Sour Service Reference

NACE MR0175 / ISO 15156 — Sour Service Material Tables

Complete NACE MR0175 / ISO 15156 reference: OCTG grades qualified for H₂S service, hardness limits, SSC region classification by pH and H₂S partial pressure, linepipe HIC requirements, and CRA material group overview. Filterable tables per ISO 15156-2 (carbon steels) and ISO 15156-3 (CRA).

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NACE MR0175 / ISO 15156 Overview

NACE MR0175 (now published as ISO 15156) defines material requirements for oil and gas equipment exposed to H₂S-containing (sour) environments that can cause sulfide stress cracking (SSC), hydrogen-induced cracking (HIC), and stress-oriented hydrogen-induced cracking (SOHIC).

The standard has three parts: Part 1 — general principles; Part 2 — carbon and low-alloy steels (OCTG, linepipe, fittings); Part 3 — corrosion-resistant alloys (CRA) and other alloys. This page covers the most critical tables for OCTG casing and tubing procurement.

Table data verified 2026-07-01 — NACE MR0175/ISO 15156:2020.

Sour Service Definition — H₂S Threshold

Sour service applies when H₂S partial pressure in the gas phase is ≥ 0.0003 MPa (0.05 psia / 0.3 kPa). Below this threshold, SSC-resistant materials are not required by the standard — though many company specifications apply stricter limits. Unit conversions:

Sour Service H₂S Threshold Unit Conversions — 0.0003 MPa Sour Service Definition (NACE MR0175/ISO 15156-1)
Unit	Value	Note
MPa	0.0003	SI unit — used in ISO 15156 text
kPa	0.30	Equivalent — often used in lab reports
psia	0.05	USC unit — used in NACE MR0175 original text, most field specs
bar	0.003	Common in European project specs
mbar	3.0	Used in some chromatograph reports
ppmv	varies	Depends on total system pressure — must convert via Dalton's law

NACE MR0175/ISO 15156-2 OCTG Carbon Steel Grade Limits — Maximum Hardness (NACE vs API 5CT) and Sour Service Qualification for Grades H40–Q125
Grade	Min Yield (ksi)	Min Yield (MPa)	Max HRC (NACE)	Max HRC (API 5CT)	Heat Treatment	PSL Required	Sour Qualified	Notes
H40	40	276	22	—	Not specified	Any	✓ Yes	Rarely used in sour service — low yield, typically shallow conductors
J55	55	379	22	—	Not specified	Any	✓ Yes	Acceptable for mild sour (Region 1). Not common in deep sour production strings
K55	55	379	22	—	Not specified	Any	✓ Yes	Same sour qualification as J55; higher tensile requirement only
N80-1	80	552	22	—	N+T or Q+T	Any	✓ Yes	Suitable for mild sour (Region 1) with hardness control; verify heat lot hardness survey
N80Q	80	552	22	—	Q+T only	Any	✓ Yes	Q+T gives more uniform hardness than N80-1. Preferred over N80-1 for sour service
L80-1	80	552	23	23	Q+T only	PSL-2	✓ Yes	Primary OCTG sour service grade. API and NACE hardness limits aligned at 23 HRC. Specify PSL-2 + NACE compliance
L80-3Cr	80	552	—	23	Q+T only	PSL-2	✗ No	NOT for sour service. Sweet CO₂ only (2–3% Cr). API 5CT 11th ed (Dec 2023)
L80-9Cr	80	552	—	23	Q+T only	PSL-2	✗ No	NOT for sour service. Sweet CO₂ only (9% Cr). API 5CT 11th ed (Dec 2023)
L80-13Cr	80	552	—	23	Q+T only	PSL-2	✗ No	NOT for sour service. Sweet CO₂ only. H₂S above threshold → ISO 15156-3 CRA required
C90	90	621	25.4	25.4	Q+T only	PSL-2	✓ Yes	Sour service up to ~3.4 MPa H₂S pp. API and NACE limits aligned at 25.4 HRC. PSL-2 mandatory
T95	95	655	22 ⚠	25.4	Q+T only	PSL-2	✓ Yes	HARDNESS TRAP: API allows 25.4 HRC; NACE requires max 22 HRC for sour service. Must specify 22 HRC on PO
R95	95	655	—	—	Q+T only	Any	✗ No	Sweet service only — no NACE MR0175 qualification
P110	110	758	—	—	Q+T only	Any	✗ No	NOT for sour service. Deep HPHT sweet wells only
C110	110	758	29.0	29.0	Q+T only	PSL-2	✓ Yes	Highest-strength NACE-qualified grade. Use for H₂S pp > 1.5 psia. API 5CT 11th ed (Dec 2023)
Q125	125	862	—	—	Q+T only	Any	✗ No	Ultra-deep sweet wells only. No NACE qualification

T95 Hardness Trap — Critical Procurement Note API 5CT permits T95 casing up to 25.4 HRC. NACE MR0175 / ISO 15156-2 requires maximum 22 HRC for sour service. Pipe can pass API 5CT acceptance inspection and still fail NACE qualification. Always add this purchase order clause for sour service T95:


"T95 Grade — NACE MR0175 / ISO 15156-2 compliant. Maximum hardness 22 HRC. PSL-2."

Grade Escalation Path for Sour Service (OCTG)

OCTG Sour Service Grade Escalation Path by H₂S Partial Pressure (NACE MR0175/ISO 15156-2)
H₂S Partial Pressure	Recommended Grade	Max Hardness (NACE)
< 0.0003 MPa (< 0.05 psia)	Any API 5CT grade	—
0.0003–0.01 MPa (0.05–1.5 psia)	L80-1 PSL-2	23 HRC
0.0003–0.01 MPa (0.05–1.5 psia)	T95 Type 1 PSL-2	22 HRC
0.01–0.10 MPa (1.5–15 psia)	L80-1 or C90 or C110 PSL-2	23 / 25.4 / 29.0 HRC
> 0.10 MPa (> 15 psia)	C110 PSL-2 or CRA	29.0 HRC
CO₂ + trace H₂S	Super 13Cr (ISO 15156-3 qual.)	Per mill qualification

SSC Region Classification

ISO 15156-2 Figure 1 defines four SSC regions based on in-situ pH and H₂S partial pressure. The region determines which materials are acceptable. Temperature below 65°C increases SSC susceptibility; above 65°C, SSC risk generally decreases and restrictions may be relaxed with qualification evidence.

ISO 15156-2 SSC Region Classification — H₂S Partial Pressure, In-Situ pH and Acceptable OCTG Materials (ISO 15156-2:2020 Figure 1)
Region	H₂S Partial Pressure	In-Situ pH (approx.)	Temperature Effect	Acceptable Materials (OCTG)
0 (Sweet)	< 0.0003 MPa < 0.05 psia	Any	Any	Any carbon steel, no SSC restriction
1 (Mild)	≥ 0.0003 MPa ≥ 0.05 psia	pH ≥ 5.5 (at low H₂S)	Any	Carbon steel ≤ 22 HRC; J55, K55, N80, L80 acceptable
2 (Mod.)	≥ 0.0003 MPa ≥ 0.05 psia	pH 4.5–5.5	< 65°C most critical	L80-1 PSL-2 (23 HRC), C90, T95 (22 HRC max) PSL-2
3 (Severe)	≥ 0.0003 MPa ≥ 0.05 psia	pH < 4.5	Low temp increases risk	L80-1 or CRA (Super 13Cr, duplex, nickel alloy)

Source: ISO 15156-2:2020 Figure 1 (SSC environmental severity regions). Boundaries are approximate — use the actual Figure 1 curve for precise region determination at your specific conditions.

pH Boundary Reference by H₂S Partial Pressure

Approximate region boundaries from ISO 15156-2 Figure 1. In-situ pH is the pH at actual well conditions, not surface pH. For CO₂-dominated wells, downhole pH is typically lower than surface pH.

ISO 15156-2 SSC Region pH Boundaries by H₂S Partial Pressure (Approximate Values from ISO 15156-2:2020 Figure 1)
H₂S pp (MPa)	H₂S pp (psia)	Region 0/1 Boundary (pH)	Region 1/2 Boundary (pH)	Region 2/3 Boundary (pH)
0.0003 (threshold)	0.05	≈ 4.5	≈ 3.5	< 3.5
0.001	0.15	≈ 5.0	≈ 4.0	< 4.0
0.01	1.5	≈ 5.5	≈ 4.5	< 4.5
0.07	10	≈ 6.5	≈ 5.5	< 5.5
0.35	50	≈ 7.5	≈ 6.5	< 6.5
1.0	145	≈ 8.0	≈ 7.5	< 7.0

Values are approximate interpolations from ISO 15156-2 Figure 1. Always use the actual figure in the published standard for region determination.

Temperature and Chloride Effects

SSC Risk Modifying Factors — Temperature, Chloride and Environmental Effects on Sour Service Material Selection (NACE MR0175/ISO 15156)
Factor	Effect on SSC Risk	Design Consideration
Temperature > 65°C (150°F)	SSC risk decreases significantly	May allow higher-strength grades; requires qualification evidence per ISO 15156-2 Annex A
Temperature < 24°C (75°F)	SSC risk increases — low temp is most critical	Conservative material selection; hardness control critical
High chloride (> 50 g/L)	Increases CSCC risk for CRA; limited effect on carbon steel SSC	Key factor for CRA selection (Super 13Cr, duplex); check ISO 15156-3
Low pH (< 3.5)	Increased H₂ activity; Region 3 conditions	CRA or strictly controlled L80-1 / C110 at low H₂S partial pressure only
High H₂S + CO₂ combination	Synergistic attack — both SSC and CO₂ corrosion	CRA selection required for most production tubing environments
Elemental sulfur	Pitting attack on CRA; sulfide film on carbon steel	Separate from SSC assessment; requires special CRA qualification

API 5L Sour Service Requirements (ISO 15156-2 / API 5L Annex H)

For line pipe in sour gas service, ISO 15156-2 and API 5L PSL2 Annex H define material qualification requirements. HIC (hydrogen-induced cracking) and SOHIC (stress-oriented HIC) testing are mandatory for sour service line pipe. Key acceptance criteria from NACE TM0284 and EFC Publication 16:

API 5L Sour Service HIC/SOHIC Qualification Requirements per ISO 15156-2 and API 5L PSL2 Annex H (NACE TM0284 Acceptance Criteria)
Parameter	Requirement	Standard Reference
Hardness (base metal)	≤ 22 HRC (250 HBW / 248 HV10)	ISO 15156-2 / API 5L Annex H
Hardness (weld + HAZ)	≤ 22 HRC (250 HBW / 248 HV10)	ISO 15156-2 / API 5L Annex H
HIC test method	NACE TM0284 — immersion in NACE A or B solution	NACE TM0284 / ISO 15156-2 Annex B
CLR (Crack Length Ratio)	≤ 15%	EFC 16 / ISO 15156-2 Table B.1
CTR (Crack Thickness Ratio)	≤ 5%	EFC 16 / ISO 15156-2 Table B.1
CSR (Crack Sensitivity Ratio)	≤ 2%	EFC 16 / ISO 15156-2 Table B.1
SSC test method	NACE TM0177 Method A — 720 h at ≥ 80% SMYS	NACE TM0177 / ISO 15156-2 Annex B
Carbon equivalent (CEIIW)	≤ 0.25 (sour service)	ISO 15156-2 Table A.1 / API 5L Annex H
Sulfur content	≤ 0.002% (≤ 0.003% if HIC test passed)	API 5L PSL2 Annex H
Phosphorus content	≤ 0.020%	API 5L PSL2 Annex H
NDE	Full-length UT (PSL2 mandatory)	API 5L PSL2

HIC Crack Ratio Definitions

CLR — Crack Length Ratio

Σ(crack lengths) / sample length × 100%

Limit: ≤ 15%

Proportion of the sample cross-section length occupied by cracks.

CTR — Crack Thickness Ratio

Σ(crack thicknesses) / sample thickness × 100%

Limit: ≤ 5%

Proportion of the sample thickness occupied by cracks.

CSR — Crack Sensitivity Ratio

CLR × CTR / 100

Limit: ≤ 2%

Combined severity metric — product of length and thickness ratios.

HIC vs SOHIC — Key Differences

HIC vs SOHIC — Mechanism, Crack Orientation, Location and Prevention
Property	HIC (Hydrogen-Induced Cracking)	SOHIC (Stress-Oriented HIC)
Driving force	Hydrogen pressure in inclusions/voids	Applied or residual stress + hydrogen
Crack orientation	Stepwise, parallel to rolling direction	Oriented perpendicular to stress direction
Location	Body of plate/pipe — not stress-dependent	HAZ of welds, high-stress zones
Primary concern	Large-diameter, plate-formed linepipe	Welds in high-stress service, HPHT
Prevention	Low S, low P, clean steel, HIC test	PWHT, low hardness HAZ, SSCC testing
Test method	NACE TM0284	NACE TM0177 / EFC 16 SOHIC test

ISO 15156-3 CRA Material Groups (OCTG Application)

When carbon steel grades (L80-1, C90, T95, C110) cannot meet the corrosion requirements — typically when CO₂ is too high for carbon steel or H₂S partial pressure exceeds the carbon steel service envelope — a corrosion-resistant alloy (CRA) is selected per ISO 15156-3. Service envelopes below are indicative; actual qualification limits depend on the specific heat, condition, and test results.

ISO 15156-3 CRA Material Groups for OCTG Sour Service — Alloy System, Qualification and Indicative H₂S Limits
Material Group	Alloy System	Sour Qualification	Max H₂S pp (indicative)	Max Temp. (°C)	Notes
L80-13Cr (API 5CT)	13% Cr martensitic	NOT sour service qualified	< 0.0003 MPa (sweet only)	≤ 150°C	CO₂ corrosion resistance only. Any H₂S → use Super 13Cr or duplex
Super 13Cr	Mod. 13Cr (13–15% Cr, Mo, Ni)	Mild sour — qualification required	≤ 0.01 MPa (project-specific)	≤ 150°C	Must pass ISO 15156-3 Annex B qualification. Check mill TDS for specific H₂S limits
22Cr Duplex (2205)	22% Cr, 5% Ni, 3% Mo	Moderate sour	≤ 0.1 MPa typical	≤ 232°C	Wide sour envelope. Used for tubing in moderate H₂S + CO₂ wells
25Cr Super Duplex	25% Cr, 7% Ni, 4% Mo	Moderate–severe sour	≤ 0.2 MPa typical	≤ 232°C	Higher strength and wider H₂S tolerance than 22Cr duplex
Alloy 825 (N08825)	Ni-Fe-Cr (21% Cr, 28–46% Ni)	Severe sour	High H₂S + CO₂ + Cl⁻	≤ 218°C	Excellent SSC resistance. Used for severe sour HPHT tubing
Alloy 625 (N06625)	Ni-Cr-Mo (21.5% Cr, 9% Mo)	Very severe sour	All H₂S levels	≤ 218°C	Premium grade for extreme environments. Very high cost

H₂S partial pressure limits are indicative. Qualification under ISO 15156-3 requires mill-specific test certificates. Verify mill TDS against project H₂S and temperature envelope before ordering.

CRA Selection by Well Environment

CRA Selection by Well Environment — Primary Corrosion Threat and Recommended Material (ISO 15156-3)
Environment	Primary Corrosion Threat	Recommended CRA	Notes
Sweet CO₂ (no H₂S)	CO₂ corrosion	L80-13Cr or 3Cr	Standard for most CO₂ wells. 13Cr preferred for high CO₂ + temp
Trace H₂S + CO₂	CO₂ corrosion + mild SSC	Super 13Cr	Must pass ISO 15156-3 qualification. Check H₂S pp vs mill limit
Moderate H₂S + CO₂	SSC + CO₂ corrosion	22Cr Duplex (2205)	Wide service envelope; high connection cost
High H₂S + CO₂ + Cl⁻	SSC + CO₂ + CSCC	25Cr Super Duplex or Alloy 825	Severe environment; premium cost. Verify with CSCC testing
Elemental sulfur + H₂S	SSC + pitting	Alloy 625 or 825	Elemental sulfur attacks 13Cr and duplex; only Ni alloys reliable
HPHT + H₂S	SSC + high stress	Alloy 825 / 625 or HT duplex	Thermal expansion and sustained load SSC testing required

Purchase Order Specification Language

Correct PO language prevents supply of API-compliant but NACE-non-compliant pipe. Example clauses by grade:

L80-1 (sour service)

API 5CT 11th Ed., Grade L80 Type 1, PSL-2. NACE MR0175 / ISO 15156-2 compliant. Maximum hardness 23 HRC (base metal and entire cross-section). SR-15 hardness survey required.

T95 (sour service)

API 5CT 11th Ed., Grade T95 Type 1, PSL-2. NACE MR0175 / ISO 15156-2 compliant. Maximum hardness 22 HRC. SR-15 hardness survey required.

C90 (sour service)

API 5CT 11th Ed., Grade C90 Type 1, PSL-2. NACE MR0175 / ISO 15156-2 compliant. Maximum hardness 25.4 HRC.

C110 (sour service)

API 5CT 11th Ed., Grade C110, PSL-2. NACE MR0175 / ISO 15156-2 compliant. Maximum hardness 29.0 HRC. Charpy impact testing required.

Common Specification Mistakes

Common Sour Service Procurement Mistakes — Consequence and Correct Practice (NACE MR0175/ISO 15156)
Mistake	Consequence	Correct Practice
Specifying T95 without 22 HRC limit	Receive 25.4 HRC pipe — fails NACE on-site	Always add 22 HRC max to T95 PO for sour service
Using L80-13Cr in trace H₂S well	SCC failure in service within months	Switch to Super 13Cr or carbon steel L80-1 if H₂S > threshold
Measuring H₂S in ppmv without converting to partial pressure	Incorrect sour service classification	pH₂S = (ppmv × 10⁻⁶) × total pressure. Use Dalton's law.
Applying 65°C SSC exemption without test evidence	Non-conformance at project audit	Obtain ISO 15156-2 Annex A qualification data from mill at service temperature
Specifying NACE conformance without PSL-2	No hardness survey; no NDE; unverified qualification	NACE-qualified OCTG is meaningless without PSL-2
Ordering HIC-tested pipe without CLR/CTR/CSR acceptance criteria on PO	Mill uses internal criteria — may not meet EFC 16 limits	Always specify CLR ≤ 15%, CTR ≤ 5%, CSR ≤ 2% per NACE TM0284 on PO

Frequently Asked Questions

What H₂S partial pressure defines sour service under NACE MR0175?

NACE MR0175 / ISO 15156-1 defines sour service as any wet system where the H₂S partial pressure in the gas phase is ≥ 0.0003 MPa (0.05 psia / 0.3 kPa). Below this threshold, no SSC-resistant material is required. In liquid hydrocarbon systems, sour service applies if the gas phase H₂S at standard conditions would exceed this limit. Note: many company specifications use 0.05 psia as the trigger threshold — confirm with your project spec.

What is the hardness limit for T95 casing in sour service per NACE MR0175?

NACE MR0175 / ISO 15156-2 requires T95 Type 1 casing used in sour service to have a maximum hardness of 22 HRC — not the 25.4 HRC permitted by API 5CT. This is the well-known T95 hardness trap: pipes that pass API 5CT dimensional and hardness inspection may still fail NACE qualification. Always order T95 with explicit NACE MR0175 conformance and specify the 22 HRC maximum on your purchase order.

Is L80-13Cr casing approved for sour service under NACE MR0175?

No. L80-13Cr is NOT approved for sour service under ISO 15156-3. It is qualified only for sweet CO₂ corrosion environments where H₂S partial pressure is below the sour service threshold (0.0003 MPa). For wells with any H₂S, even trace amounts, a sour-qualified CRA (Super 13Cr under specific conditions, 22Cr duplex, Alloy 825) or a sour-qualified carbon steel grade (L80-1, C90, T95, C110) must be selected.

Can P110 or Q125 casing be used in sour service per NACE MR0175?

No. API 5CT grades P110 and Q125 are not listed in NACE MR0175 / ISO 15156-2 as acceptable carbon steel grades for sour service. Their high yield strength (758 MPa minimum for P110; 862 MPa for Q125) makes them susceptible to sulphide stress cracking (SSC). Use in sour service requires specific qualification testing per ISO 15156-2 Annex B under defined environmental conditions. For HPHT sour wells that require high mechanical strength, corrosion-resistant alloy (CRA) tubing or a sour-qualified grade such as T95 or C110 with reduced wellbore H₂S partial pressure management is the typical engineering approach.

What is the maximum hardness limit for N80 and J55 casing in sour service per NACE MR0175?

NACE MR0175 / ISO 15156-2 permits N80-1, N80Q, J55, and K55 in sour service provided hardness does not exceed 22 HRC (237 HBW) at any location in the pipe body, coupling, or accessory. These are relatively low-strength grades and are acceptable for SSC Regions 1, 2, and 3 subject to that hardness limit. Heat lot hardness surveys are required for each lot to confirm compliance, particularly for N80Q which is quenched and tempered and can exhibit hardness variation between pipe-body and weld-line areas.

What is the difference between SSC and HIC, and does NACE MR0175 cover both?

Sulphide Stress Cracking (SSC) is hydrogen embrittlement under tensile stress in the presence of H₂S — it primarily affects high-strength, high-hardness steels. Hydrogen Induced Cracking (HIC) is step-wise internal cracking in lower-strength steels caused by hydrogen absorption and trapping at inclusions, independent of applied stress. NACE MR0175 / ISO 15156 Part 2 covers SSC hardness limits for carbon and low-alloy steels and includes HIC/SOHIC test requirements in Annex B for linepipe steels. For OCTG and gathering line pipe in sour service, project specifications often require both SSC hardness compliance per MR0175 and HIC testing per NACE TM0284.

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