Head Off Hydrogen Hazards

Proper material selection and piping design are crucial

By Dirk Willard, Contributing Editor

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Increased reliance by refineries on heavy crude has led to greater use of hydrogen. This, in turn, has resulted in a rise in accidents related to hydrogen-based unit operations. For instance, on April 2, 2010, seven workers were killed when an exchanger in the naphtha hydrotreater unit at Tesoro’s Anacortes Refinery in Anacortes, Wash., ruptured, releasing naphtha and hydrogen that exploded. High-temperature hydrogen attack (HTHA) was blamed for the accident. A fire that occurred on October 6, 2011, at the Co-op Refinery complex in Regina, Saskatchewan, due to a 7.5-in. rupture in a pipe containing H2 and H2S, injured seven workers. Authorities fingered corrosion as the cause. What’s particularly scary is that this section of pipe recently had passed inspection.

What is particularly scary is that this section of pipe recently passed inspection.


These and other incidents are spurring engineers to develop stringent controls on pipe and equipment used in H2 service. So, let’s look at some best practices. (A later column will consider commissioning.)

For hydrogen pipelines and process operations involving low-to-moderate pressures and temperatures, the main risk is hydrogen embrittlement or hydrogen-assisted stress corrosion cracking. HTHA is the predominant danger at temperatures above 250°F. (Some sources say HTHA begins at 400°F.) In HTHA, methane forms at interfaces where carbon accumulates: 8H + C + Fe3C = 2CH4 + 3Fe. Each form of attack creates hardening and stress concentration that promote metal damage. Stress corrosion cracking is a symptom not a cause.

The risk of failure increases with hardening caused by: 1) welds that are several times harder than parent metal; 2) welding that disturbs the microstructure of the virgin metal, thereby promoting H2 access; 3) cold working that creates fine cracks, allowing H2 access; and 4) the presence of H2S, which can cause blisters as hydrogen accumulates in metal (Fe0 + H2S ⇌ FeS + H2). It’s important to differentiate between pipe and equipment handling sour steams, i.e., ones with high H2S, and those with low H2S.

API 5L X52, ANSI 310 and other low-strength steels have been used in ambient H2-only pipeline applications. A useful guide for carbon steels, strictly in hydrogen service, is the Nelson diagram in API-941.

HTHA is a problem in high-pressure, high-temperature, low-H2S applications, such as hydrotreaters and even high-pressure boilers. Nickel-iron-chromium (~22%) alloys work well in such conditions (e.g., <1,500 psig, 750°F, trace H2S typical in a hydrotreater furnace). Stainless steels also are options. Austenitic (stainless) steels, containing >5% chromium, tie up carbon effectively; hydrogen diffuses more slowly in austenitic than in ferritic (carbon) steels. Type 316L sometimes is recommended for temperatures exceeding 250°F. However, it isn’t suggested for high-pressure applications because its allowable strength decreases by 19% from 300°F to 1,000°F.

Type 316L and even 304L stainless steels get chosen for low-to-moderate temperature, low-to-moderate pressure applications; type 304L is far less resistant to cold-working damage. (By the way, duplex stainless steels often are considered resistant to stress corrosion cracking but do suffer such damage in some situations. See: “Know the Limits of Duplex Stainless Steels.")

What material should be used in high-pressure, high-temperature, high-H2S applications? Austenitic stainless steels are preferred in hydrotreating and hydrocracking services: ANSI types 304, 321 and 347 have been used in cladding or weld overlays for furnace coils operated up to 3,000 psig and 850°F; type 347 generally is considered the best choice. Washing in weak base (ammonia) is required during hydrotreater shutdowns to avoid polythionic acid intergranular cracking.

Now, consider the following general design criteria for H2 pipe: 1) threaded joints are unacceptable; 2) gaskets at the few raised-face flanges should consist of two soft deformable seals surrounding a serrated solid metal ring, i.e., a ring-type joint, or metal/metal for pressures exceeding 100 psig; 3) hard metal gaskets are necessary — for fire risk and because soft metals like copper and materials like graphite are permeable to H2; 4) butt-welds should be used (socket welds concentrate loads at sharp edges); 5) choose seamless carbon steel pipe, like API 5L and ANSI 310, where applicable, or electric-fusion-welded pipe for diameters of 16 in. and above, and mandate post-weld heat treatment as well as full x-ray inspection of all welds; 6) valves should employ bellow stem seals and be of a rounded bonnet-and-crotch design to avoid stress concentrations; 7) avoid gate valves and checks as they generally aren’t useful; and 8) specify a minimum flange rating of 300 ANSI for all pipe, and go one ANSI rating above design pressure when it exceeds 300 psi.
For additional information read “Hydrogen Piping Experience in Chevron Refining,” “Tutorial: Hydrogen Damage,” “Hydrogen Transportation Pipelines,”  “The Role of Stainless Steels in Petroleum Refining,”  “Stress Corrosion Cracking: Case Studies in Refinery Equipment.”


dirk.jpgDIRK WILLARD is a Chemical Processing contributing editor. He recently won recognition for his Field Notes column from the ASBPE. Chemical Processing is proud to have him on board. You can e-mail him at dwillard@putman.net

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