With the global community striving to lower greenhouse gas emissions, the energy industry is exploring the use of hydrogen gas in existing pipeline infrastructure as a means to achieving low-carbon goals.
One of U.S. President Joe Biden’s pledges within his first 100 days in office was to put the United States on a path toward reaching net-zero carbon emissions by 2050. Instead of balking at this milestone, stakeholders within the energy industry announced plans that aligned with that goal.
Trade groups like the Interstate Natural Gas Association of American (INGAA) have committed to working together as an industry to reach net-zero greenhouse gas (GHG) emissions from natural gas transmission and storage by 2050. The American Petroleum Institute (API) launched its Climate Action Framework to develop technologies to reduce carbon emissions associated with the production and transportation of petroleum products.
Individual companies across the board have announced environmental stewardship initiatives and projects related to lowering carbon emissions within the energy industry. As the global demand for energy continues to rise, achieving these emissions goals will require a variety of solutions.
One of those solutions is hydrogen, which is an abundant and renewable zero-carbon fuel. A number of groups are researching how to add hydrogen to the energy mix, from production to transportation to storage as a means to “decarbonize” energy. Pipeline operators and utility companies have the potential to capitalize on the so-called “hydrogen revolution” with existing infrastructure that could be adapted to carry hydrogen gas.
Among the organizations involved with these research and development efforts is the Gas Technology Institute (GTI), which earned its first patent on hydrogen in the 1960s. Kristine Wiley is executive director of GTI’s Hydrogen Technology Center, which was established in 2020 to facilitate increased use of hydrogen in an integrated energy system to meet the challenges of decarbonization.
“We have deep roots in hydrogen and fuel cells,” Wiley says. “What we’re doing at GTI is taking a holistic approach to how the industry can enable the use of hydrogen in our energy system. Like our approach to natural gas research, which we cover from well head to burner tip, it’s the same with hydrogen, researching how we make, move and store hydrogen and incorporate it as an energy solution.”
As GTI researches how the industry can decarbonize energy, Wiley says her work with the Hydrogen Technology Center also explores “how we economize hydrogen” for broader use. Creating a low-cost hydrogen solution and integrating that into the energy mix requires broad collaboration from stakeholders, research and development (R&D) organizations, industry and nonprofit entities.
“On the production side, we’re looking at various pathways to producing hydrogen,” Wiley says. “GTI has a rich history with gasification technology and recently spun off SunGas Renewables, a company that uses gasification of biomass feedstocks to produce renewable fuels such as hydrogen.”
The Appeal of Hydrogen Energy
The reason why hydrogen has garnered so much attention within the energy industry is because it is a carbon-free molecule and because of its versatility, Wiley says. Among hydrogen’s greatest features are its ability to store energy for a long period of time over large distances.
“Hydrogen lends itself to large-scale, long-term energy storage, which is important for the integration of wind and solar energy,” Wiley says. “Hydrogen offers many options. There are a variety of conversion processes that can be used to produce hydrogen and many different applications it can be used in.”
An initial application being pursued is using hydrogen for power generation, either by blending it with natural gas or replacing natural gas altogether. However, there are a number of aspects that need to be understood first.
“One of the very attractive features of hydrogen gas is that it can be produced from various feedstocks, such as natural gas, biomass and renewables,” Wiley says. “We’re focused on the best way to utilize hydrogen and what the key end-use applications are. It’s also similar to natural gas in that it can be used in combustion heating and can serve as a feedstock for other chemicals.”
Another piece of the puzzle that needs to be understood is the transportation and delivery of hydrogen gas. While there are about 1,600 miles of existing, dedicated hydrogen pipelines in the United States right now, most of that is in the Gulf Coast. That’s not enough to deliver it to the rest of the country.
“Many discussions around hydrogen are about how we drive down the cost of production or the end-use applications,” Wiley says. “We’re working with pipeline operators and utilities, looking at how to evolve infrastructure and how to leverage existing assets to carry hydrogen gas.”
Some companies are looking to blend hydrogen with natural gas within their current distribution pipeline systems. A handful of companies have launched programs looking at hydrogen blending, such as Southern California Gas Co. (SoCalGas), NW Natural in Oregon and others.
“One thing to note is we’re talking about a very low blend, typically less than 5 percent,” Wiley says. “Looking at the research around hydrogen blending and the impact to pipeline infrastructure, we don’t see a significant impact at low blends. With GTI studies in the past, which looked at plastic pipe, a low blend of hydrogen and natural gas didn’t have any major effects on infrastructure. In order to increase the blend, we need to explore it more with other materials, such as steel, where there are concerns with hydrogen embrittlement.”
To take advantage of existing natural gas pipeline infrastructure to transport hydrogen, Wiley says the industry must better understand the characterization of the entire system, in terms of age, condition and material. In addition to understanding the impacts of hydrogen on different pipeline materials, Wiley adds that the industry must also consider other aspects of operations, such as leak detection and compression.
While the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) requires pipeline operators to conduct leak detection surveys on a regular basis, those processes were developed to detect methane and natural gas. Because hydrogen is a smaller molecule, leaks may occur and different tools may be required to detect them, especially considering that hydrogen has a wider flammability range than natural gas and methane.
“Some studies have shown that for low-pressure distribution pipes, the leak rates are similar between pure natural gas and a blend of natural gas and hydrogen,” Wiley says. “There is also ongoing research on hydrogen permeation.”
Similarly, current pipeline compression facilities systems were designed for natural gas and will require modification to handle hydrogen or a blend of hydrogen and natural gas. There is a current study in Europe looking at the cost to retrofit compressor stations to meet the requirements of hydrogen.
Ongoing Pilot Projects
With the heightened attention on transitioning to a low-carbon future, many energy companies are placing an increasing focus on hydrogen. Companies like SoCalGas, Dominion and Williams have launched pilot projects focused on integrating hydrogen.
In December 2020, SoCalGas announced a program to field test a new technology developed by Netherlands-based HyET Hydrogen that can simultaneously separate and compress hydrogen from a blend of hydrogen and natural gas. At scale, the technology would allow hydrogen to be easily and affordably transported via natural gas pipelines.
The objective of the testing is to get performance data that will enable fine-tuning and optimization of the HyET system so the technology can be scaled up for commercial applications, according to Neil Navin, vice president of clean energy innovations at SoCalGas.
The equipment is undergoing final factory acceptance testing off-site and will be installed at SoCalGas’ Engineering Analysis Center in Pico Rivera, California, in August 2021. Commissioning and testing should take about six weeks once it’s delivered. Within the next two years, the technology is expected to be scaled to produce 100 kg of hydrogen per day or more from a single system.
“A lot of research has been done globally to understand the impacts of hydrogen blending,” Navin says. “The general consensus is that blends of around 10 percent and potentially up to 20 percent are fine for both the system and for use in appliances, manufacturing and other end-uses. However, similar testing needs to be completed in the U.S.”
In terms of when hydrogen energy will become a more widely used source of energy, Navin says that the timing will likely be a matter of cost, which will be reduced with scaling up of investments in green hydrogen. An initiative by the Green Hydrogen Coalition that includes participants such as the Los Angeles Department of Water and Power to use a mix of hydrogen and natural gas in power plants is accelerating adoption of hydrogen energy in California.
Earlier this year, Williams also announced plans to leverage its existing pipeline network to bring hydrogen to market.
“Our nationwide pipeline footprint is well-positioned with end-use demand, particularly in highly populated areas, to participate in hydrogen-based energy storage and transport,” said Brian Hlavinka, director of business development for the renewables group at Williams. “Our ability to blend hydrogen into our existing system is a significant advantage and has the potential to accelerate the use of hydrogen in reducing carbon emissions.”
Tags: July August 2021 Print Issue
Bradley Kramer is managing editor of North American Oil & Gas Pipelines. Contact him at firstname.lastname@example.org.