Modeling the Future of Hydrogen and Carbon Dioxide Infrastructure: Webinar by GTI Energy and Carbon Solutions: September 23. 2025: Summary & Review

        This short webinar explored an H2 and CO2 infrastructure buildout scenario for the Appalachian region as the ARCH2 energy hub. It involves regional planning, supply chain modeling, and infrastructure co-optimization. The modeling framework, the area of interest, and data gathering are shown below.

     The Appalachian region’s iron and steel industry can utilize hydrogen. There is a regional abundance of capturable CO2 sources. Salt cavern storage for H2 was modeled. H2 sources modeled include blue and green H2, but since green H2 is so expensive compared to the region’s potential for blue H2, it is thought that blue H2 will predominate.

     The modeling revealed that the project will require up to 6000km of new pipelines by 2050. They note that while that may seem like a lot, it is consistent with rates of natural gas pipeline buildout. These are new pipelines for H2 and CO2. Repurposed natural gas pipelines, where some H2 could be blended with natural gas, however, were not modeled in this analysis, but could be in the future. New pipelines would likely largely follow existing gas pipeline rights-of-way. CO2 storage was modeled in depleted gas reservoirs and in deep saline reservoirs. A wildcard is public opposition to pipelines.

     They compare their models to those of the Low Carbon Resources Initiative (LCRI), noting that LCRI modeled more green H2 than they did. The authors came up with four possible scenarios that are very different depending on different input costs, such as the cost of producing H2.  

Q&A

H2 storage modeling? They considered depleted reservoirs. They identified 23 possible sites and connected all producers and consumers to the storage sites.

CO2 Assets? Used existing data.  H2- blue, used planned facilities, no green H2 planned, used areas w/abundant water

H2 pipeline blending?  It is doable – retrofitting that is, they did not model here, but could in the future.  

CO2 and H2 storage sites – CO2 – western Ohio (saline-Mt. Simon Sandstone?) and western side vs. H2 mainly in the central hub area.

 

 

Beyond Rock Characterization: Deep Learning in Mineral Classification: AAPG Webinar: September 24, 2025: Summary & Review

         This was a detailed webinar about mineralogy via microscopy, which can be a difficult subject, in my opinion. When I was a geology undergrad, we used petrographic microscopes for optical mineralogy, analyzing shadows and grains to arrive at mineralogy. It was not my favorite class because sometimes I just couldn’t tell if the shadows were just right or not. I’m glad that the technology has improved so that machines can do most of that kind of analysis now. In my work in oil and gas, I have come across grain analysis to determine primary grains, cementation, and to attempt to unravel diagenetic alteration history. The goal here was often to understand porosity and permeability development and occlusion, to determine whether the rocks could host hydrocarbon fluids. Of course, the main use of mineralogy is probably in mineral ore analysis for mining minerals and for ore body analysis. This often involves mineral phase analysis.

     This webinar was interesting but also difficult for me since I have not used any of these newer techniques. SEM software has been in use for 40 years, just beginning to be used when I was an undergrad. Now. It is being replaced by new kinds of software and analysis. Image segmentation is a new application where machine learning has excelled. When I was an undergrad, I worked for a time in a lab with two paleobotanists. One thing we did was to make acetate peels of Pennsylvanian fossils known as ‘coal balls’, which uniquely preserve, due to the presence of calcite, some of the tissue structures of ancient land plants. The goal was to get a 3D analysis of these fossils, which were inside the rock, by taking thin peels of the rock and making thin sections that could then be stacked to get a 3D image of the fossil. I think that would be considered a crude method of image segmentation. Microscopy workflows are given below.

1)        Multi-platform -  

2)        Multi-modal – lots of different techniques.

3)        Multi-scale microscopy 

4)        Multi-dimensional 1D-5D imagery.  Image segmentation allows things to be measured precisely. Electron, light, and X-ray microscopy are the means.

     Deep learning neural networking is a subset of machine learning. It is based on computational algorithms. It enables better image segmentation.

     Mineralogy software: SEM software has been used for 40 years. Crushing rocks uses 5% of global electricity. Automated mineral classification: Energy-dispersive spectroscopy (EDS) is the main method. Automated mineralogy is an old process that is being replaced. SEM and analysis, which is low precision (range of elemental concentrations), is being replaced by Phase Identifier AI, which takes segmented maps with xyz coordinates to get distributions of elements in a sample via neural networks, from elements to minerals. It can interact with it depending on what you are looking for. It is a data processing system. How is the phase identifier AI unique?  Image – explore – discover is the workflow. It can be used for particle analysis, rock & core analysis, textural analysis, concretes, factory materials, etc.

     Light microscopy via a petrographic microscope. Semantic vs. instance segmentation: Semantic is traditional and often not very useful. Instance segmentation is far more useful and utilizes deep learning. An example of marble sample segmentation gives a single image vs. instance segmentation, which gives different grain sizes, textures, and inclusions that can be analyzed. Instance segmentation can better distinguish grains and overgrowths. It is better for shape analysis and can be a powerful tool for geologists. Neural networks do a better job of segmentation analysis than previous methods.

     X-ray Microscopy – Zeiss Phase identifier 3D – quantitative analysis – indirect and direct – data is simulated in 3D. Quantitative reconstruction reduces noise. Histogram peaks are used in reconstruction. It can yield better mineral detail. It can handle more complex minerals. Automated mineral classification in 3D. CT scans are used in X-ray microscopy, and one can produce moving 3D simulations.

     Potential applications in industry and academia. In industry, low concentration gold and ore body research can benefit. It leads to better petrology.

The workflow he gives is image – explore – discover. Deep learning happens in the explore phase.

 

Q&A

References? SEM info is very new, so not much.

How can the approach be validated? EDS data – can be fed in and automatically organized. 3D and 2D comparison was done by them, not perfect, but it validates. Dating and sequencing natural processes can be untangled. Things like diagenesis and dissolution can be analyzed. Deep learning allows the removal of subjective decisions. People do things somewhat differently in their mineralogy analysis, while with deep learning, all will be the same and more consistent.

Can it be used for clay minerals (very fine-grained)? One can make maps finer, but it can be risky due to overlapping spots. It can be useful for fine-grained analysis, with some limitations not really due to software. It really depends on the resolution of the data acquired.

Sample preparation? For EDS, good data acquisition requires good sample preparation.   

  

 

The State of Utah’s Environmental Dispute with Company U.S. Magnesium, the Company’s Chapter 11 Filing, and the Implications for Domestic Magnesium Supply

     Magnesium is an important metal. It is essential in industry and for human nutrition. It has many uses. It is used in electronics and in the aircraft and automotive industries. It is the third most used structural metal after iron and aluminum. Most magnesium is produced by China and Russia. The U.S. government considers magnesium to be a critical mineral.  

     The U.S. produces about 7% of global magnesium as of 2017, but there is only one company in the U.S. that produces it – U.S. Magnesium. It is produced in the Great Salt Lake in Utah. 

     The company is currently in an environmental dispute with the State of Utah.

     According to the company’s website:

“US Magnesium is a world leader in the production and management of primary magnesium through its active participation in all major aspects of the industry: technology, refining, electrolysis and recycling.”

“US Magnesium is the largest producer of primary magnesium in North America, operating facilities on the Great Salt Lake where magnesium has been produced since 1972. The Company has repeatedly made significant capital investments to increase magnesium production capacity, while concurrently reducing the environmental footprint.”

“US Magnesium is committed to operating the facility in an environmentally responsible manner and is continually developing ways to positively impact the environment and local community. Environmental commitment is highlighted by the development and utilization of state-of-the-art magnesium electrolysis technology, minimizing both air emissions and energy requirements, alongside the extensive use of solar energy.”

     Leia Larsen of the Salt Lake Tribune explains the company’s environmental issues:

“US Magnesium’s production plant has been mothballed for years as it battles environmental regulatory actions, equipment failures, receding Great Salt Lake levels and litigation from the state of Utah, which is trying to revoke the lease that allows the company to operate.”

“Still, it has continued to pump a massive amount of water from the Great Salt Lake.”

“US Magnesium diverts water from the Great Salt Lake into solar evaporation ponds in Tooele County, where it concentrates the brine to extract magnesium chloride salt. Its Rowley plant then refined the salt into pure magnesium. The process produced corrosive waste and toxic emissions, which the company released into the air and stored on the ground — allegedly including on the state-owned lakebed — for decades.”

     The state of Utah’s regulatory agency issued an order in August for the company to cease water pumping and extraction operations. The company has been fined for its environmental non-compliance issues. It began building a large retaining wall to prevent post-production pollution from entering the Great Salt Lake, but stopped due to financial problems. The company produces both magnesium and sodium chloride for Cargill. It attempted to pivot to lithium production from its waste piles, investing $400 million when the price for lithium was really high a few years ago, but it was hurt when the inflated lithium price dropped. This failure resulted in the idling of the lithium production and loss of 85% of the company’s workforce. It was a case of bad market timing. In 2024, the Utah Division of Forestry, Fire, and State Lands moved to revoke US Magnesium’s 64-year-old lease, citing the violations listed below.

     U.S. EPA violations were listed as well, including failing to build a salt cap to contain pollution from an old waste pond and failing to retrofit its current pond. 

     Other companies have sued the company for failing to deliver contracted magnesium volumes. The violations and the company’s insistence that they are not polluting the environment have ballooned into a bitter dispute with the state, which is ready to revoke the company’s leases.

     U.S. Magnesium recently filed for Chapter 11 bankruptcy protection. This is mainly due to its financial issues, its failed lithium pivot,  and its financial inability to comply with Utah’s environmental laws. Low magnesium commodity prices amid abundant global supplies are other contributory issues. The filing occurred on September 10, 2025, and part of the company's official statement is reproduced below:

“Over the past decade, however, the company has confronted a series of profound disruptions: global oversupply and offshore dumping that drove prices to historic lows; the 2016 closure of a major customer, Allegheny Technologies Rowley plant; and essential equipment failures coupled with the COVID-19 pandemic, which triggered force majeure events and required us to idle magnesium operations.”

“In response, we pursued diversification into lithium carbonate production, building a new lithium carbonate plant, the first of its kind in the United States, applying advanced technology to our raw material feedstock.”

“Through support from our ownership, we invested more than $400 million in support of this effort and USM’s operations. However, an 80% decline in lithium carbonate prices and operational challenges coupled with changing regional water policies and an ongoing regulatory assault over the last two and a half years has compelled us to pause these operations."

 

The Pollution Associated with U.S. Magnesium’s Operations on the Great Salt Lake

     In 2009, U.S. Magnesium’s brine mining operation was deemed an EPA Superfund site. This gives it some national priority and additional funding for cleanup. The company built canals that connect to the lake to access the saltwater, but as the lake continues to dry up (it will continue to dry up since it is considered to be a terminal lake with no outlets and no major inlets), the company sought to extend those canals for better access. Their application was denied. The company concentrates the salts in the brine via solar evaporation ponds, after which there is further processing to remove impurities. One of the results of processing is the production of dioxins, which enter the watershed and the air. The contaminants of concern are listed and explained below by the Friends of Great Salt Lake, which has been advocating for cleanup.

Magnesium’s Status as a U.S. Critical Mineral

     One open question is that since the U.S. has declared magnesium to be a critical mineral, how will the bankruptcy, the disruption of operations, and the potential for total failure affect U.S. magnesium production, domestic supply, and dependence on foreign sources, particularly China? According to the DOE’s energy.gov:

"Over 80% of our nation’s supply of critical minerals comes from foreign sources, and the United States currently imports over half of its consumption of 43 of the 50 critical minerals and metals."

References:

 

Utah demands US Magnesium stop pumping massive amounts of water from the Great Salt Lake: The company is drowning in debt, and the state has resumed actions to revoke its decades-old lease. Leia Larsen. The Salt Lake Tribune. September 2, 2025. Utah demands US Magnesium stop siphoning Great Salt Lake water

Essential US manufacturing company files Chapter 11 bankruptcy. Daniel Kline. The Street. September 20, 2025. Essential US manufacturing company files Chapter 11 bankruptcy

US Magnesium. Website. US Magnesium LLC – US Magnesium is a world leader in the production and management of primary magnesium through its active participation in all major aspects of the industry: technology, refining, electrolysis and recycling.

Magnesium. Wikipedia. Magnesium - Wikipedia

What's next for the US Magnesium Superfund Site? Draft Story Map. Friends of Great Salt Lake, September 22, 2025. What's next for the US Magnesium Superfund Site?

 

Gas Turbine Deployment Will Grow Regardless of Future Energy Mix, Effects of Lower Utilization Rates on Turbine Components, and Long Wait Times Likely to Continue

      There have been long waiting times for gas turbines for a few years now. Just a few years ago, back around 2018, the demand for gas turbines was low as new gas plants were not being built, and it was thought that not many more would be built. However, as demand began to build for renewables back-up, electrification, and later for new AI data center buildout, the demand suddenly skyrocketed, and the industry was not ready for it. This led to the backlog that remains today and is expected to continue as more data center plans are announced. It is suspected that not all announced data centers will be built, but enough will likely be built to keep the delay going for longer than originally anticipated. It may take a few more years for the industry to catch up to normal wait times. Current wait times of 4-7 years are common now, and some delays are expected for new orders up to 2030.

     Gas turbines will be needed far into the future, not only for natural gas, but for other fuels as well, particularly low-carbon fuels, including hydrogen, ammonia, RNG, and even renewable diesel. Small gas turbines will also be used in Brayton (Allam) Cycle gas plants, utilizing CO2 to spin them. Currently, the U.S. has about 7000 gas turbines in operation. These must be maintained, and the maintenance requirements differ depending on how the turbines are used, typically, whether they are used for baseload power or for peaking. According to Aad den Elzen, the vice president of power generation and strategic growth at Solar Turbines, a Caterpillar Company:

“The lead times even for small turbines are increasing,” den Elzen mentioned. “Basically, we are all depending on the same supply chain. The same suppliers are pushed for more by the power generation and the aerospace industries, but all of us are spending a lot of time and energy to understand the full supply chain until every last bottleneck is opened.”     

     In January 2025, GE Vernova, a major U.S. gas turbine manufacturer, announced that it would invest $600 million in new manufacturing facilities for gas turbines. They expect demand to remain high for the foreseeable future. Burning hydrogen to spin gas turbines is still in the beginning stages and is expected to increase in the next decade and beyond. Hydrogen co-firing and blending projects continue to be developed. Turbines are being developed capable of burning 100% hydrogen, but there is currently not enough hydrogen supply to support many of those. There are other reasons as well why blending is more likely. Carbon capture can be enhanced as well by altering gas turbines, as den Elzin notes. His company has “built and operated an exhaust gas recirculation (EGR) system on one of its gas turbines and demonstrated steady operation, increasing CO2 waste from 3% to 6-7%, which would make carbon capture more effective and affordable.” 

     GE Vernova has also done some work outfitting their turbines for decarbonization via hydrogen, as reported by Power Technology:

“GE Vernova performed full-scale validation of its 100% hydrogen-fueled DLN Combustor last year, with emissions below 25ppm NOx. The innovation is based on the company’s micro-mixer technology designs tweaked and retweaked over 20+ years. The project’s genesis came back in 2005 via a collaboration with the Department of Energy- GE Vernova expects to bring a commercial offering to market as early as 2026.”

“This is another step toward solving the hydrogen challenge,” Codron declared. “This is a technology we’re going to position as a potential solution in the energy transition.”

    GE Vernova is providing the turbine technology for the Net Zero Teesside Power (NZT Power) project in the United Kingdom, which is expected to be the world’s first gas-fired power station with carbon capture and storage. The project will include a heat recovery steam generator and an EGR system that will recycle CO2-rich flue gas back into the turbine inlet to increase CO2 recovery and reduce solvent use. 

     Below are GE Vernova's offerings of different-sized simple-cycle gas combustion turbines.

     Gas turbines continue to make efficiency improvements. According to engineering company Prismecs:

“Advanced blade designs and sophisticated cooling techniques also reduce operational inefficiencies, contributing to lower fuel consumption, higher output, and improved performance. These innovations in efficiency are making gas turbines more cost-effective and sustainable, enabling them to meet the evolving energy demands of industrial applications.”

     Gas turbine design improvements are also leading to more mitigation of NOx and other pollutants:

“By incorporating cutting-edge combustion technologies, such as low-emission combustion chambers and catalytic converters, modern gas turbines significantly reduce harmful NOx and CO2 emissions, making them much cleaner and more environmentally friendly.”

     Modern gas turbines are digitalized, equipped with advanced sensors, data analytics, and machine learning algorithms, which enable real-time monitoring, supporting turbine health and performance optimization. Digital twinning is often used for testing and analysis. Micro gas turbines are commonly used in Combined Heat & Power (CHP) deployments, which means they are deployable in remote locations and for behind-the-meter applications such as small data centers. They can also be used for emergency power. Aero-derivative gas turbines provide propulsion for aircraft. They, too, can be made more efficient with incremental improvements. GE Vernov also notes the use of its gas turbines for gas-to-power operations that capture flare gas from oil wells and convert it to power. These ops make local power or power Bitcoin mining.

     Siemens Energy lists three ways that gas turbines support decarbonization: 1) replacing coal and oil generation units, 2) providing rotating masses to maintain grid inertia, especially where inverter-based resources are abundant, and 3) direct decarbonization via CCS and/or hydrogen.

     Simple cycle combustion turbine systems can be designed differently to better optimize their power usage and to support their own O&M needs. GE Vernova touts its Axial Fuel Staging technology, described below, as a means to increase flexibility, lower emissions, and reduce maintenance and fuel costs. They also offer axial fuel staging as an upgrade to some of their turbine models.

     Assuming a turbine is acquired, installation time for gas turbine plants is fast. Peaking plants can ramp power up and down quickly as needed, but this can create special O&M needs. Steve Hiner of the Parker Filtration Group writes about these O&M challenges for Gas Processing and LNG:

“One of the most profound changes affecting gas turbine operation has been the diminishing requirement for base load capacity. In previous decades, gas turbines would have typically operated at full power for ~8,000 hr or more per year and were only shut down for periodic servicing. The rapid changes of the last decade have left this desirable scenario far in the distant past.”

“Renewables now get priority dispatch, leaving gas turbines to pick up the slack only when there is insufficient wind and solar to meet demand. As so-called peaking units, most of these machines switch on and off multiple times per day and typically ramp up and down during periods of operation. This switch for gas turbines typically sees machines operate for hundreds of hours a year rather than thousands and has thrown the conventional economic and business cases for gas turbines into disarray. So, while gas turbines are certainly here to stay and will form a significant part of the energy mix even once the clean energy transition has been completed, new operating models place far greater emphasis on operational costs (OPEX) than ever before as owners look to balance the books on far fewer operating hours.”

     The company Hiner works for, the Parker Filtration Group, provides air inlet filtration units for gas turbines. Hiner notes that filter lifespans differ based on usage levels. While baseload power gas turbines lead to pressure loss due to dust clogging through frequent operating times. Instead, he says:

“…filter elements may instead last many years before plugging significantly increases their pressure drop. Under these conditions, filter longevity may be determined by other factors and could potentially become a significant OPEX in today’s operating regimes.”

     As a result of lower operating times, filter lifespans have increased. However, that can lead to other filter issues. When filter elements are exposed to corrosion agents such as saltwater, the formation of rust is accelerated. In response to this threat, the author’s company uses G90 galvanized steel instead of G60. The frames are also powder-coated to protect against corrosion. 

     Hiner also points out similar design improvements that can increase the longevity of other parts of the gas turbine system when they are used in a low capacity factor peaking mode.  

“Additionally, these considerations extend beyond the primary filtration system—each system usually contains other filters and additional components such as evaporative coolers that are deployed in many gas turbines. Materials choices such as 316 stainless-steel frames, plastic framing for pre-filters and robust cooling media are all built into a system that supports the new reality of gas turbine operations.”

     Gas turbines are here to stay and will likely continue to evolve to attain better efficiency and improved longevity of components.

 

    

 

 

References:

 

The future of gas turbines in the green revolution. Steve Hiner. Gas Processing & LNG. June 30, 2025. The future of gas turbines in the green revolution | Gas Processing & LNG

How do gas turbines fit into the clean energy transition? Paul Gerke. Power Engineering. February 12, 2025. How do gas turbines fit into the clean energy transition?

What is the Future of Gas Turbines in Innovation and Prospects? Prismecs. February 20, 2024. What is the Future of Gas Turbines in Innovation and Prospects?

Flexible gas turbine fuel offerings. GE Vernova. Flexible Fuel Offerings | GE Vernova

Gas-fired power plants fuel the energy transition. Gas-fired power plants can deliver a fast path to low-carbon energy systems today – plus, they can be fully decarbonized. Siemens Energy. Natural Gas-Fired Power Plants I Energy Transition

Flexibility blog: Why is gas plant flexibility so important now and in the future? Bob Bellis. September 27, 2023. GE Vernova. Why Gas Plant Flexibility Is Important | GE Vernova

Rising Electricity Prices Have Nothing to Do with Renewables Incentive Rollbacks or Trump Administration Policies

     I recall reading a news story a few weeks ago about a Democratic strategy to blame rising electricity prices on Trump and his policies. The strategy is not based on reality. The last thing the Dems need is another bumbling energy policy rooted in misconceptions and a lack of understanding of energy markets and technologies. The Trump policies that drop subsidies for wind, solar, batteries, and other clean tech have not even taken full effect. The stopping of wind power projects by the Trump administration will likely lead to slightly lower power prices compared to developing the projects, several of which have contracted for power prices exceeding whole power prices by concerning magnitudes It is essentially guaranteed that the offshore wind projects, if built and subsided would be paid by consumers, first as subsidies paid by taxpayers and next by those same taxpayers as power ratepayers paying higher rates. Electricity rates are always higher where grid penetration of wind, solar, and batteries is highest. High upfront costs are one reason. Renewables proponents always point out that power delivery prices are lowest for renewables. This is true, but only when they are available. Delivering the power may be cheaper, but building it, integrating it, and managing it is not cheaper.    

     The argument that rising electricity prices are due to renewables incentive rollbacks or Trump administration policies is an absurd one. The Dems need to abandon this tack if they want to be taken seriously about energy. While I think Rahm Emanuel had some great ideas about foreign policy as ambassador to Japan, his recent op ed in the Wall Street Journal, titled: ‘Rising Electricity Price? Thank Trump,' is misinformed and simply incorrect. While I only got the opening snippet on my side of the pay wall, I also got the opening snippet of the Journal’s rebuttal, where it was noted that Emanuel’s op-ed:

“…demonstrates an ignorance of basic economics. Mr. Emanuel claims that subsidies paid to green-energy providers reduce the cost of electricity. The opposite is true. The billions of dollars paid out to green-energy providers—almost $70 billion for wind and solar alone between 2020 and 2023—don’t come down from on-high. Taxpayers foot the bill.”

     When the so-called Big Beautiful Bill was passed just weeks ago, some activists began saying that it would increase the cost of electricity, an assertion not based in fact. The bill actually keeps a lot of Biden’s subsidies aside from those on EVs, solar, and wind power. Personally, I think the subsidies for solar and wind should continue or be reduced, and those for EVs should have been reduced rather than eliminated.

     Robert Bryce called Emanuel’s op-ed silliness and “a load of flapdoodle.” While power prices went up an average of 10% since January, pretty much all of those increases were already in the works and expected in 2024. Bryce goes on to cite public opposition to wind and solar projects, which has led some Democratic states to override local zoning ordinances against such projects. He also points out ill-advised plans to close more coal plants by 2030 in light of increasing power demand and uncertain supply.

     Attempts to pin rising power prices on Trump will backfire as they should. Until the Dems can be realistic about energy economics and technological capabilities and limitations, their policy positions about energy will be hard to take seriously. Energy idealism has created problems, including high power costs. Energy realism is the solution, and the Dems better get with it.

    

 

References:

 

Mitsubishi Says Sayonara To Offshore Wind, Rahm’s Silliness, XOM Spotlights Power Demand, & Gratitude For One Year With Paid Subscribers On Substack: Four (free) notes on a Sunday afternoon. Robert Bryce. September 21, 2025. Mitsubishi Says Sayonara To Offshore Wind, Rahm’s Silliness, XOM Spotlights Power Demand, & Gratitude For One Year With Paid Subscribers On Substack

Rising Electricity Price? Thank Trump: Bigger bills are a direct result of the One Big Beautiful Bill Act, which cut green-energy subsidies. Rahm Emmanuel. Wall Street Journal. September 17, 2025. Rising Electricity Price? Thank Trump - WSJ

Big Electric Bill? Thank the Energy Subsidies. Wall Street Journal. September 21, 2025. Big Electric Bill? Thank the Energy Subsidies - WSJ

 

 

Liquid Air Energy Storage, aka. Cryogenic Energy Storage, aka. Air Liquefaction: Potential for Long Duration Storage and Renewables Integration, and New Korean Design Innovations

     If developed further, liquid air energy storage (LAES), also known as cryogenic energy storage (CES), could become the lowest-cost way to store excess renewables generation on power grids. Like many other clean energy technologies, upfront cost is a big hurdle. However, new analysis suggests it could be the lowest-cost option for the long-duration grid storage needed for renewable energy integration.

     According to Wikipedia:

“Cryogenic energy storage (CES) is the use of low-temperature (cryogenic) liquids such as liquid air or liquid nitrogen to store energy. The technology is primarily used for the large-scale storage of electricity.”

     The process utilizes the Claude Cycle, which is only 25% efficient, but efficiency is increased to 50% by adding cold storage and reusing the cold for the next refrigeration cycle. When the heat is acquired through process heat recovery, efficiency as high as 70% has been claimed. Air is cooled to -196 degrees Celsius, the point at which it becomes liquified. When it is re-gasified, the pressure increases so that it can be used to spin turbines. At gasification, the air rapidly expands to about 700 times its liquid volume, and the pressure drives power turbines.

     Cryogenic energy storage can be constructed just about anywhere, in contrast to pumped hydro energy storage and compressed air energy storage, which require specific geography for pumped hydro and existing mines, wells, or caverns for compressed air. CES/LAES also uses off-the-shelf components, such as air-condensing technologies that have long been part of the chemicals industry.

CES/LAES involves cooling air until it liquifies, then storing it in insulated and pressurized tanks. The air is re-gasified when needed to run turbines for power.

     An article in Linquip Tech News explains the processes in an LAES system:

“A typical LAES system follows a three-step process. The charging process is the first step, in which excess (cheap) electrical energy is used to clean, compress, and liquefy air. Step 2 is the storing procedure, which involves storing the liquefied air from Step 1 in an insulated tank at 196 °C and at about ambient pressure. Step 3 is the discharge process, which recovers energy by pumping, warming, and expanding it in order to regenerate power during peak hours when electricity is in high demand and expensive. Step 2 also comprises the storage of heat from Step 1’s air compression process and high-grade cold energy from Step 3’s warming process. The stored heat and cold energy can be employed in Steps 3 and 1 to improve the power output and minimize the liquefaction process’s energy consumption, respectively.”

     The article also acknowledges the challenges of LAES and the opportunities to hybridize it with things like process heat recovery from power plants and industry. It can be integrated with natural gas peaking plants. It can be integrated with concentrated solar power plants. It can also be integrated with the LNG re-gasification process, which can also be integrated with carbon capture, as I noted in a recent post about LNG-Coupled Near-Cryogenic Direct Air Carbon Capture Via LNG Regasification and Physisorbents. The cold energy could be used for local cooling, and it could receive local waste heat. 

     Below are basic layouts and schematics for different LAES configurations, integrating with a gas plant, a solar thermal plant, and a nuclear plant.

  

     Consumer Energy Center describes the steps of LAES, basically charging, storage, and discharging, as follows:

     Consumer Energy Center touts LAES as a good method of grid storage, noting below its advantages and disadvantages.

     The Linquip Tech News article goes on to make technical and economic comparisons of LAES with compressed air storage, pumped hydro storage, and other potential grid storage methods such as flow batteries and hydrogen, which are given in the sections below.

 

Technical Comparisons

“When compared to connected energy storage systems, LAES, like pumped hydro and compressed air energy storage technologies, has a long discharge time (hours). The power discharge rate, on the other hand, is determined by the scalability of the energy storage technologies’ power-regenerating unit. Pumped hydro storage makes use of hydraulic turbines to regenerate electricity and so has the highest power discharge rate (up to several gigawatts). The power rate of compressed air energy storage is in the hundreds of megawatts range due to the utilization of typical gas turbines or steam turbines for power regeneration.”

“The power rate of a LAES turbine is expected to be slightly lower than compressed air energy storage, but it can still reach hundreds of megawatts. An LAES turbine is similar to a gas turbine but has a lower expansion temperature, so the power rate is expected to be slightly lower than compressed air energy storage. However, because flow batteries and hydrogen storage are difficult to scale, their power output is estimated to be less than a megawatt.”

     Pumped hydro has a round-trip efficiency between 65% and 85%. Compressed air is at 40% and LAES averages 50-60% with up to 70% possible utilizing waste heat recovery. Thus, pumped hydro is a little more efficient but much more restricted on where it can be built.

 

Environmental Comparisons

     LAES/CES is difficult to beat in environmental comparisons if powered with renewables, as is surmised. Pumped hydro destroys habitats and generates methane. Lithium and other battery chemistries are heavily reliant on mining. LAES uses air as the medium, which is readily available and environmentally benign.  

 

Economic Comparisons (and Viability)

     As detailed below, the capital costs of LAES, pumped hydro, compressed air, and flow batteries are similar, but flow batteries have much shorter life spans than the other three.

“The cost of charging and discharging devices is closely related to the capital costs per unit of power. High power capital costs (>$10,000 kW–1) characterize hydrogen storage. Pumped hydro storage, flow batteries, and compressed air energy storage, and LAES all have around the same power capital costs (between $400 and 2000 kW-1). Because of the effect of discharge durations, capital costs per unit of energy cannot be utilized to accurately measure the economic performance of energy storage devices.”

“The capital cost of storage systems like a dam for pumped hydro storage and a storage tank for LAES is an alternate measure. Because the energy carriers are either flammable or at high pressure, hydrogen storage and compressed air energy storage are projected to have the greatest storage costs. Due to its low energy density, pumped hydro storage has a cheap cost. Despite the fact that insulation is required, LAES and flow batteries offer the lowest cost.”

“Mechanical-based systems such as pumped hydro storage, compressed air energy storage, and LAES should have a lifecycle of 20–60 years because they are based on traditional mechanical engineering, and the lifecycle is mostly governed by the lifetime of mechanical components. The lifespan of hydrogen storage and flow batteries, on the other hand, are predicted to be around 5–15 years.”

     With all economic factors combined, LAES may be the cheapest long-duration energy storage option for power grid storage operations.

     According to Consumer Energy Center, LAES continues to see incremental improvements:

“Innovations such as enhanced insulation techniques and more efficient liquefaction processes are improving overall performance while reducing costs. This evolution creates a pathway for a more resilient infrastructure capable of responding effectively to fluctuations in energy supply and demand.”

     Researchers at MIT did an economic feasibility analysis for LAES. Their findings were published in the journal Energy. They modeled net present value (NPV) at a discount rate of 7%.

“They found that under some of the scenarios they modeled, LAES could be economically viable in certain locations. Sensitivity analyses showed that policies providing a subsidy on capital expenses could make LAES systems economically viable in many locations. Further calculations showed that the cost of storing a given amount of electricity with LAES would be lower than with more familiar systems such as pumped hydro and lithium-ion batteries. They conclude that LAES holds promise as a means of providing critically needed long-duration storage when future power grids are decarbonized and dominated by intermittent renewable sources of electricity.”

     The modeling requires predicting how LAES will compete in future markets when power demand exceeds supply and predicting prices when supply exceeds demand. They modeled 18 U.S. regions and eight decarbonization scenarios. Unfortunately, economic viability only occurred in the most aggressive decarbonization scenarios, which are also considered to be the least likely, and only for two states, Florida and Texas. They analyzed time periods of one day, one week, and one month, noting that weekly storage is more economically viable than monthly storage. They also noted that economic incentives could push projects into economic viability. They calculated a levelized cost of storage (LCOS) of $60 per MWh, about one third that of lithium-ion storage, and half that of pumped hydro. According to one of the paper’s authors, Shaylin A. Cetegen, a PhD candidate in the MIT Department of Chemical Engineering:

“While LAES systems may not be economically viable from an investment perspective today, that doesn’t mean they won’t be implemented in the future. With limited options for grid-scale storage expansion and the growing need for storage technologies to ensure energy security, if we can't find economically viable alternatives, we’ll likely have to turn to least-cost solutions to meet storage needs. This is why the story of liquid air storage is far from over. We believe our findings justify the continued exploration of LAES as a key energy storage solution for the future.”

     An article in Power Technology notes that LAES projects are represented in far less than 1% of upcoming thermal energy storage projects.

“We [LAES] also pull very mature components from the existing oil and gas supply chain; all we’re doing is configuring them in a different way,” LAES developer Highview Power’s business development director Mark Vyvyan-Robinson tells Power Technology.

     A 2025 paper in the Journal of Energy Storage found that hybridizing LAES with natural gas in a configuration they call LAES with added gas firing, or LAES-AF, could be economically viable, but only under high natural gas price scenarios that are not reasonable for places like the U.S. Even at maximum theoretical efficiency, it is hard to find economic viability. Thus, as one researcher put it: “Constructability cost can be a more important metric than efficiency.” The bottom line is that LAES will likely remain expensive and a niche technology for the foreseeable future, unless more cost improvements are found.

     Even with waste heat utilization, cooling recycling and efficiency gains, and hybridization with natural gas or solar thermal, and some subsidization, the economics are challenging. Without them, however, they are more challenging.

 

Korean Researchers Develop LAES Innovations

     Despite the challenges just mentioned, researchers at the Korea Institute of Machinery and Materials (KIMM), under the National Research Council of Science and Technology (NST), have developed some key LAES technologies and innovations. The project is known as "Development of Core Machinery Technologies for Large-Scale Liquid Air Energy Storage."

     An article in TechXplore explains the innovations, which include a newly designed turbo expander and a cold box with improved heat loss resistance:

“The KIMM research team, led by Principal Researcher Dr. Jun Young Park at the Department of Energy Storage Systems, independently designed and manufactured a turbo expander and cold box, achieving Korea's first successful air liquefaction test for energy storage. The system can produce up to 10 tons of liquid air per day, providing a foundation for future commercialization.”

“KIMM's innovations include a high-speed turbo expander with static gas bearings for stable rotation exceeding 100,000 RPM and a hollow shaft with thermal insulation that prevents heat ingress at ambient temperature. The cold box, employing multi-layer insulation and an ultra-high vacuum to reduce heat ingress, also recycles cold energy from power generation for more efficient liquefaction.”

"Large-scale energy storage is essential for Korea's renewable energy future," said Principal Researcher Jun Young Park. "Our achievement positions LAES as a viable, eco-friendly solution, free from geographical limitations, and accelerates the pathway to commercialization."

     Neetika Walter at Interesting Engineering calls the Korean innovations bottling air, or rather, bottling electricity.

     The UK has the world's largest LAES project deployment, According to the article in Power Technology:

"In Manchester, UK, Highview operates the world’s first commercial-scale industrial LAES plant. The operational plant has a 50MW charge/discharge rate and 300MWh capacity, but Highview’s four planned facilities would each have a much larger storage capacity of 2.5GWh. These would represent more than 10% of the country’s non-battery storage, and a much larger move toward LAES than seen anywhere else in the world."

"The UK developments are enabled by the country’s “cap and floor” pricing scheme, which eliminates the cost effects of extreme prices for operators. Vyvyan-Robinson says this elimination of risk is essential to obtaining finance for any country eyeing LAES: “It’s difficult for a bank to take a view on future revenues, and therefore to make projects ‘bankable’. You need some support around the revenues, and ‘cap and floor’ allows you to raise finance.” 

 

 

  

 

   

References:

 

Cryogenic energy storage. Wikipedia. Cryogenic energy storage - Wikipedia

What is Liquid Air Energy Storage? By Linquip Team. Last Updated: March 29, 2023. Linquip Tech News. Liquid Air Energy Storage: Efficiency & Costs | Linquip

Liquid Air Energy Storage Overview. Greg M. Consumer Energy Center. March 28, 2025. Liquid Air Energy Storage: Unlocking the Power of the Atmosphere

Researchers develop core technologies for liquid air energy storage to support Korea's energy superhighway. Science X staff. Tech Xplore. September 11, 2025. Researchers develop core technologies for liquid air energy storage to support Korea's energy superhighway

Using liquid air for grid-scale energy storage: New research finds liquid air energy storage could be the lowest-cost option for ensuring a continuous power supply on a future grid dominated by carbon-free but intermittent sources of electricity. Nancy W. Stauffer. MIT Energy Initiative. April 10, 2025. Using liquid air for grid-scale energy storage | MIT News | Massachusetts Institute of Technology

Explainer: does liquid air energy storage hold promise? The world’s most available substance could unlock a new opportunity for long-duration energy storage. Jackie Park and Matt Farmer. Power Technology. July 18, 2025. Explainer: does liquid air energy storage hold promise?

New liquid air storage system bottles electricity on demand, producing 10 tons daily. Neetika Walter. Interesting Engineering. September 12, 2025. New liquid air storage system bottles electricity on demand, producing 10 tons daily

Evaluating economic feasibility of liquid air energy storage systems in future US electricity markets. Shaylin A. Cetegen, Truls Gundersen, and Paul I. Barton. Energy. Volume 321, 15 April 2025, 135447. Evaluating economic feasibility of liquid air energy storage systems in future US electricity markets - ScienceDirect

Benchmarking of liquid air energy storage with and without added firing against batteries and gas-fired power plants.Carlos Arnaiz del Pozo, Ángel Jiménez Álvaro, and Schalk Cloete. Journal of Energy Storage. Volume 106, 15 January 2025, 114800. Benchmarking of liquid air energy storage with and without added firing against batteries and gas-fired power plants - ScienceDirect