April 2024, Vol. 251, No. 4
Features
Selection of Material for Hydrogen Services
By Ramesh Singh, Engineer
(P&GJ) — Hydrogen is a carbon-free fuel that is being considered to achieve net-zero emission. The use of the existing natural gas transportation pipelines for hydrogen gas is an essential strategy to reduce the investment required for hydrogen distribution.
However, the existing gas transmission pipelines are generally comprised of steels that are susceptible to hydrogen embrittlement (HE). In the majority of situations, the steel used for these pipelines are not suited for hydrogen service and can result in hydrogen leakage, which could cause serious incidents.
This article discusses the hydrogen related problems in pipeline steels, with specific emphasis on hydrogen behaviors, hydrogen embrittlement and related characterizations, and material selection strategies for new construction and conversion of the existing pipelines.
The current practice of burning fossil fuel to meet the increasing demand for energy adds to the greenhouse gasses released in the atmosphere.
A transition from carbon releasing energy sources to carbon-free energy sources is deemed as a solution for alleviating these climate effects, and hydrogen which is a carbon-free energy carrier can play a significant role to facilitate the global decarbonization. As is known and studied, hydrogen as fuel has a higher energy content per mass as compared to fossil fuels.
Cost-efficient hydrogen distribution is essential for establishing an economically feasible hydrogen-fueled society. With high energy, hydrogen is also a very dangerous gas due to its high flammability and explosive nature in the presence of oxygen in atmosphere.
Pipeline transmission is by far the most technologically ready and scalable method, although extra energy and cost is required to operate at pressures that can increase transmission efficiency. By one study, in the U.S. there are more than 300,000 miles of pipeline used for the transportation of gas, and data published by Morris and Baker in 2021 suggest that in the U.S. over 1,600 miles of gas pipe has been constructed and used for the transportation of hydrogen. Some of these 300,000 miles of gas carrying pipelines may be converted to carry hydrogen in future.
The inflammability and explosive properties of the hydrogen brings the quality of steel for transporting gas in focus of the discussion. Generally, the current quality practices are sufficiently suited for the gas transportation purpose. They are technically sound and economically satisfactory.
Steel for the hydrogen transportation pipeline is on very different quality criteria. This is apart from the fact that mid-strength level steel is often prescribed and used for hydrogen transportation. When operating below 1890 psi, these grades often range from API X-42 to X-52 and sometimes even X-56.
The limit on strength of steel, is due to the fact that higher grade of steel is relatively more susceptible to hydrogen embrittlement (HE), the main cause and mode of failure, expected to occur. However, some finer control over steel at the steel making stage, can allow the use of grades as higher in strength as X-65, this would also allow consideration of some safe increase in operating pressure, not reaching, or exceeding the 2,900 psi threshold.
Detrimental to Steel?
Hydrogen is detrimental to steel if it is allowed enter in the steel and cause inter structural pressure, the term used for this type of failure is Hydrogen embrittlement (HE).
This phenomenon occurs when the hydrogen molecule enters in to the voids of steel’s structure and exerts pressure exceeding the steel’s ductility to resist the pressure, thus causing the steel to gradually fail.
The ingress and subsequent solubility of hydrogen in steel occurs in the following three ways:
- Physisorption originates from the van der Waals forces between hydrogen molecule and metal surface.
- Chemisorption involves the dissociation of the hydrogen molecule and the subsequent chemical hydrogen binding onto metal surface. Since hydrogen solution in iron is endothermic, this step is less favorable to steel, than that to other metals that have higher affinity to hydrogen such as titanium, zirconium, vanadium, and magnesium (Sakintuna, et al., 2007; Schlapbach and Züttel, 2001).
- Absorption of hydrogen in pipeline steel (CH) is related to the fugacity (fH) of the hydrogen gas, which is equal to the pressure of the hydrogen, this happens at pressure over 20 MPa or about 2,900 psi.
It should be pointed out that few pipelines operate at or above 20 MPa (2,900 PSI) pressure. But if the diffusible hydrogen solute in the steel microstructure is in sufficient amount, or the operating pressure is high and for a longer period of time to allow for hydrogen diffusion, or the steel has inbuilt voids in the form of inclusions, cracks, etc., then the pipeline can be considered to be susceptible to HE and subsequent failure, even at the lower operating pressure.
Time is an essential factor in HE probability, a long-term service pipe carrying relatively high-pressure hydrogen can meet all of these requirements. The possibility of HE increases with other factors like, if the pipeline steel is of higher strength, or if there is increased residual stress, caused during fabrication and installation practices, or there are stress concentration points in the pipeline, due to poor design, cyclic loading, or due to welds.
This complex relationship of hydrogen with steel and its strength directs us to focus a little more in depth understanding of steel making and available grades in service of hydrogen transportation (Figure 1).
Hydrogen Solubility
With very few exceptions, the pipeline steels generally are constructed out of steel that have body-cantered cubic (BCC) lattice structure, and as per basic calculations by Hickel et al., published in 2014, the interstitial hydrogen solute in such lattice sits at the tetrahedral interstitial sites, called T-site.
This is in contrast with the cases in face-cantered cubic (FCC) alloys where hydrogen solute prefers octahedral interstitial sites called O-site. This difference of interstitial solute site between BCC and FCC lattice leads to the higher hydrogen diffusivity in pure BCC iron, this diffusivity is estimated to be about 10−5 to 10−4 cm2/s.
This is studied by several researchers and published for example, Bryan and Dodge, in 1963; Johnson, in 1988; Nagano, et al., in 1982.
Added to the above established diffusivity, in BCC irons, is the fact that the overall number of T-sites in BCC structure is lower than that of O-sites in FCC structure, due to this lower host sites there is lower solubility of BCC iron than FCC iron.
For example, the solubility at 298-K, for a BCC-based X70 pipeline steel is approximately 1 part per million in weight of hydrogen, this is in contrast hydrogen solubility in an FCC-based (304 austenitic) steel is approximately 100 weight parts per million.
Hydrogen and Steel
It is general practice to use low-grade steel, like API grades X-42 to X-52 for hydrogen service. However if the above description of HE probability is any indicator, the strength of the steel is only one of the other factors that leads to the HE.
It has been studied and proven that the hydrogen absorption and solubility in steel is greater in higher grades of steel with complex microstructure, at ambient temperature.
It is also a fact that the concentration of absorbed hydrogen in pipeline steels (CH) relates to environmental hydrogen pressure, (fugacity = fH). This concentration-fugacity relationship follows Sievert’s law (Mine et al., 2009; San Marchi, et al., 2007):
CH = S √ fH
Where S is the solubility constant related to temperature.
Hydrogen in Traps
In addition to interstitial solution in lattice, hydrogen can be trapped at various microstructural defects (voids) in steels, and the increase of microstructural trapping site significantly increases the amount of soluble hydrogen in the bulk. This is the greatest danger of hydrogen embrittlement, and least focused on in most pipeline design and construction projects.
The voids are also referred as Traps where in a trap in a material is defined by Barrera et. Al. as “irreversible” if it has a strong binding energy to not trap hydrogen firmly throughout the lifetime of a component at a specific temperature of service. For example, a trap has trapping energy over 50 kJ/mol is considered as irreversible at 298-K (Michler and Balogh, 2010).
Trapping energy has been theoretically calculated by Counts et al., in 2010, or experimentally measured by thermal desorption analysis (TDA) or hydrogen permeation test, as reported by Kumnick and Johnson, in 1980.
Steel Selection
In light of the above brief discussions of hydrogen ingress and potential danger to the steel the process of material selection process for the pipeline gets little more complicated than the normal gas pipeline.
The selection of steel grade and type for the hydrogen transportation pipeline is on very different quality criteria. The current practice of using API specified steel grades of X-42 to X-52 is a conservative assumed safe practice.
But it is only an assumed safe practice, as is shown in the discussion above, the absorption and diffusivity of hydrogen in BCC steel is not limited to the strength of the steel alone, though the post absorption likelihood of HE is greater in higher grades of steel the so-called lower strength steels are not immune form HE.
For a new construction projects, the consideration of suitable steel should start from the steel mill, the production of steel itself, where in the inclusion control should be the major factor to consider. Inclusions are the traps (voids) where hydrogen molecules are trapped and in subsequent service and life time exert pressure and influence failure of the steel.
Next to the steel quality, the factor to consider should be the method of making the steel (Figure 2).
It may be noted that the basic structure of pearlite and ferrite is retained in hot rolled and normalized steels up to the API grade of X-65. This group of hot rolled and normalized steel with pearlite and ferrite structured steel, with the control on inclusions, as pointed out above should be of the focus for the selection of pipeline steel.
This additional care could allow the use of API steel grades X-56, X-60, and to some extent in in very carefully considered situation use of X-65 grades of pipe material may also work, but it is suggested that the selection should generally be limited up to X-60 grades.
With due consideration of the factors contributing to the HE of pipeline steel, especially on the quality of steel used for the manufacture of line pipes, and limitations on the design pressure reasonably higher grades of steel can be used for hydrogen transportation pipeline.
For the conversion of the existing pipeline, it is essential that the detailed history of the laid pipeline is obtained and carefully evaluated. It suggested that in conversion projects material should be limited to API grade X-52 at maximum.
Welding
Welding during the pipe making and in field are of consequence to the overall integrity of the pipeline especially in the hydrogen transportation pipeline.
During the pipe making process SAW and HFW the welding process used are low hydrogen.
However, quality control over the SAW flux storage and handling should be of prime concern. HFW process is good for hydrogen control but the post weld normalizing cycles should be carefully reviewed.
During the pipeline construction on site, the use of cellulosic electrode for welding as done in most of the pipelines is not advised, instead it is strongly recommended that low hydrogen process is selected for welding especially for the root and hot passes.
This would eliminate use of SMAW process, and selection of either short circuit transfer technology or cold metal transfer technology welding systems. For root passes, and then use of pGMAW process for welding the rest of the grove thickness.
Unless due to the other stress evaluation it is necessary to conduct an ECA and set different and more stringent criteria, the flaw acceptance criteria given in section IX of the API 1104 should be good practice to follow.
Author: Ramesh Singh is a retired engineer who worked several years in the oil and gas industry in various capacities, and with associations including NACE (now AMP) and the Welding Institute UK.
Comments