1. 50 Pipeline & Gas Journal / February 2010 / www.pgjonline.com
Material Selection
For Sour Service
Environment
et us consider the properties
of hydrogen sulfide (H2S) gas
which is also known as sour gas
or sulfuretted hydrogen. It is pos-
sibly the second most deadly gas
after carbon monoxide that man
can encounter in the industrial environment.
Common in all sectors of the petroleum
industry, this gas can be found in any location
where decaying matter is present. Knowledge
of the properties of H2S is important to
understand the role of this gas.
Materials Selection
The materials selection process should
reflect the overall philosophy regarding design
life, cost profile, inspection and maintenance
philosophy, safety and environmental profile,
failure risk evaluations and other specific
project requirements. Materials selection
should be optimized and provide acceptable
safety and reliability. At a minimum, the fol-
lowing should be considered:
n Corrosivity, taking into account speci-
fied operating conditions including start
up and shut-down conditions;
n Design life and system availability
requirements;
n Failure probabilities, failure modes and
failure consequences for human health,
environment, safety and material assets;
n Resistance to brittle fracture;
n Inspection and corrosion monitoring; and
n Access for maintenance and repair.
For the final materials selection the follow-
ing additional factors should be included in the
evaluation: priority should be to select materials
with good market availability and documented
fabrication and service performance; and the
number of different materials should be mini-
mized considering stock, costs, interchangeabil-
ity and availability of relevant spare parts.
In the best engineering judgment the devia-
tions from materials selection guidance given
above may be taken if an overall cost, safety and
reliability study points to an alternative choice.
The selected material must be evaluated
for its corrosivity. At a minimum, this would
include the following: CO2-content; H2S-
content; oxygen content and content of other
oxidizing agents; operating temperature and
pressure; organic acids, (pH); halide, metal
ion and metal concentration; velocity, flow
regime and sand production; biological activ-
ity; and condensing conditions.
As is evident, there are various factors that
must be considered for material selection for
any system, some of these may be already
defined in the project documents and other
factors might require further investigations.
However, since the present discussion is lim-
ited to the material selection for sour service
system we will concentrate on that.
What is meant by sour service? What could
be considered sour service is based on the defi-
nitions and guidance provided by industry speci-
fications like NACE MR 0175/ISO 15156 and
also on Canadian specification CSA Z 662. The
approach of NACE is not so much on defining
sour service but on the question of how severe
is the possibility of sulfide stress corrosion
cracking in the material. It may be noted that,
irrespective of which approach is taken as basis
for the determination of sour service conditions,
they complement each other and the end result to
the material selection process is same.
The CSA Z 662 (Table 1) includes a list of
approved materials and allows for the non-
listed materials to be used as per the approval
process given in the NACE procedures. NACE
MR 0175 does not include a list of approved
materials but gives ways to establish suitability
of the material for sour service.
L
Service Limit describing the sour service
a Gas partial pressure >0.35 kPa (0.0508 psi)
b Multi Phase System
Pressure below•
1.4 MPa (203 psi)
> 50 mmol/mol H2S content in Gas phase
Pressure• ≥
1.4 MPa (203 psi)
> 70kPa (10.153 psi) partial pressure of H2S in gas phase.
Note For Table 1: While the concentrations given in items a) and b) are the normally accepted minimum concentra-
tions at which material problems occur, the presence of other constituents in the phases making up the fluid, such as
CO 2 in the gas phase and salts in the liquid phase, may cause problems to occur at lower concentrations of hydrogen
sulfide. Figure 1 graphically describes the limits given in the Table 1.
Table 1: Definition of “Sour Service” given in CSA Z662.
By Ramesh Singh, MS, IEng, MWeldI, Gulf Interstate Engineering

2. Pipeline & Gas Journal / February 2010 / www.pgjonline.com 51
Figure 2: Sketch of NACE SSC Regions of
environmental severity.
What happens to material in sour service?The
basic knowledge about what happens to material
like pipe, components, bolting, and equipment
used in sour service environment is described
here. Materials in the sour environment are
susceptible to sulfide stress corrosion cracking
(SSC) and hydrogen-induced cracking, hydro-
gen embrittlement and exfoliation (HE-HIC)
that leads to various modes of failure including
stepwise cracking, hence the importance during
the design stage on material selection.
Consider SSC. The NACE specification
defines the SCC as the cracking of metal
involving corrosion and stress--both residual
and or applied--in the presence of H2S and
water. It is a type of hydrogen induced crack-
ing (HIC) in which the primary poison is the
evolution of atomic hydrogen. Process condi-
resistant materials General principles for
selection of cracking-resistant materials.
n Part-2: NACE MR0175/ISO 15156-2,
Petroleum and natural gas industries —
Materials for use in H2S -containing
environments in oil and gas production
— Part 2: Cracking-resistant carbon and
low alloy steels.
n Part-3: NACE MR0175/ISO 15156-3,
Petroleum and natural gas industries —
Materials for use in H2S -containing
environments in oil and gas production
— Part 3: Cracking-resistant CRAs (cor-
rosion-resistant alloys) and other alloys.
NACE Approach
To Material Selection
Material to be qualified shall be described
and documented. Those of its properties likely
to affect performance in H2S -containing
media are defined.
The tolerances, or ranges, of properties that
can occur within the material are described
and documented.
Metallurgical properties known to affect
performance in H2S -containing environments
include chemical composition, method of
manufacture, product form, strength, hard-
ness, amount of cold work, heat-treatment
condition and microstructure.
There are two ways to qualify a material for
use in sour service system: field experience or
lab testing.
Field experience. A material could be quali-
fied by documenting field experience. The
Article continued on page 69
Table 2: Factors that affect hydrogen-induced cracking.
Temperature: Inversely proportioned to
increasing temperature above room tempera-
ture 25 degrees C. In fact, heating to 200
to 250 degrees C reverses the hardness to
some degree, and allows the material to
regain some of the lost ductility. This allows
increased workability of the affected mate-
rial. This change allows welding with suitably
developed welding procedures that would
reduce risk of post weld cracking.
Hydrogen concentration: An increase in
hydrogen ingress in steel increases the stress
level and hardness leading to premature fail-
ure. The mechanism of cracking is explained
by development of internal pressure on the
assumption that interstitial atomic hydrogen
is released as molecular hydrogen at voids or
other sites under extreme pressure that results
in formation of visible blisters associated with
HIC specially seen in ductile metals that are
cathodically polarized. Delayed cracking is
often associated with high strength of steel.
1. The internal flaws set up in steel by non-
metallic inclusions like MnS, often nucleate
hydrogen blisters. These contribute to pipe-
line failures by induced hydrogen -Blister
cracking or Stepwise cracking (for detailed
information Ref. NACE TM 0284) — such
failures originate from superficial corrosion
of steel by an acid H2S environment librat-
ing atomic hydrogen which diffuses into
the metal and is released at the inclusion-
metal interface sites as molecular hydro-
gen under high pressure. Under similar
conditions less ductile material would
crack. The hydrogen cracking is associ-
ated with time delay. The time delay is only
slightly dependent on applied stress. The
delay time decreases with the hydrogen
concentration in steel and with increase
in hardness or tensile strength. For small
concentrations the fracture may occur sev-
eral days after the stress is applied.
2. Surface flaws also influence the hydrogen
cracking (or sulfide stress cracking) of
moderate to high strength steels exposed
to brine containing H2S. Since strength of
steel parallels its hardness, the empirically
determined maximum hardness specified
in Rc22 = 248 HV10 corresponds to yield
strength of about 90 ksi. It is suggested;
that the threshold values of the stress
intensity factor for steels exposed to
aqueous H2S solutions, the Rc22 cor-
responds to a critical surface-flaw depth
of about 0.5 mm (0.02 in.). Beyond this
depth flaws are apt to develop quickly
into major cracks. Small-size flaws of this
order, which are calculated to be still less
tolerable for harder steels are not readily
avoided in practice, thereby tying in with
general practice that in H2S environ-
ment, steels of hardness > Rc22 should
be avoided. It is to be noted that surface
flaws become more important to cracking
as the strength of steel increases. On the
other hand, internal flaws affect both low
and high strength steels.
Material strength level: The strength of
material is rapidly increased by the ingress of
hydrogen in steel, thus increased stress level
and hardness leading to premature failure as
discussed above.
Cold work: The cold work increases the rate
of corrosion several folds in acidic environ-
ment. The residual energy produced by cold
working measured by calorimeter (usually <
7cal/g) is less than sufficient to account for
an appreciable change in free energy, thus the
cause of increased corrosion rate is not the
residual stress but the segregation of carbon or
nitrogen atoms at imperfection sites produced
by plastic deformation. Such sites exhibit lower
hydrogen overvoltage than either cementite or
iron. This is possibly the most important factor
for increased corrosion rate in cold worked
steel in acidic environment. n
tions involving wet hydrogen sulfide are called
sour services. A high incidence of sulfide-
induced HIC has resulted in the coining of the
term sulfide stress corrosion cracking (SSC).
This affects a normally ductile material mak-
ing it hard and brittle. The failure is brittle due
to the ingress of atomic hydrogen (H). This
is a cathodic phenomenon where the normal
evolution of hydrogen is inhibited, and atomic
hydrogen (nascent hydrogen) in the cathodic
reaction enters the metal. In such cases the
cathodic reaction aggravates the cracking. The
factors that affect hydrogen induced cracking
are discussed in Table 2.
As a result of the susceptibility to SSC
and HE, discussed in Table 2, the intended
materials for sour service should comply with
the requirements of the sour service clause of
the applicable material standard and meet the
requirements of NACE.
NACE MR O175/ ISO 15156
There are several short duration courses run
by NACE (e-mail: firstservice@nace.org) to
explain how to read and understand this speci-
fication. Readers are encouraged to attend
them for greater understanding of how to use
this specification which is of extreme impor-
tance in selecting and testing material. This is
only an introduction.
Structure Of NACE MR O175
The specification has three parts. It is titled,
Petroleum and natural gas industries—Materi-
als for use in H2S containing environments in
oil and gas production:
n Part-1: NACE MR0175/ISO 15156-1
General principles for selection of cracking-

3. Pipeline & Gas Journal / February 2010 / www.pgjonline.com 69
material shall meet the requirements stated
here and the service conditions in which the
experience has been gained must meet the
requirements described in NACE.
At least two years of such documented
field experience records shall be required and
should involve a full examination of the equip-
ment following field use. The qualification is
limited to the severity of field service condi-
tions as documented.
Laboratory testing. The lab testing can only
approximate field service conditions. Lab testing
in accordance with the all parts of NACE specifi-
cation may be used in following situations:
1. To qualify corrosion-resistant or other
alloys with respect to their resistance to gal-
vanically induced HSC;
2. To qualify metallic materials for their
resistance to SSC and/or SCC under service
conditions up to the limits that apply to pre-
qualified materials of similar types listed in
Part-2 and Part-3;
3. To qualify metallic materials for their
resistance to SSC and/or near-neutral pH SCC
under service conditions with other limits.
There are two types of SCC normally found
on pipelines, known as high pH (pH 9 to 13)
and near-neutral pH SCC (pH 5 to 7). Detailed
discussion of SCC is not part of this document
because SCC is associated with alkaline condi-
tions unlike acidic conditions of sour service;
4. To provide qualification data for a material
not currently shown as pre-qualified in NACE
Part 2 and Part 3 in such a form that it may be
considered for inclusion at a later date;
5. To qualify carbon and low alloy steels with
respect to their resistance to HIC, SOHIC or SZC.
Testing Process Details
The section describes details of the testing
process that includes the following: sampling
of materials for laboratory testing; selection
of laboratory test methods; conditions to be
applied during testing; and acceptance criteria.
Basic criteria for qualification and selection
of carbon and low alloy steels with resistance
to SSC, SOHIC and SZC.
Option 1: Selection of SSC-resistant steels
(and cast irons) using method A.2:
For p H2S < 0.3 kPa (0.05 psi)
Normally no special precautions are required
for the selection of steels for use under these con-
ditions, nevertheless, highly susceptible steels
can crack. Further information on factors affect-
ing susceptibility of steels and attack by crack
mechanisms other than SSC must be evaluated.
For p H2S > 0.3 kPa (0.05 psi), if the par-
tial pressure of H2S in the gas is equal to or
greater than 0.3 kPa (0.05 psi), SSC-resistant
steels shall be selected using method A.2.
Option 2: Selection of steels for specific
sour service applications or for ranges of sour
service Sulfide Stress Cracking (SSC):
This option allows the user to qualify select-
ed materials for SSC resistance for specific
sour service applications or for ranges of sour
service. This also facilitates fitness-for-pur-
pose evaluations of existing carbon or low
alloy steel equipment exposed to sour service
conditions more severe than assumed in the
current design.
The severity of the sour environment, deter-
mined in accordance with NACE Part 1, with
respect to SSC of a carbon or low alloy steel
should be assessed using Figure 2.
In defining the severity of the H2S -contain-
ing environment, the possibility of exposure
to unbuffered condensed aqueous phases of
low pH during upset operating conditions or
downtime, or to acids used for well stimulation
and/or the backflow of stimulation acid, after
reaction should be considered.
Consider Region 0 p H2S < 0.3 kPa (0.05
psi). Normally, no precautions are required
for the selection of steels for use under these
conditions. Nevertheless, a number of fac-
tors that can affect steel’s performance in this
region should be considered, including the fact
that a steel that is highly susceptible to SSC
and HSC may crack; and the fact that a steel’s
physical and metallurgical properties affect its
inherent resistance to SSC and HSC.
Very high strength steels can suffer HSC
in aqueous environments without H2S. Above
about 965 MPa (140 ksi) yield strength, atten-
tion may be required to steel composition and
processing to ensure that these steels do not
exhibit SSC or HSC in Region 0 environ-
ments. Stress concentrations increase the risk
of cracking.
Consider SSC Regions 1, 2 and 3. Referring
to the Regions of severity of the exposure as
defined in Figure 1, steels for Region 1 may be
selected using A.2, A.3 or A.4, steels for Region
2 may be selected using A.2 or A.3 and steels
for Region 3 may be selected using A.2.
In the absence of suitable choices from
Annex-A, carbon and low alloy steels may
be tested and qualified for use under specific
sour service conditions or for use throughout
a given SSC Region. Testing and qualifica-
tion shall be in accordance with NACE part-1
and Annex-B.
Documented field experience may also be
used as the basis for material selection for a
specific sour service application.
The user should consider SOHIC and SZC,
as defined in NACE, Part-1, when evaluating
carbon steels in plate form and their welded
products for sour service in H2S -contain-
ing environments. The occurrence of these
phenomena is rare and they are not well
understood. They have caused sudden failures
in parent steels (Stress-Oriented Hydrogen
Induced Cracking-SOHIC) and in the HAZ of
welds (SOHIC and SZC). Their occurrence is
thought to be restricted to carbon steels. The
presence of sulfur or oxygen in the service
environment is thought to increase the prob-
ability of damage by these mechanisms.
Let us consider sour environment and hard-
ness requirements. Generally, cracking of
steel pipes in the environments containing
H2S is categorized into two types, HIC and
SSC. Both HIC and SSC belong to hydrogen
embrittlement phenomena. Hydrogen atoms
generated by a sulfide corrosion process are
adsorbed on the steel surface and diffuse into
the steel. The hydrogen diffuses to the regions
with a high triaxial tensile-stressed condition,
or various defects such as inclusions, precipi-
tations or dislocations that trap hydrogen and
causes embrittlement of steel.
Unlike HIC which develops at conditions
without applied stress, SSC occurs under
externally or internally stressed or strained
conditions and propagates perpendicularly to
the tensile stress direction. SSC of line pipe
steels exposed to sour environment under
external stress is classified into type I and type
II. Type I SSC can occur in two stages, the first
stage is the formation of hydrogen induced
internal blister cracks parallel to applied stress.
In the second stage, the blister cracks link
together perpendicularly to applied stress.
Generally, type I SSC is referred to as stress-
oriented hydrogen induced cracking (SOHIC)
because of formation of the blister cracks par-
allel to the applied stress. On the other hand,
type II SSC is recognized to be the crack-
ing which results from the typical hydrogen
embrittlement. The final failure occurs in the
direction perpendicular to applied stress in the
manner of quasi-cleavage. It is to prevent the
second stage type II SSC that the maximum
hardness of 248 in Vickers is specified.
The hardness of parent materials and of welds
and their heat-affected zones play important roles
in determining the SSC resistance of carbon and
low alloy steels. Hardness control can be an
acceptable means of obtaining SSC resistance.
If hardness level for the parent metal is
specified, sufficient hardness tests is required
to establish the actual hardness of the particu-
lar steel. Individual HRC readings exceeding
the specified maximum is permitted by NACE,
if the average of several readings taken within
close proximity does not exceed the value
permitted by NACE and no individual read-
ing is greater than 2 HRC above the specified
value. Equivalent requirements shall apply to
other methods of hardness measurement when
specified in this part of specification or refer-
enced in a manufacturing specification.
Article continued from page 51
It is critical to note that the number and
location of hardness tests on parent metal
are not specified in NACE.
For ferritic steels, EFC Publication 16
shows graphs for the conversion of hard-
ness readings, from Vickers to Rockwell
(C) and from Vickers to Brinell, derived
from the tables of ASTM E 140 and BS
860. Other conversion tables also exist.
Users may establish correlations for indi-
vidual materials.

4. 70 Pipeline & Gas Journal / February 2010 / www.pgjonline.com
Consider hardness testing methods for
welding procedure qualification. The qualifi-
cation of welding procedures for sour service
shall include hardness testing in accordance
NACE. Hardness testing for welding proce-
dure qualification is carried out on the Vickers
scale using 10-kg or 5-kg load in accordance
with ISO 6507-1, or the Rockwell method in
accordance with ISO 6508-1 or ASTM A 370,
E 18, and E 92 using the 15N scale.
The HRC method may be used for welding
procedure qualification if the design stress
does not exceed two-thirds of SMYS and
the welding procedure specification includes
post weld heat treatment. The use of the HRC
method for welding procedure qualification in
all other cases shall require the agreement of
the equipment user.
Consider hardness in production welds.
Processes and consumables should be selected
in accordance with good practice and to achieve
the required susceptibility to SSC, SOHIC and
SZC cracking resistance. Welding is carried
out in compliance with specified codes and
standards. Welding procedure specifications
(WPSs) and procedure qualification records
(PQRs) are made available for inspection.
Consider hardness caused by other fabrica-
tion methods. For steels that are subject to
hardness change caused by fabrication meth-
ods other than welding, hardness testing shall
be specified as part of the qualification of the
fabrication process. Hardness testing is speci-
fied as part of the qualification of burning/cut-
ting processes if any HAZ remains in the final
product. The form and location of the samples
for evaluation and testing is specified.
Now consider evaluation of carbon and low
alloy steels for their resistance to HIC/SWC.
The designers must evaluate the flat-rolled car-
bon steel products for sour service environments
containing even trace amounts of H2S material
for HIC/SWC. The possibility of HIC/SWC
is influenced by chemistry and manufacturing
route of steel. The level of sulfur is of particular
importance, typical maximum acceptable levels
for flat-rolled and seamless products are 0.003
% and 0.01 %, respectively. Conventional forg-
ings with sulfur levels less than 0.025 %, and
castings, are not normally considered sensitive
to HIC or SOHIC. P&GJ
The author--Ramesh Singh, is senior princi-
pal engineer (materials, welding and corro-
sion), at Gulf Interstate Engineering, Houston.
Telephone: 713-850-3687, e-mail: rsingh@
gie.com.
REFERENCES
G. Biefer, MP, 21(6), 19 (1982).
Canadian Specification, CSA Z 662.
C. Carter and M. Hyatt, “Stress Corrosion Cracking and
Hydrogen Embrittlement of Iron Base Alloys,” Page 551,
edited by R. Staehle et al., NACE, Houston TX (1977).
Z. Foroulis and H. Uhlig, Journal Electrochem Society
111, 522 (1964).
J. Marquez, I. Matsushima, and H. Uhlig, Corrosion,
26, 215 (1970).
NACE MR 0175/ ISO 15156.
NACE Committee T-1F MP 12 (3), 41 (1973).
H. Uhlig, “Physical Metallurgy of Stress Corrosion
Fracture,” Pages 1 to 17 edited byT. Rodhin, Interscience
N.Y. (1959).
B. Wild, C. Kim and E. Phelps, Corrosion, 36, 625 (1980).
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