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 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.
INTRODUCTION
1.1 GENERAL
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.
1.4 READERSHIP This document is aimed at:
Drilling Engineers involved in designing and planning Repsol’s wells
Other disciplines who may be involved in these activities
It will acquaint the new engineer with the various aspects of casing design. It 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
1.7 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 CASING MATERIAL AND PROPERTIES Page 1 of 38
TABLE OF CONTENTS
2. CASING MATERIAL AND PROPERTIES ... 3
2.1 SPECIFICATION FOR CASING (API 5CT)... 3
2.1.1 Outside Diameter (OD) (in)... 3
2.1.2 Nominal Unit Weight (lb/ft)... 3
2.1.3 API Steel Grades... 5
2.1.4 Connection Types... 6
2.1.4.1 API Connections ... 6
2.1.4.2 Non-API Connections ... 7
2.1.4.3 Large Diameter Connections ... 7
2.1.4.4 Connector Assessment... 8 2.1.5 Range Length ... 8 2.1.6 Manufacturing Process ... 9 2.1.7 Inspection ... 10 2.1.7.1 Defects/Imperfections ... 10 2.1.7.2 Pipe Inspection ... 11
2.2 ENGINEERING DEFINITIONS, METALLURGY AND PROPERTIES ... 15
2.2.1 Engineering Definitions... 15
2.2.2 Steel and Steel Alloys... 21
2.2.2.1 Steel Phases ... 21
2.2.3 Codes and Standards ... 24
2.2.3.1 API Codes – General Application... 25
2.2.3.2 National Association of Corrosion Engineers (NACE Standard MR0175-99) ... 26
2.2.3.3 Institute of Petroleum ... 27
2.2.3.4 ASME/ASTM/ANSI ... 27
2.2.3.5 International Standard Organisation (ISO) ... 27
2.2.3.6 Committee for European Normalisation (CEN)... 28
2.2.4 Non-API Casing Grades/Special Materials ... 29
2.2.4.1 Sour Service ... 29
2.2.4.2 Carbon Dioxide Service ... 30
2.2.4.3 Carbon Dioxide/Mixed Corrosive Environments ... 31
2.2.4.4 High Strength... 33
2.2.4.5 High Collapse ... 33
2.2.5 Temperature Effects on Metallic Properties ... 34
2.2.5.1 High Temperature ... 34
2.2.5.2 Arctic (Low) Temperatures... 34
2.2.6 Effects of Gases on Materials... 35
2.2.6.1 Hydrogen Sulphide ... 35
2.2.6.2 Hydrogen Embrittlement ... 35
2.2.6.3 Hydrogen Induced Cracking... 35
2.2.6.4 Sulphide Stress Cracking... 35
2.2.6.5 Carbon Dioxide ... 36
2.2.7 Effects of Liquids on Materials... 36
2.2.7.1 Chlorides/Bromides... 36
2.2.8 Corrosion... 36
2.2.8.1 Corrosive Parameters ... 36
2.
CASING MATERIAL AND PROPERTIES
2.1 SPECIFICATION FOR CASING (API 5CT)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.
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.
2.1.3 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 YIELD STRENGTH (PSI)
GROUP GRADE GRADE MINIMUM MAXIMUM MIN TENSILE STRENGTH (psi) 1 H-40 40000 80000 60000 1 J-55 55000 80000 75000 1 K-55 55000 80000 95000 1 N-80 80000 110000 100000 2 L-80 80000 95000 95000 2 C-90 90000 105000 100000 2 C-95 95000 110000 105000 2 T-95 95000 110000 105000 3 P-110 110000 140000 125000 4 Q-125 125000 150000 135000
2.1.4 Connection Types
Individual joints of casing are connected together by a threaded connection. These connections are classified as: API, premium or proprietary (gastight and metal-to-metal seal).
For many years API thread connections, with or without a resilient seal ring, have 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
Figure 2.1 - Thread Forms
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
B O X PIN STAB FLANKS LOAD FLANKS API BUTTRESS API 8- ROUND B O X PIN PIN B O X M E T A L - T O - M E T A L S E A L
2.1.4.2 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
2.1.4.3.2 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
Total Range Length (ft) 16 to 25 25 to 34 34 to 48
Permissible Variation, max 6 5 6
Permissible Length, min 18 28 36
2.1.6 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
Figure 2.4 - Hot Rolling
B I L L E T P I E R C E R
Figure 2.5 - Welded (Seamed) Pipe Manufacture
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
C U R R E N T E L E C T R O D E S S K E L P ( P L A T E ) F R O M R E E L A F T E R F O R M I N G W E L D I N G FINISHED T U B E
2.1.7.2 Pipe Inspection
API 5CT also includes the following issues for pipe inspection:
Non-destructive inspection of pipe body
Non-destructive inspection of weld seam
Ultrasonic or electromagnetic inspection of pipe body
Magnetic particle inspection of the pipe body
Disposition of inspection indications and additional inspection requirements 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.
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 full-length 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.
2.1.7.2.2 Measuring Dimensions
a. Ultrasonic Wall Thickness Measurement (UWTM)
Ultrasonic techniques have the advantage of being able to find flaws in thick walled pipe. The technique does not require magnetisation and so works well on non-magnetic 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.
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 small-localised 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
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.
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%,
Figure 2.6 - Elongation Strain and Shear Strain L1 ZZ26323.056 L2 Original Length Deformed Length dL Elongation Strain = = L2 - L1 L1 dL L1 = A 3 Original Angle Deformed Angle Shear strain =
xy =/
2 BFigure 2.7 - Stress/Strain Relationship in Casing Material
B rittle Zone D uctile Zone
E lastic D eform ation
P lastic H ardening P lastic S oftening
P erm anent D eform ation E lastic lim it (onset of yielding) U ltim ate Tensile S trength N o m in a l s tr e s s ( bas ed on or ig in al di m e n s io n s ) Total S train i. Ductility
Ductility is the ability to sustain appreciable plastic deformation without rupture. A ductile material can flow, stretch, change its permanent form and remain in 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 directions. A value of 30 x 106psi 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.
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)
AP I Yield Strength N om inal Stress, Strain, 0.5%
Ideal elastic/plastic behaviour, valid up to 95,000 psiAPI 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.
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 ) d d ( 64 I 4 i 4 o
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
A value of 6.9 x 10-6/F is usually taken for tubular steel. r. Volume Thermal Expansion (CT)
Volume thermal expansivity of a fluid is the expansion per unit of original 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.
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 face-centred cubic crystallographic structure. In steels, the solute is generally carbon. Austenite is not generally stable at room temperature, in plain carbon steels, it is not stable below 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.
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.
f. 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.
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)
2.2.3.1 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.
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’.
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.
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
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-manganese-chromium-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.
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.
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 nickel-chromium 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.
‘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* <0.05 to 0.10 0.20 to 1.00 11.5 to 14.0 0.50 to 3.00 3.00 to 5.00
* Controlled nitrogen contents are usual.
Part 2: Duplex Stainless Steels and Super-austenitic Alloys
Duplex stainless steels are used in either the solution annealed or the annealed and cold-worked condition. These steels are not hardenable by heat-treatment, but require the application of cold work to strengthen them. Common varieties are:
22% Cr 5% Ni 3% MO 25% Cr 6% Ni 3% Mo
These steels are used for resistance to carbon dioxide in higher concentrations or at higher temperatures. They will tolerate small concentrations of hydrogen sulphide; the solution annealed condition being more resistant to sour conditions.
Super-austenitic alloys are nickel-chromium alloys and are used in the solution annealed and cold-worked conditions. The alloys are very resistant to carbon dioxide and hydrogen sulphide at high temperatures and pressures. They can be supplied in high strength grades up to 140ksi specified minimum yield strength.
Table 2.5 - Steels and Alloys used for OCTG
The steel and alloy compositions given here are indicative and do not constitute specifications. Only the principal alloying elements are quoted.
STEEL TYPE CARBON MANGANESE CHROMIUM MOLYBDENUM NICKEL
Duplex Stainless, 22% Cr* 0.03% max 2.00% max 21.0 to 23.0 2.50 to 3.50 4.50 to 6.50 Duplex Stainless, 25% Cr* 0.03% max 2.00% max 24.0 to 26.0 2.50 to 4.00 4.50 to 7.50 Super-austenitic, 28% Cr* 0.03% max 2.00% max 26.0 to 29.0 3.00 to 4.50 29.0 to 32.0
* Controlled Nitrogen contents are usual.
2.2.4.4 High Strength
Material selection for high strength casing has an influence for example on HPHT applications.
Where higher strength casing is required, manufacturers provide proprietary grades as well as API 5CT Q125. Proprietary grade QR-125 has a restricted yield strength range, which makes this high strength casing compatible with NACE requirements and suitable for sour service at temperatures above 80C.
For higher strengths a manufacturer grade XT-155 has a high minimum yield strength (155ksi) combined with good low temperature toughness.
2.2.4.5 High Collapse
High collapse service materials may be required in environments where movement of formations, such as salt sequences are anticipated.
Carbon manganese steels in the quenched and tempered condition are commonly used to produce API Specification 5CT grades C95 and HC110. The collapse performance of these grades has been established by statistical treatment of collapse data from a wide range of sources and defines the minimum performance that can be expected from any pipe meeting API minimum properties. Manufacturers produce high collapse grades with 95 and 110ksi minimum yield strength ranges that are guaranteed to have higher collapse properties than API standard products, typically 15% to 30% higher. Careful management of the important factors affecting collapse ratings achieves this improved performance. Pipe ovality and thickness are controlled to limits specified in internal specifications drawn up after a comprehensive research programme; residual stresses are kept to a minimum by hot straightening.
The potential for collapse improvement depends on the pipe D/t ratio and for some sizes the increase is not significant. Table 2.6 below from TISL provides a representative sample of HC95 and HC110 collapse performance properties for various sizes.
Table 2.6 - TISL Comparison for High Collapse Versus API Casing Grades DIAMETER (in) WEIGHT (lb/ft) API C95 COLLAPSE RATING (psi) HC95 COLLAPSE RATING (psi) API P110 COLLAPSE RATING (psi) HC110 COLLAPSE RATING (psi) 7 29 7,840 10,480 8,530 10,800 9-5/8 47 5,090 7,420 5,300 7,490 9-5/8 53.5 7,340 10,050 7,950 10,240 13-3/8 68 2,340 3,160 2,330 3,160 13-3/8 72 2,830 3,900 2,880 3,900
2.2.5 Temperature Effects on Metallic Properties 2.2.5.1 High Temperature
For low alloy steels up to and including Q125, a recommended yield strength temperature de-rating factor of 0.03% per F with de-rating starting at 68F. This is generally recognised as a guide for de-rating the yield strength of a material and corresponds to a 9.72% reduction in yield strength at 200C (392F).
For CRA, particularly duplex stainless steel, temperature effects can be considerably greater and should be taken into consideration.
Temperature has an influence improving the resistance of certain materials to sulphide stress cracking (SSC) by allowing the absorbed hydrogen to diffuse out of the material and form molecular hydrogen at a higher rate. Higher temperature generally causes corrosion rates to increase and result in an increase risk to SCC.
2.2.5.2 Arctic (Low) Temperatures
Low temperature environments have the effect of changing the metallurgy of a material in a number of ways. Lower temperatures change the internal molecular structure so that it does not allow the internal stresses to release, resulting in a harder more brittle material. Impact resistance is therefore reduced and failure can occur from shock load, localised flaws or even scratches.
Pipe manufacturers produce casing materials that are all quenched and tempered and feature high tensile strength as well as good ductility at low temperature.