Natural gas is an essential energy source. It provides instant and efficient heat for families and businesses, while providing a means for electricity generation and industry development throughout the U.S. One of the most significant challenges facing the natural gas industry is decarbonization. With the passage of state bills in California and Hawaii mandating 100% carbon-free electricity by 2045, and Massachusetts, New Jersey, New York and Washington, DC also considering similar legislation, the pressure on the industry to decarbonize has never been greater.

This article examines several key reports and studies focused on hydrogen. The literature referenced describes how hydrogen is generated, its interchangeability with natural gas and how it blends with natural gas. Also discussed is hydrogen’s properties, how hydrogen affects residential and industrial equipment, how blending hydrogen in pipelines affects greenhouse gas (GHG) emissions and its costs. The article also reports on the recent partnership between Gas Technology Institute (GTI) and Electric Power Research Institute (EPRI).

Hydrogen generation

Power-to-gas, electrolysis, methane pyrolysis, steam methane reforming (SMR) and biological processes are among the common hydrogen generation methods. Power-to-gas is the conversion of electrical energy into chemical energy in the form of hydrogen and/or methane. The process uses water electrolysis, often powered by renewable energy sources, to split water molecules to produce hydrogen and oxygen. It takes about 2 gallons of water to produce enough hydrogen to power a single home. That’s less than a single toilet flush. Jack Brouwer at University of California, Irvine calculated that 2% of the water delivered to Los Angeles by the aqueduct would produce enough hydrogen to fuel every vehicle in California.

With electrolysis, the electrolyzer can be a central component of Power-to-Gas strategies, as it enables the conversion of electrical energy into chemical energy contained in hydrogen through the electrolysis of water molecules. The three dominant technologies are alkaline, proton exchange membrane and solid oxide electrolyzer cell.

Methane pyrolysis converts natural gas to hydrogen and solid carbon. No CO₂ is produced or released. The solid carbon can be used to make tires black, or it might have applications in electronics, building materials or road fill. Anything that keeps the carbon out of the air means the hydrogen produced has zero carbon emissions.

The most common process is steam methane reforming in which natural gas is converted to hydrogen and carbon dioxide in the presence of steam and a catalyst. More than 95% of the world’s hydrogen is produced using the SMR process. In this reaction, natural gas is reacted with steam at an elevated temperature to produce carbon monoxide and hydrogen. A subsequent reaction — the water gas shift reaction — then reacts additional steam with the carbon monoxide to produce additional hydrogen and carbon dioxide.

Another process is gasification, which converts biomass, coal, natural gas or waxes into a synthesis gas. This gas is primarily composed of hydrogen and carbon monoxide, but also may contain smaller amounts of methane, ethane, propane, ash and tars. “In-well gasification” converts oil and gas inside a well (maybe an old, depleted well that doesn’t produce much anymore but still contains hydrocarbons) into hydrogen and CO₂. The hydrogen floats to the top for extraction; the CO₂ stays in the well. Again, produces zero carbon hydrogen from fossil fuels.

Biological processes that produce hydrogen do exist, though the path to commercialization and market viability is much longer than the previously mentioned paths. Bacteria and microalgae can produce hydrogen through biological reactions using sunlight or organic matter as a feedstock. These technology pathways are at an early stage of research, but in the long term have the potential for sustainable, low-carbon hydrogen production.

Hydrogen and natural gas interchangeability

Blending hydrogen into the existing natural gas pipeline network has been proposed as a means of increasing the output of renewable energy systems. If implemented with relatively low concentrations — up to 5% hydrogen by volume — storing and delivering renewable energy to markets appears to be viable without significantly increasing risks associated with utilization of the blended gas in end-use equipment, overall public safety or the durability and integrity of the existing natural gas pipeline network. However, the appropriate blend concentration should be assessed on a case-by-case basis.

The consequences of mixing hydrogen with natural gas throughout the North American natural gas distribution system is important for maintaining a safe and reliable network. GTI is looking at the impact of hydrogen blends on this and on end use equipment. This work assesses the corrosion and hydrogen embrittlement mechanisms associated with adding hydrogen to natural gas.

GTI has completed hydrogen blend studies for a consortium of natural gas operators as well as the U.S. National Renewable Energy Laboratory. These projects focused on the life cycle assessment of hydrogen blending as well as the safety, leakage, durability, integrity, end use and environmental impacts. Following this study, GTI conducted an evaluation of the effects of hydrogen blending in natural gas on nonmetallic material properties and operational safety through laboratory testing (see Figure 1). This work assessed the material integrity and operational compatibility of a bounded natural gas pipeline system and its components with a 5% hydrogen-blended fuel to help determine if any system upgrades might be necessary to reduce risk and support gas interchangeability. The level of effects on uncalibrated equipment will need further investigation, and those who may operate equipment or appliances that are uncalibrated should be notified and potentially assisted through an upgrade or recalibration prior to any hydrogen blending program. Equipment with operating characteristics that are sensitive to varying hydrogen concentration will need additional study on a case-by-case basis, as a number of these combustion systems may be sensitive to small changes in gas properties. It also identified future research needs when considering gas interchangeability with blends that contain greater than 5% hydrogen.

The most common index when considering interchangeability is the Wobbe Number. Wobbe Number accounts for variations in the heating value of a fuel gas by normalizing the heating value of a fuel gas over the area of a burner orifice. The Wobbe Number of a fuel gas is defined as the heating value divided by the square root of the specific gravity. Many gas specifications use Wobbe Number as a key parameter. Wobbe Number is considered superior to heating value as an index for interchangeability determination, but a single number is insufficient for assessing interchangeability since it does not address attributes such as flame speed, lift or characteristics that can contribute to incomplete combustion.

Properties of hydrogen

The most important combustion properties in terms of the differences between hydrogen and methane combustion are calorific value, Wobbe Number, flammability range and flame speed. The calorific value of hydrogen on a volumetric basis is a third of that of natural gas primarily due to its low relative density. However, in terms of combustion, the Wobbe Number provides the most appropriate indicator of gas interchangeability. The Wobbe Numbers of hydrogen and methane are much closer together than the volumetric calorific value. The blend could be in the 15% range before the Wobbe Number of the blend dips blow acceptable limits for most equipment. The flammable range of hydrogen is 4% to 75% by volume. The flammable range of methane at 4.4% to 17% by volume. This can be calculated for methane-hydrogen mixtures (see Figure 2). However, the flammability of hydrogen is higher than methane, which could be a safety concern. But its diffusivity also is much higher, which means that hydrogen wafts away quickly.

Hydrogen is flammable when mixed even in small amounts with air. Ignition can occur at a volumetric ratio of hydrogen to air as low as 4% due to the oxygen in the air and the simplicity and chemical properties of the reaction. However, hydrogen has no rating for innate hazard for reactivity or toxicity. The storage and use of hydrogen poses unique challenges due to its ease of leaking as a gaseous fuel, low-energy ignition, wide range of combustible fuel-air mixtures, buoyancy and its ability to embrittle metals that must be accounted for to ensure safe operation. Liquid hydrogen poses additional challenges due to its increased density and the extremely low temperatures needed to keep it in liquid form.

How hydrogen affects industrial equipment

End use equipment burning natural gas can be divided into three broad categories:

• Residential and commercial appliances
• Industrial burners equipment
• Stationary engines and turbines.

Residential and commercial appliances. Residential and commercial appliances as a class of combustion equipment are designed to operate with little monitoring by consumers. They are manufactured by many companies, can vary in burner configuration and can have a long service life. This means appliance burners have the potential to be out of tune. When gas composition is changed, out-of-tune appliances are of the most concern. Older water heaters and furnaces are at higher risk of operating out of manufacturer specifications. Changing natural gas by adding hydrogen has the potential to lower flame temperature, decrease heat transfer rates and increase CO emissions. SoCalGas is working with University of California, Irvine to explore the feasibility and cost of retrofitting residential appliances for higher hydrogen blends. If an inexpensive component like a burner orifice could be replaced, it might make higher blends of hydrogen easy to achieve.

Industrial burners. Unlike residential appliance burners, industrial burners cover a wide combustion range and much wider range of firing rates. There is a lot of opportunity in industrial applications. These are processes that are hard or impossible to electrify. Hydrogen could be a good way to decarbonize them. Industrial equipment typically is attended and is managed by control systems. The indices developed for appliance burners are not well suited for industrial burners. Instead, approaches have been developed to determine the most sensitive industrial burners and to make needed adjustments of these burners based on changes in the fuel gas composition. According to “Literature Review: Hydrogen Impact on End-Use Equipment, Infrastructure and Safety,” published by GTI, two methods can be used to characterize industrial burners. The first, burner operating mode characterization groups burners by fuel type, oxidizer type, draft type, mixing type, heating type and control type. This classification approach provides guidance in identification of the burners most sensitive to fuel gas composition changes. The addition of hydrogen will lower heating value and Wobbe Number. However, these effects could be overcome by making an airflow adjustment or using a different burner nozzle.

Power turbines and large stationary engines. Turbines operate at the highest practical temperature to achieve the greatest possible efficiency. These units are sensitive to material degradation and thermal damage, according to the GTI report. Adjustments are made when fuel gas is changed to prevent material and thermal harm. These adjustments are often made when the natural gas supply changes. Hydrogen is particularly problematic for turbines because flame speeds and flame lengths change with hydrogen addition. Hydrogen also can attack metal blades at high temperatures. Turbine operators typically specify low hydrogen limits in the fuel gas to safeguard their equipment. The addition of hydrogen requires study of the impact of the hydrogen and the concentration of hydrogen on the turbine, according to the GTI review. However, manufacturers are now building turbines that can handle hydrogen blends (see “LADWP embarks on hydrogen generation project”)

Stationary engines also are sensitive to fuel gas changes. However, their operating conditions are less severe than that turbine conditions. This makes large engines more tolerant of fuel gas changes. The addition of hydrogen can affect engine performance. Engine operators must be informed when hydrogen is added to the fuel gas so tunings can be changed.

Blending hydrogen with natural gas does have an impact on industrial equipment, but the studies are not conclusive. It depends on the amount of hydrogen and the content of the blend.

How blending hydrogen in pipelines affects emissions

GHG effects of blending hydrogen into natural gas supplies depend on the source of the hydrogen used in the blending strategy. The amount of benefit can be quantified in terms of a carbon intensity in grams of CO₂ emitted per megajoule of potential energy. Each unique source will have a unique carbon intensity value. The carbon intensity of the hydrogen fuel can be combined with the carbon intensity of the natural gas fuel on a weighted average basis, according to the GTI report.

A report titled “Pathways for Deep Decarbonization in California,” published in May 2019 by Energy Futures Initiative (EFI), was produced to define the existing California clean energy landscape and recommend steps for accelerating the move to meet the state’s carbon reduction goals by midcentury. According to the EFI report, there are several opportunities for reducing GHG emissions in the industry sector through fuel switching: fuel switching from fossil fuels to electrification or hydrogen, substituting gas or renewable natural gas (RNG) for coal and substituting gas or RNG for petroleum.

In cases where electrification and energy efficiency cannot lead to measurable emissions reductions, hydrogen can offer a clean-burning substitute. Certain processes require combustion-based heat because the fuel meets a specific heating need and provides components important to the chemistry of the process, according to the EFI report. Where industrial end-use systems permit, hydrogen may be blended with natural gas to reduce the emissions intensity of methane.

Cost

A report from the Hydrogen Council shows that the cost of hydrogen solutions will fall sharply within the next decade, and sooner than previously expected. As scale up of hydrogen production, distribution, equipment and component manufacturing continues, cost is projected to decrease by up to 50% by 2030 for a wide range of applications, making hydrogen competitive with other low-carbon alternatives and, in some cases, even conventional options, according to the Hydrogen Council report.

Significant cost reductions are expected across different hydrogen applications. For more than 20 of them, such as long-distance and heavy-duty transportation, industrial heating and heavy industry feedstock, which together comprise roughly 15% of global energy consumption, the hydrogen route appears the decarbonization option of choice, the report said.

The report attributes this trajectory to scale-up that positively impacts the three main cost drivers:

• Strong fall in the cost of producing low-carbon and renewable hydrogen
• Lower distribution and refueling costs thanks to higher load utilization and scale effect on infrastructure utilization
• Dramatic drop in the cost of components for end-use equipment under scaling up of manufacturing.

Because of hydrogen’s impact on and value as a renewable fuel, it has zero GHG footprint (depending on the source of the hydrogen used in the blending strategy), it can be blended with natural gas and it can be stored in the natural gas infrastructure.

The benefits of scaling up the hydrogen economy extend beyond its head-to-head cost competitiveness. Hydrogen can support governments’ energy security goals, and its relative abundance creates opportunities for new players to emerge in energy supply and for new job creation to stimulate the global economy. Hydrogen remains the only viable, scalable option to decarbonize industry and other segments that have struggled to minimize their environmental impact.

EPRI and GTI partnership

GTI has recently begun an unprecedented partnership with EPRI in what GTI is calling the “Low-Carbon Resources Initiative (LCRI).” It is a five-year, collaborative effort supported by major electric and gas utilities to advance the technologies needed for deep decarbonization within the next decade so they can be deployed in the 2030 to 2050 timeframe.

Both GTI and EPRI recognize that breakthrough technologies across the full energy value chain will be required to achieve decarbonization goals, and the organizations see opportunities to combine and leverage resources across the utility industry for the greater good. The effort will improve the strength, efficiency and resiliency of the U.S. energy grid and reduce impact on the environment. In addition, accelerating hydrogen successes will be a major emphasis in their work together under the LCRI.

EPRI provides thought leadership, industry expertise and collaborative value to help the electricity sector identify issues, technology gaps and broader needs that can be addressed through effective research and development programs for the benefit of society. GTI is the leading research, development and training organization addressing energy and environmental challenges to enable a secure, abundant and affordable energy future. For more than 75 years, GTI has been providing economic value to the natural gas industry and energy markets by developing technology-based solutions for industry, government and consumers.

LADWP embarks on hydrogen generation project

The Los Angeles Department of Water and Power (LADWP) is embarking on a groundbreaking hydrogen generation project, said an article from the American Public Power Association.

The article said that LADWP plans to phase out 1,800 MW, coal-fueled generation at the Intermountain Power Project (IPP), which it participates in with electric power cooperatives and other public power utilities in California, Nevada and Utah, and replace it with natural gas-fueled generation that would eventually be fueled entirely by hydrogen. In addition to generation, the IPP also includes two large transmission systems that move power throughout the region and to Southern California.

The motivation for the decision for LADWP to shut down the coal facility and replace it with another generation source was the city’s adoption of a target to be powered by 55% renewable energy by 2025 and be powered 80% by renewable energy by 2036. In addition, Los Angeles, like the rest of California, faces a target of being powered 100% by clean energy by 2045.

“If you look at reality, there is no way to get to 100% renewable energy without hydrogen in the mix; it just doesn’t exist,” Marty Adams, LADWP’s General Manager and Chief Engineer, told the utility’s board of commissioners this month.

There are two main factors driving the decision to stay with a fossil fueled plant, according to the American Public Power Association article. One is the need to have a generation source that can integrate increasing amounts of renewable energy into the grid; the other is the need for “a dispatchable rotating mass” to support a 500 kV high voltage direct current (HV dc) line that runs from the plant and provides Southern California with 2,400 MW of capacity, Paul Schultz, LADWP’s director of Power External Energy Resources, said.

In addition to generation from the IPP, the HV dc line also serves as a conduit to move renewable energy to California load centers. It currently connects with about 400 MW of wind power, but it could serve as a renewable energy hub in the future. There are already 2,300 MW of solar interconnection requests in the queue, and LADWP is in discussions with entities to bring as much as 1,500 MW of wind power from Wyoming.

Intermountain’s role as a renewable energy hub, and its unique location, are central to the plan to convert the plant to burn hydrogen. The hydrogen to fuel the plant would have to be manufactured through electrolysis, a process where water is separated into its two constituents, hydrogen and oxygen. The process would be powered by renewable energy provided through Intermountain’s transmission systems. Running that process using renewable energy helps reduce the overall emission profile of the repowering project. It could also help with the economics of the project as renewable power that might otherwise be curtailed.

Burning hydrogen does produce nitrogen oxide, but it does not produce carbon dioxide. The generator’s heat recovery steam generator would be sized to increase air flow and help reduce emissions from the plant, Schultz said. LADWP also is discussing carbon capture technologies with several vendors. LADWP says that based on technology of the turbine manufacturers, the generators are expected to have the capability of burning a fuel mixture of 30% hydrogen when it begins operating in 2025.

In all, the total cost of the project, the generation and HV dc converters is $1.9 billion, Schultz said. The hydrogen conversion equipment would be a separate cost. LADWP is exploring “working with partnerships” to that portion of the project and is not yet ready to go public with a cost estimate, Schultz said. One possibility would be to secure funding through a Department of Energy grant, he said.

Converting the generation equipment to gradually increase the hydrogen burning capacity would be an “incremental capital cost” and could be coordinated with regular turbine maintenance schedules, Schultz said.

Further out, LADWP is also looking at the potential at the IPP site to store hydrogen. The plant is located on top of a large geologic salt dome, the only one in the Western U.S. A single cavern at the site could store hydrogen equivalent to 84 times as much energy as a 1,200 MWh battery system and store that energy for months at a time. The site has the potential for 100 caverns, LADWP said.

Storing hydrogen at the Intermountain site would allow for “seasonal shifting” that could provide arbitrage opportunities to defray the costs of hydrogen production, by manufacturing hydrogen when energy prices are low and using it to generate power when prices are high. The utility also is looking at the caverns to support a 160-MW compressed air energy storage generating plant.

The current energy-in, energy-out roundtrip efficiency of the renewable hydrogen process is about 30% to 35%, Schultz said, but noted that calculation does not take into account other factors such as the policy mandates the utility must comply with and other potential costs such as the potential for forced renewable energy curtailments.

“We are very excited about the opportunity to take a leadership role with this project,” Schultz said. When completed, the project would be the largest commercial scale hydrogen generating plant in the world.

Final thoughts

Because decarbonization is inevitable, the natural gas industry must take another look at how to achieve the goals within the 2030 to 2050 timeframe. Electrification and RNG are only part of the answer. Blending hydrogen into the existing natural gas pipeline network shows promise toward reducing GHG emissions.

Hydrogen is easily generated. Its interchangeability with natural gas is predictable. It can be blended with natural gas with little effect on equipment and pipelines and can significantly reduce GHG emissions. In addition, cost is expected to decrease over the next decade.

– This article appeared in the Gas Technology supplement.

MORE info

ENERGY FUTURES INITIATIVE (EFI)

ENERGY SOLUTIONS CENTER

GAS TECHNOLOGY INSTITUTE

HYDROGEN COUNCIL

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