Four U.S. nuclear generators—Energy Harbor, Xcel Energy, Exelon, and Arizona Public Service (APS)—are making headway on projects to demonstrate hydrogen production at nuclear plants, but scaling those efforts up to net new end-users and sources of revenue is still ridden with hurdles, company officials said in a panel discussion at the American Nuclear Society’s (ANS’s) virtual 2020 annual meeting on June 9.
Energy Harbor, Xcel Energy, and APS are spearheading a multi-pronged project to develop and demonstrate nuclear-hydrogen hybrids and their commercial applications. Last September, the consortium garnered funding and technical support from the Department of Energy’s (DOE’s) Light Water Reactor Sustainability (LWRS) Program, as well as from its Integrated Energy Systems program (formerly known as the Nuclear-Renewable Hybrid Energy Systems program). Idaho National Laboratory (INL), an emerging hotbed for existing and advanced nuclear reactor technologies, leads both DOE programs.
The utilities will this year embark on a two-year pilot project to demonstrate hydrogen production using a 2-MWe low-temperature electrolysis (LTE) polymer electrolyte membrane (PEM) technology that will be integrated with Energy Harbor’s 925-MWe (2,817 MWth) Davis-Besse Nuclear Power Station, a pressurized water reactor (PWR) in Ohio.
Exelon, meanwhile, kicked off development its own $7.2 million nuclear-hydrogen project in August 2019, backed with up to $3.6 million in federal funding from the DOE’s H2@Scale program under the Office of Energy Efficiency and Renewable Energy (EERE), and technical expertise from INL, Argonne National Laboratory, and the National Renewable Energy Laboratory. The three-year demonstration, which is slated to begin this year, will entail installation of a Nel Hydrogen 1-MW PEM electrolyzer at one of Exelon Nuclear’s 14 boiling water reactors (BWRs), likely in an organized power market, to demonstrate “dynamic production” of hydrogen from nuclear power.
However, because both Exelon and the consortium’s projects are being developed under the DOE’s cross-cutting initiatives, the four utilities and their federal partners are sharing expertise to develop the nuclear hybrid projects. They also share common goals, foremost among them to improve nuclear economics, which have lately been challenged by the proliferation of cheap renewable and natural gas power.
If successfully scaled up and replicated, they could, for example, transform nuclear generators into chemical energy storage facilities—leveraging their flexibility and participation in grid services, including for reserves and grid regulation. As hydrogen producers, the nuclear generators could also cement new sources of revenue and establish a foothold in burgeoning “green” hydrogen markets for use in chemicals and fuels synthesis, steel manufacturing, ammonia-based fertilizers, and transportation.
Location a Key Consideration for Nuclear-Hydrogen Pilot Development
However, as the ANS panelists underscored on Monday, these are general benefits, and achieving them will be highly dependent on location, including as they concern existing infrastructure, and market reach. Each utility representative also pointed to different needs for exploring hydrogen production at their nuclear plants.
As Energy Harbor Project Manager for Strategic Engineering Alan Scheanwald explained, Davis-Besse presents a good location for the pilot because the plant’s relative proximity to key markets is ideal for reducing transport distances. The nuclear plant is also within 150 miles of major existing hydrogen consumers, such as oil refineries, steel manufacturers, syngas, and chemical plants. The location also has the right inputs for the necessary electricity and water. It will consume 2 MWe of power at plant output, prior to the switchyard, and use the containerized PEM electrolyzer and 2,400 gallons of water per day (at maximum operating capacity) to produce between 800 kilograms and 1,000 kilograms of hydrogen, noted Scheanwald.
Energy Harbor’s goals are to determine the effect the skid and supporting equipment will have on plant operation, design, and the licensing basis, as well as to develop the safest and most efficient means to connect the equipment to the plant’s electrical distribution system, he said. Significantly, it will also test software, which will interface with a programmable logic controller (PLC), that could modulate hydrogen output based on input variables.
Exelon, meanwhile, is focusing on BWRs because they use “far more hydrogen” than a PWR (to cool the generator as a coolant gas and control the chemistry of the coolant water), explained Exelon Nuclear Vice President for Engineering and Technical Support Scot Greenlee on Monday. But Exelon is currently limiting its efforts to produce only enough hydrogen to meet needs onsite, mainly because it offers a better business case when compared with large-scale generation, which would require hydrogen gas transportation via pipeline or truck.
“The good news is, with hydrogen, you can mix it with natural gas and burn it in a combustion turbine, and ultimately we want to get to the point where we’re burning pure hydrogen, which means you’re emitting no carbon dioxide, unlike the current natural gas cycles,” Greenlee said. “Right now, everything that we’re seeing in this particular use case has a positive net present value, so it will eventually be worth the installation versus buying hydrogen and bringing to the site.”
Hydrogen: A Quest to Keep Nuclear Afloat
The economics are especially important for Exelon, the nation’s largest nuclear generator, and exploring hydrogen production is a natural evolution to keep its plants financially afloat amid stagnating load growth and challenging economics in competitive energy markets, Greenlee said.
Energy Harbor faces similar predicaments. In 2018, the independent power producer—which was known as FirstEnergy Solutions until Feb. 27, when it completed Chapter 11 restructuring—had planned to shutter Davis-Besse in 2020; along with the twin-unit 1,872-MW Beaver Valley Power Station in Shippingport, Pennsylvania, in 2021; and the Perry Nuclear Power Plant in Perry, Ohio, in 2021. Last year, Energy Harbor pushed for and won nuclear subsidies in Ohio to keep the Davis-Besse and the Perry nuclear plants open through 2027, and this March, it said Beaver Valley would remain open.
Like Energy Harbor, Exelon helped enact the Future Energy Jobs Act in December 2016 (it went into effect in June 2017), to keep Exelon’s Clinton and Quad Cities plants running. Exelon also strongly backed New York’s Clean Energy Standard, a measure that became effective in April 2017, to preserve the at-risk Nine Mile Point, FitzPatrick, and Ginna reactors in upstate New York. And in 2018, New Jersey also enacted zero-emission credits (ZECs) to bolster profitability of the Hope Creek plant, which is owned by PSEG, and Salem, whose output Exelon owns jointly with PSEG.
As Greenlee noted, Exelon has since 2018 been seeking ways to “repurpose” its nuclear plants to make them more viable. The company’s efforts included convening academic experts, former employees, and former federal regulators in a brainstorm session. “And over the last several years, what we have boiled that table down to is, basically, hydrogen,” he said. “Hydrogen is what we want to look at going forward. We think it fits in with potentially a future hydrogen economy.”
Xcel Planning HTSE Electrolyzer Demonstration, Likely at Prairie Island
Patrick Burke, vice president of Nuclear Strategy at Xcel Energy, also pointed to better economics as a key driver for its focus on hydrogen. The Minneapolis–based company has two nuclear plants in Minnesota: a 671-MWe (2,004-MWth) BWR at Monticello and two 520-MWe (1,677 MWth) PWRs at Prairie Island. But while those units will play a crucial role in Xcel’s ambitions to become 100% carbon-free by 2050, they are seeing “significant price pressures” from renewable energy. “[The cost for] wind is down by 25% and solar is down by 33%, and we forecast those trends will continue,” Burke said. “That is driving the nuclear power plants to flex-operate the units on windy days,” and Xcel has been seeking ways to operate the units more efficiently, he said.
As part of the consortium with Energy Harbor and APS, Xcel has been looking into the technical feasibility and economics of producing hydrogen at its nuclear facilities. Efforts so far have assessed future electric and hydrogen markets to determine their potential, as well as to determine how industry could navigate hydrogen-nuclear hybrid operations in a regulated market, Burke said.
“Surprisingly, Minnesota has quite a few refineries that could use hydrogen, and as you would imagine, Minnesota has quite a bit of farm land, so fertilizers and ammonia are opportunities,” Burke said. Opportunities also exist for “turning hydrogen back to electricity for data centers,” he noted.
While the Davis-Besse pilot is a crucial first step, the consortium has also developed a proposal that it recently submitted to the DOE and INL to develop a high-temperature steam electrolysis (HTSE) system demonstration at one of Xcel’s nuclear facilities, Burke said.
The high-temperature source would come from the nuclear power steam cycle, he noted. “We’re evaluating both stations, but it looks like right now Prairie Island would be the preferred site to extract steam from the balance of plant, take that steam over to the electrolyzer, and use that in a high-temperature capacity,” Burke said. “But, of course, it’s a newer technology and we need to demonstrate it, as well as all the licensing, and permitting, and associated challenges that you would have in a nuclear facility by adding another function to the site.”
Low‐Temperature and High‐Temperature Electrolysis in the Nuclear Context ExplainedThe Department of Energy’s (DOE) Office of Nuclear Energy program on Integrated Energy Systems (IES)—formerly known as the Nuclear‐Renewable Hybrid Energy Systems (N‐R HES) program—explains that there are two general types of hydrogen generation technologies: reforming and water splitting. Reforming technologies use fossil fuels or biomass and steam to produce hydrogen at the lowest cost—but they also produce carbon dioxide. Water splitting technologies, meanwhile, fall into three general categories: thermo‐chemical cycles, electrolysis, and direct photoelectrochemical (PEC), all of which are being explored at the DOE.
Thermo‐chemical cycles utilize heat—sourced from a nuclear plant or from concentrated solar plants, for example—and chemical reactions to produce hydrogen and oxygen, but they also involve corrosive acids or volatile chemicals. The PEC pathway directly uses solar radiation to split water using semiconductor‐based devices, but it currently has a fairly low technology readiness level. For now, nearer-term electrolysis is often elected as the better option for “green” hydrogen production.
Electrolysis generally falls into two categories. Low‐temperature electrolysis (LTE), which is already commercially available and often the choice for emerging power-to-gas projects, involves placing electrodes in an electrolytic solution or using membranes to separate the hydrogen from the oxygen. High‐temperature steam electrolysis (HTSE) utilizes heat and electricity to split water into hydrogen and oxygen, so, compared to LTE, the additional heat reduces the amount of work needed. In HTSE, solid oxide electrolysis cells are used to electrochemically separate the hydrogen and oxygen from steam at temperatures around 800C.
As shown in this schematic of a high-temperature steam electrolysis (HTSE) system, an integrated high-temperature solid oxide electrolysis cell (SOEC) uses thermal energy (steam) to reduce electrolysis cell potential (voltage) and improve efficiency. A reversible system (rSOEC) can use hydrogen to generate power in the same stack. Courtesy: APS
“Although the temperature of the steam is high, pressurized water reactors (PWRs) can be used by employing temperature-boosting techniques, such as resistive heating or chemical heat pumps,” explained Dr. Shannon Bragg-Sitton, INL lead for the IES program. “The efficiency of the process is strongly coupled to the thermal efficiency of the power cycle used to produce power.”
APS Looking Into Nuclear Hydrogen as a Renewables ‘Hedge’
Michael Green, general manager of Nuclear Policy and associate general counsel at Pinnacle West Capital Corp.—APS’s corporate parent—said APS’s efforts were also driven in part by its ambitions to exit from coal over the next decade and decarbonize its entire fleet by 2050. Nuclear power—from APS’s three-unit 3.3-GW Palo Verde Generating Station in Wintersburg, Arizona, a plant licensed to operate until 2047—is slated to be such an integral part of that effort that the company opposed an Arizona ballot initiative in 2018 to raise the renewable portfolio standard to 50% in 2030 because it did not include nuclear, Green said.
“We believe that in the 2030 to 2050 timeframe, we’re going to see our resource mix be composed of nuclear, solar, some form of storage, and some form of thermal electric generation,” he said. Nuclear will have a significant role in the future because APS sees a steep ramp in the afternoons, which peaks in late afternoons and in the evenings. “That’s the time when a lot of our solar generation is falling off so production of hydrogen provides us a great opportunity to meet our aspirations for storage and for thermal electric generation.”
While APS is a crucial partner in the utility consortium, “candidly, we’re not as far as [Energy Harbor and Xcel],” Green noted. “We will be in phase one of the project, producing a technical and economic assessment, much like is being done at Xcel, and we expect those results later this year.” APS anticipates, however, that those efforts may lead to “scaling up production and running meaningful demonstrations on some of our fossil assets with various blends of coal-fired, hydrogen, and natural gas,” he said.
Scaling Up Requires a Big Vision
But scaling up planned demonstrations may prove to be a bigger challenge. Nuclear generators mulling utility-scale hydrogen feel the implicit urgency to accelerate the pace of demonstrations, as Xcel’s Burke noted. “If you think about the 2030s, and all of us have goals for carbon reduction, it’s really not that far away,” he said. “If you start thinking about utility-scale hydrogen, the amount of work is enormous to get there.”
Burke also pointed out Xcel operates in a region characterized by substantial wind generation, so the energy source will need to be flexible and dispatchable. Costs must also be competitive enough to be endorsed by ratepayers, regulators, investors, and wholesale markets, which will provide the impetus for additional investments. Scheanwald noted the pilots will be pivotal in pushing down capital costs of key equipment, such as for the electrolyzers, at least.
But then there are technical challenges. “To become a serious producer of hydrogen, you’re probably talking hundreds of megawatts—which is a very large scale. The associated challenges come with the scaling of it: How do you connect all the electrolyzers, create a distribution network for the gas that you produce, as well as the operating and maintenance costs,” Burke said.
For Xcel, demonstrating HTSE, which is currently commercially unavailable, already poses notable challenges, because, among its myriad considerations, it will entail securing the proper fabrication and the right vendors. Scaling up will require big vision, he said.
“It’s really one thing to do a 1-MW skid in the parking lot. It’s a whole other challenge if you’re talking about 100 MW, 200 MW,” because more falls into play, such as equipment life and maintenance needs. And so, as crucially, scaling up will require training operators and developing the right workforce skills. Burke noted, “We all believe it is necessary but it’s going to take a lot of work, and we’re going to get cracking on it.”
Bigger projects will also need a focus on storage. “Hydrogen is best utilized at the point of production—or to put it differently, where there is an end, so should the supply be located,” noted APS’s Green. Developing the ability to “store sufficient volumes at a scale that will support, potentially, what we hope will be seasonal storage,” should be an ongoing focus, he said.
Regulatory and Market Acceptance
Meanwhile, regulatory oversight isn’t an immediate concern, because, as Greenlee noted, “we maintain hydrogen at our nuclear plants, and we’re just changing the way it gets delivered.” But as the projects scale up, “it will be key to keep the Nuclear Regulatory Commission (NRC) in the loop because the more hydrogen you generate, the more concerns there are going to be of the explosive nature of the gas at a nuclear plant, and we’re going to have to prove to the NRC that it’s safe to ramp up our efforts as we go forward,” he said.
But for now, the utilities, which lauded the DOE’s leadership on the project, also seem to have wide backing from the vast power arena—including from academia, local government officials, and industry. The panelists suggested most hurdles would be resolved over time, and with more collaboration. “As you dig deeper into it and educate more people around hydrogen, it does become clearer,” Burke said.
Other panelists suggested more comprehensive coordination from the outset would be pivotal to jumpstarting utility-scale nuclear hydrogen. While APS’s Green commended the DOE’s support, for example, he noted that the utility pilots are being funded under separate DOE initiatives under its Nuclear and EERE offices. Factoring in the potential to burn hydrogen in combustion turbines may also rope in the DOE’s Fossil Energy group. “If you look at hydrogen as an energy storage medium, it touches all three [DOE programs] and I think coordination between the three would be very helpful from our perspective,” he said.
Finally, larger nuclear hydrogen projects will need viable markets. Energy Harbor’s Scheanwald pointed to what he said will be the crucial development of partnerships with industrial gas distributors, as well as with potential consumers for non-electric nuclear “products.” The starkest challenge that Greenlee described, meanwhile, is garnering interest from states where nuclear hydrogen projects may be sited. Putting these projects to play in organized markets—such as in PJM Interconnection, where many Exelon BWR reactors are located—could require changes.
“The market construct is broken, and it really needs to be fixed, and some of the states are considering what they’re calling a fixed resource requirement, which would mean that the state would actually pull the nuclear plants out of PJM, and then provide capacity payments for those nuclear plants inside the state to meet the state’s energy goals,” Greenlee said.
“And that’s probably our biggest challenge—making that a reality—because I don’t think hydrogen is going to come fast enough to save the existing fleet in some cases, depending on the revenue stream at that particular site. And so for us, after that, it just comes down to business case—can you become competitive with the existing producers?”