Researchers are still evaluating the net environmental impacts of some hydrogen production pathways (like blue hydrogen) as these technologies develop. Additionally, continued evaluation of the benefits afforded by hydrogen compared to natural gas and other fuels on a life cycle basis will be important in providing a range of options to achieve overall decarbonization goals.
While we produce comparatively little green hydrogen today, the technology has tremendous potential as a sustainable energy source across broad geographic areas and in multiple industries. A future powered by hydrogen produced with a low-to-no carbon footprint could go a long way towards achieving the goals of the Paris Accords. With the spotlight on hydrogen now, a key question is how can we effectively transition our current energy infrastructure to maximize hydrogen’s potential?
Hydrogen’s vast integration potential
Regardless of color, hydrogen’s characteristics lend themselves well to integration with existing energy infrastructure, from natural gas pipelines and household appliances to vehicles and power generation. In some applications, hydrogen presents a “no regrets” option for owners of gas assets who might otherwise face few alternatives but asset retirement in a zero-carbon future.
How natural gas pipelines can carry hydrogen
One of the main advantages of hydrogen is its compatibility with existing natural gas infrastructure and end-use applications. Hydrogen is an energy carrier whose gaseous-state properties facilitate integration with pipelines, tank and salt cavern storage, and gas combustion technologies. This overlap can extend the useful life of existing natural gas assets, which is particularly valuable in regulatory environments with deep decarbonization goals. While pure hydrogen creates some undeniable challenges, a moderate amount of hydrogen can be integrated into the natural gas transportation and distribution system with relative ease. Further, hydrogen can be combined with carbon dioxide to create natural gas through methanation, essentially reversing the SMR process and directly replacing conventional natural gas. Leveraging biogenic carbon resources with blue or green hydrogen could significantly expand clean fuel supplies flowing through natural gas pipelines, effectively growing the renewable natural gas supply.
Hydrogen in end-use equipment
There are four ways to use hydrogen in conjunction with or in lieu of natural gas: 1) blending directly with methane, 2) leveraging hydrogen as a methanation feedstock for cleaner natural gas, 3) converting natural gas infrastructure to be able to use 100% hydrogen, or 4) creating new dedicated hydrogen equipment—and each of these four options has varying applications.
Power and building applications
In the power sector, hydrogen can directly generate electricity, a key application for the fuel. Using high hydrogen blends in refinery power systems is already a well-established practice. Turbines in the future could run on 100% hydrogen, as could smaller gas appliances. Maintaining turbines as a generation option in the future allows for a reliable, long-duration power supply. Hydrogen production and storage can utilize otherwise curtailed renewable electricity through electrolysis and build reserves of dispatchable renewable energy. Researchers have explored converting existing home cooking and heating natural gas appliances to run on natural gas-hydrogen blends or pure hydrogen.
Transportation is likewise a significant opportunity for the hydrogen market. In the near term, diesel vehicles can be retrofit to accommodate hydrogen blends. Alternatively, hydrogen can operate in dedicated hydrogen vehicles. Like conventional gasoline, diesel, and natural gas, compressed gaseous hydrogen can be stored in a vehicle fuel tank, and a hydrogen vehicle can replenish its fuel supply at a dispensing station in a matter of minutes (rather than battery electric vehicles that can take 30+ minutes for partial change and hours to fully charge). Instead of burning in an internal combustion engine, hydrogen can be converted to electricity within a fuel cell in the vehicle. The resulting electricity propels the vehicle forward using electric motors. This highly efficient configuration is known as a Fuel Cell Electric Vehicle (FCEV). The Toyota Mirai, the Honda Clarity, and the Hyundai Nexo are all examples of early passenger FCEVs.
Heavy-duty vehicle operators have also begun to take notice and consider hydrogen a viable fuel for long-haul transport due to its high energy density, especially when compared to battery electric vehicles. In a decarbonizing economy, FCEVs are well suited to moving heavy payloads and long-haul transport, with faster fill times, compact fuel tanks, and the ability to hold more load—all areas where current battery technology hamstrings electric vehicles. Recent regulations such as California’s Advanced Clean Truck rule may even accelerate the development of this emerging vehicle class.
Hydrogen blending and conversion projects underway
Hydrogen blending in natural gas pipelines:
- Hawaii Gas runs up to 15% hydrogen (by volume) through its distribution system.
Power generation from hydrogen:
- New York Power Authority pilot project to blend green hydrogen into natural gas flows at the Brentwood Power Station on Long Island, scheduled for fall 2021.
- Intermountain Power Project’s transition from coal to 840 MW of hydrogen-compatible (30% blend initially, 100% by 2045) natural gas electricity generation with onsite green hydrogen production and salt cavern storage.
- Mitsubishi Hitachi Power Systems + Netherlands Carbon-Free Gas Power project plans to convert a 440 MW unit at Vattenfall’s 1.32-GW Magnum combined cycle plant to 100% renewable hydrogen by 2023.
Piloting residential hydrogen appliances:
- SoCalGas’s H2 Hydrogen Home will demonstrate onsite green hydrogen production to generate electricity via a fuel cell and blend with natural gas in the home’s gas appliances by late 2021.
The technical limits to hydrogen integration
Hydrogen presents an opportunity to position natural gas infrastructure as a network for low- and zero-carbon energy supplies. Yet, there are limitations to integrating hydrogen into the current infrastructure that the industry is studying and addressing, including technical, regulatory, and policy-related hurdles.
Providers of transportation fuels and power and gas utilities have traditionally relied on pipelines to distribute oil and natural gas supplies. There have been relatively few natural gas and hydrogen compatibility studies conducted for these pipelines, but a survey completed by the Department of Energy (DOE)/National Renewable Energy Laboratory (NREL), as well as a handful of separate industry studies, indicates that hydrogen can generally be blended into natural gas supplies in distribution pipelines up to 20% by volume, or 7% on an energy basis. The primary constraint, these studies suggest, is the permeability of polymer piping and safety concerns related to elevated concentrations of hydrogen in confined spaces. Transmission lines may blend up to 50% by volume of hydrogen at current pipeline operating pressures, with the principal constraint being hydrogen embrittlement of the pipelines’ steel.
The existing hydrogen distribution pipeline infrastructure on the Gulf Coast is typically run at lower pressures (about 500 psi, compared to typical natural gas pipelines that vary in pressures but can range up to 1,500 psi) to mitigate this issue. It may be possible to transport 100% hydrogen through existing natural gas pipelines with limited capital outlays if they operated at similarly reduced pressures. However, transporting hydrogen at lower pressures implies moving less product through pipelines. Even at standard operating pressures, the difference in energy content between hydrogen and methane means that the same capacity pipeline will deliver less energy moving hydrogen than if it were moving methane. The reduction in energy content will require potentially significant changes in pipeline rates and rate structures to maintain pipelines’ economic viability.
Keeping those constraints in mind and anticipating that, as the hydrogen economy develops, demand and supply may well increase, there could be the potential for investment in supplemental midstream infrastructure. Natural gas pipelines offer a sizable potential hydrogen distribution network for blending or conversion. Gazifère and Evolugen announced in February that they plan to build 20 MW of hydrogen production from hydro-powered-electrolysis to inject into Gazifère’s natural gas distribution network in Quebec via 15 kilometers of new pipeline interconnect.
Liquid hydrogen delivery trucks and rail cars are also viable distribution alternatives for transport use. However, current storage tank technology limits the delivery capacity of these approaches, leading to challenges in providing the volumes needed for power generation and utility-scale gas. These technology limitations also create economic challenges relative to repurposing existing natural gas infrastructure.
Considerations for commercial and residential applications
Practical blending limits for end-use consumer and industrial gas-based equipment are more restrictive than those for the midstream sector. Various studies have tested blending upper limits for gas home appliances but have yet to develop consensus. So, while hydrogen compatibility depends on individual devices, it is possible to blend volumes under 5% of hydrogen into gas supplies without modifying some residential devices. Exceeding these limits would require the burners and valves used in end-use equipment from residential furnaces, package boilers, and cooking appliances to be retrofitted or replaced. Another limitation on residential and commercial hydrogen use is safety. Modifications to warning systems like flame-detection units and other modifications to conventional natural gas equipment will be required given hydrogen’s greater flammability and odorless and colorless properties. Transitioning end-use gas appliances is constrained by the limited availability of hydrogen-compatible devices. The market is growing, however, as demonstrated in projects like the U.K.’s Hy4Heat program and Southern California Gas Co.’s “H2 Hydrogen Home.”
Generating power with clean hydrogen
While there are significant constraints on the consumer and industrial side, power generation applications are well placed to utilize high-hydrogen blends. Though most turbines would need retrofits to their combustors, fuel piping, and instrumentation to accommodate hydrogen’s high flame speed and reactivity, the retrofit cost is relatively small compared to the cost of a new unit or other zero-carbon power sources. Smaller (<50MW) aero-derivative turbines currently used in refineries (and elsewhere) can run on anywhere from 75%-95% hydrogen. For example, GE’s 6B turbines at the Daesan refinery in South Korea have been heavily hydrogen-powered since 1997. While smaller aero-derivative-based gas turbines are already capable of running on high hydrogen blends, original equipment manufacturers (OEMs) are now adapting their larger, more efficient frame turbines for high hydrogen use as well. Leading manufacturers of combined cycle gas turbine (CCGT) units such as Mitsubishi Hitachi and GE have announced technology roadmaps for burning hydrogen blends of 50% or higher, with an eye towards burning 100% hydrogen by 2025-2030. It is generally an area of under-leveraged potential. Going forward, utilizing hydrogen in existing power plants could obviate the need to retire certain simple cycle and CCGT assets and recover what would otherwise be sunk capital in natural gas power.
The challenge of regulating an emerging industry
Occupational safety and health regulations exist around hydrogen compression, liquefication, storage, and transport. However, most current hydrogen usage is at industrial facilities with established safety systems. Safety standards and building codes for consumers dispensing and using hydrogen are in development and early deployment with building officials. There are technical feasibility uncertainties that create regulatory ambiguity, which may, in turn, slow hydrogen adoption. Organizations like the Center for Hydrogen Safety and the Hydrogen Safety Panel have mobilized to facilitate safe hydrogen development. In an attempt at creating consensus in this space, in conjunction with the Hy4Heat initiative in the U.K., the British Standards Institution published Publicly Available Specification (PAS) 4444 as a template for hydrogen cooking and heating appliance standards. One focus for hydrogen appliances is ensuring safe air quality levels of NOx emissions from hydrogen combustion. The International Energy Agency identified international regulatory uniformity as a key factor in scaling up hydrogen use. Questions remain regarding regulatory overlaps across industries as hydrogen expands its reach.
Similarly, water consumption for hydrogen production may challenge existing water rights compacts, mainly because many areas with the best solar resources for inexpensive green power for electrolysis also face extended droughts. For example, while less than 0.1% of the ~70 MMT of dedicated global hydrogen production comes from water electrolysis today, with each kilogram of hydrogen requiring approximately 4 gallons of water, growing this supply will raise concerns about water consumption. Global energy generation already accounts for 52 billion cubic meters of water consumed annually – with regulatory uniformity, hydrogen production for energy would be subject to the same standards as other energy generation methods.
What the government has already done and what it can still do
The scale of hydrogen production and the utilization of hydrogen dispensing/fueling assets both drive hydrogen prices. Under-utilizing asset capacity yields higher overhead costs for customers. As demand for fuel in energy applications grows, costs will decline. Policy can also facilitate cost declines, spur increased hydrogen production, and ultimately help hydrogen penetrate the energy market, in part by making use of existing infrastructure. The U.S. Department of Energy’s Hydrogen and Fuel Cells Program has put millions of research and development dollars into hydrogen blending in natural gas infrastructure, safety standards, regulatory frameworks, and medium- and heavy-duty FCEVs.
Future development of low-carbon fuel standards like that in California and an expansion of the U.S. Renewable Fuel Standard to include hydrogen together would facilitate transportation hydrogen demand growth. Carbon taxes or other emissions caps could also spur interest in low- and zero-carbon hydrogen applications in existing infrastructure. The hydrogen “Energy Earthshot” target of $1.00/kg (or $7.44/MMBtu) clean hydrogen by 2030 announced by the DOE in June 2021 would further accelerate the hydrogen market’s growth, perhaps exponentially.
Hydrogen’s key role in carrying existing infrastructure into a net-zero future
Hydrogen is one of the most promising options for deep decarbonization of the transport, industrial, and power generation and natural gas utility sectors. It stands apart in its ability to leverage existing energy infrastructure to speed deployment. If policy and decarbonization targets limit the use of natural gas, clean hydrogen can provide a second life for those stranded assets and provide a long-duration green alternative for power generation. Hydrogen blending offers a “no regrets” option to existing asset owners and governments, which can both extend the life of existing assets and shift millions of skilled employees from natural gas to hydrogen with minimal retraining. Further, clean hydrogen supplies bolster the energy industry’s decarbonization options—offering an approach that can lower emissions from harder to electrify sectors.