SIST EN ISO 21457:2012

SLOVENSKI STANDARD
01-november-2012
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Petroleum, petrochemical and natural gas industries - Materials selection and corrosion
control for oil and gas production systems (ISO 21457:2010)
Erdöl-, petrochemische und Erdgasindustrie - Werkstoffauswahl und
Korrosionsschutzmaßnahmen für Öl- und Gasproduktionssysteme (ISO 21457:2010)
Industries du pétrole, de la pétrochimie et du gaz naturel - Choix de matériaux et contrôle
de corrosion pour les systèmes de production de pétrole et de gaz (ISO 21457:2010)
Ta slovenski standard je istoveten z: EN ISO 21457:2010
ICS:
75.180.10 Oprema za raziskovanje in Exploratory and extraction
odkopavanje equipment
2003-01.Slovenski inštitut za standardizacijo. Razmnoževanje celote ali delov tega standarda ni dovoljeno.

EUROPEAN STANDARD
EN ISO 21457
NORME EUROPÉENNE
EUROPÄISCHE NORM
September 2010
ICS 75.180.01
English Version
Petroleum, petrochemical and natural gas industries - Materials
selection and corrosion control for oil and gas production
systems (ISO 21457:2010)
Industries du pétrole, de la pétrochimie et du gaz naturel - Erdöl-, petrochemische und Erdgasindustrie -
Choix des matériaux et contrôle de la corrosion pour les Werkstoffauswahl und Korrosionsprüfung für Öl- und
systèmes de production de pétrole et de gaz (ISO Gasproduktionssysteme (ISO 21457:2010)
21457:2010)
This European Standard was approved by CEN on 11 September 2010.

CEN members are bound to comply with the CEN/CENELEC Internal Regulations which stipulate the conditions for giving this European
Standard the status of a national standard without any alteration. Up-to-date lists and bibliographical references concerning such national
standards may be obtained on application to the CEN Management Centre or to any CEN member.

This European Standard exists in three official versions (English, French, German). A version in any other language made by translation
under the responsibility of a CEN member into its own language and notified to the CEN Management Centre has the same status as the
official versions.
CEN members are the national standards bodies of Austria, Belgium, Bulgaria, Croatia, Cyprus, Czech Republic, Denmark, Estonia,
Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Latvia, Lithuania, Luxembourg, Malta, Netherlands, Norway, Poland,
Portugal, Romania, Slovakia, Slovenia, Spain, Sweden, Switzerland and United Kingdom.

EUROPEAN COMMITTEE FOR STANDARDIZATION
COMITÉ EUROPÉEN DE NORMALISATION

EUROPÄISCHES KOMITEE FÜR NORMUNG

Management Centre: Avenue Marnix 17, B-1000 Brussels
© 2010 CEN All rights of exploitation in any form and by any means reserved Ref. No. EN ISO 21457:2010: E
worldwide for CEN national Members.

Contents Page
Foreword .3

Foreword
This document (EN ISO 21457:2010) has been prepared by Technical Committee ISO/TC 67 “Materials,
equipment and offshore structures for petroleum, petrochemical and natural gas industries” in collaboration
with Technical Committee CEN/TC 12 “Materials, equipment and offshore structures for petroleum,
petrochemical and natural gas industries” the secretariat of which is held by AFNOR.
This European Standard shall be given the status of a national standard, either by publication of an identical
text or by endorsement, at the latest by March 2011, and conflicting national standards shall be withdrawn at
the latest by March 2011.
Attention is drawn to the possibility that some of the elements of this document may be the subject of patent
rights. CEN [and/or CENELEC] shall not be held responsible for identifying any or all such patent rights.
According to the CEN/CENELEC Internal Regulations, the national standards organizations of the following
countries are bound to implement this European Standard: Austria, Belgium, Bulgaria, Croatia, Cyprus, Czech
Republic, Denmark, Estonia, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Latvia,
Lithuania, Luxembourg, Malta, Netherlands, Norway, Poland, Portugal, Romania, Slovakia, Slovenia, Spain,
Sweden, Switzerland and the United Kingdom.
Endorsement notice
The text of ISO 21457:2010 has been approved by CEN as a EN ISO 21457:2010 without any modification.

INTERNATIONAL ISO
STANDARD 21457
First edition
2010-09-01
Petroleum, petrochemical and natural gas
industries — Materials selection and
corrosion control for oil and gas
production systems
Industries du pétrole, de la pétrochimie et du gaz naturel — Choix des
matériaux et contrôle de la corrosion pour les systèmes de production
de pétrole et de gaz
Reference number
ISO 21457:2010(E)
©
ISO 2010
ISO 21457:2010(E)
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ii © ISO 2010 – All rights reserved

ISO 21457:2010(E)
Contents Page
Foreword .iv
Introduction.v
1 Scope.1
2 Normative references.1
3 Terms, definitions and abbreviated terms.2
3.1 Terms and definitions .2
3.2 Abbreviated terms .5
4 Design information for materials selection .6
5 Materials selection report.7
6 General guidelines for corrosion evaluations and materials selection.7
6.1 General .7
6.2 Internal corrosion in oil and gas production and processing .8
6.3 Internal corrosion in injection systems .12
6.4 Internal corrosion in utility systems.12
6.5 Sand erosion.13
6.6 External corrosion.13
6.7 Polymeric materials.15
6.8 Glass-fibre-reinforced plastic .15
6.9 Mechanical properties and material usage limitations.15
7 Materials selection for specific applications and systems.16
7.1 General .16
7.2 Oil and gas production and processing systems .17
7.3 Injection systems .19
7.4 Utility systems .20
7.5 Pipelines and flowlines.24
8 Corrosion control .25
8.1 Chemical treatment .25
8.2 Internal corrosion allowance.26
8.3 Selection of internal and external coatings.27
8.4 External splash zone protection .27
8.5 Cathodic protection.27
8.6 Corrosion protection of closed compartments.28
8.7 Connection of dissimilar materials.28
8.8 Sealing materials .29
8.9 Fasteners.29
8.10 Weld overlay .30
8.11 Preferential weld corrosion .30
8.12 Corrosion management .30
Annex A (informative) Design basis for hydrocarbon systems .31
Annex B (informative) Corrosion monitoring.33
Annex C (informative) Chemical composition of some typical oilfield alloys .34
Bibliography.38

ISO 21457:2010(E)
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.
International Standards are drafted in accordance with the rules given in the ISO/IEC Directives, Part 2.
The main task of technical committees is to prepare International Standards. Draft International Standards
adopted by the technical committees are circulated to the member bodies for voting. Publication as an
International Standard requires approval by at least 75 % of the member bodies casting a vote.
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.
ISO 21457 was prepared by Technical Committee ISO/TC 67, Materials, equipment and offshore structures
for petroleum, petrochemical and natural gas industries.
iv © ISO 2010 – All rights reserved

ISO 21457:2010(E)
Introduction
The provision of well-established and robust material selection guidelines offers a means of satisfying
long-term materials performance that meet the minimum requirements for a broad range of end users in the
petroleum, petrochemical and natural gas industries. An additional benefit can be to enable product suppliers
to develop, manufacture and provide off-the-shelf equipment that meets these requirements.
Oil and gas production projects benefit from a structured evaluation of materials used for the different fluids
being handled. Therefore, the main objective of this International Standard is to provide general requirements
with guidelines for the selection of materials for systems and components, with due consideration to the
transported fluids and the external environment.
It is the end user's responsibility to provide a project document with respect to implementation of the
requirements and guidelines of this International Standard, and to specify the design conditions for material
selection. In addition to the end user, the organization responsible for the facility or for the equipment design,
or for both, is regarded as responsible for materials selection.
This International Standard is developed to provide responsible parties with a structured process to carry out
materials selection in a consistent manner as a part of the engineering work, based upon a design basis for a
particular installation. This International Standard is intended for use by oil companies and engineering
contractors.
Users of this International Standard are advised that further or differing requirements might be needed for
individual applications. This International Standard is not intended to inhibit a vendor from offering, or the
purchaser from accepting, alternative equipment or engineering solutions for the individual application. This
can be particularly applicable where there is innovative or developing technology. Where an alternative is
offered, it is advisable that the vendor identify any variations from this International Standard and provide
details.
INTERNATIONAL STANDARD ISO 21457:2010(E)

Petroleum, petrochemical and natural gas industries —
Materials selection and corrosion control for oil and gas
production systems
1 Scope
This International Standard identifies the corrosion mechanisms and parameters for evaluation when
performing selection of materials for pipelines, piping and equipment related to transport and processing of
hydrocarbon production, including utility and injection systems. This includes all equipment from and including
the well head, to and including pipelines for stabilized products. This International Standard is not applicable
to downhole components.
Guidance is given for the following:
⎯ corrosion evaluations;
⎯ materials selection for specific applications, or systems, or both;
⎯ performance limitations for specific materials;
⎯ corrosion control.
This International Standard refers to materials that are generally available, with properties that are known and
documented. It also allows other materials to be evaluated and qualified for use.
This International Standard does not provide detailed material requirements or guidelines for manufacturing
and testing of equipment. Such information can be found in particular product and manufacturing standards.
2 Normative references
The following referenced documents are indispensable for the application 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.
1)
ISO 15156-1 , Petroleum and natural gas industries — Materials for use in H S-containing environments in
oil and gas production — Part 1: General principles for selection of cracking-resistant materials
1)
ISO 15156-2 , Petroleum and natural gas industries — Materials for use in H S-containing environments in
oil and gas production — Part 2: Cracking-resistant carbon and low-alloy steels, and the use of cast irons
1)
ISO 15156-3 , Petroleum and natural gas industries — Materials for use in H S-containing environments in
oil and gas production — Part 3: Cracking-resistant CRAs (corrosion-resistant alloys) and other alloys

1) ISO 15156 (all parts) has been adopted by NACE as NACE MR0175/ISO 15156.
ISO 21457:2010(E)
3 Terms, definitions and abbreviated terms
3.1 Terms and definitions
For the purposes of this document, the following terms and definitions apply.
3.1.1
aquifer water
water from an underground layer of water-bearing permeable rock or unconsolidated materials
3.1.2
carbon steel
alloy of carbon and iron containing up to 2 % mass fraction carbon and up to 1,65 % mass fraction
manganese and residual quantities of other elements, except those intentionally added in specific quantities
for deoxidation (usually silicon and/or aluminium)
NOTE Carbon steels used in the petroleum industry usually contain less than 0,8 % mass fraction carbon.
[ISO 15156-1:2009, definition 3.3]
3.1.3
corrosion-resistant alloy
alloy intended to be resistant to general and localized corrosion by oilfield environments that are corrosive to
carbon steels
NOTE This definition is in accordance with ISO 15156-1 and is intended to include materials such as stainless steel
with minimum 11,5 % (mass fraction) Cr, and nickel, cobalt and titanium base alloys. Other ISO standards can have other
definitions.
3.1.4
end user
owner or organization that is responsible for operation of an installation/facility
3.1.5
free-machining steel
steel composition to which elements such as sulfur, selenium or lead have been intentionally added to
improve machinability
3.1.6
fugacity
non-ideal partial pressure that a component in a mixture exerts in the vapour phase when in equilibrium with
the liquid mixture
NOTE The fugacity factor depends on the temperature and the total pressure.
3.1.7
glass-fibre-reinforced plastic
composite material made of thermosetting resin and reinforced with glass fibres
3.1.8
hydrogen-induced cracking
HIC
planar cracking that occurs in carbon and low alloy steels when atomic hydrogen diffuses into the steel and
then combines to form molecular hydrogen at trap sites
2 © ISO 2010 – All rights reserved

ISO 21457:2010(E)
NOTE Cracking results from the pressurization of trap sites by hydrogen. No externally applied stress is needed for
the formation of hydrogen-induced cracks. Trap sites capable of causing HIC are commonly found in steels with high
impurity levels that have a high density of planar inclusions and/or regions of anomalous microstructure (e.g. banding)
produced by segregation of impurity and alloying elements in the steel. This form of hydrogen-induced cracking is not
related to welding.
[ISO 15156-1:2009, definition 3.12]
3.1.9
hydrogen stress cracking
HSC
cracking that results from the presence of hydrogen in a metal and tensile stress (residual and/or applied)
NOTE HSC describes cracking in metals that are not sensitive to SSC but which can be embrittled by hydrogen when
galvanically coupled, as the cathode, to another metal that is corroding actively as an anode. The term “galvanically
induced HSC” has been used for this mechanism of cracking.
[ISO 15156-1:2009, definition 3.13]
3.1.10
liquid metal embrittlement
form of cracking caused by certain liquid metals coming into contact with specific alloys
3.1.11
low alloy steel
steels containing a total alloying element content of less than 5 % mass fraction, but more than that specified
for carbon steel
[20]
EXAMPLE AISI 4130; AISI 8630; ASTM A182 Grade F22 .
3.1.12
manufacturer
firm, company or corporation responsible for making a product in accordance with the requirements of the
order, or with the properties specified in the referenced product specification, or both
3.1.13
marine atmosphere
atmosphere over and near the sea
NOTE A marine atmosphere will extend a certain distance inland, depending on topography and prevailing wind
direction. It is heavily polluted with sea-salt aerosols (mainly chlorides).
[ISO 12944-2:1998, definition 3.7.4]
3.1.14
maximum operating temperature
maximum temperature to which a component is subjected, including during deviations from normal operations,
such as start-up/shutdown
3.1.15
onshore
inland area with a non-chloride-containing atmosphere
3.1.16
operating temperature
temperature to which a component is subjected during normal operation
ISO 21457:2010(E)
3.1.17
pH stabilization
increasing the bulk pH by addition of a suitable chemical to reduce CO corrosion in hydrocarbon systems
with condensing water
3.1.18
pitting resistance equivalent number
PREN
F
PREN
number, developed to reflect and predict the pitting resistance of a stainless steel, based upon the proportions
of Cr, Mo, W and N in the chemical composition of the alloy
NOTE 1 For the purposes of this International Standard, F is calculated from Equation (1):
PREN
F = w + 3,3(w + 0,5w ) + 16w (1)
PREN Cr Mo W N
where
w is the percent (mass fraction) of chromium in the alloy;
Cr
w is the percent (mass fraction) of molybdenum in the alloy;
Mo
w is the percent (mass fraction) of tungsten in the alloy;
W
w is the percent (mass fraction) of nitrogen in the alloy.
N
NOTE 2 Adapted from ISO 15156-3:2009, definition 3.10, and ISO 15156-3:2009, 6.3.
3.1.19
type 13Cr
martensitic stainless steel alloys with nominal 13 % Cr mass fraction alloying
EXAMPLE UNS S41000; UNS S41500.
3.1.20
type 316
austenitic stainless steel alloys of type UNS S31600/S31603
3.1.21
type 6Mo
austenitic stainless steel alloys with PREN W 40 and a nominal Mo alloying content of 6 % mass fraction, and
nickel alloys with Mo content in the range 6 % to 8 % mass fraction
EXAMPLE UNS S31254; UNS N08367; UNS N08926.
3.1.22
type 22Cr duplex
ferritic/austenitic stainless steel alloys with 30 u PREN u 40 and Mo u 2,0 % mass fraction
EXAMPLE UNS S31803; UNS S32205.
3.1.23
type 25Cr duplex
ferritic/austenitic stainless steel alloys with 40 u PREN u 45
EXAMPLE UNS S32750; UNS S32760.
4 © ISO 2010 – All rights reserved

ISO 21457:2010(E)
3.1.24
stress corrosion cracking
SCC
cracking of metal involving anodic processes of localized corrosion and tensile stress (residual and/or applied)
NOTE 1 Parameters that influence the susceptibility to SCC are temperature, pH, chlorides, dissolved oxygen, H S
and CO .
NOTE 2 The above definition differs from that of the same term given in ISO 15156-1:2009, definition 3.21, since it
includes external environments.
3.1.25
sulfide stress cracking
SSC
cracking of metal involving corrosion and tensile stress (residual and/or applied) in the presence of water and
H S
NOTE SSC is a form of hydrogen stress cracking (HSC) and involves embrittlement of the metal by atomic hydrogen
that is produced by acid corrosion on the metal surface. Hydrogen uptake is promoted in the presence of sulfides. The
atomic hydrogen can diffuse into the metal, reduce ductility and increase susceptibility to cracking. High strength metallic
materials and hard weld zones are prone to SSC.
[ISO 15156-1:2009, definition 3.23]
3.2 Abbreviated terms
AFFF aqueous film-forming foams
API American Petroleum Institute
ASCC alkaline stress corrosion cracking
ASME American Society of Mechanical Engineers
CP cathodic protection
CRA corrosion-resistant alloy
CUI corrosion under insulation
GRP glass-fibre-reinforced plastic
HAZ heat-affected zone
HB Brinell hardness
HDG hot-dip galvanized
HIC hydrogen-induced cracking
HRC Rockwell hardness C scale
HSC hydrogen stress cracking
HVAC heating-ventilation-air conditioning
MEG monoethylene glycol
MIC microbiologically induced corrosion
ISO 21457:2010(E)
PE polyethylene
PP polypropylene
PREN pitting resistance equivalent number
PTFE polytetrafluoroethylene
PVC polyvinyl chloride
SCC stress corrosion cracking
SMYS specified minimum yield strength
SS stainless steel
SSC sulfide stress cracking
SWC step-wise cracking
TEG triethylene glycol
UNS unified numbering system (for alloys)
4 Design information for materials selection
This International Standard provides guidelines for material selection for oil and gas production facilities. To
enable the contractor to perform the material selections for the facility, the end user should as a minimum
provide the information specified in Table 1 at the time of enquiry and contract.
Table 1 — Design information for materials selection
Information to be provided Subclause
Project design basis, ref. Annex A 6.1
Corrosion-prediction model 6.2.1 and 6.2.2.2
Future changes in reservoir H S- content 6.2.2.4
Methodology or model for pH calculation of produced water 6.2.3.2
Formation water analysis 6.2.3.2
Content of mercury in production fluids or gas 6.2.3.8
The oxygen content in de-aerated seawater for injection 6.3
Erosion-prediction model 6.5
Temperature limitations for use of stainless steels in marine atmosphere 6.6.2, Table 3
[21]
Compliance with DNV-RP-F112 for duplex stainless steel exposed to cathodic protection 6.6.4
Limitations in mechanical properties and use of materials 6.9
Temperature limitations for non-metallic materials 7.4.2, Table 9
Environmental requirements regarding use of corrosion inhibitors 8.1
Model for inhibitor evacuation, corrosion inhibition test methods and acceptance criteria 8.1
Use of external coatings to increase maximum temperature for stainless steel (SS) 8.3
Applicable standard for cathodic protection (CP) design to be defined 8.5.1
Strength and hardness limitation of fasteners in marine atmosphere 8.9

6 © ISO 2010 – All rights reserved

ISO 21457:2010(E)
5 Materials selection report
Corrosion evaluations and materials selection should be documented in a report for further use by the project
and operations.
The following elements should be included:
⎯ short description of the project and expected facilities, e.g. field layout, remoteness of location, manned
versus unmanned facilities, etc.;
⎯ materials-related design input data for the operating conditions during the design life of the facility, e.g.
temperatures, pressures, fluid composition, sand production, etc. (see Annex A);
⎯ corrosion evaluations and materials selection;
⎯ requirements for corrosion inhibitor efficiency and availability;
⎯ requirements for corrosion control, e.g. CP and coatings;
⎯ requirements for corrosion monitoring;
⎯ identification of uncertainties from a materials perspective, new application for materials, use of new
grades;
⎯ need for material qualification testing.
6 General guidelines for corrosion evaluations and materials selection
6.1 General
The materials selection process shall take into account all statutory and regulatory requirements. The project
design criteria, such as design lifetime, inspection and maintenance philosophy, safety and environmental
profiles, operational reliability and specific project requirements, should be considered.
In general, robust materials selection should be made to ensure operational reliability throughout the design
life. For offshore installations and particularly subsea, access for the purposes of maintenance and repair can
be limited and costly, and should be carefully considered in the design.
Materials selection should normally be based on an evaluation of corrosion and erosion as described in the
following subclauses. All internal and external media should be considered for the entire design life. This
should also include the stages of transportation, storage, installation, testing and preservation. Degradation
mechanisms not specifically covered in this International Standard, such as fatigue, corrosion-fatigue, wear
and galling, should be considered for relevant components and design conditions.
Mechanical properties and usage limitations for different material grades should comply with applicable design
code requirements and guidelines given in 6.9. The material weldability should also be considered to ensure
an effective fabrication.
Cost and material availability have a significant influence on materials selection, and evaluations should be
made to support the final selection.
NOTE If life-cycle cost evaluations are considered appropriate, then ISO 15663-2 describes one methodology.
ISO 21457:2010(E)
6.2 Internal corrosion in oil and gas production and processing
6.2.1 Corrosion evaluation
A corrosion evaluation should be carried out to determine the general corrosivity of the internal fluids for the
materials under consideration. The corrosion mechanisms and the specified process design parameters
included in 6.2.2 and 6.2.3 should be considered.
The corrosion evaluation should be based on a corrosion prediction model, or on relevant test or field
corrosion data agreed with the end user. General and localized corrosion of carbon steel takes place over
time, and the anticipated corrosion rate should be calculated for the operating conditions.
6.2.2 Corrosion mechanisms
6.2.2.1 General
For wet hydrocarbon systems made of carbon steel or corrosion-resistant alloy (CRA) the corrosion
mechanisms indicated in Table 2 should be evaluated.
Table 2 — Materials prone to internal corrosion mechanisms in hydrocarbon systems
Corrosion mechanism Carbon and low alloy steel CRA
a
CO and H S corrosion Yes Yes
2 2
MIC Yes Yes
SSC/SCC caused by H S Yes Yes
HIC/SWC Yes No
ASCC Yes No
SCC without H S No Yes
a
The presence of H S in combination with CO can also lead to localized attacks of CRAs. The critical parameters are temperature,
2 2
chloride content, pH and partial pressure of H S. There are no generally accepted limits and the limits vary with type of CRA.
6.2.2.2 CO and H S corrosion
2 2
CO corrosion is one of the most common corrosion mechanisms that occur on carbon steels in oil and gas
production and processing systems. The most important parameters for CO corrosion are temperature,
partial pressure of CO , pH, content of organic acids and flow conditions. Several models for the prediction of
CO corrosion on carbon steel are available, and the model used should be agreed with the end user.
The presence of H S in combination with CO influences the corrosion of carbon steel. The type of corrosion
2 2
is dependent on the proportions of these constituents in the production fluids. For carbon steel, general
mass-loss corrosion caused by H S-dominated corrosion conditions is rarely a problem, since the iron sulfide
scale is generally protective. However, if the scale is damaged, then localized pitting corrosion can occur.
Deposition of elemental sulfur or solids due to stagnant flow conditions may promote such localized corrosion.
No generally accepted corrosion models exist to predict this form of localized attack, and the evaluation
should therefore be based on operational experience.
Top-of-line corrosion can take place due to condensation of water in the top of the pipe in a stratified flow
regime. Important parameters for such top-of-line corrosion are flow regime, operating temperature,
condensation rate, CO fugacity and content of organic acids. Top-of-line corrosion should be evaluated using
models specifically made for this or using test data gathered under similar operating conditions. Top-of-line
corrosion can also be influenced by the presence of H S.
8 © ISO 2010 – All rights reserved

ISO 21457:2010(E)
Under flowing conditions flow-enhanced corrosion or erosion-corrosion can occur. Flow-enhanced corrosion
will occur under high flow rates, as a result of accelerated mass transport of the reactants and reaction
products. Many corrosion models consider the influence of flow-enhanced corrosion and such models should
be used for prediction of corrosion rate under flowing conditions. At very high fluid velocities, even in the
absence of solids, the liquid phase can be so energetic as to mechanically erode any protective scales or
remove the protective inhibitor film in inhibited lines and cause erosion-corrosion. In the presence of solids,
such mechanical erosion of the protective layers/films can occur at lower fluid velocities. In both cases, the
consequences are more rapid material wastage rates than would be expected if simply summing predicted
erosion and corrosion rates. This erosion-corrosion can occur even at low predicted sand erosion rates in
fluids that are corrosive to the material under consideration. More information on sand erosion is provided
in 6.5.
6.2.2.3 Microbiologically induced corrosion
Microbiologically induced corrosion (MIC) from sulfate-reducing bacteria, or other bacteria such as
acid-producing bacteria and nitrate-reducing bacteria, can lead to high local corrosion rates. Low flow
velocities in pipelines increase the likelihood of MIC.
MIC is likely to occur in dead legs and other settling locations. Cleaning and chemical treatment can be used
to prevent MIC. The need for sampling points and biocide injection facilities should be considered in design.
NOTE MIC is normally caused by sessile bacteria in contact with carbon steel rather than planktonic bacteria.
6.2.2.4 Sulfide stress cracking (SSC)/stress corrosion cracking (SCC) caused by H S
The evaluation and use of materials in conditions containing H S, where cracking including hydrogen-induced
cracking (HIC) is possible, shall follow the requirements given in ISO 15156 (all parts). This evaluation should
include the potential for future changes in reservoir H S content, especially if water injection is planned.
Dehydration of gas or use of corrosion inhibitors should not relax the requirement to use H S-resistant
materials if the conditions are otherwise categorized as sour in accordance with ISO 15156 (all parts).
6.2.2.5 Alkaline stress corrosion cracking
Alkaline environments containing compounds such as amines, caustic or carbonates can cause alkaline
stress corrosion cracking (ASCC) of carbon steels, especially where there is the potential to concentrate these
compounds, e.g. in the presence of crevices or evaporation.
Typical mitigation measures may include heat treatment after welding or forming, use of protective coatings,
CRA or non-metallic materials.
[26] [18]
NOTE Reference can be made to NACE RP0403 for guidance on caustic cracking or to API RP 945 for
guidance on amine cracking.
6.2.2.6 Stress corrosion cracking without H S
Occasionally, internal SCC can occur in SS in the absence of H S and dissolved oxygen in oil and gas
production systems. This is due to local process conditions causing water evaporation and
deposition/concentration of chlorides in high salinity waters and at high temperatures. Systems where this can
occur should be designed with fresh wash water injection facilities to prevent concentration of chlorides or
resistant materials should be used.
6.2.3 Corrosion parameters
6.2.3.1 General
Parameters considered in a corrosion evaluation should include the following, as appropriate:
a) CO ;
ISO 21457:2010(E)
b) H S;
c) temperature;
d) organic acids;
e) oil/gas properties and water content;
f) oxygen;
g) elemental sulfur;
h) mercury (Hg);
i) production chemicals.
Annex A gives an example of the contents of the design basis for materials evaluation in hydrocarbon systems.
It should be noted that the design basis should consider the possibility of changing operational conditions over
a facility's design life, such as increasing water cut and reservoir souring over the design life of the facilities.
6.2.3.2 CO and H S contents
2 2
Most CO corrosion prediction models for carbon steel require input in terms of CO fugacity. The CO partial
2 2 2
pressure in the gas phase should be used, which can be derived from flash calculations for the actual
conditions. For piping/pipelines transporting wet hydrocarbon liquids (oil and condensate), the CO content
and the total pressure for the last separation stage should be used to estimate the corrosion rate. For lines
carrying wet gas, the CO fugacity is a function of the lines operational pressure and temperature.
To compensate for non-equilibrium conditions downstream of a pressure reduction, the corrosion rate found
for the conditions upstream of a pressure reduction may be assumed.
For evaluation of cracking including HIC in H S-containing service, the partial pressure is normally used. The
H S content in the gas phase should be used, which should be derived from flash calculations for the actual
conditions.
Corrosion and H S cracking resistance vary with pH which is difficult to measure accurately since it has to be
done under actual pressure and temperature. Therefore, pH should be calculated by a suitable model or by
using ISO 15156. The calculation should be based on CO and H S fugacities at the actual pressure,
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temperature and composition of the produced water. The methodology used should be agreed with the end
user.
If a full water analysis is not available, the values used for corrosion and cracking evaluations should be
agreed with the end user. The following values may be used for an initial evaluation:
⎯ for solutions representing condensed water, as in gas-producing wells, the pH should be calculated
based on the actual temperature and CO /H S fugacity for pure water; with no data available, a pH of 3,5
2 2
and a chloride content of 600 mg/l may be used (1 000 mg/l of NaCl) (this corresponds to a CO fugacity
of 1,0 MPa);
⎯ for solutions representing formation water, as in oil-producing wells, a pH of 4,5 and a chloride content of
100 000 mg/l may be used (165 000 mg/l of NaCl).
When calculating the pH used in CO corrosion predictions in gas production environments with condensing
water, it should be evaluated if the water contains sufficient corrosion products, as they act to increase pH and
reduce corrosivity. Downstream of CRA piping or equipment, such as gas coolers, it should be assumed that
the water is free from corrosion products and potentially corrosive to carbon steel.
10 © ISO 2010 – All rights reserved

ISO 21457:2010(E)
6.2.3.3 Temperature
Resistance to corrosion and SCC vary with temperature for carbon steels and CRAs. Sensitivity calculations
or evaluations can be necessary to determine the most critical temperature range.
The possibility of periods involving higher temperatures, such as heat tracing, steam-out or solar radiation,
should be considered in the corrosion evaluation.
Temperatures during construction, transportation, storage and installation should also be considered.
6.2.3.4 Organic acids
Organic acids increase the corrosivity of the produced fluids and their presence should be included in the
corrosion evaluation for carbon steel.
NOTE The corrosivity due to organic acids is determined by the presence of undissociated organic acid, as opposed
to organic acid salts. Hence, it is essential to consider the complete water chemical analysis.
6.2.3.5 Oil/gas properties and water content
Flow effects and liquid properties can keep the water entrained in the oil phase. This may prevent contact
between the separated water and the steel surface. However, the potential inhibition effect of the oil phase
should be used with caution. Laboratory testing can be utilized to determine if oil can have inhibiting properties.
A gas is considered dry when the water dew point at the operational pressure is at least 10 °C lower than the
minimum operating temperature for the system. Such systems are not subject to electrochemical corrosion
and no corrosion prediction is required.
NOTE Gas dehydration in glycol contactors leads to condensation of a glycol/water mixture in dry gas pipelines
[typically less than 10 % (mass fraction) water]. Even though this does not represent any corrosion threat for the pipeline,
large quantities of corrosion products can accumulate in the pipeline. These products can cause problems, since the
corrosion products can arrive at the receiving facility as “black dust” during pigging operations.
If the export gas specification is less than this dew point limit or there is a possibility of transient periods of
operation with insufficient or no dehydration, this should be considered in the corrosion evaluation.
6.2.3.6 Oxygen
Oxygen is not
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