Gas Storage Capacity Research Articles

Risk assessment of domino effects under fire and explosion accidents in LNG storage tank farms based on Bayesian network

With the increase of liquefied natural gas (LNG) storage capacity, the number of storage tanks in LNG tank farms increases, which makes the possibility of domino effect higher, so it is important to analyze the risk of domino effect in LNG tank farms. However, the traditional domino effect risk assessment only considers a single accident type, which is not consistent with reality. Therefore, a Bayesian network-based risk assessment method for the domino effect of fire and explosion accidents in LNG storage tank farm is proposed in this study. The method utilizes the Bayesian network approach to model the propagation of domino accidents and calculate the failure probability of domino effects under fire and explosion accidents. The most likely sequence of accidents and the critical tank in the LNG storage tank farm can also be defined through the Bayesian network inference. Finally, the reliability of the proposed method is proved by a real case. Compared with only considering a single accident type, mixed accident types lead to a more reasonable result in the domino effect probabilistic analysis. It is believed that the developed approach has great theoretical significance for domino accident prevention and control in LNG storage tank farms.

Enhancing hydrate-based natural gas storage capacity via optimal concentrations of epoxycyclopentane

With the growing demand for energy, natural gas has gained attention as a lower-emission option compared to the other conventional fossil fuels such as oil and coal. Consequently, there is significant interest in developing energy-efficient natural gas storage technologies. Gas hydrate-based storage offers a promising solution due to its relatively high capacity at moderate operating pressure and temperature conditions. Epoxycyclopentane (ECP) has emerged as an effective thermodynamic promoter, but its limited miscibility in water can influence storage capacity depending on its concentration. This study investigated the effect of varying ECP concentrations (4.0, 5.0, 5.6, 6.0, 6.5, and 7.0 mol%) on the gas storage capacity of hydrates formed from pure CH4 and a natural gas mixture (CH4 (90%) + C2H6 (7%) + C3H8 (3%)). We systematically examined thermodynamic stability, formation kinetics, crystalline structure, and guest distribution in ECP hydrates. The results revealed that ECP significantly promoted hydrate thermodynamic formation across all concentrations, with the optimal concentration for natural gas storage identified as 6.5 mol%, which achieved the highest gas storage capacity. Synchrotron XRD confirmed the formation of sII hydrates in both ECP + natural gas and ECP + CH4. Raman and 13C solid-state NMR analyses showed no CH4 occupancy in sII-L, which suggests the absence of pure natural gas hydrates. Cage occupancy estimation revealed that the highest CH4 occupancy in sII-S cages occurred at 6.5 mol% ECP, which contributed to an enhanced gas uptake. Time-dependent in-situ Raman and NMR analyses demonstrated that excess ECP can induce a two-step formation process, which further enhances storage capacity. Hence, we believe that these findings offer valuable insights into optimizing ECP concentration for the development of hydrate-based natural gas storage.

Evaluating flue gas geo-sequestration and EOR in fractured reservoirs through simulated synergistic reservoir characteristics and injection kinetics

The global reliance on hydrocarbon resources and fossil fuels has resulted in a significant surge in carbon dioxide emissions, necessitating urgent measures to mitigate greenhouse gas emissions. Integrating CO2 storage with enhanced oil recovery (EOR) presents a promising solution for reducing emissions and enhancing oil recovery by sequestering CO2 within oil reservoirs, especially in fractured carbonate reservoirs. The research utilized the Eclipse simulator to model different gas injection scenarios in a crude oil reservoir, focusing on assessing the effectiveness of CO2 and flue gas geo-sequestration and EOR, performing sensitivity analyses on reservoir characteristics, and evaluating the impact of varying injection rates on gas storage capacity and oil recovery factor. The findings demonstrated a superior capacity to store flue gas (150 MMSCF) in comparison to CO2 (85 MMSCF) and flue gas injection demonstrated better reservoir pressure maintenance than CO2 injection, while CO2 injection resulted in a higher oil recovery factor of 52% compared to flue gas injection at 36%. Additionally, analysis of reservoir characteristics in gas storage revealed that, an augmentation in reservoir porosity, permeability, and injection rate substantiated an increase in gas storage capacity for both CO2 and flue gas injection. Except for CO2 storage, which displayed a normal distribution trend in the permeability analysis. Additionally, it was elucidated that higher reservoir pressure and temperature in flue gas injection resulted in a reduction of gas storage capacity, while these variables exhibited relative stability in the context of CO2 injection. The scrutiny of gas storage in reservoir characteristics unveiled substantial alterations in porosity and injection rate, signifying their pivotal roles in influencing gas storage capacity. In the EOR study, heightened reservoir pressure, temperature, permeability, and injection rate collectively contributed to an amplified oil recovery for both flue gas and CO2, except CO2 injection demonstrated a normal distribution trend in oil recovery within the permeability analysis. Conversely, higher porosity was associated with a decrease in oil recovery. The findings of this research provide valuable insights into the feasibility and effectiveness of employing flue gas geo-sequestration and EOR in fractured carbonate reservoirs.

A Stable Layered Microporous MOF Assembled with Y-O Chains for Separation of MTO Products.

Benefiting from highly tunable pore environments, some metal-organic frameworks (MOFs) have recently shown promising prospects in the separation of methanol-to-olefin (MTO) products (mainly C3H6 and C2H4). However, the "trade-off" between gas storage capacity and selectivity always results in inefficient separation. In addition, poor stability of MOFs also limits practical separation applications. Herein, we have successfully assembled a layered Y-MOF (FJI-W9) with bent diisophthalate ligands (H4L), Y-O chains, and 2-fluorobenzoic acids. As expected, FJI-W9 not only exhibits good chemical stability but also shows significant potential for C3H6/C2H4 separation. For FJI-W9, the C3H6 uptake at 298 K and 10 kPa is 63 cm3/g, and the IAST selectivity of FJI-W9 for C3H6/C2H4 (V/V = 50/50) is calculated to be 20.5. To the best of our knowledge, both C3H6 uptake and selectivity of FJI-W9 surpass most porous materials. GCMC simulation indicates that the special supramolecular binding sites in FJI-W9 have much stronger interactions with C3H6 than C2H4 molecules. More importantly, practical breakthrough experiments demonstrate that FJI-W9 can effectively separate C3H6/C2H4 (50/50) mixtures, thus obtaining high-purity C2H4 and C3H6, respectively.

Substantial gas enrichment in shales influenced by volcanism during the Ordovician–Silurian transition

The substantial gas enrichment in shales of the Ordovician–Silurian transition is associated with the development of the organic matter (OM)-rich source rock. While organic matter enrichment has been linked to intensive volcanism, it remains a challenge to precisely evaluate the impact of the volcanism on substantial gas enrichment containing the largest gas storage capacity. This study focused on consecutive borehole shale samples from the Wufeng–Longmaxi formations during the Ordovician–Silurian transition in southern China. We conducted a comprehensive analysis, integrating the major geological volcanism with high-resolution analysis, including QEMSCAN, argon-ion SEM, thin-section examination, XRD mineralogy, TOC, Hg concentration, petrophysical properties and nanopore structure analysis (low-pressure CO2/N2 gas adsorption, helium porosity and permeability). The results link the significant shale gas enrichment in Wufeng–Longmaxi formations to intensive volcanism across the Ordovician–Silurian transition. We identified the most favorable shale intervals in the lower Longmaxi Formation, aligning with the peak period of volcanism. This period showed synchronous spikes in Hg, Hg/TOC, and TOC contents. Shale deposited during this favorable paleoenvironment exhibited the highest values of TOC, porosity, permeability, specific surface area, pore volume, and maximum gas adsorption capacity, leading to the largest amount of gas content and substantial gas enrichment. Our work, therefore, provides new insights into identifying the most favorable shale gas resources. This knowledge assists in accurate predictions of the stratigraphic ‘sweet spot’ intervals for large shale gas storage capacity, providing crucial information for engineering explorations and developments in shale formations.

Exploring the demand for inter-annual storage for balancing wind energy variability in 100% renewable energy systems

As research in 100% renewable energy systems progresses, closing remaining research gaps, such as quantifying inter-annual balancing requirements, is necessary. For this study, inter-annual variations of wind power yield and the resulting balancing requirements are analysed for the energy transition towards 100% renewable energy of the United Kingdom and the Republic of Ireland. The energy system components are determined and cost implications are quantified comparing two options for inter-annual storage: e-hydrogen and e-methane for a low, medium, and high security case, which are expanded over ten years. The results indicate that more than 300 TWhth,LHV and 500 TWhth,LHV of inter-annual gas storage capacity in 2050 for the low and the high security case, respectively are required. For both investigated cases, the annual system costs increase notably compared to the reference scenario without inter-annual storage. For the case of e-hydrogen, the annualised system costs increase by 19% compared to an increase of 7% for e-methane for medium security cases. The difference in cost growth is due to significantly higher hydrogen underground storage costs that overcompensate additional system costs for e-methane production. This study provides an expansion from seasonal to inter-annual storage and a first estimate of inter-annual balancing requirements and costs.

Single-Crystalline 3D Covalent Organic Frameworks with Exceptionally High Specific Surface Areas and Gas Storage Capacities.

Single-crystalline covalent organic frameworks (COFs) are highly desirable toward understanding their pore chemistry and functions. Herein, two 50-100 μm single-crystalline three-dimensional (3D) COFs, TAM-TFPB-COF and TAPB-TFS-COF, were prepared from the condensation of 4,4',4″,4‴-methanetetrayltetraaniline (TAM) with 3,3',5,5'-tetrakis(4-formylphenyl)bimesityl (TFPB) and 3,3',5,5'-tetrakis(4-aminophenyl)bimesityl (TAPB) with 4,4',4″,4‴-silanetetrayltetrabenzaldehyde (TFS), respectively, in 1,4-dioxane under the catalysis of acetic acid. Single-crystal 3D electron diffraction reveals the triply interpenetrated dia-b networks of TAM-TFPB-COF with atom resolution, while the isostructure of TAPB-TFS-COF was disclosed by synchrotron single-crystal X-ray diffraction and synchrotron powder X-ray diffraction with Le Bail refinements. The nitrogen sorption measurements at 77 K disclose the microporosity nature of both activated COFs with their exceptionally high Brunauer-Emmett-Teller surface areas of 3533 and 4107 m2 g-1, representing the thus far record high specific surface area among imine-bonded COFs. This enables the activated COFs to exhibit also the record high methane uptake capacities up to 28.9 wt % (570 cm3 g-1) at 25 °C and 200 bar among all COFs reported thus far. This work not only presents the structures of two single-crystalline COFs with exceptional microporosity but also provides an example of atom engineering to adjust permanent microporous structures for methane storage.

Transient pressure prediction in large-scale underground natural gas storage: A deep learning approach and case study

Large-scale underground natural gas storage (UNGS) facilities typically allocate only one month annually for well shut-in to facilitate pressure build-up. This limited well shut-in period affects the subsequent pressure measurements and evaluation of gas storage capacity. This study proposes a novel workflow to directly predict the transient pressure behavior of UNGS during pressure build-up without requiring additional well shut-in operations. The proposed workflow uses the gas injection-withdrawal rate as a dynamic input feature for a deep learning model, with reservoir pressure as the output feature. An enhanced WA-BiLSTM model integrates multiple physical mechanisms and advanced optimization algorithms. The model achieves mean squared error (MSE) of 2 × 10-3, which is less than 5 % of traditional model's results. Field data from the largest Hutubi UNGS exhibit a prediction accuracy of 99.0 % during the well shut-in phase. High-precision prediction results with low MSE ensure the reliability of pressure derivative data. By analyzing the predicted pressure data, the actual gas storage volume is 104.75 × 108 m3, accounting for 97.9 % of the facility's designated storage capacity.

Optimizing Underground Natural Gas Storage Capacity through Numerical Modeling and Strategic Well Placement

This study focuses on optimizing the storage capacity of an underground natural gas storage facility through numerical modeling and simulation techniques. The reservoir, characterized by an elongated dome structure, was discretized into approximately 16,000 cells. Simulations were conducted using key parameters such as permeability (10–70 mD) and porosity (12–26%) to assess the dynamics of gas injection and pressure distribution. The model incorporated core and petrophysical data to accurately represent the reservoir’s behavior. By integrating new wells in areas with storage deficits, the model demonstrated improvements in storage efficiency and pressure uniformity. The introduction of additional wells led to a significant increase in storage volume from 380 to 512 million Sm³ and optimized the injection process by reducing the storage period by 25%. The study concludes that reservoir performance can be enhanced with targeted well placement and customized flow rates, resulting in both increased storage capacity and economic benefits.

Depressurization-induced production of shale gas in organic-inorganic shale nanopores: A kinetic Monte Carlo simulation

Methane gas production from unconventional reservoirs, such as shale formations, is in high demand due to the global energy needs. However, maximizing production remains challenging due to the ultra-tight porosity, heterogeneity, and complex nature of shale rocks under high pressure. To address this issue, we employ a novel kinetic Monte Carlo (kMC) simulation to investigate the molecular-level behavior of shale gas in both homogeneous and heterogeneous organic-inorganic shale nanopores. This approach not only provides accurate computations of shale gas under high pressure but also aims to uncover the mechanisms of shale gas storage at reservoir pressure and production during pressure drawdown. Our findings indicate that organic shale ultramicropores (pore width < 0.7 nm) contribute significantly to the highest storage capacity of shale gas but pose challenges for production capacity solely through depressurization. In contrast, the free gas zone is the primary source of shale gas production from mesoporous shales, which has a high recovery efficiency but a low production capacity due to less pronounced interaction effects from the shale surface. The heterogeneous nature of shale surfaces leads to asymmetric distributions of density and potential energy across pore widths, with methane molecules favoring locations near organic pore walls due to stronger attractive interactions, while inorganic pore walls facilitate shale gas migration. Interestingly, the optimal ultramicropore size yields the highest recovery efficiency of shale gas via depressurization, characterized by a transition from near-commensurate to incommensurate molecular packing between reservoir and post-drawdown pressures. Based on these detailed molecular simulations, further research is necessary to develop innovative techniques for enhancing shale gas recovery, especially in micropores.

Structural strength and fatigue analyses of large-scale underwater compressed hydrogen energy storage accumulator

Underwater compressed hydrogen energy storage (UWCHES) is a potential solution for offshore energy storage. By taking advantage of the hydrostatic pressure of deep seawater, the compressed hydrogen can be isobarically stored in underwater artificial energy storage accumulators. The accumulator should withstand high pressure and large buoyancy and possess reliable anchoring to the seabed. In this study, the structural strength analysis and fatigue life of the large-scale accumulator is conducted employing the finite element method (FEM). The dimensionless stress prediction model and dimensionless fatigue life prediction model are developed through dimensional analysis and multivariate regression analysis. The performance of the accumulator with operating water depth of 100∼300 m, gas storage volume of 1081∼10128 m³, and concrete wall thickness of 0.1∼0.63 m is investigated. The results show that with an operating water depth of 100 m, gas storage capacity of 10,128 m3, and concrete wall thickness of 0.63 m, the maximum compressive stress is 1.43 MPa (yield strength is 60 MPa) and the maximum tensile stress of the accumulator is 2.55 MPa (yield strength is 6 MPa). The design fatigue life is 106 cycles which is larger than the expected service life of 104 cycles. Therefore, the accumulator structure meets the static strength and fatigue life. As the operating water depth increases with a consistent gas storage capacity, a transition in the stress state shifts from primarily tensile stress to predominantly compressive stress. The accuracy of the dimensionless stress prediction model and the dimensionless fatigue life prediction model were verified, with maximum deviations of 10.3 % and 13.7 %, respectively. Furthermore, the anchoring factor of safety of 1.12 is achieved.

Spatial evolution of CO2 storage in depleted natural gas hydrate reservoirs and its synergistic efficiency analysis

Carbon neutrality is now a common strategic target worldwide, with geological storage seen as the mainstream scheme to address CO2 emissions and the greenhouse effect. Depleted natural gas hydrate reservoirs (DNHR), with their high-pressure, low-temperature environment, could capture CO2 in the form of hydrates, being an innovative way for carbon storage. A lab-scale reactor was used in this work to simulate CO2 injection into the reservoir after gas hydrate exploitation. As expected, it was found that the low-temperature environment of the depleted reservoir at the end of gas production provided a high driving force and accelerated the rate of CO2 hydrate formation. Consequently, the maximum gas storage capacity was increased by 66% by optimizing the injection timing and reducing the gas injection flow rate to enable enough hydrate formation. Besides, the formation of CO2 hydrate in the DNHR could also help stabilize the reservoir to achieve a more efficient CH4 production and CO2 storage. This study provides a novel strategy for gas hydrate exploitation as well as subsequent geological storage of CO2 in depleted natural gas hydrate reservoirs by making full use of their favorable conditions.

Graphene pillared - Porous graphene framework; structural analysis and gas storage capacities

Porous graphene structures continue to attract attention with their increasingly superior properties. Especially through carbon-based porous structures in a framework form have found applications in various fields such as gas storage. In this study, graphene fragments were utilized as pillars between graphene layers to create a novel framework structure, and geometry optimization was performed under different external pressures. Adsorptions of hydrogen, carbon dioxide, and methane gases, which need to be controlled for combating global warming, were investigated for the optimized structure. It is found that the structure which withstand deformations up to 5 GPa of external pressure could store 2.005 wt % hydrogen hydrogen at room temperature and 100 bar pressure. Moreover, capable to adsorb 6.426 and 8.776 mmol/g carbon dioxide and methane at room temperature and 1 bar pressure, respectively. In conclusion, alongside other potential applications like electrical and energy storage, its usability as a gas adsorbent for combating global warming have a great potential.

A Review of the Utilization of CO2 as a Cushion Gas in Underground Natural Gas Storage

A cushion gas is an indispensable and the most expensive part of underground natural gas storage. Using CO2 injection to provide a cushion gas, not only can the investment in natural gas storage construction be reduced but the greenhouse effect can also be reduced. Currently, the related research about the mechanism and laws of CO2 as a cushion gas in gas storage is not sufficient. Consequently, the difference in the physical properties of CO2 and CH4, and the mixing factors between CO2 and natural gas, including the geological conditions and injection–production parameters, are comprehensively discussed. Additionally, the impact of CO2 as a cushion gas on the reservoir stability and gas storage capacity is also analyzed by comparing the current research findings. The difference in the viscosity, density, and compressibility factor between CO2 and CH4 ensures a low degree of mixing between CO2 and natural gas underground, thereby improving the recovery of CH4 in the operation process of gas storage. In the pressure range of 5 MPa–13 MPa and temperature range of 303.15 K–323.15 K, the density of CO2 increases five to eight times, while the density of natural gas only increases two to three times, and the viscosity of CO2 is more than 10 times that of CH4. The operation temperature and pressure in gas storage should be higher than the temperature and pressure in the supercritical conditions of CO2 because the diffusion ability between the gas molecules is increased in these conditions. However, the temperature and pressure have little effect on the mixing degree of CO2 and CH4 when the pressure is over the limited pressure of supercritical CO2. The CO2, with higher compressibility, can quickly replenish the energy of the gas storage facility and provide sufficient elastic energy during the natural gas production process. In addition, the physical properties of the reservoir also have a significant impact on the mixing and production of gases in gas storage facilities. The higher porosity reduces the migration speed of CO2 and CH4. However, the higher permeability promotes diffusion between gases, resulting in a higher degree of gas mixing. For a large inclination angle or thick reservoir structure, the mixed zone width of CO2 and CH4 is small under the action of gravity. An increase in the injection–production rate intensifies the mixing of CO2 and CH4. The injection of CO2 into reservoirs also induces the CO2–water–rock reactions, which improves the porosity and is beneficial in increasing the storage capacity of natural gas.

Assessment of the source rock potential in the Sirka and Giddi collieries of South Karanapura coalfield, Jharkhand, India: Insights from megaflora, palynology, and geochemistry

Permian deposits in the Indian Peninsula have long been a significant source of coal and have great potential for hydrocarbon exploration. Here we present results of megafloral, palynological, and geochemical analysis of the Late Artinskian-Kungurian sediments in the South Karanpura coalfield to assess hydrocarbon generation potential, kerogen types, depositional settings, and thermal maturation. The results suggest anoxic to oxic depositional environments with fluctuating water levels, influenced by terrestrial inputs. The Sirka colliery is considered to be most favorable for hydrocarbon generation due to the palaeodepositional setting dominated by flooded palaeomires. The dominance of degraded organic matter and the rarity of opaque phytoclasts suggest type II/III to type III kerogen material in the palaeomire of the Srika succession, characterized by low-energy dysoxic to anoxic conditions. The thermal maturation values (Tmax 429℃) and the production index (0.01–0.02) indicate that the Sirka area has immature kerogen, but the Giddi colliery has a relatively higher Tmax (average 435℃) placing the studied sample within the mature zone. However, due to deposition in the oxidized swamp, Giddi C has poor potential for hydrocarbon generation, showing that type III/IV material has charcoal input into the sediments. Our findings contribute to global knowledge of coal formations’ oil and gas storage capacity, which has implications for energy resource assessment and exploration strategies.

Uncovering optimal carbon and boron nitride nanotube geometries for methane and hydrogen release

We screened 1651 carbon and boron nitride (BN) nanotubes to investigate methane release at 298 K and hydrogen release at 77 K through grand canonical ensemble Monte Carlo (GCMC) simulations. The effects of nanotube radius, density, and van der Waals spacing on the release quantities of these gases were explored. Our research shows that CH4 release in C(40,40) and BN(40,40) nanotubes reaches a high of 0.15 g/g, below the DOE's 0.5 g/g target. Similarly, the best nanotubes for volumetric release, C(21,9) and BN(18,18), peak at 175 cm³/cm³, below the DOE target of 330 cm³/cm³. This suggests that internal adsorption within isolated nanotubes is insufficient to meet DOE targets, highlighting the need for optimization of inter-tube van der Waals spacing. For H2, C(40,39) and BN(40,40) nanotubes are optimal for weight release, achieving up to 12.19% at a pressure of 8 MPa. This surpasses the 2025 DOE benchmark of 5.5 wt%. Meanwhile, C(28,7) and BN(24,24) nanotubes are most suitable for volumetric release. The C(28,7) nanotube, recommended for H2 storage, reaches a volumetric release quantity close to the DOE target of 0.04 kg/L at a van der Waals spacing of 1 nm. At pressures exceeding 2 MPa, the weight adsorption outside nanotubes accounts for 40–55% of the total, underscoring the pivotal role of extra-tube adsorption in gas storage capacity for both CH4 and H2. The results provide a foundation for the design of nanotube-based materials for efficient gas storage and release, with implications for clean energy applications.

Experimental study on the influence of particle size and grain grading on the CO2 hydrate formation and storage process in porous media

CO2 sequestration in sediments as hydrate form is considered to be a promising way to achieve CO2 emission reduction in the atmosphere. The key problem with hydrate-based technology for CO2 geological storage is the evaluation of the formation process and gas storage capability of hydrate. In this study, the fundamental issue of different particle size and grain grading affected CO2 hydrate formation and storage characteristics in porous media was deeply analyzed. The effect of various particle sizes and grain grading on the gas consumption rate and gas storage capacity of CO2 hydrate were quantitatively illustrated. The results indicated that the hydrate formation is more difficult in porous media with tiny particle sizes. The gas storage capacity and gas consumption rate of CO2 hydrate increased as the particle size increased within a range of 10–63 μm. The maximum gas storage capacity attains 25.65 L/L when the particle size is 63 μm. Besides, compared with single particle size, porous media with grain gradation is adverse to hydrate formation. The results also show that, the obstruction effect on the gas consumption rate and gas storage capacity is more obvious with the increase of the differences in grain gradation. The cooperative impact of particle size and gradation on hydrate formation was studied. The closer the size of the mixed particles is, the more favorable to hydrate formation. The relevant results will aid in comprehending the hydrate formation properties in submarine sediments and will serve as an essential theoretical reference and guide for CO2 capture and sequestration hydrate-based method.

High-performance static formation of methane hydrate in fixed bed constructed by incorporating expanded graphite into polyimide foam

Hydrate has been endowed with great potential in energy storage and transportation. However, the kinetics of its formation process has been a challenge, often requiring dynamic mechanical processes that are energy-intensive and cumbersome to operate. Herein, a well-designed expanded graphite (EG)/polyimide (PI) foam was first explored as fixed bed for the formation of methane hydrate. The results demonstrate that the EG/PI fixed bed exhibits a remarkable performance in hydrate formation under static conditions, with a high gas storage capacity of 149 V/V, a short induction time and a rapid formation rate of 13.1 V·V−1·min−1 at 6 MPa and −2 °C, and excellent recyclability, which are attributed to its stable micro/macro structures. Thereinto, the pores of EG serves as gas adsorption and reaction sites, initialing the formation with extremely short induction time. The three-dimensional framework of PI foam supports the uniform dispersion of EG particles and enables the efficient formation of hydrate under static condition. The EG/PI fixed bed decreases the water freezing point and leads to a high supercooling that facilitates the rapid nucleation of hydrate. Meanwhile, the fixed bed provides extensive mass-transfer channels, sufficient growing space, and superior heat conductivity, which contribute to the hydrate growth under static condition. This work not only offers a novel strategy for fabricating high-performance fixed bed, but also provides an insight into its promotion mechanism in hydrate formation.

Effect of geothermal heat transfer on performance of the adiabatic compressed air energy storage systems with the salt cavern gas storage

The temperature and pressure of compressed air influence the output performance of the adiabatic compressed air energy storage system with salt cavern gas storage. However, current studies often overlook the impact of geothermal heat transfer on system performance. In this paper, a mathematical model of the energy storage system with salt cavern gas storage is developed, considering the geothermal heat transfer in wellbore and salt carven. The model is used to illustrate the effects of geothermal heat transfer on the system performance through a sensitivity analysis of some key parameters. The results show that geothermal heat transfer will significantly reduce the gas and energy storage capacity, with a maximum reduction of 15.3 % and 11.1 % at a depth of 2000 m, respectively. Furthermore, this reduction would increase with the depth of the salt cavern. The geothermal energy reduces the round-trip efficiency from 68.7 % to 66.26 % and the energy storage density from 5.18 kWh·m−3 to 4.32 kWh·m−3. For common salt cavern gas storage at a depth of about 600 m ∼ 1200 m, the negative impacts of geothermal heat transfer on round-trip efficiency and energy storage density are less than 2.2 % and 0.5 kWh·m−3, respectively. Sensitivity analysis also demonstrates that the primary factors influencing the system’s performance are the thermal conductivity of the surrounding rock, the volume of the salt cavern, and the length of the wellbores. The secondary factors include the heat transfer coefficient on the inner wall of the salt cavern, the inner pipe radius, and the roughness of the inner pipe. Irrelevant factors include the thermal conductivity of the protective fluid and the thermal conductivity of the cement layer. The proposed comprehensive mathematical model of the system and simulation findings aid in forecasting the performance of storage systems and offer theoretical guidance for the design of large-scale compressed air energy storage systems.

Evaluation of underground gas storage capacity in the depleted gas reservoir with water evaporation and salt precipitation

Water evaporation and salt precipitation will occur in gas reservoirs and underground gas storage (UGS) with high-salinity formation water during production and operation. This phenomenon seriously affects the efficient and safe operation and gas storage capacity. This work focuses on quantitatively evaluating the UGS capacity based on depleted gas reservoirs considering water evaporation and salt precipitation. The core flooding experiments are conducted to analyze the influence of water evaporation and salt precipitation on rock properties under different water salinity during multi-cycle injection-production. A numerical model considering water evaporation is established to determine the salt precipitation radius around the gas well. According to the experimental and simulation results, a new analytical model is developed to calculate the underground natural gas storage capacity based on material balance principles. The field case study is presented to show the practical potential of the established model. Both formation porosity and permeability in near-well region may be finally improved by water evaporation and salt precipitation under irreducible water condition. In the presence of movable-water, formation porosity and permeability of the near-well region may be firstly improved and finally reduced due to continuous salt precipitation in porous media. Salt-precipitation radius achieves 28.5 m after ten cycles. The UGS capacity is 101.11 × 108 m3 without considering salt precipitation, 1.11% higher than original geological reserves. The UGS capacity considering both irreducible-water evaporation and salt precipitation is 101.03 × 108 m3. However, when the moveable-water evaporation volume increases to 15Virr, the final UGS capacity is further decreased to 98.55 × 108 m3. The UGS capacity has decreased by 0.82%, 1.64%, and 2.45% compared with irreducible water. The continuous evaporation of movable water and salt deposition will reduce the gas storage capacity and cause damage to the UGS. This work provides an effective method to investigate the quantitative impact of water evaporation and salt precipitation on UGS capacity.