Hydrogen storage

Long-duration H2 storage in solution-mined salt caverns—Part 2

L. J. EVANS, Global Gas Group, Houston, Texas and T. SHAW, LK Energy, Houston, Texas 

Part 1 of this article, published in the Q3 issue, discussed the variety of methods available for storing H₂, the need for dispatchable energy and the benefits of having a mix of storage alternatives during seasonal events. The final segment of this article series examines the environmental impacts and sustainability of H₂ storage, as well as opportunities for process and facility integration.

Environmental considerations

Environmental, social, and corporate governance (ESG) is an increasingly important aspect of corporate strategies and investment decisions. The authors have considered the environmental impacts and sustainability of H₂ energy storage (HES), the specifics of which are dependent on the combustion generation technology chosen.

Air emissions. The only emission from the electrolyzer is free O₂ resulting from the splitting of the water molecule. Fuel cells, likewise, do not have any emissions other than fugitive water vapor. Combustion technologies are associated with CO₂, NO_X, and thermal emissions.

CO₂. When running on 100% H₂, an HES plant using a combustion technology has no CO₂ emissions. If blending with methane during ramp-up is required, then 10 vol%–15 vol% methane may be consumed for 3 min–10 min per cold start.

CO₂ reduction when cofiring with natural gas is nonlinear. When paired with an existing gas-fired turbine, assuming a maximum H₂ content of 40%, cofueling with H₂ reduces the CO₂ emissions by up to 20%. Repowering with high H₂ (> 80 vol%) can lower CO₂ emissions by 50%–100%.

NO_X. Due to the high flame temperature of H₂, water injection cooling may be required for combustion generation, which increases the rate of NO_X formation. Typically, emissions guarantee for high-H₂ fuels is > 25 ppm NO_X, but this can be reduced to 15 ppm NO_X with advanced emissions controls. The primary impact of higher NO_X formation is the additional capital and operating costs.

Thermal emissions. H₂ burns at a substantially higher flame temperature than natural gas. As a result, ambient exhaust temperature is higher than a natural gas plant. Potential impacts are site specific, but rarely adverse, and can be mitigated by waste heat recovery and/or exhaust cooling.

Water. Water is consumed during both charging and discharging. Demineralized water is required for both electrolysis and generation, so an HES facility will include a reverse osmosis (RO) water treatment facility. The volume and composition of waste brine and solids rejected during water treatment will be site-specific and dependent on source water quality.

A HES facility utilizing fuel cells for the electrical generation cycle can be constructed with a closed-loop water system, where water is converted to H₂ gas and then passed through the fuel cell, where H₂ combines with atmospheric O₂ to form water, which is then recovered and returned to the electrolyzer. Water requirements are limited to makeup water for water vapor losses.

Table 6 shows estimated water requirements for varying sizes of utility-scale, air-cooled gas turbines in the western U.S., paired with PEM electrolysis and running simple cycle with water injection cooling. Recovery of water from the combustion cycle by condensing the emitted steam has not been fully investigated, so these estimates are maximum values.

 

 

 

Land use. The footprint of an HES utilizing salt cavern storage is generally determined by the salt cavern size and spacing. Surface facilities may occupy 5–50 acres (2–20.2 hectares), depending on technology choices and building and safety codes.

Commercial availability and equipment supply chain

Each element of an HES system utilizes proven, financeable technologies, but the technologies may or may not have been deployed at a utility scale, with purity H₂ and/or integrated at commercial scale. The authors are not aware of any other compressed air energy project examples where combustion or fuel cell technologies have been directly connected to salt cavern storage. Consequently, the authors believe that opportunities exist for process and facility integration to reduce costs and/or improve efficiency. Table 7 summarizes significant integrated HES projects that are proposed, as well as completed demonstration projects.

 

 

 

Electrolysis

Electrolysis has been used for sourcing H₂ at industrial scale since before World War 2. Like batteries, the core technology is mature, but recent innovations in new materials have significantly reduced the size and capacity per unit. In the case of electrolysis, polymer electrolyte membrane (PEM) is favored for energy storage applications vs. alkaline electrolysis, which has been used commercially since the 1940s, is a comparatively mature technology and is (currently) more efficient (72%). PEM maintains its efficiency when partially loaded, it has a lower current density, it operates at low pressure (< 30 bar, < 580 psi) and temperature (50°C–80°C, 122°F–176°F), it has a smaller physical footprint per MW, and it can ramp up more quickly.¹⁰ At present, commercial PEM electrolyzers have an electrical energy efficiency of 64% vs. a theoretical efficiency of 86%.

It is expected that the rapid expansion of electrolyzer manufacturing capacity worldwide will result in a substantial reduction in the unit cost of electrolysis, by as much as 65% by 2025, and increase the diversity of suppliers.^11,12 The cost of alkaline electrolyzers may also benefit from economies of scale.¹³

Generation. The combustion of blends of natural gas and H₂ for power is a mature technology. Cogeneration using high-H₂ fuels in the coking and refining industries dates to the 1950s. The supply chain and operating and maintenance support for combustion engines and turbines is well established and reliable.

Depending on required ramp-up time and output requirement, using available technology at normal operation can fire on 80%–100% H₂ and 0%–20% pipeline gas for flame stability. At present, thermal generation technologies available with performance guarantees are small units (2 MW–3 MW); however, nearly all major thermal generation equipment suppliers will warranty performance on existing technologies firing on 30%–65% H₂ and forecast certifying various products for 100% H₂ service by 2025–2030.

Integration of operations. Since 1988, more than 140 power-to-gas projects have been completed worldwide, including 102 power-to-H₂ projects.^14,15 Of these, 10 are substantive projects demonstrating the integration of renewal generation and electrolysis and/or geologic storage. Among these 10 projects, six also feature integrated power generation.

Geologic storage of H₂

Naturally occurring geologic salt has the unique characteristic of behaving plastically, which makes it effectively impermeable to gases, including H₂. Consequently, natural occurring salt bodies in the subsurface are widely used for storage of natural gas (44 facilities in N. America), and more than 500 caverns are used for the storage of propane, butane, ethane and mixed grades of natural gas liquids. One helium storage cavern facility is operated by the U.S. Bureau of Land Management, and several others are operated by the Russian government for storage of H₂ and O₂. Utilities in the U.S. and Germany operate three salt caverns for compressed air storage.

High H₂ town gas (60% H₂) was first stored in salt at two locations in Germany (Table 8), but both locations later converted the caverns to natural gas service. Subsequently, four H₂ storage facilities using salt caverns have been put into service, primarily to support petrochemical use of H₂. The combined capacity of existing facilities is 8.5 Bsft³, or 20.468 MMkg of H₂.

 

 

 

Unlike salt, geologic storage of H₂ has not been attempted at commercial scale in porous rocks, and concerns remain about H₂-rock chemical reactions, subsurface microbial contamination, and top seal integrity. H₂-rock mineral reactions have been evaluated at a general level,^18,19 and some reservoir-specific investigations have been reported,^21–23 but detailed core testing under burial conditions and in the presence of subsurface fluids have not been widely performed. Ongoing field tests, such as geologic storage of H₂ in porous reservoirs, are being investigated by a number of projects.

Salt caverns for the storage of H₂ are constructed by the same methods as other gas storage caverns. Under-saturated water is injected into a salt formation, where the highly-soluble halite, natural occurring salt (sodium chloride), will go into solution. The salt-saturated fluid, brine, is circulated back to the surface. Approximately 7–10 volumes of water are required for each volume of salt dissolved.

A solution mining well consists of multiple strings of casing, steel pipe that are cemented into the drilled hole and that serve as the barrier between the open volume in the hole (the “annulus”) and the adjacent rock. Cement fills the void between the outside wall of the pipe and the rock face to form an impermeable barrier to prevent brine and/or stored gas from migrating vertically, and isolates the well contents from any groundwater resources. The casing is held in place at the top of the cavern by a cement plug set between the casing and the salt (referred to as a “shoe”). For H₂ service, care must be taken to select materials that are H₂ compatible.

A string of pipe hung within the casing is called a “mining string.” The water is injected via tubing lowered into the mining string from the surface, which is attached to, or “hung,” from the wellhead. As water is pumped down the injection tubing into the cavern void, the newly formed brine in the cavern is displaced to the space between the mining string and the injection tubing.

At the initiation of the solution mining operation, an inert fluid, diesel or nitrogen gas is first pumped down and maintained as a stagnant layer above the bottom of the mining string and up the annulus to the wellhead. This “blanket” protects the salt at the top of the cavern from erosion around the casing shoe.

Upon completion of the cavern, the cavern integrity is assessed by a mechanical integrity test (MIT). Fluid is pumped into the cavern until the permitted maximum operating pressure is attained and held for a period specified by the regulator. If the cavern pressure is maintained over the test period, the cavern is not leaking and can be put into service. Due to the high mobility of H₂, the best practice is to conduct the MIT for a longer time period than those used for natural gas.

To put the cavern into service, gas is injected into the cavern, which displaces the brine to the surface (i.e., “de-brining”). Eventually, the gas volume displaces all the brine in the cavern. Until the cavern is de-brined, storage operations are limited to injection, and withdrawals (“discharges”) are limited in duration and magnitude. Once completely de-brined, storage operations are unrestricted. Residual moisture in the cavern requires the withdrawn gas to be dehydrated, but over time the need for dehydration becomes less necessary.

Insoluble lithic components

Insoluble lithic components in bedded salts and entrained in salt diapirs present potential complications for H₂ storage due to the reactivity of H₂ with rock minerals and/or pore fluids, the growth of H₂-consuming microbes and changes in rock properties because of mineral alteration.²⁴

Based on core testing of the Vosges Sandstone (Triassic age, France), under a variety of conditions up to 30 bar and 150°C and in the presence of water and iron, H₂ does not appear to react with quartz or feldspars.²³ H₂, theoretically, has the potential to react directly with sulfur and iron oxide (Fe₂O₃), but only at higher temperatures and pressures.¹⁹ Truche and others^25,26 and Ding and Liu²⁷ found that H₂ does react abiotically with pyrite, particularly in clay-rich rocks, but only at pressures and temperatures greater than typically found in salt caverns. However, kinetic modeling by Hassannayeb and others²⁸ found that alkaline pore fluids promoted H₂-induced pyrite reduction to pyrrhotite, and loss of H₂ as H₂S, at gas storage conditions but at low volumes. An additional concern is the pyrite oxidation in the presence of carbonates resulting in the release of CO₂ and acidifying pore fluids, but this appears to be limited to temperatures higher than typical cavern storage operations.²⁹

The greater concern is H₂-induced reactions in the presence of saline, CO₂-bearing pore fluids and methanogenic bacteria. Carbonate, anhydrite and barite may be dissolved when H₂ reacts with dissolved CO₂ in pore fluids to create a weak acid. Henkel and others²¹ reported induced secondary porosity from Permo-Triassic sandstones used for gas storage in Germany at ambient conditions. Flesch and Pudlo²⁰ reported an increase in porosity in sandstone core samples after saturation by 100% H₂ under burial conditions and saline fluids. Barite dissolution²² increased SO₄^–, which may promote the formation of hydrogen sulfide (H₂S).

Microbial facilitated reaction of H₂ and minerals may generate methane.³⁰ “Hydrogenotrophs,” organisms that are able to metabolize molecular H₂, include sulfate- and iron-reducing bacteria and H₂-oxidizing bacteria. Microbial conversion of H₂ can be significant under storage conditions. Šmigán and others³¹ compared the composition of injected and withdrawn gas from a “town gas” (54% H₂) single-cycle aquifer storage facility in an anticline near Lobodice, Czech Republic. Within a 7-mos injection/withdrawal cycle, H₂ content decreased by 23% and methane content increased by 18.2%.

Isotope data indicated that the increased methane was the result of bacterial conversion of H₂ and CO₂ to methane. The rate of microbial conversion of H₂ to methane or H₂S is a function of the availability of sulfate, CO₂, temperature, pressure and storage time.³² Salt caverns commonly have residual brine in the cavern sump after de-brining, which can contain bacteria.¹⁶ Laban¹⁷ modeled microbial activity in salt caverns and found that within 2 yr, microbial-sourced H₂S contamination of H₂ would require a gas treatment before use as a turbine fuel. Hemme and van Berk³³ found that H₂S formation from anhydrite can be mitigated by adding dissolved ferrous iron to the solution mining brine and/or sump fluid. As a result, bactericide treatment may be required during solution mining operations and/or procedures implemented to mitigate the introduction of bacteria into a storage cavern during operations.

Takeaway

H₂ energy storage supports global and regional power markets by providing resource assurance during weather-driven events. It also matches intermittent generation with variable demand by providing dispatchable generation with little or no GHG emissions, using conventional and readily available technologies that can be variably configured to meet market requirements.

Since salt caverns are the only technology, at present, that can store utility-scale volumes of H₂, locating such facilities is limited to areas where suitable salt caverns can be constructed (Fig. 10). Although additional characterization of design considerations is required in cavern design and construction, due to H₂’s unique chemical, physical and biochemical properties, HES utilizing salt cavern storage is a viable solution for balancing H₂ supply and demand and providing dispatchable power resource assurance in major markets around the world.

 

Fig. 10. Global distribution of geologic salt deposits.³⁴

 

Note

This paper was first presented on May 19, 2021, at H₂Tech’s H₂Tech Solutions virtual conference.

Literature cited

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¹¹ Schmidt, et. al, “Future cost and performance of electrolysis: An expert elicitation study,” International Journal of Hydrogen Energy, Vol. 42, 2017.

¹² Mayyas, A., M. Ruth, B. Pivovar, G. Bender and K. Wipke, “Manufacturing cost analysis for proton exchange membrane water electrolyzers,” National Renewable Energy Laboratory, Golden, Colorado, 2018.

¹³ Morgan, E. R., J. F. Manwell and J. G. McGowan, “Opportunities for economies of scale with alkaline electrolyzers,” International Journal of Hydrogen Energy, Vol. 38, 2013.

¹⁴ Thema, M., F. Bauer and M. Sterner, “Power-to-gas: Electrolysis and methanation status review,” Renewable and Sustainable Energy Reviews, Vol. 112, 2019.

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¹⁶ Panfilov, M., “Chapter 4: Underground and pipeline hydrogen storage,” in Compendium of Hydrogen Energy, 2016, online: http://dx.doi.org/10.1016/B978-1-78242-362-1.00004-3

¹⁷ Laban, P. M., “Hydrogen storage in salt caverns: Chemical modelling and analysis of large-scale hydrogen storage in underground salt caverns,” MS Thesis, Delft University of Technology, Delft, The Netherlands, 2020.

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²⁰ Flesch, S. and D. Pudlo, “Hydrogen underground storage—Potential reservoir effects investigated with high-resolution computer tomography,” European Hydrogen Energy Conference, Costa del Sol, Spain, March 15–16, 2018.

²¹ Henkel, S., D. Pudlo, L. Werner, F. Enzmann, V. Reitenbach, D. Albrecht,
H. Wurdemann, K. Heister, L. Ganzer and R. Gaupp, “Mineral reactions in the geological underground induced by H₂ and CO₂ injections,” Energy Procedia, Vol. 63, 2014.

²² Henkel, S., D. Pudlo and C. Heubeck, “Laboratory experiments for safe underground hydrogen/energy storage in depleted natural gas reservoirs,”
Near Surface Geoscience Conference and Exhibition, Malmo, Sweden, September 3–7, 2017.

²³ Yetka, A. E., M. Pichavant and P. Audigane, “Evaluation of geochemical reactivity of hydrogen in sandstone: Application to geological storage,” Applied Geochemistry, Vol. 95, 2018.

²⁴ Heinemann, N., J. Alcalde, J. M. Miocic, S. T. Hangx, J. Kallmeyer, C. Ostertag-Henning, A. Hassanpouryouzband, E. M. Thaysen, G. J. Strobel, C. Schmidt-Hattenberger, K. Edlmann, M. Wilkinson, M. Bentham, R. S. Haszeldine, R. Carbonell and A. Rudloff, “Enabling large-scale hydrogen storage in porous media—The scientific challenges,” Energy Environmental Sciences, Vol. 14, 2021.

²⁵ Truche, L., G. Berger, C. Destrigneville, D. Guillaume and E. Giffaut, “Kinetics of pyrite to pyrrhotite reduction by hydrogen in calcite buffered solutions between 90 and 180°C: Implications for nuclear waste disposal,” Geochem. Cosmochim. Acta, Vol. 74, 2010.

²⁶ Truche, L., M. C. Jodin-Caumon, C. Lerouge, G. Berger, R. Mosser-Ruck, E. Giffaut and N. Michau, “Sulphide mineral reactions in clay-rich rock induced by high hydrogen pressure: Application to disturbed or natural settings up to 250°C and 30 bar,” Chem. Geol., Vol. 351, 2013.

²⁷ Ding, K. and L. Yan, “Hydrolysis of pyrite: A possible pathway for generation of high concentrations of H₂S gas in deep-buried reservoirs?” Development in Earth Science, Vol. 5, 2017.

²⁸ Hassannayebi, N., S. Azizmohammadi, M. De Lucia and H. Ott, “Underground hydrogen storage: Application of geochemical modelling in a case study in the Molasse Basin, Upper Austria,” Environmental Earth Sciences, 2019.

²⁹ Verron, H., J. Sterpenich, J. Bonnet, B. Franck, R. Mosser-Ruck, C. Lorgeoux, A. Randi and N. Michau, “Experimental study of pyrite oxidation at 100°C: Implications for deep geological radwaste repository in claystone,” Minerals, Vol. 9, 2019.

³⁰ Hagemann, B., M. Rasoulzadeh, M. Panfilov, L. Ganzer and V. Reitenbach, “Hydrogenization of underground storage of natural gas,” Computer Geoscience, 2015.

³¹ Šmigán, P., M. Greksák, J. Kozánkova, F. Buzek, V. Onderka and I. Wolf, “Methanogenic bacteria as a key factor involved in changes of town gas stored in an underground reservoir,” FEMS Microbiology Ecology, Vol. 73, 1990.

³² Hemme, C. and W. van Berk, “Hydrogeochemical modeling to identify potential risks of underground hydrogen storage in depleted gas fields,” Applied Sciences, Vol. 8, 2018.

³³ Hemme, C. and W. van Berk, “H₂S generation and release in salt cavern gas storage,” American Association of Petroleum Geologists, May 29, 2017.

³⁴ Horváth, P. L., S. Mirau, G.-S. Schneider., H. Bernhardt, C. Weiler, J. Bödeker, W. Wippich, T. Tangermann and R. Ratigan, “Update of SMRI’s compilation of worldwide salt deposits and salt cavern fields,” Solution mining research institute, (SMRI), Research Project Report 2017-5, April 2018.

Jay Evans, Jr has 40 yr of experience in the oil and gas industry, with extensive experience in oil and gas reserve/reservoir engineering and acquisitions, drilling and production operations, midstream project development and construction. He also has significant background in project management, engineering design and technical advisory on numerous gas storage and gas cycling projects, conventional and unconventional oil and gas field development projects, gas reservoir and salt cavern storage projects, and construction of gathering and transmission pipelines with associated compression, processing and treating facilities. He is the author of numerous industry technical papers and presentations. He has worked for companies including MD America Energy, Kinder Morgan, Swift Energy, Unocal (Chevron), Tenaska, TransCanada, KN Energy, American Oil & Gas, Gulf Energy, ENSERCH, Air Liquide, Niska Partners, Freeport LNG, AGL Resources, ENSTOR (Iberdrola), RB International Finance, Dominion Transmission, ENSTAR, Arizona Public Service, King Operating, H2B2 and many others. He holds a BS degree in petroleum engineering from the University of Texas at Austin and is a Registered Professional Engineer in Texas.

 

Tom Shaw is President of LK Energy in Houston, Texas. Dr. Shaw has more than 30 yr of experience in energy project development, including oil and gas production, natural gas storage, power transmission and other infrastructure. LK Energy has been evaluating the feasibility of integrated hydrogen electrolysis, storage and power generation since 2012.