Depleted Gas Reservoir Research Articles

Hydrate management strategies for CO2 injection into depleted gas reservoirs

Sequestering CO2 in depleted gas reservoirs using carbon capture, utilization, and storage technologies has emerged as a viable strategy for mitigating global carbon emissions. However, CO2 hydrate formation during injection processes is challenging and poses a risk to the operational integrity and efficiency of sequestration projects. This study investigated CO2 hydrate formation dynamics within silica gel environments that closely mimicked the median pore size of natural sandstone reservoirs, particularly targeting depleted gas fields in the East Sea of Korea. Integrating kinetic insights into experimental hydrate formation assessments and molecular dynamics simulations provided a comprehensive understanding of the CO2 hydrate formation mechanisms, as well as the formation dynamics and stability of the CO2 hydrates. For example, the hydrate formation kinetics were significantly reduced in the small pores, suggesting the feasibility of implementing more economical hydrate inhibitor injection strategies during CO2 injection. Moreover, this study evaluated the inhibitory effects of NaCl and methanol on CO2 hydrate stability by accurately measuring the three-phase (H-Lw-V) equilibria and employing silica gels (6 nm pore size). The presence of methanol and amorphous silica significantly impacted hydrate formation, with methanol potentially influencing the local structure around the hydrate phase and silica hindering hydrate growth through dynamic interactions with CO2 molecules. In addition, we elucidated the complex interplay between CO2, water, and methanol (hydrate inhibitor) within the constrained environments of porous media, offering strategic insights for the development of effective CO2 injection and sequestration strategies. Integrating molecular-level observations with real-world geological modeling presents a novel methodology for enhancing the safety, efficiency, and environmental sustainability of carbon capture and storage operations. The findings of this study provide critical insights into hydrate phase behavior, highlighting the importance of precise equilibrium determination under simulated reservoir conditions to effectively anticipate and mitigate hydrate formation challenges.

Research on the Injection–Production Law and the Feasibility of Underground Natural Gas Storage in a Low-Permeability Acid-Containing Depleted Gas Reservoir

Depleted gas reservoirs are important places for the rebuilding of gas-storage reservoirs. In order to demonstrate the feasibility of constructing and operating such underground gas storage, a low-permeability gas-storage seepage model considering fracture development was developed and established. The model was solved using semi-analytical methods, and the pressure–response characteristics during natural gas injection were analyzed. The impact of gas injection volume on formation pressure has been clarified, and the calculation method for ultimate injection pressure has been determined. Additionally, through numerical simulation methods, the migration law of acidic gas during gas injection, the variation law of produced acidic gas concentration, and the main control factors affecting the concentration of the produced acidic gas were studied. Furthermore, measures to reduce the concentration of the acidic gas produced were proposed. Finally, injection and production plans were designed for typical depleted acidic gas reservoirs, simulating the operation of gas storage for 12 cycles. The results indicate that the quality of natural gas produced in the third cycle can meet the Class II standard for commercial natural gas. Through this study, the feasibility of constructing gas-storage facilities for acidic depleted gas reservoirs has been demonstrated, and injection and production strategies for this type of gas reservoir have been proposed.

Roles of kaolinite-oil-gas molecular interactions in hydrogen storage within depleted reservoirs

Hydrogen is a clean alternative to fossil fuels, emitting only water vapor during combustion. In a future hydrogen economy, large-scale storage will be an important component of the supply chain. Due to its low volumetric density, conventional surface storage methods are inadequate. Underground hydrogen storage (UHS) offers a viable solution, enabling the storage of millions of cubic meters. Among potential geological sites, including salt caverns, aquifers, and depleted gas reservoirs, depleted oil reservoirs show promise. Studying hydrogen interactions with residual oil and reservoir minerals is vital for understanding the properties of hydrogen and the reservoir post-injection. In this study, we employed molecular dynamics simulations to gain molecular-level insights into these interactions. We investigated hydrogen dissolution in oil, adsorption at kaolinite/oil interfaces, the role of CO2 as a cushion gas, and the influence of kaolinite’s hydrophobicity on H2 behavior. The main findings include: (1) hydrogen dissolves more in oil than in water, (2) the introduction of CO2 suppresses hydrogen dissolution in oil and reduces the interfacial tension (IFT) between oil and gas, (3) CO2 decreases H2 partitioning near kaolinite surfaces due to its strong affinity for the hydrophilic gibbsite surface of kaolinite, and (4) CO2 is more effective than H2 in reducing IFT between kaolinite and the oil–gas mixture. These findings emphasize the effectiveness of CO2 as a cushion gas and the important role of clay hydrophobicity in UHS, providing insights that are challenging to obtain experimentally.

Software for CO2 Storage in Natural Gas Reservoirs

The paper presents a simulation-based approach for optimizing CO2 injection into depleted gas reservoirs, with the goal of enhancing underground CO2 storage. The research employs a two-dimensional dynamic reservoir model, developed using Darcy’s law, to describe gas flow in a pressure-homogeneous porous medium, along with real gas equations. The model integrates the Du Fort–Frenkel and finite-difference methods to accurately simulate the behavior of CO2 during injection and storage. Real data from an operational gas storage facility were used to calibrate the model. CO2sim v1 software, specifically developed for this purpose, simulates CO2 injection cycles and quiescence phases, enabling the optimization of storage capacity and energy efficiency. The reservoir model, based on the engineering of the geological structure, is discretized into approximately 16,000 cells and solved using the finite-difference method, allowing for rapid simulation of CO2 injection and quiescence processes. The average computation time for a 150-day cycle is approximately 5 min. Simulation results indicate that increasing the number of injection wells and carefully controlling the injection rates significantly improves the distribution of CO2 within the reservoir, thereby enhancing storage efficiency. Additionally, appropriate well placement and prolonged quiescence periods lead to better CO2 dispersion, increasing the storage potential while reducing energy costs. The study concludes that further development of the software, along with comprehensive technical and economic assessments, is required to fully optimize CO2 storage on a commercial scale.

On the Significance of Hydrate Formation/Dissociation during CO2 Injection in Depleted Gas Reservoirs

Summary The study aims to quantitatively assess the risk of hydrate formation within the porous formation and its consequences on injectivity during storage of CO2 in depleted gas reservoirs considering low temperatures caused by the Joule-Thomson (JT) effect and hydrate kinetics. Hydrates formed during CO2 storage operation can occupy porous spaces in the reservoir rock, reducing the rock’s permeability and thus becoming a hindrance to the storage project. The aim was to understand which mechanisms can mitigate or prevent the formation of hydrates. The key mechanisms we studied included water dry-out, heat exchange with surrounding rock formation, and capillary pressure. A semicompositional thermal reservoir simulator is used to model the fluid and heat flow of CO2 through a reservoir initially composed of brine and methane. The simulator can model the formation and dissociation of both methane and CO2 hydrates using kinetic reactions. This approach has the advantage of computing the amount of hydrate deposited and estimating its effects on the porosity and permeability alteration. Sensitivity analyses are also carried out to investigate the impact of different parameters and mechanisms on the deposition of hydrates and the injectivity of CO2. Simulation results for a simplified model were verified with results from the literature. The key results of this work are as follows: (1) The JT effect strongly depends on the reservoir permeability and initial pressure and could lead to the formation of hydrates within the porous media even when the injected CO2 temperature was higher than the hydrate equilibrium temperature; (2) the heat gain from underburden and overburden rock formations could prevent hydrates formed at late time; (3) permeability reduction increased the formation of hydrates due to an increased JT cooling; and (4) water dry-out near the wellbore did not prevent hydrate formation. Finally, the role of capillary pressure was quite complex, as it reduced the formation of hydrates in certain cases and increased in other cases. Simulating this process with heat flow and hydrate reactions was also shown to present severe numerical issues. It was critical to select convergence criteria and linear system tolerances to avoid large material balance and numerical errors.

A parallel compositional reservoir simulator for large-scale CO2 geological storage modeling and assessment

Storing CO2 in deep aquifers and depleted gas reservoirs is an effective way to achieve carbon neutrality. However, the numerical simulation of CO2 storage in these formations is challenging due to the complexity of gases-brine systems. The number of gas species included in the gases-brine fluid models of existing simulators cannot meet the rapidly evolving CO2 sequestration scenarios. To address this intricate issue, we developed a three-dimensional fully implicit parallel CO2 geological storage simulator (PRSI-CGCS) on distributed-memory computers based on our in-house parallel platform. This simulator uses a compositional fluid model with a diverse range of gas species, including CO2, C1 ~ C3, N2, H2S, as well as newly added gases H2 and O2, which may be encountered in geological CO2 storages. Besides, we provide more suitable scaling factors for different gases in the stability analysis bypassing (SAB) method to accelerate the gases-brine phase equilibrium calculations. PRSI-CGCS does not incorporate energy conservation equations, and salt precipitation or dissolution is also not considered. Numerical experiments show that our simulator is scalable, robust and validated to simulate large-scale CO2 storage problems with hundreds of millions of grid blocks on a parallel supercomputer cluster. Besides, after our modification on scaling factors, the SAB method can reduce the number of stability analyses by 61.39 % to 88.71 %, thereby reducing simulation time. Furthermore, case studies indicate that injecting O2 and H2 along with CO2 reduces the stability or capacity of CO2 storage and increases the pressure required for injection. However, this impact is not significant when the impurity content is less than 10 %.

Differential Pressure Power Generation in UGS: Operational Optimization Model and Its Implications for Carbon Emission Reduction

Underground Gas Storage (UGS) is an important facility for natural gas peak adjustment and ensuring the balance between energy supply and demand. The daily gas injection and production capacity of large UGS can reach several hundred million or even billions of cubic meters, and the energy consumed by the injection and production equipment is not to be underestimated, which also contains a large amount of pressure energy that can be utilized for power generation. In this context, the optimization of low-carbon operation of UGS is of great practical significance in engineering. In this study, an innovative UGS system operation optimization method is proposed to integrate a natural gas differential pressure generator set in the UGS system. Considering the complex interconnections among multiple storage areas, multiple wells and wellsites, and the hydro-thermodynamic constraints during the operation of injection and production pipeline network, and with the objective of minimizing the carbon emission, the UGS integrated with Differential Pressure Power Generation System (UGSIDPPGS) is established. In order to solve this complex model, this paper designs an optimization solution framework based on variational assignment, which effectively avoids the problem of falling into inferior solutions during the solution process. The optimization model is applied to the case study of a large-scale depleted gas reservoir in China, and the optimal operation schemes under three scenarios are successfully obtained. The results show that the UGSIDPPGS optimization model, not only effectively utilizes the pressure energy, generates up to 56.908×106kW·h per month, and reduces the CO2 emission by 56,738 tons, but also achieves the low-carbon and economic operation of the UGS. In conclusion, the operation strategy proposed in this study is of great value for optimizing the operation of UGS, and provides practical guidance and suggestions for the low carbon and environmental protection of UGS and the utilization of new energy sources.

Diffusive nature of different gases in graphite: Implications for gas separation membrane technology

Graphite membranes have gained attention in membrane technology for gas separation due to their high stiffness, strength, and stability in corrosive and high-temperature environments. Graphite exists naturally in geologic media and can also be prepared by synthetic processes. In- situ hydrogen (H2) production in petroleum reservoirs or H2 storage in depleted gas reservoirs results in contamination with CH4 and CO2. To address the separation challenge at the surface, a sustainable downhole wellbore membrane must be available to separate H2, leaving behind CO2 and other gases to improve operational economics. Currently, there are no studies in the literature on the self-diffusivity of gases (CO2, H2, and CH4) in graphite as a function of pore size. To overcome time constraints in diffusivity experiments, this work utilized mathematical models and molecular simulations to delineate the self-diffusivity of gases in graphite of different pore sizes.To acknowledge subsurface operational conditions during in situ hydrogen production, we considered a temperature of 360 K and a wide pressure spectrum from 2 MPa to 20 MPa. In this study, we explored the diffusive nature of H2, CH4, and CO2 gases in different nanopore-sized graphite using analytical and molecular simulation approaches. We validated the results by presenting unrestricted case density calculations. First, effective diffusivity was calculated using the mean free pore path, followed by gas adsorption at high pressures (10–20 MPa) and a temperature of 350 K. The study utilized theoretical models and molecular dynamics (MD) simulations to determine the self-diffusivity of gases in graphite systems with various structures.

Numerical simulation of seasonal underground hydrogen storage: Role of the initial gas amount on the round-trip hydrogen recovery efficiency

Subterranean structures such as aquifers and depleted gas reservoirs (DGRs) offer a scalable, high-pressure, secure, cost-efficient, and ecologically friendly means of hydrogen (H2) storage. Underground H2 storage (UHS) has emerged as a potential solution to alleviate the imbalance between the fluctuating renewable energy generation and the demand for a constant energy supply. Quantifying the recovery efficiency is of paramount importance in the effort toward large-scale UHS. In this numerical simulation study, we employed a high-resolution grid for the discretization of a synthetic (but realistic) heterogeneous anticline intended as a H2 storage facility, and we assessed the H2 recovery efficiency, and the purity of produced gas associated with UHS in natural reservoirs involving different pre-existing gases and their quantities. All of these studies included an initial phase of cushion gas injection, followed by 4 cycles of H2 storage operations composed of injection-idle-withdrawal periods. The simulation results indicated that the H2 round-trip recovery efficiency RH increased (a) with an increasing number of storage cycles, routinely exceeding 90% and providing evidence of a self-enhancement or self-optimization H2 recovery mechanism and (b) with an increasing amount of pre-existing gas in the storage zone prior to the H2 injections — at the end of the 4-cycle test, the highest RH is associated with a DGR with a pre-existing gas consisting of residual CH4 and additional injected N2, and the lowest RH corresponds to an aquifer with no cushion gas. Conversely, the H2 mass fraction of the produced gas FHQ (a) increased with an increasing number of storage cycles, but (b) decreased rapidly with an increasing amount of pre-existing gas. The presence of a pre-existing gas inevitably leads to severe contamination of the produced H2, which never exceeds 40% in the produced gas, can be as low as 4% in early cycles, and cannot be used as a H2 fuel without gas separation. Aquifer storage without a cushion gas may exhibit the lowest H2 recovery (about 75% in the long run), but yields practically pure H2 that does not require further processing before use. A positive conclusion is that, under the conditions of this study, total H2 losses (including H2 escaping into the caprock, and inaccessible H2 dissolved in the aqueous phase of the formation or remaining in the gas storage zone) are limited and manageable, indicating the technical feasibility of geologic H2 storage.

Feasibility of Carbon Dioxide as Cushion Gas in Depleted Gas Reservoirs: An Experiment Study on CO2–CH4 Dispersion during Flow Alternation

Feasibility of Carbon Dioxide as Cushion Gas in Depleted Gas Reservoirs: An Experiment Study on CO2–CH4 Dispersion during Flow Alternation

Modeling of Geothermal Energy Recovery from a Depleted Gas Reservoir: A Case Study

Modeling of Geothermal Energy Recovery from a Depleted Gas Reservoir: A Case Study

Geochemical influences of hydrogen storage in depleted gas reservoirs with N2 cushion gas

Geochemical investigation of hydrogen (H2), brine, rock formations, and residual gases (nitrogen – N2, methane – CH4, and carbon dioxide – CO2) is crucial for understanding H2 storage processes in depleted gas reservoirs. This study examines the effects of injecting a gas mixture (60% H2 + 30% N2 + 5% CH4 + 5% CO2) into Bandera Grey sandstone with notable clay mineral content. The experiment lasted 50 days at 42 °C, 1350 psi, and 5 wt% NaCl brine, with detailed analytical characterization before and after aging. Results show minimal sample reactivity, causing slight alterations in petrophysical characteristics. Dissolution primarily affected dolomite and barite minerals, while illite and kaolinite caused pore blockage. Gas chromatography data indicate only 0.45% of injected H2 is lost (via dissolution in brine and reaction with CO2), CH4 increased by 6.22%, N2 remained stable, and CO2 decreased by 1%. These results provide valuable insights into the feasibility and safety of utilizing depleted gas reservoirs for H2 storage.

Modelling of Joule-Thomson cooling effect using a modified shift-DeepONet method for predicting hydrate onset during CO2 sequestration

Carbon Storage in underground depleted oil and gas reservoirs play a key role in reducing anthropogenic Carbon Dioxide (CO2) emissions around the world. Injection of CO2 at high pressure into a low pressure depleted gas formations containing methane (CH4) leads to Joule-Thompson (J-T) cooling, possibly resulting in injection blocking precipitation of CO2 or CH4 hydrates. Here, we present a deep neural operator-based approach to model the J-T effects during CO2 injection in depleted reservoirs to demonstrate the effectiveness of Deep Operator Networks (DeepONets) in modelling piece-wise functions with sharp changes in gradient for cases of varying permeabilities. We propose a modified version of the shift-DeepONet model using non-linear constructors in the neural network architecture to accurately model temperature and pressure profiles in space and time. The modified shift-DeepONet model achieves a higher accuracy in modelling temperature for permeability in the range of 1.01mD to 101mD with three to up to ten times improvement in reducing Relative L2 (RL2) norm and with a testing RL2 norm of 3.8 × 10−4 compared to 2.97 × 10−3 for the Vanilla DeepONet. Using the temperature and pressure profiles, estimates are made for hydrate onset in space and time. The proposed modified shift-DeepONet method achieves high accuracy in hydrate classification with precision values > 0.99, recall values > 0.86 and F1 scores >0.92 in classification of CO2 or CH4 hydrate onset during CO2 injection into depleted gas reservoirs.

Analytical Estimation of Hydrogen Storage Capacity in Depleted Gas Reservoirs: A Comprehensive Material Balance Approach

Analytical Estimation of Hydrogen Storage Capacity in Depleted Gas Reservoirs: A Comprehensive Material Balance Approach

SAFT2 equation of state for the CH4–CO2–H2O–NaCl quaternary system with applications to CO2 storage in depleted gas reservoirs

Understanding the phase equilibria and physical-chemical characteristics of the CH4–CO2–H2O–NaCl quaternary system is important for evaluating costs and risks for the storage of CO2 in depleted natural gas reservoirs as well as fluid inclusion studies. In this study, phase equilibria and thermodynamic properties of this system were investigated through the utilization of a statistical association fluid theory-based (SAFT) equation of state (EOS) at temperatures from 298 to 513 K (25–240 °C), pressures up to 600 bar (60 MPa) and concentration of NaCl up to 6 mol/kgH2O. The model parameters were obtained from the fitting of available experimental data of subsystems (i.e., CH4–H2O, CH4–CO2, and CH4–H2O–NaCl) that were judged to be reliable and incorporation of available parameters for the subsystems (i.e., pure component, CO2–H2O, and CO2–H2O–NaCl). Using the SAFT EOS developed in this study, we predicted the solubility of (CH4 + CO2) gas mixtures in pure H2O and compared it with the available experimental data and the predicted values from four popular numerical simulators. The results indicate that our model can provide reliable predictions for the CH4–CO2–H2O ternary system. Subsequently, we further predicted the phase equilibria and density of the CH4–CO2–H2O–NaCl system with NaCl varying from 0 to 6 mol/kgH2O. We also employed the SAFT EOS to predict the solubility of CO2 and CH4 in the water-alternating-gas process for CO2-enhanced oil recovery, demonstrating good agreement with the simulation results obtained through the Peng-Robinson EOS for predicting the CO2 and CH4 solubility. These predicted thermodynamic properties and phase behaviors in the CH4–CO2–H2O–NaCl system provide quantitative insights into the implications of CO2 storage in depleted oil and gas reservoirs.

Density-Driven CO2 Dissolution in Depleted Gas Reservoirs with Bottom Aquifers

Depleted gas reservoirs with bottom water show significant potential for long-term CO2 storage. The residual gas influences mass-transfer dynamics, further affecting CO2 dissolution and convection in porous media. In this study, we conducted a series of numerical simulations to explore how residual-gas mixtures impact CO2 dissolution trapping. Moreover, we analyzed the CO2 dissolution rate at various stages and delineated the initiation and decline of convection in relation to gas composition, thereby quantifying the influence of residual-gas mixtures. The findings elucidate that the temporal evolution of the Sherwood number observed in the synthetic model incorporating CTZ closely parallels that of the single-phase model, but the order of magnitude is markedly higher. The introduction of CTZ serves to augment gravity-induced convection and expedites the dissolution of CO2, whereas the presence of residual-gas mixtures exerts a deleterious impact on mass transfer. The escalation of residual gas content concomitantly diminishes the partial pressure and solubility of CO2. Consequently, there is an alleviation of the concentration and density differentials between saturated water and fresh water, resulting in the attenuation of the driving force governing CO2 diffusion and convection. This leads to a substantial reduction in the rate of CO2 dissolution, primarily governed by gravity-induced fingering, thereby manifesting as a delay in the onset and decay time of convection, accompanied by a pronounced decrement in the maximum Sherwood number. In the field-scale simulation, the injected CO2 improves the reservoir pressure, further pushing more gas to the producers. However, due to the presence of CH4 in the post-injection process, the capacity for CO2 dissolution is reduced.

Study Reviews Reservoir Engineering Aspects of Geologic Hydrogen Storage

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23943, “Reservoir Engineering Aspects of Geologic Hydrogen Storage,” by Johannes F. Bauer, Mohd M. Amro, SPE, and Taofik Nassan, SPE, Technical University Bergakademie Freiberg, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference. Reproduced by permission. _ Safe and effective large-scale storage of hydrogen (H2) is one of the greatest challenges of the global energy transition and can be realized only through storage in geological formations. The aim of the study detailed in the complete paper is to address and discuss the reservoir engineering aspects of geological H2 storage (GHS). The study is based on two sources: first, a comprehensive literature review and, second, experimental and numerical work performed by the authors’ institute. H2 Pressure/Volume/Temperature (PVT)/Phase Behavior The definition of the PVT/phase behavior of reservoir fluids is crucial in GHS because thermodynamic properties significantly affect safety and effectiveness. The properties of H2 are widely known and modeled, but its reaction with other gases, such as in-situ gases like natural gas in depleted gas reservoirs (DGR), currently is under investigation. Although the ideal gas law can account for H2 behavior at low pressure, accurate depiction of its thermodynamic properties requires more-sophisticated equations of state (EOS), especially when it is mixed with other gases such as methane. Most commercial reservoir simulators use EOS packages that can model the complex properties of these mixtures, mostly within required reliability. In most instances, calibration is still required if experimental PVT data are available. Reservoir Engineering of GHS. GHS projects must meet three crucial technical benchmarks for underground storage: capacity (storage volume), injectivity/productivity (rate of injection/withdrawal in relation to wellhead pressure), and containment integrity (prevention of leakage). Economic sustainability requires that projects must adhere to these standards, which may vary according to the selected geological formations. Although various subsurface structures can store H2, only specific formations such as salt caverns (SCs), saline aquifers (SAs), and depleted gas/oil reservoirs (DGRs and DORs), fulfill the requirements. While the complete paper discusses all three of these formation types in detail, this synopsis will concentrate on SCs. GHS in SCs. SC storage typically involves up to three wells for one cavern with a volume of up to 500,000 std m3, providing a delivery rate of 8,500–17,000 std m3/day. Working gas accounts for up to 65% of the total gas, while water should be kept to a minimum. SCs usually allow between six and 12 operating cycles per year, each lasting approximately 10 days for withdrawal periods. SCs offer high H2 purity and sealed storage. The storage capacity of caverns in Germany is determined by their volume and pressure limitations while avoiding any negative geomechanical effects. These caverns can range in depth from 500 to 2000 m, with heights of up to 400 m. Approximately 30 to 50% of the total stored volume is used as cushion gas to maintain production pressure. Estimating the capacity of these caverns relies on their geometry and thermodynamics, resulting in relatively lower uncertainties when compared with storages in porous media.

Underground hydrogen storage in depleted gas reservoirs with hydraulic fractures: Numerical modeling and simulation

Underground hydrogen storage (UHS) is one of the key technological solutions for balancing energy systems and promoting sustainable energy development. In this study, we propose a novel UHS method, which involves injecting hydrogen generated from electrolyzing formation water into depleted gas reservoirs through hydraulic fractures during off-peak electricity periods, and then efficiently producing hydrogen for power generation during peak electricity periods. We establish a numerical simulation model for UHS in a depleted fractured gas reservoir, covering the entire process from injecting hydrogen gas into the reservoir through wells to shutting them down and subsequently producing hydrogen when required. We then investigate the impact of hydrogen injection rate, injection duration, and shut-in duration on the UHS process and storage efficiency. Our findings reveal that hydrogen production efficiency can exceed 85 % by optimizing hydrogen injection and production strategies. Our study provides an exemplary numerical simulation scheme to evaluate the feasibility of UHS in depleted gas reservoirs with hydraulic fractures.

Hydrogen unclogging of caprock

Kerogen has a lower affinity to hydrogen than methane; thus, it allows hydrogen to flow more easily, but it is unclear how the permeabilities of hydrogen and methane differ. This study determines the single-phase permeability of hydrogen and compares it with methane permeability in organic-rich caprock. It takes into account adsorption to the pore wall and slippage at the boundary. It implements the two processes at 370 K for pressures from 500 to 4000 psi to obtain the hydraulic conductance of a sub-100-nm conduit. It then relates them to the macroscopic behavior via network modeling. Lower pressures represent depleted gas reservoirs in the subsurface. Decreasing pore pressure enhances hydrogen transport by reducing its adsorption to the pore wall and transitioning its behavior from continuum to discrete particles, leading to first- or second-order slippage. The results show that hydrogen conductance, qin−situ (H2), is always larger than the reference conductance without adsorption and slippage (q0). Hydrogen permeability, kin−situ (H2), is also larger than methane permeability, kin−situ (CH4), while the permeability values differ by 70% − 130%, depending on the pore pressure. This study also determines the conduit size corresponding to the ratio of hydrogen permeability to methane permeability at in-situ conditions by comparing it with the ratio of hydraulic conductance of hydrogen to methane. The results have applications in underground hydrogen storage by indicating how hydrogen flow changes with pressure in ultra-tight formations.

Mixing dynamics and recovery factor during hydrogen storage in depleted gas reservoirs

Large-scale hydrogen storage is strategically important for society and depleted gas reservoirs have been proposed as a potential solution. However, the mixing with remaining hydrocarbon gas during injection/production cycles and the impact of different reservoir parameters on the hydrogen recovery factor (RFH2) have not been fully understood. We investigate mixing dynamics and analyze the effects of initial hydrocarbon recovery factor, reservoir permeability, well perforation length, intelligent completion, and fractures on RFH2. Fine-grid gas reservoir models with compositional simulation were used to simulate cyclic hydrogen storage. Mixing of injected hydrogen with remaining hydrocarbon gas occurred in three distinct phases in each cycle: 1) displacement of remaining hydrocarbon gas through pressure-driven flow during hydrogen injection, 2) density-driven flow of gases during the idle time after hydrogen injection, and 3) pressure-driven flow of gases towards the production intervals during the hydrogen production phase. Higher RFH2 s were obtained when the storage process was initiated at higher hydrocarbon gas recovery factors. Storing hydrogen in reservoirs with lower permeability also led to higher RFH2 s, provided the well pressure limits were not an issue. In conditions of a 5× to 15× increase in permeability, the injected hydrogen moved upward and spread laterally, positioning it farther from the wellbore. This made hydrogen production more difficult and placed the mixing zone and hydrocarbon gas closer to perforations. Shorter perforation lengths at the top of the formation resulted in the best RFH2 s. Additionally, intelligent completions (that closed perforations producing gas with low hydrogen content) improved RFH2 by providing the possibility of purer hydrogen production. The presence of natural fractures significantly reduced hydrogen recovery, especially in the first few cycles. However, the influence decreased over time as highly conductive flow paths provided by fractures can contribute to the production of the accumulated unrecovered hydrogen from previous cycles.