Pressure

=

=

Cement Hydrostatic + Mud Hydrostatic + Displacement Pressure (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 (Burst) Pressure

= (4,654 – 3,346) = 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

EXAMPLE CASING DESIGN

10.4.4.2.2

Page 61 of 66

Installation: Plug Bump to 3,000psi

Pe: External Pressure

= = =

Cement Hydrostatic (4,500 x 16.0 x 0.052psi) 3,744psi

Pi: Internal Pressure

= = =

Mud Hydrostatic + Plug Bump (14.3 x 4,500 x 0.052) + 3,000 6,346psi

Design Factor

=

1.1

Pb: Differential

= = =

(6,346 – 3,744) 2,602 x 1.1 2,862.2psi (This is < the 7in body burst rating of 9,340psi) SAFE

= =

9,340/2,602 3.59

(Burst) Pressure Actual Design Factor

10.4.4.2.3

Drilling: Casing Pressure Test after WOC

Psurf: Pressure Test

=

2,500psi

Note: Based on a bottom hole pressure of 8,600psi at TD and using a gas gradient of 0.15psi/ft, the gas to surface load after the liner is installed would result in the following: Gas to Surface

Gas pressure at 7in liner top

= 8,600 – (12,000 x 0.15 ) = 8,600 – 1,800 = 6,800psi = 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 pressure at 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 a hydrostatic 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 7in liner top. Therefore the minimum pressure test required using the 14.3ppg mud is 7,925 to 5,577psi. This yields a minimum pressure test requirement of 2,348psi for drilling load cases. Therefore, pressure test the 7in liner lap and casing to 2,500psi with the 14.3ppg mud.

EXAMPLE CASING DESIGN

Page 62 of 66

However, we will need to check the liner also satisfies the DST/completion load case for an SITHP leak at surface, on top of the mud column during DST assuming the packer 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

Pi: Internal Pressure

= Mud Hydrostatic + Test Pressure = (14.3 x 12,000 x 0.052) + 2,500 = 11,423psi

Design Factor

= 1.1

Pb: Differential (Burst) Pressure

Actual Design Factor

= (11,423 – 6,115) = 5,308 x 1.1 = 5,939psi. (Internal yield pressure of 7in, C-75, 35 lb/ft casing is 9,340psi) SAFE = 9,340/5,308 = 1.76

Note: LOT test and kick tolerance are not required for the final string. However, if further drilling below the liner were ever considered, then the load cases must be calculated. Design Factor

= 1.1

Pb: Differential (Burst) Pressure

= (13,000 – 6,130) x 1.1 = 7,600psi SAFE

EXAMPLE CASING DESIGN

10.4.4.3

Collapse Loads

10.4.4.3.1

Cementing

Page 63 of 66

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

Pi: Internal Load

= Mud Hydrostatic = 12,000 x 14.3 x 0.052 = 8,923psi

Design Factor

= 1.0

Pc: Differential (Collapse) Load

Actual Design Factor

10.4.4.3.2

= (9,321 – 8,923) x 1.0 = 398psi (This is < the collapse resistance of the 7in C-75, 35 lb/ft casing, 9,670psi) SAFE = 9,670/398 = 24.30

Drilling: Full Evacuation Pressure

Pe: External Pressure

= Hydrostatic Pressure of mud used when cementing casing = 14.3 x 12,000 x 0.052 = 8,923psi

Pi: Internal Pressure

= 0psi (Air)

Design Factor

= 1.0

Pc: Differential (Collapse) Pressure

Actual Design Factor

= (8,923 – 0) x 1.0 = 8,923psi (This is < the collapse resistance of the 7in C-75, 35 lb/ft casing, 9,670psi) SAFE = 9,670/8,923 = 1.08

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 into consideration if it was not possible to obtain the liner to 6.0in special drift.

EXAMPLE CASING DESIGN

CASING/ LINER 20in, H-40, 94 lb/ft

13-3/8in, C-75, 72 lb/ft (Special Drift)

9-5/8in, C-90, 53.5 lb/ft (Special Drift)

LOAD CASE

Page 64 of 66

ACTUAL LOAD

CASING STRENGTH

ACTUAL DF

MINIMUM DF

Tension

Installation (Running)

272,894 lb

581,000 C

2.13

1.6

Collapse

Cementing (Stab-in)

110psi

520psi

4.70

1.0

Collapse

Full evacuation

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

Burst

Pressure test after 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 to 2,000psi

440,867 lb

1,558,000 lb C

3.53

1.4

Burst

Cement displacement

2,345psi

4,930psi C

2.10

1.1

Burst

Bump plug to 2,000psi

596psi

4,930psi C

8.27

1.1

Burst

Pressure test after WOC (2,000psi)

2,234psi

4,930psi C

2.20

1.1

Burst

LOT after drilling shoe

936psi

4,930psi C

5.26

1.1

Burst

100bbl kick from next shoe

1,293psi

4,930psi C

3.81

1.1

Collapse

Cementing

1,404psi

2,590psi

1.84

1.0

Collapse

Full evacuation

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

Tension

Bump plug to 2,000psi

464,667 lb

1,399,000 lb

3.00

1.4

EXAMPLE CASING DESIGN

CASING/ LINER 9-5/8in, C-90, 53.5 lb/ft (Special Drift)

7in, C-75, 35 lb/ft Liner (Special Drift)

LOAD CASE

Page 65 of 66

ACTUAL LOAD

CASING STRENGTH

ACTUAL DF

MINIMUM DF

Tension

Bump plug to 6,800psi

739,277 lb

1,399,000 lb

1.89

1.4

Tension

Pre-tension to 60klb

410,267 lb

1,399,000 lb

3.40

1.4

Burst

Cement displacement

1,906psi

8,920psi

4.68

1.1

Burst

Plug bump to 2,000psi

1,043psi

8,920psi

8.55

1.1

Burst

Plug bump to 6,800psi

5,843psi

8,920psi

1.52

Burst

Pressure test after WOC to 3,500psi

3,999psi

8,920psi

2.23

1.1

Burst

LOT after drilling shoe

2,205psi

8,920psi

4.04

1.1

Burst

100bbl gas kick from next shoe

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 on packer fluid at 10,000ft

6,280psi

8,920psi

1.42

1.1

Burst

7in Liner lap test at 7,500ft

2,341psi

8,920psi

3.81

1.1

Collapse

Cementing

353psi

7,120psi

20.1

1.0

Collapse

Full evacuation

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

Tension

Bump plug to 2,000psi

150,754 lb

679,000 lb C

4.50

1.4

EXAMPLE CASING DESIGN

CASING/ LINER 7in, C-75, 35 lb/ft Liner (Special Drift)

LOAD CASE

Page 66 of 66

ACTUAL LOAD

CASING STRENGTH

ACTUAL DF

MINIMUM DF

Burst

Cement displacement (1,000psi)

1,308psi

9,340psi

7.14

1.1

Burst

Bump plug to 3,000psi

2,602psi

9,340psi

3.59

1.1

Burst

Pressure test after WOC to 2,500psi

5,308psi

9,340psi

1.76

1.1

Collapse

Cementing

398psi

9,340psi

24.30

1.0

Collapse

Full evacuation

8,923psi

9,340psi

1.08

1.0

SECTION 11

Drilling and Production Operations

Ref: CDES 11

CASING DESIGN MANUAL

Issue: Feb 2000

REFERENCES

Page 1 of 5

TABLE OF CONTENTS 11.

REFERENCES....................................................................................................... 2

Page 2 of 5

REFERENCES

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 of Casing, 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 and Plain 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 Connections.

(10)

API:

RP-5C6. Welding Connections to Pipe.

(11)

API:

Bulletin 5C2. Performance Properties of Casing, Tubing and Drill Pipe.

(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 and Thread Inspection of Casing, Tubing and Line Pipe Threads.

(14)

ISO 10405:

Petroleum and Natural Gas Industries
Care and Use of Casing and Tubing.

(15)

ISO 10400:

Petroleum and Natural Gas Industries
Formulae and Calculations for Casing, Tubing, Drill Pipe and Line Pipe Properties.

(16)

ISO 11960:

Petroleum and Natural Gas Industries
Steel Pipes for Use As Casing or Tubing for Wells.

Procedures

for

Casing

and

Tubing

(17)

Institute of Petroleum – Model Code of Safe Practice Part 17 Well Control during the Drilling and Testing of High Pressure Offshore Wells.

(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-todate edition, prior to use.

Page 3 of 5

REFERENCES

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, England Tel +44 1462 453211 Fax +44 1462 457714 Web http://www.techstandards.co.uk Email [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, Second Edition.

(26)

Moore, Preston L

Drilling Practices Manual. 1974 and Second Edition 1986.

(27)

Economides, Michael J Watters Larry T, Dunn Norman Shari

Petroleum Well Construction, Wiley 1998.

(28)

Rabia H

Fundamentals of Casing Graham and Trotman.

(29)

Fraser Ken

Managing Drilling Operations. 1991 Elsevier Science Limited.

(30)

Selley, Richard C

Elements of Freeman.

(31)

Adams, Neal

Well Control Problems and Solutions. 1980 Petroleum 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 of Materials and Mechanics of Solids. Pitman.

Petroleum

Design.

Geology.

1987

1985

REFERENCES

(36)

Page 4 of 5

SPE Papers. The web address for the Society of Petroleum Engineers is: http://www.spe.org

PAPER NUMBER

AUTHOR(S)

TITLE

29232

Patillo PD, Moschovidis ZA, Manohar Lal

An Evaluation of Concentric Non-uniform Load Applications

28710

Rocha LA, Bourgoyne AT

A Simple Method to Estimate Fracture Pressure Gradient

51188

Abbassian F and Parfitt SHL

A Simple Model for Collapse and Post-collapse Behaviour of Tubulars With Application to Perforated and Slotted Liners

26738

Oudeman P and Bacarezza LJ

Field Trial Results of Annular Pressure Behaviour in a High Pressure/High Temperature Well

25694

Halal AS and Mitchell RF

Casing Design for Trapped Annular Pressure Buildup

23923

Marshall DW, Hitoshi Asahi and Masakatsu Ueno

Revised Casing Design Criteria for Exploration Wells Containing H2S

36447

Adams AJ and Hodgson T

Calibration of Casing/Tubing Design Criteria by Use of Structural Reliability Techniques

29462

Mitchell RF

Effects of Well Deviation on Helical Buckling

20900

Krus H and Prieur J-M

High Pressure Well Design

19991

Redmann KP

Understanding Kick Tolerance and its Significance in Drilling Planning and Execution

22217

Wessel M and Tarr BA

Underground Flow Well Control: The Key to Drilling Low-Kick-Tolerance Wells Safely and Economically

20909

Walters JV

Internal Blowouts, Cratering, Casing Setting Depths, and the Location of Subsurface Safety Valves

21908

Payne ML, Asbill WT, Davis HL and Pattillo PD

Joint Industry Qualification Test Program for High-Clearance Casing Connections

Casing

for

REFERENCES

Page 5 of 5

PAPER NUMBER

AUTHOR(S)

TITLE

18776

Maruyama K, Tsuru E, Ogasawara Y and EJ Peters

An Experimental Study of Casing Performance Under Thermal Cycling Conditions

13431

Hackney RM

A New Approach to Casing Design for Salt Formations

28327

Kuriyami Y

A New Formula for Elasto-Plastic Collapse Strength of Thick Walled Casing

22547

Pascay PR and Cernocky EP

Bending Stress Magnification in Constant Curvature Doglegs with Impact on Drillstring and Casing

12361

Klementich EF and Jellison MJ

A Service Life Model for Casing Strings

20328

Klementich EF and Jellison MJ

An Expert System for Casing String Design