99 Diseases of Pressure Equipment: High Temperature Hydrogen Attack (HTHA)

HTHA falls into multiple categories of corrosion mechanisms, including environmentally assisted cracking, hydrogen assisted cracking, and high temperature degradation. Sometimes HTHA is confused with low temperature hydrogen cracking mechanisms that result from hydrogen being driven into steels by aqueous corrosion reactions. But on the contrary, HTHA only occurs with exposure to hydrogen at elevated temperatures (at least 400F / 204C), under dry conditions, when hydrogen disassociates into nascent (atomic) hydrogen, which is then driven into the steel by the temperature and pressure of the environment. That atomic hydrogen then reacts with unstable carbides in steel to form methane gas, which then causes gas pockets to form which leads to fissuring, blistering and cracking. HTHA affects carbon and low alloy steels, but is most commonly found in carbon steel and carbon -1/2 Mo steel that are operating above their corresponding Nelson curve limits. Those curves, plus much more valuable information on HTHA are found in the sixth edition of API RP 941(2). If you are still relying on an older edition, you may need to get an updated copy because this standard has been updated substantially, and most recently to include much better information on inspection techniques.
The three most common reasons for HTHA in service are firstly that older C-1/2Mo equipment designed to previous editions of API 941 may be still operating at too high of a pressure/temperature for the new downward revised limits of exposure for the steel. Several years ago, the industry started to experience HTHA failures with C-1/2Mo steels below their corresponding Nelson curve limit, ie in what was thought to be the “safe zone”. After numerous failures, testing, and data collection, the Nelson curve limit for the C-1/ 2Mo steels was substantially reduced and even eliminated for new construction.

A second reason for experiencing HTHA involves equipment being designed for service at the limits of the various steels for allowable stress as specified by ASME, without due consideration for their limits for exposure to hydrogen at operating temperatures, ie without sufficient advice from a competent materials engineer. And a third reason is that operations may not have a properly specified integrity operating window IOW) established by materials engineers, and may operate equipment at temperatures and pressures that it was not designed to withstand, ie not knowing that

they are damaging the equipment. This can also happen during so called “end of run” conditions when catalyst activity is declining and therefore temperatures and/or pressures may be increasing. HTHA is a time-temperature- pressure function, which basically means the longer that a piece of equipment is exposed to temperatures above it’s resistance limit in a certain hydroprocess environment, the more damage to the steel will accumulate; and the higher the temperature rises above the limit of the steel, the more rapidly the damage will occur. Sometimes damage is isolated to certain areas, e.g. weldments, HAZ, and sometimes it is of a more general nature, ie it’s not entirely predictable where it will occur and it could be scattered throughout the equipment. Typically we look first at the areas which are hotter, which is often near the outlet nozzle of catalytic equipment, or perhaps the hotter inlet nozzle of an exchanger that is cooling the process. We also focus our inspection techniques on welds, which seem to degrade preferentially in many cases.

To avoid HTHA, one need only to choose the right steel to resist the combination of hydrogen partial pressure and temperature, or adjust the operating conditions to stay below the Nelson curve limit for the existing materials of construction. Typically, as we increase the alloy content e.g. Cr content of the steel, in order to stabilize the carbides, the more resistance to HTHA we obtain. Additionally some benefit is obtained from austenitic stainless steel cladding or overlay welding, which is commonly applied to increase the sulfidation resistance of equipment in hot sour hydroprocessing environments.
Inspection techniques for HTHA have improved considerably in recent years. We now use a combination of volumetric and surface techniques. Surface techniques are used for finding advanced stages of HTHA at the surface, ie fissuring and cracking. Our surface techniques include WFMT, MT, and in-situ metallography, e.g. field metallographic replication (FMR). Automated ultrasonic backscatter testing (AUBT), which uses a combination of velocity ratios, frequency dependent backscatter and spectral analysis is used for finding earlier stages of HTHA. And for sizing and detection of fissuring and cracking from HTHA below the surface, we use time of flight diffraction (TOFD).

Do you have the proper IOW’s established for all your equipment operating in hydroprocess service at elevated temperatures, and does your RBI plan include the proper inspection techniques and frequency for equipment that may be exposed to HTHA?