Guidelines for Selecting Downhole Tubular Materials for Oil & Gas Production Wells (2000 Edition) J W Martin Major contributors: D Harrop, W Hedges Sunbury Report No. S/UTG/023/00 dated February 2000
Main CD Contents
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 BE UNDERTAKEN. 5 4. USE OF MATERIALS SELECTION ‘ROAD MAPS’ 5. QUESTIONS TO BE ASKED OF PROSPECTIVE SUPPLIERS.
7 11
6. PROPOSALS FOR TESTING CANDIDATE MATERIALS VIA REFERENCED TEST PROTOCOLS. 12 APPENDIX A : GENERAL CORROSION RESISTANCE
13
APPENDIX B : CORROSION RESISTANCE OF CORROSION RESISTANT ALLOYS
40
APPENDIX C : WHAT IS THE DEFINITION OF A "SOUR ENVIRONMENT"?
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APPENDIX D : SULPHIDE STRESS CRACKING
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APPENDIX E : WHAT OTHER FACTORS NEED TO BE CONSIDERED?
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Introduction
1. INTRODUCTION Material selection of downhole tubulars is an important aspect of completion design. If the wrong material is selected then premature failure can result, with considerable cost implications in both replacing the tubulars and lost production.
The purpose of this document is to provide clear guidance that can be used by engineers to carry out a “first stage” evaluation of the material requirements for the downhole tubulars. The guidelines cover all aspects of corrosion and stress corrosion resistance, including sulphide stress cracking in sour environments. Where the guidelines are unable to give unequivocal recommendations on the material to be selected, test protocols are referenced which will allow the 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 (‘road maps’) 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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Background Information on Corrosion Aspects
2. BACKGROUND INFORMATION ON CORROSION ASPECTS. Background information on the various corrosion aspects relevant to the selection of materials for downhole tubulars is contained in the Appendices. The subject matter of the appendices is as follows: Appendix A. Corrosion resistance of carbon/low alloy steels. This appendix describes how the CO2 corrosion rate for carbon/low-alloy steel can be estimated. A method for deciding whether the predicted corrosion rate will result in an acceptable service life for carbon/low-alloy steel is indicated. Advice is given on what to do if the corrosion rate estimates indicate that carbon/low-alloy steel would not give an adequate life. This appendix also includes a discussion on the use of downhole corrosion inhibition programmes as a means of utilising carbon/low-alloy steel tubulars under corrosive conditions where 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 is considered, particularly at the elevated temperatures often experienced downhole. One of the most important aspects to be considered in selecting the right corrosion-resistant alloy (CRA) for the intended application is the material's resistance to localised corrosion. The two 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 the upper temperature limits for CRAs to avoid pitting corrosion and how to avoid crevice corrosion. Of the CRAs more commonly used for downhole tubulars, stress corrosion cracking is mainly a concern with austenitic and duplex stainless steels. The mechanisms are discussed in the appendix, together with advice on the application limits for the alloys to avoid stress corrosion cracking 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 considered as "sour". This is based upon the definition of NACE Standard MR-0175 “Standard Material Requirements - Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment”. Appendix D. Sulphide Stress Cracking This appendix describes the mechanism of sulphide stress cracking in sour conditions. NACE Standard MR0175 is concerned with the resistance of materials to sulphide stress cracking (SSC) in sour conditions. In some countries, such as the United States, the standard is a legislative requirement, i.e. it must be applied there. Its application in materials selection is discussed in the appendix. It was recognised within BP some time ago that the use of the NACE Standard MR0175 alone is not sufficient to allow the selection of the optimum material with adequate sulphide stress cracking resistance. For example, the NACE Standard makes no reference to the “in-situ” pH, which is known to affect the likelihood of sulphide stress cracking (SSC) of materials. In
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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 conservative regarding which materials are acceptable for hydrogen sulphide service. Finally, there is insufficient information in the NACE standard regarding the operating limits of many corrosion-resistant alloys. Therefore, BP developed a methodology based upon laboratory test results and some limited field experience, to allow the user to select the correct material for the 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 sour conditions are discussed, as are the effects of elevated temperature on the material strength and isotropy in the cold worked duplex stainless steels. Flow-Induced Damage - Erosion and Erosion-Corrosion - mechanisms of erosion and erosion-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 to avoid it in completion design.
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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 for downhole tubulars. However it is realised that, especially at the concept stage, the full suite of required information may not be available. Therefore in the following listings two types of data have 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 final specification 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 CO2 in 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 desireable but 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 CO2 and H2S in a gas in equilibrium with the fluids (requires knowledge of the bubble point pressure for oil wells) • The operating and design pressures/temperatures (bottom hole, well head flowing/shut-in) • The expected flow rates and regimes • The likelihood of sand production and likely rates (pptb [i.e. lbs/thousand barrels] for liquid flows, lbs/mmscf for gaseous flows) • The water chemistry (to include full water analysis [Na+, Ca2+, K+, Mg2+, Fe2+, Ba2+, Sr2+, Cl-, S2-, SO42-, HCO3-], amounts of fatty acids/salts [e.g. acetate, propionate, butyrite and associated acids], pH) • Water Dewpoint Temperature for gas wells (if condensing water only is anticipated this will help determine whether the downhole completion will be ‘water wetted’ or not)
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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 in cold climes)
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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 tubular material. These are: (a) Materials Selection for Sweet Conditions - This should be used for well conditions where there is no hydrogen sulphide present, or where only very low levels of hydrogen sulphide are anticipated such that the conditions would not be considered ‘sour’ (refer to Appendix C for definitions of ‘sour’ service). (b) Materials Selection for Sour Conditions (Carbon/Low Alloy Steels) - This should be used for sour conditions where the well fluid corrosivity is such that carbon/low alloy steels are considered suitable (refer to Appendix A regards well fluid corrosivity). (c) Materials Selection for Sour Conditions (Corrosion Resistant Alloys) - This should be used for sour conditions where the well fluid corrosivity is such that carbon/low alloy steels are not considered 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 not on the Road Maps that need to be considered in the materials 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 intention is rather to flag the major considerations that need to be made in selecting downhole tubular materials. 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 aspects of materials selection have been addressed before the final specification of materials. In the ‘road maps’ decision points at which it will be necessary to consult the relevant specialist/s have been highlighted. The relevant specialists have not been identified in these maps due to the likelihood of changes through the life of the document. If you are unsure who the relevant specialist is, then advice on contacts should be available via the ‘Corrosion & Materials’ Networks. In general, the ‘road maps’ are intended to be self explanatory. If further information is required on any of the aspects raised, the relevant specialist/s should be contacted.
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Use of Materials Selection Road Maps
MATERIALS SELECTION FOR SWEET CONDITIONS NOTES (1) Gas fugacity should strictly be used which is what the corrosion Isoplots are based on. The difference between fugacity and partial pressure becomes significant at high pressures where simply using partial pressure will result in over-estimating the corrosion rate and under-estimating the pH. (2) If acetic acid is present in the produced water this can suppress formation of potentially protective iron carbonate scales resulting in a higher than predicted corrosion rate. This may also raise the value of Tscale and the onset of the associated limiting corrosion rate condition; and how to view the impact of erosion in the preence or absence of a protective scale. Care must be exercised when applying the pH and CO 2 Corrosion Isoplots in the presence of acetic acid and it is recommended that Specialist Advice is sought under such circumstances. (3) It may be necessary to complete with a suitable CRA below the corrosion inhibitor injection point if treating by continuous injection. See also the section on Corrosion Inhibition in Appendix A. (4) If a corrosion inhibitor film and / or protective corrosion scale is present a √ρ should be applied - ρ is the fluid density in limiting of velocity ≤ 200/√ρ lbs/ft3 (1 kg/m3 = 0.06242). See also the Erosion Section in Appendix E. (5) The corrosion rate of 13%Cr does vary with T, PCO2 and pH in a similar manner to carbon steel, although the corrosion rates are very much lower. For information on calculating corrosion rates and on pitting behaviour for 13%Cr see Appendix B. (6) At high T and/or high chlorides 13%Cr will exhibit increased susceptibility to pitting. Under such conditions Appendix B should be consulted. If in any doubt Specialist Assistance should be sought.
INPUT
ë PCO2 / bara (1) ë T oC
NO
CONSULT
in situ pH?(2)
pH Isoplots
YES
H2S present?
YES
q If PCO2 /PH2S ≤ 10 then pH Isoplot is affected by presence of H2S - Seek Specialist Advice. q H2S can reduce general corrosion rate by a factor 10 or more due to formation of FeS - no account taken in CO2 Isoplots. q H2S most likely to cause localised or pitting corrosion. q Pitting rate taken as that from the relevant CO2 corrosion Isoplot; but can get localised acidification inside a pit and galvanic affect of FeS film accelerating pitting rate.
CONSULT Materials Selection for Sour Conditions Road Maps
NO
Totally Solids Free
Solids present?(2)
Yes/Don’t Know!
CONSULT
NO Specialist Advice
Erosion Rate ≤ 0.1 mm/y
Erosion Section of Appendix E
YES
YES
V > 13 m/s
• CO 2 Corrosion Isoplots only strictly apply for velocities ≤ 13 m/s - use with caution beyond this! • If in any doubt - Seek Specialist Advice.
NO
Detailed analysis
?
CONSULT
NO
CO2 Corrosion Isoplots (2)
CR ≤ 0.1 mm/y
YES
Specialist Advice
q Can use carbon or low alloy steels q If H2S present note limits this may impose - See Materials Selection for Sour Conditions Road Map q The affect of acetic acid can be particularly pronounced here and inhibition may be required(3, 4)
0.1mm/y
YES q Carbon steel + corrosion Inhibitor can be considered(3, 4) q Check economics and logistics against 13%Cr q If H2S present consult Materials Selection for Sour Conditions Road Map
NO
0.1mm/y
NO
YES q Seek specialist advice on feasibility of carbon steel + corrosion inhibitor (3, 4) q 13%Cr likely to be best option(5, 6) but care needed above 120 oC q If H2S present consult Sour Service Road Map
CR>10mm/y T ≤ 175 oC
T>175 oC
Specialist Advice
YES q 13%Cr should be considered(5, 6) but care needed above 120 oC q Super or Hyper grades 13%Cr for T < 175 oC q If H2S present consult Materials Selection for Sour Conditions Road Map
q GRE lined tubing is a possible alternative standalone option, but is not commonly used for producing wells: main application is water injection. Specialist advice should be sought if T > 80oC q The economics of using CRA internally clad carbon steel over that for solid CRA are questionable. There is limited experience with use of CRA clad tubing.
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Use of Materials Selection Road Maps
MATERIALS SELECTION FOR TUBULARS - SOUR CONDITIONS- CARBON/LOW ALLOY STEELS KNOWN DATA THE CONDITIONS ARE ’SOUR’ WITHIN THE DEFINITIONS OF NACE MR-0175 CARBON/LOW ALLOY STEEL HAS ADEQUATE CO2 CORROSION RESISTANCE (SEE CHART I) REQUIRED TUBULAR STRENGTH IN-SITU pH AND pH2S OPERATING & DESIGN TEMPERATURES
Apply Requirements of NACE MR-0175
Yes
Is the use of NACE MR-0175 a statutory requirement for this area?
No
Consider use of the BP Amoco Methodology
Alternatively can use NACE MR-0175
Consideration can also be given to using N80(Q+T), C95 or proprietary Q+T grades with a MAXIMUM yield strength of 110ksi1
=>65oC
What is the MINIMUM exposure temperature?
Establish required material strength and downhole pH and pH2S <65oC
Sulphide Stress Cracking Performance Domain of “Sour Resistant” Grade 110ksi Steel
Consideration can also be given to using H40, N80, P110 or proprietary Q+T grades with a MAXIMUM yield strength of 140ksi1
=<95ksi
Refer to Domain Diagram for the material with adequate strength. If no material with suitable pH/pH2S resistance can be identified apply requirements of NACE MR-0175
What is the required material strength?
Solution pH
6.5
=>80oC
Acceptable 5.5
4.5 Unacceptable 3.5 0.003 0.001
=>107oC
Consideration can also be given to using Q1251,2
0.1
1.0
10
Sulphide Stress Cracking Performance Domain of Grade N80 Carbon Steel
Sulphide Stress Cracking Performance Domain of Grade P110 Carbon Steel
>95ksi
6.5 Acceptable
Solution pH
Notes. 1. If temperatures below this minimum are expected, even for short periods 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 be given to using proprietary sour resistant grades up to 110ksi SMYS (Consult relevant specialists)
Solution pH
6.5
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0.01
pH2S (bara)
Consider API 5CT Grades H403; J55; K55; L80 (Type 1) C90 (Type 1); T95 (Type 1)
5.5
4.5
Acceptable 5.5
4.5 Unacceptable
Unacceptable 3.5
3.5
0.003
0.003 0.001
0.01
0.1
pH2S (bara)
1.0
10
0.001
0.01
0.1
1.0
10
pH2S (bara)
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Use of Materials Selection Road Maps
MATERIALS SELECTION FOR TUBULARS - SOUR CONDITIONS- CORROSION RESISTANT ALLOYS KNOWN DATA CRA GRADE REQUIRED TO OBTAIN ADEQUATE CO2 CORROSION RESISTANCE (SEE CHART I) REQUIRED TUBULAR STRENGTH IN-SITU pH AND pH2S3 OPERATING & DESIGN TEMPERATURES PRODUCED WATER CHEMISTRY (CHLORIDE LEVEL)
Notes: 1. Where more than one possible candidate material is identified, the materials should be considered in terms of increasing cost/corrosion resistance, i.e. L80 13Cr Steel 95ksi and 110ksi ‘Super 13Cr’ Alloys 22%Cr Duplex Stainless Steel 25%Cr Duplex Stainless Steel. 2. For the ‘Super 13Cr Alloys’ Domain Diagrams have been developed for high chloride (typical of produced water in oil/gas wells) and low chloride (typical of condensing water in gas wells) conditions. For intermediate chloride levels two courses of action are available: Default to the high chloride domain diagram Produce/use test data (pre-qualification) for the specific application that demonstrates acceptability. 3. For high levels of H2S and/or for very high temperatures it may be necessary to consider the use of highly alloyed austenitic stainless steels (e.g. Sanichro 28, NIC-32, Incoloy 825) for temperatures below 175oC or nickel alloys (e.g. Hastelloy G3, Hastelloy C-276) for temperatures aboove 175oC. Contact the relevant specialists.
Refer to Domain Diagram for the materials with adequate strength and corrosion resistance (Refer to Chart I). Consider in order of increasing cost/corrosion resistance1 to select ‘optimum’ material
If no material with suitable pH/pH2S resistance can be identified refer to relevant specialist
95ksi Super 13Cr Alloys2
22Cr Duplex Stainless Steel 6.5
110ksi Super 13Cr Alloys2 6.5
6.5
Acceptable Further Assessment Required
Solution pH
Acceptable Acceptable
5.5
5.5
5.5
4.5
4.5
4.5 Further Assessment Required
Unacceptable 3.5
Unacceptable
3.5
3.5
Unacceptable
0.02 0.001
0.01
0.1
1.0
10
0.001
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 22Cr Duplex Stainless Steel
L80 13Cr Steel
0.01
0.1
1.0
10
0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 110ski Super 13Cr Alloys in high Chloride (120,000 ppm Cl) Waters
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 95ski Super 13Cr Alloys in high Chloride (120,000 ppm Cl-) Waters
25Cr Duplex Stainless Steel 6.5
6.5
6.5
6.5
Solution pH
Solution pH
Acceptable Acceptable
5.5
4.5
5.5
5.5 0.5
4.5
4.5
0.25
3.5
4.5
Further Assessment Required
Unacceptable Unacceptable
3.5
Further Assessment Required
Acceptable
5.5
Acceptable
3.5
Unacceptable
3.5
Unacceptable
0.003 0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of API5CT L80 13Cr Steel
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0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 25Cr Duplex Stainless Steels
0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 95ski Super 13Cr Alloys in low Chloride (1000 ppm Cl-) Waters
0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 110ski Super 13Cr Alloys in low Chloride (1000 ppm Cl-) Waters
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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 the intended duty, it may be necessary to consider the use of a 'proprietary' material outside the scope 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 be suitable 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 service conditions? (b) Will the material have adequate resistance to sulphide stress cracking under all conditions likely to be experienced during service? (c) Will the material have an adequate combination of material strength and toughness under the 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 a result of chlorides)? If so, will it have adequate resistance under the expected service conditions? (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 with respect 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 prevailing conditions?
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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 for the intended duty, it may be necessary to consider carrying out laboratory corrosion tests to select the optimum material for the intended application. Aspects that need to be considered in these 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, together with constant extension rate tensile (CERT) and double cantilever beam (DCB) tests if necessary. 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 corrosionresistant alloys, in particular the duplex and austenitic alloys. A testing protocol is outlined in Appendix B. (c) Resistance to general and pitting corrosion. The resistance to general and/or pitting corrosion shall be determined using an "immersion corrosion test". A testing protocol is outlined in Appendix B.
1
"Materials Assessment for Downhole Sour Service Applications; An overview", Sunbury Branch Report PFB/135/124159, 14th May 1991.
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Appendix A
APPENDIX A : GENERAL CORROSION RESISTANCE 1. CO2 Corrosion CO2 corrosion, or ‘sweet corrosion’, is the most prevalent form of attack associated with oil and gas production and its understanding, prediction and control are key requirements to sound design and subsequent assurance of operational integrity. The form of attack is often localised - frequently referred to as Mesa attack - and, together with dissolved CO2 content and 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 CO2 corrosion rate for carbon and low alloy steels. Of these the most commonly used is that of de Waard (Shell) et al which is empirical in origin although its general applicability has been confirmed by test work in several independent laboratories 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 and formation of iron carbonate scale - both factors being affected by [HCO3-] (the concentration of bicarbonate ions), PCO2 and T. The influence of flow - as mass transfer is a component in the overall CO2 corrosion reaction - has been factored into the latest version of the de Waard model on a semi-empirical basis. Correlation with field data generally shows the de Waard model usually provides an acceptable prediction of the worst case situation. The BP Amoco Corrosion Prediction Modelling guidelines2 use the latest versions of the de Waard model adapted to include BP’s experience and philosophy for application. These guidelines provide a comprehensive approach to determining CO2 corrosion rate and the application to detailed design. No such models exist for Corrosion Resistant Alloys. However, standard grade 13% Cr does exhibits a CO2 corrosion rate, albeit much lower than for carbon steel. Limited laboratory work at BP Amoco, Sunbury(2) found that for a given set of conditions multiplying the predicted CO2 corrosion for carbon steel by 0.0016 gave a reasonable estimate of that for 13% Cr. Further information on the estimation of CO2 corrosion rates for 13%Cr steel is given in Appendix B of these Guidelines. Duplex stainless steels and higher alloys are highly resistant to purely CO2 corrosion and as such this is not a consideration in itself in determining the suitability 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/or cracking are the primary concerns (see Appendices B and D for further information). There are no available CO2 corrosion models able to take direct account of the affect of H2S if present- other than the small affect on pH. The presence of H2S may cause the models to over predict 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 corrosion under extreme conditions. The other major complicating factor for predicting CO2 corrosion is the presence of acetic acid. The influence of acetic acid is not well understood and is still being actively researched. A primary role appears to be suppression of the formation of protective iron carbonate scale; but there is also evidence of a ‘direct’ affect on corrosion rate especially at low PCO2 where the purely CO2 corrosion rate - ie. in the absence of acetic acid - would be acceptably low. As
2
“Corrosion Prediction Modelling”, Sunbury Report Number ESR.96.ER.066, November 1997.
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Appendix A
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 under certain conditions the CO2 corrosion rate is moderated by the presence of an iron carbonate corrosion scale. If erosion is an issue this may lead to under prediction of the associated CO2 corrosion rate when simply applying the BP Amoco Guidelines(2). Erosion and erosioncorrosion 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 these Guidelines. This is based primarily on consideration of the CO2 corrosion rate, but also takes account 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 letters refer to the various Information (indicated by a •) or Decision (indicated by a ♦) boxes on the Road Map.
• Input The primary inputs are temperature (T in oC) and partial pressure of CO2 (PCO2 in bara) defined as: PCO2 = (mole % CO2 x Ptotal)/100. The worst downhole conditions (upper limit) will be at the Bubble Point which defines the maximum amount of dissolved CO2 and hence the maximum PCO2 in terms of CO2 corrosion rate. If the Bubble Point is not known the default should be the bottomhole flowing or reservoir conditions - a conservative position. The lower limit will be determined by the wellhead flowing conditions. ♦ In situ pH? For corrosion to occur free water must be present at the pipe wall. For a gas well operating above the dew point corrosion should not be a concern. For oil wells the water cut and flow regime will be critical to determining if the pipewall is waterwetted. A complicating factor for oil / water systems is the emulsion tendency of the crude oil. For fully mixed flowing conditions the resulting emulsion will be water-inoil at low water cuts inverting to oil-in-water at high water cuts. The inversion point will depend on the water cut, temperature and pressure and typically sits at about 30% to 40% water. Exact determination will normally require measurement so the worst case of water wetting should be assumed and refined later subject to specialist advice. It should also be recognised that under certain specific conditions (e.g. conditions/regions close to the gas break-out point) corrosion of carbon steel has been experienced downhole even at very low water cuts (around 1% or even less). Under multiphase conditions a range of flow regimes are possible - eg. for vertical flow: bubble, churn and annular - which will depend on the superficial velocities of the liquid and gas phases, the gas/liquid ratio (GLR) and the angle of inclination. Any concerns should prompt specialist advice being sought. Again the worst case of water wetting should be assumed for the first pass assessment.
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Appendix A
It is important to know the in situ pH at temperature and pressure. If a produced water analysis is available this may well give a measured pH; however, care should be taken to check that this is at temperature and pressure and not for the water after the dissolved gases have been flashed off. The pH Isoplots (in the absence of H2S - see next section for the case where H2S is present) enable a ready estimate of what the in situ pH will be for a given T (up to 120oC - the limit of the pH model used) and PCO2. For gas wells with no production of formation water the condensed water Isoplot should be used. For oil wells the other Isoplots 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 Production Chemist 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 not always analysed for: care also needs to be exercised in how acetic acid is measured in the presence of bicarbonate Acetic acid can suppress the formation of potentially protective iron carbonate scales (discussed later) and will affect the in situ pH. The pH affect is not considered in the pH Isoplots and for any significant levels of acetic acid 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 to develop 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 CO2 the presence of H2S, being and acid gas, 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 corrosion model exists which accounts for CO2 + H2S metal loss corrosion, but in conjunction with the pH Isoplots the following may be applied in their use when H2S is present. PH2S (bar)
PCO2 (bara) below which the pH Isoplot is affected by H2S
0.0001
Not affected
0.001
0.01
0.0034 (NACE sour service limit for carbon steels, refer to Appendix C)
0.01
0.01
0.1
0.1
1
Where H2S is present below the above PCO2 limits increased acidification will result ie. PCO2/PH2S ≤ 10. This can range between 0.5 and 3 pH units depending on the actual PCO2/PH2S ratio and here pH modelling for the specific conditions is required.
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Once the pH has been fixed the CO2 Corrosion Isoplots can be consulted subsequent to satisfying the remaining questions in the Road Map. For many cases where H2S is present a protective iron sulphide film is readily formed often leading in practice to very low corrosion rates below those given in CO2 Corrosion Isoplots. However, should this protective film breakdown highly localised corrosion can result at rates at least equal to those given in the Corrosion Isoplots: the risk will be greater where erosion is a concern. Consequently, designing on the basis of achieving protection from formation of an iron sulphide film is not recommended. Furthermore, subsequent inspection 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 of metal wastage that will be at least additive to that due to the CO2 corrosion. Appendix E provides guidelines for limiting the erosion rate to ≤ 0.1 mm/yr. It is considered that as long as the rate of erosion can be limited to 0.1mm/yr or less then the risks of unacceptable 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 iron carbonate scale forms when a critical temperature, Tscale, is exceeded for a given PCO2. The CO2 corrosion model used to generate the Corrosion Isoplots treats the influence of protective corrosion scale as being a limiting effect on corrosion rate ie. for all temperatures > Tscale the corrosion rate is equal to that at Tscale. The following graph shows how Tscale varies with PCO2. 230 210 190 170 150 130 110 90 70 50 0.0001
0.001
0.01
0.1
1
10
P C O 2 , bar
The nature of and long term dependence on such scale for protection is a subject still being researched and one where there are conflicting results and experience i.e. in practice corrosion rate often decreases for temperatures > Tscale but there are some examples of the reverse effect. The BP Amoco approach is therefore a pragmatic one for design purposes.
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As mentioned previously the presence of acetic acid can suppress the formation of iron carbonate scales and /or maybe raise Tscale to a value higher than that given above. Erosion studies at Tulsa University have shown that where a protective iron carbonate scale is formed but becomes damaged due to erosion rapid, highly localised corrosion can result. Therefore if the erosion rate is > 0.1 mm/y and the temperature is > Tscale Specialist Advice should be sought. 13%Cr Stainless Steel Erosion, where the predicted rate is > 0.1 mm/y, will remove the naturally forming 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 which the 13%Cr is able to repassivate. For further information reference should be made to Appendix E of these Guidelines and the BP Amoco Erosion Guidelines Duplex Stainless Steels These materials generally do not suffer from CO2 corrosion and so under erosive conditions the wastage rate will equal the erosion rate. u Flow Velocity > 13 m/s? The 13 m/s limit applies only to carbon and low alloy steels and arises from the fact the CO2 corrosion model used to generate the Corrosion Isoplots was developed from corrosion data obtained at velocities up to 13 m/s. As the relationship is principally empirical, extrapolation beyond this limit is questionable and Specialist Advice should be sought. The CO2 Corrosion Isoplots were in fact developed for a nominal fluid velocity of 3 m/s and pipe internal diameter of 4.5”. While the CO2 corrosion rate is sensitive to velocity - 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. n Consult CO2 Corrosion Isoplots The CO2 Corrosion Isoplots provide a simple means of quickly estimating what the corrosion rate for carbon and low alloy steels will be for the conditions of interest. For 13%Cr stainless steel refer to Appendix B. . If you feel uncomfortable using this simplified approach, a more detailed analysis maybe appropriate and can be acgieved using the CO2 corrosion model: this is best done in consultation with Specialist Advice. 2.2. Corrosion Inhibition This is covered in more detail later in this Appendix. BP Amoco experience and application predominantly lies with flowlines and main export lines. The logistics, ease of deployment and ability to effectively monitor performance downhole are important considerations which generally have limited use of this approach for corrosion control downhole. There are differences within the industry about how to account for inhibited corrosion rate at the design stage. The BP Amoco Corrosion Prediction Guidelines2, for design purposes,
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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 / operational life will be the time during which inhibitor is effectively deployed - due to upsets, under injection, failed injections pumps etc. Applying this approach leads to a predicted effective inhibited corrosion rate (CRinh) of: CRinh = (0.1 x T + CRuninhib x (DL - T))/DL where T is the time in years with effective inhibitor deployment (inhibitor availability), DL is the design / field / operational life in years, (DL - T) is the time in years where effective inhibitor depolyment is not achieved, and CRuninhib is the uninhibited CO2 corrosion rate taken from the Corrosion Isoplots or from running a more detailed analysis using the BP Amoco CO2 Corrosion model2. Inhibitor availability is normally taken as a maximum of 95% of DL for 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) and water (GRE lined tubing) and there is the risk of collapse under rapid decompression due to gas permeating behind the coating / liner. In addition, the coatings/linings have upper temperature limitations, the limiting temperature being dependant upon which coating/lining is used. However, mechanical robustness is probably the most important consideration - during handling / installation and subsequent running of downhole tools and wirelining operations. Plastic coated tubing is particularly prone to mechanical damage, especially at joints, and as such 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 CO2 corrosion rates are unacceptably high, the use of 13%Cr stainless steel is often the most 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 is 0.1bara 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 Sour Condition Road Maps for further information) . The material also has limitations in terms of pitting resistance which is temperature and chloride concentration dependent (refer to Appendix B for further information: as a rule of thumb, its use is acceptable for chlorides < 50,000 ppm and temperatures ≤ 120oC. For temperatures > 120oC or chlorides above 50,000ppm refer to Appendix B and/or specialist advise should be sought. The so called Hyper or Super grades of 13%Cr now available offer improved pitting and SCC resistance, a higher temperature limit (ca. 175oC and no specific limit on chloride concentration). However, they are not generic materials and performance is dependent on composition, which differs from supplier to supplier, and specific application may require laboratory testing to confirm suitability. Higher strength grades than API 5CT L80 13Cr steel (i.e. 95ksi and 110ksi) are now readily available but resistance to H2S remains a major limitation (refer to Appendix D). There also remains some question as to whether these alloys are prone to chloride stress corrosion cracking (refer to Appendix D). For use of higher CRAs - this will most commonly be duplex stainless steels - Specialist Advise should be sought. Here there is a significant Capex cost penalty - duplex stainless steel grades are typically 6 to 8 times the material cost of carbon steel; 13%Cr steel grades are
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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 not adequate to guarantee a suitable service life, alternatives will need to be sought. One such alternative 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 for corrosion 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 of this method, i.e. sand production, flow rate, etc. can all affect the effectiveness of the corrosion inhibitor programme, logistics of inhibitor supply to remote locations needs to be considered (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 inhibition scheme. For these reasons it had not been common practice within BP to consider downhole corrosion inhibition as a design strategy, rather this has been viewed as a corrective measure in circumstances where the specified carbon steel proved inadequate, e.g. due to changing field conditions. The preference within BP has been to use corrosion resistant alloys in circumstances where carbon steel proved inadequate. However, given the ever changing face of new field developments (e.g. the development of onshore gas and oil fields, the need to minimise 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, inhibition is usually the most economic option. For very short pipe sections the use of corrosion resistant alloys is the best option. For wells the answer is not always clear cut and is dependant on several factors. This usually simplifies 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 reduces CAPEX. • If inhibitors are to be used in the flowline and pipeline systems then moving the location of the injection point downhole essentially provides inhibition of the well without additional inhibitor costs. • If the actual conditions differ from those predicted the type of inhibitor can be changed to deal with them. Concerns with Inhibition • If corrosion rates are high then any interruption in the scheduled treatment may result in significant damage.
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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 a film on the surface which lasts until the next treatment. This method is not preferred, as its effectiveness 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 is not 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 protective film. Inhibitor must always be present in the fluid for the film and therefore the protection to be 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 it completely. 3. Care is taken to ensure the fluid does not enter the formation. 4. The fluid is allowed to contact the tubing for several hours ( 4 -24 ) 5. The well is brought back onto production 6. Treatment is repeated every 2 to 12 weeks depending on conditions This treatment is used successfully on low productivity wells such as rod pumped oil wells in Texas, USA. Until 1998 BP Alaska used this method for their oil wells. The repeat interval was 12 weeks. The treatment was stopped when the film life was determined to be less than one week.
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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. This minimises the volume of inhibitor used and potential problems encountered when the well is returned 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 high density brine. This allows the inhibitor to ‘fall’ to the bottom of the well under the influence of gravity and thus minimises the volume of solvents and intervention required. There is insufficient 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 may be thought of as pseudo continuous methods. They can provide longer times between treatments. 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 is usually fabricated into spheres or sticks which are ‘dropped’ or placed down the tubing where they 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 As already stated, continuous treatment is the preferred method. However, it is essential that regular checks be made to ensure that: 1. The product is transported throughout the entire system to be protected. 2. The inhibitor is providing the required corrosion protection 3.2.1. Capillary String (Macaroni string) A capillary string, typically 6mm ( ¼” ) diameter, is run from the wellhead and down the annulus space to the bottom of the well, where it is connected to an injection valve into the tubing. This location is usually just above the packer and so tubing below this must be resistant to corrosion or be in non corrosive service.
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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 to allow fluid in the annulus to be pumped into the tubing. The annulus is filled with a solution of the inhibitor which is also pumped into it on a continuous basis. As the pressure in the annulus rises it will exceed the differential setting on the valve and product will be injected into the tubing. 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.
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pH ISOPLOTS
10
P CO2 , bara
1
0.1
0.01
0.001
0.0001 -4
-3
-2
-1
0
1
Log(Pco2)
Conversion of PCO2 to Log10 (PCO2) for use in subsequent pH Isoplots
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pH ISOPLOTS
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
6.50 6.00 5.50 5.00 4.50 4.00
-4
3.50
-3
3.00 120
-2 110
100
-1 90
80
Temperature, degC
70
Log(Pco2)
0 60
50
40
1 30
This case assumes no significant concentration of dissolved salts present and represents water condensing from a wet gas.
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pH ISOPLOTS
3.5% Brine + 50 ppm Bicarbonate
8.00-8.50 7.50-8.00 8.50
7.00-7.50
8.00
6.50-7.00
7.50
6.00-6.50 5.50-6.00
7.00
5.00-5.50
6.50
4.50-5.00
6.00
4.00-4.50
5.50
3.50-4.00
5.00
3.00-3.50
4.50
-4
4.00 -3
3.50 3.00 120
-2 110
100
-1 90
80
70
Temperature, degC
Log(Pco2)
0 60
50
40
1 30
10% Brine + 50 ppm Bicarbonate
8.00-8.50 7.50-8.00 8.50
7.00-7.50
8.00
6.50-7.00
7.50
6.00-6.50 5.50-6.00
7.00
5.00-5.50
6.50
4.50-5.00
6.00
4.00-4.50
5.50
3.50-4.00
5.00
3.00-3.50
4.50
-4
4.00 -3
3.50 3.00 120
-2 110
100
-1 90
80
Temperature, degC
February 2000
70
Log(Pco2)
0 60
50
40
1 30
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pH ISOPLOTS
3.5% Brine + 100 ppm Bicarbonate
8.50-9.00 8.00-8.50 7.50-8.00
9.00
7.00-7.50
8.50
6.50-7.00
8.00
6.00-6.50
7.50
5.50-6.00
7.00 6.50
5.00-5.50 4.50-5.00
6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
4.00-4.50 3.50-4.00 3.00-3.50 -4 -3 -2 110
100
-1 90
80
70
Temperature, degC
Log(Pco2)
0 60
50
40
1 30
10% Brine + 100 ppm Bicarbonate
8.50-9.00 8.00-8.50 7.50-8.00
9.00
7.00-7.50
8.50
6.50-7.00
8.00
6.00-6.50
7.50
5.50-6.00
7.00 6.50
5.00-5.50 4.50-5.00
6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
4.00-4.50 3.50-4.00 3.00-3.50 -4 -3 -2 110
100
-1 90
80
Temperature, degC
February 2000
70
Log(Pco2)
0 60
50
40
1 30
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pH ISOPLOTS
3.5% Brine + 200 ppm Bicarbonate
8.50-9.00 8.00-8.50 7.50-8.00
9.00
7.00-7.50
8.50
6.50-7.00
8.00
6.00-6.50
7.50
5.50-6.00
7.00 6.50
5.00-5.50 4.50-5.00
6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
4.00-4.50 3.50-4.00 3.00-3.50 -4 -3 -2 110
100
-1 90
80
70
Temperature, degC
Log(Pco2)
0 60
50
40
1 30
10% Brine + 200 ppm Bicarbonate
8.50-9.00 8.00-8.50 7.50-8.00
9.00
7.00-7.50
8.50
6.50-7.00
8.00
6.00-6.50
7.50
5.50-6.00
7.00 6.50
5.00-5.50 4.50-5.00
6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
4.00-4.50 3.50-4.00 3.00-3.50 -4 -3 -2 110
100
-1 90
80
Temperature, degC
February 2000
70
Log(Pco2)
0 60
50
40
1 30
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pH ISOPLOTS
3.5% Brine + 400 ppm Bicarbonate
9.00-9.50 8.50-9.00 8.00-8.50 7.50-8.00
9.50 9.00 8.50 8.00 7.50 7.00 6.50 6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
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 -4 3.00-3.50 -3 -2 110
100
-1 90
80
70
Temperature, degC
Log(Pco2)
0 60
50
40
1 30
10% Brine + 400 ppm Bicarbonate
8.50-9.00 8.00-8.50 7.50-8.00
9.00
7.00-7.50
8.50
6.50-7.00
8.00
6.00-6.50
7.50
5.50-6.00
7.00 6.50
5.00-5.50 4.50-5.00
6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
4.00-4.50 3.50-4.00 3.00-3.50 -4 -3 -2 110
100
-1 90
80
Temperature, degC
February 2000
70
Log(Pco2)
0 60
50
40
1 30
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pH ISOPLOTS
3.5% Brine + 800 ppm Bicarbonate
9.00-9.50 8.50-9.00 8.00-8.50 7.50-8.00
9.50 9.00 8.50 8.00 7.50 7.00 6.50 6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
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 -4 3.00-3.50 -3 -2 110
100
-1 90
80
70
Temperature, degC
Log(Pco2)
0 60
50
40
1 30
10% Brine + 800 ppm Bicarbonate
9.00-9.50 8.50-9.00 8.00-8.50 7.50-8.00
9.50 9.00 8.50 8.00 7.50 7.00 6.50 6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
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 -4 3.00-3.50 -3 -2 110
100
-1 90
80
Temperature, degC
February 2000
70
Log(Pco2)
0 60
50
40
1 30
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pH ISOPLOTS
3.5% Brine + 1600 ppm Bicarbonate
9.00-9.50 8.50-9.00 8.00-8.50 7.50-8.00
9.50 9.00 8.50 8.00 7.50 7.00 6.50 6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
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 -4 3.00-3.50 -3 -2 110
100
-1 90
80
70
Temperature, degC
Log(Pco2)
0 60
50
40
1 30
10% Brine + 1600 ppm Bicarbonate
9.00-9.50 8.50-9.00 8.00-8.50 7.50-8.00
9.50 9.00 8.50 8.00 7.50 7.00 6.50 6.00 5.50 5.00 4.50 4.00 3.50 3.00 120
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 -4 3.00-3.50 -3 -2 110
100
-1 90
80
Temperature, degC
February 2000
70
Log(Pco2)
0 60
50
40
1 30
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CO2 CORROSION ISOPLOTS 10
1
0.1
0.01
0.001
0.0001 -4
-3
-2
-1
0
1
L o g (P c o 2)
Conversion of PCO2 to Log10 (PCO2) for use in subsequent CO2 Corrosion Isoplots
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CO2 CORROSION ISOPLOTS pH 3
55 50 45
n > 10 mm/y n 5 - 10 mm/y n 0 - 5 mm/y
40 35 30 25 20 15
1
10
0
5
-1
0 30
Log(Pco2)
-2 40
50
60
70
-3
80
90
100
110
120
Temperature, degC
130
140
-4 150
pH 3
n n n n n n n n n n
1.0 0.9 0.8 0.7 0.6 0.5 0.4
1
0.3
0
0.2
-1
0.1
-2
Log(Pco2)
-3
0.0 30
40
50
60
70
80
90
100
Temperature, degC
February 2000
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
110
120
130
-4 140
150
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CO2 CORROSION ISOPLOTS pH 3.5
45 40 35
n > 10 mm/y n 5 - 10 mm/y n 0 - 5 mm/y
30 25 20 15
1
10 0
5
-1
0 30
Log(Pco2)
-2 40
50
60
70
-3
80
90
100
110
120
Temperature, degC
130
140
-4 150
pH 3.5
n n n n n n n n n n
1.0 0.9 0.8 0.7 0.6 0.5 0.4
1
0.3
0
0.2
-1
0.1
-2
Log(Pco2)
-3
0.0 30
40
50
60
70
80
90
100
Temperature, degC
February 2000
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
110
120
130
-4 140
150
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CO2 CORROSION ISOPLOTS pH 4
40 35 30
n > 10 mm/y n 5 - 10 mm/y n 0 - 5 mm/y
25 20 15 10
1 0
5 -1 0 30
Log(Pco2)
-2 40
50
60
70
-3
80
90
100
110
120
Temperature, degC
130
140
-4 150
pH 4
n n n n n n n n n n
1.0 0.9 0.8 0.7 0.6 0.5 0.4
1
0.3
0
0.2
-1
0.1
-2
Log(Pco2)
-3
0.0 30
40
50
60
70
80
90
100
Temperature, degC
February 2000
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
110
120
130
-4 140
150
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CO2 CORROSION ISOPLOTS pH 4.5
30
25
n > 10 mm/y n 5 - 10 mm/y n 0 - 5 mm/y
20
15
10 1 5
0 -1
0 30
Log(Pco2)
-2 40
50
60
70
-3
80
90
100
110
120
Temperature, degC
130
140
-4 150
pH 4.5
n n n n n n n n n n
1.0 0.9 0.8 0.7 0.6 0.5 0.4
1
0.3
0
0.2
-1
0.1
-2
Log(Pco2)
-3
0.0 30
40
50
60
70
80
90
100
Temperature, degC
February 2000
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
110
120
130
-4 140
150
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CO2 CORROSION ISOPLOTS pH 5
25
20
n > 10 mm/y n 5 - 10 mm/y n 0 - 5 mm/y
15
10
1
5 0 -1 0 30
Log(Pco2)
-2 40
50
60
70
-3
80
90
100
110
120
Temperature, degC
130
140
-4 150
pH 5
n n n n n n n n n n
1.0 0.9 0.8 0.7 0.6 0.5 0.4
1
0.3
0
0.2
-1
0.1
-2
Log(Pco2)
-3
0.0 30
40
50
60
70
80
90
100
Temperature, degC
February 2000
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
110
120
130
-4 140
150
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CO2 CORROSION ISOPLOTS pH 5.5
20
15
n > 10 mm/y n 5 - 10 mm/y n 0 - 5 mm/y
10
5
1 0 -1
0 30
Log(Pco2)
-2 40
50
60
70
-3
80
90
100
110
120
Temperature, degC
130
140
-4 150
pH 5.5
n n n n n n n n n n
1.0 0.9 0.8 0.7 0.6 0.5 0.4
1
0.3
0
0.2
-1
0.1
-2
Log(Pco2)
-3
0.0 30
40
50
60
70
80
90
100
Temperature, degC
February 2000
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
110
120
130
-4 140
150
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CO2 CORROSION ISOPLOTS pH 6
15
n > 10 mm/y n 5 - 10 mm/y n 0 - 5 mm/y
10
5 1 0 -1 0 30
Log(Pco2)
-2 40
50
60
70
-3
80
90
100
110
120
Temperature, degC
130
140
-4 150
pH 6
n n n n n n n n n n
1.0 0.9 0.8 0.7 0.6 0.5 0.4
1
0.3
0
0.2
-1
0.1
-2
Log(Pco2)
-3
0.0 30
40
50
60
70
80
90
100
Temperature, degC
February 2000
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
110
120
130
-4 140
150
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CO2 CORROSION ISOPLOTS pH 6.5
10
n > 10 mm/y n 5 - 10 mm/y n 0 - 5 mm/y 5
1 0 -1 0 30
Log(Pco2)
-2 40
50
60
70
-3
80
90
100
110
120
Temperature, degC
130
140
-4 150
pH 6.5
n n n n n n n n n n
1.0 0.9 0.8 0.7 0.6 0.5 0.4
1
0.3
0
0.2
-1
0.1
-2
Log(Pco2)
-3
0.0 30
40
50
60
70
80
90
100
Temperature, degC
February 2000
0.9 - 1.0 mm/y 0.8 - 0.9 mm/y 0.7 - 0.8 mm/y 0.6 - 0.7 mm/y 0.5 - 0.6 mm/y 0.4 - 0.5 mm/y 0.3 - 0.4 mm/y 0.2 - 0.3 mm/y 0.1 - 0.2 mm/y 0.0 - 0.1 mm/y
110
120
130
-4 140
150
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APPENDIX B : CORROSION RESISTANCE OF CORROSION RESISTANT ALLOYS 1. General corrosion resistance of corrosion-resistant alloys. It should not be assumed that the corrosion-resistant alloys are immune to general corrosion in CO2-containing environments. Specifically, it is known that 13%Cr steel is prone to general corrosion at elevated temperatures. The rate of corrosion will be dependant on a number of factors, including partial pressure of carbon dioxide, solution chemistry (particularly chloride content), 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 steel manufacturers putting a limit of 150oC on the use of 13%Cr steels. The origin of this limit seems to be corrosion tests undertaken by the steel manufacturers in a 5% sodium chloride solution with a CO2 partial pressure of 35bara. In these tests the acceptable corrosion rate was considered to be 1 mm/yr, which occurred at 150oC. Clearly the use of a single 'blanket' figure of this type will be unacceptable for many circumstances. Firstly, a wastage rate of 1 mm/yr may 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 of 150oC. A simple ‘rule of thumb’ methodology has been established within BPX to obtain a ‘first order’ evaluation of the likely general corrosion rate for 13%Cr steel in sweet or mildly sour conditions, 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 <120°C ⇒ 4.0>pH>3.5 and bottom hole temperature <95°C • At temperatures greater than these limits, or for lower levels of pH, then to a rough first approximation the corrosion rate of 13%Cr steel can be calculated using the following formula: ⇒ Log10 (Vcorr) = 3.0 - 1710/(t+273) + 0.67log10 PCO2 Where: Vcorr is the corrosion rate in mm/yr t is the temperature in °C PCO2 is the partial pressure of CO2 in bara If the value obtained from this analysis represents an acceptable corrosion rate (see Appendix A for further details) then the use of 13%Cr steel can be considered. For conditions beyond those for which the use of 13%Cr steel can be justified it has been necessary to consider higher metallurgies with improved passive films and hence improved general corrosion resistance (e.g. duplex stainless steel, austenitic stainless steel, nickel alloys). However, in the past 2 to 3 years a new family of chromium steels have been developed for
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downhole tubulars known as the ‘alloyed martensitic 13%Cr steels”. These alloys are a development of the ‘conventional’ 13%Cr steels (e.g. API 5CT L80 13%Cr steel) to which alloying 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 the ‘conventional’ 13%Cr steels, including: • Higher strength/toughness (available in strengths up to 110ksi) • Much better corrosion resistance at high temperatures (>120°C) • Slightly better resistance to sulphide stress cracking under sour conditions (i.e. for the same strength level) These have been found to have good general (and pitting) corrosion resistance over a wide range of conditions up to a temperature of 200°C. 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 200°C. Some manufacturers on the other hand indicate that these alloys have good general/pitting corrosion resistance for all levels of chlorides only up to a temperature of 175°C. Therefore, given that this is a relatively new family of materials with a potentially wide range of chemical compositions and that field experience is relatively limited further laboratory testing will be required for specific field applications. 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. The likelihood/rate of pitting corrosion is dependant on a number of factors, notably produced water chemistry (particularly chloride content, pH), level of dissolved gases (CO2, H2S and O2) and operating temperature. However, the pitting process is strongly affected by temperature, with the propensity towards pitting increasing with increasing temperature. The result is that for many CRAs a “critical” temperature 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 the temperature service limits for CRAs. This protocol was used to determine the temperature service limits for two of the most commonly used CRAs for downhole tubulars, i.e. 13%Cr steel (which has been found to be prone to pitting in the presence of hydrogen sulphide) and 25%Cr/7%Ni duplex stainless steel. Two temperatures were determined using different techniques. In the first, an immersion test was used to determine the temperature at which pits start to form, this was designated the “onset of pitting” temperature. However, it was determined that there is a temperature range above the onset of pitting temperature over which only “non-propagating” pits form, i.e. pits will form but they will not grow, such that they are not normally harmful to the integrity of the tubulars. Therefore, an electrochemical noise technique was developed to allow the determination of the temperature at which significant pit growth will commence. This was designated the “propagating pit temperature”. Both these temperature limits are quoted in Table B1 for a range of environments. These temperatures can be used as the service limits for the material/environment combination, with the lower 3
“Downhole Tubulars - Evaluation of the application regimes for super 13%Cr Alloys”; ESR.96.ER.008, January 1996.
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(onset of pitting) temperature limit being used for conditions where even superficial pitting is unacceptable and the upper temperature limit being used where superficial pitting is acceptable, 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 temperature range over which the rate of pitting is “acceptable”, i.e. the required service life will be achieved. For 13%Cr steel, as an initial ‘rough estimate’ the possible rate of pitting can be evaluated 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 is confirmed via service experience under similar conditions or laboratory tests. In the case of duplex 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, it will be necessary to undertake service history evaluations/laboratory tests under the specific field conditions, to demonstrate the acceptability of the candidate materials for the intended service duty/life. When using Table B1 for determining the acceptability of candidate materials for the intended service it will be necessary to know the operating temperature, downhole pH (this can be evaluated 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 acceptable to even higher temperatures than those given, if the intended service conditions are significantly less onerous. This can only be determined by service experience on similar conditions or a series of laboratory evaluations using the test protocols outlined in Section 4 of this appendix (Appendix B). In addition, the use of materials other than those stated in Table B1 will require justification via documented good previous service experience or further testing if there is a concern about pitting corrosion. For the ‘alloyed’ martensitic 13%Cr steels (such as Sumitomo’s ‘Super 13Cr alloy’) tests undertaken at BP Sunbury indicated good general pitting corrosion resistance in a high chloride (120,000ppm) solution at a pH of 3.5 and a temperature of 200°C. However, given that this is a relatively new family of materials with a potentially wide range of chemical compositions and given that field experience is relatively limited it may well be that further laboratory 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" between two adjacent components. Examples of crevices that can occur in downhole tubulars are at interfaces between two joints, under deposits, in contact with downhole jewellery, etc. The local environment produced within the crevice can be quite different to the bulk fluid environment, leading to corrosion damage which could not be predicted from the general fluid composition. The likelihood and rate of crevice corrosion is dependant on a large number of factors. These include solution chemistry and service temperature, as with pitting corrosion. However, the factors also include crevice geometry and the changes in this geometry as the crevice develops. This makes it extremely difficult to establish the "maximum service temperatures" to avoid crevice corrosion. Therefore, in downhole tubular designs steps need to be taken to ensure that crevices are, as far as possible, eliminated. In this way the risk of crevice corrosion can be minimised so that the material can be used up to the service temperature limit indicated from a consideration of pitting corrosion. It is recommended that the following steps are taken to minimise the risk of crevice corrosion: (i) Use only "premium" connections with CRAs. These connections have an energised metal/metal seal on the inner diameter that minimises the size of any crevice so formed. Good experience has been achieved with these types of joint and problems of crevice have only been
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observed under conditions where an unsuitable material was chosen in the first place (e.g. the use 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 affecting the well productivity by affecting the throughput of the tubulars, can lead to crevices at the scale/metal surface interface leading in turn to crevice corrosion. Therefore, if necessary, steps should be taken to prevent significant scale build-up, e.g. by de-scaling treatments, use of scale inhibitors, 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 stress corrosion cracking in downhole environments. Hence there is no need to consider the stress corrosion 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 Sumitomo’s ‘Super 13Cr’ alloys) may be prone to chloride stress corrosion cracking (CSC). However, tests undertaken at Sunbury4 did not reveal any signs of CSC under typical ‘produced 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 data and service experience, care should be taken in their application in respect of the possibility of CSC (e.g. check with the supplier/s and/or undertake evaluations if/when necessary). In addition very recently (i.e. in 1999) there has been a case within BP Amoco of a 95ksi‘alloyed’ martensitic 13%Cr 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 at the present the most likely cause is CSC in the calcium chloride high density completion brine. Therefore, extra care needs to be exercised in the selection of completion 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 downhole environments. This type of cracking is exacerbated by increasing temperature. It is also known that such cracking can be exacerbated by the presence of hydrogen sulphide. The possibility of such cracking has meant that only alloys that are very resistant to it have been selected for downhole applications in the past. For example, the NIC 32, Sanicro 28, type alloys are often considered for downhole tubulars in place of the cheaper and more common AISI 300 series stainless steels. These alloys have not been widely evaluated within BP Amoco. However, there is some limited information available from the manufacturers. For example, NKK indicate a temperature limit for NIC-32 (22%Cr, 4.5%Mo, 32%Ni) of 175°C, if CSC is to be avoided. It is recommended that if such alloys are being considered, the relevant specialist should be consulted.
4
‘Downhole Tubulars - Evaluation of the Application Regimes for Super 13%Cr Alloys’, ESR.96.ER.008, January 1996.
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(c) Duplex Stainless Steels The duplex stainless steels are prone to some "unique" mechanisms of stress corrosion cracking as a result of their duplex (ferrite/austenite) structure. Early work by Japanese steel manufacturers showed that there was a possibility of stress corrosion cracking at elevated temperatures in sodium chloride test solutions containing dissolved CO2 and H2S. The work indicated that stress corrosion cracking was exacerbated by increasing levels of H2S, decreasing pH and increasing chloride content. The cracking is thought to be the combination of a chloride stress corrosion cracking mechanism and a hydrogen assisted mechanism cracking (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 100°C), such that tests are often carried out at 80oC to represent a "worst case". However, work at Sunbury indicated that the temperature range for most severe cracking is dependant on the type of duplex stainless steel and test environment, with the most severe range being 20 to 60°C in some circumstances. Therefore, for any particular environment it is necessary to consider testing across the full temperature 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 downhole tubulars (22%Cr/5%Ni [UNS S31803] and 25%Cr/7%Ni [UNS S32750]). These have been plotted in terms of pH v. PH2S plots, in a similar manner as for sulphide stress cracking (SSC) resistance of ferritic/martensitic materials, as described in Appendix D. For ease of use these have been included with the other Individual alloy ‘go/no go’ charts at the end of these Guidelines. In addition very recently (i.e. in 1999) there has been a case of a 130ksi 25%Cr ‘super duplex stainless 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 at the present the most likely cause is CSC at high temperature (around 130°C) in the calcium chloride high density completion brine. Therefore, extra care needs to be exercised in the selection 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-qualification process to determine the suitability of a candidate material for the intended application with regards to general/localised corrosion resistance:Specimen and Preparation The specimens shall be taken from the tube wall and shall measure a minimum of 25mm x 50mm. Specimens shall be ground flat to a 600# paper finish on one side and left as manufactured on the other side. Specimens shall be thoroughly degreased, dried in a nitrogen gas stream, weighed and finally kept in a desiccator prior to immersion. Solutions a) Prepare base solutions to represent the: • Produced Water Chemistry - for the case of oil wells or gas wells in which produced water is anticipated. and/or
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• Condensed Water - for the case of gas wells. For the purpose of these tests distilled water with 1000ppm of sodium chloride should be used. b) Deaerate fully using ‘oxygen free’ nitrogen prior to specimen immersion. Insert the specimens, close the autoclave and re-deaerate fully by nitrogen. Purge the test solution using the CO2 and/or H2S mixture for a period of at least one hour and then add CO2 and/or H2S up to a suitable pressure such that at the test temperature the partial pressures of these gases anticipated 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 the autoclave wall and other specimens.) Reagents The reagents shall be high purity grades. Acidic Gases High purity CO2 and H2S gas shall be used. Solution Volume This shall be a minimum of 30 cc/cm2 of specimen. Test Duration Test duration shall be kept to a minimum of 30 days. Post Exposure Analysis The specimens shall be examined immediately after exposure and their condition noted. They shall then be mechanically cleaned by scrubbing with a soft brush under 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). Specimens shall 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 case of pitting, all pits which are greater than 0.1mm diameter shall be reported. The report shall include 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 to stress corrosion cracking resistance:Test Solution The test solution shall consist of NaCl (at a concentration to simulate the level of Cl anticipated 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)5 in distilled or de-ionised water. The procedure for solution preparation shall be as follows:a.
prepare a base solution of NaCl in distilled or de-ionised water
b.
Add the sodium acetate (CH3COONa)1
5
As an alternative to the acetate/hydrochloric acid buffering system, a bicarbonate/CO2 buffering system may be offered for approval by BP Exploration.
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c.
Acidise using concentrated hydrochloric acid 1 down to a pH representative of the ‘in situ’ pH anticipated in the downhole tubulars.
d.
Introduce the solution into a test vessel, deaerate and saturate with a mixture of CO2/H2S with the following gas ratios:
H2S at the partial pressure anticipated in the downhole tubulars, with the balance being CO2 up 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 solution volume 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/CO2 gas mixtures shall be used. The test solution shall be purged with the gas mixture 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 specified in NACE TM0177-96 (Method A) and the additional requirements described in this document. Both types of stress fixtures and test containers used for stress corrosion testing are acceptable; namely, constant load devices or sustained load (proof ring of spring loaded) devices (ASTM G49-76). Failure Appraisal Total fracture of a test piece during the 720 hour test period shall be considered a failure. To be considered a pass, the gauge length of the test piece shall be free from any signs of fissure and/or cracks, after the exposure period. This may be assessed through visual
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examination of the gauge length (at a magnification of x10) plus one of the following procedures:• Metallographic examination of the gauge length by longitudinal sectioning and polishing. • 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 and fracture 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 strength shall 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 NACE TM0177-96 (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, gas mixture), 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 CORROSIONRESISTANT ALLOYS TO AVOID LOCALISED CORROSION (a) 13% Chromium Steel MATERIAL
13%Cr steel
13%Cr steel
13%Cr steel
13%Cr steel
13%Cr steel
13%Cr steel
13%Cr steel
13%Cr steel
13%Cr steel
WELL CONDITIONS
6,000ppm Chloride pH = 4.5* pH2S = 0.001 bara 30,000ppm Chloride pH = 4.5* pH2S = 0.001 bara 120,000ppm Chloride pH = 4.5* pH2S = 0.001 bara 6,000ppm Chloride pH = 4.5* pH2S = 0.01 bara 30,000ppm Chloride pH = 4.5* pH2S = 0.01 bara 120,000ppm Chloride pH = 4.5* pH2S = 0.01 bara 6,000ppm Chloride pH = 4.5* pH2S = 0.1 bara 30,000ppm Chloride pH = 4.5* pH2S = 0.1 bara 120,000ppm Chloride pH = 4.5 pH2S= 0.1bara
MAXIMUM TEMPERATURE LIMITS (oC) Onset of Pitting
Pit Propagation
100
140 (GC**)
110
140 (GC**)
120
140 (GC**)
120
130 (P)
120
130 (P)
120
130 (P)
120
120 (P)
120
120 (P)
120
120 (P)
* Note that at pH levels lower than 4.5 13%Cr steels are liable to general corrosion over the whole temperature range. In the case of general corrosion the likely rate of attack can be assessed using the methodology outlined in Section 1 of Appendix B. ** For 13%Cr steel "significant attack" is likely to occur either as pitting corrosion (P) or general corrosion (GC). The likely rate of general corrosion attack can be assessed using the methodology outlined in Section 1 of Appendix B.
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(b) 25%Cr/7%Ni Duplex Stainless Steel
MATERIAL
25%Cr/7%Ni duplex stainless steel 25%Cr/7%Ni duplex stainless steel 25%Cr/7%Ni duplex stainless steel 25%Cr/7%Ni duplex stainless steel 25%Cr/7%Ni duplex stainless steel 25%Cr/7%Ni duplex stainless steel 25%Cr/7%Ni duplex stainless steel 25%Cr/7%Ni duplex stainless steel 25%Cr/7%Ni duplex stainless steel
February 2000
WELL CONDITIONS
6,000ppm Chloride pH = 3.5 pH2S = 0.001 bara 30,000ppm Chloride pH = 3.5 pH2S = 0.001 bara 120,000ppm Chloride pH = 3.5 pH2S = 0.001 bara 6,000ppm Chloride pH = 3.5 pH2S = 0.01 bara 30,000ppm Chloride pH = 3.5 pH2S = 0.01 bara 120,000ppm Chloride pH = 3.5 pH2S = 0.01 bara 6,000ppm Chloride pH = 3.5 pH2S = 0.1 bara 30,000ppm Chloride pH = 3.5 pH2S = 0.1 bara 120,000ppm Chloride pH = 3.5 pH2S = 0.1 bara
MAXIMUM TEMPERATURE LIMITS (oC) Onset of Pitting
Pit Propagation
180
200
160
200
140
200
170
200
140
180
140
180
140
180
130
170
130
170
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Appendix C
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 a liquid, together with hydrogen sulphide at a level exceeding certain criteria, as detailed in Figures C1 and C2. For convenience, these criteria are summarised in Tables C1 and C2. It should be noted that only environments containing liquid water are classified as sour in the context 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 of Hydrogen Sulphide (psia)
Sour Environment (YES/NO)
<65
<0.05
NO
<65
>0.05
NO
>65
<0.05
NO
>65
>0.05
YES
TABLE 2. DEFINITION OF SOUR SERVICE FOR AN OIL WELL (oil/water or oil/water/gas) Total System Pressure (psia)
Partial Pressure of Hydrogen Sulphide in the gas phase (psia)
Mol.-% H2S in the gas phase
Sour Environment (YES/NO)
<265
<0.05
<15
NO
<265
>0.05, <10
<15
NO
>265
<0.05
<15
NO
>265
>0.05
-
YES
-
>10
-
YES
-
-
>15
YES
From the Tables, it is clear that the definition of sour conditions is different for gas and oil wells. For the purposes of this definition any well with a gas/oil ratio of greater than 5000 standard cubic feet per barrel of oil is taken as a gas well. It is also apparent from these Tables that the definition of sour conditions is normally based upon the partial pressure of hydrogen sulphide in the gas phase. To determine the partial pressure of hydrogen sulphide in the gas phase certain field information is required. Considering firstly a gas well, the information required is the bottom hole pressure and the mole (or volume) fraction of hydrogen sulphide in the gas. The partial pressure is then
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calculated simply by multiplying the mole fraction of hydrogen sulphide in the gas by the bottom 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 hydrogen sulphide 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 partial pressure of hydrogen sulphide can be estimated by multiplying the total pressure by the mole fraction 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 hydrogen sulphide that needs to be calculated is that in a gas phase in equilibrium with that dissolved in the well liquids (oil/water). An alternative description of this is the partial pressure of hydrogen 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 by the mole fraction of hydrogen sulphide in the gas phase.
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Appendix D
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 recombine via 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 to form H2 gas and hence encourage the entry of atomic hydrogen into the metal. Once in the metal, the atomic hydrogen will diffuse to "trap" sites, where it will lead to a local increase in the stress and/or a reduction in the strength of the metal lattice. For a material under load there is evidence to suggest that the atomic hydrogen will concentrate near to stress concentrators and may give rise to crack initiation at such points, hence leading to a brittle-like fracture. This type of cracking can occur quite rapidly. Thus even if materials are only to be exposed to sour conditions for short periods of time they must be resistant to SSC. 2. NACE Standard MR0175 (Standard Material Requirements - Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment) The NACE Standard MR0175 is concerned with the resistance of materials to sulphide stress cracking (SSC) in sour conditions. In some countries, such as the United States, the standard is a legislative requirement, i.e. it must be applied there. This document should be referred to for 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 of sulphide stress cracking, particularly for low-alloy steels. Hence, NACE MR0175 allows the use of materials with a specified minimum yield strength above that of the fully sour-resistant grades under circumstances where the minimum operating temperature is above certain limits. The information in Table D1 taken from NACE MR0175-99 details the acceptable tubular material grades for different temperature ranges (refer to NACE MR0175-99 for the full Table).
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Appendix D
TABLE D1. ACCEPTABLE API SPECIFICATIONS FOR TUBULAR GOODS For all temperatures (1)
For operating temperatures 65oC or greater (2)
For operating temperatures 80oC or greater (2)
For operating temperatures 107oC or greater (2)
API Spec. 5CT grades H40 (3); J55; K55; L80 (Type 1); C90 (Type1); T95 (Type1)
API Spec. 5CT grades N80 (Q + T); C95
API Spec. 5CT grades H40; N80; P110
API Spec. 5CT grade Q125. See Note 4.
Proprietary grades Per NACE MR-0175 Section 10.2.
Proprietary Q + T grades with 110ksi or less maximum yield strength
Proprietary Q + T grades with 140ksi or less maximum yield strength.
Notes to Table D1: 1. Impact resistance may be required by other standards and codes for low operating temperatures. 2. Continuous minimum temperature; 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 relatively short time span, so that periods of exposure to sour conditions at temperatures below those stated in the Table could potentially lead to SSC problems. For this reason it is important to note that the temperature levels quoted in Table D1 are the minimum operating temperature the tubing will experience. If temperatures below this minimum are expected even for short periods of time then the non-sour higher strength materials should not be 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 not sufficient to allow the selection of the optimum material with adequate sulphide stress cracking resistance. For example, the NACE Standard makes no reference to the “in-situ” pH, which is known to affect the likelihood of sulphide stress cracking (SSC) of materials. In 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 conservative regarding which materials are acceptable for hydrogen sulphide service. Finally, there is insufficient information in the NACE standard regarding the operating limits of many corrosion-resistant alloys. Therefore, BP AMOCO developed a methodology based upon laboratory test results and field experience, to allow the user to select the most cost-effective material for the intended service. As a result of the concerns over the temperature conditions in Table D1, the decision was made to carry out all testing for the “BP AMOCO methodology” under room temperature conditions, i.e. the "worst case" scenario. Therefore, the methodology described here is
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applicable to all likely operating temperatures (Note: This methodology need not be applied to the traditional ‘sour-resistant grades’ in API 5CT [i.e. L80, C90, T95] which it is assumed are suitable for all sour conditions on the basis of past experience and test data). To apply the BP AMOCO methodology, it is necessary to know certain information about the proposed well, i.e. the partial pressure of hydrogen sulphide in the gas phase, and the “in-situ” pH 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 of certain well information. Once the necessary information has been collected, the conditions can be plotted onto the appropriate “sulphide stress cracking performance domain” charts for individual alloys at the end of these Guidelines. There are two domains identified on the individual alloy “go/no go” charts. If the operating conditions fall within the “acceptable” domain then the material can be considered 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 to consider 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 are comprised of a family of alloys with differing chemical compositions (varying between manufacturers) 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 of interpretation, charts with three domains have been developed. These three domains represent: • Acceptable (Green for ‘go’) - the material is satisfactory for the proposed application. • Unacceptable (Red for ‘no go’) - the material is unsuitable for the proposed application and an alternative material with greater SSC resistance should be considered. • Further Assessment Required (Yellow for ‘caution’) - to assess whether the material is suitable for the intended application or not, further assessment is required in the form of consideration of specific pre-qualification data for the alloy/manufacturer being considered, reference to relevant past test data (e.g. for a similar 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 the materials. 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) conditions. For intermediate chloride levels two courses of action are available: • Default to the high chloride domain diagram • Produce/use test data (pre-qualification) for the specific application that demonstrates acceptability. With regards to the effect of chloride content, the present domain diagrams seem to infer that the 110ksi materials perform better in condensing water conditions. This most probably reflects the improvements in material chemistry and manufacturing methods between the two sets of tests (the 95ksi materials were tested in 1995 and the 110ksi materials were tested in 1998, a time period which saw significant improvements in the manufacturing methods,
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control of chemistry for these materials). Instinctively, if anything, the 95ksi material should outperform the 110ksi material. Therefore, it is recommended that manufacturers are requested to retest the 95ksi materials in low (1000ppm) chloride conditions if intended for use in gas wells where only condensing water will be present and where the partial pressure of H2S is such that it would be in an ‘acceptable’ regime on the attached Regime charts for the 110ksi material but not for the 95ksi material. Given the wide range of proprietary 'super 13Cr alloys' now available on the market, it has not been possible to test all those available. Rather, a few representative materials have been tested. A Qualification Procedure has been developed on the basis of the present results6. It is recommended that all manufacturers are requested to qualify their material using this Qualification Procedure prior to using the material in BP Amoco. This will ensure that, as a minimum, their material conforms with the attached Domain Diagrams. If uncertain whether the prospective manufacturers material has already been pre-qualified contact the relevant specialist within BP AMOCO. It should be noted that the domain diagrams are not “all encompassing”, but only deal with resistance to SSC. Before making the final selection of production tubular material, it will be necessary to consider many other corrosion-related factors. For example, resistance to general/localised corrosion, stress corrosion cracking resistance, etc. under the prevailing conditions. These aspects are covered elsewhere in these Guidelines. In addition, it should be noted that the assessment of the resistance of duplex stainless steels to SSC and stress corrosion cracking (SCC) is considered further in Appendix B. As a result of their ‘unique’ duplex structure consisting of a combination of austenite and ferrite in approximately equal volume fractions, they are prone to a number of unique cracking mechanisms. 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 to determine the suitability of a candidate material for the intended application with regards to sulphide stress cracking resistance:Test Solution The test solution shall consist of NaCl (at a concentration to simulate the level of Cl anticipated 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)7 in distilled or de-ionised water. The procedure for solution preparation shall be as follows:a.
prepare a base solution of NaCl in distilled or de-ionised water
b.
Add the sodium acetate (CH3COONa)5
6
‘Super 13%Cr Alloy Seamless Tubing Pre-qualification Assessment’, J W Martin & R G MacCuish, April 1999. 7
As an alternative to the acetate/hydrochloric acid buffering system, a bicarbonate/CO2 buffering system may be offered for approval by BP Exploration.
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c.
Acidise using concentrated hydrochloric acid 5 down to a pH representative of the ‘in situ’ pH anticipated in the downhole tubulars.
d.
Introduce the solution into a test vessel, deaerate and saturate with a mixture of CO2/H2S with the following gas ratios:
H2S at the partial pressure anticipated in the downhole tubulars, with the balance being CO2 up 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 solution volume 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/CO2 gas mixtures shall be used. The test solution shall be purged with the gas mixture 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 specified in NACE TM0177-96 (Method A) and the additional requirements described in this document. Both types of stress fixtures and test containers used for stress corrosion testing are acceptable; namely, constant load devices or sustained load (proof ring of spring loaded) devices (ASTM G49-76). Failure Appraisal Total fracture of a test piece during the 720 hour test period shall be considered a failure.
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To be considered a pass, the gauge length of the test piece shall be free from any signs of fissure 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 following procedures:• Metallographic examination of the gauge length by longitudinal sectioning and polishing. • 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 and fracture 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 strength shall 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 NACE TM0177-96 (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, gas mixture), 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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Appendix E
APPENDIX E : WHAT OTHER FACTORS NEED TO BE CONSIDERED? Apart from the factors relating to corrosion discussed above, there are a number of other factors that must be considered before finally selecting the material for downhole application. Briefly, the main ones are as follows: 1. Mechanical Properties Clearly it is necessary to ensure that the material selected for the downhole tubulars has sufficient mechanical strength. There are a number of issues that need to be considered in selecting the correct strength grade, i.e.: (i) Maximum strength grade the can be used There are a number of limits on the maximum strength of tubular that can be selected. Principally: (a) Low alloy steels. The 155ksi grade low alloy steels (e.g. XT155) are unsuitable for sour service and should not be considered. (b)13%Cr steels. Generally the highest acceptable strength level for 13%Cr steel is the C95 grade. At strength levels higher than this it is difficult to ensure adequate toughness. Even at 95ksi the required toughness can be difficult to achieve and it is important to ensure the correct requirements (specification) are used. (c) Alloyed Martensitic 13%Cr steels (e.g. ‘Super’ 13Cr) Presently available in two strength levels 95ksi and 110ksi. (d) Duplex Stainless Steels. Generally the highest acceptable strength level for the duplex stainless steels is 125ksi. There is a possible reduction in corrosion/stress corrosion resistance above this level. Duplex stainless steels with higher yield strength levels can be considered on the basis of specific environmental testing for the intended application. (ii) Directionality of mechanical properties It is important to note that the cold worked duplex stainless steels can suffer from a degree of directionality in their mechanical properties, as a result of isotropy induced by cold working processes. This can result in a lower strength in the transverse direction than in the longitudinal direction. The magnitude of this effect will be dependant on the manufacturing process, but can be as high as 15% for high strength materials manufactured using the Pilger process. Therefore, if specifying cold worked duplex stainless steel this issue should be discussed with the supplier. However, for initial design purposes it is recommended that it is assumed that the strength in the transverse direction is 5% lower than in the longitudinal direction.
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Appendix E
(iii) Effect of elevated temperature on mechanical properties The strength of many materials decreases with increasing temperature. It is important to take such decreases into account in completion design. For the more commonly used downhole tubular materials the magnitude of this affect is as follows: (a) Carbon steel, 13%Cr steel and Super 13%Cr alloys Over the range of temperatures likely to be experienced downhole the reduction in strength is likely to be relatively small. The present Casing Design Manual8 recommends that for low alloy steels up to and including Q125 a yield strength temperature de-rating factor of 0.03% per °F is applied, with de-rating commencing at 68°F. Given the similarity in behaviour in this respect for low alloy steels and 13%Cr steel/Super 13Cr alloys, it would be reasonable to assume a similar temperature derating factor for both 13%Cr steel and Super 13Cr alloys. (b) Duplex stainless steel The reduction in strength with increasing temperature is greater for duplex stainless steels than for low alloy steels. This resulted in a design guideline for Miller that assumed a 10% reduction in yield strength at 120oC. The magnitude of this affect is likely to be different for different grades of duplex stainless steel and for tubulars made by different manufacturing routes. Therefore, this aspect should be discussed with the suppliers. However, for initial design purposes it is recommended that it is assumed that the strength is reduced at a rate of 8% per 100oC. Where design yield strength has a critical influence on weight or grade selection, and conservative assumptions are economically undesirable, it will be necessary to ensure that the actual yield strength at the required elevated temperature is adequate for the design by undertaking mechanical tests. Tests should be undertaken both before (as a pre-qualification) and during (as a quality control check) manufacture of the downhole tubulars. 2. Flow-Induced Damage: Erosion and Erosion-Corrosion Resistance Erosion can defined as the mechanical loss of material by the impact of liquid droplets, gas bubbles and/or solid particles (e.g. sand). The term erosion-corrosion is used to define the conjoint action of erosion and corrosion. Guidelines have been developed for the avoidance of erosion/erosion-corrosion problems9. Amongst other things, these can be used to determine velocity limits for the avoidance of erosion/erosion-corrosion damage. Different velocity limits apply in different situations, depending on the fluids/flow regime (gas, liquid or multiphase gas and liquid), the environment (corrosive or non-corrosive), the downhole tubular/equipment materials and whether or not solids are present.
8
Casing Design Manual, Issue 2, BPA-D-003, September 1999
9
‘Erosion Guidelines Revision 2.1 (1999), J W Martin, Sunbury Report No. S/UTG/102/99, October 1999)
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Appendix E
Summary guidance for evaluating erosional velocity limits is given in Section 2.1. below. These indicate the erosional velocity limits for which the rate of erosion will be 0.1mm/yr or less. Three main categories for solids content are used in these guidelines: “Totally solids free” The flow streams are such that there is no risk of solids being transported in the fluids. It should be noted that even very low levels of solids can cause significant wastage (erosion or erosion/corrosion) rates. Hence it is very important to be sure there is no risk of solids entrainment before using these limits. • “Nominally solids free” less than 1pptb (lbs per thousand barrels) for liquid systems, less than 0.1lb/mmscf for gas systems; no solids detectable. • “Solids present” Solids detectable in the system. In this case the levels of solids will need to be known, or appropriate assumptions made regards their likely level. 2.1. Evaluation of Velocity Limits. The following criteria indicate the maximum velocity limit to obtain an estimated rate of erosion of 0.1 mm/yr. or less. Totally Solids Free Duties: • Non Corrosive ⇒ Single Phase (liquid/gas) - no velocity limits for avoidance of erosion ⇒ Multiphase - limit velocity to 70m/s to avoid droplet/gas bubble impingement erosion.
• Corrosive ⇒ Single Phase Liquid - no velocity limits for avoidance of erosion ⇒ Un-inhibited wet gas/multiphase10 - limit velocity to 70m/s to avoid droplet/gas bubble impingement erosion. ⇒ Inhibited carbon steel wet gas/multiphase - use the API RP14e11 equation with C=200 or 20m/s (whichever is lower). Nominally Solids Free Duties: ⇒ Single Phase Liquid - use the API RP14e7 equation with C=250 for carbon steel; C=300 for 13Cr steel and C=450 for duplex stainless steel. ⇒ Multiphase - use the API RP14e7 equation with C=135 for carbon steel; C=300 for 13Cr steel and C=350 for duplex stainless steel.
10
For carbon steel it is assumed that the fluid has sufficiently low corrosivity to justify it’s use and is un-filmed (i.e. no carbonate film). For carbonate filmed carbon steel (see Section ????) use the ‘inhibited’ flow velocity limits. 11
API RP14e equation is: Maximum Allowable Velocity (ft/sec) = C/(mixture density in lb/ft3)0.5
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⇒ Single Phase Gas - Evaluate using the Erosion Rate models in the Erosion Guidelines5. Assume a solids production rate of 0.1lb/mmscf if no specific data available. Solids Containing Duties: It is not possible to define a rational flow velocity for all possible operating conditions below which the rate of erosion will be below 0.1 mm/yr. Therefore, it will be necessary to undertake an assessment of the likely erosion rate/acceptable flow velocities on a case by case basis using the relevant erosion rate models from the Erosion Guidelines5. If the anticipated maximum flow rate is less than the critical velocity calculated using the information above, the effect of high fluid flow rates and/or sand erosion need not be considered further. However, if the maximum flow rate is greater than the critical velocity then significant wastage may result. In this case further consideration of the likely wastage rates resulting from erosion/erosion-corrosion will be required. In the first instance reference should be made to the BP Amoco Erosion Guidelines5. 3. Galvanic Corrosion This is the preferential corrosion that can occur to one of the metals when two different metals are electrically coupled in a corrosive environment. In such a couple one of the metals will act as an anode (i.e. it will corrode at an enhanced rate) and the other will act as a cathode (i.e. there will be a certain degree of protection). The susceptibility of a material couple towards galvanic corrosion of the 'anodic' metal is influenced by a number of factors, such as the conductivity of the corrosive medium, the relative surface area of the two metal components and the magnitude of the potential difference between the two metals in the corrosive environment. In general, downhole tubular systems should be designed to eliminate galvanic cells where possible. For the purposes of downhole materials selection galvanic corrosion should be considered a potential problem if there is a corrosion-resistant alloy (CRA)/carbon steel interface. However, if such interfaces do not occur then the problem of galvanic corrosion can be discounted. If galvanic corrosion between CRA jewellery and carbon steel tubulars is a concern, consideration should be given to installing an internally coated CRA between the components. In general, 9Cr-1Mo or 13%Cr steel against C-steel is not a concern, the major concern is for the higher metallurgies, e.g. nickel alloys, against carbon steel. If there is a concern about any material combination that occurs in a downhole tubular design the relevant specialist/s should be consulted.
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Appendix E
INDIVIDUAL ALLOY "GO/NO GO" CHARTS SULPHIDE STRESS CRACKING AND STRESS CORROSION CRACKING PERFORMANCE DOMAINS
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Sulphide Stress Cracking Performance Domain of ”Sour Resistant” Grade 110ksi Steel
Solution pH
6.5
Acceptable 5.5
4.5
Unacceptable 3.5
0.003 0.001
0.01
0.1
1.0
10
pH2S (bara) February 2000
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Sulphide Stress Cracking Performance Domain of Grade N80 Carbon Steel
Solution pH
6.5
Suitable Acceptable 5.5
4.5
Unsuitable Unacceptable 3.5
0.003 0.001
0.01
0.1
1.0
10
pH2S (bara) February 2000
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Appendix E
Sulphide Stress Cracking Performance Domain of Grade P110 Carbon Steel
Solution pH
6.5
Suitable Acceptable 5.5
4.5
Unsuitable Unacceptable 3.5
0.003 0.001
0.01
0.1
1.0
10
pH2S (bara) February 2000
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H2S Limits for 95ksi Super 13Cr Alloys
6.5
Solution pH
Acceptable 5.5
4.5
Further Assessment Required 3.5
Unacceptable 0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 95ksi Super 13Cr Alloys in low Chloride (1000 ppm Cl-) Waters
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H2S Limits for 95ksi Super 13Cr Alloys
6.5
Solution pH
Acceptable 5.5
4.5
Further Assessment Required
Unacceptable
3.5
0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 95ksi Super 13Cr Alloys in High Chloride (120,000 ppm Cl-) Waters
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Appendix E
H2S Limits for 22Cr Duplex Stainless Steel
Solution pH
6.5
Acceptable
5.5
4.5
Further Assessment Required
Unacceptable
3.5
0.02 0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 22Cr Duplex Stainless Steel
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Appendix E
H2S Limits for 25Cr Duplex Stainless Steel
Solution pH
6.5
5.5
Acceptable 0.5
4.5
Further Assessment Required
Unacceptable
0.25
3.5
0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 25Cr Duplex Stainless Steels
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H2S Limits for 110ksi Super 13Cr Alloys
6.5
Acceptable
Solution pH
Further Assessment Required 5.5
4.5
3.5
Unacceptable
0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 110ksi Super 13Cr Alloys in High Chloride (120,000 ppm Cl) Waters
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H2S Limits for 110ksi Super 13Cr Alloys
Solution pH
6.5
5.5
Further Assessment Required
Acceptable
4.5
3.5
Unacceptable 0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of 110ksi Super 13Cr Alloys in Low Chloride (1000 ppm Cl-) Waters
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H2S Limits for API5CT L80 13Cr Steel
Solution pH
6.5
Acceptable
5.5
4.5
Further Assessment Required
Unacceptable
3.5
0.003 0.001
0.01
0.1
1.0
10
pH2S (bara) Domain diagram for the Sulphide Stress Cracking Limits of API5CT L80 13Cr Steel
February 2000
Page 72
