Numerical modelling of H2 storage with cushion gas of CO2 in subsurface porous media: Filter effects of CO2 solubility

The central objective of this study is to improve the understanding of flow behaviour during hydrogen (H₂) storage in subsurface porous media, with a cushion gas of carbon dioxide (CO₂). In this study, we investigate the interactions between various factors driving the flow behaviour, including the underlying permeability heterogeneity, viscous instability, and the balance between the viscous and gravity forces. In particular, we study the impact of CO₂ solubility in water on the level of H₂ purity. This effect is demonstrated for the first time in the context of H₂ storage. We have performed a range of 2D vertical cross-sectional simulations at the decametre scale with a very fine cell size (0.1 m) to capture the flow behaviour in detail. This is done since it is at this scale that much of the mixing between injected and native fluids occurs in physical porous media. It is found that CO₂ solubility may have different (positive and negative) impacts on the H₂ recovery performance (i.e., on the purity of the produced H₂), depending on the flow regimes in the system. In the viscous dominated regime, the less viscous H₂ may infiltrate and bypass the cushion gas of CO₂ during the period of H₂ injection. This leads to a quick and dramatic reduction in the H₂ purity when back producing H₂ due to the co-production of the previously bypassed CO₂. Interestingly, the impurity levels in the H₂ are much less severe in the case when CO₂ solubility in water is considered. This is because the bypassed CO₂ will redissolve into the water surrounding the bypassed zones, which greatly retards the movement of CO₂ towards the producer. In the gravity dominated scenario, H₂ accumulates at the top of the model and displaces the underlying cushion gas in an almost piston-like fashion. Approximately 58% of H₂ can be recovered at a purity level above 98% (combustion requirements by ISO) in this gravity-dominated case. However, when CO₂ solubility is considered, the H₂ recovery performance is slightly degraded. This is because the dissolved CO₂ is also gradually vaporised during H₂ injection, which leads to an expansion of mixing zone of CO₂ and H₂. This in turn reduces the period of high H₂ purity level (>98%) during back-production.     

Influence of capillary threshold pressure and injection well location on the dynamic CO2 and H2 storage capacity for the deep geological structure

The subject of this study is the analysis of influence of capillary threshold pressure and injection well location on the dynamic CO₂ and H₂ storage capacity for the Lower Jurassic reservoir of the Sierpc structure from central Poland. The results of injection modeling allowed us to compare the amount of CO₂ and H₂ that the considered structure can store safely over a given time interval. The modeling was performed using a single well for 30 different locations, considering that the minimum capillary pressure of the cap rock and the fracturing pressure should not be exceeded for each gas separately.Other values of capillary threshold pressure for CO₂ and H₂ significantly affect the amount of a given gas that can be injected into the reservoir. The structure under consideration can store approximately 1 Mt CO₂ in 31 years, while in the case of H₂ it is slightly above 4000 tons. The determined CO₂ storage capacity is limited; the structure seems to be more prospective for underground H₂ storage. The CO₂ and H₂ dynamic storage capacity maps are an important element of the analysis of the use of gas storage structures. A much higher fingering effect was observed for H₂ than for CO₂, which may affect the withdrawal of hydrogen. It is recommended to determine the optimum storage depth, particularly for hydrogen. The presented results, important for the assessment of the capacity of geological structures, also relate to the safety of use of CO₂ and H₂ underground storage space.     

Development of a novel simulator for modelling underground hydrogen and gas mixture storage

Underground hydrogen storage can store grid-scale energy for balancing both short-term and long-term inter-seasonal supply and demand. However, there is no numerical simulator which is dedicated to the design and optimisation of such energy storage technology at grid scale. This study develops novel simulation capabilities for GPSFLOW (General Purpose Subsurface Flow Simulator) for modelling grid-scale hydrogen and gas mixture (e.g., H₂–CO₂–CH₄–N₂) storage in cavern, deep saline aquifers and depleted gas fields.The accuracy of GPSFLOW is verified by comparisons against the National Institute of Standard and Technology (NIST) online thermophysical database and reported lab experiments, over a range of temperatures from 20 to 200 °C and pressure up to 1000 bar. The simulator is benchmarked against an existing model for modelling pure H₂ storage in a synthetic aquifer. Several underground hydrogen storage scenarios including H₂ storage in a synthetic salt cavern, H₂ injection into a CH₄-saturated aquifer experiment, and hydrogen storage in a depleted gas field using CO₂ as a cushion gas are used to test the GPSFLOW's modelling capability. The results show that GPSFLOW offers a robust numerical tool to model underground hydrogen storage and gas mixture at grid scale on multiple parallel computing platforms.     

Simulation and analysis of dual-reflux pressure swing adsorption using silica gel for blue coal gas initial separation

A dual-reflux pressure swing adsorption (DR-PSA) process was proposed and simulated to initially separate the blue coal gas, aiming to capture carbon dioxide (CO₂) and enrich hydrogen (H₂), simultaneously. With a feed flow rate of 7.290 slpm, a light product reflux flow rate of 0.505 slpm and the heavy product reflux flow rate of 3.68 slpm, the developed DR-PSA process could capture CO₂ up to 64.01% with a recovery of 99.60% and enrich H₂ up to 34.66% with a recovery of 97.63% from the blue coal gas (36.2% N₂/28.5% H₂/13.9% CO/12.7% CO₂/8.7% CH₄). In addition, in order to optimize the process, the effects of various operating parameters on the DR-PSA process performance in terms of product purity and recovery were discussed in detail, including the feed position, the light product reflux ratio and the heavy product reflux ratio. Moreover, the dynamic distribution behaviors of pressure, temperature and gas-solid concentration were presented to explain and evaluate the process separation performance in depth under different operating conditions.     

Effects of relative permeability change resulting from interfacial tension reduction on vertical sweep efficiency during the CO2-LPG hybrid EOR process

The addition of liquefied petroleum gas (LPG) to the CO₂ stream reduces interfacial tension (IFT) between the injected gas and the reservoir oil, and it changes the gas-liquid relative permeability by making it more water-wet, which affects not only the oil mobility, but also the vertical sweep efficiency. The reduction of the IFT decreases vertical sweep efficiency because it enhances the relative permeability of the solvent, resulting in an increase in the viscous gravity number. For CO₂-LPG enhanced oil recovery (EOR), oil recovery is enhanced by up to 47%, as compared to CO₂ flooding, when the relative permeability change caused by the IFT is not considered. By taking the vertical sweep-out caused by IFT and relative permeability change into consideration, this increase is reduced to 40%. These results indicate the importance of considering the relative permeability and IFT change when predicting the performance of the CO₂-LPG EOR process.     

Role of methane as a cushion gas for hydrogen storage in depleted gas reservoirs

Depleted natural gas reservoirs play an important role as a viable option for large-scale hydrogen storage and production. However, its deployment depends on the accurate knowledge of the cushion gas (such as CH₄, CO₂, and N₂) compositions, which are key components affecting the rock-fluid interfacial phenomenon. In addition, there are currently few reported studies on rock/brine/gas-mixture wettability and gas-mixture/brine surface tension representing this type of reservoir. Hence, we report the feasibility of using CH₄ as a cushion gas (in the presence of CO₂ and N₂) for H₂ storage at various pressures (500 up to 3000 psi), temperatures (30 up to 70) ^oC, and salinities (2 up to 20) wt.% using drop shape analyzer equipment. Contact angle (CA) and surface tension (ST) experiments were extensively conducted for the different gas mixtures (H₂–CH₄–CO₂–N₂) to establish relevant data for H₂ storage in depleted gas reservoirs.Our result indicates that unless when the rock's initial wetting state is altered, the studied gas-mixture compositions (Test case 1: 80% H₂ – 10% CH₄ – 5% CO₂ – 5% N₂; case 2: 70% H₂ – 20% CH₄ – 5% CO₂ – 5% N₂; case 3: 60% H₂ – 30% CH₄ – 5% CO₂ – 5% N₂; case 4: 50% H₂ – 40% CH₄ – 5% CO₂ – 5% N₂; case 5: 40% H₂ – 50% CH₄ – 5% CO₂ – 5% N₂; case 6: 30% H₂ – 60% CH₄ – 5% CO₂ – 5% N₂; and case 7: 20% H₂ – 70% CH₄ – 5% CO₂ – 5% N₂) will exhibit comparable wettability behavior as the CAs ranged between [20 to 41°] irrespective of the reservoir pressure, temperature, and salinity. ST decreases with increasing temperature and linearly with increasing pressure. ST for each gas mixture increased with salinity. ST decreases systematically with increasing CH₄ fraction (at any given salinity, temperature, and pressure) with the highest observed in Test case 1 and the lowest in Test case 7 compositions. Test cases 3 and 4 with H₂ (50–60%) and CH₄ (30–40%) fractions was selected as the optimal gas mixture based on CA and ST for H₂ storage and withdrawal. The study's findings offer precise and useful input data for the reservoir-scale simulation used in geo-storage optimization in depleted natural gas reservoirs.     

Three-dimensional numerical modeling on high pressure membrane reactors for high temperature water-gas shift reaction

This study presents a three-dimensional numerical model that simulates the H₂ production from coal-derived syngas via a water-gas shift reaction in membrane reactors. The reactor was operated at a temperature of 900 °C, the typical syngas temperature at gasifier exit. The effects of membrane permeance, syngas composition, reactant residence time, sweep gas flow rate and steam-to-carbon (S/C) ratio on reactor performance were examined. Using CO conversion and H₂ recovery to characterize the reactor performance, it was found that the reactor performance can be enhanced using higher sweep gas flow rate, membrane permeance and S/C ratio. However, CO conversion and H₂ recovery limiting values were found when these parameters were further increased. The numerical results also indicated that the reactor performance degraded with increasing CO₂ content in the syngas composition.     

Elevated temperature pressure swing adsorption process for reactive separation of CO/CO2 in H2-rich gas

Purification of CO and CO₂ to the ppm level in H₂-rich gas without losing H₂ is one of the technical difficulties for fuel cell power systems. In this work, a two-column seven-step elevated temperature pressure swing system with high purification performance was proposed. The concept of reactive separation by adding water gas shift catalysts into the columns filled with elevated temperature CO₂ adsorbents was adopted. The H₂ recovery ratio and H₂ purity were greatly improved by the introduction of steam rinse and steam purge, which could be realized due to the increasing operating temperature (200–450 °C). An optimized operating region to both achieve high efficiency and low energy consumption was proposed. The optimized case with 0.09 purge-to-feed ratio and 0.15 rinse-to-feed ratio could achieve 99.6% H₂ recovery ratio and 99.9991% H₂ purity at a stable state for a feed gas containing 1% CO, 1% CO₂, 10% H₂O, and 88% H_2. No performance degradation was observed for at least 1000 cycles. The proposed (ET-PSA) system possessed self-purification ability while the columns were penetrated by CO₂. It is however suggested that periodical heat regeneration should be adopted to accelerate performance recovery during long-term operation.     

Storage of hydrogen,natural gas,and carbon dioxide – Geological and legal conditions

The analysis of geological and reservoir conditions of the underground storage of hydrogen, methane, and carbon dioxide, that are important when choosing rock formations for the storage of gas, was presented. Physico-chemical properties of the discussed gases, affecting underground storage, were taken into account. Aquifers, hydrocarbon reservoirs, and caverns leached in salt rocks were analyzed. Legal aspects of underground gas storage were indicated.The physico-chemical conditions of the gases considered (especially molecular mass, and dynamic viscosity) are important for the selection of geological structures for their storage. The reservoir tightness is one of the most important geological and reservoir conditions when taking the appropriate porosity and permeability of rocks building underground storage sites into account. Salt caverns should be mainly used for hydrogen storage due to the tightness of rock salt. Geochemical and microbiological interactions affecting the operation of the underground storage site and its tightness are especially important and should be taken into account. The size of the underground storage site, while not as crucial in the case of H₂ storage, is important for CO₂ storage. When it comes to reservoir conditions, the amount of cushion gas and storage efficiency are important. The legal status of gas storage sites is highly variable. While there are existing regulations regarding natural gas storage, CO₂ storage requires further legislation. In the case of H₂ storage legal regulations need to be developed based on the experience of storage of other gases. The potential competition from other entities focused on the use of underground space for gas storage should be taken into account.     

Thermodynamic characterization of H2-brine-shale wettability: Implications for hydrogen storage at subsurface

Large-scale underground hydrogen storage (UHS) appears to play an important role in the hydrogen economy supply chain, hereby supporting the energy transition to net-zero carbon emission. To understand the movement of hydrogen plume at subsurface, hydrogen wettability of storage rocks has been recently investigated from the contact angles rock-H₂-brine systems. However, hydrogen wettability of shale formations, which determines the sealing capacity of the caprock, has not been examined in detail. In this study, semi-empirical correlations were used to compute the equilibrium contact angles of H₂/brine on five shale samples with various total organic content (TOC) at various pressures (5–20 MPa) and at 343 K. The H₂ column height that can be securely trapped by the shale and capillary pressures were calculated. The shale's H₂ sealing capacity decreased with increasing pressure, increasing depth and TOC values. The CO₂/brine equilibrium contact angles were generally higher than H₂/brine equilibrium, suggesting that CO₂ could be used as favorable cushion gas to maintain formation pressure during UHS. The utmost height of H₂ that can be safely trapped by shale 3 (with TOC of 23.4 wt%) reduced from 8950 to 8750 M while that of shale 5 (with TOC of 0.081 wt%) reduced slightly from 9100 M to 9050 M as the pressure was increased from 5 to 20 MPa. The capillary entry pressure decreased with increasing depth and shale TOC, implying that the capillary trapping effect, as well as the over-pressure required to move brines from the pores by hydrogen displacement, reduces with increasing depth, and shale TOC. However, the shales remained at strongly water-wet conditions, having an equilibrium contact angles of not more than 17° at highest pressure and TOC. The study suggests that the increasing contact angles with increasing pressure and shale TOC, as well as decreasing column height and capillary pressure with increasing depth for H₂-brine-shale systems might not be sufficient to exert significant influence on structural trapping capacities of shale caprocks due to low densities of hydrogen.     

Cycle analysis of low and high H2 utilization SOFC/gas turbine combined cycle for CO2 recovery

A major factor in global warming is CO₂ emission from thermal power plants, which burn fossil fuels. One technology proposed to prevent global warming is CO₂ recovery from combustion flue gas and the sequestration of CO₂ underground or near the ocean bed. Solid oxide fuel cell (SOFC) can produce highly concentrated CO₂, because the reformed fuel gas reacts with oxygen electrochemically without being mixed with air in the SOFC. We therefore propose to operate multi-staged SOFCs with high utilization of reformed fuel to obtain highly concentrated CO₂. In this study, we estimated the performance of multi-staged SOFCs considering H₂ diffusion and the combined cycle efficiency of a multi-staged SOFC/gas turbine/CO₂ recovery power plant. The power generation efficiency of our CO₂ recovery combined cycle is 68.5%, whereas the efficiency of a conventional SOFC/GT cycle with the CO₂ recovery amine process is 57.8%.     

Geologic storage of carbon dioxide and enhanced oil recovery. I. Uncertainty quantification employing a streamline based proxy for reservoir flow simulation

Carbon dioxide (CO₂) is already injected into a limited class of reservoirs for oil recovery purposes; however, the engineering design question for simultaneous oil recovery and storage of anthropogenic CO₂ is significantly different from that of oil recovery alone. Currently, the volumes of CO₂ injected solely for oil recovery are minimized due to the purchase cost of CO₂. If and when CO₂ emissions to the atmosphere are managed, it will be necessary to maximize simultaneously both economic oil recovery and the volumes of CO₂ emplaced in oil reservoirs. This process is coined “cooptimization”.This paper proposes a work flow for cooptimization of oil recovery and geologic CO₂ storage. An important component of the work flow is the assessment of uncertainty in predictions of performance. Typical methods for quantifying uncertainty employ exhaustive flow simulation of multiple stochastic realizations of the geologic architecture of a reservoir. Such approaches are computationally intensive and thereby time consuming. An analytic streamline based proxy for full reservoir simulation is proposed and tested. Streamline trajectories represent the three-dimensional velocity field during multiphase flow in porous media and so are useful for quantifying the similarity and differences among various reservoir models. The proxy allows rational selection of a representative subset of equi-probable reservoir models that encompass uncertainty with respect to true reservoir geology. The streamline approach is demonstrated to be thorough and rapid.     

Gas hydrate formation process for pre-combustion capture of carbon dioxide

In this study, gas hydrate from CO₂/H₂ gas mixtures with the addition of tetrahydrofuran (THF) was formed in a semi-batch stirred vessel at various pressures and temperatures to investigate the CO₂ separation/recovery properties. This mixture is of interest to CO₂ separation and recovery from Integrated Gasification Combine Cycle (IGCC) power plants. During hydrate formation the gas uptake was determined and composition changes in the gas phase were obtained by gas chromatography. The impact of THF on hydrate formation from the CO₂/H₂ was observed. The addition of THF significantly reduced the equilibrium formation conditions. 1.0 mol% THF was found to be the optimum concentration for CO₂ capture based on kinetic experiments. The present study illustrates the concept and provides thermodynamic and kinetic data for the separation/recovery of CO₂ (pre-combustion capture) from a fuel gas (CO₂/H₂) mixture.     

Theoretical study of brine secondary imbibition in sandstone reservoirs: Implications for H2, CH4, and CO2 geo-storage

In gas geo-storage operations, the injected ex-situ gas will displace the in-situ formation brine and partially occupy the porous space of the target rock. In case of water-wet rock, the displaced formation brine re-imbibes into the in-situ porous space so that the system reaches thermodynamic equilibrium. This process, referred to as ‘secondary imbibition (SI)’, has important influences on the final gas geo-storage performance, as it determines gas loss (e.g., due to capillary forces, “residual trapping”) and injection/withdrawal efficiency. Herein, a fundamental analysis of this SI process in a single capillary tube was performed.Thus, the modified Lucas-Washburn equation was applied to a theoretical analysis, and the effects of gas type, formation depth, organic acid concentration, carbon number, and silica nanofluid on the SI dynamics were assessed. It was found that the SI rate depended on gas type following the order H₂, CH₄, CO₂, and that the SI rate increased with formation depth for H₂ and CH₄, while it decreased for CO₂. Further, the adsorbed organic matter reduced the SI rate, while the silica nanofluid aging accelerated the SI rate.These insights will promote fundamental understanding of gas geo-storage processes. This work thus will provide useful guidance on gas storage capacity optimization and containment security evaluation.     

A framework for assessing economics of blue hydrogen production from steam methane reforming using carbon capture storage & utilisation

Hydrogen (H₂) generation using Steam Methane Reforming (SMR) is at present the most economical and preferred pathway for commercial H₂ generation. This process, however, emits a considerable amount of CO₂, ultimately negating the benefit of using H₂ as a clean industrial feedstock and energy carrier. That has prompted growing interest in enabling CO₂ capture from SMR for either storage or utilisation and producing zero-emission “blue H₂”. In this paper, we propose a spatial techno-economic framework for assessing blue hydrogen production SMR hubs with carbon capture, utilisation and storage (CCUS), using Australia as a case study. Australia offers a unique opportunity for developing such ‘blue H₂’ hubs given its extensive natural gas resources, availability of known carbon storage reservoirs and an ambitious government target to produce clean/zero-emission H₂ at the cost of <A$2 kg^?1 by 2030. Our results highlight that the H₂ production costs are unsurprisingly dominated by natural gas, with the additional capital requirement of carbon capture and storage (CCS) also playing a critical role. These outcomes are especially pertinent for eastern Australian states, as they are experiencing high natural gas costs and would generally require extensive CO₂ transport and storage infrastructure to tap potential storage reservoirs, ultimately resulting in a higher cost of producing H₂ (>A$2.7 kg_H2^?1). On the other hand, Western Australia offers lower gas pricing and relatively lesser storage costs, which would lead to more economically favourable hydrogen production (<A$2.2 kg_H2^?1). We further explore the possibility of utilising the emissions captured at blue SMR hubs by converting them into formic acid through CO₂ electroreduction, yielding revenue that will decrease the cost of blue H₂ and reduce the reliance on CO₂ storage. Our analysis reveals that formic acid production utilising a 10 MW CO₂ electrolyser can potentially reduce H₂ production costs by between 4 and 9%. Further cost reduction is possible by scaling the CO₂ electrolyser capacity to convert a larger portion of the emissions captured, albeit at the cost of higher capital investment, electricity consumption and saturating the market for formic acid. Thus, carbon utilisation for a range of products with high market demand represents a more promising approach to replacing the need for costly carbon storage. Overall, our modelling framework can be adapted for global application, particularly for regions interested in generating blue H₂ and extended to include other CO₂ utilisation opportunities and evaluate other hydrogen production technologies.     

Blue sky mining: Strategy for a feasible transition in emerging countries from natural gas to hydrogen

Natural gas is often considered a transition fuel to a deep decarbonized world. However, for this to happen, new technologies should be fostered, among which a natural gas-based H₂ industry can become a key-option. This study tests the hypothesis that the development of a natural gas-based H₂ industry equipped with CO₂ capture can monetize natural gas remaining resources, mitigate CO₂ emissions and facilitate the transition to the renewable energy-based H₂. To do that, this study evaluates a stepwise strategy for setting up the development of H2, departing from the idle capacity in the existing natural gas industry, to progressively create a H₂ independent supply. Findings indicated that this strategy can be feasible, according to the case study assessed at relatively moderate crude oil prices. Nevertheless, CO₂ storage can become a constraint to deal with the co-produced CO₂ from the steam methane reforming units. Therefore, it is worth developing storage options.     

CO2-selective membranes for hydrogen purification and the effect of carbon monoxide (CO) on its gas separation performance

Industrial hydrogen production may prefer CO₂-selective membranes because high-pressure H₂ can therefore be produced without additional recompression. In this study, high performance CO₂-selective membranes are fabricated by modifying a polymer–silica hybrid matrix (PSHM) with a low molecular weight poly(ethylene glycol) dimethyl ether (PEGDME). The liquid state of PEGDME and its unique end groups eliminate the crystallization tendency of poly(ethylene glycol) (PEG). The methyl end groups in PEGDME hinder hydrogen bonding between the polymer chains and significantly enhance the gas diffusivity. In pure gas tests, the membrane containing 50 wt% additive shows CO₂ gas permeability and CO₂/H₂ selectivity of 1637 Barrers and 13 at 35 °C, respectively. In order to explore the effect of real industrial conditions, the gas separation performance of the newly developed membranes has been studied extensively using binary (CO₂/H₂) and ternary gas mixtures (CO₂/H₂/carbon monoxide (CO)). Compared to pure gas performance, the second component (H₂) in the binary mixed gas test reduces the CO₂ permeability. The presence of CO in the feed gas stream decreases both CO₂ and H₂ permeability as well as CO₂/H₂ selectivity as it reduces the concentration of CO₂ molecules in the polymer matrix. The mixed gas results affirm the promising applications of the newly developed membranes for H₂ purification.     

The CO2 storage capacity evaluation: Methodology and determination of key factors

It is a win–win technology to inject CO₂ into the oil or gas reservoirs. Because it can reduce the greenhouse gas emission and enhance oil recovery. In some oil or gas reservoirs, the reservoir water and the strong heterogeneity make the CO₂ storage capacity difficult to be determined. In this research, the CO₂ storage evaluation method is introduced. This method considers the CO₂ displacement efficiency, the CO₂ sweep efficiency, the CO₂ dissolution in oil and gas and the CO₂ displacement mechanism. The key factors in this evaluation method are determined by the reservoir simulation method, the thermodynamic theories and the statistical analysis methods separately. At last, the CO₂ storage capacity evaluation system is built. This system can be used to evaluate the CO₂ storage capacity fast and reliably and it worth to be promoted in the area of CO₂ storage.     

Hydroxyl aluminium silicate clay for biohydrogen purification by pressure swing adsorption: Physical properties,adsorption isotherm,multicomponent breakthrough curve modelling,and cycle simulation

Hydroxyl aluminium silicate clay (HAS-Clay) is a novel adsorbent in pressure swing adsorption for CO₂ capture (CO₂-PSA) and can also adsorb H₂S. To investigate the performance of HAS-Clay as a CO₂-PSA adsorbent, multicomponent breakthrough curves were determined using experimental measurements and theoretical models, and, based on those results, CO₂-PSA simulations were conducted. The breakthrough curves produced from the theoretical models agreed well with those derived from experiment. CO₂-PSA with HAS-Clay could purify biomass-gasification-derived producer gas of contaminants (carbon dioxide, methane, carbon monoxide, and hydrogen sulfide) with high CO₂ recovery and low energy input. The CO₂ recovery rate of CO₂-PSA with HAS-Clay was 58.4%, and the CO₂ purity was 98.4%. The specific energy demand was 2.83 MJ/kg-CO₂. In addition, the H₂S regenerability of HAS-Clay was investigated. The results show that HAS-Clay retained the ability to adsorb H₂S at a steady-state value of 0.02 mol/kg for the regeneration cycles. Therefore, it is suggested that CO₂-PSA with HAS-Clay is suitable for CO₂ separation from multicomponent gas mixtures.     

Thermodynamic analysis of a novel fossil-fuel–free energy storage system with a trans-critical carbon dioxide cycle and heat pump

This paper presents and analyzes a novel fossil-fuel–free trans-critical energy storage system that uses CO₂ as the working fluid in a closed loop shuttled between two saline aquifers or caverns at different depths: one a low-pressure reservoir and the other a high-pressure reservoir. Thermal energy storage and a heat pump are adopted to eliminate the need for external natural gas for heating the CO₂ entering the energy recovery turbines. We carefully analyze the energy storage and recovery processes to reveal the actual efficiency of the system. We also highlight thermodynamic and sensitivity analyses of the performance of this fossil-fuel–free trans-critical energy storage system based on a steady-state mathematical method. It is found that the fossil-fuel–free trans-critical CO₂ energy storage system has good comprehensive thermodynamic performance. The exergy efficiency, round-trip efficiency, and energy storage efficiency are 67.89%, 66%, and 58.41%, and the energy generated of per unit storage volume is 2.12 kW·h/m³, and the main contribution to exergy destruction is the turbine reheater, from which we can quantify how performance can be improved. Moreover, with a higher energy storage and recovery pressure and lower pressure in the low-pressure reservoir, this novel system shows promising performance.