Beyond PSL2 — API 5L Annex H Metallurgy Requirements for Sour Gas Pipelines

Standard API 5L PSL2 is a meaningful upgrade from PSL1 — it adds yield strength ceiling control, mandatory Charpy impact testing, carbon equivalent limits, and full-length NDE. But PSL2 alone does not make a pipe suitable for H₂S service. The additional metallurgical requirements for sour gas pipelines go significantly beyond what PSL2 mandates, and that gap is where procurement errors become pipeline integrity failures. API 5L Annex H defines what PSL2 misses: HIC resistance testing, tighter sulphur and phosphorus chemistry, calcium treatment for inclusion shape control, and mandatory hardness surveys of the weld HAZ. None of these are automatic under a standard PSL2 purchase order. All of them must be explicitly invoked.

ZC Steel Pipe supplies sour service line pipe to API 5L PSL2 with Annex H supplementary requirements (SR15C and SR15A), HIC-tested per NACE TM0284, to pipeline contractors across Africa, the Middle East, and South America. What follows is how we think about Annex H qualification — drawn from the purchase orders we process, the MTCs we review, and the inspection holds we navigate.

Why Standard PSL2 Is Insufficient for H₂S Service

PSL2 controls the properties that matter for mechanical integrity in sweet service: yield ceiling, yield-to-tensile ratio, carbon equivalent, Charpy energy, and full-length NDE. Sulphur is limited to 0.015%. That limit exists to maintain weldability, not to prevent HIC. The two are different metallurgical requirements, and 0.015% S is four to five times higher than the threshold above which HIC risk becomes significant.

A pipe produced to standard PSL2 chemistry — with sulphur at 0.012%, within specification — can contain enough elongated manganese sulphide (MnS) inclusions in the pipe body to initiate HIC cracking within months of commissioning in an H₂S environment. The pipe would carry a valid MTC, pass all PSL2 inspection requirements, and still be the wrong material for the service. Annex H exists because PSL2 was not designed to address this.

What PSL2 explicitly does not control: HIC resistance of the pipe body, sulphide inclusion morphology, calcium treatment, HAZ hardness after field welding, and SSC resistance of the weld seam. These are the exact failure modes that Annex H addresses.

HIC vs SSC — Two Different Failure Modes

Hydrogen-induced cracking and sulphide stress cracking are both H₂S-driven failure modes, but they occur by different mechanisms, in different locations, and under different conditions. Understanding the distinction matters because they require different supplementary requirements to address.

HIC — pipe body failure, no applied stress required. In an H₂S environment, corrosion at the pipe inner surface generates atomic hydrogen. This hydrogen diffuses into the steel lattice and accumulates at internal discontinuities — primarily elongated MnS inclusions oriented parallel to the pipe axis from hot rolling. When the local hydrogen pressure at an inclusion tip exceeds the fracture toughness of the surrounding steel, a crack initiates. These cracks propagate parallel to the pipe wall, and multiple cracks on adjacent planes can link up to form a blister or step crack that grows toward the outer surface. No tensile stress is required — HIC occurs in the pipe body under normal operating conditions in H₂S service.

SSC — weld and HAZ failure under tensile stress. Sulphide stress cracking is a form of hydrogen embrittlement. Atomic hydrogen diffuses into zones of high hardness and high residual stress — the weld HAZ in LSAW and ERW pipe is the primary location — and causes brittle fracture at stress levels well below the material's nominal yield strength. SSC requires both H₂S exposure and tensile stress to occur. The critical variable is hardness: above 22 HRC, the risk of SSC increases sharply.

Both failure modes are addressed by Annex H, but through different supplementary requirements. SR15C targets HIC through chemistry controls and pipe body testing. SR15A targets SSC through weld and HAZ testing under NACE TM0177. For most sour gas pipelines, both supplementary requirements should be invoked.

What Annex H Requires

Annex H of API Specification 5L, 46th Edition invokes two supplementary requirements relevant to sour service:

SR15C — HIC Testing (pipe body): Testing per NACE TM0284 using NACE Solution A, 96 hours duration. Acceptance criteria: CLR ≤ 15%, CTR ≤ 5%, CSR ≤ 2%. Testing frequency is per heat of steel.

SR15A — SSC Testing (weld and HAZ): Testing per NACE TM0177 Method A (tensile) or Method D (four-point bend) using NACE Solution A, 720 hours. Acceptance: no cracking at 90% SMYS. Required for LSAW and ERW welded pipe where the HAZ is the high-hardness, high-stress zone at risk.

The chemistry requirements that accompany Annex H represent the largest departure from standard PSL2:

The progression from PSL1 to PSL2 to Annex H represents a 10× reduction in the sulphur maximum — from 0.030% to 0.003%. That is not a safety margin adjustment; it reflects the difference between a sweet-service chemistry specification and a sour-service metallurgical requirement.

For the complete PSL2 grade tables with chemistry and mechanical properties, see the API 5L specification tables →

To calculate minimum wall thickness or design pressure for a sour gas pipeline, use the Pipeline Design Calculator →

HIC Testing — NACE TM0284 Criteria

The HIC test per NACE TM0284 — the standard referenced by API 5L Annex H SR15C — immerses pipe body specimens in NACE Solution A (5% NaCl + 0.5% acetic acid, saturated with H₂S at 24°C, pH 2.7–3.7) for 96 hours. After the immersion period, specimens are sectioned transversely, polished, and examined for cracking. Three ratios are calculated from the measured crack dimensions in each cross-section:

• CLR (Crack Length Ratio): total crack length divided by specimen length in the cross-section, expressed as a percentage. Acceptance limit: ≤ 15%.
• CTR (Crack Thickness Ratio): total crack thickness divided by specimen thickness, expressed as a percentage. Acceptance limit: ≤ 5%.
• CSR (Crack Sensitivity Ratio): the product of CLR and CTR divided by 100 — a combined area measure. Acceptance limit: ≤ 2%.

Worked acceptance check — passing example:

A production heat of X65QS LSAW pipe produces the following HIC test results from three sections examined per specimen:

All three ratios are within acceptance limits. The heat is HIC-compliant per Annex H SR15C.

Failing example: A second heat from the same mill — sulphur at 0.008%, above the 0.003% Annex H limit but the mill attempted to apply calcium treatment — returns CLR = 18%. This exceeds the 15% CLR limit regardless of the CTR and CSR results. The heat is rejected. No remediation is possible once the pipe is manufactured; the heat cannot be re-treated for HIC compliance. The only resolution is replacement with a new heat meeting the 0.003% S product analysis limit and verified Ca/S ≥ 1.5.

The MTC for every accepted sour service heat must show the actual numeric CLR, CTR, and CSR values for each tested section — not a blanket statement of compliance. If an MTC states only "HIC tested per NACE TM0284 — pass" without numeric results, we treat it as non-conforming and request the raw data before shipment release.

Hardness Control — Pipe Body and HAZ

NACE MR0175 / ISO 15156-2 sets 22 HRC (equivalent to 250 HV10 Vickers or 237 HBW Brinell) as the maximum hardness for carbon and low-alloy steel line pipe in sour service. This limit applies universally across the pipe cross-section: pipe body, weld metal, and heat-affected zone.

The HAZ is reliably the hardest zone and the most frequent cause of sour service rejection. During LSAW or field welding, the base metal adjacent to the fusion line is heated to near-melting temperatures and then cooled rapidly. At higher carbon equivalents, this thermal cycle produces hard martensite in the HAZ. HAZ hardness above 22 HRC cannot be resolved by post-shipment treatment on already-manufactured pipe — it requires either rejection or a design-of-service variance, which most project specifications do not permit.

HAZ hardness is controlled during LSAW production through minimum preheat (per qualified WPS), maximum interpass temperature (typically 250°C), controlled heat input range, and post-weld heat treatment for thick-wall pipe. For field girth welding, the same WPS controls apply and are the responsibility of the pipeline contractor — but the base metal carbon equivalent is fixed by the mill chemistry, and a mill that supplies CE IIW ≤ 0.38% gives the field welding team more margin against HAZ hardening than pipe shipped at the PSL2 maximum of 0.43%.

When Annex H Is Not Enough

Annex H SR15C and SR15A address the primary metallurgical risks for most sour gas pipeline applications, but severe sour service conditions can require additional supplementary requirements beyond what Annex H covers.

When H₂S partial pressure is very high — above roughly 0.1 MPa (15 psia) in subsea or deep high-pressure gathering systems — project specifications frequently invoke additional requirements: cold bend testing of production bends to verify HIC resistance in the deformed zone, CTOD fracture toughness testing for heavy-wall pipe, extended SSC testing durations, and stricter chemistry windows (CE ≤ 0.36%, Mn ≤ 1.40%) beyond the Annex H baseline. These are not standardised within API 5L and must be written into the project supplementary requirements directly.

Coating system selection is also part of the sour service qualification. Internal FBE coating on sour gas pipe does not change the metallurgical requirements — the pipe body must still meet Annex H chemistry and HIC acceptance criteria — but a damaged or absent internal coating accelerates the H₂S corrosion rate that drives HIC. For the intersection of metallurgical and coating requirements in sour service, the pipeline coating selection guide covers internal FBE and its role in sour gas system design.

Procurement Trap — Complete PO Language

The procurement trap for sour gas line pipe is straightforward and extremely common: a purchase order reads "API 5L X65 PSL2" for a sour gas pipeline. Annex H is not invoked. The mill produces PSL2 pipe — correct grade, correct CE, correct NDE — that has never been HIC tested and has sulphur at 0.012% (fully within PSL2 limits, 4× above the Annex H limit). The pipe is delivered with a conforming MTC. The project metallurgist or third-party inspector reviews the MTC at the receiving yard and identifies the gap. The full pipe order is placed on hold.

The correct purchase order for sour service X65 line pipe must explicitly state every Annex H requirement:

• Grade designation: API 5L X65QS PSL2 (the 'S' suffix designates sour service qualification per Annex H; 'Q' designates quench and temper delivery condition — adjust suffix for M or N delivery condition as required)
• HIC testing: Supplementary Requirement SR15C — per NACE TM0284, NACE Solution A, 96 hours; acceptance CLR ≤ 15%, CTR ≤ 5%, CSR ≤ 2%; frequency per heat of steel; numeric results on MTC
• SSC testing (welded pipe): Supplementary Requirement SR15A — per NACE TM0177 Method A; NACE Solution A; 720 hours; no cracking at 90% SMYS
• Chemistry: S ≤ 0.003% (product analysis), P ≤ 0.020% (product analysis), calcium treatment — Ca/S ≥ 1.5 or equivalent sulphide shape control; heat analysis and product analysis certificates required
• Hardness: pipe body ≤ 22 HRC (250 HV10); weld metal ≤ 22 HRC; HAZ ≤ 22 HRC — mandatory hardness survey per NACE MR0175 / ISO 15156-2 with survey maps on MTC
• NDE: full-length pipe body UT, full-length weld seam UT, lamination UT of incoming plate (LSAW), end area UT
• Charpy: per PSL2 + SR4A at [project-specified temperature]
• MTC: EN 10204 3.2 (third-party witnessed)
• Third-party inspection: [SGS / Bureau Veritas / TÜV] at mill throughout production

The 'QS' designation in the grade name is the clearest signal that Annex H has been correctly invoked. A PO that specifies "X65Q" or "X65M" without the 'S' suffix has not specified sour service — the mill is compliant manufacturing sweet service pipe.

Supply and Documentation

We supply sour service line pipe to API 5L PSL2 with Annex H SR15C and SR15A to pipeline contractors, EPC firms, and national oil company procurement teams. Grades X65QS and X70QS in LSAW and seamless are the most frequently requested. For large-diameter sour gas trunk lines (above 16 inches), LSAW PSL2 + Annex H is the standard route — seamless is not commercially available at those diameters.

MTC documentation for Annex H supply includes: heat analysis and product analysis certificates confirming 0.003% S and calcium treatment; numeric HIC test results (CLR, CTR, CSR) per heat; hardness survey maps showing pipe body, weld metal, and HAZ measurements; Charpy V-notch test records; full-length NDE reports; and EN 10204 3.2 third-party endorsement.

Third-party inspection scope for sour service orders typically adds a pre-production chemistry review and a hold point at HIC test result receipt — before pipe is released for coating. This adds time to the inspection cycle but prevents a sour service rejection from propagating through to coated finished pipe, which is significantly more costly to reject and replace.

Contact us with your pipeline grade, outer diameter, wall thickness, delivery condition, and sour service supplementary requirements. We will confirm availability, MTC scope, and inspection cycle timeline before confirming lead time.

For the full API 5L grade table covering PSL1 and PSL2 mechanical properties and chemistry, see the API 5L specification tables →

For related guidance on pipeline system design in sour environments, see the API 5L PSL1 vs PSL2 guide and the pipeline coating selection guide for sour service and offshore.