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Energy - Мыслительная карта

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Which Has More Energy an Iceberg or a Cup of Coffee

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A Significant Partnership, An Expanding Project Pipeline, The Big Boost From Technology Validation, Business Combination With RAC II

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2nd Article

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NET Power will combine with Rice Acquisition Corp. II (RAC II), a decarbonization solutions special purpose acquisition company (SPAC), in a new business direction designed to accelerate the deployment of NET Power's much-watched novel natural gas-fired power plant technology.

When the business combination transaction closes as expected in the second quarter of 2023, the new company, NET Power Inc., will be listed as "NPWR" on the New York Stock Exchange. The transaction will also result in a leadership shuffle, with current RAC II Director and former CEO of Rice Energy Inc. Danny Rice taking over from current NET Power CEO Ron DeGregorio as head of the new combined company.

NET Power and RAC II's business combination, which has an "implied" pro forma enterprise value of $1.5 billion will help position NET Power Inc. to capture the substantial market opportunity that is developing for its novel technology, the companies told investors during a briefing on Dec. 14.

NET Power says it has to date logged over 155 total project opportunities from "a diverse set of companies." So far, six projects-four in the U.S. and two in Europe-are targeting utility-scale 300-MW sized plants based on the NET Power cycle. All have completed feasibility studies or similar due diligence and could be commercially operational in the 2026-2027 timeframe, it said.

The transaction to combine with RAC II, meanwhile, follows a "strategic investment and partnership with Baker Hughes to deliver key turbomachinery for future NET Power plants," DeGregrio noted. The business combination "properly capitalizes NET Power and enables the company to commercialize this revolutionary technology," he said. "The Rice Group is a logical strategic partner, and I am excited to hand the reins to Danny to lead NET Power."

The Big Boost From Technology Validation

As POWER has reported in-depth , NET Power's technology is based on the Allam-Fetvedt Cycle (AFC), which is essentially a specialized Brayton cycle in which the combustor is supplied with three flows: fuel gas, which is compressed in the fuel compressor; oxygen, which is produced in an air separation unit and then compressed; and a carbon dioxide working fluid that is heated in the multi-flow regenerator.

The process begins with a "commercially available" air separation unit, which separates air into its constituents of oxygen, argon, and nitrogen, NET Power Chief Technology Officer Brock Forrest. While argon and nitrogen can be sold as industrial gases or vented, the oxygen is mixed with natural gas and combusted (a process known as oxy-combustion) to create a stream of supercritical carbon dioxide (CO ₂) and water vapor. This high-pressure CO ₂ moves to a specialized turboexpander to generate electricity.

" This patented, high-efficiency cycle inherently captures over 97% of CO which can then be utilized or sequestered, transforming natural gas into clean baseload power," the company said last week. "NET Power is designed to generate reliable power with a carbon intensity similar to solar or wind coupled with a short-duration battery at a levelized cost of electricity of approximately $21-$40 per megawatt hour."

During the presentation, notably, Forrest refrained from calling the cycle "AFC," referring to it instead as the "NET Power cycle," a label NET Power confirmed it would use going forward for the novel power cycle. Forrest also suggested the company's technology offering has evolved. While the company's Generation 1 design-its initial 300-MW commercial utility-scale design-is expected to have plant efficiencies of about 50% (but with a higher firing temperature), its "Generation 2" design "is expected to achieve efficiencies over 60%, in-line with combined cycle natural gas plants," he said.

The technology evolution stems from efforts to validate the technology's many first-of-a-kind components at NET Power's test facility in La Porte, Texas. Since May 2018, when the company the first fire of a novel industrial-scale (1/11th the size of a utility-scale plant ) 50-MWth combustor designed by Toshiba , the company has run three separate testing campaigns at the test facility to validate the technology, amounting to 1,500 hours of operational uptime.

The multiple 24-hour test campaigns tested start-stop sequences, steady-state, and ramping operations, the company said. Among key highlights are that the supercriticalCO ₂ turbine generated power while synchronized to the grid. In addition, the facility exceeded its 925C design temperature expected of a utility-class plant turbo expander through optimized combustion and recycle temperature controls. Meanwhile, balance of plant (BOP) exceeded 300 bar pressure operation, consistent with utility-scale plant specifications. Heat exchanger performance, too, has been "robust, resilient, and tested at temperatures meeting and exceeding required benchmarks," it said.

"Most importantly, La Porte has given us and Baker Hughes the confidence to move forward with designing the key equipment necessary for utility-scale deployment," said Forrest.

A Significant Partnership

According to Brian Allen, NET Power's president and chief operating officer, sealing the partnership deal with global equipment firm Baker Hughes in February 2022 marked an "incredibly important milestone" for NET Power. Baker Hughes, which has a vast portfolio of gas turbines and compressors installed globally, agreed both to invest in NET Power as well as develop and commercialize a turbo expander equipment package with performance guarantees. In addition, however, Baker Hughes will jointly market NET Power's technology through their global sales channels.

" Further, Baker agreed to only sell jointly developed turboexpanders to NET Power licensees, which will further deepen NET Power's competitive moat," Allen said. "Lastly, Baker was willing to provide industry-standard warranties and guarantees to enable future customers to move forward with constructing projects."

Allen said Baker Hughes could begin quoting units for customers as early as summer 2023. It is also poised to test the first industrial-scale Baker Hughes combustor and turbo expander at the La Porte facility in 2024-2015. "First delivery of the utility-scale equipment package is expected by 2026," he said.

An Expanding Project Pipeline

"While we only signed the partnership seven months ago, the teams are working well together and hitting milestones set out in the original scope of work on both our technical and commercial workstreams. We are on track and have started fielding reverse inquiries from several large customers seeking to deploy NET Power plants in the near future, while strategizing to enter new markets across the world," Allen added.

The technology certainty has sparked widespread interest and extended the project pipeline, Allen suggested. So far, six projects have completed feasibility studies and are on track to kick off front-end engineering (FEED) in 2023 and have targeted commercial operation dates in the 2026 to 2027 timeframe.

The first project- "serial number one"-will be a 300-MW natural gas-fired power plant at an Occidental-hosted site near Odessa, Texas . Construction is slated to begin in the third quarter of 2024, and NET Power is targeting commissioning in the third quarter of 2026.

NET Power said that it has already secured $200 million through "committed investments" to fully fund corporate operations through the commercialization of the Odessa project in 2026. Allen, however, noted that the company may still be exploring a range of options to finance the Odessa plant's design and construction. "First, a portion of the SPAC capital raised can be applied to the project. We will also pursue [Department of Energy] funding through loan and grant programs that are currently in place. The shareholder group can also provide financial assistance as necessary."

"Importantly, we expect each [of NET Power's shareholders] will play a meaningful role in moving the project to completion. Baker will provide the key rotating equipment, and [Occidental] will provide CO ₂ and power offtake. Constellation can provide [operation and maintenance] services of the plant as well as power offtake, and 8 Rivers can provide project development support," he said. "This level of shareholder support is a key differentiator of NET Power relative to many other early-stage technologies. We are confident we have the expertise and capital to deliver serial number 1 to set the stage for commercialization."

Occidental, NET Power's biggest shareholder, last week also highlighted the importance of the first project, including demonstrating how a supply of emissions-free power could be beneficial to the direct air capture (DAC) sites and sequestration hubs Occidental is developing. "Occidental is advancing feasibility studies to incorporate NET Power plants into DAC hubs being developed by its 1PointFive subsidiary, where approximately 30 - 40 plants could provide enough clean power for a DAC program capturing 100 - 135 million tonnes of CO per year," the company said.

Other publicly announced NET Power projects include the Coyote Clean Power Project in southwest Colorado, which will be located within the Southern Ute Indian Reservation, and the Broadwing Clean Energy Complex , which is being developed under a partnership with agricultural and processing firm Archer-Daniels-Midlands Co. (ADM) at an existing CO2 storage facility site in Decatur, Illinois. A 300-MW natural gas-fired NET Power station is also under development at an existing site at Teesside, potentially making it the first UK installation.

During the briefing last week, NET Power also revealed a project comprising two 300-MW NET Power plants is moving forward at the Wilhelmshaven Green Energy Hub in Germany. TES Energy Solutions is developing that project with ENGIE. "TES is notably cooperating closely with NET Power in its effort to offer green power-on-demand and independent from the intermittency of European solar and wind power production," NET Power said. Finally, a 300-MW NET Power plant is under development at G2 Net Zero, a pioneering net-zero liquefied natural gas (LNG) liquefaction terminal in southwestern Louisiana.

Business Combination With RAC II

Looking ahead, a substantial market may be developing for NET Power plants, officials from NET Power and RAC II said. One of the combined company's primary use cases will be to replace existing baseload capacity slated for retirement. That alone would equate to "over 1,000 NET Power plants in the U.S. alone, and over 15,000 NET Power plants when including global baseload retirements and expected electrification demand growth," said RAC II's director, Danny Rice.

Market potential also lies in global decarbonization, which will require lower-carbon power generation solutions. "But today's lower-carbon solutions are unreliable, unaffordable, or limited by scale," he noted.

Both companies also suggested natural gas may have a solid future as decarbonization efforts gain momentum. " In the U.S., we've nearly doubled supply in the last 15 years of natural gas and have over 75 years' worth of it in some of the most responsibly produced and lowest-cost gas reserves in the world," said Rice. "But here's the challenge: With this growth in gas supply comes growth in gas emissions which recently surpassed U.S. coal emissions. And in order for natural gas to have a permanent role in a clean energy future, policymakers have made it clear that the industry needs to develop ways to rapidly decarbonize natural gas," he added.

"Unfortunately, the challenge is that traditional carbon capture for gas plants is very expensive and inefficient, and clean hydrogen options have significant cost and logistical challenges. Even the new incentives recently passed into law aren't high enough to make economic sense."

NET Power's business model-an "asset-light, licensing-based revenue model"-offers a "simple and straightforward" approach, Rice said. "These licenses are expected to generate a fee stream of approximately $65 [million] of per utility-scale plant, most of which is received by the time the plant is commissioned. For investors, you can multiply $65 [million] by the expected addressable market to understand future value potential. [Ten] plants are worth $650 [million], 20 plants are worth $1.3 billion, etc."

Rice also suggested the current policy environment and market economics are compelling. " A further boost to the company's momentum was the recent passing of the Inflation Reduction Act [IRA], which increases the 45Q [tax credit] price for CO 2 capture and storage to $85/ton and materially increases the NET Power value proposition for our future customers," he said.

Under the revised 45Q, a NET Power plant, which is designed to capture up to 820,000 tonnes of CO per year, becomes more economical to deploy than carbon-emitting coal and natural gas-fired alternatives, he said. "Moreover, the IRA sends a very strong signal to NET Power's prospective customer base that carbon capture will have long-term support in the U.S."

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NET Power Consolidates Business to Gear Up for Allam Cycle Power Plant Deployment

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NET Power will combine with Rice Acquisition Corp. II (RAC II), a decarbonization solutions special purpose acquisition company (SPAC), in a new business direction designed to accelerate the deployment of NET Power's much-watched novel natural gas-fired power plant technology. When the ...

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1st article

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The first of two units at China's much-watched high-temperature gas-cooled modular pebble bed (HTR-PM) demonstration project was successfully connected to the grid on Dec. 20. The achievement marks a major milestone for fourth-generation advanced nuclear technology.

The demonstration high-temperature gas-cooled reactor pebble-bed module (HTR-PM) at the Shidaowan site in Shandong Province of China was connected to the grid in December 2021. Courtesy: China Nuclear Energy Association

Grid-connection of Unit 1 at the "national project" at the Shidao Bay site in Rongcheng, Shandong Province, will be soon followed by Unit 2. When commercially operational as expected in mid-2022, the two HTR-PMs will drive a single 210-MWe steam turbine. Construction of the pioneering project began in December 2012, led by China Huaneng (which holds a 47.5% stake in the demonstration), along with China National Nuclear Corp. (CNNC) subsidiary China Nuclear Engineering Corp. (CNEC, 32.5%), and Tsinghua University's Institute of Nuclear and New Energy Technology (20%). Chinergy, a joint venture between Tsinghua and CNEC, served as the engineering, procurement, and construction contractor for the nuclear island.

Decades of Development

As Tsinghua's Institute of Nuclear and New Energy Technology has noted, the demonstration project stems from a series of developments that marked a "qualitative leap from laboratory to engineering application." High-temperature gas-cooled reactor (HTGR) technology has been explored for decades. China's own HTGR research and development program kicked off in the mid-1970s, echoing similar government-led initiatives to develop the 200-MWth HTR-module of the Siemens/Interatom Co. in Germany, and General Atomics' 350-MWth modular high-temperature gas-cooled reactor MHTGR in the U.S.

China's research institutions eventually accomplished the construction of the HTR-10 test reactor in the late 1990s. In February 2008, China approved the 200-MWe HTR-PM demonstration plant as part of its slate of National Major Science and Technology Projects. As Tsinghua noted, the government then anticipated the technology would prove to be "a highly efficient nuclear power technology, as a supplement to pressurized water reactor [PWR] technology." Chinese researchers also heralded the technology's high-heat potential, as well as the opportunity to further global innovation in advanced nuclear technologies. A key focus was to improve nuclear safety inherently.

Pebble-Bed Modules

The HTR-PM demonstration comprises two pebble-bed reactor modules-each which consists of a reactor pressure vessel, graphite, carbon, and metallic reactor internals-a steam generator, and a helium blower. "The thermal power of one reactor module is 250 MWth, the helium temperatures at the reactor core inlet/outlet are 250/750C, and steam at 13.25 MPa/567 C is produced at the steam generator outlet," Tsinghua said.

Among the HTR-PM's distinctive differentiators, when compared to PWR technology, for example, is that it uses helium as a coolant. An HTGR "does not use 'water cooling' but 'air cooling' for core cooling and heat transfer-that is, the coolant is a gas. As an ideal inert gas, helium has stable chemical properties, does not easily react with other materials in the reactor at high temperatures, and has good thermodynamic properties," it explained. In addition, unlike light water reactors and heavy water reactors that use water and heavy water as moderators-materials that help slow down the speed of neutron movement and sustain a fission reaction-HTGRs use graphite as the moderator, mainly for its good high-temperature resistance.

The HTR-PM, specifically, also adopts a modular design. "The core idea is to split a large [megawatt-sized] reactor into 10 small modules, each of which is a small reactor that can operate independently," Tsinghua said. "Each small module can use a very low power density," about one-thirtieth of that of a large PWR nuclear power plant, it said. "In the event of an accident, even without active cooling, the residual heat of the reactor core can be safely dissipated through basic phenomena, such as heat conduction and thermal radiation after the reactor is shut down." Modularity also translates to scalability, as well as flexibility, it said.

Yet another notable aspect of the pebble-bed design is that it uses a heat-resistant all-ceramic-coated particle spherical nuclear fuel element. The fuel spheres used at the Shidaowan HTR-PM demonstration are graphite-coated balls (six centimeters in diameter) made up of about 12,000 four-layer particles dispersed in a graphite powder matrix, it said.

Tsinghua expects the HTR-PM's high heat production will be beneficial on multiple levels. "At present, about 40% of the world's energy is utilized in the form of electricity, and the rest are non-electrical applications, including industrial heat, residential heat, and transportation energy utilized in various forms. There is a great demand for high-temperature process heat in various industries," it noted. "The helium outlet temperature of the Shidaowan HTR-PM demonstration can reach 750C, producing superheated steam of 566C. In addition to high-efficiency power generation, high-temperature steam can also be used for cogeneration, thermal recovery of heavy oil, chemical industry, metallurgy, and so on," it said. If development further boosts temperatures to 950C, as tests at the HTR-10 suggest, the technology's heat may also be used for large-scale hydrogen production, providing more wide-ranging decarbonization solutions, it said.

Success at the Shidaowan demonstration project could prompt several similar projects. CNNC said it plans to further strengthen its partnership with Tsinghua University to accelerate deployment of the HTGR technology and establish an advanced nuclear industry in the nation. For now, a further 18 HTR-PM projects are proposed for the Shidaowan site. Proposals also call for a scaled-up version, the HTR-PM600, which would comprise six HTR-PM reactor units driving a 650-MWe turbine. According to the World Nuclear Association, feasibility studies on HTR-PM600 deployment are underway for Sanmen, Zhejiang Province; Ruijin, Jiangxi Province; Xiapu and Wan'an, Fujian Province; and Bai'an, Guangdong Province.

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China Starts Up First Fourth-Generation Nuclear Reactor

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The first of two units at China's much-watched high-temperature gas-cooled modular pebble bed (HTR-PM) demonstration project was successfully connected to the grid on Dec. 20. The achievement marks a major milestone for fourth-generation advanced nuclear technology. The demonstration high-temperature gas-cooled reactor pebble-bed module (HTR-PM) at the Shidaowan site in Shandong Province of China was connected to the grid in December 2021.

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Pebble-Bed Modules, China Starts Up First Fourth-Generation Nuclear Reactor, High-temperature gas-cooled modular pebble bed (HTR-PM)

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fuel and air, Heat and Power, burner, water, fire tube, combustion emissions, steam

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2nd part is find video about your field 

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2nd part is find video about your field 

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Marine fire-tube boiler

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NYPA, GE Successfully Pilot Hydrogen Retrofit at Aeroderivative Gas Turbine

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A pioneering GE aeroderivative gas turbine project to demonstrate hydrogen combustion as part of a retrofit at an existing U.S. natural gas power plant has successfully utilized blends of 5% to 44% hydrogen with natural gas-some of the highest volumes of hydrogen blended into a commercially operating gas turbine.

The project spearheaded by New York Power Authority (NYPA), the nation's largest state public power organization, and GE demonstrated combustion of the hydrogen-natural gas blend on an LM6000 SAC gas turbine at NYPA's 2001-opened 45-MW Brentwood Small Clean Power Plant in Suffolk County, Long Island, New York.

A key study objective was to demonstrate the gas turbine's steady state operational capability on hydrogen, as well as to identify an impact on combustion emissions on the LM6000 gas turbine's outlet emissions, including carbon dioxide (CO ₂), nitrogen oxide (NO x), and carbon monoxide (CO). Results of the successful test, unveiled on Sept. 23 by project partners the Electric Power Research Institute (EPRI) and GTI Energy, which worked under the research groups' 2020-launched Low-Carbon Resources Initiative (LCRI), will be pivotal for exploring hydrogen integration at aeroderivative gas turbine plants, which are widely used to provide peaking power, project partners said.

But while the project represents one of the first utility-scale hydrogen blending projects at an existing gas plant in the U.S., it also unveiled several significant challenges that suggest hydrogen combustion is still a long way from practical implementation at a competitive gas power plant.

At Brentwood (Figure 1), which operates in the New York Independent System Operator (NYISO) market, those challenges include a lack of access to the volume of hydrogen required to run the plant, limited industry experience to run the plant on blended hydrogen fuel, and restrictive code requirements. That's why for now, NYPA does not plan to apply technology learning from the pilot to continue the project at Brentwood or any of its other gas-fired power plants, the organization told POWER on Friday.

A First Crucial Step to Assess a Decarbonization Pathway

The project's learnings will still, however, play an important role as intended in informing stakeholder discussions about the feasibility of hydrogen power. A key benefit has been to provide insight, said Neva Espinoza, EPRI vice president of Energy Supply and Low-Carbon Resources. LCRI is determined to accelerate development and demonstrate low-carbon technologies that will be needed to help private companies and governments achieve increasingly ambitious decarbonization goals by 2050, she noted. "As industry and government seek innovative energy solutions, NYPA's hydrogen blending demonstration is uncovering new insights with implications well beyond New York," she said.

The Brentwood project stems from a July 2021 effort New York State launched to evaluate hydrogen's potential role in displacing fossil fuels from power generation as it pursues an ambitious target to reduce its carbon emissions 85% by 2050. The state is also looking to achieve mandating a zero-emission electricity sector by 2040, and get to 70% renewable energy by 2030, noted NYPA Interim President and CEO Justin E. Driscoll. The pilot project, meanwhile, aligns with NYPA's strategic vision priority to decarbonize its natural gas plants by 2035 without sacrificing the reliability of the electric system.

NYPA, a self-financed public power entity, owns 6.6 GW of generating capacity, 1.2 GW of which comes from gas and oil-fired power plants that operate in NYISO. Brentwood is part of NYPA's "Small Clean Power Plants," portfolio (Figure 2), which comprises 11 aeroderivative gas plants the entity opened in 2001 to bolster New York's energy security.

Driscoll told POWER on Friday NYPA's internal goal is now to retire its gas assets by 2035, five years before the state's goal of 2040. The Brentwood hydrogen retrofit project "was really just to inform others in the industry and academia to learn whether this could be done, how the plant would tolerate blending, and what the effect on emissions would be," he said.

As a public power company that is committed to progress, NYPA is"leading the way in New York by piloting new technologies that can help accelerate New York State's clean energy transition and inform the power industry so that we can move toward a carbon-free economy," he explained. "Decarbonizing the power sector will require a collaborative, multi-pronged approach, including the use of new technologies and additional renewable power resources."

However, NYPA is "committed to retiring those plants whether hydrogen would play a role or not," Driscoll said. "We don't have any current plan to utilize hydrogen in the transition of those plants. We're certainly not ruling anything out, but we have no apparent plan to take that learning from this study and apply it to our gas assets. NYPA is "more focused on battery storage solutions," Driscoll said. NYPA's plans to retire the plants stem from a recent collaborative study, which demonstrated that the frequency and duration of its aeroderivative fleet's run times are projected to decline, allowing for the possibility of full replacement with 4-hour battery storage at each individual site, he said.

A Pioneering Project in Its Own Right

As Alan Ettlinger, senior director ofResearch, Technology Development & Innovation at NYPA, told POWER, the pioneering project's more significant function was to serve as a preliminary test bed to explore hydrogen combustion, a much-hyped pathway to decarbonize gas power. The cross-cutting industry consortium it convened will likely continue to apply lessons learned to further future initiatives, he said.

While New York in July tasked NYPA with leading the hydrogen combustion pilot, GE, as the LM6000's original equipment maker, supplied a hydrogen/natural gas blending system and supported the project's planning and execution. LCRI, led by EPRI, assisted with project design and technical evaluation. Other partners include Sargent & Lundy, the Brentwood plant's original architect engineer, which served as engineer of record for the project. Airgas, an Air Liquide company, supplied the renewable hydrogen for testing, sourcing it from Air Liquide's facility in Bécancour, Québec , which is powered by 99% renewable energy. Fresh Meadow Power, developed the piping system that delivered the hydrogen to the GE-designed mixing skid and, ultimately, into the turbine.

Planning-from initial concept to implementation-took "a little bit over a year," including months of construction with supply chain delays and specialty valves and components, and months of testing preparations. The actual testing period spanned three stages over eight weeks starting in November 2021, Ettlinger said on Friday. "First, we made sure the system was okay-we ran it on natural gas with the modifications we did to the plant, and then we ran it at a lower percentage of hydrogen. Eventually, we did the third test of up to 44%," he said.

Ettlinger noted that the team's original plan was to test hydrogen blends of up to 40%. However, as the team got closer to the end of testing, it had enough hydrogen, and all the systems were performing as or better than expected, he said. The actual testing time that involved injection of hydrogen "was closer to 12 hours," and the third test of a 44% hydrogen volume spanned "probably a couple of hours," he said.

Another Big Demonstration for GE's Gas Turbines

For GE, which rolled out the LM6000 in the early 1990s, the project is another meaningful validation of the important role that hydrogen can play in lowering carbon emissions from power generation-while still providing crucial reliability and flexibility to the changing grid.

GE was part of a team that, in March, conducted another pioneering test to combust an initial blending of 5% hydrogen and 95% natural gas fuel at a GE 7HA.02 gas turbine at the 485-MW Long Ridge Energy Terminal combined cycle power plant in Ohio, a project purpose-built to transition from natural gas to hydrogen blends and ultimately be capable of burning 100% hydrogen.

While GE has combusted hydrogen in several gas turbine models, the Long Ridge test marked the first time a GE HA-class machine combusted hydrogen. GE is also spearheading hydrogen combustion tests in other models. Last year it announced it would pilot an F-class dual-fuel gas and hydrogen plant at EnergyAustralia's existing 316-MW Tallawarra B Power Station in New South Wales, Australia. In September 2021, Territory Generation , a utility in Australia's Northern Territory, separately said that it will install a GE TM2500 trailer-mounted aeroderivative gas turbine at the Channel Island Power Station, outside Darwin, to demonstrate the merits of hydrogen combustion.

The recent test at Brentwood marks a first big step for GE's aeroderivative fleet, but it's also a first triumph for GE's capability to retrofit hydrogen capabilities on its existing fleet, Dr. Jeffrey Goldmeer, director of Emergency Technologies at GE Gas Power told POWER.

Owing to its history of more than 60 years of supplying gas turbine technology, more than half the global gas installed base is from GE. That's roughly 7,000 gas turbines representing more than 800 GW of installed capacity in more than 120 countries.

GE LM6000 aeroderivative gas turbine, which now has the benefit of three decades of operational experience, is a quick-start, highly efficient technology that has widely been deployed for peaking operations. Today, it is highly suited to support renewable balancing. Derived from GE's CF6-80C2 high bypass turbofan aircraft engine, the 46.1-MW simple-cycle, two-shaft turbine model installed at Brentwood is still one of the most fuel-efficient in its size class.

"The LM6000 unit located at NYPA's Brentwood facility is a PC model, which means that it is configured with a singular annular combustor (SAC)," Goldmeer explained. "This is a diffusion combustion system that uses water injection for NOx emission control.Diffusion combustion systems typically also have the ability to operate on higher levels of hydrogen. The LM6000 has the largest installed base of any GE Aeroderivative gas turbine, so these learnings could be applicable to many other plants in the US.In addition, learnings can be shared with other SAC combustors (on LM2500 and LMS100 units), helping GE to accelerate our capability," he said.

Goldmeer said the Brentwood pilot required no modifications to the gas turbine with the exception of instrumentation-temperature and dynamic pressure sensors-which GE added to monitor the combustion system during operation on the hydrogen fuel blends. "During operation on the hydrogen fuel blend, gas turbine operation was stable and the temperature and dynamic pressure data did not indicate any significant changes to gas turbine operation," he noted.

Overall, the test demonstrated that "we can operate on blends of hydrogen and natural gas, and maintain NO x emissions at existing permit levels" with available technologies. At Brentwood, that entails a water-injected combustor and post-combustion after-treatment that includes selective catalytic reduction (SCR), Goldmeer said.

That's highly promising, given that gas power is poised to take on a more significant role in balancing renewables as the energy transition unfolds. "In terms of the larger picture, we will need dispatchable power generation assets to support the electrical grid with increased installation of variable renewable energy systems, i.e. wind and solar," he said. "Fast ramping aeroderivative gas turbines that are capable of operating on increased blends of hydrogen and natural gas could provide dispatchable power with lower carbon emissions that support grid reliability."

LCRI Findings: Emissions Advantages Clear

According to LCRI's key findings unveiled on Friday , the demonstration showed "expected trends," including that CO ₂ emissions decreased as the hydrogen fuel percentages increased. "At 47 MWe, CO ₂ mass emission rates were reduced by approximately 14% at 35% by volume hydrogen cofiring," LCRI's report notes.

Significantly, at steady-state conditions, the plant's current post-combustion emissions controls-including SCR and CO catalyst systems-were able to control stack NO x, CO, and ammonia slip levels below those limited by its New York State Department of Environmental Conservation (DEC) Title V regulatory permit. The demonstration achieved the reductions with "no known detrimental effects on the gas turbine operations," NYPA said. "This result could prove consequential for power plant operators to begin testing and using hydrogen fuels-aiming to lower a facility's carbon output-with minimal or no required modifications to plant systems."

The study also explored impacts of NO x and CO emissions at the gas turbine outlet, upstream of the catalyst systems. It found that at steady water injection rates based on burning natural gas, gas turbine outlet NO x levels increased, and CO levels decreased as the volume of hydrogen in the blended fuel was increased. "By increasing water injection rates less than 20% by volume, [gas turbine] outlet NO x levels were maintained at a constant level as hydrogen fuel increased to greater than 35% by volume," the report says. However, at higher levels of hydrogen, NO x levels increased by up to 24%.

What it means is that hydrogen co-firing could require LM6000 SAC operators to increase water injection almost linearly with hydrogen fuel percentage to maintain steady gas turbine outlet NOx levels. "It is important to note that this NO x increase observation is specific to LM6000 SAC technology and may not apply to dry-low emissions combustors," the report notes.

CO levels also decreased substantially-as much as 88%-as the hydrogen volume increased during testing, even with increasing water injection rates for NO x control. That's a significant finding that implies hydrogen cofiring (depending stack permit requirements) could allow LM6000 units "to operate across a wider load range without CO oxidation catalysts or with reduced volumes of catalyst, potentially lowering capital and [operation and maintenance] costs," the report says.

GE's Goldmeer highlighted this finding as a "great result." It means hydrogen combustion at the LM6000 "has the potential to increase the emissions compliant turndown capability, which is normally limited by CO emissions," he said. GE's engineering teams are now "examining the data to determine what type of commercial offering might be included for plants that have interest in operating on blends of hydrogen and natural gas," he noted.

Another key finding is that the turbine's flame remained stable with increasing hydrogen fuel levels. As pivotally, "no significant changes to [gas turbine] operation were observed as measured by temperature and dynamic pressure sensors (which monitored combustion dynamics) during operation on hydrogen blends." During the demonstration, gas turbine control was stable. It did not experience trips during variations in fuel composition, "provided that the lower heating value (LHV) and specific gravity data were transmitted to control software at the appropriate time."

Challenges: Hydrogen Supply, Project Timing, Equipment Procurement

LCRI also offered some key takeaways for project developers looking to integrate hydrogen into their existing gas turbine fleet.One entails employing a collaborative design approach "early" to help identify and overcome integration challenges. At the Brentwood project, the "large number of teams involved with different design aspects of this project created situations where the design process was progressing at different speeds for each team. This led to rework late in the design process to ensure all the safety and operational requirements were met," the report says. Design concepts must also take into account permit considerations, such as for the National Fire Protection Association, and allow enough time for permit exceptions, it notes.

A second crucial challenge with technical and market implications for gas generators looking at hydrogen as a replacement fuel involves maintaining a stable hydrogen supply. The Brentwood project had adequate volumes of hydrogen, which was trucked in on trailers, for the cumulative 12 hours during which testing was conducted.However, the team grappled with keeping the hydrogen supply stable, requiring constant manual adjustments to the hydrogen regulators located separately on each hydrogen trailer connection. "The team was able to make the system work with significant manual intervention that required constant monitoring and adjustment during the test," the report says. "This would not be practical for normal plant operation."

Other challenges include ensuring adequate natural gas supply pressure, which was inevitable as the hydrogen ratio increased. "As the hydrogen ratio increased, it was necessary to raise the [natural gas] supply pressure. This proved to effectively increase the limit of hydrogen that could be blended with [natural gas]," the report notes.

These issues may be overcome through further study. The most prominent hurdle industry faces if gas-powered hydrogen combustion is to thrive involves procuring adequate large-scale hydrogen supply and equipment to store it. Ettlinger noted the largest U.S. known tank containing hydrogen is NASA's hydrogen storage tank, which holds 1.25 million gallons of liquid hydrogen. "The hydrogen in that tank would only provide four days of supply of hydrogen [at 100%] to Brentwood," he said. "So again, getting back to probably one of the big themes is the supply of hydrogen is not something that can be ignored. It's a significant issue as we move forward."

LCRI also highlighted gaps in the foundational knowledge base for LM6000 cofiring, and issued a few recommendations to satisfy them. A notable recommendation involves hydrogen starts. While the demonstration's gas turbine was always started up on natural gas, LCRI suggested that future investigations should perform starts with increasing hydrogen fuel. That will be key to establishing safe limits for startup, it said.

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NYPA, GE Successfully Pilot Hydrogen Retrofit at Aeroderivative Gas Turbine

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A pioneering GE aeroderivative gas turbine project to demonstrate hydrogen combustion as part of a retrofit at an existing U.S. natural gas power plant has successfully utilized blends of 5% to 44% hydrogen with natural gas-some of the highest volumes of hydrogen blended into a commercially ...