Sour service OCTG selection is the most consequential material decision in well design. A wrong grade in an H₂S environment does not simply corrode slowly and give warning — it fractures under load, without visible deterioration, at stresses well below yield. Sulfide stress cracking failures in production casing and tubing have caused blowouts and well losses. The engineering and procurement decisions made before the pipe ships determine whether the well operates safely or fails catastrophically.
This article consolidates the NACE MR0175/ISO 15156-2 qualification requirements for API 5CT OCTG grades, explains why the API hardness limit and the NACE hardness limit are not the same number for all grades, and provides a decision framework for selecting the correct grade across the range of H₂S partial pressures encountered in oil and gas production. ZC Steel Pipe supplies L80, C90, T95, and C110 to operators in West Africa, the Middle East, and Southeast Asia — and the procurement traps described here come from purchase orders we have reviewed, not from reading the standard.
What we see on orders: A recurring situation: T95 pipe arrives at the wellsite, hardness testing at the mill records values in the 23–24 HRC range, and it ships with a fully compliant API 5CT MTC. Everything looks correct. Then the company man asks for the NACE MR0175 compliance certificate, and the problem becomes visible — NACE MR0175/ISO 15156-2 requires a maximum of 22.0 HRC for T95, not 25.4 HRC. Pipe testing at 24.0 HRC passes API 5CT receiving inspection (limit 25.4 HRC) but is non-conforming for sour service. The order has to be replaced. Emergency replacement pipe ordered under rig standby pressure costs significantly more per tonne than getting the specification right on the original purchase order. The 3.4 HRC gap between the API limit and the NACE limit for T95 is real, and it catches teams who specify the grade without explicitly calling out the NACE hardness ceiling.
What Makes a Well "Sour" — The NACE Threshold
NACE MR0175/ISO 15156 Part 1 defines sour service as any system in which the H₂S partial pressure in the gas phase exceeds 0.0003 MPa (0.05 psia). This threshold is intentionally conservative — at the wellbore pressures common in deep or HPHT wells, trace H₂S concentrations that appear insignificant on a gas analysis report can easily exceed it.
At 10,000 psi (69 MPa) wellbore pressure, 50 ppm H₂S in the produced gas yields an H₂S partial pressure of approximately 0.5 psia — ten times the NACE trigger. A well with 5 ppm H₂S at 10,000 psi still exceeds the threshold. For liquid-dominated systems, Part 1 adds criteria based on in-situ pH and dissolved H₂S concentration; these conditions can trigger sour service requirements even at gas-phase partial pressures below 0.05 psia.
The operational rule is straightforward: if the well contains any measurable H₂S and is operated at significant pressure, design for sour service. The cost of upgrading to a NACE-qualified grade is small relative to the consequence of an SSC failure.
SSC Mechanism — Why Hardness Matters
Sulfide stress cracking proceeds through a hydrogen embrittlement mechanism. H₂S in produced water dissociates to form H⁺ and HS⁻ ions. These ions react at the steel surface, generating atomic hydrogen. Molecular hydrogen cannot penetrate the steel lattice — atomic hydrogen can. It diffuses inward and accumulates at grain boundaries, inclusions, and any region of elevated stress concentration in the microstructure.
Under applied or residual stress, brittle fracture initiates at hydrogen-enriched sites. The defining feature of SSC is that fracture occurs at stress levels far below the material's yield strength — sometimes below 50% of yield. There is no plastic deformation, no visible necking, no forewarning. The pipe performs normally under hydrostatic test and then fractures in service.
Hardness is the engineering proxy for SSC susceptibility because it correlates directly with tensile strength and with the density of high-energy microstructural sites where hydrogen can accumulate. A higher-hardness heat of T95 pipe is more susceptible to SSC than a lower-hardness heat of the same nominal grade — and NACE MR0175/ISO 15156-2 encodes this by setting maximum hardness limits that are lower, in some cases significantly lower, than the API 5CT production limits.
For the complete grade ladder with tensile, hardness, and chemistry data, see the API 5CT specification tables →
SSC is a system failure, not a material defect. The same T95 pipe at 24 HRC performs perfectly in a sweet well — within specification, full burst and collapse capacity, no corrosion concern. In an H₂S environment, that pipe can fracture. The material did not change; the environment did. This is why NACE MR0175 compliance must be specified before the order is placed, not after the pipe arrives on the wellsite. A mill that ships T95 at 24 HRC is not shipping defective pipe — it is shipping API 5CT-compliant pipe. The specification gap is in the purchase order, not the product.
Approved Grades and Their Hardness Limits
API 5CT 11th Edition designates four Group 2 and 3 grades as sour service qualified: L80 Type 1, C90, T95 Type 1, and C110. The low-strength grades H40, J55, and K55 are also permitted under NACE MR0175/ISO 15156-2 with appropriate hardness verification — their inherently low yield strength makes them less susceptible to SSC.
The table below shows, for each NACE-approved grade, the API 5CT hardness limit, the NACE MR0175/ISO 15156-2 hardness limit, and whether a gap exists between them. Every number in this table is verified against api-5ct-spec.json (API 5CT, 11th Edition).
| Grade | Min Yield (MPa / ksi) | Max Yield (MPa / ksi) | API Max HRC | NACE Max HRC | Gap | Sour Approved? |
|---|---|---|---|---|---|---|
| L80 Type 1 | 552 / 80 | 655 / 95 | 23.0 | 23.0 | None | Yes |
| C90 | 621 / 90 | 724 / 105 | 25.4 | 25.4 | None | Yes |
| T95 Type 1 | 655 / 95 | 758 / 110 | 25.4 | 22.0 | 3.4 HRC | Yes — with NACE limit |
| C110 | 758 / 110 | 828 / 120 | 29.0 | 29.0 | None | Yes |
Three grades have no gap between their API and NACE hardness limits — L80 Type 1, C90, and C110. For these grades, pipe that passes API 5CT hardness inspection automatically meets the NACE hardness requirement. T95 is the exception: the API limit is 25.4 HRC but NACE MR0175/ISO 15156-2 requires no more than 22.0 HRC. That 3.4 HRC window is where sour service procurement errors happen.
The chemistry requirements for sour service grades are also tighter than for general service grades. C90 and T95 both carry S_max 0.010% and P_max 0.020%. C110 has the tightest sulphur limit in the entire API 5CT grade list: S_max 0.005%. These limits reflect the role of sulphide inclusions as hydrogen trapping sites — lower sulphur means fewer inclusions and lower SSC susceptibility at a given hardness level.
To match a grade to your well conditions, use the AI Pipe Grade Selector →
The T95 Hardness Trap — Worked Example
The worked example below shows precisely why the T95 hardness gap matters in practice.
A shipment of 7" T95 casing is manufactured to API 5CT 11th Edition, PSL-2. Mill hardness testing records the following results across the heat: 22.4 HRC, 23.1 HRC, 24.0 HRC, 23.7 HRC. All readings are at or below 25.4 HRC — the API 5CT limit for T95. The MTC is issued. The pipe ships. API 5CT receiving inspection at the wellsite confirms the readings and accepts the consignment.
The sour service compliance check then asks: does this pipe meet NACE MR0175/ISO 15156-2?
For the reading at 24.0 HRC:
- 24.0 HRC vs. API 5CT limit of 25.4 HRC: passes (24.0 < 25.4)
- 24.0 HRC vs. NACE MR0175 limit of 22.0 HRC: fails (24.0 > 22.0)
The pipe at 24.0 HRC is API-compliant and NACE non-conforming simultaneously. Any test reading above 22.0 HRC — from the 23.1 HRC reading, the 23.7 HRC, and the 24.0 HRC reading — fails the NACE requirement. Three of the four readings in this example fail. The mill was not at fault: it shipped pipe that meets the specification it was given. The PO did not specify the NACE hardness limit. The entire consignment now requires either rejection, additional documentation to establish traceability of individual joints, or replacement.
The correct PO language for T95 in a sour well:
"T95 Type 1, API Specification 5CT 11th Edition, PSL-2, maximum hardness 22.0 HRC per NACE MR0175/ISO 15156-2. Hardness shall be verified at both pipe body and upset ends. Individual hardness readings shall appear on the mill test report. Mill shall provide a NACE MR0175/ISO 15156-2 compliance letter for each heat."
Grades NOT Approved for Sour Service
The following grades are not listed in NACE MR0175/ISO 15156-2 Table B.1 and must not be used in H₂S-containing wells under any circumstances.
N80 (Type 1 and N80Q): N80 carries no hardness limit under API 5CT — the JSON shows max_hardness_hrc: null. No hardness limit means no SSC control. N80 is a general service grade that happens to sit in the same yield range as L80; the two grades are not interchangeable in sour wells. The N80 vs L80 comparison covers this distinction in detail.
P110: P110's 758 MPa (110 ksi) minimum yield strength at the bottom of its range, combined with its unrestricted microstructure and no hardness limit (API 5CT carries no HRC limit for P110), makes it inherently unsuitable for H₂S environments. No heat treatment protocol qualifies P110 for sour service. Teams who need 110 ksi yield strength in a sour well must specify C110, not P110. C110 and P110 share the same minimum yield floor — 758 MPa / 110 ksi — but C110 is designed and tested for sour service, with a 29.0 HRC hardness limit and S_max 0.005%.
Q125: Q125 is not approved for sour service. Its minimum yield of 862 MPa (125 ksi) places it far above the hardness range that NACE MR0175/ISO 15156-2 qualifies for carbon and low-alloy steel.
All chromium-bearing L80 sub-types — L80-3Cr, L80-9Cr, L80-13Cr: These grades share the L80 mechanical property window and even the same 23 HRC hardness limit, but they are CO₂ corrosion grades, not sour service grades. The chromium content in these alloys provides electrochemical corrosion resistance to CO₂ attack in sweet wells. It provides no resistance to sulfide stress cracking in H₂S. All three sub-types are classified sour_service: false in API 5CT, and none are listed in NACE MR0175/ISO 15156-2 Table B.1.
Specifying L80-13Cr for a sour well is a non-conforming material selection — and it is a selection we have seen on purchase orders from procurement teams who confused CO₂ resistance with H₂S resistance. The two corrosion mechanisms are entirely different. For wells with both CO₂ and H₂S in the produced fluid, the correct approach is to specify L80 Type 1 with NACE hardness verification for the H₂S resistance, or escalate to Super 13Cr or a duplex CRA alloy where both mechanisms must be addressed simultaneously.
Grade Selection by H₂S Partial Pressure
No single grade fits all sour service conditions. The selection depends on the H₂S partial pressure, the required casing yield strength for the well design, and the well depth and temperature. The framework below is a starting point; the well-specific design governs.
| H₂S Partial Pressure | Recommended Grade | Key Consideration |
|---|---|---|
| < 0.05 psia (0.0003 MPa) | Any API 5CT grade | Below NACE MR0175 threshold — standard selection applies |
| 0.05–1.5 psia | L80 Type 1 (80 ksi) | Primary sour service grade; 23 HRC limit aligned between API and NACE |
| 0.05–1.5 psia (higher strength needed) | T95 Type 1 with NACE 22.0 HRC limit | Higher yield for deeper strings; must specify NACE limit explicitly in PO |
| 1.5–10 psia | C90 or T95 Type 1 with NACE limit | Both qualified; C90 provides intermediate yield step at 90 ksi |
| > 10 psia (severe sour) | C110 | Highest NACE-approved carbon steel grade; S_max 0.005% addresses inclusion control |
| CO₂ + H₂S combined | L80 Type 1 (mild H₂S) or CRA alloy | L80-13Cr is NOT acceptable in any H₂S environment; escalate to Super 13Cr or duplex |
Temperature matters. SSC severity increases as temperature decreases — the same pipe in the same H₂S environment is more susceptible at 20°C wellhead temperature than at 80°C bottomhole temperature. NACE MR0175/ISO 15156-2 includes temperature-dependent restrictions for some applications; review these against the well temperature profile, not just the reservoir conditions.
Procurement Trap and Correct PO Language
The procurement trap for sour service OCTG is not complicated, but it is consistent: the purchase order specifies the API grade without specifying the NACE hardness limit. The mill ships fully API-compliant pipe. The pipe fails NACE MR0175 qualification on arrival.
Wrong PO language:
"T95 API 5CT 11th Edition, PSL-2"
What this produces: T95 pipe manufactured to API 5CT, with hardness anywhere from below 22 HRC to 25.4 HRC. All of it is API-compliant. None of the pipe above 22 HRC is NACE-compliant for sour service.
Correct PO language for T95 sour service:
"T95 Type 1, API Specification 5CT 11th Edition, PSL-2, maximum hardness 22.0 HRC per NACE MR0175/ISO 15156-2. Hardness testing to be performed at pipe body and both upset ends. Individual test results to appear on the MTC by heat number. Mill to provide NACE MR0175/ISO 15156-2 compliance letter."
For other grades, the NACE limit language is simpler because the API and NACE limits align:
- L80 Type 1: Add "NACE MR0175/ISO 15156-2 qualified, maximum hardness 23.0 HRC" — consistent with the API limit, but stating it explicitly creates a paper trail.
- C90: "NACE MR0175/ISO 15156-2 qualified, maximum hardness 25.4 HRC" — aligned with API limit.
- C110: "NACE MR0175/ISO 15156-2 qualified, maximum hardness 29.0 HRC, S_max 0.005%" — the sulphur limit is the critical chemistry call-out.
Every sour service order should also state: quench and temper heat treatment (mandatory for all Group 2 and 3 sour grades), sulphur and phosphorus chemistry limits by heat analysis, and EN 10204 3.2 MTC (third-party witnessed) for projects where NACE non-compliance would delay well operations. In West African deepwater and Middle Eastern gas well projects, we treat 3.2 MTC as the default for all sour service casing.
Supply — NACE Certification Documentation
When we supply sour service OCTG, the documentation package for each heat includes the mill test report with individual hardness readings at body and ends, the heat treatment record (time, temperature, quench method), the heat analysis and product analysis showing S and P within the grade limits, and a NACE MR0175/ISO 15156-2 compliance letter issued by the mill identifying the heat number and confirming it meets Table B.1 qualification requirements.
For severe sour service applications (H₂S partial pressure above 3 psia), we can arrange NACE TM0177 SSC testing and NACE TM0284 HIC testing by an accredited third-party laboratory. These tests are not required by API 5CT or NACE MR0175 for standard qualification, but deepwater operators and HPHT projects increasingly request them as supplementary assurance. Request these at order placement — they add lead time.
The hardness limit is the controlling parameter, but it is not the only one. A sour service order without explicit NACE documentation is a sour service order that cannot be verified at the wellsite. When the company man asks for the NACE compliance letter and it is not in the documentation package, the options are: fly out replacement pipe or accept unverified material. Neither is acceptable when H₂S is present.
For the full L80 sour service grade specification, see API 5CT L80 Casing Pipe — Sour Service Guide →
For T95 sour service detailed specifications, see API 5CT T95 Casing Pipe — Sour Service Guide →
For C110 high-strength sour service specifications, see API 5CT C110 Casing Pipe →
Frequently Asked Questions
Which API 5CT grades are approved for sour service under NACE MR0175?
NACE MR0175/ISO 15156-2 approves the following API 5CT grades for sour service: H40, J55, K55 (with hardness limits), L80 Type 1 (max 23 HRC per API 5CT and NACE MR0175), C90 (max 25.4 HRC — same limit in both API 5CT and NACE MR0175, no gap), T95 Type 1 (max 25.4 HRC per API 5CT but NACE MR0175 requires 22.0 HRC — a 3.4 HRC gap), and C110 (max 29.0 HRC per API 5CT and NACE MR0175). The chromium-bearing L80 sub-types — L80-3Cr, L80-9Cr, L80-13Cr — are CO₂ corrosion resistance grades and are NOT approved for sour service. N80, P110, and Q125 are also NOT approved for sour service. The hardness limit is the critical compliance parameter — pipe passing API 5CT inspection can still fail NACE MR0175 qualification.
What is sulfide stress cracking and why does it matter for OCTG?
Sulfide stress cracking (SSC) is a form of hydrogen embrittlement that occurs when high-strength steel is exposed to H₂S in the presence of water. H₂S in solution produces atomic hydrogen that diffuses into the steel lattice and causes brittle fracture at stress levels well below the material's yield strength. SSC risk increases with higher steel hardness, higher H₂S partial pressure, lower temperature, and higher stress. This is why NACE MR0175 imposes hardness limits — hardness is a proxy for SSC susceptibility.
What H₂S partial pressure triggers NACE MR0175 requirements?
NACE MR0175/ISO 15156 defines sour service as any system where the H₂S partial pressure exceeds 0.0003 MPa (0.05 psia) in the gas phase. This is a very low threshold — even trace H₂S concentrations in high-pressure wells can exceed it. For liquid systems, additional criteria apply based on in-situ pH and H₂S content in solution. When in doubt, treat the well as sour and specify accordingly.
What is the hardness gap between API 5CT and NACE MR0175 for T95?
API 5CT specifies a maximum hardness of 25.4 HRC for T95. NACE MR0175/ISO 15156-2 imposes a stricter limit of 22.0 HRC for T95 in sour service. This 3.4 HRC gap means pipe that passes API 5CT hardness inspection can still fail NACE MR0175 qualification — and this is exactly what happens when the PO only specifies 'T95 API 5CT' without requiring the NACE 22.0 HRC limit. C90 and C110 do not have this gap: for C90, the API and NACE hardness limits are identical (25.4 HRC). For C110, both limits are 29.0 HRC.
Is L80-13Cr suitable for H₂S service?
No. L80-13Cr is a CO₂ corrosion resistance grade, not a sour service grade. Its 13% chromium content provides electrochemical resistance to CO₂ corrosion in sweet wells, NOT resistance to H₂S sulphide stress cracking. L80-13Cr is not listed in NACE MR0175/ISO 15156-2 as approved for H₂S service. Specifying L80-13Cr for a sour well is a non-conforming material selection. For wells with both CO₂ and H₂S, the correct path is to specify L80 Type 1 (with NACE hardness verification) for the H₂S resistance, or escalate to Super 13Cr or a CRA alloy for combined CO₂/H₂S service. The same applies to L80-3Cr and L80-9Cr — all chromium-bearing L80 sub-types are CO₂ grades only.
Can P110 be used with special heat treatment for sour service?
No. P110 is not listed in NACE MR0175/ISO 15156-2 Table B.1 for sour service regardless of heat treatment or hardness. The high yield strength of P110 (110 ksi minimum) combined with its microstructure makes it inherently unsuitable for H₂S environments. There is no special heat treatment or certification that qualifies P110 for sour service. If 110 ksi yield strength is required in a sour well, C110 is the correct grade — it is explicitly listed in NACE MR0175 with a maximum hardness of 29.0 HRC.