The U.S. Chemical Safety Board (CSB) issued a safety alert on Preventing High Temperature Hydrogen Attack (HTHA) in August, 2016 in relation to a catastrophic failure that occurred in a 40 year old heat exchanger due to HTHA. The CSB warned that predicting and identifying equipment damage due to HTHA is complex, and made the following recommendations:
- Identify all carbon steel equipment in hydrogen service that has the potential to harm workers or communities due to catastrophic failure;
- Verify actual operating conditions (hydrogen partial pressure and temperature) for the identified carbon steel equipment;
- Replace carbon steel process equipment that operates above 400°F and greater than 50 psia hydrogen partial pressure; and
- Use inherently safer materials, such as steels with higher chromium and molybdenum content.
This article focuses on item (2) above and discusses gathering and verifying process data to determine susceptibility to HTHA.
HTHA Damage Concerns
HTHA occurs from prolonged exposure to hydrogen at elevated temperature and pressure when molecular hydrogen dissociates to form atomic hydrogen which reacts with unstable carbides present in steel to form methane. HTHA can result in the following types of damage:
- Surface decarburization: occurs when the reaction occurs primarily at the steel surface and results in slight localized reduction in strength and hardness along with an increase in ductility.
- Internal decarburization: occurs when the methane formed cannot diffuse out of the steel and accumulates within the steel (typically at grain boundaries and locations of non-metallic inclusions or laminations). The methane pressure builds up and results in high localized stresses that lead to the formation of fissures, cracks, or blisters. Internal decarburization is much more of a concern than surface decarburization since it can result in a significant deterioration of mechanical properties and reduce the load carrying ability, leading to failure of the pressure containing equipment.
One of the main concerns with HTHA is that it can be very difficult to detect the location and extent of damage due to limitations with NDE methods, particularly during the initial stages.
HTHA Susceptibility and Screening Criteria
The API RP 941 Nelson Curves, which plot the operating temperature vs hydrogen partial pressure for several different materials, are typically used to determine whether an asset is susceptible to HTHA. The curves are based on a combination of empirical data and industry experience accumulated since the 1940's and indicate whether the operating conditions fall into a safe or unsafe region for HTHA damage to occur. Since temperature and hydrogen partial pressure data were not always precisely known and due to the uncertainty of actual operating conditions experienced over many decades of operation for data points on the Nelson curves, API RP 941 recommends operating companies add a safety margin when using the curves.
Gathering adequate process data to determine HTHA susceptibility is sometimes a difficult and time consuming task. Therefore a simple screening can be performed to determine if more detailed process data is required. If all of the below criteria are met, a more detailed review of the process data is required to determine the HTHA susceptibility and potential for damage (e.g. high, medium, low):
- Hydrogen partial pressure > 50 psia,
- Operating temperature is > 400°F, and
- Operating conditions fall within the criteria listed in the below table:
|Material||Operating Conditions for HTHA Service (Note 1)|
|CS||Above the relevant CS Nelson curve or within 50°F / 50 psia below the curve|
|C-0.5Mo||Above the CS Nelson curve|
|1.0 Cr||Above the 1.0 Cr Nelson curve or within 50°F below the curve|
|1.25 Cr – actual Cr content unknown ||Above the 1Cr Nelson curve |
|1.25 Cr – actual Cr content known and > 1.2% (Note 2)||Above the 1.25% Cr Nelson curve or within 50°F below the curve|
|All other steels||Above the appropriate Nelson curve or within 50°F below the curve|
|Note 1: operating temperatures for screening include normal, offset, upset, startup, shutdown, etc.|
Note 2: chemical composition information may be available in material test reports
If the operating conditions fall within the above screening criteria, further evaluation of the data is required including the length of time the equipment was operating in the HTHA susceptibility region and the severity of the operating conditions.
Since temperature is a key variable in determining HTHA susceptibility, information on temperature should be collected with knowledge on where the data comes from in order to ascertain the accuracy of the values reported. For example, information taken from direct measurements using thermocouples is likely to be more accurate than that taken using an IR gun, process simulations, or extrapolated based on measurements taken at other locations. If process simulations were used, it is important to confirm that the degree of fouling was accurately modeled. Failure to do so can provide inaccurate temperature data which can lead to a false assessment of the HTHA potential. Below are some additional guidelines on providing temperature data:
- In general, sustained high temperatures may be used; however if a more detailed analysis is required due to significantly varying conditions, a review of the distributed control system (DCS) data may be required
- For reactors, use worst case temperatures (e.g. at end of run)
- For heat exchangers, collect inlet and outlet temperatures
- For fired heaters, collect process outlet temperature and maximum tube metal temperature
- For refractory lined equipment, obtain process temperature and skin temperatures
- For piping branch and bypass lines, use the worst case temperature based on flow or no flow conditions
- If offset or upset conditions apply, include the amount of time at the temperature
Hydrogen Partial Pressure
Gathering information on the amount of hydrogen present at any given location within a process unit is often a complex task and typically needs to be performed taking into consideration a combination of factors including the location of hydrogen probes, extent of reaction, material balance or process simulations, along with information on whether the hydrogen is in vapor phase or dissolved in liquid. Since the amount of hydrogen present can vary along the run length, it is recommended to use sustained high values for the first pass.
Determining the H2PP for components having a vapor phase is a much more straightforward process than for equipment where only a liquid phase exists. For equipment having a vapor phase, the below formulas can be used to calculate the H2PP once the amount of hydrogen present is determined:
H2PP=(moles hydrogen / total moles in stream) * total pressure (psia)
H2PP=(volume hydrogen / total volume of stream) * total pressure (psia)
The H2PP for liquid filled systems where no vapor phase exists can be estimated by following the guidelines provided in Appendix G of the latest edition of API RP 941. Appendix G provides five different methods for determining the H2PP. Detailed discussion of these methods is outside the scope of this blog, however Appendix G essentially recommends using the H2PP of the vapor that was last in equilibrium with the liquid or using the calculated H2PP that would be in equilibrium with the liquid at its operating temperature and pressure.
HTHA is a time dependent mechanism that occurs from prolonged exposure to hydrogen at elevated temperature and pressure. Due to the variability in operating conditions that can occur over the lifetime of an asset, along with the difficulty in obtaining H2PP data, collecting process data for determining HTHA susceptibility is often a complicated task. A screening process can be used to determine whether a more detailed data collection effort is required. This blog provides guidelines for performing a screening to determine if process conditions place an equipment at risk for HTHA. It also provides guidelines on how to gather more accurate temperature and H2PP to determine the potential for HTHA.
Stay tuned for the next entry in this eight-part series covering guidelines on assigning process conditions for RBI efforts:
- Guidelines for Providing Process Conditions for Risk Based Inspection (RBI) Implementation and Revalidation (Introduction)
- Corrosion Under Insulation (CUI) and How it Relates to Risk Based Inspection
- Process Fluids and Consequence Models
- High Temperature Damage Mechanisms
- Low Temperature Damage Mechanisms
- High Temperature Hydrogen Attack (this article)
- Environmental Cracking Damage Mechanisms
- Concluding Remarks
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