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
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’ 7
5. QUESTIONS TO BE ASKED OF PROSPECTIVE SUPPLIERS. 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"? 50
APPENDIX D : SULPHIDE STRESS CRACKING 52
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.
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
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
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
• 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
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.
CONSULT pH Isoplots
Detailed analysis
CR ≤≤0.1 mm/y 0.1mm/y<CR<10 mm/yT ≤ ≤ 150oC CR>10mm/yT ≤ ≤ 175oC
Specialist Advice Specialist Advice Specialist Advice CONSULT CO2 Corrosion Isoplots(2) CONSULT Erosion Section of Appendix E 0.1mm/y<CR<10 mm/y T ≤≤ 100oC
qCan use carbon or low alloy steels
qIf H2S present note limits this may
impose - See Materials Selection for Sour Conditions Road Map
qThe affect of acetic acid can be particularly pronounced here and inhibition may be required(3, 4)
qCarbon steel + corrosion Inhibitor can be considered(3, 4)
qCheck economics and logistics against 13%Cr
qIf H2S present consult Materials
Selection for Sour Conditions Road Map
qSeek specialist advice on feasibility of carbon steel + corrosion inhibitor(3, 4)
q13%Cr likely to be best option(5, 6)but care needed above 120oC
qIf H2S present consult Sour Service
Road Map
q13%Cr should be considered(5, 6)but care needed above 120oC
qSuper or Hyper grades 13%Cr for T < 175oC
qIf H2S present consult Materials
Selection for Sour Conditions Road Map T>175oC NO NO NO YES
YES YES YES
YES
YES NO
Yes/Don’t Know! Totally Solids Free
NO
CONSULT
Materials Selection for Sour Conditions Road
Maps
qIf PCO2/PH2S ≤ ≤ 10 then pH Isoplot is affected by presence of H2S - Seek
Specialist Advice.
qH2S can reduce general corrosion rate by a factor 10 or more due to
formation of FeS - no account taken in CO2 Isoplots.
qH2S most likely to cause localised or pitting corrosion.
qPitting rate taken as that from the relevant CO2 corrosion Isoplot; but
can get localisedacidification inside a pit and galvanic affect of FeS film accelerating pitting rate.
qGRE 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
qThe 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.
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 CO2 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 limiting of velocity ≤ ≤ 200/√ρ√ρ should be applied - ρρ is the fluid density in 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.
MATERIALS SELECTION FOR SWEET CONDITIONS
• CO2 Corrosion Isoplots only strictly apply for
velocities ≤≤ 13 m/s - use with caution beyond this! • If in any doubt - Seek Specialist Advice.
? YES NO V > 13 m/s ëPCO2 / bara(1) ëToC in situ pH?(2) H2S present? Solids present?(2) YES NO INPUT Erosion Rate ≤≤ 0.1 mm/y
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
Is the use of NACE MR-0175 a statutory requirement for this area? Yes No What is the MINIMUM exposure temperature?
Consider use of the BP Amoco Methodology
Alternatively can use NACE MR-0175 Apply Requirements
of NACE MR-0175
=>65oC <65oC
=>80oC
=>107oC Consideration can also be
given to using N80(Q+T), C95 or proprietary Q+T grades with a MAXIMUM yield strength of 110ksi1
Consideration can also be given to using Q1251,2
Notes.
1. If temperatures below this minimum are expected, even for 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 also be given to using H40, N80, P110 or proprietary Q+T grades with a MAXIMUM yield strength of 140ksi1
What is the required material strength? =<95ksi
>95ksi Consider API 5CT Grades
H403; J55; K55; L80 (Type 1) C90 (Type 1); T95 (Type 1)
Consideration can be given to using proprietary sour
resistant grades up to 110ksi SMYS (Consult relevant specialists)
Establish required material strength and downhole
pH and pH2S
Refer to Domain Diagram for the material with adequate strength. If no material with suitable pH/pH2S
resistance can be identified apply requirements of NACE MR-0175 6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 S o lu ti on p H pH2S (bara) Acceptable Unacceptable Sulphide Stress Cracking Performance Domain of
“Sour Resistant” Grade 110ksi Steel
6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 S o lu ti on p H pH2S (bara) Acceptable Unacceptable Sulphide Stress Cracking Performance Domain of
Grade P110 Carbon Steel
6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 S o lu ti on p H pH2S (bara) Acceptable Unacceptable Sulphide Stress Cracking Performance Domain of
Grade N80 Carbon Steel
0.003
0.003 0.003
MATERIALS SELECTION FOR TUBULARS - SOUR CONDITIONS- CORROSION RESISTANT ALLOYS
L80 13Cr Steel
22Cr Duplex Stainless Steel 95ksi Super 13Cr Alloys2 110ksi Super 13Cr Alloys2 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)
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 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.
25Cr Duplex Stainless Steel
6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 S o lu ti on pH pH2S (bara) Acceptable Unacceptable
Domain diagram for the Sulphide Stress Cracking Limits of 22Cr Duplex Stainless Steel
6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 S o lu ti on pH pH2S (bara) Acceptable Unacceptable
Domain diagram for the Sulphide Stress Cracking Limits of 25Cr Duplex Stainless Steels
0.5 0.25 0.02 6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 S o lu ti on pH pH2S (bara) Acceptable Unacceptable
Domain diagram for the Sulphide Stress Cracking Limits of API5CT L80 13Cr Steel 0.003 6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 pH2S (bara) Acceptable Unacceptable
Domain diagram for the Sulphide Stress Cracking Limits of 95ski Super 13Cr Alloys in low Chloride (1000 ppm Cl-) Waters
Further Assessment Required 6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 pH2S (bara) Acceptable Unacceptable
Domain diagram for the Sulphide Stress Cracking Limits of 95ski Super 13Cr Alloys in high Chloride (120,000 ppm Cl-) Waters
Further Assessment Required 6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 pH2S (bara) Acceptable Unacceptable
Domain diagram for the Sulphide Stress Cracking Limits of 110ski Super 13Cr Alloys in high Chloride (120,000 ppm Cl) Waters
Further Assessment Required 6.5 5.5 4.5 3.5 0.001 0.01 0.1 1.0 10 pH2S (bara) Acceptable Unacceptable
Domain diagram for the Sulphide Stress Cracking Limits of 110ski Super 13Cr Alloys in low Chloride (1000 ppm Cl-) Waters
Further Assessment Required
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?
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 corrosion-resistant 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.
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
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
erosion-corrosion are addressed in Appendix E of these Guidelines.
2. ‘Materials selection for sweet conditions’ Road Map
The ‘Materials Selection for Sweet Conditions’ Road Map is given in Section 4 of 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.
•
InputThe 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 water-wetted. 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-in-oil at low water cuts inverting to water-in-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.
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
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.
50 70 90 110 130 150 170 190 210 230 0.0001 0.001 0.01 0.1 1 10 PC 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
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
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
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
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
• 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.
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.
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 ).
pH ISOPLOTS
0.0001 0.001 0.01 0.1 1 10 - 4 - 3 - 2 - 1 0 1 Log(Pco2) PCO2 , barapH ISOPLOTS
30 40 50 60 70 80 90 100 110 120 -4 -3 -2 -1 0 1 3.00 3.50 4.00 4.50 5.00 5.50 6.00 6.50 Temperature, degC Log(Pco2) Condensed Water 6.00-6.50 5.50-6.00 5.00-5.50 4.50-5.00 4.00-4.50 3.50-4.00 3.00-3.50This case assumes no significant concentration of dissolved salts present and represents water condensing from a wet gas.
