Hydrogen Service Embrittlement — Materials Selection Guide

Executive Summary

Hydrogen embrittlement is the loss of ductility and toughness in metals exposed to hydrogen-bearing environments. In refineries and hydrogen production plants, it’s one of the most serious material-selection risks — a part can look fine and then fail catastrophically under service. This guide gives process engineers the framework to identify hydrogen service zones, select appropriate materials, and conduct design reviews that prevent failures.

The core rule: Never assume carbon steel is acceptable in hydrogen service. Always verify the service against material limits using three parallel criteria: temperature, pressure, and corrosion rate (which determines local hydrogen concentration).

Hydrogen Embrittlement Mechanisms

Hydrogen can damage metals through four distinct pathways:

Mechanism	Abbreviation	Typical Service	Temperature Range	Key Risk Factor
Hydrogen Attack	HA / HTHA	High-P, high-T H₂	200–750°F	Diffusion + carbide reaction
Hydrogen-Induced Cracking	HIC	Sour environments (H₂S)	50–300°F	Surface hydrogen ingress
Stress-Corrosion Cracking	SCC	Corrosive aqueous + stress	50–200°F	Localized hydrogen at stress concentration
Sulfide Stress Cracking	SSC	Sour oil/gas (H₂S)	50–300°F	Cathodic hydrogen + high hardness

Why this matters: Each mechanism has different material limits and design rules. Confusing them is one of the most common design errors.

High-Temperature Hydrogen Attack (HTHA) — The Nelson Curve

High-temperature, high-pressure hydrogen attacks carbon steel through a chemical mechanism: hydrogen diffuses into the metal, reacts with carbides at grain boundaries, and forms methane gas. The result is decarburization, loss of strength, and internal cracking.

The Nelson Curve (API 941 / NACE MR0175) defines safe zones for carbon and low-alloy steels in hydrogen service as a function of temperature and partial pressure of hydrogen.

Safe Material Regions (HTHA)

Material Grade	Safe Temp @ 500 psia H₂	Safe Temp @ 1000 psia H₂	Safe Temp @ 2000 psia H₂	Upper Hardness Limit
Carbon Steel (SA-106 Gr B)	~450°F	~400°F	~350°F	HRC 22
1.25% Cr–0.5% Mo	~700°F	~650°F	~600°F	HRC 23
2.25% Cr–1% Mo	~750°F	~700°F	~650°F	HRC 23
5% Cr–0.5% Mo	~850°F	~800°F	~750°F	HRC 23
9% Cr–1% Mo	~900°F	~850°F	~800°F	HRC 23
Austenitic Stainless (304/316)	No limit (immune)	No limit (immune)	No limit (immune)	N/A

Key insight: Carbon steel is only safe for hydrogen service below ~450°F and only at modest pressures. Once you exceed that, you must step up to a chromium-molybdenum alloy.

Design Rule — Hardness Cap

Never exceed HRC 22 on carbon or low-alloy steels in HTHA service. This includes: - Base metal hardness - Weld metal hardness - Heat-affected zone hardness

High hardness accelerates hydrogen diffusion and trapping at microstructural defects. The API 941 hardness limit is non-negotiable.

Welding in HTHA Service

All welds in HTHA zones must be: 1. Qualified under ASME Section IX with a hydrogen-controlled procedure 2. Post-weld heat-treated (PWHT) per ASME B31.3 Appendix R (typically 1100–1200°F) 3. Tested for hardness post-PWHT (must remain ≤HRC 22) 4. Impact-tested if the code requires it for the base metal

Failure to PWHT is a common cause of cold-cracking failures in the HAZ.

Sour Service (H₂S) — HIC, SSC, and SCC

In sour environments (oil/gas with H₂S contamination, or internal H₂S generation from sulfur compounds), hydrogen enters the metal from the gas phase via a different route: cathodic charging at corroding surfaces. This creates three failure modes:

Hydrogen-Induced Cracking (HIC)

Mechanism: Hydrogen diffuses through the metal, gets trapped at non-metallic inclusions (MnS), and builds up pressure.
Failure mode: Multi-layered internal cracks parallel to the surface (the so-called “stair-step” pattern on fracture surface).
Typical service: Sour crude oil, sour water, sulfidic corrosion.
Prevention:
Use ultra-low-sulfur (ULS) steels or rare-earth-treated steels.
Perform sulfide-inclusion control per NACE MR0175.
Limit carbon content and hardness.
Perform Thin-Laminar Cracking (TLC) testing per NACE TM0284 if high restraint is suspected.

Stress-Corrosion Cracking (SCC)

Mechanism: Hydrogen accumulates at stress concentrations (sharp corners, threading, welds) in the presence of tensile stress and corrosive species (Cl⁻, CO₂, or acetate).
Failure mode: Single rapid-propagation cracks; often initiated at the surface and progressing into the bulk.
Typical service: Sour CO₂/H₂S pipelines, high-pressure acidic water, corrosive refinery streams.
Prevention:
Avoid sharp stress concentrations; use large radii (R ≥ 0.5 in if possible).
Cathodically protect (shift potential negative to inhibit hydrogen entry).
Use low-hardness materials (HRC ≤22 for sour service).
Post-weld stress-relieve.

Sulfide Stress Cracking (SSC)

Mechanism: Hydrogen enters at corroding surfaces in the presence of H₂S, gets trapped, and initiates cracks at stress concentrations under applied or residual tensile stress.
Failure mode: Short, often branched cracks initiating at the surface; can propagate rapidly once initiated.
Typical service: Sour oil/gas wells, sour processing, sour water systems.
Prevention:
Hardness limit: HRC ≤ 22 (same as HTHA).
Material selection: Use NACE MR0175-compliant steels; austenitic stainless steels are immune if no localized corrosion occurs.
Cathodic protection: Shift potential to –950 mV (CSE) if the service allows.
Stress relief: PWHT to remove residual tensile stress.
Post-weld hardness testing: Mandatory.

Material Selection Decision Matrix

Service	Primary Risk	Recommended Base Metal	Hardness Limit	Weld PWHT Required?	Special Tests
High-T, high-P H₂ (HTHA)	HTHA (HA)	Cr-Mo alloy (1.25, 2.25, 5, or 9% Cr)	HRC 22	Yes, 1100–1200°F	Nelson Curve verification, post-PWHT hardness
Sour crude, high H₂S	HIC, SSC	Low-C, low-hardness steel (ULS) or 304/316 SS	HRC 22 (or none for SS)	Yes, stress relief recommended	NACE TM0284 (HIC test), hardness survey
Sour water, acetate	SCC	Low-hardness steel or 304/316 SS	HRC 22 (or none for SS)	Yes, stress relief recommended	Hardness check, cathodic protection design
Caustic (alkaline)	Stress corrosion	Carbon steel, but avoid sharp stress raisers	—	Per ASME code	Stress-relief post-weld
Chloride / high Cl⁻	SCC (localized at pits)	316L, 6Mo SS, or duplex	—	Per code	Pitting resistance index (PREN) check

Design Review Checklist for Hydrogen Service

Use this checklist before you release design for construction:

[ ] Hydrogen source identified: Is H₂ a process gas, a byproduct, or produced in situ (e.g., from sulfidic corrosion)?
[ ] Service temperature confirmed: Is it above or below the HTHA threshold for the material?
[ ] Hydrogen partial pressure (or corrosion rate) quantified: Do you have a psia H₂ number, or evidence of local H₂S generation?
[ ] Base metal hardness limit verified: Is the selected material capable of remaining ≤HRC 22 in all zones (base, HAZ, weld)?
[ ] Weld procedure qualified: Does the WPS specify PWHT for the service?
[ ] Post-weld heat treatment plan documented: Temperature, duration, and cooling rate?
[ ] Post-weld hardness testing specified: Will hardness be checked on every circumferential weld (or per code)?
[ ] Stress concentrations minimized: Are there sharp threads, sharp corners, or stress raisers that could trap hydrogen?
[ ] Cathodic protection evaluated: If sour service, is CP needed? Is the material compatible with CP (e.g., can you reach –950 mV without hydrogen uptake)?
[ ] Impact testing requirement checked: Does the code require impact testing at service temperature?
[ ] Non-destructive testing plan complete: UT, RT, or eddy current for internal defects?
[ ] Vendor material certification reviewed: Does the mill test report confirm hardness, chemistry, and sulfur content limits?

Common Mistakes and How to Avoid Them

Mistake	What Goes Wrong	Prevention
Assuming carbon steel is OK in any hydrogen service	Catastrophic brittle failure, often with little warning	Always check temperature against Nelson Curve; if T > 450°F at significant H₂ pressure, use Cr-Mo
Not post-weld heat treating	Cold cracking in the HAZ; failures 6–18 months into service	Specify PWHT per ASME B31.3 Appendix R (1100–1200°F min); make it non-negotiable in specs
Allowing weld hardness > HRC 22	Hydrogen trapping and cracking at grain boundaries	Require post-PWHT hardness testing on every circumferential weld; reject welds that exceed limit
Overlooking residual stress from machining	Sharp threading or sharp stress raisers act as hydrogen traps	Use large radii (≥0.5 in) on threads and shoulders; avoid sharp corners; consider shot peening
Mixing materials across a weld	Different diffusivity and trapping behavior can localize hydrogen	Use dissimilar-metal welds only with a shim or approved procedure; verify via impact testing
Ignoring local corrosion (pitting, crevice)	Localized low pH + high local hydrogen concentration at pits	Specify high-PREN materials (316L, 6Mo, duplex) if chloride risk is present; consider CP

References

API 941: Steels for Hydrogen Service at Elevated Temperatures and Pressures (5th ed., 2016)
API RP 934-A: Recommended Practice for Corrosion and Cathodic Protection Monitoring on Submerged Structures
NACE MR0175 / ISO 15156: Petroleum, Petrochemical and Natural Gas Industries — Materials for Use in H₂S-Containing Environments in Oil and Gas Production (Eqpt, Tubulars, Misc.)
ASME B31.3: Process Piping (Section 323, Appendix R on PWHT for hydrogen service)
Couper, J.R., Penney, W.R., Fair, J.R., and Walas, S.M. Chemical Process Equipment Design (2nd ed., Butterworth-Heinemann, 2012) — Chapter on corrosion and materials
Tuttle, R.B., and Jones, R.H. “Mechanisms of Hydrogen Damage in Steels,” Corrosion Mechanisms in Theory and Practice (Dekker, 1986)
Nelson, H.M. “Hydrogen Embrittlement of Steels,” in Metals Handbook, Volume 13, Corrosion (ASM International, 1987)

Last updated: 2026-04-12 | For questions or corrections, contact the Engineering Library maintainer.