bp guide to material selection.pdf

7/21/2019 BP Guide to Material Selection.pdf

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Guidelines

for SelectingDownhole TubularMaterials forOil & GasProduction Wells(2000 Edition)

J W MartinMajor contributors: D Harrop, W Hedges

Sunbury Report No. S/UTG/023/00

dated February 2000


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S/UTG/023/00 Contents

CONTENTS

1. INTRODUCTION 2

2. BACKGROUND INFORMATION ON CORROSION ASPECTS. 3

3. INFORMATION REQUIRED TO ALLOW THE MATERIALS SELECTION TO BEUNDERTAKEN. 5

4. USE OF MATERIALS SELECTION ROAD MAPS 7

5. QUESTIONS TO BE ASKED OF PROSPECTIVE SUPPLIERS. 11

6. PROPOSALS FOR TESTING CANDIDATE MATERIALS VIA REFERENCEDTEST PROTOCOLS. 12

APPENDIX A : GENERAL CORROSION RESISTANCE 13

APPENDIX B : CORROSION RESISTANCE OF CORROSION RESISTANTALLOYS 40

APPENDIX C : WHAT IS THE DEFINITION OF A "SOUR ENVIRONMENT"? 50

APPENDIX D : SULPHIDE STRESS CRACKING 52

APPENDIX E : WHAT OTHER FACTORS NEED TO BE CONSIDERED? 58


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S/UTG/023/00 Introduction

1. INTRODUCTION

Material selection of downhole tubulars is an important aspect of completion design. If the wrongmaterial is selected then premature failure can result, with considerable cost implications in bothreplacing the tubulars and lost production.

The purpose of this document is to provide clear guidance that can be used by engineers tocarry out a first stage evaluation of the material requirements for the downhole tubulars. Theguidelines cover all aspects of corrosion and stress corrosion resistance, including sulphide

stress cracking in sour environments. Where the guidelines are unable to give unequivocalrecommendations on the material to be selected, test protocols are referenced which will allowthe choice of the optimum material for the intended duty.

Guidance is given on:

(a) The information required to allow the assessment to be undertaken.

(b) Materials selection for downhole tubulars, by the application of flow charts (roadmaps) with references back to the text where necessary.

(c) Questions to be asked of prospective suppliers.

(d) Proposals for testing alternative materials via referenced test protocols


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S/UTG/023/00 Background Information on Corrosion Aspects

2. BACKGROUND INFORMATION ON CORROSION ASPECTS.

Background information on the various corrosion aspects relevant to the selection of materialsfor downhole tubulars is contained in the Appendices. The subject matter of the appendices isas follows:

Appendix A. Corrosion resistance of carbon/low alloy steels.

This appendix describes how the CO2corrosion rate for carbon/low-alloy steel can be

estimated. A method for deciding whether the predicted corrosion rate will result in anacceptable service life for carbon/low-alloy steel is indicated. Advice is given on what to do ifthe corrosion rate estimates indicate that carbon/low-alloy steel would not give an adequatelife.

This appendix also includes a discussion on the use of downhole corrosion inhibitionprogrammes as a means of utilising carbon/low-alloy steel tubulars under corrosive conditionswhere they would otherwise give an inadequate service life.

Appendix B. Corrosion resistance of corrosion resistant alloys (CRAs).

In this appendix the general and localised corrosion resistance of corrosion resistant alloys isconsidered, particularly at the elevated temperatures often experienced downhole.

One of the most important aspects to be considered in selecting the right corrosion-resistantalloy (CRA) for the intended application is the material's resistance to localised corrosion. Thetwo forms of localised corrosion of most relevance to downhole tubulars are pitting and

crevice corrosion. These aspects are considered in the appendix, with advice given on theupper temperature limits for CRAs to avoid pitting corrosion and how to avoid crevicecorrosion.

Of the CRAs more commonly used for downhole tubulars, stress corrosion cracking is mainlya concern with austenitic and duplex stainless steels. The mechanisms are discussed in theappendix, together with advice on the application limits for the alloys to avoid stress corrosioncracking in service.

Appendix C. What is the definition of a sour environment?

This appendix gives advice on how to determine if the service conditions should be consideredas "sour". This is based upon the definition of NACE Standard MR-0175 Standard MaterialRequirements - Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment.

Appendix D Sulphide Stress Cracking


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S/UTG/023/00 Background Information on Corrosion Aspects

addition, the testing solution used in assessing the acceptability of materials for sour service in

NACE is very severe (1 bar H2S, pH 2.8), meaning that the standard is very conservativeregarding which materials are acceptable for hydrogen sulphide service. Finally, there isinsufficient information in the NACE standard regarding the operating limits of manycorrosion-resistant alloys. Therefore, BP developed a methodology based upon laboratory testresults and some limited field experience, to allow the user to select the correct material forthe intended service. This methodology is discussed in the appendix.

Appendix E. What other factors need to be considered?

This appendix covers the issues of:

Mechanical Properties - limits on the maximum strength of materials to be used in sourconditions are discussed, as are the effects of elevated temperature on the material strengthand isotropy in the cold worked duplex stainless steels.

Flow-Induced Damage - Erosion and Erosion-Corrosion - mechanisms of erosion anderosion-corrosion are discussed, together with how to avoid and/or account for such attack in

downhole tubulars.

Galvanic Corrosion - the mechanism of galvanic corrosion is discussed, together with how toavoid it in completion design.


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S/UTG/023/00 Information Required

3. INFORMATION REQUIRED TO ALLOW THE MATERIALS SELECTION TO

BE UNDERTAKEN.

A significant amount of information is required to fully establish the materials requirements fordownhole tubulars. However it is realised that, especially at the concept stage, the full suite ofrequired information may not be available. Therefore in the following listings two types of datahave been highlighted:

The minimum requirements to enable initial materials selection.This enables initial

materials selection for conceptual studies, order of magnitude estimates, etc.

Information required for final materials selection.This is required before preparing a finalspecification for the downhole tubulars.

(1) Minimum Information Required

The design life in years

The type of well (i.e. whether oil or gas)

The partial pressure of H2S and CO2in the gas phase

The operating and design temperatures/pressures (bottom hole, well head flowing/shut-in)

The bubble point pressure (i.e. for oil wells). Knowledge of this value is highly desireablebut not absolutely essential

The water composition (as complete as possible, but the levels of water salinity,bicarbonate and organic acids as a minimum, to enable the in-situ pH to be estimated)

The material strength requirements

(2) Information Required for Final Materials Selection

The design life in years

The type of well (whether oil or gas)

The partial pressure of CO2and H2S in a gas in equilibrium with the fluids (requiresknowledge of the bubble point pressure for oil wells)

The operating and design pressures/temperatures (bottom hole well head flowing/shut-in)


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S/UTG/023/00 Information Required

Predicted water cuts

Predicted changes in the field condition during service life of tubulars

Required material strength, pipe size, connection type.

Lowest ambient temperature (can be important when handling downhole equipment incold climes)


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S/UTG/023/00 Use of Materials Selection Road Maps

4. USE OF MATERIALS SELECTION ROAD MAPS

Three road maps have been developed for the selection of the optimum downhole tubularmaterial. These are:

(a) Materials Selection for Sweet Conditions- This should be used for well conditionswhere there is nohydrogen sulphide present, or where only very low levels of hydrogensulphide are anticipated such that the conditions would not be considered sour (refer toAppendix C for definitions of sour service).

(b) Materials Selection for Sour Conditions (Carbon/Low Alloy Steels)- This should beused for sour conditions where the well fluid corrosivity is such that carbon/low alloy steelsare considered suitable (refer to Appendix A regards well fluid corrosivity).

(c) Materials Selection for Sour Conditions (Corrosion Resistant Alloys)- This should beused for sour conditions where the well fluid corrosivity is such that carbon/low alloy steelsare notconsidered suitable.

The intention is that the Road Maps should be used in conjunction with these Guidelines.They are not designed as stand alone documents.

Items dealt with in the Guidelines but noton the Road Maps that need to be considered in thematerials selection process for downhole tubulars include:

Use of carbon steel plus corrosion inhibition (Appendix A, Section 2)

Localised corrosion resistance of corrosion resistant alloys (Appendix B, Section 2)

Stress Corrosion Cracking of corrosion resistant alloys (Appendix B, Section 3)

Mechanical properties (Appendix E, Section 1)

Erosion and erosion-corrosion resistance (Appendix E, Section 2)

Galvanic Corrosion (Appendix E, Section 3)

It is not intended that the Road Maps/Guidelines should be all encompassing. The intentionis rather to flag the major considerations that need to be made in selecting downhole tubularmaterials. With the very complex issues involved it is possible that there will be omissions.Therefore it is incumbent upon the user of these Guidelines to ensure that all necessary aspectsof materials selection have been addressed before the final specification of materials.


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S/UTG/023/00 Use of Materials Selection Road Maps

February 2000 Page 9

MATERIALS SELECTION FOR TUBULARS - SOUR CONDITIONS- CARBON/LOW ALLOY STEELS

KNOWN DATA

THE CONDITIONS ARE SOUR WITHIN THE DEFINITIONS OF NACE MR-0175CARBON/LOW ALLOY STEEL HAS ADEQUATE CO2CORROSION RESISTANCE (SEE CHART I)

REQUIRED TUBULAR STRENGTHIN-SITU pH AND pH2S

OPERATING & DESIGN TEMPERATURES

Is the

use of NACE MR-0175

a statutory requirement

for this

area?

Yes No

What is

the MINIMUM

exposuretemperature?

Consider use of the

BP Amoco Methodology

Alternatively can use NACE MR-0175

Apply Requirements

of NACE MR-0175

=>65oC 80oC

=>107oC

Consideration can also be

given to using N80(Q+T),

C95 or proprietary Q+Tgrades with a MAXIMUM

yield strength of 110ksi1

Consideration can also be

given to using Q1251,2

Notes.

1. If temperatures below this minimum are expected, even for shortperiods of time,then the higher temperature limit criteria for non-sour

grades should not be used.

2. Regardless of the requirements for the current edition of API Spec. 5CT,

the Q125 grades shall always (1) have a maximum yield strength of 150ksi;

(2) be quenched and tempered; (3) be an alloy based on Cr-Mo chemistry(the C-Mn alloy chemistry is not acceptable).

3. For H40 material in sour conditions at temperatures less than 80oC

the maximum permissible yield strength is 80ksi

Consideration can also begiven to using H40, N80,

P110 or proprietary Q+T

grades with a MAXIMUM

yield strength of 140ksi1

What is

the requiredmaterial strength?

=95ksi

Consider API 5CT GradesH403; J55; K55; L80 (Type 1)

C90 (Type 1); T95 (Type 1)

Consideration can be givento using proprietary sour

resistant grades up to

110ksi SMYS(Consult relevant specialists)

Establish required material

strength and downhole

pH and pH2S

Refer to Domain Diagram for thematerial with adequate strength. If

no material with suitable pH/pH2S

resistance can be identifiedapply requirements of

NACE MR-0175

6.5

5.5

4.5

3.5

0.001 0.01 0.1 1.0 10

Solution

pH

pH2S (bara)

Acceptable

Unacceptable

Sulphide Stress Cracking Performance Domain ofSour Resistant Grade 110ksi Steel

6.5

5.5

4.5

3.5

0.001 0.01 0.1 1.0 10

Solution

pH

pH2S (bara)

Acceptable

Unacceptable

Sulphide Stress Cracking Performance Domain ofGrade P110 Carbon Steel

6.5

5.5

4.5

3.5

0.001 0.01 0.1 1.0 10

Solution

pH

pH2S (bara)

Acceptable

Unacceptable

Sulphide Stress Cracking Performance Domain ofGrade N80 Carbon Steel

0.003

0.0030.003


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S/UTG/023/00 Questions to be asked of Prospective Suppliers

5. QUESTIONS TO BE ASKED OF PROSPECTIVE SUPPLIERS.

In certain circumstances, for example if there is no 'standard' material that is suitable for theintended duty, it may be necessary to consider the use of a 'proprietary' material outside thescope of these Guidelines. In such circumstances there are a number of questions that the

prospective supplier should be asked to ascertain whether the proposed material may besuitable for the intended duty. These include:

(a) Will the proposed material have adequate resistance to corrosion wastage, principally

general corrosion, pitting corrosion and crevice corrosion, under the anticipated serviceconditions?

(b) Will the material have adequate resistance to sulphide stress cracking under all conditionslikely to be experienced during service?

(c) Will the material have an adequate combination of material strength and toughness underthe range of temperatures likely to be experienced? Is there any isotropy of the mechanical

properties in the material that need to be accounted for during completion design? Will the

material experience any loss of strength at the highest temperature anticipated in service? If so,by how much?

(d) Is the material prone to stress corrosion cracking in the downhole environment (e.g. as aresult of chlorides)? If so, will it have adequate resistance under the expected serviceconditions? (NB Remember to consider the issues for both the produced fluids and completion

brine environments, where appropriate)

(e) Is the proposed material compatible with other materials likely to be used downhole withrespect to galvanic corrosion? If not, what precautions will need to be taken?

(f) Has the material sufficient resistance to erosion and erosion-corrosion under the prevailingconditions?


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S/UTG/023/00 Proposals for Testing Candidate Materials

6. PROPOSALS FOR TESTING CANDIDATE MATERIALS VIA REFERENCED

TEST PROTOCOLS.

In certain circumstances, for example if there is no 'standard' material that is clearly suitable forthe intended duty, it may be necessary to consider carrying out laboratory corrosion tests toselect the optimum material for the intended application. Aspects that need to be considered inthese corrosion tests, together with references to the preferred test protocols are as follows:

(a) Resistance to sulphide stress cracking.

A protocol has been developed based upon NACE TM-0177 smooth tensile tests, togetherwith constant extension rate tensile (CERT) and double cantilever beam (DCB) tests ifnecessary. This is detailed in a separate Sunbury Report1.

An alternative simplified protocol is outlined in Appendix D.

(b) Resistance to stress corrosion cracking.

It is only necessary to consider other stress corrosion cracking issues for the corrosion-resistant alloys, in particular the duplex and austenitic alloys. A testing protocol is outlined inAppendix B.

(c) Resistance to general and pitting corrosion.

The resistance to general and/or pitting corrosion shall be determined using an "immersioncorrosion test". A testing protocol is outlined in Appendix B.


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S/UTG/023/00 Appendix A

APPENDIX A : GENERAL CORROSION RESISTANCE

1. CO2Corrosion

CO2corrosion, or sweet corrosion, is the most prevalent form of attack associated with oiland gas production and its understanding, prediction and control are key requirements tosound design and subsequent assurance of operational integrity. The form of attack is oftenlocalised - frequently referred to as Mesa attack - and, together with dissolved CO2contentand temperature, is affected by flow, water chemistry, steel composition and the exposure to

mechanical damage of the surface corrosion scales often formed.

Several models are available to predict the CO2corrosion rate for carbon and low alloy steels.Of these the most commonly used is that of de Waard (Shell) et alwhich is empirical in originalthough its general applicability has been confirmed by test work in several independentlaboratories including BP Amoco, Sunbury. The basic equation relates corrosion rate to the

partial pressure of CO2(PCO2), and temperature (T) with correction factors for pH andformation of iron carbonate scale - both factors being affected by [HCO3

-] (the concentrationof bicarbonate ions), PCO2and T. The influence of flow - as mass transfer is a component in

the overall CO2corrosion reaction - has been factored into the latest version of the de Waardmodel on a semi-empirical basis. Correlation with field data generally shows the de Waardmodel usually provides an acceptable prediction of the worst case situation.

The BP Amoco Corrosion Prediction Modelling guidelines2use the latest versions of the deWaard model adapted to include BPs experience and philosophy for application. Theseguidelines provide a comprehensive approach to determining CO2corrosion rate and theapplication to detailed design.

No such models exist for Corrosion Resistant Alloys. However, standard grade 13% Cr doesexhibits a CO2corrosion rate, albeit much lower than for carbon steel. Limited laboratorywork at BP Amoco, Sunbury(2)found that for a given set of conditions multiplying the

predicted CO2corrosion for carbon steel by 0.0016 gave a reasonable estimate of that for 13%Cr. Further information on the estimation of CO2corrosion rates for 13%Cr steel is given inAppendix B of these Guidelines. Duplex stainless steels and higher alloys are highly resistantto purely CO2corrosion and as such this is not a consideration in itself in determining thesuitability of these alloys. Chloride content, temperature, pH and presence of H2S are the key

factors which determine their acceptability where susceptibility to pitting corrosion and/orcracking are the primary concerns (see Appendices B and D for further information).

There are no available CO2corrosion models able to take direct account of the affect of H2S ifpresent- other than the small affect on pH. The presence of H2S may cause the models to overpredict the corrosion rate due to the presence of a highly protective FeS surface film.However this sulphide film can be susceptible to localised breakdown leading to severe pitting


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little as 10 ppm acetic acid can present a problem and Specialist Advice should be sought

where acetic acid is present.

Finally the presence of erosion, leading to erosion-corrosion, needs to be determined as undercertain conditions the CO2corrosion rate is moderated by the presence of an iron carbonatecorrosion scale. If erosion is an issue this may lead to under prediction of the associated CO2corrosion rate when simply applying the BP Amoco Guidelines(2). Erosion and erosion-corrosion are addressed in Appendix E of these Guidelines.

2. Materials selection for sweet conditions Road Map

The Materials Selection for Sweet Conditions Road Map is given in Section 4 of theseGuidelines. This is based primarily on consideration of the CO2corrosion rate, but also takesaccount of other key factors which will affect materials selection.

2.1. Use of the Road Map

The following text gives guidance on the use of the Road Map. The section headings in bold

lettersrefer to the various Information (indicated by a) or Decision (indicated by a

) boxeson the Road Map.

Input

The primary inputs are temperature (T in oC) and partial pressure of CO2(PCO2in bara)defined as:

PCO2= (mole % CO2x Ptotal)/100.

The worst downhole conditions (upper limit) will be at the Bubble Point which definesthe maximum amount of dissolved CO2and hence the maximum PCO2in terms of CO2corrosion rate. If the Bubble Point is not known the default should be the bottomholeflowing or reservoir conditions - a conservative position. The lower limit will bedetermined by the wellhead flowing conditions.

In situpH?

For corrosion to occur free water must be present at the pipe wall. For a gas welloperating above the dew point corrosion should not be a concern. For oil wells thewater cut and flow regime will be critical to determining if the pipewall is water-wetted. A complicating factor for oil / water systems is the emulsion tendency of thecrude oil. For fully mixed flowing conditions the resulting emulsion will be water-in-oil at low water cuts inverting to oil-in-water at high water cuts. The inversion point


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It is important to know the in situpH at temperature and pressure. If a produced

water analysis is available this may well give a measured pH; however, care should betaken to check that this is at temperature and pressure and not for the water after thedissolved gases have been flashed off.

The pH Isoplots (in the absence of H2S - see next section for the case where H2S ispresent) enable a ready estimate of what the in situpH will be for a given T (up to120oC - the limit of the pH model used) and PCO2. For gas wells with no production offormation water the condensed water Isoplot should be used. For oil wells the otherIsoplots should be used which consider the affect of water salinity (at 3.5% and 10%)and the presence of bicarbonate (50 to 1600 ppm which provides pH buffering) on pH.If the produced water composition is not known then guidance from a ProductionChemist should be sought. If this is not immediately available then as an interim

position 10% brine with 50 ppm and 400 ppm bicarbonate should be considered.

It is also important to know if acetic acid is present in the water, something that is notalways analysed for: care also needs to be exercised in how acetic acid is measured inthe presence of bicarbonate Acetic acid can suppress the formation of potentially

protective iron carbonate scales (discussed later) and will affect the in situpH. ThepH affect is not considered in the pH Isoplots and for any significant levels of aceticacid present - in the range 10 to 100 ppm - a more exacting calculation of pH should

be undertaken. This is an area still not well understood and is still being researched todevelop better guidelines.

H2S Present?

A primary concern with the presence of H2S is susceptibility to Sulphide Stress

Cracking (SSC) and this is addressed in Appendix D.

For metal loss corrosion effected primarily by CO2the presence of H2S, being and acidgas, will affect the pH which in turn will affect corrosion rate. However, the effect on

pH is usually small. It is not possible to give generalised guidelines, and no corrosionmodel exists which accounts for CO2+ H2S metal loss corrosion, but in conjunctionwith the pH Isoplots the following may be applied in their use when H2S is present.

PH2S(bar) PCO2(bara) below whichthe pH Isoplot is affectedby H2S

0.0001 Not affected

0.001 0.01


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Once the pH has been fixed the CO2Corrosion Isoplots can be consulted subsequent

to satisfying the remaining questions in the Road Map. For many cases where H2S ispresent a protective iron sulphide film is readily formed often leading in practice tovery low corrosion rates below those given in CO2Corrosion Isoplots. However,should this protective film breakdown highly localised corrosion can result at rates atleast equal to those given in the Corrosion Isoplots: the risk will be greater whereerosion is a concern. Consequently, designing on the basis of achieving protectionfrom formation of an iron sulphide film is notrecommended. Furthermore, subsequentinspection and corrosion monitoring should pay particular attention to the possibility of

pitting corrosion being present.

Solids Present?

Here the principal concern is erosion-corrosion. Pure erosion provides a source ofmetal wastage that will be at least additive to that due to the CO2corrosion. AppendixE provides guidelines for limiting the erosion rate to 0.1 mm/yr. It is considered thatas long as the rate of erosion can be limited to 0.1mm/yr or less then the risks ofunacceptable levels of erosion or of synergistic erosion-corrosion are acceptably low.

Carbon/Low Alloy steels

The presence / stability of a protective surface corrosion scale - iron carbonate- on carbon and low alloy steels will be affected by erosion. A stable ironcarbonate scale forms when a critical temperature, Tscale, is exceeded for agiven PCO2. The CO2corrosion model used to generate the Corrosion Isoplotstreats the influence of protective corrosion scale as being a limiting effect oncorrosion rate ie. for all temperatures > Tscalethe corrosion rate is equal to that

at Tscale. The following graph shows how Tscalevaries with PCO2.

90

110

130

150

170

190

210

230


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As mentioned previously the presence of acetic acid can suppress the formation

of iron carbonate scales and /or maybe raise Tscaleto a value higher than thatgiven above.

Erosion studies at Tulsa University have shown that where a protective ironcarbonate scale is formed but becomes damaged due to erosion rapid, highlylocalised corrosion can result. Therefore if the erosion rate is > 0.1 mm/yand the temperature is > TscaleSpecialist Advice should be sought.

13%Cr Stainless Steel

Erosion, where the predicted rate is > 0.1 mm/y, will remove the naturallyforming surface oxide film which normally affords passivity to 13%Cr. (NB.Film stability is temperature, pH and chloride ion concentration dependent.)The resulting extent of corrosion will depend primarily on the speed at whichthe 13%Cr is able to repassivate. For further information reference should bemade to Appendix E of these Guidelines and the BP Amoco Erosion Guidelines

Duplex Stainless Steels

These materials generally do not suffer from CO2corrosion and so undererosive conditions the wastage rate will equal the erosion rate.

uu Flow Velocity > 13 m/s?

The 13 m/s limit applies only to carbon and low alloy steels and arises from the fact theCO2corrosion model used to generate the Corrosion Isoplots was developed from

corrosion data obtained at velocities up to 13 m/s. As the relationship is principallyempirical, extrapolation beyond this limit is questionable and Specialist Advice shouldbe sought.

The CO2Corrosion Isoplots were in fact developed for a nominal fluid velocity of 3m/s and pipe internal diameter of 4.5. While the CO2corrosion rate is sensitive tovelocity - it has a mass transfer component to the reaction - for the purpose of this first

pass assessment the Corrosion Isoplots are acceptable up to 13 m/s.

nConsult CO2Corrosion Isoplots

The CO2Corrosion Isoplots provide a simple means of quickly estimating what thecorrosion rate for carbon and low alloy steels will be for the conditions of interest. For13%Cr stainless steel refer to Appendix B. .


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assume for a correctly selected and applied corrosion inhibitor the inhibited corrosion rate will

be 0.1 mm/y. What then determines the acceptability over a given design / field / operationallife will be the time during which inhibitor is effectively deployed - due to upsets, underinjection, failed injections pumps etc. Applying this approach leads to a predicted effectiveinhibited corrosion rate (CRinh) of:

CRinh= (0.1 x T + CRuninhibx (DL- T))/DL

where T is the time in years with effective inhibitor deployment (inhibitor availability), DListhe design / field / operational life in years, (DL- T) is the time in years where effective

inhibitor depolyment is not achieved, and CRuninhibis the uninhibited CO2corrosion rate takenfrom the Corrosion Isoplots or from running a more detailed analysis using the BP AmocoCO2Corrosion model

2. Inhibitor availability is normally taken as a maximum of 95% of DLfor design purposes.

2.3. Plastic Coated or Lined Tubing

This option is most commonly used for injection tubing. Uncertainties remain about the long

term performance when continuously exposed to hydrocarbons (plastic coated tubing) andwater (GRE lined tubing) and there is the risk of collapse under rapid decompression due togas permeating behind the coating / liner. In addition, the coatings/linings have uppertemperature limitations, the limiting temperature being dependant upon which coating/lining isused. However, mechanical robustness is probably the most important consideration - duringhandling / installation and subsequent running of downhole tools and wirelining operations.Plastic coated tubing is particularly prone to mechanical damage, especially at joints, and assuch must be seriously questioned as a standalone corrosion control measure: the primary

benefit is more likely to lie with friction reduction. GRE lined tubing is therefore the only

standalone corrosion control option. Specialist advise should be sought for temperatures >80oC for use of GRE lined tubing and 120oC for plastic coated tubing.

2.4. Corrosion Resistant Alloys

Where CO2corrosion rates are unacceptably high, the use of 13%Cr stainless steel is often themost cost effective and logistically attractive option. There are limitations with regard to H2S- e.g. NACE limits the use of L80 13Cr steel to conditions where the partial pressure of H2S is0.1bara or less and the pH is 3.5 or more - such that the presence or absence of H2S over life

needs to be rigorously questioned if considering this option (refer to Appendix D and the SourCondition Road Maps for further information) . The material also has limitations in terms of

pitting resistance which is temperature and chloride concentration dependent (refer toAppendix B for further information: as a rule of thumb, its use is acceptable for chlorides 120oC or chlorides above50,000ppm refer to Appendix B and/or specialist advise should be sought.


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typically 2.5 to 4 times the material cost of carbon steel. These penalties are significantly

lower when comparing installed costs.

3. Use of downhole corrosion inhibition programmes with carbon steel tubulars.

If a consideration of the available information indicates that specifying carbon steel is notadequate to guarantee a suitable service life, alternatives will need to be sought. One suchalternative is to specify carbon steel, but add a suitable corrosion inhibitor to the fluids.Generally the use of carbon steel with corrosion inhibition offers a cheap CAPEX option forcorrosion control. However, downhole corrosion inhibition is a complex issue, with the need

to consider many factors, e.g. type of inhibitor, application method, level of protection,thermal stability, compatibility etc. In addition, there are many pitfalls with the application ofthis method, i.e. sand production, flow rate, etc. can all affect the effectiveness of thecorrosion inhibitor programme, logistics of inhibitor supply to remote locations needs to beconsidered (whether these are remote onshore locations or subsea well sites), etc. As a result,great care needs to be taken in the design and operation of a downhole corrosion inhibitionscheme.

For these reasons it had not been common practice within BP to consider downhole corrosioninhibition as a design strategy, rather this has been viewed as a corrective measure incircumstances where the specified carbon steel proved inadequate, e.g. due to changing fieldconditions. The preference within BP has been to use corrosion resistant alloys incircumstances where carbon steel proved inadequate. However, given the ever changing faceof new field developments (e.g. the development of onshore gas and oil fields, the need tominimise capex costs) it is likely that this option will be viewed more favourably in the future.

A very important question before deciding whether to consider a downhole corrosion

inhibition scheme is Does it provide the best whole life economic option ?

For pipelines over a few kilometres in length and all but the highest corrosion rates, inhibitionis usually the most economic option. For very short pipe sections the use of corrosion resistantalloys is the best option.

For wells the answer is not always clear cut and is dependant on several factors. This usuallysimplifies to a consideration of the risks involved in using inhibitors and the cost savings vs.the cost of failure of the inhibitor approach. For offshore wells the high cost of getting

inhibition wrong usually results in corrosion resistant alloys being selected.

Benefits of Inhibition

Where practical, the use of Inhibitors allows the use of carbon steel and thus reducesCAPEX.


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Delivery of the chemicals downhole is more problematic than injection into pipe lines.

Installation of delivery systems can increase CAPEX.

Handling Chemicals

May cause operational problems ( e.g. foaming, emulsions )

Corrosion monitoring and/or inspection is essential (although inspection can be difficult)

Increased OPEX.

Treatment Options

There are two types of inhibitor treatment:

Batch Treatment

Periodic treatments with the chemical are applied to the metal surface. The inhibitor forms afilm on the surface which lasts until the next treatment. This method is not preferred, as itseffectiveness is dependant solely on film persistency (determines the time between treatments)and it requires the well to be shut-in. It should only be used when the continuous method isnot practical.

Continuous Treatment

Inhibitor is continually injected into the fluids upstream of the location of corrosion. As the

fluids contact the metal surfaces the inhibitor adsorbs onto the surface to form a protectivefilm. Inhibitor must always be present in the fluid for the film and therefore the protection tobe maintained. This is the preferred method of inhibition.

3.1. Batch Treatment Methods

3.1.1. Tubing Displacement

This is the most common method of treating gas wells.

1. The well is shut in.

2. A concentrated solution (1 to 10%) of inhibitor is slowly pumped down the tubing to fill itcompletely.


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In one variation on this theme a slug (sometimes called a pill) of inhibited solution is placed

in the tubing which is then pushed down to contact all of the tubing by a solvent. Thisminimises the volume of inhibitor used and potential problems encountered when the well isreturned to service and the inhibitor flows back into the production stream.

In another variation the inhibitor is dissolved in a weighted carrier fluid such as a highdensity brine. This allows the inhibitor to fall to the bottom of the well under the influenceof gravity and thus minimises the volume of solvents and intervention required. There isinsufficient evidence that this method works and hence it can not be recommended.

The following batch methods are designed to provide a continuos stream of inhibitor and maybe thought of as pseudo continuous methods. They can provide longer times betweentreatments.

3.1.2. Formation Squeeze

1. The well is shut in.

2. A concentrated slug of inhibitor is pushed down the tubing and into the formation.

3. The inhibitor is allowed to contact the formation rock for several hours (4 to 24).

4. The well is brought back onto production.

5. Treatment is repeated every 3 to 12 months depending on conditions.

This method is used widely for scale control. For corrosion inhibitors the concern is with

plugging the formation and it is not recommended for low porosity (tight) formations.

3.1.3. Slow Release Inhibitors

The inhibitor is encapsulated in a slow release agent such as a wax, gel or capsule. This isusually fabricated into spheres or sticks which are dropped or placed down the tubing wherethey locate at the bottom of the well (in the rat hole).

In a variation on this method a container of inhibitor (a dump bailer ) is run on a wire line to

the bottom of the well. The bailer is tripped to release the product into the bottom of the well

There is little experience with such systems.

3.2. Continuous Treatment Methods


23/73


The capillary tubing is used to inject inhibitor into the bottom of the well.

This is probably the preferred method and is used in many locations.

Problems can occur with either the capillary tubing or the injection valve becoming blocked.The capillary strings have a reputation for being difficult to install and retrieve ( e.g. Bruce,June 1998 ).

3.2.2. Annulus Injection

In this method an injection valve is fitted at the bottom of the well just above the packer toallow fluid in the annulus to be pumped into the tubing. The annulus is filled with a solution ofthe inhibitor which is also pumped into it on a continuous basis. As the pressure in the annulusrises it will exceed the differential setting on the valve and product will be injected into thetubing.

Shell use this method on many of their gas wells around the world.

There have been problems with sludge formation in the annulus and blocking of the valves(both open and closed ).

The valves usually sit in side pockets and can be removed using a wire line.


24/73


pH ISOPLOTS

0.0001

0.001

0.01

0 .1

1

10

- 4 - 3 - 2 - 1 0 1

Log ( Pco2 )

PCO2

,bara

Conversion of PCO2to Log10(PCO2) for use in subsequent pH Isoplots


25/73


pH ISOPLOTS

3040

5060

7080

90100

110120

-4

-3

-2

-1

0

1

3.00

3.50

4.00

4.50

5.00

5.50

6.00

6.50

Temperature, degC

Log(Pco2)

Condensed Water

6.00-6.50

5.50-6.00

5.00-5.50

4.50-5.00

4.00-4.50

3.50-4.00

3.00-3.50


26/73


pH ISOPLOTS

30

4050

6070

8090

100110

120

-4

-3

-2

-1

0

1

3.00

3.50

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

8.50

Temperature, degC

Log(Pco2)

3.5% Brine + 50 ppm Bicarbonate

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5.00-5.50

4.50-5.00

4.00-4.50

3.50-4.00

3.00-3.50

6 50

7.00

7.50

8.00

8.50

10% Brine + 50 ppm Bicarbonate

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5.00-5.50


27/73


pH ISOPLOTS

30

4050

6070

8090

100110

120

-4

-3

-2

-1

0

1

3.00

3.50

4.00

4.50

5.005.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

Temperature, degC

Log(Pco2)


8.50-9.00

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5.00-5.50

4.50-5.00

4.00-4.50

3.50-4.00

3.00-3.50

7.00

7.50

8.00

8.50

9.00


8.50-9.008.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5 00 5 50


28/73


pH ISOPLOTS

30

4050

6070

8090

100110

120

-4

-3

-2

-1

0

1

3.00

3.50

4.00

4.50

5.005.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

Temperature, degC

Log(Pco2)


8.50-9.00

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5.00-5.50

4.50-5.00

4.00-4.50

3.50-4.00

3.00-3.50

7.00

7.50

8.00

8.50

9.00


8.50-9.008.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5 00 5 50

S/UTG/023/00 A di A


29/73


pH ISOPLOTS

30

4050

6070

8090

100110

120

-4

-3

-2

-1

0

1

3.00

3.50

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

9.50

Temperature, degC

Log(Pco2)


9.00-9.50

8.50-9.00

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5.00-5.50

4.50-5.00

4.00-4.503.50-4.00

3.00-3.50

7.00

7.50

8.00

8.50

9.00


8.50-9.008.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5 00 5 50



30/73


pH ISOPLOTS

30

4050

6070

8090

100110

120

-4

-3

-2

-1

0

1

3.00

3.50

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

9.50

Temperature, degC

Log(Pco2)


9.00-9.50

8.50-9.00

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5.00-5.50

4.50-5.00

4.00-4.503.50-4.00

3.00-3.50

7.50

8.00

8.50

9.00

9.50


9.00-9.50

8.50-9.00

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00



31/73


pH ISOPLOTS

30

4050

6070

8090

100110

120

-4

-3

-2

-1

0

1

3.00

3.50

4.00

4.50

5.00

5.50

6.00

6.50

7.00

7.50

8.00

8.50

9.00

9.50

Temperature, degC

Log(Pco2)


9.00-9.50

8.50-9.00

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00

5.00-5.50

4.50-5.00

4.00-4.503.50-4.00

3.00-3.50

7.50

8.00

8.50

9.00

9.50


9.00-9.50

8.50-9.00

8.00-8.50

7.50-8.00

7.00-7.50

6.50-7.00

6.00-6.50

5.50-6.00



32/73


CO2CORROSION ISOPLOTS

0.0001

0.001

0.01

0.1

1

10

- 4 - 3 - 2 - 1 0 1

L o g ( P c o 2 )



33/73

pp


30 40 50 60 7080 90 100 110

120 130

140 150

-4

-3

-2

-1

0

1

0

5

10

15

20

25

30

35

40

45

50

55

Temperature, degC

Log(Pco2)

pH 3

n > 10 mm/y

n 5 - 10 mm/y

n 0 - 5 mm/y

0.7

0.8

0.9

1.0

pH 3

n 0.9 - 1.0 mm/y

n 0.8 - 0.9 mm/y

n 0.7 - 0.8 mm/yn 0.6 - 0.7 mm/y

n 0.5 - 0.6 mm/y

n 0.4 - 0.5 mm/y

n 0.3 - 0.4 mm/y

n 0 2 - 0 3 mm/y



34/73


30 40 50 60 7080 90 100 110

120 130

140 150

-4

-3

-2

-1

0

1

0

5

10

15

20

25

30

35

40

45

Temperature, degC

Log(Pco2)

pH 3.5

n > 10 mm/y

n 5 - 10 mm/y

n 0 - 5 mm/y

0.7

0.8

0.9

1.0

pH 3.5

n 0.9 - 1.0 mm/y

n 0.8 - 0.9 mm/y

n 0.7 - 0.8 mm/yn 0.6 - 0.7 mm/y

n 0.5 - 0.6 mm/y

n 0.4 - 0.5 mm/y

n 0.3 - 0.4 mm/y

n 0 2 - 0 3 mm/y



35/73


30 40 50 60 7080 90 100 110

120 130

140 150

-4

-3

-2

-1

0

1

0

5

10

15

20

25

30

35

40

Temperature, degC

Log(Pco2)

pH 4

n > 10 mm/y

n 5 - 10 mm/y

n 0 - 5 mm/y

0.7

0.8

0.9

1.0

pH 4

n 0.9 - 1.0 mm/y

n 0.8 - 0.9 mm/y

n 0.7 - 0.8 mm/yn 0.6 - 0.7 mm/y

n 0.5 - 0.6 mm/y

n 0.4 - 0.5 mm/y

n 0.3 - 0.4 mm/y

n 0 2 - 0 3 mm/y



36/73


30 40 50 60 7080 90 100 110

120 130

140 150

-4

-3

-2

-1

0

1

0

5

10

15

20

25

30

Temperature, degC

Log(Pco2)

pH 4.5

n > 10 mm/y

n 5 - 10 mm/y

n 0 - 5 mm/y

0.7

0.8

0.9

1.0

pH 4.5

n 0.9 - 1.0 mm/y

n 0.8 - 0.9 mm/y

n 0.7 - 0.8 mm/yn 0.6 - 0.7 mm/y

n 0.5 - 0.6 mm/y

n 0.4 - 0.5 mm/y

n 0.3 - 0.4 mm/y

n 0 2 - 0 3 mm/y



37/73


30 40 50 60 7080 90 100 110

120 130 140150

-4

-3

-2

-1

0

1

0

5

10

15

20

25

Temperature, degC

Log(Pco2)

pH 5

n > 10 mm/y

n 5 - 10 mm/y

n 0 - 5 mm/y

0.7

0.8

0.9

1.0

pH 5

n 0.9 - 1.0 mm/y

n 0.8 - 0.9 mm/y

n 0.7 - 0.8 mm/yn 0.6 - 0.7 mm/y

n 0.5 - 0.6 mm/y

n 0.4 - 0.5 mm/y

n 0.3 - 0.4 mm/y

n 0 2 - 0 3 mm/y



38/73


30 40 50 60 7080 90 100 110

120 130 140150

-4

-3

-2

-1

0

1

0

5

10

15

20

Temperature, degC

Log(Pco2)

pH 5.5

n > 10 mm/y

n 5 - 10 mm/y

n 0 - 5 mm/y

0.7

0.8

0.9

1.0

pH 5.5

n 0.9 - 1.0 mm/y

n 0.8 - 0.9 mm/y

n 0.7 - 0.8 mm/yn 0.6 - 0.7 mm/y

n 0.5 - 0.6 mm/y

n 0.4 - 0.5 mm/y

n 0.3 - 0.4 mm/y

n 0 2 - 0 3 mm/y



39/73


30 40 50 60 7080 90 100 110

120 130 140150

-4

-3

-2

-1

0

1

0

5

10

15

Temperature, degC

Log(Pco2)

pH 6

n > 10 mm/y

n 5 - 10 mm/y

n 0 - 5 mm/y

0.7

0.8

0.9

1.0

pH 6

n 0.9 - 1.0 mm/y

n 0.8 - 0.9 mm/y

n 0.7 - 0.8 mm/yn 0.6 - 0.7 mm/y

n 0.5 - 0.6 mm/y

n 0.4 - 0.5 mm/y

n 0.3 - 0.4 mm/y

n 0 2 - 0 3 mm/y



40/73


30 40 50 60 7080 90 100 110

120 130 140150

-4

-3

-2

-1

0

1

0

5

10

Temperature, degC

Log(Pco2)

pH 6.5

n > 10 mm/y

n 5 - 10 mm/y

n 0 - 5 mm/y

0.7

0.8

0.9

1.0

pH 6.5

n 0.9 - 1.0 mm/y

n 0.8 - 0.9 mm/y

n 0.7 - 0.8 mm/yn 0.6 - 0.7 mm/y

n 0.5 - 0.6 mm/y

n 0.4 - 0.5 mm/y

n 0.3 - 0.4 mm/y

n 0 2 - 0 3 mm/y

S/UTG/023/00 Appendix B


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APPENDIX B : CORROSION RESISTANCE OF CORROSION RESISTANTALLOYS

1. General corrosion resistance of corrosion-resistant alloys.

It should not be assumed that the corrosion-resistant alloys are immune to general corrosion inCO2-containing environments. Specifically, it is known that 13%Cr steel is prone to generalcorrosion at elevated temperatures. The rate of corrosion will be dependant on a number offactors, including partial pressure of carbon dioxide, solution chemistry (particularly chloridecontent), temperature. For many low temperature applications the rate of general corrosion

will be very low such that it will not be a concern. This led in the past to many steelmanufacturers putting a limit of 150oC on the use of 13%Cr steels. The origin of this limitseems to be corrosion tests undertaken by the steel manufacturers in a 5% sodium chloridesolution with a CO2partial pressure of 35bara. In these tests the acceptable corrosion rate wasconsidered to be 1 mm/yr, which occurred at 150oC. Clearly the use of a single 'blanket' figureof this type will be unacceptable for many circumstances. Firstly, a wastage rate of 1 mm/yrmay not be acceptable, such that consideration will need to be given to other metallurgies.Secondly, the conditions may be significantly less onerous than those used in the

manufacturers' tests, such that the 13%Cr steel can be used for temperatures in excess of150oC.

A simple rule of thumb methodology has been established within BPX to obtain a firstorder evaluation of the likely general corrosion rate for 13%Cr steel in sweet or mildly sourconditions, as follows:

Establish the downhole pH (refer to Appendix A)

If the following criteria are met 13%Cr steel can be considered:

pH>4.0 and bottom hole temperature pH>3.5 and bottom hole temperature


42/73

downhole tubulars known as the alloyed martensitic 13%Cr steels. These alloys are adevelopment of the conventional 13%Cr steels (e.g. API 5CT L80 13%Cr steel) to whichalloying elements of nickel (typically 4 to 6%), molybdenum (typically 0.5 to 2.5%) and

possibly copper (up to 1.5%) have been added. These have a number of advantages over theconventional 13%Cr steels, including:

Higher strength/toughness (available in strengths up to 110ksi)

Much better corrosion resistance at high temperatures (>120C)

Slightly better resistance to sulphide stress cracking under sour conditions (i.e. forthe same strength level)

These have been found to have good general (and pitting) corrosion resistance over a widerange of conditions up to a temperature of 200C. Indeed, tests undertaken at BP Sunbury3

indicated good general (and pitting) corrosion resistance in a high chloride (120,000ppm)solution at a pH of 3.5 and a temperature of 200C. Some manufacturers on the other handindicate that these alloys have good general/pitting corrosion resistance for all levels ofchlorides only up to a temperature of 175C. Therefore, given that this is a relatively new

family of materials with a potentially wide range of chemical compositions and that fieldexperience is relatively limited further laboratory testing will be required for specific fieldapplications.

2. Localised corrosion of corrosion-resistant alloys.

2.1. Pitting Corrosion.

Pitting corrosion occurs when certain regions on the metal surface become fixed anodic sites.An example of this is the pitting of stainless steels in chloride-containing solutions. Thelikelihood/rate of pitting corrosion is dependant on a number of factors, notably producedwater chemistry (particularly chloride content, pH), level of dissolved gases (CO2, H2S andO2) and operating temperature.

However, the pitting process is strongly affected by temperature, with the propensity towardspitting increasing with increasing temperature. The result is that for many CRAs a criticaltemperature can be defined below which pitting corrosion will not be a significant risk. A

programme of work was undertaken within BP to develop a test protocol for determining thetemperature service limits for CRAs. This protocol was used to determine the temperatureservice limits for two of the most commonly used CRAs for downhole tubulars, i.e. 13%Crsteel (which has been found to be prone to pitting in the presence of hydrogen sulphide) and25%Cr/7%Ni duplex stainless steel. Two temperatures were determined using differenttechniques. In the first, an immersion test was used to determine the temperature at which pits



43/73

(onset of pitting) temperature limit being used for conditions where even superficial pitting isunacceptable and the upper temperature limit being used where superficial pitting isacceptable, as long as it will not lead to perforation. Clearly, this is not the end of the story.Even above the temperature at which propagating pits form there is likely to be a temperaturerange over which the rate of pitting is acceptable, i.e. the required service life will beachieved. For 13%Cr steel, as an initial rough estimate the possible rate of pitting can beevaluated using the methodology outlined for general corrosion in Section 1 of this appendix(Appendix B). However, given the different nature of the attack it is recommended that this isconfirmed via service experience under similar conditions or laboratory tests. In the case ofduplex stainless steels the evaluation of such situations is outside the scope of the present

guidelines. If it is intended to consider these materials for use in the pitting regime region, itwill be necessary to undertake service history evaluations/laboratory tests under the specificfield conditions, to demonstrate the acceptability of the candidate materials for the intendedservice duty/life.

When using Table B1 for determining the acceptability of candidate materials for the intendedservice it will be necessary to know the operating temperature, downhole pH (this can beevaluated using the Methodology outlined in Appendix A) and equivalent chloride level.Clearly, if the intended service conditions are less onerous than those quoted in Table B1, then

the material is acceptable up to the temperature given. It is possible that it will be acceptableto even higher temperatures than those given, if the intended service conditions aresignificantly less onerous. This can only be determined by service experience on similarconditions or a series of laboratory evaluations using the test protocols outlined in Section 4 ofthis appendix (Appendix B). In addition, the use of materials other than those stated in TableB1 will require justification via documented good previous service experience or furthertesting if there is a concern about pitting corrosion.

For the alloyed martensitic 13%Cr steels (such as Sumitomos Super 13Cr alloy) testsundertaken at BP Sunbury indicated good general pitting corrosion resistance in a highchloride (120,000ppm) solution at a pH of 3.5 and a temperature of 200C. However, giventhat this is a relatively new family of materials with a potentially wide range of chemicalcompositions and given that field experience is relatively limited it may well be that furtherlaboratory testing will be required for specific field applications

2.2. Crevice Corrosion.

Crevice corrosion is the localised damage that can result in a narrow gap or "crevice" betweentwo adjacent components. Examples of crevices that can occur in downhole tubulars are atinterfaces between two joints, under deposits, in contact with downhole jewellery, etc. Thelocal environment produced within the crevice can be quite different to the bulk fluidenvironment, leading to corrosion damage which could not be predicted from the general fluidcomposition. The likelihood and rate of crevice corrosion is dependant on a large number of



44/73

observed under conditions where an unsuitable material was chosen in the first place (e.g. theuse of 13%Cr steel for sea water containing oxygen, even at low levels).

(ii) Prevent significant scale build up. Significant scale build-up, as well as possibly affectingthe well productivity by affecting the throughput of the tubulars, can lead to crevices at thescale/metal surface interface leading in turn to crevice corrosion. Therefore, if necessary, stepsshould be taken to prevent significant scale build-up, e.g. by de-scaling treatments, use of scaleinhibitors, etc.

(iii) Ensure that due consideration is given to the potentially adverse effects of crevices in the

design of any downhole jewellery and that steps are taken to minimise the number of crevices.

3. Stress corrosion cracking of corrosion-resistant alloys.

(a) 13%Cr steel and alloys

The martensitic 13%Cr steels (e.g. API 5CT L80 13%Cr Steel) are not prone to stresscorrosion cracking in downhole environments. Hence there is no need to consider the stresscorrosion cracking behaviour of these materials for downhole applications.

There have been some indications in the literature that the alloyed martensitic 13%Cr steels(such as Sumitomos Super 13Cr alloys) maybe prone to chloride stress corrosion cracking(CSC). However, tests undertaken at Sunbury4did not reveal any signs of CSC under typicalproduced water conditions. Therefore, it is not presently envisaged that CSC will be a

problem for produced fluids with this family of materials. However, given the limited test dataand service experience, care should be taken in their application in respect of the possibility ofCSC (e.g. check with the supplier/s and/or undertake evaluations if/when necessary). Inaddition very recently (i.e. in 1999) there has been a case within BP Amoco of a 95ksialloyed

martensitic 13%Cr steel tubing string suffering from cracking. This initiated from the externalsurface, i.e. the surface in contact with the completion brine. This incident is still beinvestigated, but at the present the most likely cause is CSC in the calcium chloride highdensity completion brine. Therefore, extra care needs to be exercised in the selection ofcompletion brines for use with this family of materials.

(b) Austenitic Stainless Steels

In principle, the austenitic stainless steels can be prone to CSC in typical downholeenvironments. This type of cracking is exacerbated by increasing temperature. It is also knownthat such cracking can be exacerbated by the presence of hydrogen sulphide. The possibility ofsuch cracking has meant that only alloys that are very resistant to it have been selected fordownhole applications in the past. For example, the NIC 32, Sanicro 28, type alloys are oftenconsidered for downhole tubulars in place of the cheaper and more common AISI 300 series



45/73

(c) Duplex Stainless Steels

The duplex stainless steels are prone to some "unique" mechanisms of stress corrosioncracking as a result of their duplex (ferrite/austenite) structure. Early work by Japanese steelmanufacturers showed that there was a possibility of stress corrosion cracking at elevatedtemperatures in sodium chloride test solutions containing dissolved CO2and H2S. The workindicated that stress corrosion cracking was exacerbated by increasing levels of H2S,decreasing pH and increasing chloride content. The cracking is thought to be the combinationof a chloride stress corrosion cracking mechanism and a hydrogen assisted mechanismcracking (e.g. SSC) and/or selective corrosion of the ferrite phase leading to "crack-like"

defects. Many workers have indicated that this type of cracking is most severe in an"intermediate" range of temperatures (e.g. 60 to 100C), such that tests are often carried outat 80oC to represent a "worst case". However, work at Sunbury indicated that thetemperature range for most severe cracking is dependant on the type of duplex stainless steeland test environment, with the most severe range being 20 to 60C in some circumstances.Therefore, for any particular environment it is necessary to consider testing across the fulltemperature range if the worst case for cracking is to be covered.

A series of stress corrosion cracking tests were undertaken at Sunbury to determine the

application limits for the two duplex stainless steels most commonly used for downholetubulars (22%Cr/5%Ni [UNS S31803] and 25%Cr/7%Ni [UNS S32750]). These have been

plotted in terms of pH v. PH2Splots, in a similar manner as for sulphide stress cracking (SSC)resistance of ferritic/martensitic materials, as described in Appendix D. For ease of use thesehave been included with the other Individual alloy go/no go charts at the end of theseGuidelines.

In addition very recently (i.e. in 1999) there has been a case of a 130ksi 25%Cr super duplexstainless steel tubing string suffering from cracking. This initiated from the external surface,

i.e. the surface in contact with the completion brine. This incident is still be investigated, but atthe present the most likely cause is CSC at high temperature (around 130C) in the calciumchloride high density completion brine. Therefore, extra care needs to be exercised in theselection of completion brines for use with duplex stainless steel.

4. Test Protocols.

4.1. General/Localised Corrosion.

The following immersion test protocol can be used as part of the material pre-qualificationprocess to determine the suitability of a candidate material for the intended application withregards to general/localised corrosion resistance:-

Specimen and PreparationThe specimens shall be taken from the tube wall and shall



46/73

Condensed Water - for the case of gas wells. For the purpose of these tests distilledwater with 1000ppm of sodium chloride should be used.

b) Deaerate fully using oxygen free nitrogen prior to specimen immersion. Insert thespecimens, close the autoclave and re-deaerate fully by nitrogen. Purge the test solution usingthe CO2and/or H2S mixture for a period of at least one hour and then add CO2and/or H2S upto a suitable pressure such that at the test temperature the partial pressures of these gasesanticipated in service is achieved.

c) Heat to the test temperature (this should represent the anticipated bottom hole

temperature).

(Note: During the immersion, specimens should be kept away from direct contact with theautoclave wall and other specimens.)

ReagentsThe reagents shall be high purity grades.

Acidic GasesHigh purity CO2and H2S gas shall be used.

Solution VolumeThis shall be a minimum of 30 cc/cm2

of specimen.

Test DurationTest duration shall be kept to a minimum of 30 days.

Post Exposure AnalysisThe specimens shall be examined immediately after exposure andtheir condition noted. They shall then be mechanically cleaned by scrubbing with a soft brushunder running water followed by the application of an appropriate cleaning solution (e.g.inhibited acid) to remove any scale (refer to ASTM Standard G1, latest edition). Specimensshall be dried and re-weighed to identify the weight loss. After weighing the specimens shall

be visually examined for corrosion/pitting with the aid of a stereo microscope at X40. In caseof pitting, all pits which are greater than 0.1mm diameter shall be reported. The report shallinclude the number, maximum depth (mm), population per unit area of pits and pitting rate(mm/yr).

4.2. Stress Corrosion Cracking.

The following test protocol can be used as part of the material pre-qualification process to

determine the suitability of a candidate material for the intended application with regards tostress corrosion cracking resistance:-

Test Solution

The test solution shall consist of NaCl (at a concentration to simulate the level of Cl



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c. Acidise using concentrated hydrochloric acid1down to a pH representative of the insitu pH anticipated in the downhole tubulars.

d. Introduce the solution into a test vessel, deaerate and saturate with a mixture ofCO2/H2S with the following gas ratios:

H2S at the partial pressure anticipated in the downhole tubulars, with the balance being CO 2up to the ambient test pressure (1 bar)

During the test the pH may alter, but shall not exceed a value 0.2 above the target figure. This

will be achieved through complete exclusion of oxygen and maintaining a sufficient solutionvolume to test piece surface area ratio.

Test Temperature

The temperature shall be maintained at ambient (23oC)

Reagents

The reagents shall be in accordance with those specified in NACE TM0177-96 Section 3.

Acidic Gases

High purity H2S/CO2gas mixtures shall be used. The test solution shall be purged with the gasmixture throughout the test period.

Test pieces

All test pieces shall be machined from the pipe wall in the longitudinal direction

Test Vessels and Solution Volume

These shall be in accordance with those specified in NACE TM0177-96 and ISO 7539-1:1987.

Number of Tests

A set shall comprise duplicate tests.

SSC Test Method

A smooth test piece tensile test shall be carried out in accordance with the procedures



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examination of the gauge length (at a magnification of x10) plus one of the followingprocedures:-

Metallographic examination of the gauge length by longitudinal sectioning andpolishing.

Fast fracturing of the test piece using a tensile test machine. Subsequent

visual examination of the gauge length for cracks. Analysis of the tensile test data andfracture surfaces for evidence of embrittlement and/or brittle fracture.

Alternative methods may be offered for approval by BPX.

Applied Stress

The applied stress shall be 90% of the measured (actual) yield strength. The yield strengthshall be determined on a round bar test piece (Figure 4 of ASTM A370-94) using the 0.2%offset method in ASTM A370-94.

Test pieces

The standard tensile test pieces shall be in accordance with those recommended in NACETM0177-96 (Method A). Where full-size test pieces can not be achieved then sub-size test

pieces in line with NACE TM-0177-96 may be used.

Test Duration

The test duration shall be 720 hours

Data Reporting

Data reporting shall include test piece geometry, test solution and conditions (temperature, gasmixture), pH (initial and final), loading device used, test duration, test result (failure/pass) and

test piece surface appearance subsequent to test termination.



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TABLE B1. MAXIMUM SERVICE TEMPERATURE LIMITS FOR CORROSION-RESISTANT ALLOYS TO AVOID LOCALISED CORROSION

(a) 13% Chromium Steel

MATERIAL WELLCONDITIONS

MAXIMUMTEMPERATURE LIMITS

(oC)

Onset of

Pitting

Pit

Propagation13%Cr steel 6,000ppm Chloride

pH = 4.5*pH2S = 0.001 bara

100 140 (GC**)

13%Cr steel 30,000ppm ChloridepH = 4.5*

pH2S = 0.001 bara110 140 (GC**)

13%Cr steel 120,000ppm ChloridepH = 4.5*pH2S = 0.001 bara

120 140 (GC**)


pH2S = 0.01 bara120 130 (P)


pH2S = 0.01 bara

120 130 (P)


pH2S = 0.01 bara120 130 (P)


pH2S = 0.1 bara120 120 (P)


pH2S = 0.1 bara120 120 (P)

13%Cr steel 120,000ppm ChloridepH = 4.5 120 120 (P)



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(b) 25%Cr/7%Ni Duplex Stainless Steel

MATERIAL WELLCONDITIONS

MAXIMUMTEMPERATURE LIMITS

(oC)

Onset ofPitting

PitPropagation

25%Cr/7%Niduplex stainless

steel

6,000ppm ChloridepH = 3.5

pH2S = 0.001 bara180 200


steel


pH2S = 0.001 bara160 200

25%Cr/7%Ni

duplex stainlesssteel

120,000ppm Chloride

pH = 3.5pH2S = 0.001 bara 140 200


steel


pH2S = 0.01 bara170 200


steel


pH2S = 0.01 bara140 180


steel


pH2S = 0.01 bara140 180


steel


pH2S = 0.1 bara140 180

25%Cr/7%Ni

duplex stainlesssteel

30,000ppm Chloride

pH = 3.5pH2S = 0.1 bara

130 170


steel


pH2S = 0.1 bara130 170

S/UTG/023/00 Appendix C


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APPENDIX C : WHAT IS THE DEFINITION OF A "SOUR ENVIRONMENT"?

A "sour environment" is defined in NACE Standard MR0175 as a fluid containing water as aliquid, together with hydrogen sulphide at a level exceeding certain criteria, as detailed inFigures C1 and C2. For convenience, these criteria are summarised in Tables C1 and C2. Itshould be noted that only environments containing liquid water are classified as sour in thecontext of the standard. Therefore dry gas would not be considered sour.

TABLE C1. DEFINITION OF SOUR SERVICE FOR A GAS WELL

Total System Pressure(psia)

Partial Pressure ofHydrogen Sulphide (psia)

Sour Environment(YES/NO)

65

0.05

0.05

NO

NO

NO

YES

TABLE 2. DEFINITION OF SOUR SERVICE FOR AN OIL WELL

(oil/water or oil/water/gas)

Total SystemPressure (psia)

Partial Pressure ofHydrogen Sulphide

in the gas phase(psia)

Mol.-% H2S in thegas phase

Sour Environment(YES/NO)

265

-

0.05, 10


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calculated simply by multiplying the mole fraction of hydrogen sulphide in the gas by thebottom hole pressure. For example, for a 5500m deep gas well with a bottom hole pressure of

14,000 psi and a hydrogen sulphide content of 5 ppm mole, the partial pressure of hydrogensulphide would be 0.07 psia (5/1,000,000 * 14,000), i.e. the well would be classified as sour.

For oil wells under circumstances where there is gas present (multiphase wells), the partialpressure of hydrogen sulphide can be estimated by multiplying the total pressure by the molefraction of hydrogen sulphide. The situation for oil wells in which there is no gas phase

present under downhole conditions is somewhat different. The partial pressure of hydrogensulphide that needs to be calculated is that in a gas phase in equilibrium with that dissolved inthe well liquids (oil/water). An alternative description of this is the partial pressure ofhydrogen sulphide in the gas phase formed at its bubble point. Therefore, a "convenient"method often used to calculate the partial pressure is to multiply the bubble point pressure bythe mole fraction of hydrogen sulphide in the gas phase.

S/UTG/023/00 Appendix D


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APPENDIX D : SULPHIDE STRESS CRACKING

1. Background.

Sulphide stress cracking occurs as a result of the entry of atomic hydrogen into the metal.Aqueous corrosion will produce atomic hydrogen, which would normally tend to recombinevia the reaction:

2H++ 2e H + H H2(gas)

These hydrogen gas molecules are too large to enter the metal and are thus not harmful to it.However, hydrogen sulphide is thought to discourage the recombination of hydrogen atoms toform H2gas and hence encourage the entry of atomic hydrogen into the metal. Once in themetal, the atomic hydrogen will diffuse to "trap" sites, where it will lead to a local increase inthe stress and/or a reduction in the strength of the metal lattice. For a material under load thereis evidence to suggest that the atomic hydrogen will concentrate near to stress concentratorsand may give rise to crack initiation at such points, hence leading to a brittle-like fracture. Thistype of cracking can occur quite rapidly. Thus even if materials are only to be exposed to sourconditions for short periods of time they must be resistant to SSC.

2. NACE Standard MR0175 (Standard Material Requirements - Sulfide StressCracking Resistant Metallic Materials for Oilfield Equipment)

The NACE Standard MR0175 is concerned with the resistance of materials to sulphide stresscracking (SSC) in sour conditions. In some countries, such as the United States, the standardis a legislative requirement, i.e. it mustbe applied there. This document should be referred tofor initial information on materials with adequate resistance to SSC for sour conditions.

In particular, it should be noted that increasing the temperature reduces the likelihood ofsulphide stress cracking, particularly for low-alloy steels. Hence, NACE MR0175 allows theuse of materials with a specified minimum yield strength above that of the fully sour-resistantgrades under circumstances where the minimum operating temperature is above certain limits.The information in Table D1 taken from NACE MR0175-99 details the acceptable tubularmaterial grades for different temperature ranges (refer to NACE MR0175-99 for the fullTable).



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TABLE D1. ACCEPTABLE API SPECIFICATIONS FOR TUBULAR GOODS

For all temperatures(1)

For operatingtemperatures 65oC

or greater (2)

For operatingtemperatures

80oC or greater(2)

For operatingtemperatures

107oC orgreater (2)

API Spec. 5CT gradesH40 (3); J55; K55;L80 (Type 1); C90

(Type1); T95 (Type1)

API Spec. 5CT gradesN80 (Q + T); C95

API Spec. 5CTgrades H40; N80;

P110

API Spec. 5CTgrade Q125. See

Note 4.

Proprietary gradesPer NACE MR-0175

Section 10.2.

Proprietary Q + Tgrades with 110ksi orless maximumyield

strength

Proprietary Q + Tgrades with 140ksior less maximum

yield strength.

Notes to Table D1:

1. Impact resistance may be required by other standards and codes for low operatingtemperatures.

2. Continuous minimumtemperature; for lower temperatures, select from column 1.

3. For H40 material the maximum permissible yield strength is 80ksi.

4. Regardless of the requirements for the current edition of API Spec. 5CT, the Q125 grade

shall always (1) have a maximum yield strength of 150ksi; (2) be quenched and tempered;(3) be an alloy based on Cr-Mo chemistry. The C-Mn alloy chemistry is not acceptable.

When using these criteria, it is important to bear in mind that SSC can occur within a relativelyshort time span, so that periods of exposure to sour conditions at temperatures below thosestated in the Table could potentially lead to SSC problems. For this reason it is important tonote that the temperature levels quoted in Table D1 are the minimumoperating temperaturethe tubing will experience. If temperatures below this minimum are expected even for shortperiods of timethen the non-sour higher strength materials should notbe used.

3. BP AMOCO Methodology for selecting materials with adequate SSC resistance.

It was recognised some time ago that the use of the NACE Standard MR0175 alone is notsufficient to allow the selection of the optimum material with adequate sulphide stress cracking

i F l h NACE S d d k f h i i H hi h i



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applicable to alllikely operating temperatures (Note: This methodology need not be applied tothe traditional sour-resistant grades in API 5CT [i.e. L80, C90, T95] which it is assumed are

suitable for allsour conditions on the basis of past experience and test data).

To apply the BP AMOCO methodology, it is necessary to know certain information about theproposed well, i.e. the partial pressure of hydrogen sulphide in the gas phase, and the in-situpH of the water associated with the produced fluids. As an in-situ pH is not usually available,the methodology outlined in Appendix A can be used to assess the in-situ pH on the basis ofcertain well information.

Once the necessary information has been collected, the conditions can be plotted onto theappropriate sulphide stress cracking performance domain charts for individual alloys at theend of these Guidelines. There are two domains identified on the individual alloy go/no gocharts. If the operating conditions fall within the acceptable domain then the material can beconsidered to have an acceptable resistance to SSC under the prevailing conditions. However,if the operating conditions fall within the unacceptable domain then it will be necessary toconsider a material with greater SSC resistance.

Domain diagrams are included for 95ksi alloyed martensitic 13%Cr steels (e.g. Super 13Cr;

Hyper 13Cr). These alloys do not represent a distinct chemical composition, but rather arecomprised of a family of alloys with differing chemical compositions (varying betweenmanufacturers) and hence often having differing sour resistance. For this reason, it has not

been possible to develop a simple go no go domain chart. Therefore, for ease ofinterpretation, charts with three domains have been developed. These three domains represent:

Acceptable(Green for go)- the material is satisfactory for the proposedapplication.

Unacceptable(Red for no go)- the material is unsuitable for the proposedapplication and an alternative material with greater SSC resistance should beconsidered.

Further Assessment Required(Yellow for caution)- to assess whether thematerial is suitable for the intended application or not, further assessment is requiredin the form of consideration of specific pre-qualification data for thealloy/manufacturer being considered, reference to relevant past test data (e.g. for asimilar application), application specific testing.

In addition, tests in BP Amoco have demonstrated that the level of chloride is very important,as increased chloride levels significantly reduces the sulphide stress cracking resistance of thematerials. Therefore domain diagrams have been developed for both high chloride (typical of

produced water in oil/gas wells) and low chloride (typical of condensing water in gas wells)



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control of chemistry for these materials). Instinctively, if anything, the 95ksi material shouldoutperform the 110ksi material. Therefore, it is recommended that manufacturers are

requested to retest the 95ksi materials in low (1000ppm) chloride conditions if intended foruse in gas wells where only condensing water will be present and where the partial pressure ofH2S is such that it would be in an acceptable regime on the attached Regime charts for the110ksi material but not for the 95ksi material.

Given the wide range of proprietary 'super 13Cr alloys' now available on the market, it has notbeen possible to test all those available. Rather, a few representative materials have beentested. A Qualification Procedure has been developed on the basis of the present results6. It isrecommended that all manufacturers are requested to qualify their material using thisQualification Procedure prior to using the material in BP Amoco. This will ensure that, as aminimum, their material conforms with the attached Domain Diagrams. If uncertain whetherthe prospective manufacturers material has already been pre-qualified contact the relevantspecialist within BP AMOCO.

It should be noted that the domain diagrams are not all encompassing, but only deal withresistance to SSC. Before making the final selection of production tubular material, it will benecessary to consider many other corrosion-related factors. For example, resistance to

general/localised corrosion, stress corrosion cracking resistance, etc. under the prevailingconditions. These aspects are covered elsewhere in these Guidelines.

In addition, it should be noted that the assessment of the resistance of duplex stainless steels toSSC and stress corrosion cracking (SCC) is considered further in Appendix B. As a result oftheir unique duplex structure consisting of a combination of austenite and ferrite inapproximately equal volume fractions, they are prone to a number of unique crackingmechanisms. These can consist of either a combination of sulphide stress corrosion cracking(of the ferrite phase) and chloride stress corrosion cracking (of the ferrite and austenite

phases) or selective corrosion of the ferrite phase leading to crack-like defects.

4. Simplified Test Protocol.

The following test protocol can be used as part of the material pre-qualification process todetermine the suitability of a candidate material for the intended application with regards tosulphide stress cracking resistance:-

Test Solution

The test solution shall consist of NaCl (at a concentration to simulate the level of Clanticipated in the produced water) + sodium acetate (CH3COONa, at a level sufficient to

buffer the pH, e.g. 0.86g/l has often been used in the past)7in distilled or de-ionised water.The procedure for solution preparation shall be as follows:-



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c. Acidise using concentrated hydrochloric acid5down to a pH representative of the insitu pH anticipated in the downhole tubulars.

d. Introduce the solution into a test vessel, deaerate and saturate with a mixture ofCO2/H2S with the following gas ratios:

H2S at the partial pressure anticipated in the downhole tubulars, with the balance being CO 2up to the ambient test pressure (1 bar)

During the test the pH may alter, but shall not exceed a value 0.2 above the target figure. Thiswill be achieved through complete exclusion of oxygen and maintaining a sufficient solutionvolume to test piece surface area ratio.

Test Temperature

The temperature shall be maintained at ambient (23oC)

Reagents

The reagents shall be in accordance with those specified in NACE TM0177-96 Section 3.

Acidic Gases

High purity H2S/CO2gas mixtures shall be used. The test solution shall be purged with the gasmixture throughout the test period.

Test pieces

All test pieces shall be machined from the pipe wall in the longitudinal direction

Test Vessels and Solution Volume

These shall be in accordance with those specified in NACE TM0177-96 and ISO 7539-1:1987.

Number of Tests

A set shall comprise duplicate tests.

SSC Test Method



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To be considered a pass, the gauge length of the test piece shall be free from any signs offissure and/or cracks, after the exposure period. This may be assessed through visual

examination of the gauge length (at a magnification of x10) plus one of the followingprocedures:-

Metallographic examination of the gauge length by longitudinal sectioning andpolishing.

Fast fracturing of the test piece using a tensile test machine. Subsequent

visual examination of the gauge length for cracks. Analysis of the tensile test data andfracture surfaces for evidence of embrittlement and/or brittle fracture.

Alternative methods may be offered for approval by BPX.

Applied Stress

The applied stress shall be 90% of the measured (actual) yield strength. The yield strengthshall be determined on a round bar test piece (Figure 4 of ASTM A370-94) using the 0.2%

offset method in ASTM A370-94.

Test pieces

The standard tensile test pieces shall be in accordance with those recommended in NACETM0177-96 (Method A). Where full-size test pieces can not be achieved then sub-size test

pieces in line with NACE TM-0177-96 may be used.

Test Duration

The test duration shall be 720 hours

Data Reporting

Data reporting shall include test piece geometry, test solution and conditions (temperature, gasmixture), pH (initial and final), loading device used, test duration, test result (failure/pass) andtest piec

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