Underground hydrogen storage (UHS) in saline aquifers presents a promising solution for large-scale energy storage for the Midwestern United States because of the limit availability of depleted hydrocarbon reservoirs. This study focuses on the Manlove Field at the Mt. Simon sandstone formation, Illinois, a geological site with proven sealing capacity and known reservoir properties because of previous natural gas storage projects. We developed a three-dimensional numerical model, implemented using the TOUGH + RealGasBrine simulator, to investigate several key factors influencing UHS performance, including production strategies, well completion interval, and the cushion gas injection. The results show that the method of constant production rates can significantly reduce water production compared to constant bottom hole pressure, for the same amount of recovered H2. Because of gravity separation effect, perforating wells in upper zones improves H2 storage by reducing water production and achieving higher recovery efficiency. Cushion gas (nitrogen in this study) enhances recovery efficiency, mitigates H2 leakage and dissolution, and delays water breakthrough, thereby improving the overall economic viability of UHS. However, gas mixing in both subsurface and produced stream necessitates the potential need for gas separation facilities, which remains an important consideration if large amounts of a cushion gas are injected. Lastly, the results show that the non-recoverable H2, trapped by relative permeability hysteresis, may exceed 50 % of the injected total. This study provides insights into the design and optimization of UHS operations in aquifers using three-dimensional large-scale numerical simulations, emphasizing the key role of well completion interval and cushion gas in improving H2 storage efficiency.

A new parallel code for simulating particle transport in porous media is integrated with the TOUGH + HYDRATE simulator to investigate sand production associated with gas production from unconsolidated gas hydrate-bearing sediments (HBS). The parallel coupled simulator is named THMPT and uses the integral finite difference method to describe the Darcian and non-Darcian flow of fluids and heat transport, the finite element method to describe the associated geomechanical changes, and the discrete element method to track the trajectory of individual sand particles within the HBS. The THMPT simulator is written in Fortran, incorporates multiple optimized algorithms, and can comprehensively address the coupled flow, thermal, chemical, geomechanical, and particle transport processes that characterize the system behaviors during gas production from HBS. The simulator can capture all processes involved in sand particle transport in porous media, including sand detachment, collision, clogging (i.e., bridging), and migration. A benchmark case study of sand production in the course of depressurization-induced gas production from a representative HBS reveals various distinct microscopic particle migration mechanisms and the adverse impact of sand particle detachment, transport, and clogging. The numerical investigation also examines the effect of bottomhole pressure on mitigating sand production. The simulation results indicate that sand clogging near the wellbore significantly reduces permeability, decreasing gas production by at least 50%. Lastly, the efficiency of gravel packing in mitigating sand production is numerically evaluated, revealing that the structure of the porous media appears to profoundly influence the macroscopic motion behavior of sand particles and sand clogging characteristics.

Abstract Well interference test methods in Multi-Fracture Horizontal Wells (MFHWs) focus on the connectivity and conductivity between the "entire" wells. Practically it is challenging to identify the contribution of each fracture from each cluster in a MFHW. However, understanding fracture connections at the cluster level can provide detailed guidance for optimizing completion designs and well spacing. This work proposes a new method to interpret far-field strain change and pressure data to quantify fracture connectivity and properties at the cluster level. The case study uses field data acquired from the DOE Hydraulic Fracturing Test Site-1 (Phase III) performed in the Eagle Ford shale. A dedicated well with permanent fiber and external pressure gauges installed was used to monitor strain and pressure changes (respectively) during put-on production (so-called "POP") of adjacent wells. A 1D linear flow model was proposed to simulate transient flow within fractures, allowing for the calculation of pressure responses at the monitoring well. By assuming a linear relationship between pressure and strain changes, we were able to match the observed pressure and strain changes to determine fracture connectivity and conductivity between the production and monitoring wells. Using field data from permanent fiber and external pressure gauges, we validated the analytical solution for modeling changes in strain during initial production performance. We note that the pressure and strain changes indicate the same fracture properties. During hydraulic fracturing treatment, 59 fracture hits were identified in the monitoring well, which is 250 ft horizontally from the producing well. During initial production, DSS strain data revealed only 20 fracture connections among 230 clusters between the producing well and the monitoring well. The calculations show fracture conductivities ranging from 0.1 to 15 mD·ft, with 10 connections exceeding 1 mD·ft. This analysis provides an important observation: out of the 230 perforation clusters and considering a well spacing of 250 ft, approximately 26% of the fractures connected from the treatment well to the monitoring well during fracturing, while only about 9% of the fractures remained connected during initial production. This study introduces an innovative interpretation method that can be used to quantify fracture connectivity and conductivity at the cluster level by leveraging advanced monitoring technology in unconventional reservoirs. This approach provides practicing engineers with unique data to optimize the well completion designs and well spacing, thereby enhancing the development and productivity of unconventional reservoirs.

An important challenge in ensuring the long-term effectiveness of geological nuclear waste disposal is predicting the transportation of decay heat and gases released from nuclear waste canisters. In this study, thermo-hydromechanical (THM) coupled simulations were conducted using the TOUGH + FLAC3D simulator to predict the THM behaviors of a generic nuclear waste repository over 100,000 years following closure. The designed engineered barrier system (EBS) consists of the waste canister, backfill, and concrete liner. The objective of this study is to evaluate the long-term performance of the repository in the presence of continued hydrogen (H2) and heat release around the canister. The simulation results show that thermal pressurization and gas accumulation significantly raise the pore pressure within the EBS and surrounding host rock, while the peak pore pressure is not likely to exceed the lithostatic stress so that there is no risk of widespread hydro-fracturing in the host rock. However, tension failure and fracturing can occur at the tunnel scale because of internal gas buildup. Meanwhile, the generated H2 continuously migrates outward and tends to accumulate in the concrete liner and excavation disturbed zone surrounding the tunnel because of lower capillary pressure. Nevertheless, the fluids that may contain radionuclides will not leach into the confining units over a 100,000-year time frame. Our analysis indicates that for the assumed disposal system in Opalinus Clay, the generated heat and gas can gradually be transported through the host rock without significantly disturbing the isolation characteristics of the repository.

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.

The objectives of this study are to investigate (a) the technical feasibility of gas production from a gas hydrate accumulation at Site NGHP-02-09 in the Krishna-Godavari Basin, India Ocean using a hybrid production method involving a combination of depressurization and thermal stimulation, as well as (b) the associated geomechanical system response when considering both a simplified and a full geomechanical model. This is an extension of the earlier numerical study of Moridis et al. (2019a) of the site using cylindrical (single-well) 2D systems, which indicated (a) the main source of the produced gas to be CH4 dissolved in the water rather than CH4 from hydrate dissociation because of the presence of a high-permeability water-bearing zone that short-circuits the depressurization process and (b) the possibility of adverse geomechanical issues caused by significant displacements that could not be adequately investigated and resolved by the one-way coupling scheme invoked in that study. The proposed hybrid production plan involves two vertical wells in a 3D Cartesian domain: an injection well of warm ocean (saline) water and a production well at an appropriate distance, with the expectation that the hydrate dissociation caused by the depressurization at the production well can be augmented by the thermal effect of the injected warm water (as well as by its salinity), thus mitigating the effects of the high-permeability water zone. The results of this study that uses high-resolution 3D grids indicate that (a) the hybrid production scheme does not appear to offer any advantage over the simple single-well depressurization method of the earlier study, (b) the majority of the produced gas originates from CH4 exsolution from the water rather from hydrate dissociation, and (c) consideration of full geomechanics leads to generally slightly higher dissociation and fluid production because of the evolution of lower porosities and permeabilities, but also to the disappearance of the gas phase after 62 days of production, after which time CH4 from hydrate dissociation is fully dissolved in the water before production. Thus, the hybrid scheme investigated here appears ineffectual in enhancing hydrate dissociation and gas production, and the hydrate deposits at the Site NGHP-02-09 do not appear to be a promising production target under the conditions in this study, in agreement with the earlier conclusion of Moridis et al. (2019a).

Abstract A simple power-law model is presented for performance of gas reservoirs experiencing water influx using only cumulative production, reservoir pressure, and the gas deviation factor (i.e., the z-factor). The application of the model provides estimation of gas-in-place. The gas material balance relation including ONLY water influx is given in dimensionless form as: pzD=(1−GpD)(1−WeD) where: pzD=p/zpi/zi WeD=weBWGBgi GpD=GpG The following empirical model is proposed for dimensionless water influx function (WeD): WeD=aGpb+1 Substituting this model into the gas material balance yields: pzD=(1−GpD)(1−aGpb+1) The proposed power-law water influx model was exhaustively validated using the Carter-Tracy and Van Everdingen-Hurst methods to simulate water influx and pressure-cumulative gas production behavior for an unsteady-state water-influx system. The results of these simulation cases were fitted using the proposed (empirical) power-law water influx model and for every case that was tested, the proposed model gave an essentially perfect correlation of the simulated reservoir performance behavior.

Natural gas hydrates (NGHs) are a potentially important future energy resource because of the vast amounts of methane they trap. Numerical simulation is a critical tool for the design, planning, and evaluation of NGH exploitation. The effects of geomechanics and discretization on simulations of production from NGH deposits have barely been addressed in earlier studies. We expand on an early study of gas production employing depressurization-induced dissociation from a marine hydrate accumulation at the UBGH2-6 site in the Ulleung Basin, and we use two grids - a coarser one and a finer one - to investigate the effects (a) of consideration of geomechanics on gas production from NGHs and (b) of discretization on both production and the associated geomechanical response of the hydrate accumulation. In our study, we use (a) the parallel flow-thermal-chemical process simulator pTOUGH + HYDRATE (pT + H) V1.5 that involves limited geomechanical capabilities and (b) the pT + H V1.5 code coupled with the parallel RGMS code that involves a full geomechanical model. Consideration of the full geomechanical behavior leads to the estimation of substantially lower fluid production rates for both discretizations, confinement of the depressurization zone to a smaller region, shallower penetration of dissociation fingers into the main body of the hydrate and an overall difference in the locations of active dissociation. The finer grids capture critical process features that completely elude the coarser grid, yielding predictions of larger fluid production rates and of much larger displacements. The study indicates that, when NGH systems include compressible media (such as clays and silts), parallel simulations are a necessity and they need to involve the finer grid and a full geomechanical model for reliable results. This study offers a first-level evaluation of the importance of geomechanics and grid refinement, but more systematic studies are necessary before authoritative quantitative conclusions can be drawn.

The unstable supply of renewable energy due to seasonal dependency contradicts the periodic energy demand. As hydrogen presents high energy density and flow mobility, and low solubility and residual saturation, underground hydrogen storage (UHS) is a promising solution of scalable energy storage to rebalance energy demand and supply. Depleted gas reservoirs (DGR) are a suitable option for UHS due to their demonstrated integrity. In this study, we developed a numerical simulation model based on Tough + RealGasBrine (T + RGB) simulator to evaluate the feasibility of UHS in DGR. We calibrated different Equation-of-State (EOS) models for modeling the phase behavior of hydrogen-included mixtures with experimental data, and this further helps to examine the impact of various cushion gas pre-injection strategies on pressure maintenance and potential hydrogen leakage through cap-rock. After comparison among three EOS models, we adopted the Soave-Redlich-Kwong (SRK) EOS in our simulations as its high accuracy and computational efficiency. Afterward, we simulated one hydrogen injection-idle -withdrawal operation in a high-resolution mesh based on a synthetic heterogeneous anticline DGR. We observed that hydrogen displaces pre-existing methane and resides at the top of the storage zone due to gravity segregation. The average pressure and gas saturation of the whole simulation domain increase with the hydrogen injection. With regard to the hydrogen leakage, when the cap-rock permeability ranges from 10-5 to 10-3 mD, 0.05% of the injected hydrogen at maximum leaks into the cap-rock while about 1% of injected hydrogen is dissolved into the aqueous phase. Those results demonstrate that DGR is a viable option for UHS. However, only about 73% of injected hydrogen can be recovered if the bottom-hole pressure of the production well is 2 MPa below the reservoir pressure. The cushion gas becomes necessary for the UHS project to increase hydrogen recovery. Injecting cushion gas of nitrogen and carbon dioxide increases hydrogen recovery from the initial 73%-91% and 81%, respectively. The simulation results demonstrate that nitrogen exhibits better performance, in terms of higher hydrogen recovery factor and purity of producing gas, as the cushion gas. In this work, we quantitatively evaluated the hydrogen leakage problem, including leakage into cap-rock, dissolution in water, and mixing with other gas components, which is the first-of-its-kind analysis in literature to the author's best knowledge. The simulation results support the feasibility of UHS in the DGR.(c) 2023 Hydrogen Energy Publications LLC. Published by Elsevier Ltd. All rights reserved.

Summary Unstable supply of renewable energy arises with the inevitable seasonal dependency, which contradicts with periodic energy demand. As hydrogen shows high energy density and mobility, yet low solubility and residual saturation, underground hydrogen storage (UHS) becomes a promising solution of scalable energy storage to rebalance demand and supply. Depleted gas reservoirs (DGR) are one of the most appropriate options for UHS because of the integrity of their caprock and storage system. In this study, we developed a numerical model based on TOUGH+RGB simulator (code) to simulate the flow and thermal transport during UHS in reservoirs such as DGR. Given the different transport and thermodynamic properties of hydrogen, different Equation-of-State (EOS) for modeling the phase behavior of hydrogen-included mixtures are calibrated with literature (lab) data, and further are coupled with the simulator. This benefits our numerical experiments to exam various cushion gas pre-injection strategies for pressure maintenance, boundary conditions, and potential hydrogen leakage into caprock. Hence, we can comprehensively assess the seasonal gas recovery factor of hydrogen stored in DGR. The calculated density of hydrogen-methane mixture based on GERG-2008 EOS and Soave-Redlich-Kwong (SRK) EOS is in perfect agreement with experimental data, while that from Peng-Robinson EOS is not quite consistent. Due to the accuracy and efficiency, SRK EOS is employed in our simulator. Hydrogen injection-idle-withdrawal operation is simulated in a synthetic heterogeneous anticline DGR. Due to gravity segregation, we observe that hydrogen displaces pre-existing methane and resides at the top of the storage zone. When the caprock permeability ranges from 10(-5) to 10(-3) mD, only 0.05% of the injected hydrogen at maximum leaks into the caprock. Besides, an open boundary condition connecting with the storage zone helps the pressure maintenance in the storage and lowers the leakage, since with a close boundary condition the leakage rises to 0.35%. Further, about 1% of injected hydrogen is dissolved into the aqueous phase. Those results demonstrate that UHS in DGR has become a feasible choice. Nevertheless, only about 75% amount of hydrogen can be withdrawn if the bottom-hole pressure of producing well is 2MPa below the reservoir pressure. Therefore, cushion gas is necessary for the UHS project to increase hydrogen recovery. This work provides an in-depth investigation of various physics important to UHS, including EOS, hydrogen transport, capillary pressure, mixing, and dissolution. We quantitatively evaluated the hydrogen loss problem, including leakage to caprock, dissolved in water, and mixing with other gas molecules, which is the first-of-its-kind analysis in literature to the authors’ best knowledge. The modeling study is useful for the feasibility analysis of hydrogen storage in the depleted gas reservoir.

Wavelets are localized small waves that exhibit the characteristic oscillatory behavior of waves with an amplitude that declines rapidly to zero. Their properties include orthogonality or bi-orthogonality, a natural multiresolution and, often, compact support. These properties can be used to repeatedly rescale a signal or a function, decomposing it to a desirable level, and obtaining and preserving trend and detail data at all scales that allow re-composition of the original signal. The overall goal of this work is to create a set of wavelet-based (WB) numerical methods using different wavelet bases for application to the solution of the PDEs of interest to petroleum engineering, namely the solution of the PDEs of fluid flow through porous and fractured media. A particular emphasis of the study is in processes associated with ultra-low permeability media such as shale oil and shale gas reservoirs. To address the problem, we developed WTFS (wavelet transform flow simulator), a new flow simulator written in MATLAB that couples wavelet transform with a standard finite-difference scheme. In the current state of development, the WB numerical solution is verified against analytical solutions of 1D problems for liquid flow through porous media and is validated through comparisons to numerical solutions for problems of 2D and 3D flow through porous media obtained from a conventional numerical simulator.

The Reservoir GeoMechanics Simulator (RGMS or RGM simulator), a geomechanics simulator based on the finite element method (FEM) and parallelized using the Message Passing Interface (MPI), is developed in this work to model the stresses and deformations in subsurface systems. RGMS can be used standalone or coupled with flow and transport models. pTOUGH+ HYDRATE (pT+H) V1.5, a parallel MPI-based version of the serial TOUGH+HYDRATE (T+H) V1.5 code that describes mass and heat flow in hydrate-bearing porous media, is also developed. Using the fixed--stress split iterative scheme, RGMS is coupled with the pT+H V1.5 codes to investigate the geomechanical responses associated with gas production from hydrate accumulations. In the first paper of this series, we discuss the governing equations underlying physics and their mathematical representation in the modeling of the geomechanics, methane hydrate, and coupled problems as well as the numerical methods and the parallelization processes (involving a domain decomposition method based on the MPI approach) used for the parallel simulators. Two 2D problems (in Cartesian and radial--cylindrical coordinates) and a 3D Cartesian coordinate problem are created to validate the FEM and the parallelization method in RGMS. The displacements and the maximum principal effective stresses obtained from the RGMS solution of these three problems are compared to those from the commercial software Ansys Mechanical and are shown to practically coincide. The parallelization of pT+H V1.5 is validated by comparing its results to those from the serial T+H V1.5 code in a study that involved (a) fluid production from a large--scale 2D cylindrical system describing a real--life oceanic hydrate deposit and (b) a simplified geomechanical model based on hydrate--dependent pore compressibility. The coupling method is validated by comparing the numerical results to the analytical solutions of the Terzaghi and the McNamee--Gibson problems. The parallelization validation of the coupled simulator is achieved by comparing the results obtained for different numbers of processes in the solution of the problems used for the pT+H V1.5 parallelization validation with the full geomechanical model. The results clearly demonstrate the validity and reliability of the parallel codes (a) RGMS, (b) pT+H V1.5, and the (c) coupled pT+H V1.5 and RGM simulators, which can be used to solve the large--scale physics of complex problems.