ISO/DIS 15156-2:2025(en)

Secretariat: NEN

ISO/TC 67/WG 7

Date: 2025-10-24

Oil and gas industries including lower carbon energy — Materials for use in H₂S-containing environments in oil and gas production — Part 2: Service environment assessment and material selection

© ISO 2025

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Contents

Foreword vii

Introduction ix

1 Scope 1

2 Normative references 2

3 Terms and definitions 3

4 Symbols and abbreviated terms 5

5 General principles 6

6 H₂S-service assessment 8

6.1 Analysis of the environment and application severity 8

6.1.1 General 8

6.1.2 Environmental parameters 10

6.1.3 Influence of equipment design and application 13

6.2 Analysis of applicable damage mechanisms 15

6.2.1 General 15

6.2.2 Carbon and low alloy steels 17

6.2.3 Cast irons 20

6.2.4 Corrosion-resistant and other alloys 20

7 Materials selection 21

7.1 General 21

7.2 Guidance on specific equipment 22

7.2.1 Wellhead and tree components 22

7.2.2 Other equipment and components 24

8 Specification, qualification and verification 24

8.1 General 24

8.1.1 Material selected using Annex A or Annex B 24

8.1.2 Verification 24

8.1.3 Qualification 24

8.2 Carbon and low alloy steels 25

8.3 Cast irons 25

8.4 CRA and other alloys 25

8.5 Weldments 26

8.5.1 General 26

8.5.2 Weldments in carbon and low alloy steels 26

8.5.3 Weldments in CRA and other alloys 27

8.5.4 Dissimilar welds 27

8.6 Weld overlayed, clad, metallic lined and hard-faced components 28

8.7 Wear-resistant alloys used for sintered, cast, or wrought components 28

8.8 Coated, plated or polymeric lined components 28

8.9 Surface treatments 28

8.10 Additively manufactured equipment and components 29

9 Report on the method of selection 29

Annex A (normative) SSC-resistant cast irons, carbon and low alloy steels 30

A.1 General 30

A.2 SSC-resistant cast irons 31

A.2.1 General 31

A.2.2 Packers and subsurface equipment 31

A.2.3 Compressors and pumps 31

A.3 SSC-resistant steels for use throughout SSC Region 4 31

A.3.1 General 31

A.3.2 Service limits and acceptable materials for specific product forms 31

A.3.2.1 Pressure vessel steels 31

A.3.2.2 Piping, valves and associated components 32

A.3.2.3 Line pipe 32

A.3.2.4 Downhole casing, tubing and tubular components 32

A.4 SSC-resistant steels for use throughout SSC Region 3 33

A.4.1 General 33

A.4.2 Service limits and acceptable materials for specific product forms 33

A.4.2.1 Pressure vessel steels 33

A.4.2.2 Piping, valves and associated components 33

A.4.2.3 Line pipe 33

A.4.2.4 Downhole casing, tubing and tubular components 34

A.4.3 Service limits and acceptable materials for specific equipment 35

A.4.3.1 Bolting and fasteners 35

A.4.3.2 Drilling blowout preventers 36

A.4.3.2.1 General 36

A.4.3.2.2 Rams 36

A.4.3.3 Drilling and well equipment exposed only to drilling fluids, or completion or kill weight brines 36

A.4.3.4 Compressors and pumps 37

A.4.3.5 Gaskets 37

A.5 SSC-resistant steels for use throughout SSC Region 2 37

A.6 SSC-resistant steels for use throughout SSC Region 1 37

A.7 SSC-resistant steels for use throughout SSC Region 0 37

A.8 Acceptable steels for specific service applications 38

A.8.1 General 38

A.8.2 Pipelines transporting stabilized crude 38

A.9 Surface treatment of carbon and low alloy steels 38

Annex B (normative) Environmental cracking-resistant CRAs and other alloys 39

B.1 General 39

B.1.1 Use of Annex B 39

B.1.2 Material groups 39

B.2 Materials options for any equipment or components, and for specific equipment or components 40

B.2.1 Materials selection tables 40

B.2.1.1 General 40

B.2.1.2 Guidance on legacy entries 42

B.2.2 Austenitic stainless steels 42

B.2.3 Highly alloyed austenitic stainless steels 43

B.2.4 Annealed and cold worked nickel-based alloys 44

B.2.5 Ferritic stainless steels 46

B.2.6 Martensitic stainless steels 47

B.2.7 Duplex stainless steels 49

B.2.8 Precipitation-hardened austenitic stainless steels 51

B.2.9 Precipitation-hardened martensitic stainless steels 51

B.2.10 Precipitation-hardened nickel-based alloys 51

B.2.11 Cobalt-based alloys 56

B.2.12 Titanium and tantalum alloys 57

B.2.13 Copper- and aluminium-based alloys 58

B.2.13.1 Copper-based alloys 58

B.2.13.2 Aluminium-based alloys 59

B.3 Materials options that have specific restrictions or mitigating factors 59

B.3.1 General 59

B.3.2 Gaskets and seal rings 59

B.3.3 Screen devices, including downhole screens 59

B.3.4 Equipment in gas lift service 60

B.3.5 Set screws and pins 60

B.3.6 Compressor components 60

B.3.7 Control line tubing, and associated fittings 61

B.3.8 Instrumentation and control devices 61

B.3.9 Instrument tubing and compression fittings 61

B.3.10 Pins, shafts and valve stems 62

B.3.11 Non-pressure-containing internal-valve, pressure-regulator, and level-controller components 62

B.3.12 Snap rings 62

B.3.13 Springs 62

B.3.14 Wellhead and tree components 63

B.3.15 Subsurface equipment 64

B.3.16 Any equipment or component 64

B.4 End sizing of corrosion resistant alloy pipe and OCTG 65

B.5 CRA bolting and fasteners 65

B.6 Surface treatment of corrosion-resistant alloys and other alloys 65

Annex C (informative) Determination of H₂S partial pressure, fugacity, activity and concentration in the aqueous phase 66

C.1 General 66

C.2 Calculation for systems with a gas phase 66

C.2.1 General 66

C.2.2 Gas phase considerations, H₂S partial pressure and fugacity 67

C.2.3 Aqueous phase considerations, H₂S concentration and chemical activity 67

C.3 Calculations for gas-free, liquid-only systems 68

C.3.1 General 68

C.3.2 Considerations for high pressure gas-free oil wells 68

Annex D (informative) Assessment of pH 70

Annex E (informative) Fundamental mechanistic aspects of H₂S cracking 71

E.1 General 71

E.2 Sulfide stress cracking 71

E.3 Stress corrosion cracking (SCC) 71

E.4 Hydrogen-induced cracking (HIC)/stepwise cracking (SWC) 71

E.5 Stress-oriented hydrogen-induced cracking (SOHIC) 72

E.6 Galvanically induced hydrogen stress cracking (GHSC) 72

E.7 Other mechanisms 72

Bibliography 73

Foreword

ISO (the International Organization for Standardization) is a worldwide federation of national standards bodies (ISO member bodies). The work of preparing International Standards is normally carried out through ISO technical committees. Each member body interested in a subject for which a technical committee has been established has the right to be represented on that committee. International organizations, governmental and non-governmental, in liaison with ISO, also take part in the work. ISO collaborates closely with the International Electrotechnical Commission (IEC) on all matters of electrotechnical standardization.

The procedures used to develop this document and those intended for its further maintenance are described in the ISO/IEC Directives, Part 1. In particular the different approval criteria needed for the different types of ISO documents should be noted. This document was drafted in accordance with the editorial rules of the ISO/IEC Directives, Part 2 (see www.iso.org/directives).

Attention is drawn to the possibility that some of the elements of this document may be the subject of patent rights. ISO shall not be held responsible for identifying any or all such patent rights. Details of any patent rights identified during the development of the document will be in the Introduction and/or on the ISO list of patent declarations received (see www.iso.org/patents).

Any trade name used in this document is information given for the convenience of users and does not constitute an endorsement.

For an explanation of the voluntary nature of standards, the meaning of ISO specific terms and expressions related to conformity assessment, as well as information about ISO's adherence to the World Trade Organization (WTO) principles in the Technical Barriers to Trade (TBT), see www.iso.org/iso/foreword.html.

This document was prepared by Technical Committee ISO/TC 67, Oil and gas industries including lower carbon energy, in collaboration with the European Committee for Standardization (CEN) Technical Committee CEN/TC 12, Oil and gas industries including lower carbon energy, in accordance with the Agreement on technical cooperation between ISO and CEN (Vienna Agreement).

This fifth edition cancels and replaces the fourth edition (ISO 15156-2:2020) which has been technically revised. The main changes compared to the previous edition are as follows:

— ISO 15156 series has been rewritten and the content reorganized into three new parts as follows:

— Part 1: Materials and materials processing requirements;

— Part 2: Service environment assessment and material selection;

— Part 3: Verification, qualification and balloting requirements.

— greater detail is given in assessing H₂S-containing environments in Clause 6, including:

— the definition of a new region of SSC environmental severity (Region 4) that has been defined for the most severe environments;

— clearer guidance on when and how to apply parameters other than p_H2S in the definition of environmental severity (e.g. f_H2S, aH₂S and cH₂S).

— cast iron, and carbon and low alloy steel material selection requirements are detailed for the new SSC environmental severity Region 4 in Annex A;

— CRA materials selection tables in Annex B have been rationalised and updated according to the latest industry experiences;

— many equipment-specific CRA entries in ISO 15156-3:2020 with few or no environmental limits have been moved to Clause B.3, providing better guidance on why this was historically acceptable and the potential limits of its applicability;

— guidance has been added to increase clarity with respect to API 6A wellhead and tree material classes.

A list of all parts in the ISO 15156 series can be found on the ISO website.

Any feedback or questions on this document should be directed to the user’s national standards body. A complete listing of these bodies can be found at www.iso.org/members.html.

Introduction

The consequences of sudden failures of metallic oil and gas field components, associated with their exposure to H₂S-containing production fluids, led to the preparation of the first edition of ANSI/NACE MR0175, which was published in 1975 by the National Association of Corrosion Engineers, now known as AMPP (Association for Materials Protection and Performance). Collaboration with the European Federation of Corrosion (EFC) resulted in the first joint publication of the ISO 15156 series in 2003.

The fifth edition of the ISO 15156 series makes substantive changes to the structure of the standard and is organized as follows:

— Part 1: Materials and materials processing requirements;

— Part 2: Service environment assessment and material selection;

— Part 3: Verification, qualification, and balloting requirements.

Material specification requirements are given in ISO 15156-1. This includes requirements that are generic to a material class and those that are specific to a material listed in ISO 15156-2. In some instances, specifically for those grades whose performance in H₂S-containing environments is most susceptible to materials processing variation, ISO 15156-1 also specifies materials processing or qualification requirements for a listed material.

Acceptable materials selections for a given combination of equipment and service environment are stated in ISO 15156-2: it lists environmental limits for materials that have been accepted through the development and maintenance of the ISO 15156 series, and stipulates the path to acceptance for materials and/or environmental conditions not listed.

The processes and procedures for qualification and verification by H₂S-testing (including where required by ISO 15156-1 and ISO 15156-2) are given in ISO 15156-3. Processes and procedures for balloting new materials, material conditions, environmental limits, and/or product specifications for incorporation into the ISO 15156 series are also described in ISO 15156-3.

Conformance with the ISO 15156 series can require conformance with more than one document in the ISO 15156 series. Paths for conformance with the ISO 15156 series are given in Figure 1.

^a See exclusions in ISO 15156-2:202x, Table 1.

^b There is an option to ballot for inclusion in the ISO 15156 series.

Figure 1 — Path for conformance with the ISO 15156 series

The ISO 15156 series were developed and approved by representative groups from within the oil and gas production industry, following the applicable ISO and ANSI/AMPP rules.

Future changes to the ISO 15156 series may be published as interim updates to this document in the form of ISO Technical Circulars. Document users should check for applicable ISO Technical Circulars when applying the ISO 15156 series.

ISO 15156-3 describes the requirements for balloting changes based on test data and/or field experience (e.g. new materials, alternative requirements or alternative limits).

The joint ISO 15156 and ANSI/NACE MR0175/ISO 15156 Maintenance Agency at DIN was set up after approval by the ISO Technical Management Board given in document 34/2007. This document describes the makeup of the agency, which includes experts from AMPP and ISO/TC 67, and the process for approval of ISO Technical Circulars. It is available from the ISO 15156 maintenance website and from the ISO/TC 67 Secretariat. The website also provides access to related documents that provide more detail on ISO 15156 series maintenance activities.

In this document, the following verbal forms are used:

— “shall” indicates a requirement;

— “should” indicates a recommendation;

— “may” indicates a permission;

— “can” indicates a possibility or a capability.

Oil and gas industries including lower carbon energy — Materials for use in H₂S-containing environments in oil and gas production — Part 2: Service environment assessment and material selection

WARNING — It is the equipment user’s responsibility to ensure that the equipment is suitable for the intended application with consideration of all H₂S-related damage mechanisms (not just those considered in this document) and that the materials are specified appropriately.

This document specifies requirements and gives recommendations for assessment of the service environment, and the selection of metallic materials used in oil and gas production in H₂S-containing environments, where the failure can pose a risk to the functionality of the equipment, to the health and safety of the public and personnel or to the environment.

This document is not intended for application to equipment for carbon capture, utilisation and/or storage (CCUS, CCS) or downstream oil and gas (for downstream applications see ISO 17945/NACE MR0103), but the guidance and principles can be applied by the equipment user for these applications.

This document addresses the selection of carbon and low alloy steels, cast irons, corrosion-resistant alloys and other alloys for resistance to damage mechanisms that are a consequence of H₂S, or which are exacerbated by H₂S. This includes sulphide stress cracking, hydrogen-induced cracking, stepwise cracking, stress-oriented hydrogen-induced cracking, soft-zone cracking, galvanically induced hydrogen stress cracking and stress corrosion cracking. Some of these mechanisms can also occur in environments that do not contain H₂S, but these are not included in the scope of this document. These are not included in the scope of this document. Materials with established service limits, or which have a successful history of application are listed. A path for qualifying and accepting materials that are not listed is described in ISO 15156-3.

NOTE H₂S can also influence degradation mechanisms other than cracking, including general and localized corrosion.

This document is intended primarily for equipment users and other parties that select and accept materials and equipment for service in H₂S-containing environments. It stipulates when materials need to be specified to be in conformance with ISO 15156-1 or qualified in conformance with ISO 15156-3.

All oil and gas production equipment categories handling H₂S-containing fluids are within the scope of this document, including but not limited to:

a) drilling, well construction, and well-servicing equipment;

b) wells including subsurface equipment, gas lift equipment, wellheads, and tree equipment;

c) flow-lines, gathering lines, field facilities, and field processing plants;

d) water-handling, injection and disposal equipment;

e) gas-handling and injection equipment including those used for CO₂ enhanced oil recovery;

f) natural gas treatment plants (for gas sweeting plants see also API RP 945);

g) transportation pipelines for liquids, gases, and multi-phase fluids.

Exclusions to the scope of this document are given in Table 1.

Table 1 — List of exclusions to this document

The following documents are referred to in the text in such a way that some or all of their content constitutes requirements of this document. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced document (including any amendments) applies.

ISO 11960, Petroleum and natural gas industries — Steel pipes for use as casing or tubing for wells

ISO 15156‑1:202x, Oil and gas industries including lower carbon energy — Materials for use in H₂S-containing environments in oil and gas production — Part 1: Materials and materials processing requirements

ISO 15156‑3:202x, Oil and gas industries including lower carbon energy — Materials for use in H₂S-containing environments in oil and gas production — Part 3: Verification, qualification and balloting requirements

API 5CT,^[1] Casing and Tubing

SAE— ASTM,^[2] Metals and alloys in the Unified Numbering System, ISBN 0-7680-04074

For the purposes of this document, the following terms and definitions given in ISO 15156-1 and the following apply.

ISO and IEC maintain terminological databases for use in standardization at the following addresses:

— ISO Online browsing platform: available at https://www.iso.org/obp

— IEC Electropedia: available at https://www.electropedia.org/

3.1

barrier element

equipment that is part of the primary or secondary pressure containing envelope preventing the release of the fluids that it contains, as specified by the governing code, standard or specification for that equipment and application

3.2

chemical activity

unit-less ratio of actual fugacity (of a gas species) divided by its fugacity at a conveniently defined reference state

Note 1 to entry: In this document, the term chemical activity is primarily used as a property of species in the liquid or aqueous phase, a “pseudo mole fraction”, see Annex C.

3.3

environmental severity

aggressiveness of the service environment with respect to the cracking mechanisms of relevance to the ISO 15156 series

3.4

galvanically-induced hydrogen stress cracking

GHSC

cracking that results from hydrogen absorbed by the cathode of a galvanic couple in the presence of tensile stress (residual and/or applied)

Note 1 to entry: This mostly affects CRA in a carbon/low alloy steel to CRA couple.

3.5

H₂S fugacity

effective pressure of H₂S under ideal gas conditions, which has the same chemical potential (partial Gibbs free energy) as the H₂S under real gas conditions

Note 1 to entry: In this document, the term H₂S fugacity is primarily used as a property of H₂S in the gas phase, an “effective partial pressure”, but for all liquid systems it is the H₂S fugacity of H₂S vapor that would be in equilibrium with the concentration present in the liquid, see Annex C.

3.6

H₂S content

general description of the amount of H₂S in a system, which could be based upon classical (partial pressure or dissolved concentration) and/or thermodynamic considerations (H₂S fugacity (3.5), chemical activity (3.2))

3.7

H₂S service assessment

assessment of the environment and credible cracking mechanisms that can influence a materials selection

3.8

maximum sustained tensile stress

greatest principal stress that can be experienced by the material in the H₂S-containing environment for a defined period, determined for the purposes of comparison with threshold stress (3.15) limits for H₂S service

3.9

pH

in situ pH of the H₂S-containing aqueous phase at the temperature(s) and pressure(s) of interest

3.10

production environment

oil and gas production fluids without contamination from oxygen or chemicals that will temporarily or continuously reduce pH

3.11

qualification

demonstration of the resistance of the material to the cracking modes of relevance to this document, typically involving H₂S-testing of sufficient material to establish confidence in performance

Note 1 to entry: The result of the qualification is effectively a validation statement similar to the desired outcome from ISO/IEC 17029:2019 regarding the specific material and environment combination examined.

Note 2 to entry: Examples of qualification are:

Example 1: qualification to permit use of a material in a service environment outside of the temperature, pH, p_H2S and/or chloride limits given in Annex A or Annex B;

Example 2: Qualification of a material produced by a defined manufacturing route to validate application within the limits given in Annex A or Annex B (e.g. OCTG and martensitic stainless steel bar stock);

Example 3: Qualification of a material not listed in Annex A or Annex B, or with materials properties that differ from the specification referenced in this document (including ISO 15156-1, where applicable).

3.12

specific service

conditions of application for the materials/products for which H₂S-testing is defined to match the user’s requirements

Note 1 to entry: Fitness-for-purpose has also been historically used to define these same requirements but also extends to evaluation steps related to in-service issues, assessment of damage etc.

3.13

stabilized crude

processed hydrocarbon liquids that have a vapor pressure below 101 kPa at 25 °C per ASTM D6377 at 4:1 liquid/gas volume ratio, and that are dehydrated to ≤ 0,5 vol% water with a pH typically ≥ 5,6

Note 1 to entry: Processing includes that achieved by separation or heater treaters, reducing water content and removing free gas phase(s).

3.14

soft-zone cracking

SZC

form of SSC that can occur when a steel contains a local “soft zone” of low-yield-strength material

Note 1 to entry: Under service loads, soft zones can yield and accumulate plastic strain locally, increasing the SSC susceptibility to cracking of an otherwise SSC-resistant material. Such soft zones are typically associated with welds in carbon steels.

3.15

threshold stress

maximum stress permitted for some materials for application within their defined environmental limits

The material manufacturer shall ensure that material specified for service in H₂S-containing environments is manufactured in conformance with ISO 15156-1. Where required by this document, the material manufacturer can also be responsible for qualification of the manufacturing route in accordance with ISO 15156-3.

The material supplier shall ensure that all material supplied within the scope of the ISO 15156 series have been specified and documented in conformance with ISO 15156-1.

The equipment manufacturer shall ensure that equipment specified for service in H₂S-containing environments is manufactured in conformance with the ISO 15156 series (including manufacturing requirements specific to an ISO 15156-3 qualification, where applicable).

The equipment supplier shall ensure that all equipment within the scope of the ISO 15156 series have been specified and documented in conformance with the ISO 15156 series.

The equipment user shall ensure that the material selection is suitable for the intended service environment.

NOTE 1 A single party can have one or more of the above roles. For example, it is common for a manufacturer to also be a supplier. In such instances, the party concerned has responsibilities encompassing all the roles that they fulfil.

NOTE 2 Materials processing requirements are given in ISO 15156-1 for most materials listed in Annex A and Annex B. For some materials listed in these Annexes, ISO 15156-1 has no additional requirements other than meeting the listed materials specification given in Annex A or Annex B. For materials not listed in Annex A or Annex B, the materials requirements would be defined as part of a qualification defined in ISO 15156-3.

This document shall be applied by those selecting materials or determining if a material is acceptable for service in an H₂S-containing environment. This may include equipment users, equipment manufacturers and those acting on behalf of these parties. A simplified flow chart illustrating the use of this document and its relationship with ISO 15156-1 and ISO 15156-3 is shown in Figure 2.

Figure 2 — Simplified flowchart illustrating the use of this document and its relationship with ISO 15156-1 and ISO 15156-3

Equipment users shall conduct an H₂S service assessment to demonstrate that materials selections have been made in conformance with this document. This assessment shall define and evaluate all H₂S-containing service conditions to which equipment can be exposed.

NOTE 3 If such assessments are performed by other parties, the equipment user remains responsible for ensuring that they are in conformance.

The equipment user may accept environmental assessments conducted to previous editions of the ISO 15156 series, if conducted prior to the release of this edition, as valid H₂S service assessments. In this instance, an H₂S service assessment per Clause 6, should be conducted if the environmental conditions change from those assessed previously. Equipment users should also perform an H₂S service assessment per Clause 6 if the equipment is to operate in SSC Region 4, per Figure 3.

The H₂S service assessment shall:

a) determine if a material can be selected using Annex A or Annex B;

b) determine the qualification requirements for materials not selected using Annex A or Annex B;

NOTE 4 This includes materials listed in Annex A or Annex B, which are to be used in a condition not in conformance with ISO 15156-1, or which are to be used in environments that are more severe than the environmental limits given by these Annexes for the material.

c) determine if additional material requirements are necessary. These could be in addition or different to those specified in ISO 15156-1, for materials selected using Annex A or Annex B, or to ensure that a material qualified in accordance ISO 15156-3 is adequately verified.

The H₂S service assessment should include analysis of:

— the environment (see 6.1.2);

— application and equipment design (see 6.1.3);

— damage mechanisms applicable to the proposed material selection (see 6.2).

Materials may be selected using Clause 7 (in accordance with Annex A or Annex B), where the listed environmental limits of these materials are adequate for all expected service conditions. Materials (including their manufacturing process and condition) selected per Clause 7 from Annex A or Annex B shall be specified in accordance with ISO 15156-1.

Materials (including their manufacturing process and/or condition) that are not listed in this document, or which are used outside of the limits given in Annex A or Annex B, may be selected provided these are qualified in accordance with ISO 15156-3.

The use of this document often requires an exchange of information between the equipment user and the supply chain.

The focus of the assessments in this document is for service in production fluids. Reference is also made to other relevant service environments, e.g. packer and completion fluids, but only guidance is given for their assessment in this document.

The behaviour of materials in H₂S-containing environments is affected by complex interactions of factors, including the following:

a) metallurgical aspects, including:

i. chemical composition;

ii. method of manufacture;

iii. product form;

iv. strength and other mechanical properties;

v. hardness and its local variations;

vi. amount of cold work;

vii. heat-treatment condition;

viii. microstructure and its uniformity, including grain size and cleanliness.

b) H₂S content (see 6.1.2.2);

c) chloride concentration in the water phase (see 6.1.2.4);

d) acidity (pH) of the water phase (see 6.1.2.1);

e) presence of oxygen (see 6.1.2.6), sulfur (see 6.1.2.5) or other oxidants in the service environment;

f) exposure to non-production fluid service environments;

g) temperature (see 6.1.2.3);

h) stress (applied plus residual), (see 6.1.3.1);

i) galvanic coupling of materials (see 6.1.3.4)

Each factor, when applicable, should be part of the H₂S service assessment undertaken by the equipment user. Different service instances (for example through life scenarios for a souring production reservoir subject to pressure depletion) can result in various combinations of these factors. Different equipment in the same production system can also see different combinations of parameters (for example, due to adiabatic heating).

Damage mechanisms to be addressed include SSC, SCC, HIC, SOHIC and GHSC. A mechanistic description of these cracking mechanisms is given in Annex E.

For each damage mechanism, service conditions may be evaluated:

— separately (i.e. evaluating multiple conditions, with different specific environmental parameters);

— aggregated (i.e. evaluating a single condition, comprising the most severe combination of environmental parameters selected from the different service conditions).

NOTE Guidance on what constitutes a more severe environment for each environmental parameter is given in 6.2.

For materials listed in this document, relevant controls on the metallurgical aspects listed in 6.1.1 a) are given in ISO 15156-1.

pH

The pH is necessary for the selection of most materials per this document and the minimum estimated in situ pH shall be included in the H₂S service assessment.

When pH is calculated by third parties, the method shall be agreed with the equipment user.

NOTE While in situ pH can be directly measured for systems operating at or near atmospheric pressure, direct measurement is challenging in most oil and gas production environments. Accurate calculation of the equilibrium in situ pH requires speciation of the aqueous (water/brine) phase in equilibrium with the non-aqueous phases, necessitating the use of proprietary software. Further information on the essential parameters for pH calculation is given in Annex D.

H₂S

The maximum H₂S content expected during the life of the equipment shall be included in the H₂S service assessment.

The H₂S content shall be defined in terms of the maximum H₂S partial pressure in the gas phase (see Annex C for determination of p_H2S in the absence of a separate gas phase). Alternatively, the equipment user may define the H₂S content as H₂S fugacity, activity or concentration in the aqueous phase. See Clause 8, for the use of these parameters with respect to materials selection, and see Clause 9, for use of these parameters with respect to materials qualification.

H₂S partial pressure may be calculated following the guidance in Annex C. Determination of H₂S fugacity, activity or concentration requires the application of proprietary software. The method of prediction of H₂S fugacity, activity or concentration in the aqueous phase shall be agreed by the equipment user.

NOTE 1 The application of H₂S fugacity (or any other measurement of H₂S other than partial pressure) requires validated calculation approaches and confidence that all other environmental parameters are quantified conservatively. Calculation of H₂S chemical activity, fugacity, or aqueous concentration (in the service environment) requires the application of complex thermodynamic calculations with validated thermodynamic databases, typically via proprietary software. Further guidance on the calculation and application of H₂S fugacity, activity or concentration is given in Annex C.

NOTE 2 There are many sources of H₂S; e.g. see References [38] and [59].

Temperature

The range of temperatures anticipated for the equipment shall be included in the H₂S service assessment. In general, lower temperatures are more severe for SSC, HIC and GHSC while higher temperatures are more severe for SCC.

SSC susceptibility can be more severe for some materials at service temperatures close to 4 °C. This is a lower temperature than commonly used for SSC qualification and verification (approximately 24 °C, [75 °F]). This should be accounted for in the H₂S service assessment of carbon and low alloy steels, martensitic stainless steels, ferritic stainless steels and precipitation-hardened martensitic stainless steels. Conversely, at elevated temperatures these materials can show increased resistance to SSC; for example, see Table A.3 for carbon and low alloy steels.

NOTE 1 The detrimental influence of low temperature has been demonstrated for Q&T low alloy steels and martensitic stainless steels, see References [40], [43] and [58]. Clause 6 gives more guidance on the impact of temperature on the cracking mechanisms of relevance to this document.

The effect of temperature on SSC and SCC is not absolute and intermediate temperatures can be more severe for environmentally-assisted cracking (EAC) when the distinction/synergy between SSC and SCC is unclear.

NOTE 2 The maximum severity of H₂S cracking for duplex stainless steels is generally regarded to be between 80 °C [176 °F] and 100 °C [212 °F] but some investigations have found greater susceptibility at lower temperatures particularly at ≥ pH 4 and chloride content ≥ 100 000 mg/l, see References [49], [71] and [76].

NOTE 3 Temperature can also have an impact on corrosion (including localised corrosion mechanisms), which can influence the cracking mechanisms discussed in this document.

Susceptibility to HIC for carbon and low alloy steels is typically assessed at temperatures close to 24 °C (75 °F).

NOTE 4 Temperatures higher than 24 °C (75 °F) reduce HIC susceptibility. There are insufficient data available for determining relative susceptibility at temperatures lower than 24 °C (75 °F).

Chloride and other halides

The maximum chloride and halide anion content occurring in the production system expected during the life of the equipment shall be included in the H₂S service assessment.

NOTE 1 Production environments are typically low in halide ions other than chloride.

Chloride and halide content is typically of little significance to SSC, HIC and SOHIC susceptibility of carbon and low alloy steels, but is a key parameter for analysis of the SSC and SCC threats for CRA and other alloys.

Condensed water contains little to no chloride in production environments. It is prudent to assume some chloride content for condensed water in unprocessed production fluids, representing likely amounts of pore/formation water carry over. Typical values range up to 1 000 mg/l.

NOTE 2 Increased chloride/halide concentrations can occur where water condenses and evaporates, for example due to large pressure and temperature changes.

NOTE 3 Chloride content can be negligible (< 50 mg/l) in some scenarios, such as water condensing from separated gas, limiting or even preventing the electrochemical processes underlying the cracking mechanisms considered in this document.

NOTE 4 Packer and completion fluids are out of scope of this document. Some SCC data for these fluids is given in API TR 13TR1.

Elemental sulfur

Elemental sulfur can influence environmentally assisted cracking resistance, most commonly SCC performance. If elemental sulfur, S⁰, is expected, then its form and concentration in the production system during the life of the equipment shall be included in the H₂S service assessment, indicating a sulfur exposure category S1, S2 or S3 as follows:

S1 – Exposure to dissolved sulfur in an aqueous brine phase at concentrations below the saturation limit;

S2 – Exposure to brine and solid sulfur on the metal surface;

S3 – Exposure to brine and liquid sulfur on the metal surface.

Determination of elemental sulfur form is challenging and different forms can be present in the production system depending upon factors such as pressure and temperature changes. If greater than 8 mol% H₂S is present in the produced fluids a detailed sulfur speciation assessment should be performed.

NOTE 1 Downhole sampling and thermodynamic models can misinterpret the form and quantity of sulfur present in production fluids. Special approaches can be necessary to determine the presence or otherwise of elemental sulfur.

NOTE 2 Oxygen contamination of H₂S-containing fluids can result in the formation of elemental sulfur.

Most testing has been conducted for an S1 environment, but the equipment user shall determine if other forms are credible and select appropriate materials that have been qualified per ISO 15156-3.

Exposure severity for otherwise equal or less severe conditions (e.g., p_H2S, pH, p_CO2, Cl^-, salts) shall be defined as S3 > S2 > S1, with S3 being the most severe exposure.

In cases of intermittent exposure to solid or liquid sulfur the equipment user may decide on the most appropriate designation and qualification approach based on the duration of the exposures.

Proven acceptable exposure categories for CRA and other alloys are given in the tables of Annex B. The exposure categories above align with the test exposure options given in ISO 15156-3:202x, 8.4.3.3.3.

Test approaches for sulfur exposure categories shall be in accordance with ISO 15156-3:202x, 8.4.3.3.3.

Oxygen

If dissolved oxygen is present in the production fluids, then this should be included in the H₂S service assessment. Whilst oxygen is not typically present in produced fluids, it can be introduced through seals, high-oxygen containing blanket gases or comingling of produced and treated water in injected fluids. Dissolved oxygen can react with H₂S to deposit elemental sulfur.

NOTE No guidance is given on acceptable oxygen levels, but analogy can be made to experience in H₂S-testing of cracking resistance, including those tests used to develop Annex A and Annex B. Such tests were and are typically conducted in water with very low oxygen content to avoid this influencing the test result: since complete deaeration is impossible, this is often > 0, but < 10 ppb dissolved oxygen. Some materials, for example modified martensitic and precipitation-hardened stainless steels, are more sensitive to dissolved oxygen, demanding even more stringent oxygen control to avoid its detrimental influence.

Dry fluids

Some material entries in Annex B rely on the assumption of dry fluids during normal operation.

The analysis of fluids that are nominally free of an aqueous phase should include consideration of transient or other conditions that can result in the presence of an aqueous phase. During transient conditions (such as start-up, shut-down and upsets in dehydration processes) an aqueous phase can exist (through water condensation), albeit, perhaps, with very low chloride concentration.

NOTE 1 Failures have occurred in, for example, compressor components during unplanned wet service (see Reference [68]), emphasizing the importance of assessing transient conditions.

NOTE 2 Water can accumulate in piping/pipeline low points or vessel or equipment bottoms.

Other mitigating and exacerbating environmental factors

The detrimental impact of any chemicals injected shall be accounted for in the H₂S service assessment. Any potential mitigating effect of chemical injection (including corrosion inhibitor) should not be relied upon in the H₂S service assessment.

NOTE Chemical additives are common in oil and gas production and in water injection. Some chemicals can be beneficial to cracking resistance, such as those intended to increase pH, scavenge H₂S, remove oxygen or inhibit corrosion. However, chemical injection is not infallible, requiring care when considering these in the H₂S service assessment. Other chemicals can be detrimental to cracking resistance, such as those that can produce H₂S and/or reduce pH.

Oil wetting shall not be applied as a mitigating factor for the prevention of the cracking mechanisms of relevance to the ISO 15156 series. See 6.1.2.7 for dry fluids and see A.8 for exceptions with respect to pipeline steels.

Stress

Susceptibility to many of the cracking mechanisms within the scope of this document increase with increasing total tensile stress on the equipment in the presence of H₂S. The stresses on a component include contributions from residual stresses from manufacture, fabrication, installation and commissioning as well as the applied service stresses from loading, pressurisation, temperature and displacements. The geometry of the equipment can influence local tensile stresses.

Some entries in Annex A and Annex B define a threshold stress, below which environmental cracking has not been observed in the balloted test data or for the applicable equipment when designed to the governing codes. These are the exceptions and threshold stresses are not stated for most materials.

In some instances, peak stresses are only experienced by some equipment for very short periods. If the equipment manufacturer and user agree that the exposure period is short enough to ignore (see 6.1.3.3) maximum sustained tensile stress may be used for the purposes of the H₂S service assessment.

Equipment manufacturers and users should be attentive to novel designs, or use, that could result in stresses exceeding those typical for the specific material and equipment.

NOTE 1 Care is needed when assessing loading modes, since non-tensile loading modes, including compression and torsional loading, can still result in tensile stresses in some locations of the equipment.

NOTE 2 Most materials listed in this document have been balloted based on H₂S-testing at stresses between 80 % and 100 % of yield. Some CRA have been qualified at lower stresses and this is noted in the relevant entries in Annex B. Some other CRA have been accepted historically for some equipment on the basis that the codes governing the design of this equipment ensure that stresses are relatively low. Again, this is noted in the relevant entries in Annex A and Annex B.

NOTE 3 Product specifications define yield stress in materials with no definitive yield point in different ways, some using 0,2 % proof stress, others defining a stress at a specific elongation under load (i.e. stress at a given elongation). For the purposes of verification by H₂S-testing, the product specification’s definition of yield strength applies.

NOTE 4 Within the context of this document, low stress is assumed to be < ½ SMYS and moderate stress is assumed to be < ⅔ SMYS.

Strain

This document historically has been based on qualification and selection of materials for equipment designed and constructed using load-controlled tests and/or design methods at or below the yield strength. For equipment utilizing strain-based design methods, the equipment user should determine if additional qualification approaches are required, that are not defined by the ISO 15156 series.

Cold work can increase susceptibility to the cracking mechanisms that are within the scope of this document. Limits placed on plastic strain during manufacture of the grades/equipment listed in Annex A and Annex B are given in ISO 15156-1.

NOTE Certain cold-worked CRA grades are listed in Annex B. No plastic strain limits are given in ISO 15156-1 for these grades. Instead, appropriate mechanical property limits are defined.

Plastic strain occurring during installation shall be defined and included in the H₂S service assessment. This can require qualification of pre-strained material by H₂S-testing in accordance with ISO 15156-3.

Plastic strain occurring in the presence of H₂S exacerbates the threat of EAC. The environmental limits given in Annex A and Annex B should not be applied for plastic straining in the presence of H₂S, nor for strain-based design codes or scenarios. Alternative criteria should be established by H₂S- testing, see ISO 15156-3.

Exposure time

Annex A and B.2 do not express environmental limits in terms of exposure duration, the limits are acceptable for any exposure duration. The equipment user may determine that a material is acceptable given the duration of exposure and severity of the environment, based on their H₂S service assessment and supporting data.

Time is required to initiate the cracking mechanisms relevant to this document, but this period is highly dependent on the material, the mechanism, the stress it experiences and the service environment.

NOTE 1 Failure by HIC can be much slower than failure by SSC or SCC.

NOTE 2 Some specific permissions regarding exposure period and maximum sustained tensile stress are given in B.3.

Galvanic coupling

Galvanic coupling can be detrimental in accelerating hydrogen charging of the more noble material and consequently result in GHSC (see ISO 15156-3:202x, 6.2) of materials susceptible to this cracking mode.

The equipment user should assess galvanic couples and include the likelihood of GHSC in the H₂S service assessment, where applicable. EAC severity for GHSC is greater for environments and/or couples that result in increased absorption of hydrogen into the CRA or other alloy either locally or generally. Where GHSC is deemed a credible threat, qualification testing should be undertaken. Guidance on GHSC testing approaches is given in ISO 15156-3:202x, 8.4.4.

NOTE 1 Guidance on the susceptibility of the different material categories to GHSC is included in Table 2.

NOTE 2 The effect of GHSC of martensitic and ferritic stainless steels (including precipitation hardened variants) is typically most pronounced at temperatures close to (and likely below) 24 °C, for any specific combination of other parameters defined for the environment. Environmental effect of GHSC for other CRAs and other alloys can be more pronounced at other temperatures.

NOTE 3 Galvanic couples can exist between a surface treatment and the underlying substrate.

Exposure only in the event of a leak or seep of the H₂S-containing fluids

Some components will only see H₂S-containing fluids in the event of a leak or seep of production or injection fluids, but nevertheless an equipment user or equipment specification can require that such components be designed to tolerate the leaking fluids.

In such instances, the accidentally exposed equipment shall be selected in accordance with this document assuming the same environmental conditions that apply to the equipment exposed to the production fluids by design. The equipment user may alternatively conduct a separate H₂S service assessment specific to the environment established by the leak and select materials accordingly.

NOTE 1 One such example can be low alloy steel bolting and fasteners under insulation or that is buried, or otherwise denied direct exposure to the surrounding non-H₂S-containing environment (e.g. seawater or atmosphere); see A.4.3.1. If the equipment user determines that p_H2S of the environment that would be established at a leak has less than 0,34 kPa (0,05 psia), then only Region 0 requirements apply.

NOTE 2 Another example can be production casing above a packer that is exposed to fluids leaking through a communication between the completion and the A-annulus. It is common practice to select carbon/low alloy steel production casing (and other not normally flow-wet secondary/primary barriers) that are resistant to SSC, assuming full exposure to the completion bore fluids.

The equipment user’s H₂S service assessment shall include the credible cracking threats.

Table 2 presents a summary of the cracking mechanisms that can be credible for each material group.

Table 2 — Cracking mechanisms of relevance to each material group

SSC

When assessing SSC threats to carbon and low alloy steels, the SSC environmental severity shall be defined, as a minimum, with the following environmental parameters: minimum pH, maximum p_H2S and minimum service temperature.

The combination of minimum pH and maximum p_H2S shall be used to define the Region of SSC environmental severity as defined in Figure 3. Region 4 contains the most severe conditions and Region 0 contains the least severe.

For the potential effect of other parameters, see 6.1.

NOTE 1 SSC is a form of hydrogen stress cracking. Environmental severity for SSC is greater for environments that result in increased absorption of hydrogen into the carbon or low alloy steel either locally or generally, see API 6ACRA and ISO 11960.

Region 0 defines a region of SSC environmental severity for which carbon and low alloy steels are generally not susceptible to SSC.

The discontinuities in Figure 3 at and below 0,34 kPa (0,05 psia), reflect areas of uncertainty. These areas of uncertainty are shaded to highlight the relevant pH and p_H2S parameters. At pH < 4, the Region 0 boundary can deviate from the p_H2S 0,34 kPa (0,05 psia) boundary line. Within this area of uncertainty, increased yield strength (see 6.2.2.1 NOTE 2), decreased pH and increased p_H2S increase susceptibility to SSC. The equipment user may designate conditions within the areas of uncertainty as Region 0, 1, 2, or 3.

NOTE 2 SSC within the regions of uncertainty in Region 0 has been demonstrated by SSC test failures of some product manufactured to API 5CT (ISO 11960) grade Q125, P110 and N80 Type 1, covering a range of SMYS from 552 MPa to 862 MPa (80 ksi to 125 ksi), see Reference [69].

H₂S environments in Region 4 are more severe than those qualified by standard test conditions at 100 kPa (14,5 psia) H₂S, e.g. NACE TM0177:2024, Solution A. For more information see Reference [42].

The equipment user shall assign an SSC Region for environments with pH < 2,5.

For partial pressures of H₂S exceeding 1 000 kPa (145 psia), the equipment user may designate the SSC environmental severity as Region 3 or Region 4. If no Region is designated, then materials shall be qualified in accordance with ISO 15156-3 and not selected from Annex A.

Key

NOTE 1 The discontinuities in the Figure 3 at and below 0,34 kPa (0,05 psia) reflect areas of uncertainty with respect to the measurement of H₂S partial pressure (low H₂S) and the performance of some steels at low values of pH. These areas of uncertainty are shaded for clarity.

NOTE 2 Regions can be extrapolated to higher pH values than are shown in the Figure 3, but the Figure 3 is only valid for pH ≥ 2,5, and 0 kPa to 1 000 kPa (0 psia to 145 psia) partial pressure H₂S.

Figure 3 — Regions of SSC environmental severity for carbon and low-alloy steels

In addition to pH and p_H2S, the service temperatures that the equipment can be exposed to in the presence of H₂S can impact susceptibility. Figure 3 is based on H₂S-testing conducted at 24 °C (75 °F). SSC testing at approximately 24 °C (75 °F) was also used for the original qualification of the materials listed in Annex A. Lower temperatures can increase SSC susceptibility (see 6.1.2.3) and higher temperatures can decrease SSC susceptibility, see Table A.4.

NOTE 3 Figure 3 is based on H₂S tests conducted mostly at approximately 100 kPa (14,5 psia) total pressure.

HIC/SWC

Hydrogen induced cracking (HIC) is a consequence of the internal recombination of absorbed hydrogen. Step-wise cracking (SWC) is a form of hydrogen stress cracking, but is typically not assessed as a threat that is distinct from HIC. Analysis of environmental severity for HIC and its assessment are considered to also address SWC; SWC is not described separately in this document. Assessment for HIC is considered to also provide assessment of SWC.

Analysis of a HIC threat shall include determination of the need to specify more restrictive manufacturing parameters than are mandated by ISO 15156-1.

NOTE 1 Some flat rolled steels can be susceptible to HIC even within the well-defined areas of SSC Region 0. This is especially true for some legacy steels with high sulfur contents.

NOTE 2 Manufacturing parameters such as steel composition, cleanliness, microstructure and manufacturing route, have an important influence on HIC susceptibility. For example, increased microstructural banding and more pronounced segregation are detrimental to HIC resistance. Clean steel technologies and control of metallurgy with desulfurization and inclusion shape control, minimized centreline segregation and minimization of banded microstructures are common in the manufacture of HIC-resistant steels. ISO 15156-1 provides guidance on these aspects for improved HIC resistance.

Environmental severity for HIC should be assessed for all flat rolled carbon and low alloy steels (and components manufactured from these products, e.g. seam welded pipes). No HIC-specific regions of environmental severity are defined, such as would be analogous with the SSC regions of environmental severity that are described in 6.2.2.1. However, like SSC, the environmental severity for HIC is more aggressive at lower values of pH and higher values of p_H2S.

NOTE 3 Some product specifications provide more restrictive manufacturing parameters and HIC testing to ensure adequate HIC resistance, for example line pipe in conformance with ISO 3183. For the purposes of this note, API 5L is considered equivalent to ISO 3183. Similarly, ISO 13628-2 requires HIC testing of tensile armor wires for unbonded flexible pipe. For the purposes of this note API 17J is considered equivalent ISO 13628-2.

For p_H2S exceeding 100 kPa (14,5 psia), the equipment user’s H₂S service assessment should determine if HIC qualification testing in an H₂S partial pressure exceeding 100 kPa (14,5 psia) is required.

When assessing HIC threats to flat rolled steels, the environmental severity assessment shall be defined with at least minimum pH and maximum p_H2S. The equipment user may include exposure durations and effect of corrosion inhibition (including its reliability) in their assessment of HIC.

NOTE 4 In some specific instances, HIC can also be a threat for some seamless pipe, high strength wire used in flexible pipe, rod, forgings and castings. For example, very thick section seamless pipe or forgings, high strength wire used in flexible pipe and other products that can have oriented microstructural heterogeneities.

NOTE 5 HIC is less likely at low partial pressures of H₂S. Work on seam welded line pipe has demonstrated that HIC does not occur at partial pressures of H₂S that do not exceed 0,1 kPa (0,015 psia) in production environments, see References [47] and [75].

SOHIC

Stress Oriented Hydrogen Induced Cracking (SOHIC) is a consequence of the internal recombination of absorbed hydrogen and hydrogen stress cracking. Environmental severity for SOHIC is greater for environments that result in increased absorption of hydrogen into the carbon or low alloy steel either locally or generally.

No SOHIC-specific regions of environmental severity are defined, such as would be analogous with the SSC regions of environmental severity that are described in 6.2.2.1. However, like HIC, the environmental severity for SOHIC is more aggressive at lower values of pH and higher values of p_H2S.

SOHIC is typically limited to flat rolled product and often is considered not credible for steels proven to be resistant to SSC and HIC. Some flat rolled steels can be susceptible to SOHIC even within the well-defined areas of SSC Region 0.

When assessing SOHIC threats to flat rolled steels, the environmental severity shall be defined at least with minimum pH and maximum p_H2S.

Environmental severity for SOHIC of carbon and low alloy steels is at a maximum at temperatures close to 24 °C (75 °F), for any specific combination of other environmental parameters.

The threat of SSC shall be assessed for cast irons.

Assessment and definition of environmental severity is the same as that specified for carbon and low alloy steels, see 6.2.2.

NOTE Typically, in oil and gas service cast irons are used for equipment under compression or with low applied stresses.

General

For CRAs and other alloys no environmental severity regions (such as shown in Figure 3 for carbon alloy steels) are defined. Instead, individual parameter limits are defined for those materials in Annex B. An H₂S service assessment shall be performed for service environments that contain H₂S.

SSC

The H₂S service assessment shall include SSC for all ferritic and martensitic stainless steels, including those that are precipitation hardened, and all duplex stainless steels. The assessment shall include at least the following parameters: minimum pH, maximum p_H2S, maximum chloride concentration and service temperature range.

The environmental severity for SSC in CRA and other alloys is greater at lower values of pH and higher values of p_H2S and chloride.

Environmental severity for ferritic and martensitic stainless steels, including those that are precipitation hardened, is typically greatest at 24 °C or below, for any combination of environmental parameters. Environmental severity for duplex stainless steels can be greatest at temperatures between 80 °C and 100 °C, for any combination of environmental parameters.

SCC

The H₂S service assessment shall include SCC for CRA and other alloys. The assessment shall include at least the following parameters: minimum pH, maximum p_H2S, maximum chloride concentration, maximum temperature and the presence of elemental sulfur.

The environmental severity for SCC in CRA and other alloys increases at lower values of pH and higher values of p_H2S, temperature and chloride. Environmental severity is also increased in the presence of elemental sulfur.

GHSC

Some material groups are susceptible to GHSC where these are the cathode in the galvanic couple, see 6.1.3.4 and Table 2. The H₂S service assessment should include GHSC for susceptible material groups that are coupled (in the H₂S-containing environment) to a material that is not corrosion-resistant to the H₂S-containing environment. In most instances the non-corrosion-resistant material is a carbon or low-alloy steel. The assessment shall include at least the following parameters: minimum pH, maximum p_H2S, maximum chloride concentration, temperature range and the galvanic couple.

It is the responsibility of the equipment user to determine the severity and the acceptability of a galvanic couple in the given service environment.

NOTE 1 Galvanic couples between CRA can shift the corrosion potential in a direction that can cause an otherwise corrosion-resistant material to pit and possibly crack.

NOTE 2 Guidance on testing for qualification for GHSC is provided in ISO 15156-3:202x, 8.4.4. ISO 15156-3:202x, C.8 specifies a permitted test for qualifying GHSC resistance for solid solution nickel-based alloys and precipitation hardened nickel-based alloys.

Materials shall be selected from the following options:

— carbon and low alloy steels and cast irons in accordance with Annex A for applications within the defined SSC environmental severity Regions defined in 6.2.2.1;

— CRA and other alloys according with Annex B;

— carbon and low alloy steels, cast irons, CRA or other alloys qualified in accordance with Clause 8.

Materials selected from the options given in Annex A or Annex B shall meet the following provisions:

a) the materials selected are acceptable based on the factors determined in the H₂S service assessment;

b) where applicable (see 8.5 to 8.7), its weldments and coatings, plating, cladding, weld overlays and the impact of other manufacturing processes are in conformance with ISO 15156-1.

When selecting materials from Annex A or Annex B, the H₂S content shall be defined in terms of H₂S partial pressure in the gas phase. The equipment user may apply H₂S fugacity instead of H₂S partial pressure (i.e. applying f_H2S as a direct substitute for p_H2S in the H₂S service assessment, and when using the environmental limits given in Annex A and Annex B), provided that this is justified by supporting high pressure test data. Further guidance on the use and validation of H₂S fugacity for materials selection is given in Annex C.

NOTE The environmental severity regions in 6.2.2.1 for carbon and low-alloy steels and the H₂S environmental parameter limits in Annex A and Annex B, are stated in terms of H₂S partial pressure. Guidance is given in Annex C for the calculation of an “associated” H₂S partial pressure for evaluation of all liquid systems (for which there is no actual separate gas phase).

In some instances, Annex B gives different environmental limits for the same CRA individual alloy, dependent on the equipment application. Where there are specific restrictions to an extended, application-specific limit, this is stated in the relevant clauses of Annex B.

ISO 15156-1 allowances for plastic strain during manufacturing shall not be used as a basis to accept plastic strain experienced in an H₂S-containing environment. Plastic strain in the presence of H₂S can increase the threat of EAC. Annex A and Annex B are not valid for plastic strain coincident with the presence of H₂S.

Materials that are not listed in Annex A or Annex B, alternative material conditions to those listed in ISO 15156-1, or alternative limits for general or specific applications may be qualified in accordance with ISO 15156-3. Further requirements and guidance are given in Clause 8.

Material classes in API 6A and the overall API 6A designation include a material grouping, an H₂S partial pressure limit and temperature class. Other environmental parameters of relevance to the ISO 15156 series are not part of the designation. Use of trees and wellheads shall be limited by the most restrictive combination of material and environment. Environmental parameters used for materials selection for production/injection fluids shall include, as a minimum:

a) temperature range;

b) maximum p_H2S;

c) maximum chloride concentration;

d) minimum pH;

e) presence of elemental sulfur.

Table 3 addresses pressure containing and higher stressed components (body, bonnet, hanger, end and outlet connectors), and components that are typically under low maximum sustained tensile stress (valve bore sealing mechanisms, choke trim and stems).

NOTE The grouping of components does not necessarily match the grouping in API 6A.

Table 3 — Correlation between API 6A:2024 materials class, components, and the ISO 15156 series limits and requirements<Tbl_--></Tbl_-->

For other equipment and components see Tables A.1 and B.1.

Specifications for materials selected using Annex A or Annex B shall conform with the materials requirements of ISO 15156-1.

Qualification or verification (with respect to service in H₂S-containing fluids) shall be undertaken if specified by the equipment user or by the relevant clauses in Annex A or Annex B, or in ISO 15156-1.

Qualification of carbon or low alloy steels selected from Annex A should be undertaken for service in environments where H₂S exceeds 1 000 kPa (145 psia).

NOTE Qualification or verification of alloys selected from Annex A or Annex B is not common for most equipment and service environments. Further requirements that are specific to the material group or manufacturing/fabrication process are given in 8.2 to 8.7.

Verification is typically by hardness or mechanical property test. The equipment user or manufacturer may specify verification by H₂S-testing in conformance with ISO 15156-3 for materials qualified as per 8.1.3.

NOTE Verification H₂S-testing in accordance with ISO 15156-3 can be required by product specifications but it is rare for most products. Examples where verification testing that includes environmental cracking tests has become standardized include some grades of casing (ISO 11960, API 5CT) and line pipe (ISO 3183, API 5L).

The equipment user may select a material which is not listed in Annex A or Annex B, or which does not meet the material specification requirements of ISO 15156-1. Where this is the case, material qualification by H₂S-testing or field experience in conformance with ISO 15156-3 shall be undertaken.

Existing qualification data may be used; for example, previous H₂S-testing performed by the equipment user or manufacturer. The equipment user shall remain responsible for the acceptance of qualification data and the associated materials specification. In some cases, existing data might not be in full conformance with the current version of the ISO 15156 series (including its normative references such as NACE TM series documents). The equipment user shall assess and document the validity of such existing qualification data and accept or reject accordingly.

Examples of reasons to conduct qualification by H₂S-testing include:

a) use of carbon and low alloy steel outside of the bounds of Figure 3 or beyond the limits stated in Annex A;

b) use of CRA and other alloys beyond the limits stated in Annex B;

c) use of a material or manufacturing/fabrication procedure that is not in conformance with the requirements of ISO 15156-1 (for example additively manufactured components);

d) use of a material that is not included in Annex A or Annex B;

e) use of a carbon and low alloy steel within Region 4, as described in 6.2.2.1;

f) verification of a materials selection approach that substitutes p_H2S with f_H2S (where permitted by the equipment user);

g) qualification of a welding procedure or surface modification procedure, where this is required by the H₂S service assessment;

h) qualification of a specific manufacturer’s product, where this is required by the H₂S service assessment;

i) qualification of materials in existing equipment for a change in operational environment e.g. increased souring or tie-back of wells from a different reservoir.

Further guidance on the identification of credible cracking mechanisms is given in 6.2. Qualification test environment shall be appropriate for the material being tested and representative of the environmental factors described in 6.1. More than one test environment can be required to cover the full range of service conditions and avoid a single test environment that is more severe than any of the actual service exposures.

8.2 to 8.5 list the minimum set of cracking mechanisms that shall be addressed by the qualification tests.

Carbon and low-alloy steels that are selected in accordance with Annex A shall conform with ISO 15156-1.

Qualification of a material not included in Annex A shall as a minimum include SSC testing in conformance with ISO 15156-3. The requirement to address other cracking mechanisms shall be as per the equipment user’s H₂S service assessment.

Verification of HIC resistance shall be performed when required by the equipment user’s H₂S service assessment for HIC, or by the applicable product specification. If a product specification gives requirements and acceptance criteria for a HIC verification test, then these shall apply. If the product specification refers to the ISO 15156 series for test method and/or acceptance criteria, those given in accordance ISO 15156-3 shall be used.

Cast irons that are selected in accordance with Annex A shall conform with ISO 15156-1.

Qualification of a material not included in Annex A shall include SSC testing in conformance with ISO 15156-3. The requirement to address other cracking mechanisms shall be as per the equipment user’s H₂S service assessment.

CRAs and other alloys that are selected in accordance with Annex B shall conform with ISO 15156-1.

Qualification of a material not included in Annex B shall be in conformance with ISO 15156-3 and include all relevant cracking modes identified in the equipment user’s H₂S service assessment, see Clause 6.

Materials that can be susceptible to GHSC are indicated in Table 2. For these grades, where galvanic couples are present, the equipment user shall determine the need for qualification based on their H₂S service assessment. The equipment user shall specify if supplemental qualification H₂S-testing in accordance with ISO 15156-3 is required. The equipment user may specify alternative test method, test environment, surface area ratio of the dissimilar metal combination, and test temperature to better represent the application and service.

The metallurgical changes that occur on welding or weld overlay can affect the susceptibility of the base metal and the weld/overlay to the relevant cracking mechanisms.

Weldments shall conform with ISO 15156-1, which includes hardness testing and applicable acceptance criteria, or be qualified by H₂S-testing in accordance with ISO 15156-3. The equipment user should assess if the hardness test method used for the qualification can discriminate between different microstructural regions of the weld (including the HAZ).

NOTE Rockwell C hardness indents are much larger than Vickers hardness indents and might not be capable of discriminating different microstructural zones.

Weldments shall conform with ISO 15156-1.

When the equipment user's H₂S service assessment identifies an exposure to Region 1 or Region 2 environments, the equipment user may permit the following weldment hardness readings:

a) for SSC Region 1, weldment hardnesses not exceeding 300 HV;

b) for SSC Region 2, weldment hardnesses not exceeding 280 HV.

When hardness requirements are relaxed as permitted in 8.5.2 a) or 8.5.2 b) the weld should be qualified for SSC resistance in conformance with ISO 15156-3 and hardness testing shall be undertaken using the Vickers hardness test method.

NOTE 1 These alternative hardness requirements have typically been applied only to pipeline steels. For further background information on weld hardness and SSC resistance see Reference [61]. Relaxed hardness criteria have also been historically applied to downhole screens where temperatures are elevated and service stresses are typically low.

Verification for HIC resistance by H₂S-testing in accordance with ISO 15156-3 can be required for seam welds in components manufactured from flat rolled product. The equipment user shall specify HIC verification testing in conformance with ISO 15156-3 when appropriate based on their H₂S service assessment.

NOTE 2 Seam welds fabricated using high frequency induction (HFI) or electric resistance (ERW) welding processes can be more susceptible to HIC than those fabricated using other processes: verification by H₂S-testing of HIC resistance is important for HFI or ERW seam welded pipe and fittings even at low values of p_H2S.

Weld procedure qualification hardness testing of surface piping and linepipe may be waived by the equipment user for steels with SMYS not exceeding 360 MPa (52 ksi), see ISO 15156-1:202x, 8.9. This decision should be influenced by the H₂S service assessment and is typically only granted for less severe environments (such as SSC Region 1 or Region 2).

Weldments shall conform with ISO 15156-1, which also specifies hardness testing for weld procedure qualification.

The metallurgical changes that occur when welding CRAs and other alloys can affect their susceptibility to SSC, SCC, and/or GHSC. Welded joints can have greater susceptibility to cracking than the parent material(s) joined.

NOTE 1 Even “similar” welding consumables can have different chemistry, as well as result in grain size, inclusion contents, microstructural phase balance and other factors that are very different to the parent materials. In addition, weld thermal cycles, together with any post-weld heat treatment, can alter the properties and performance of both the weldment as a whole and the parent materials.

Depending on the material, ISO 15156-1 requires specific chemistry, specific weld consumable, post-weld heat treatment and mechanical property requirements for weldments in CRA and other alloys. The equipment user should assess if these criteria are sufficient to deliver adequate cracking resistance given the applicable H₂S service assessment.

The equipment user may specify qualification testing in conformance with ISO 15156-3, as part of the welding procedure qualification to ensure the weldment provides adequate resistance to SSC, SCC, and/or GHSC for the application.

The environmental limits listed in Tables of Annex B can be inappropriate for weldments due to the following factors:

a) welding consumables suitable for the parent material often do not match the chemical composition requirements of the parent grade listed in Annex A or Annex B;

b) the heat-affected zone of a weld will likely no longer meet one of the permitted parent material heat treatment conditions;

c) the weld fusion zone will comprise the weld consumable chemistry diluted to some extent by that of the parent material and further complicated by absorption of gaseous species in the shielding gases and evaporation of volatile elements in the consumable/parent;

d) the welding process will result in residual stresses and strains across the weld zone due to the contraction of the fused metal and localised heating although this can be mitigated by thermal stress relief;

e) the weldment surface condition will be different from that of the parent material due to oxidation during welding and, if applied, subsequent chemical treatments.

f) the weld profiles can present a stress concentration, resulting in high local stresses under load.

NOTE 2 Cracking susceptibility is particularly high when environmental severity is near the application limits of the parent material and high stresses or strains are present (welds that have not been stress-relieved often exhibit near-yield level residual stresses).

Dissimilar weldments, for which the dissimilar metals are exposed to the H₂S-containing environment, shall be in conformance with the clauses of ISO 15156-1 that are applicable to each parent material and the weld material. This can result in each zone of the dissimilar weldment (first parent material and HAZ, weld metal and second parent material and HAZ) having different specifications and acceptance criteria.

Dissimilar welds between carbon steel and corrosion-resistant alloys should be qualified by H₂S-testing in conformance with ISO 15156-3, unless established as acceptable by the equipment user’s H₂S service assessment.

NOTE 1 Failures have been experienced in some production environments in dissimilar joints between CRA and low alloy steels due to GHSC, exacerbated by local hard zones in the weldment, see References [44], [48], [51] and [72].

NOTE 2 See 8.6 for clad or weld overlayed components.

The substrate parent material and HAZ of weld overlayed, clad, metallic lined or hard-faced parts shall be in conformance with ISO 15156-1 requirements, unless all the following apply:

a) the substrate parent material and HAZ are wholly isolated from the H₂S-containing fluids;

b) the overlay, cladding, liner or hard-facing is designed for the full life of the equipment (accounting for all applicable degradation modes);

c) the overlay, cladding, liner or hard-facing materials selection is in conformance with this document and ISO 15156-1 or has been qualified in accordance with ISO 15156-3.

Except where listed in Annex A or Annex B, material processing and property requirements and environmental limits are not specified in the ISO 15156 series for wear-resistant alloys.

Wear-resistant alloys that are used for components that are subject to tensile loading (and that are a critical to pressure containment) shall be included in the H₂S-service assessment, see Clause 6.

NOTE Some materials used for wear-resistant applications can be brittle. Cracking can occur if these materials are subject to tension. Components made from these materials are normally loaded only in compression.

The parent material of coated, plated or polymeric lined parts that are exposed to H₂S-containing environments shall be selected in conformance with this document. The equipment manufacturer shall ensure that the coating, plating and polymeric and other non-metallic lining procedures conform with the applicable clauses of ISO 15156-1.

NOTE Coatings and platings are not reliable barriers to H₂S-containing fluids. Polymeric liners are permeable and H₂S-containing fluids can diffuse through the liner.

Surface treatments shall not be relied upon to prevent EAC; the selection of the substrate material shall conform with this document. The equipment user and manufacturer should assess the impact of a surface treatment on the cracking resistance (including GHSC) of the substrate.

Spray metalizing, nitriding, nitrocarburizing and boronizing are permitted surface treatments and shall conform with ISO 15156-1. Brazing is permitted for carbon and low alloy steels and shall conform with ISO 15156-1.

Permitted surface treatments for carbon and low alloy steels are given in A.8.

Permitted surface treatments for corrosion-resistant alloys and other alloys are given in B.4.

Annex A and Annex B shall not be used for additively manufactured equipment and components.

NOTE 1 Whilst the UNS numbers included in Annex A and Annex B can be used for AM parts, the content of Annex A and Annex B does not apply to AM equipment and components.

Additively manufactured equipment and components shall be qualified in accordance with ISO 15156-3:202x, 10.2.3. The equipment user may, on the basis of their H₂S service assessment, accept an AM component without H₂S-testing in accordance with ISO 15156-3.

NOTE 2 Qualification by H₂S-testing can be unnecessary when the environmental severity derived by the H₂S service assessment is benign compared to the general performance envelope of the wrought or cast equipment.

The qualification protocol of AM equipment and components for sour service is not well established. General guidance is given in ISO 15156-3:202x, C.8.

NOTE 3 See AMPP TR21522 for general guidance on AM equipment and components.

The equipment user may permit qualification of wire arc AM (WAAM) as per the requirements for a weld or for AM equipment and components in accordance with ISO 15156-3:202x, 10.3 or C.7, respectively.

NOTE 4 The scope exclusions in Table 1 apply to all manufacturing processes, including AM.

The H₂S service assessment shall be documented. In addition, materials selected or qualified in accordance with this document shall have the method of selection documented as one of the following options:

a) for a material selected in accordance with Annex A or Annex B, reference to ISO 15156-1 for specification;

b) for a material selected on the basis of qualification, reference to documentation in conformance with ISO 15156-3.

The equipment user shall be responsible for ensuring that the required documentation is prepared and retained.

If materials are selected on the basis of item b), appropriate additional information shall be clearly indicated in the materials purchasing specification, e.g. requirements for verification H₂S-testing.

1. 
   (normative)
   
   SSC-resistant cast irons, carbon and low alloy steels
   1. General

Annex A describes and lists SSC-resistant cast irons and carbon and low alloy steels for materials selection purposes. Specification requirements for these materials are given in ISO 15156-1. Steels complying with ISO 15156-1 might not resist SOHIC, SZC, HIC or SWC. It can be necessary to specify additional supplemental tests to demonstrate resistance to these mechanisms (see ISO 15156-3).

Table A.1 provides a guide to the applicable clause for SSC-resistant cast irons, carbon and low alloy steels for the relevant equipment or components.

Table A.1 — Guidance on the use of Annex A for service conditions within the different regions of SSC environmental severity

• 1. SSC-resistant cast irons
     1. General

Ferritic ductile iron in accordance with ASTM A395 may be used for equipment unless otherwise limited or restricted by the equipment standard.

Grey, austenitic and white cast irons shall not be used for pressure-containing parts. These materials may be used for internal components if their use is permitted by the equipment standard and has been approved by the equipment user.

• • 1. Packers and subsurface equipment

The cast irons in Table A.2 may be used for the listed applications.

Table A.2 — Cast irons for packers and other subsurface equipment

• • 1. Compressors and pumps

Grey cast iron (ASTM A278, Class 35 or 40) and ductile (nodular) cast iron (ASTM A395) may be used as compressor cylinders, liners, pistons and valves. Soft, low-carbon irons may be used as gaskets.

• 1. SSC-resistant steels for use throughout SSC Region 4
     1. General

Carbon and low alloy steels selected in conformance with A.3 may be used for use in any SSC Region defined in 6.2.2.1.

Steels listed in A.4 may be used, with the exceptions and supplemental requirements given in A.3.2.

Legacy qualifications conducted to previous editions of the ISO 15156 series in NACE TM0177:2024, Solution A remain valid for qualification to Region 4, except for those material-product form combinations specifically described in A.3.2.

• • 1. Service limits and acceptable materials for specific product forms
       1. Pressure vessel steels

Pressure vessel steels shall meet the requirements of A.4.2.1.

Pressure vessel steels manufactured from TMCP product shall conform with the supplemental requirements for TMCP-rolled steels given in A.3.2.3.

• • • 1. Piping, valves and associated components

Piping, valves and associated components shall meet the requirements of A.4.2.2.

Piping, valves and associated components manufactured from TMCP product shall conform with the supplemental requirements for TMCP-rolled steels given in A.3.2.3.

• • • 1. Line pipe

Products for line pipe shall meet the requirements of A.4.2.3, with the following exceptions and supplemental requirements:

HFI seam welded pipe shall not be used.

TMCP-rolled steels shall be specified in accordance with ISO 15156-1 and shall be qualified by H₂S-testing in accordance with ISO 15156-3 based on the equipment user’s H₂S service assessment.

TMCP-rolled steels (including pipe and fittings made from this product) shall be subject to additional specification to ensure that local hard zones are not present at surfaces in contact with the H₂S-containing environment. Based on the equipment user’s H₂S service assessment the equipment user or manufacturer may specify one or more of the following with agreed acceptance criteria:

a) manufacturing procedures and associated surveillance that prevent the formation of local hard zones at the surface;

b) micro hardness testing in close vicinity to surfaces in contact with the H₂S-containing environment (see ISO 15156-1:202x, 8.1 for further guidance).

NOTE 1 IOGP S-616 contains guidance on the detection of local hard zones in TMCP line pipe.

NOTE 2 TMCP-rolled steels that are free of local hard zones have shown SSC resistance, but this can also depend on the microstructure type and homogeneity. The presence of local hard zones close to the surfaces can, however, affect their susceptibility to SSC. Increasing environmental severity, decreased material homogeneity, microstructure type and higher local surface hardness can increase susceptibility to SSC.

• • • 1. Downhole casing, tubing and tubular components

Production casing and associated tubular components, and production tubing and associated tubular components shall meet the requirements of A.4.2.4, with the following exceptions and supplemental requirements:

a) They shall be seamless.

NOTE 1 There have been field failures of seam welded API 5CT grades J55 and L80 Type 1 in SSC Region 4, see References [55] and [67].

b) They shall be qualified by H₂S-testing in accordance with ISO 15156-3. The equipment user may accept alternative qualifications for equipment manufactured from bar or mechanical tubing.

c) They shall be verified by NACE TM0177:2024, Method A and Solution A, H₂S-testing in accordance with API 5CT 11^th Edition, SR 46. The equipment user may accept an alternative verification testing approach.

NOTE 2 API 5CT 11^th Edition, SR 46 specifies NACE TM0177:2024, Method A verification testing at 90 % SMYS. SR 46 is specifically for grades C90 and T95, but the same philosophy (90 % SMYS test stress and identical sampling locations) can also be applied to other grades.

d) The elevated temperature permissions in Table A.4 (i.e. the second, third and fourth columns of Table A.4) shall not be used without the agreement of the equipment user. The equipment user or manufacturer may determine acceptable minimum elevated temperature thresholds by H₂S-testing in accordance with ISO 15156-3.

NOTE 3 Production casing in this context includes production casing, production liner, production tie-backs and their connected accessories that form a secondary (sometimes a primary) barrier to the containment of production fluids.

NOTE 4 Production tubing in this context is the conduit through which production fluids flow to the tree and includes tubing accessories, such as crossovers. Associated tubular components include bored bar, mechanical tubing and API 5CT coupling stock and accessory material used for the manufacture of completion equipment.

NOTE 5 SSC testing has demonstrated that SSC environmental fracture toughness can be greatly reduced in Region 4 compared with Region 3. Fissuring also appears to have a greater likelihood. For further information, see References [73], [74] and [79].

• 1. SSC-resistant steels for use throughout SSC Region 3
     1. General

Carbon and low alloy steels selected in conformance with A.3 may be used.

Carbon and low alloy steels may be used for any equipment or product form not listed in A.3.2 to A.3.3, provided the material meets the requirements listed for steels specified in ISO 15156-1:202x, 8.1.

NOTE 1 Unless stated otherwise in the applicable clauses of A.4, implicit in the listed material product specification or in ISO 15156-1, steels in this category are limited to 22 HRC (250 HV, 237 HBW).

NOTE 2 The method of hardness assessment and other essential requirements are given in ISO 15156-1:202x, Clause 7.

NOTE 3 Verification for HIC resistance can be required for plate and product manufactured from plate; see 8.2 for assessment of HIC and the need for supplemental testing for this threat.

• • 1. Service limits and acceptable materials for specific product forms
       1. Pressure vessel steels

Pressure vessel steels classified as P-No 1, Group 1 or 2, in Section IX of the ASME Boiler and Pressure Vessel Code may be used. Pressure vessel steels that are equivalent to these steels in EN 10028-2 may also be used, such as P235GH, P265GH, 295GH and P355GH. For materials specification requirements see ISO 15156-1:202x, 8.8.

• • • 1. Piping, valves and associated components

Products for piping, valve and associated components shall meet the requirements of ISO 15156-1, see ISO 15156-1:202x, 8.7.

NOTE Many industrial specifications do not conform with the composition and hardness requirements of ISO 15156-1. IOGP S-563 is an example of sour service supplementary requirements to common ASTM specifications.

• • • 1. Line pipe

Line pipe products listed in Table A.3 may be used.

Line pipe that is subject to strain hardening, e.g. lay operations, should be qualified by H₂S- testing in accordance with ISO 15156-3.

TMCP-rolled steels may be used when specified in accordance with ISO 15156-1 and if permitted by the equipment user’s H₂S service assessment. The equipment user should require additional specification as described in A.3.2.3. The equipment user may determine that qualification testing per ISO 15156-3 is not necessary based on their H₂S service assessment.

Table A.3 — Acceptable line pipe products

Line pipe shall meet the requirements of ISO 15156-1, see ISO 15156-1:202x, 8.7.

• • • 1. Downhole casing, tubing and tubular components

ISO and API grades of oil country tubular goods (OCTG) may be used within the temperature ranges given in Table A.4. Temperature ranges for equivalent variant OCTG grades and for bar, forging and mechanical tubing grades commonly used for equipment are also given in Table A.4.

API 5CT grades with greater than 0,99 mass% Ni shall not use Table A.4. For these materials, qualification to ISO 15156-3 shall be performed at the relevant minimum permissible temperature.

Material grades not listed in Table A.4 may be qualified in conformance with one of the qualification options in ISO 15156-3. Qualification in conformance with ISO 15156-3 may also be undertaken to establish alternative temperature limits.

OCTG specified to IOGP S-735 may be used for the service limits of the base API 5CT grade and/or the service limits established per the sour service performance envelope established as part of the product performance qualification defined in IOGP S-735.

ISO 15156-1 specifies requirements for stress-relief following cold work during connection manufacture, including when stress relief is necessary and minimum stress relief temperature, see ISO 15156-1: 202x 8.3.1 and 8.3.2.

Table A.4 — Acceptable exposure temperatures for casing, tubing, coupling stock, coupling material, accessory material and materials commonly used in downhole equipment^e

• • 1. Service limits and acceptable materials for specific equipment
       1. Bolting and fasteners

Bolting and fasteners that can be exposed to a sour environment shall conform to the requirements of A.3.1. See 6.1.3.5 regarding fasteners under insulation, buried or otherwise denied direct exposure to the external environment that are exposed to the H₂S environment in the event of a leak or seep through, for example, a seal.

Examples of materials that conform with A.3.1 are given in Table A.5.

Table A.5 — Bolting and fasteners materials that meet the requirements of A.3.1

• • • 1. Drilling blowout preventers
         1. General

The material, hardness, strength level and maximum sustained tensile stress of the blowout preventer shall be assessed for its robustness to H₂S-containing fluids considering the likelihood of SSC (see Clause 6) and its consequence.

NOTE Shear blades are by necessity manufactured from high strength grades that do not conform with the other provisions of A.4.

• • • • 1. Rams

Cr-Mo low-alloy steels for rams shall conform with UNS G41XX0 (formerly AISI 4IXX, and including modifications of these steels) and meet the requirements of A.4.1.

Rams may be manufactured from quenched and tempered Cr-Mo low-alloy steels that conform with ISO 15156-1:202x 8.4.

Material that does not conform with this provision shall be qualified in conformance with one of the qualification approaches given in ISO 15156-3.

• • • 1. Drilling and well equipment exposed only to drilling fluids, or completion or kill weight brines

Drilling and well equipment which does not comply with the other clauses of the ISO 15156 series may be selected provided that the following requirements are met:

a) the controlled environment shall be maintained by maintenance of sufficient hydrostatic head of the controlled fluid to minimize formation-fluid in-flow;

b) the controlled fluid shall meet one or more of the following criteria:

— the drilling fluid or brine is treated and monitored to maintain pH 10 or greater;

— the drilling fluid or brine is treated with a compatible chemical sulfide scavenger that is of sufficient concentration to remove the anticipated H₂S and which is uniformly mixed;

— the drilling fluid is oil-based with insufficient water content to form a separate aqueous phase (i.e. a continuous oil phase is maintained).

If the requirements of a) or b) cannot be met, the equipment may be accepted by the equipment user provided it is not a barrier element.

NOTE 1 Guidance on testing drilling fluids is given in API RP 13I.

NOTE 2 Equipment that meets these clauses can include casing strings in exploration wells that are not flowed (i.e. wells used for downhole sampling only), drill pipe and drilling equipment, and well construction and service tools and associated equipment. These items often require high strength, but there is no threat of SSC provided that they are only exposed to benign drilling or completion fluids.

NOTE 3 Temporary service tools that are not a barrier element, including but not limited to fishing tools, wellbore cleanup tools, casing exits, and through-tubing intervention equipment, are excluded from the scope of this document, see Table 1.

NOTE 4 Unintended flow of unexpectedly low pH and/or high p_H2S fluids can overwhelm the drilling fluid or brine chemical treatments described in A.4.3.3 b).

• • • 1. Compressors and pumps

Compressor impellers may be manufactured from UNS G43200 (formerly AISI 4320) and modified variants. Specification requirements for these grades are given in ISO 15156-1:202x, 8.7.

• • • 1. Gaskets

Soft carbon steel may be used for gaskets.

NOTE These gaskets are typically very low carbon steels (lower than 0,12 % C) that are annealed.

• 1. SSC-resistant steels for use throughout SSC Region 2

The steels listed in A.3 and A.4 may be used.

ISO 11960 or API 5CT grade C110 may be used for downhole casing, tubulars and tubular equipment.

NOTE Some pipeline steels with SMYS up to 485 MPa (70 ksi) have been successfully qualified. Typically, fabrication and field weld hardness has not exceeded 280 HV.

• 1. SSC-resistant steels for use throughout SSC Region 1

Steels listed in A.3, A.4, and A.5 may be used.

No specific carbon or low alloy steels are listed as suitable for service solely in SSC Region 1.

NOTE 1 Some casing, tubing and tubular components made of Cr-Mo low-alloy steels (UNS G41XX0, formerly AISI 41XX and modifications) and with actual yield strength ≤ 896 MPa (130 ksi) have been successfully qualified in the quenched and tempered condition. For these steels, typically SMYS ≤ approximately 760 MPa (110 ksi)] and hardness ≤ 30 HRC.

NOTE 2 Some pipeline steels with SMYS up to 550 MPa (80 ksi) have been successfully qualified. Typically, fabrication and field weld hardness has not exceeded 300 HV.

• 1. SSC-resistant steels for use throughout SSC Region 0

No restrictions are placed on the use of steels with actual yield strength not exceeding 965 MPa (140 ksi).

Steels with yield strength exceeding 965 MPa (140 ksi) can be susceptible to SSC, see 6.2.2.1. If H₂S exceeds 0,07 kPa (0,01 psia) use of such steels shall require the agreement of the equipment user. API 5CT (ISO 11960) grade Q125 may be used above the temperature limits given in Table A.4 even if its yield strength exceeds 965 MPa (140 ksi).

• 1. Acceptable steels for specific service applications
     1. General

Some equipment can be acceptable for service conditions not readily described by SSC Regions 0, 1, 2, 3, or 4. This equipment, and their specific acceptable applications and service environments, are described in A.8.2.

• • 1. Pipelines transporting stabilized crude

Pipeline steels with SMYS up to 483 MPa (70 ksi) may be used for service with stabilized crude (without environmental assessment per Clause 6). Fabrication and field welds should have hardness below 350 HV and be made in accordance with API 1104, ISO 13847 or CSA Z662 for non-sour service welds.

For new pipelines, equipment users shall assess the threat of HIC in accordance with 6.2.2.2.

NOTE Field experience has demonstrated successful service for stabilized crude (which typically has associated pH and p_H2S within Region 0 or Region 1), even for materials that do not meet the requirements of A.5. This is further mitigated by low water volumes. See 3.12 for definition of stabilized crude.

• 1. Surface treatment of carbon and low alloy steels

Surface treatments shall conform with ISO 15156-1:202x, 10.3.

Brazing, spray metalizing, nitriding, nitrocarburizing and boriding/boronizing surface treatments may be performed for service in all Regions of SSC environmental severity according to 6.2.2.1.

Other surface modifications of carbon and low alloy steel base materials may be performed where these do not result in any thermal transformations of the underlying material (See ISO 15156-1:202x 10.3 for definition of a critical temperature). Examples of surface modification processes that can meet these requirements include:

— electroplating and electroless plating;

— sherardizing;

— conversion coatings;

— plasma and chemical coating systems;

— gas dynamic cold spray coatings;

— peening;

— galvanizing;

— thermal cleaning;

— curing of organic coatings.

1. 
   (normative)
   
   Environmental cracking-resistant CRAs and other alloys
   1. General
      1. Use of Annex B

Annex B describes environmental limits for SSC and SCC resistant CRAs and other alloys, and gives guidance on GHSC resistance. Materials may be selected from either B.2 or B.3. Materials selected from B.2. or B.3 shall conform with the associated material requirements of ISO 15156-1.

B.2 lists alloys with established environmental limits both for general (any) applications and for specific components/equipment.

B.3 lists legacy entries based on past service experience including where no specific recorded data exists. The entries listed have no or limited environmental limits, but are restricted for use in specific application restrictions and/or in presence of mitigating factors.

Where the alloy-component combination is listed in B.3 and the alloy is also listed in B.2, either may be applied but the respective material requirements shall be applied in accordance with ISO 15156-1.

• • 1. Material groups

Materials groups are used to categorize CRAs or other alloys in Annex B as follows:

a) austenitic stainless steels (see B.2.2);

b) highly alloyed austenitic stainless steels (see B.2.3);

c) solid-solution nickel-based alloys (see B.2.4);

d) ferritic stainless steels (see B.2.5);

e) martensitic stainless steels (see B.2.6);

f) duplex stainless steels (see B.2.7);

g) precipitation-hardened austenitic stainless steels (see B.2.8)

h) precipitation-hardened martensitic stainless steels (see B.2.9);

i) precipitation-hardened nickel-based alloys (see B.2.10);

j) cobalt-based alloys (see B.2.11);

k) titanium and tantalum (see B.2.12);

l) copper, aluminium (see B.2.13).

• 1. Materials options for any equipment or components, and for specific equipment or components
     1. Materials selection tables
        1. General

B.2 contains materials selection tables showing the environmental limits of the materials when used for any equipment or component. B.2 also contains materials selection tables showing less restrictive environmental limits for materials when used for named equipment or components.

Materials may be selected using Tables B.2 to B.20.

Any material selected using the tables in B.2 shall conform to the material specification requirements of ISO 15156-1, including those applicable to the material group, grade, manufacturing process and equipment or component.

Welded materials shall conform to the requirements of ISO 15156-1.

The environmental limits presented in the tables in B.2 were established for parent materials that had not been welded. Welded materials can be more susceptible to cracking in the presence of H₂S than unwelded parent material.

The equipment user should determine the acceptability of welded material based on their H₂S service assessment. For an environmental severity that is close to the limit for the parent material, the equipment user should specify that welding procedures be qualified for service in the H₂S-containing environment by H₂S-testing in conformance with ISO 15156-3.

NOTE 1 See Clause 8 for guidance on qualification by H₂S-testing.

NOTE 2 All materials groups can be more susceptible when welded. Welded martensitic stainless steel and precipitation-hardened martensitic stainless steel materials groups can exhibit a marked reduction in cracking resistance.

The tables in B.2 show the application limits with respect to temperature, p_H2S, Cl−, pH and S⁰ level. Where no S⁰ level has been defined a “-“ is given in the respective entry. These limits apply collectively. The pH used in the tables corresponds to the minimum in situ pH (see 3.9). Guidance for the determination of these parameters is given in Clause 6. The limits given in the tables in B.2 are for production environments and do not cover conditions occurring during injection or flowback of chemicals that can reduce pH.

NOTE 3 In the tables given in B.2, the SI unit “milligrams per litre” is used for mass concentration. In US Customary units, concentration is commonly expressed in parts per million (ppm) by weight (sometimes expressed as ppmw). These SI and US customary units are not equivalent.

The environmental limits for an alloy are valid only for the alloy specification(s) listed in the same table. See Clause 7 and Clause 8 for other requirements regarding material selection, specification, qualification and/or verification.

Table B.1 provides a guide to the materials selection tables for any equipment or component (all-equipment tables). It also references B.3 for specific named equipment or components when other, less restrictive, environmental, or metallurgical limits may be applied (equipment-specific options). ISO 15156-1 often has different requirements associated with the same UNS number, applicable to specific equipment. Where ISO 15156-1 is referenced in Table B.2 to B.20 the ISO 15156-1 requirements specific to both the UNS number/material designation and the equipment shall be applied.

Table B.1 — Applicable clauses in Annex B by Material Group and equipment type<Tbl_--></Tbl_-->

• • • 1. Guidance on legacy entries

Some legacy entries in the materials selection tables originated from user experience documentation or H₂S-testing that deviates significantly from the principles of today’s practices. Often these entries give no limits for one or more of the parameters given in the respective table in B.2. Whilst most of these entries are given in B.3, some remain in the tables of B.2.

To assist the user of this document, table entries can contain remarks on equipment user experience. This equipment user experience is limited to the equipment users that participated in the development of this document and the actual limits of the material can differ from this experience (either higher or lower, as influenced by the overall combination of parameters that influence performance in H₂S-containing environments).

The absence of a specific environmental parameter limit does not necessarily mean that there is no limit and does not imply that the material could pass qualification to ISO 15156-3 for a given combination of parameters.

The H₂S service assessment remains the responsibility of the equipment user, including identification of any specific qualification needs for materials selected in accordance with B.2.

• • 1. Austenitic stainless steels

Environmental limits for austenitic stainless steels for any equipment or component are shown in Table B.2.

Table B.2 — Environmental limits for austenitic stainless steels used for any equipment or components

• • 1. Highly alloyed austenitic stainless steels

ISO 15156-1 lists the chemical compositions of alloys with two different groupings of alloying content. These are designated as AA and AB, with AB being the more highly alloyed. Materials are listed in Table B.3 either by these groupings or their specific UNS number:

a) type AA are highly alloyed austenitic stainless steels with (w_Ni + 2w_Mo) > 30 (where w_Mo has a minimum value of 2 %). The symbol w represents the percentage mass fraction of the element indicated by the subscript;

b) type AB are highly alloyed austenitic stainless steels with F_PREN > 40,0. Type AB grades also conform with type AA.

Highly alloyed austenitic stainless steels of Types AA or AB which also meet the requirements of B.2.4 Type NC may be evaluated as Type NC in accordance with Table B.4. In this instance the material shall meet the requirements for solid solution nickel-based alloy Type NC in accordance with ISO 15156-1.

Environmental limits for highly alloyed austenitic stainless steels for any equipment or component are shown in Table B.3.

Table B.3 — Environmental limits for highly alloyed austenitic stainless steels used for any equipment or components

• • 1. Annealed and cold worked nickel-based alloys

ISO 15156-1 specifies nickel-based alloy types with different groupings of chemical composition (specifically Cr, Mo and W in addition to Ni and Co content) and metallurgical condition.

The types NC, ND, NE and NF describe Ni-Cr-Mo/W alloys in either solution annealed or cold worked condition. Generally, the resistance to H₂S cracking increases with alloying and decreases with cold work. Limits for these types are shown in Table B.4.

Table B.4 — Environmental limits for annealed and cold-worked, solid-solution nickel-based alloys used as any equipment or component

• • 1. Ferritic stainless steels

Environmental limits for ferritic stainless steels for any equipment or component are shown in Table B.5.

Table B.5 — Environmental limits for ferritic stainless steels used for any equipment or components

• • 1. Martensitic stainless steels

Environmental limits for martensitic stainless steels for any equipment or component are shown in Table B.6.

Environmental limits for martensitic stainless steels in specific equipment/components are shown in Table B.7 and Table B.8.

NOTE Martensitic stainless steels can be susceptible to GHSC when coupled to carbon steel. H₂S-testing has demonstrated that S41426 can be resistant to GHSC at pH > 4,6.

Table B.6 — Environmental limits for martensitic stainless steels used for any equipment or components

Table B.7 — Environmental limits for martensitic stainless steel tubular mill product: casing, tubing, coupling stock, coupling material and accessory material

Table B.8 — Environmental limits for martensitic stainless steel used for subsurface equipment^a

• • 1. Duplex stainless steels

Environmental limits for duplex stainless steels for any equipment or component are shown in Table B.9.

Environmental limits for duplex stainless steels for downhole tubular components and for packers and other subsurface equipment are shown in Table B.10.

Table B.9 — Environmental limits for solution annealed duplex stainless steels used for any equipment or component

Table B.10 — Environmental limits for cold-worked duplex stainless steels used as downhole tubulars and subsurface equipment

• • 1. Precipitation-hardened austenitic stainless steels

Application limits for austenitic precipitation-hardened stainless steels for any equipment or component are shown in Table B.11.

Table B.11 — Environmental limits for austenitic precipitation-hardened stainless steels used for any equipment or component

• • 1. Precipitation-hardened martensitic stainless steels

Precipitation-hardened martensitic stainless steels have been balloted successfully for wellhead and tree sealing surfaces and trims and stems and for subsurface equipment excluding bodies, but only with restrictions on the tensile loads, see B.3.14 and B.3.15 respectively.

• • 1. Precipitation-hardened nickel-based alloys

Environmental limits for cast precipitation-hardened nickel-based alloys for any equipment or component are shown in Table B.12.

Environmental limits for material in conformance with API 6ACRA used for any equipment or component are shown in Table B.13.

Environmental limits for other precipitation-hardened nickel-based alloy bar or forged product for any equipment or component are shown in Table B.14.

Environmental limits for plate, sheet, strip and wire precipitation-hardened nickel-based alloys for any equipment or component are shown in Table B.15.

Environmental limits for powder metallurgy precipitation-hardened nickel-based alloys for any equipment or component are shown in Table B.16.

Environmental limits for precipitation-hardened nickel-based alloys used for wellhead and tree components (excluding bodies and bonnets) and valve and choke components (excluding bodies and bonnets) are shown in Table B.17.

Table B.12 — Environmental limits for cast precipitation-hardened nickel-based alloys used for any equipment or component

Table B.13 — Environmental limits for material in conformance with API 6ACRA used for any equipment or component

Table B.14 — Environmental limits for other precipitation-hardened nickel-based alloy bar or forged product used for any equipment or component

Table B.15 — Environmental limits for plate, sheet, strip and wire precipitation-hardened nickel-based alloys used for any equipment or component

Table B.16 — Environmental limits for powder metallurgy precipitation-hardened nickel-based alloys used for any equipment or component

• • 1. Cobalt-based alloys

Environmental limits for cobalt-based alloys for any equipment or component are shown in Table B.17.

Environmental limits for cobalt-based alloys in specific equipment/components are shown in Table B.18.

Table B.17 — Environmental limits for cobalt-based alloys used for any equipment or component

Table B.18 — Environmental limits for cobalt-based alloys used as diaphragms, pressure measuring devices, pressure seals and springs

• • 1. Titanium and tantalum alloys

Environmental limits for titanium for any equipment or component are shown in Table B.19.

Environmental limits for tantalum for any equipment or component are shown in Table B.20.

NOTE Titanium and Tantalum alloys can be susceptible to environmental cracking in conditions that do not typically pose problems for other alloys in this document. For example, hydrogen embrittlement of titanium alloys can occur if these alloys are galvanically coupled to certain active metals (e.g. carbon steel) in H₂S-containing aqueous media at temperatures greater than 80 °C (176 °F). Some titanium alloys can be susceptible to crevice corrosion and/or SCC in chloride environments.

Table B.19 — Environmental limits for titanium used for any equipment or component

Table B.20 — Environmental limits for tantalum used for any equipment or component

• • 1. Copper- and aluminium-based alloys
       1. Copper-based alloys

These materials have been used without restriction on temperature, p_H2S, Cl−, or in situ pH in production environments. No limits are defined for one or more parameters, but some severe combinations of environmental parameters could result in H₂S-realated cracking.

Copper-based alloys with SMYS ≥ 655 MPa (95 ksi) can be susceptible to environmentally-assisted cracking, see References [53], [62], [80] and [82]. The equipment user should restrict use of such grades to applications and environments that have a record of success.

NOTE 1 Copper-based alloys can undergo accelerated mass loss corrosion (weight loss corrosion) in sour oil field environments, particularly if oxygen is present.

NOTE 2 Some copper-based alloys have shown sensitivity to GHSC.

• • • 1. Aluminium-based alloys

These materials have been used without restriction on temperature, p_H2S, Cl−, or in situ pH in production environments. No limits are defined for one or more parameters, but some severe combinations of environmental parameters could result in H₂S-related cracking.

NOTE Mass loss corrosion (weight loss corrosion) of aluminium-based alloys is strongly dependent on environmental pH and flow rate.

• 1. Materials options that have specific restrictions or mitigating factors
     1. General

The acceptability of materials without environmental restrictions, for equipment or components listed in B.3, originates from legacy versions of NACE MR0175 (1975-2003), which documented the consensus of expert opinion based on service experience at the time. The limits of these service experiences have not been documented in the ISO 15156 series.

The equipment or component, combined with any associated operating conditions or mitigating factors given in B.3 such as low stresses or dry fluids, give a reduced susceptibility to SSC or SCC and may be used for the given application.

When no environmental limits are given, some combinations of individual environmental parameters may not be used, especially if the mitigating factors are not present.

When choosing a material from Annex B, the requirements of ISO 15156-1 shall apply. These may be specific to the component and different to those given for the same material when applied to the “any equipment or component” category.

The permitted materials for a given equipment or component are not restricted to those listed in B.3. The equipment user or equipment manufacturer may specify materials listed in B.2; either those listed in the tables “for any equipment or components” or those listed in the relevant equipment/component specific tables. In this instance, the ISO 15156-1 requirements referenced in the relevant table shall apply.

• • 1. Gaskets and seal rings

Gaskets and seal rings made of UNS J92600, J92900, S30400, S30403, S31600 and S31603 in accordance with ISO 15156-1:202x, 9.1.4 and Table 5 may be used. These have been used for production environments without restrictions on environmental parameters, in the absence of elemental sulfur.

Materials for gaskets and seal rings may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): by design these components are predominantly under compressive stress when in contact with H₂S-containing environments.

• • 1. Screen devices, including downhole screens

The following materials may be used for screen devices, including downhole screens. These have been used without restriction on environmental parameters, in the absence of elemental sulfur:

a) austenitic stainless steels in accordance with ISO 15156-1:202x, 9.1.4 and Table 5;

b) highly alloyed stainless steels materials types AA and AB, UNS N08020 and UNS N08904 in accordance with ISO 15156-1:202x, 9.2.4.2.

Materials for screens devices, including downhole screens may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): by design screen devices are typically exposed to low tensile stresses.

Expandable screens can have increased susceptibility to cracking, see References [50] and [57]. Expandable screens should be included in the H₂S-service assessment when applicable.

• • 1. Equipment in gas lift service

The following materials may be used for equipment in gas lift service (excluding gas lifts mandrels). These have been used without restriction on environmental parameters, in the absence of elemental sulfur:

a) austenitic stainless steels in accordance with ISO 15156-1:202x, 9.1.4 and Table 5;

b) highly alloyed austenitic stainless steels in accordance with ISO 15156-1:202x, 9.2.4;

c) UNS N05500 in accordance with ISO 15156-1:202x, Table 9;

d) UNS N04400 in accordance with ISO 15156-1:202x, Table 7;

e) UNS N04405 in accordance with ISO 15156-1:202x, Table 7:

f) UNS N24135 in accordance with ISO 15156-1:202x, Table 7.

Materials for equipment in gas lift service may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): Lift gas is ordinarily dry and near chloride-free.

NOTE For an example of a published qualification of UNS N05500 see Reference [56].

• • 1. Set screws and pins

The following materials may be used for set screws and pins. These have been used without restriction on environmental parameters, in the absence of elemental sulfur:

a) austenitic stainless steels in accordance with ISO 15156-1:202x, 9.1.4 and Table 5;

b) UNS S20910 in accordance with ISO 15156-1:202x, 9.1.4 and Table 5.

Materials for set screws and pins may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): Set screws and pins are typically exposed to low service stresses.

• • 1. Compressor components

Unrestricted environmental limits are permitted for some materials on the basis that compressor components are not typically exposed to a chloride-containing aqueous phase. The service assessment should consider transient conditions during shutdown and start-up as carry over of liquids from the process in some circumstances can occur.

The following materials may be used for compressor components (excluding compressor bodies). These have been used without restriction on environmental parameters, in the absence of elemental sulfur:

a) austenitic stainless steels in accordance with ISO 15156-1:202x, 9.1.4 and Table 5;

b) UNS S41000, S41500, S42400, J91150, J91151, J91540 in accordance with ISO 15156-1:202x, 5.4.2;

c) UNS S17400, S15500, S14500 in accordance with ISO 15156-1:202x, 5.4.2.

The above materials when used for impellers shall be in accordance with ISO 15156-1:202x, 9.5.3.3.

Materials for compressor components may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): the gas in compressors is ordinarily dry and near chloride-free.

If a chloride and H₂S-containing aqueous phase is present simultaneously with operational loading then materials shall be selected in accordance with B.2.

NOTE There have been instances of failure in these and other circumstances where chloride-containing aqueous phases have been present, for example see Reference [68].

• • 1. Control line tubing, and associated fittings

The following materials may be used for control line tubing and associated fittings. These have been used without restriction on environmental parameters, in the absence of elemental sulfur:

a) austenitic stainless steels in accordance with ISO 15156-1:202x, 9.1.4 and Table 5;

b) UNS S31600 in accordance with ISO 15156-1:202x, 9.1.4 and Table 5;

c) highly alloyed stainless steel materials types AA and BB, and UNS N08904 in accordance with ISO 15156-1:202x, 9.2.4.2.

Materials for control line tubing, and associated fittings may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): control line tubing, and associated fittings are typically under low tensile stress, encapsulated and/or exposed to a controlled packer fluid.

• • 1. Instrumentation and control devices

Austenitic stainless steels in accordance with ISO 15156-1:202x, 9.1.4 and Table 5 may be used for instrumentation and control devices (including, but not limited to diaphragms, pressure measuring devices and pressure seals). This has been used without restriction on environmental parameters, in the absence of elemental sulfur.

Materials for instrumentation and control devices may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): there are no specific mitigation factors for instrumentation and control devices, especially when welded. Caution should be taken when selecting materials in accordance with B.3.8.

• • 1. Instrument tubing and compression fittings

The following materials may be used for instrument tubing and compression fittings. These have been used without restriction on environmental parameters, in the absence of elemental sulfur:

a) austenitic stainless steels in accordance with ISO 15156-1:202x, 9.1.4 and Table 5;

b) UNS S31600 in accordance with ISO 15156-1:202x, 9.1.4 and Table 5;

c) highly alloyed stainless steels materials types AA and BB, and UNS N08904 in accordance with ISO 15156-1:202x, 9.2.4.2.

Materials for Instrument tubing, and compression fittings may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): Instrument tubing and compression fittings are typically under low tensile stress.

• • 1. Pins, shafts and valve stems

UNS S20910 in accordance with ISO 15156-1:202x, 9.1.4 and Table 5 may be used for pins, shafts and valve stems. This has been used without restriction on environmental parameters, in the absence of elemental sulfur.

Materials for pins, shafts and valve stems may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): Pins, shafts and valve stems are typically not exposed to significant tensile stress.

• • 1. Non-pressure-containing internal-valve, pressure-regulator, and level-controller components

The following materials may be used for non-pressure-containing internal-valve, pressure-regulator, and level-controller components. These have been used without restriction on environmental parameters, in the absence of elemental sulfur:

a) CB7Cu-1, CB7Cu-2, S17400, S15500, S45000 in accordance with ISO 15156-1:202x, 9.6.4.2;

b) N07750, N05500 in accordance with ISO 15156-1:202x, Table 9.

Materials for non-pressure-containing internal-valve, pressure-regulator, and level-controller components may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): non-pressure-containing internal-valve, pressure-regulator, and level-controller components are typically not exposed to significant tensile stress.

• • 1. Snap rings

UNS S15700 in accordance with ISO 15156-1:202x, 9.6.4.3 may be used for snap rings. This has been used without restriction on environmental parameters, in the absence of elemental sulfur.

Materials for snap rings may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): snap rings are typically not exposed to significant tensile stress.

• • 1. Springs

UNS N07750 and N07090 in accordance with ISO 15156-1:202x, Table 9 may be used for springs. These have been used in production service without restrictions on environmental parameters, in the absence of elemental sulfur.

For these nickel alloys, hydrogen charging should be considered for the service assessment.

NOTE Field failures of springs made from UNS N07750 have been experienced in some oil and gas production environments.

Materials for springs may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): there are no specific mitigation factors for springs.

• • 1. Wellhead and tree components

UNS S41000, S41500, S42000, J91150, J91151, S42400 and J91540 in accordance with ISO 15156-1:202x 9.5.1 may be used for wellhead and tree components for sealing surfaces, trim and stems. These have been accepted for production service at pH 3,5 or higher without restrictions on Cl- concentration, p_H2S or temperature.

UNS N05500 in accordance with ISO 15156-1:202x Table 9 may be used for wellhead and tree components for sealing surfaces, trim and stems. This been accepted for production service at pH 4,5 or higher and p_H2S 3,4 kPa (0,5 psia) or lower without restrictions on Cl- concentration or temperature.

Mitigating factor(s): Limits presented for UNS S41000, S41500, S42000, J91150, J91151, S42400, J91540 in B.3.14 are more permissive than in B.2 on the assumption that these components are only exposed to low or moderate tensile stresses. If this assumption is incorrect (see 6.1.3) then materials and environmental limits shall be according to the relevant Table in B.2.

The following precipitation-hardened martensitic stainless steels in accordance with ISO 15156-1:202x 9.6.3 may be used for wellhead and tree components for sealing surfaces, trim and stems:

a) UNS S17400 has been accepted for production service at pH 4,5 or higher and p_H2S 3,4 kPa (0,5 psia) or lower without restrictions on Cl- concentration or temperature.

b) UNS S45000 has been accepted for production service at pH 4,5 or higher and p_H2S 3,4 kPa (0,5 psia) or lower without restrictions on Cl- concentration or temperature.

UNS S17400 and S45000 may be used for wellhead valve trim where the stem is subjected to higher stress levels for very short periods of time during actuation: maximum sustained tensile stress shall not exceed 50 % of the specified minimum yield strength (SMYS) or 380 MPa (55 ksi), whichever is less.

Mitigating factor(s): Limits presented for UNS S17400 and S45000 in B.3.14 are based on the assumption that these components (except for very short periods) are only exposed to low tensile stresses. UNS S17400 and S45000 shall not be used for applications where the maximum sustained tensile stress is more than 50 % of the specified minimum yield strength (SMYS) or 380 MPa (55 ksi), whichever is less.

NOTE H₂S-testing has demonstrated the sensitivity of some martensitic stainless steels and precipitation hardened martensitic stainless steel to applied stress, see References [63], [70] and [77].

In addition to sealing surfaces, trim and stems, UNS S41500 may be used for other wellhead and tree components for production service where pH is 3,5 or higher and p_H2S is 10 KPa (1,5 psia) or lower, without restrictions on Cl- concentration or temperature.

Mitigating factor(s): Users of UNS S41500 typically have relevant prior service experience or have qualified the grade for their applications.

Materials for wellhead and tree components may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

• • 1. Subsurface equipment

UNS S17400 and S45000 precipitation-hardened martensitic stainless steels in accordance with ISO 15156-1:202x 9.6.3 may be used for subsurface equipment excluding bodies within the following environmental limits:

a) UNS S17400: production service with pH 4,5 or higher and p_H2S 3,4 kPa (0,5 psia) or lower without restrictions on Cl- concentration or temperature.

b) UNS S45000: production service with pH 4,5 or higher and p_H2S 3,4 kPa (0,5 psia) or lower without restrictions on Cl- concentration or temperature.

UNS S17400 and S45000 shall not be used for applications where the maximum sustained tensile stress is more than 50 % of the specified minimum yield strength (SMYS) or 380 MPa (55 ksi), whichever is less.

Mitigating factor(s): Limits for UNS S17400 and S45000 presented in B.3.15 are more permissive than in B.2 on the assumption that these components are only exposed to low to moderate tensile stresses. If the assumption of low to moderate tensile stress is incorrect (see 6.1.3) then materials and environmental limits shall be according to the relevant Table in B.2.

NOTE 1 H₂S-testing has demonstrated the sensitivity of precipitation hardened martensitic stainless steel to applied stress, see References [63] and [70].

UNS K90941, ASTM A182/A182M grade P9 and ASTM A213/213M grade T9 in accordance with ISO 15156-1:202x 9.5.3.1 may be used for subsurface equipment. These have been used without restrictions on environmental parameters, in the absence of elemental sulfur.

UNS S42500 in accordance with ISO 15156-1:202x 9.5.3.2 may be used for subsurface equipment. This has been used without restrictions on environmental parameters, in the absence of elemental sulfur.

ISO 11960 or API 5CT L80-9Cr may be used for subsurface equipment. This has been used without restrictions on environmental parameters, in the absence of elemental sulfur.

Mitigating factor(s): Users of UNS K90941, ASTM A182/A182M grade P9 and ASTM A213/213M grade T9 typically have relevant prior service experience or have qualified the grade for their applications.

NOTE 2 An example of qualification H₂S-testing experience is shown in Reference [66].

Materials for subsurface equipment may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

• • 1. Any equipment or component

UNS N04400 and UNS N04405 in accordance with ISO 15156-1:202x, Table 7 may be used for any equipment or component. These have been used in production service without restrictions on environmental parameters, in the absence of elemental sulfur.

Mitigating factor(s): these grades are typically used in the annealed condition.

Equipment users may permit the use of UNS N07718 in accordance with ISO 15156-1:202x, 9.9.1.2 for applications with operating temperatures no greater than 135 °C (275 °F). The equipment user may also permit the use of UNS N07718 in accordance with ISO 15156-1:202x, 9.9.1.2 within the environmental parameter limits given in Table B.13 for API 6ACRA UNS N07718 120K.

Precipitation hardened nickel alloys may also be selected in accordance with B.2 (applying the associated environmental parameter limits).

Mitigating factor(s): Whilst much of the oil and gas industry has migrated to the API 6ACRA standard, this transition has not completed. The API 6ACRA standard brings improvements in quality and general hydrogen embrittlement resistance, but material in conformance with ISO 15156-1:202x, 9.9.1.2 has also performed well in H₂S-containing environments.

• 1. End sizing of corrosion resistant alloy pipe and OCTG

Verification of end sized SSC performance shall be performed in conformance with ISO 15156-3 to confirm end sized SSC resistance for the following materials when the end sizing results in greater than 0,5 % plastic strain, in the absence of stress relief:

a) API 5CT or ISO 11960 L80-9Cr;

b) API 5CT or ISO 11960 API L80-13Cr;

c) Any ISO 13680 or API 5CRA Group 1 material.

Qualification of end sized SSC performance shall be confirmed for the materials listed in B.4 a) to c) if the end sized material (after any applicable stress relief) exceeds the permissible hardness and/or yield strength of the base material.

Qualification of end sized SCC performance shall be performed for ISO 13680 or API 5CRA Group 2 to 4 materials for which the end sized material has been cold worked beyond the yield strength and/or hardness permitted for the base material.

• 1. CRA bolting and fasteners

Bolting and fasteners that can be exposed to a sour environment shall conform to the requirements of B.2 or B.3, as applicable. See 6.1.3.5 regarding fasteners under insulation, buried or otherwise denied direct exposure to the external environment that are exposed to the H₂S environment in the event of a leak or seep through, for example, a seal.

• 1. Surface treatment of corrosion-resistant alloys and other alloys

The following surface treatments may be performed where these do not result in any thermal transformations of the underlying material (See ISO 15156-1:202x, 3.31 for definition limiting of temperature):

— conversion coatings;

— plasma and chemical coating systems;

— peening;

— thermal cleaning;

— curing of organic coatings.

Nitriding and nitrocarburizing diffusion treatments shall be in conformance with ISO 15156-1:202x, 10.3.2.

Boriding/boronizing diffusion treatment shall be in conformance with ISO 15156-1:202x, 10.3.3.

Other surface treatments of CRA and other alloys may be performed per ISO 15156-1:202x, 10.3.5, ensuring no detrimental alteration to the substrate material.

1. 
   (informative)
   
   Determination of H₂S partial pressure, fugacity, activity and concentration in the aqueous phase
   1. General

H₂S is naturally occurring in many oil and gas reservoirs but also can be generated due to anthropomorphic activities, including microbiological generation and thermochemical generation. Microbiological generation includes reservoir souring due to water injection and that occurring during long term shut-in or in stagnant fluids.

Much of this document relies upon the use of H₂S partial pressure. In some instances other parameters can be applicable such as H₂S fugacity (accounting for non-ideal gas behaviour) or H₂S activity and concentration in the aqueous phase.

NOTE Examples of non-ideal thermodynamic effects and their analysis in the context of sour corrosion cracking are given in the following References [39], [41], [46], [64], [65] and [78].

For systems with a gas phase, evaluations based on H₂S partial pressure give an environmental severity that equals or exceeds that of the field service. In these systems, the severity of H₂S is greatest when using H₂S partial pressure.

For gas-free liquid systems, assumptions based on H₂S partial pressure at the bubble point or H₂S partial pressure at the last stage of separation is not always conservative, especially at very high pressures. The severity of H₂S is greatest when using H₂S fugacity.

In addition to impact on materials susceptibility, chloride, halide, and total dissolved solids can significantly affect the other critical variables, particularly aqueous H₂S concentration. When assessing the other critical variables, the anticipated range of total dissolved solids should be used.

• 1. Calculation for systems with a gas phase
     1. General

The partial pressure of H₂S, pH₂S, expressed in megapascals (pounds per square inch), can be calculated by multiplying the system total pressure by the mole fraction of H₂S in the gas phase as given in Formula (C.1):

(C.1)

where

p is the system total absolute pressure, expressed in megapascals (pounds per square inch);

is the mole fraction of H₂S in the gas, expressed as a percentage.

For example, in a 70 MPa (10 153 psia) gas system, where the mole fraction of H₂S in the gas is 10 %, the H₂S partial pressure is 7 MPa (1 015 psia).

• • 1. Gas phase considerations, H₂S partial pressure and fugacity

The partial pressure concept, based on the ideal gas law, provides an accurate representation of thermodynamic activity of gas species like CO₂ and H₂S at near atmospheric total pressures. At higher pressures, the true thermodynamic activity (chemical potential), expressed as gas phase fugacity, drops below the partial pressure. Therefore, the partial pressure concept introduces an excess in severity that increases with total pressure. (Generally, this excess decreases with increasing temperature.) Hence, assessments of systems with a gas phase, based on partial pressure, imply an environmental severity that equals or exceeds that of the corresponding field service considered and can be used for any total pressure, in line with historical practice for evaluation of the severity of a sour environment.

Equipment users can employ H₂S fugacity rather than partial pressure to characterize the environmental severity of the production environment and to define the test environment representing field service, thereby reducing excess severity introduced by the partial pressure concept. The degree to which this excess would be reduced by considering H₂S fugacity depends on total pressure, temperature and composition of the hydrocarbon-water system.

NOTE Systems with an extreme total pressure, typically above 150 MPa (21 756 psia), would be characterized as a dense fluid rather than gas or liquid and are preferably evaluated based on H₂S fugacity.

H₂S fugacity calculations should be validated to ensure they adequately reflect the severity of the production environment and that all the test conditions applied are at least as severe, with respect to the potential mode of failure, as those defined to occur in the field service. This should include:

a) use of thermodynamic software that is appropriate for the conditions of interest;

b) H₂S-testing in accordance with ISO 15156-3 at high pressure representative of the field conditions (accompanied by thermodynamic modelling of the test conditions in comparison with the full service environment).

• • 1. Aqueous phase considerations, H₂S concentration and chemical activity

Since the cracking mechanisms relevant to this document occur in the aqueous phase, user can assess the likelihood of cracking on the basis of H₂S dissolved in the aqueous phase instead of H₂S partial pressure in the gas phase. At near atmospheric pressure, assessments based on gas phase partial pressure, H₂S fugacity, aqueous concentration or aqueous phase chemical activity are essentially equivalent. However, at higher pressure, thermodynamic activity, be it H₂S fugacity in the gas phase as discussed above or chemical activity in the aqueous phase, deviates from strictly ideal partial pressure and aqueous concentration, respectively.

NOTE 1 Fugacity can be considered an “effective partial pressure”, incorporating the non-ideal thermodynamic effects in the real gas that are ignored in the partial pressure derived from the ideal gas law. It is dependent on and generally calculated from the total pressure, the mole fraction of the species in the mixture and its fugacity coefficient, which in turn depends on temperature. The concept of fugacity is applicable to all phases, gas or liquid, and can be thought of as “escaping tendency” – the driver for a component to leave a phase. At equilibrium, the fugacity for each component is the same in all phases of a mixture, gas or liquid. In this document, the term fugacity is primarily used as a property of species in the gas phase.

NOTE 2 Activity or chemical activity can be considered a “pseudo mole fraction”, and incorporates the non-ideal thermodynamic effects in the real liquid phase that are ignored if just concentration is accounted for. Activity is meaningless if the reference state is not specified. Activity also incorporates the effect of brine salinity on a species. Activity is often expressed as the mole fraction of the species multiplied by an activity coefficient. Since activity and fugacity are unambiguously related and are derived from the thermodynamic concept of chemical potential (partial Gibbs free energy), it is sufficient to specify either activity or fugacity. In this document, the term chemical activity is primarily used as a property of species in the liquid or aqueous phase.

NOTE 3 H₂S fugacity is a function of pressure, temperature, and mixture composition; the impact of activity is further complicated by the salinity of the aqueous phase.

NOTE 4 The in situ pH is defined based on the chemical activity of protons in the water phase. This activity in turn depends on the CO₂ and H₂S chemical activities in the water phase which are equivalent to the respective fugacities. This implies high pressures have an effect on pH, which can be accounted for by thermodynamic analysis.

• 1. Calculations for gas-free, liquid-only systems
     1. General

Traditionally, for liquid systems (for which no equilibrium gas composition is available), the effective thermodynamic activity of H₂S is defined by a virtual partial pressure (the associated H₂S partial pressure for the liquid system) of H₂S that has been determined in the following way:

a) Calculation of the bubble-point pressure, pB, of the fluid at operating temperature by any suitable method.

NOTE For a liquid-full pipeline downstream of gas separation units, a good approximation for bubble-point pressure is the total pressure of the last gas separator.

b) Calculation of the mole fraction of H₂S in the gas phase at bubble-point conditions by any suitable method.

c) Calculation of the partial pressure of H₂S, p_H2S, expressed in megapascals (pounds per square inch), in the gas at the bubble point as given in Formula (C.2):

(C.2)

where

p_B is the bubble-point pressure, expressed in megapascals (pounds per square inch);

is the mole fraction of H₂S in the gas, expressed as a percentage.

Formula C.2 gives the associated H₂S partial pressure for the liquid system.

• • 1. Considerations for high pressure gas-free oil wells

The approach in C.3.1 assumes the H₂S severity of the environment is adequately represented by p_H2S at bubble-point at any pressure higher than the bubble-point. This assumption is generally correct at low to moderate pressures, but is not necessarily true at high pressures.

For gas-free liquid systems operating well above the bubble-point, increasing the pressure does not significantly increase the concentration of H₂S in the aqueous phase, but does increase the chemical activity of H₂S in water. Hence, the environment can behave as if there is more H₂S.

An example oil well case assessment showed that at total pressures typically exceeding 35 MPa to 50 MPa (5 076 psia to 7 252 psia), H₂S fugacity could surpass the bubble-point p_H2S. In this instance use of bubble-point p_H2S was an inadequate indicator of environmental severity and H₂S fugacity was the preferred parameter, see Reference [64]. In such instances, H₂S fugacity or activity calculations should be performed.

For production fluids where the difference between bubble-point and system pressure is greater than 20 MPa (2 900 psia), a thermodynamic analysis considering aqueous chemical activity should be performed to ensure environmental severity is properly characterized in the H₂S service assessment.

1. 
   (informative)
   
   Assessment of pH

Chemical activity of dissolved H₂S and CO₂ directly impact the pH in both buffered produced water and unbuffered condensed water. The following factors influence pH:

a) Organic and mineral acids – naturally occurring organic acids are common in produced fluids and higher concentrations of organic and mineral acids can occur due to chemical interventions, particularly acidizing activities. Maximum plausible content of acids is typically included in the pH assessment.

b) Alkalinity – buffering compounds are common in produced fluids and include bicarbonates and salts of organic acids, e.g. acetate. Minimum plausible content of buffer compounds is typically included in the pH assessment. Condensed water analysis typically does not include any consideration of buffer compounds.

c) Total dissolved solids (TDS) – the total amount of dissolved ions. It impacts the dissolution of acid gases. As TDS impacts the electrolytic strength, it also impacts the activity of species in the solution.

d) Temperature – temperature changes both the ionization of water and the dissolution of acid gases. pH variability with temperature is typically included in the pH assessment.

e) Pressure – system pressure impacting the partitioning of gases, including water vapor, and therefore the ionic strength. Pressure also impacts the equilibrium of the different reactions in the aqueous phase.

NOTE 1 Oil and gas production environments typically have pH values greater than 3,5 for condensed water and greater than 4,5 for formation water, but there are cases where lower pH can be encountered.

NOTE 2 Very low pH (pH < 3) conditions can be experienced during treatment with or backflow of chemicals.

pH is typically determined using software for the calculation of thermodynamic and ionic behaviour, or empirical models.

1. 
   (informative)
   
   Fundamental mechanistic aspects of H₂S cracking
   1. General

Annex E provides background with respect to the cracking mechanisms that are within the scope of the ISO 15156 series. It is not intended to capture all the potential synergies between these and other cracking mechanisms.

• 1. Sulfide stress cracking

SSC is a form of hydrogen embrittlement where the presence of H₂S enhances hydrogen adsorption and absorption into the material. Carbon and low alloy steels and some CRA can be susceptible to SSC. This hydrogen (whether atomic or protonic) can diffuse to locations of high hydrogen activity, such as stress and strain concentrations. The resultant embrittlement makes the material more susceptible to crack initiation and propagation under load. A tensile stress (residual and/or applied) is necessary to generate SSC. Lower temperatures decrease hydrogen absorption and diffusion rates, but can increase the susceptibility to embrittlement. Higher temperatures can increase hydrogen absorption and diffusion rates, but can also decrease the susceptibility to embrittlement. Generally, the degree of embrittlement dominates for surface cracking phenomena given the relatively short hydrogen diffusion distances and the influence of stress/strain distribution on the hydrogen activity gradient. Thus, for carbon and low alloy steels, SSC resistance at 4 °C can be worse than at 24 °C, but SSC resistance can be greatly improved at, for example, 80 °C.

For the duplex stainless steel material group, “SSC” testing is typically conducted at 90 °C. However, this is a convention intended to ensure the worst-case synergy between SSC and SCC mechanisms, as opposed to SSC alone.

NOTE Soft-zone cracking (SZC) is a form of SSC that can occur when a steel contains a local “soft zone” of low-yield-strength material. The mechanism is restricted to carbon steels but is rarely observed in practice.

• 1. Stress corrosion cracking (SCC)

SCC can be via a variety of mechanism, but for most materials in H₂S-containing environments is a synergistic cracking mechanism involving anodic processes of localized corrosion and tensile stress (residual and/or applied) and is generally only applicable to CRA. Like pitting corrosion, SCC is sensitive to the stability of the passive film on the surface of the CRA. However, pitting corrosion thresholds and SCC thresholds are not necessarily the same. The disruption of the passive film is more likely at higher temperature and therefore SCC is typically evaluated for CRAs at their maximum design temperature.

• 1. Hydrogen-induced cracking (HIC)/stepwise cracking (SWC)

HIC is a type of planar cracking that occurs in carbon and low alloy steels when hydrogen (atomic or protonic) diffuses into the steel and then combines to form molecular hydrogen at trap sites. Favourable trap sites are typically found in rolled products along elongated inclusions or segregated bands of microstructure, resulting in lamellar cracks perpendicular to the through-thickness direction. Cracks are formed by increased hydrogen pressure inside the traps and no external stresses are necessary. When these phenomena occur close to the surface, it can result in blistering. Stepwise cracking (SWC) occurs when cracking connects hydrogen-induced cracking on adjacent lamellar planes of segregation/banding in the steel microstructure.

• 1. Stress-oriented hydrogen-induced cracking (SOHIC)

SOHIC appears as staggered small cracks formed approximately perpendicular to the principal stress (residual or applied) resulting in a “ladder-like” crack array linking HIC cracks. The mechanism is restricted to carbon and low alloy steels and is sensitive to the same parameters as for SSC but is not governed by the limitations for SSC as expressed in Figure 3.

• 1. Galvanically induced hydrogen stress cracking (GHSC)

GHSC results from the combined effect of the presence of hydrogen absorbed in a metal which is induced by the cathode of a galvanic couple and, tensile stress (residual and/or applied). Conventionally, GHSC has been considered only in the context of testing for SSC. However, galvanic coupling often influences SCC or activates other hydrogen embrittlement mechanisms not included in this document.

• 1. Other mechanisms

Other damage mechanisms not addressed in the ISO 15156 series can be relevant to the service conditions and equipment design. For example, corrosion and localised corrosion resistance can be relevant considerations in both material selection and H₂S cracking resistance testing. Additionally, the H₂S cracking mechanisms within the scope of the ISO 15156 series can act synergistically with fatigue mechanisms, for example decreasing the life of risers and flowlines under some cyclic loading conditions.

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