Large-scale underground hydrogen storage: Integrated modeling of reservoir-wellbore system

Underground Hydrogen Storage (UHS) has received significant attention over the past few years as hydrogen seems well-suited for adjusting seasonal energy gaps.We present an integrated reservoir-well model for “Viking A″ the depleted gas field in the North Sea, as a potential site for UHS. Our findings show that utilizing the integrated model results in more reasonable predictions as the gas composition changes over time. Sensitivity analyses show that the lighter the cushion gas, the more production can be obtained. However, the purity of the produced hydrogen will be affected to some extent, which can be enhanced by increasing the fill-up period and the injection rate. The results also show that even though hydrogen diffuses into the reservoir and mixes up with the native fluids (mainly methane), the impact of hydrogen diffusion is marginal. All these factors will potentially influence the project's economics.     

A detailed comparative performance study of underground storage of natural gas and hydrogen in the Netherlands

With the expected increase in the use of hydrogen as an energy carrier, large-scale underground storage sites will be needed. Unlike underground natural gas storage (UGS), many aspects on the performance of underground hydrogen storage (UHS) are not well understood, as there is currently no UHS in use for energy supply. Here we present the results of a detailed comparative performance study of UGS and UHS, based on an inflow/outflow nodal analysis. Three UGS sites in depleted gas fields and one in a salt cavern cluster in the Netherlands are used as case studies. The results show that although hydrogen can be withdrawn/injected at higher rates than natural gas, this can be limited by technical constraints. It also indicates that wider ranges of working pressures are required to increase the storage capacity and flow performance of an UHS site to compensate for the lower energy density of hydrogen.     

Underground hydrogen storage to balance seasonal variations in energy demand: Impact of well configuration on storage performance in deep saline aquifers

Grid-scale underground hydrogen storage (UHS) is essential for the decarbonization of energy supply systems on the path towards a zero-emissions future. This study presents the feasibility of UHS in an actual saline aquifer with a typical dome-shaped anticline structure to balance the potential seasonal mismatches between energy supply and demand in the UK domestic heating sector. As a main requirement for UHS in saline aquifers, we investigate the role of well configuration design in enhancing storage performance in the selected site via numerical simulation. The results demonstrate that the efficiency of cyclic hydrogen recovery can reach around 70% in the short term without the need for upfront cushion gas injection. Storage capacity and deliverability increase in successive storage cycles for all scenarios, with the co-production of water from the aquifer having a minimal impact on the efficiency of hydrogen recovery. Storage capacity and deliverability also increase when additional wells are added to the storage site; however, the distance between wells can strongly influence this effect. For optimum well spacing in a multi-well storage scenario within a dome-shaped anticline structure, it is essential to attain an efficient balance between well pressure interference effects at short well distances and the gas uprising phenomenon at large distances. Overall, the findings obtained and the approach described can provide effective technical guidelines pertaining to the design and optimization of hydrogen storage operations in deep saline aquifers.     

Hydrogen storage in saline aquifers: The role of cushion gas for injection and production

Hydrogen stored on a large scale in porous rocks helps alleviate the main drawbacks of intermittent renewable energy generation and will play a significant role as a fuel substitute to limit global warming. This study discusses the injection, storage and production of hydrogen in an open saline aquifer anticline using industry standard reservoir engineering software, and investigates the role of cushion gas, one of the main cost uncertainties of hydrogen storage in porous media.The results show that one well can inject and reproduce enough hydrogen in a saline aquifer anticline to cover 25% of the annual hydrogen energy required to decarbonise the domestic heating of East Anglia (UK). Cushion gas plays an important role and its injection in saline aquifers is dominated by brine displacement and accompanied by high pressures. The required ratio of cushion gas to working gas depends strongly on geological parameters including reservoir depth, the shape of the trap, and reservoir permeability, which are investigated in this study. Generally, deeper reservoirs with high permeability are favoured. The study shows that the volume of cushion gas directly determines the working gas injection and production performance. It is concluded that a thorough investigation into the cushion gas requirement, taking into account cushion gas costs as well as the cost-benefit of cushion gas in place, should be an integral part of a hydrogen storage development plan in saline aquifers.     

Comprehensive study of the underground hydrogen storage potential in the depleted offshore Tapti-gas field

Hydrogen is becoming an alternative for conventional energy sources due to absence of any Greenhouse Gases (GHG) emissions during its usage. Geological storage of hydrogen will be potential solution for dealing with large volume requirement to manage uninterrupted Hydrogen supply-chain. Geological Storages such as depleted reservoirs, aquifers and salt caverns offer great potential option for underground hydrogen storage (UHS). There are several depleted gas fields in India. One of such field is located in Tapti-Daman formation. A comprehensive study is conducted to assess the possibility of hydrogen storage in this Indian field which is first of its kind. The geological characteristic of this site is assessed for its viability for storage. Additionally, several aspects including storage capacity, sealability, chemical and micro-biological stability, reservoir simulation, and production viability are assessed using various analytical and numerical models.The qualitative analysis of the Tapti-gas field suggests that the integrity of the storage site will be intact due to existing anticlinal four-way closed structure. The chemical and micro-biological losses are minimal and will not lead to major loss of hydrogen over time. The reservoir modeling results show that optimum gas production-injection scheme needs to be engineered to maintain the required reservoir pressure level in the Tapti-gas field. Also, the deliverability of the various seasonal storage time show that 80 days production scheme will be suitable for efficient operation in this field. Finally, a synergistic scheme to enable green energy production, storage, and transportation is proposed via implementation of UHS in the offshore Tapti-gas field.     

Impact of experimentally measured relative permeability hysteresis on reservoir-scale performance of underground hydrogen storage (UHS)

Underground Hydrogen Storage (UHS) is an emerging large-scale energy storage technology. Researchers are investigating its feasibility and performance, including its injectivity, productivity, and storage capacity through numerical simulations. However, several ad-hoc relative permeability and capillary pressure functions have been used in the literature, with no direct link to the underlying physics of the hydrogen storage and production process. Recent relative permeability measurements for the hydrogen-brine system show very low hydrogen relative permeability and strong liquid phase hysteresis, very different to what has been observed for other fluid systems for the same rock type. This raises the concern as to what extend the existing studies in the literature are able to reliably quantify the feasibility of the potential storage projects. In this study, we investigate how experimentally measured hydrogen-brine relative permeability hysteresis affects the performance of UHS projects through numerical reservoir simulations. Relative permeability data measured during a hydrogen-water core-flooding experiment within ADMIRE project is used to design a relative permeability hysteresis model. Next, numerical simulation for a UHS project in a generic braided-fluvial water-gas reservoir is performed using this hysteresis model. A performance assessment is carried out for several UHS scenarios with different drainage relative permeability curves, hysteresis model coefficients, and injection/production rates. Our results show that both gas and liquid relative permeability hysteresis play an important role in UHS irrespective of injection/production rate. Ignoring gas hysteresis may cause up to 338% of uncertainty on cumulative hydrogen production, as it has negative effects on injectivity and productivity due to the resulting limited variation range of gas saturation and pressure during cyclic operations. In contrast, hysteresis in the liquid phase relative permeability resolves this issue to some extent by improving the displacement of the liquid phase. Finally, implementing relative permeability curves from other fluid systems during UHS performance assessment will cause uncertainty in terms of gas saturation and up to 141% underestimation on cumulative hydrogen production. These observations illustrate the importance of using relative permeability curves characteristic of hydrogen-brine system for assessing the UHS performances.     

Blasingame decline theory for hydrogen storage capacity estimation in shale gas reservoirs

The estimation of storage capacity is crucial for underground hydrogen storage. Shale gas reservoirs have low permeability and porosity, so it is the potential site for hydrogen storage. The study is based on the depleted shale gas reservoirs with multiple flow mechanisms (diffusion, desorption and seepage). Firstly, this paper, using Laplace transformation, point source function and Stehfest inversion, presents a semi-analytical solution for bottom-hole pressure response with hydrogen duration injection. Then we, considering the multiple flow mechanisms, deduce a material balance equation specifically for shale gas reservoirs and plot modified type curves based on the Blasingame decline analysis theory. Furthermore, we discuss the effects of different critical parameters related to hydrogen storage capacity on type curves. In the final part, we describe in detail the method of obtaining hydrogen reserves using type curves. The proposed one can estimate the hydrogen volume in fractures and matrix systems, and get the actual underground storage volume through pressure response, compared with the hydrogen storage capacity calculated by the volumetric method. This study is helpful for the hydrogen capacity estimation of shale gas underground storage on-site.     

Evaluating the hydrogen storage potential of shut down oil and gas fields along the Norwegian continental shelf

The underground hydrogen storage (UHS) capacities of shut down oil and gas (O&G) fields along the Norwegian continental shelf (NCS) are evaluated based on the publicly available geological and hydrocarbon production data. Thermodynamic equilibrium and geochemical models are used to describe contamination of hydrogen, loss of hydrogen and changes in the mineralogy. The contamination spectrum of black oil fields and retrograde gas fields are remarkably similar. Geochemical models suggest limited reactive mineral phases and meter-scale hydrogen diffusion into the caprock. However, geochemical reactions between residual oil, reservoir brine, host rock and hydrogen are not yet studied in detail. For 23 shut down O&G fields, a theoretical maximum UHS capacity of ca. 642 TWh is estimated. We conclude with Frigg, Nordost Frigg, and Odin as the best-suited shut down fields for UHS, having a maximum UHS capacity of ca. 414 TWh. The estimates require verification by site-specific dynamic reservoir models.     

Productivity analysis of fractured wells in reservoir of hydrogen and carbon based on dual-porosity medium model

Hydrogen is usually locked in energy-rich organic compounds and there is almost no pure hydrogen in nature. Organic compounds produced in reservoirs of hydrogen and carbon are an important source of hydrogen production. Understanding the productivity characteristics reservoirs of hydrogen and carbon is the important step to ensure adequate hydrogen energy. This study analyzes the production of hydraulically fractured organic reservoir of hydrogen and carbon. First, based on the diffusion mechanism in reservoir matrix, a multi-scale dual-porosity medium model of reservoir of hydrogen and carbon is established. Then, the mathematical model is solved and verified through a historical matching of field gas production data. Finally, parameter analysis was performed to determine the key parameters to improve the recovery efficiency in organic reservoir of hydrogen and carbon. Results show that improving fracture permeability can improve gas recovery efficiency of hydrocarbon reservoirs. The matrix desorption can develop natural gas production for a long period. Long sizes of hydraulic fractures have large contact surfaces for gas diffusion and increase gas generation and cumulative gas production. The proposed model can predict and analyze the production performance of reservoirs of hydrogen and carbon.     

Hydrogen tightness evaluation in bedded salt rock cavern: A case study of Jintan,China

Hydrogen is regarded as one of the most important energy sources for the future. Safe, large-scale storage of hydrogen contributes to the commercial development of the hydrogen industry. Use of bedded salt caverns for natural gas storage in China provides a new option for underground hydrogen storage (UHS). In this study, the physical properties of multicomponent gases in UHS and salt rock are reviewed and discussed, along with the flow of hydrogen in the surrounding salt rock. Mathematical models of the two-phase multicomponent flow of the gas–brine system in the UHS were established. A numerical model of a simplified elliptical salt cavern was built to simulate the migration of the gas–brine system in the UHS. The hydrogen tightness of the UHS was evaluated through simulation with different storage strategies, salt rock and interlayer permeabilities, and gas components. The results indicate that: (1) Cyclic injection and withdrawal facilitate hydrogen leakage, which is accelerated by increasing the frequency. (2) The huff-n-puff of hydrogen gas in the injection and withdrawal cycles forces the gas into pore space and enhances the relative permeability of the gas phase. The migration of hydrogen and brine weakens the hydrogen tightness. Brine saturation is an important index for evaluating the hydrogen tightness of UHS. (3) The leakage rate of UHS increases with an increase in the permeability of the salt rock and interlayer and the total thickness of the interlayers. The average permeability K_wa weighted by the thickness of layers for the bedded salt formation is proposed to integrate three variables to facilitate field application of the simulation results. The critical K_wa is less than 3.02 × 10⁻¹⁷ m² if the recommended annual hydrogen leakage rate is less than 1%. (4) The difference between hydrogen and other gas species is another important factor in the leakage rate and should be considered. This study provides theoretical guidance for evaluating the feasibility of UHS in salt caverns and site selection in China.     

A dual-porosity dual-permeability model for acid gas injection process evaluation in hydrogen-carbonate reservoirs

The Pre-Caspian basin is one of the most prolific in terms of oil and gas exploration and hydrogen and carbon compounds energy production around the world. The major hydrogen and carbon compounds reservoirs are Carboniferous reef and platform hydrogen-carbonate rocks. The original fluids under subsurface conditions contain 15% hydrogen sulfide and 4% carbon dioxide. Acid hydrogen and carbon compounds reinjection is not only an environmentally friendly solution for disposal of produced greenhouse gases but also enhances oil recovery and supplies more fuel energy. On the other hand, the presence of fractures makes hydrogen-carbonate reservoir characteristics nature more complicated than conventional sandstone reservoirs, which leads to a tremendous challenge to evaluate the gas injection process. In this work, a dual-porosity dual-permeability formulation was used to model the dual-medium nature incorporating matrix system with high porosity and low permeability and fracture network with low porosity and high permeability. After matching PVT experiments, a ten pseudo-components fluid model was generated for running compositional simulation. The miscible hydrogen and carbon compounds injection was simulated as an effective enhanced oil recovery approach. Sensitivity analysis such as timing of injection gas, injection rate, well spacing and completion interval have proposed the optimal condition for the miscible hydrogen and carbon compounds flooding. The recommended optimum hydrogen and carbon compounds injection scenario is twice higher oil recovery compared with natural depletion. The results of this study illustrate further the practicability of pseudo-components splitting and lumping for compositional simulation to evaluate the performance of hydrogen and carbon compounds injection processes, and are of great importance using the dual-porosity dual-permeability method performing numerical simulation of naturally fractured hydrogen-carbonate reservoirs.     

Geochemical reactions-induced hydrogen loss during underground hydrogen storage in sandstone reservoirs

Underground hydrogen storage (UHS) appears to be an important means as a large-scale and long-term energy storage solution. A primary concern of UHS is the in-situ geochemical reactions-induced hydrogen loss. In this context, we performed geochemical modelling to examine the hydrogen loss associated with hydrogen dissolution and fluid-rock interactions using PHREEQC (Version 3) as a function of temperature and pressure. We also performed geochemical modelling with kinetics to investigate the potential hydrogen loss in two commercial gas storage reservoirs (Tubridgi and Mondarra) in Western Australia against the reservoir mineralogy, fluid properties, depth and temperature.Our results show that increasing pressure and temperature only slightly increases hydrogen solubility in brines without minerals. Increasing salinity slightly decreases the solubility of hydrogen in brines. The saturated hydrogen aqueous solution almost does not react with silicate and clay minerals, which is favorable for underground hydrogen storage in quartz-rich sandstone reservoirs. However, unlike silicate and clay minerals, carbonates like calcite triggers up to 9.5% hydrogen loss due to calcite dissolution induced hydrogen dissociation process. Kinetic simulations show that Tubridgi only leads to 0.72% of hydrogen loss, and Mondarra causes 2.76% of hydrogen loss as a result of reservoir calcite dissolution and hydrogen dissociation in brines in 30-year time. Nearly over 87% of calcite cement from Mondarra may be dissolved in 30-year, suggesting potential risks associated with wellbore stability. In conclusion, geochemical reactions-induced hydrogen loss would be minor for UHS in porous media, and we argue that deep calcite-free reservoirs together with calcite-free caprocks would be preferable for underground hydrogen storage.     

Review on using the depleted gas reservoirs for the underground H2 storage: A case study in Niigata prefecture,Japan

Underground hydrogen storage (UHS) in depleted hydrocarbon reservoirs is a prospective choice to store enormous volumes of hydrogen (H₂). However, these subsurface formations must be able not only to store H₂ in an effective and secure manner, but also to produce the required volumes of H₂ upon demand. This paper first reviews the critical parameters to be considered for geological analysis and reservoir engineering evaluation of UHS. The formation depth, the interactions of rock-brine-H₂, the caprock (seal) and well integrity are the most prominent parameters as far as UHS is concerned. In respect of these critical parameters, tentative H₂ storage is screened from the existing gas storage fields in the Niigata prefecture of Japan, and it was revealed that the Sekihara gas field is a suitable candidate for UHS with a storage capacity of 2.06 × 10⁸ m³ and a depth of 1000 m. Then, a series of numerical simulations utilizing CMG software was conducted to find out the extent to which critical parameters alter H₂ storage capacity. The results demonstrated that this field, with a recovery factor of 82.7% in the sixth cycle of production is a prospective site for H₂ storage.     

The potential of hydrogen storage in depleted unconventional gas reservoirs: A multiscale modeling study

Subsurface energy storage in depleted petroleum reservoirs is a promising technique to balance and optimize the utilization of energy resources. In this work, we numerically explore the possibility of storing excessive hydrogen gas in depleted unconventional gas reservoirs. Our study is a multiscale analysis. From the molecular (pore) scale, we investigate the thermodynamics and transport mechanism of the hydrogen gas in the nanopores of the unconventional reservoirs. Then based on the results of the pore scale, we conduct reservoir-scale simulations to quantitatively investigate the preferred cycling pressure, the effective fraction of cushion gas and the amount of storage capacity of unconventional reservoirs. We have discovered that, compared to conventional gas reservoirs, hydrogen stored in unconventional reservoirs maintains higher purity because of the differential adsorption effect of the nanopores. This feature makes depleted unconventional gas reservoirs appealing candidates for underground storage of the hydrogen gas.     

First assessment of an area potentially suitable for underground hydrogen storage in Italy

Hydrogen storage can help achieve climate change and reduce greenhouse gas emissions. This paper presents a first assessment of the suitability of northeastern Italy for underground hydrogen storage (UHS). The study focuses on the analysis of publicly available well data, which allowed identifying geological formations potentially suitable for UHS. The most promising area, known as the “Treviso Area” consists of both saline aquifers and depleted gas fields. One of the key petrophysical properties, i.e. porosity, was calculated for each of the five wells revealing conditions potentially suitable for UHS by applying empirical formulas to geophysical log data. For the two depleted gas fields, a hydrogen injection simulation was also performed. This work is a pioneer study and lays the foundation for hopeful further analyses, which could help implement the recently launched “North Adriatic Hydrogen Valley” initiative.     

Underground hydrogen storage: A comprehensive review

Increased emissions of greenhouse gasses into the atmosphere has adversely been contributing to global warming as a result of burning fossil fuels. Therefore, the energy sectors have been looking into renewable sources such as wind, solar, and hydro energy to make electricity. However, the strongly fluctuating nature of electricity from such energy sources requires a bulk energy storage system to store the excess energy as a buffer and to fulfill the demand constantly. Underground storage is a proven way to store a huge amount of energy (electricity) after converting it into hydrogen as it has higher energy content per unit mass than other gases such as methane and natural gas. This paper reviews the technical aspects and feasibility of the underground storage of hydrogen into depleted hydrocarbon reservoirs, aquifers, and manmade underground cavity (caverns). Mechanisms of underground hydrogen storage (UHS) followed by numerous phenomena such as hydrodynamics, geochemical, physiochemical, bio-chemical, or microbial reactions have been deliberated. Modeling studies have also been incorporated in the literature to assess the feasibility of the process that are also reviewed in this paper. Worldwide ongoing lab study, field study together with potential storage sites have been reported as well. Technical challenges along with proper remedial techniques and economic viability have been briefly discussed. Finally, this paper delivers some feasible strategies for the underground hydrogen storage process, which would be helpful for future research and development of UHS.     

Influence mechanism of brine-gas two-phase flow on sealing property of anisotropic caprock for hydrogen and carbon energy underground storage

As the simplest saturated hydrocarbon, methane is an important hydrogen and carbon energy. The stability and sealing of caprock are keys to ensure the safe storage of energy in the process of hydrogen and carbon energy underground storage. A fully coupled two-phase flow model is established to analyze the migration mechanism of methane in caprock. This model considers the characteristics of dual porosity medium composed of caprock fractures and matrix, including the seepage of methane and brine. In the model, the replacement process of methane and brine exists in the fracture network, and the dynamic adsorption desorption process of methane exists in the matrix. Under the action of tectonic stress, obvious differences are observed in the fracture and permeability in different directions. All these characteristics are considered in the fully coupled two-phase flow model. The restraining and strengthening effects of caprock in the process of methane leakage are analyzed. The results show that the gas induces the adsorption expansion of the caprock matrix and reduces the fracture opening and permeability of the caprock. With the gradual invasion of gas into the caprock, the sealing characteristics of caprock show the evolution of self-inhibition first and then self-enhancement. With the increase in dip angle, gas tends to invade vertically rather than horizontally. Realizing gas–brine replacement is easier with the existence of large fractures. This study provides an effective numerical analysis method, which can be used to evaluate the sealing efficiency in the caprock in underground methane storage.     

Seasonal hydrogen storage in a depleted oil and gas field

Hydrogen storage is essential in hydrogen value chains and subsurface storage may be the most suitable large-scale option. This paper reports numerical simulations of seasonal hydrogen storage in the Norne hydrocarbon field, offshore Norway. Three different storage schemes are examined by injecting pure hydrogen into the gas-, oil-, and water zones. Implementation of four annual withdrawal-injection cycles followed by one prolonged withdrawal period show that the thin gas zone is a preferred target with a final hydrogen recovery factor of 87%. The hydrogen distribution in the subsurface follow the geological structures and is restricted by fluid saturation and displacement efficiencies. Case studies show that the pre-injection of formation gas as a cushion gas efficiently increases the ultimate hydrogen recovery, but at the cost of hydrogen purity. The injection of 30% hydrogen-formation gas mixture results in a varying hydrogen fraction in the withdrawn gas. An alternative well placement down the dipping structure shows lower storage efficiency.     

Experimental investigation of hydrogen-carbonate reactions via computerized tomography: Implications for underground hydrogen storage

The underground hydrogen storage (UHS) in depleted hydrocarbon reservoirs, aquifers, and saline caverns is regarded as a vital component of hydrogen economy value-chains, meant to tackle carbon emissions and global warming. The caprock integrity and storage capacity of the carbonate formations can be altered by the reaction between the injected hydrogen and the calcite/dolomite minerals during UHS. However, experimental investigations of hydrogen-calcite/dolomite reactions at underground storage temperature are rarely reported in literature. Thus, we conducted X-ray computed micro-tomography (μCT) scans of limestone and dolomite cores before and after pressurization with hydrogen for 75 days at 700 psi and 75 °C. For the first time, a significant calcite expansion was observed and led to reduction in storage capacity (i.e., effective porosity) by 47%. However, the storage capacity of the dolomite rock slightly increased (～6%) because the grain expansion effects canceled out the dissolution effects. The study suggests that reduction in storage capacity of carbonate formation due to hydrogen reactivity with calcite is possible during UHS in carbonate formations. Thus, hydrogen reactivity with carbonate minerals should be evaluated to de-risk hydrogen storage projects in carbonate formations.     

Measurement of hydrogen dispersion in rock cores using benchtop NMR

Electrolysis followed by underground hydrogen storage (UHS) in both salt caverns and depleted oil and gas reservoirs is widely considered as a potential option to overcome fluctuations in energy provision from intermittent renewable sources. Particularly in the case of depleted oil and gas reservoirs, a denser layer of cushion gas (N₂, CH₄ or CO₂) can be accommodated in these storage volumes to allow for sufficient system pressure control as hydrogen is periodically injected and extracted. These gases/fluids are however fully soluble with hydrogen and thus with sufficient mixing can undesirably contaminate the extracted hydrogen product. Fluid mixing in a porous medium is typically characterized by a dispersion coefficient (K_L), which is hence a critical input parameter into reservoir simulations of underground hydrogen storage. Such dispersion data is however not readily available in the literature for hydrogen at relevant storage conditions. Here we have developed and demonstrated novel methodology for the measurement of K_L between hydrogen and nitrogen in a Berea sandstone at 50 bar as a function of displacement velocity (0.007–0.722 mm/s). This leverages off previous work quantifying K_L between carbon dioxide and methane in rock cores relevant to enhanced gas recovery (EGR). This used infrared (IR) spectroscopy to differentiate the two fluids, hydrogen is however IR invisible. Hence the required time-resolved quantification of hydrogen concentration emerging from the rock core is uniquely performed here using bench-top nuclear magnetic resonance (NMR). The resultant hydrogen-nitrogen dispersion data as a function of displacement velocity allows for the determination of dispersivity (α = 0.31 mm). This intrinsic rock property compares favorably with previous CO₂ dispersion measurements on similar sandstones, hence validating our methodology to some extent. In addition, at very low velocities, determination of the rock core tortuosity (τ, another intrinsic rock property) produces a value (τ = 10.9) that is similar to that measurement independently using pulsed field gradient NMR methods (τ = 11.3).