Geomechanical Effects Research Articles

A New Explicit Sequentially Coupled Technique for Chemo-Thermo-Poromechanical Modelling and Simulation in Shale Formations

A new explicit sequentially coupled technique for chemo-thermo-poromechanical problems in shale formations is developed. Simultaneously solving the flow and geomechanics equations in a single step is computationally expensive with consequent limitations on the computations involving well or reservoir-scale geometries. The newly developed solution sequence involves solving the temperature field within the porous system. This is followed by the computation of the chemical activity constrained by the previously computed temperature field. The pore pressure is then computed by coupling the pore thermal and chemical effects but without consideration of the volumetric strains. The geomechanical effect of the volumetric strain, stress tensors, and associated displacement vectors on the pore fluid is subsequently computed explicitly in a single-step post-processing operation. By increasing the borehole pressure to 20 MPa, it is observed that the rock displacement and velocities concurrently increase by 50%. However, increasing the wellbore temperature and chemical activities shows only a slight effect on the rock and pore fluid. In the chemo-thermo-poroelasticity steady-state simulation, the maximum displacements recorded in the Hmin and Hmax are 0.00633 m and 0.0035 m, respectively, for 2D and 0.21 for the 3D simulation. In the transient simulation, the displacement values are observed to increase gradually over time with a corresponding decrease in the maximum pore-fluid velocity. A comparison of this work and the partial two-way coupling scheme in a commercial simulator for the 2D test cases was carried out. The maximum differences between the computed temperatures, displacement values, and fluid velocities are 0.33%, 0.7%, and 0%, respectively. The analysed results, therefore, indicate that this technique is comparatively accurate and more computationally efficient than running a full or partial two-way coupling scheme.

Three-Way Coupled Modeling Evaluates CO2 Sequestration in Depleted Reservoir

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206156, “Importance of Three-Way Coupled Modeling for Carbon-Dioxide Sequestration in a Depleted Reservoir,” by Prasanna Chidambaram, SPE, Pankaj K. Tiwari, SPE, and Parimal A. Patil, SPE, Petronas, et al. The paper has not been peer reviewed. _ Three major depleted gas reservoirs in the Central Luconia field offshore Sarawak, Malaysia, are being evaluated for future carbon-dioxide (CO2) storage. A three-way coupled modeling approach that integrates dynamic, geochemistry, and geomechanics models is used to obtain the cumulative effect of all three changes. This integrated model provides a more-accurate estimate of CO2 storage capacity, caprock-integrity evaluation, CO2-plume migration path, and volume of CO2 stored through different mechanisms. Background The CO2 storage sites being evaluated are depleted gas reservoirs that have been in production for a few decades. At the end of their producing life, they have the potential to be converted into CO2 storage sites. The Central Luconia sedimentary basin is in a seismic-free zone with limited faults and consists of shale interbedded with high-sand-content sediment, making it ideal for CO2 storage. These reservoirs provide the required geological characteristics and volume needed to ensure long-term CO2 storage in a safe and economical way. The depleted gas reservoirs have an in-place volume of approximately 1.5–3 Tscf. Their thickness ranges from 100 to 150 m, with a porosity of 15–32% and permeability of 10–1600 md. These fields are believed to be supported by a regional aquifer several thousand feet thick. Large seafloor subsidence has been observed in these reservoirs. Storage-Capacity Estimation Storage capacity of a depleted hydrocarbon reservoir is affected by several factors including voidage created; aquifer influx and efflux during the production and CO2-injection phases, respectively; maximum injection pressure; rock compressibility; and geochemical effects. Depending on which of these factors are prominent in the storage reservoir, CO2-storage capacity may be estimated using a simple material-balance model or may require a more-complex approach to capture these effects. Use of the Three-Way Coupled Model Injected CO2 is anticipated to react with reservoir rock, leading to either dissolution of reservoir rock or precipitation of solids that are products of the geochemical reactions, causing a net change in porosity and permeability. With regard to geomechanical effects, uplift is anticipated to occur during CO2 injection. The degree to which subsidence is reversed depends on whether compaction of the reservoir is fully elastic or if plastic deformation has occurred. During production, reduction in porosity and permeability has occurred because of subsidence. Conventional or stand-alone reservoir simulation does not capture geochemical and geomechanical effects. Hence, it is critical to use an integrated model that captures the effects of dynamic, geochemical, and geomechanical changes caused by CO2 injection in order to evaluate suitability of the reservoir for long-term CO2 storage. A three-way coupled modeling approach that integrates dynamic, geochemistry, and geomechanics models provides a more-accurate estimate of CO2 storage capacity, along with estimation of subsidence. In three-way coupled modeling, the dynamic model is at the center, which passes input parameters to the geochemical and geomechanical models. Once it receives updated porosity and permeability values back from the geochemical and geomechanical models, the dynamic model incorporates these changes before proceeding to the next simulation timestep.

Analysis of geomechanical thermal effects caused by geothermal flows

W pracy przedstawiono analizę wpływu efektów temperaturowych na zmianę stanu naprężeń w trakcie pracy złoża geotermalnego. Cel pracy został zrealizowany przy wykorzystaniu metody efektywnego sprzężenia symulacji złożowo-termalnych i geomechanicznych jako sprzężenia hydro-termo-mechanicznego (H-T-M). W ramach tego zadania zbudowano dwa syntetyczne złożowe modele symulacyjne, model przepływowo-termalny oraz model geomechaniczny. Do przepływowego modelu symulacyjnego zaimplementowano dublet otworów: jeden otwór zatłaczający zimną wodę i drugi – wydobywający gorącą wodę. Obliczenia różnych wariantów prognoz przepływu płynów złożowych i energii cieplnej dla złoża geotermalnego realizowano przy użyciu symulatorów Eclipse i Visage pod kontrolą oprogramowania Petrel firmy Schlumberger. W wyniku sprzężonych symulacji uzyskano rozkłady zmian parametrów złożowych (ciśnienia i temperatury) oraz zmian parametrów geomechanicznych (naprężeń i odkształceń) w funkcji czasu. Otrzymane wyniki obliczeń posłużyły do analizy stanu geomechanicznego złoża geotermalnego pod wpływem zmian ciśnienia i temperatury. Dzięki temu możliwe było określenie udziałów efektów temperaturowych i efektów ciśnieniowych w zmianie tensora naprężeń. Wykonane analizy pozwoliły również na wykazanie, który z tych czynników odgrywał dominującą rolę w trakcie pozyskiwania energii geotermalnej. Analiza stanu geomechanicznego została także uzupełniona o analizę stabilności skały złożowej z użyciem diagramów koła Mohra, ze szczególnym uwzględnieniem efektów temperaturowych. Sprzężone symulacje wariantowe pozwoliły na określenie optymalnych parametrów operacyjnych pracy złoża geotermalnego. Zbadano zmienność w czasie temperatury wydobywanej wody dla każdego wariantu symulacyjnego. Skorelowano ze sobą następujące parametry operacyjne: wydajność zatłaczania/odbioru wody i temperaturę zatłaczanej wody oraz wynikowe charakterystyki procesu pozyskiwania energii geotermalnej: czas redukcji temperatury wydobywanej wody do zadanej wartości i całkowitą ilość pozyskanej energii cieplnej. Znalezione zależności pomiędzy wspomnianymi parametrami pozwoliły na optymalizację parametrów operacyjnych pod kątem pozyskania maksymalnej ilości energii cieplnej.

Integrated modeling of fracturing-flowback-production dynamics and calibration on field data: Optimum well startup scenarios

We aim at the development of a general modelling workflow for design and optimization of the well flowback and startup operation on hydraulically fractured wells. Fracture flowback model developed earlier by the authors is extended to take into account several new fluid mechanics factors accompanying flowback, namely, viscoplastic rheology of unbroken cross-linked gel and coupled “fracture-reservoir” numerical submodel for influx from rock formation. We also developed models and implemented new geomechanical factors, namely, (i) fracture closure in gaps between proppant pillars and in proppant-free cavity in the vicinity of the well taking into account formation creep; (ii) propagation of plastic deformations due to tensile rock failure from the fracture face into the fluid-saturated reservoir.We carried out parametric calculations to study the dynamics of fracture conductivity during flowback and its effect on well production for the set of parameters typical of oil wells in Achimov formation of Western Siberia, Russia. The first set of calculations is carried out using the flowback model in the reservoir linear flow regime. It is obtained that the typical length of hydraulic fracture zone, in which tensile rock failure at the fracture walls occurs, is insignificant. In the range of rock permeability in between 0.01 mD and 1 D, we studied the effect of non-dimensional governing parameters as well as bottomhole pressure drop dynamics on oil production. We obtained a map of pressure drop regimes (fast, moderate or slow) leading to maximum cumulative oil production. The second set of parametric calculations is carried out using integrated well production modelling workflow, in which the flowback model acts as a missing link in between hydraulic fracturing and reservoir commercial simulators. We evaluated quantitatively effects of initial fracture aperture, proppant diameter, yield stress of fracturing fluid, pressure drop rate and proppant material type (ceramic and sand) on long-term well production beyond formation linear regime. The third set of parametric calculations is carried out using the flowback model history-matched to field data related to production of four multistage hydraulically fractured oil wells in Achimov formation of Western Siberia, Russia. On the basis of the matched model we evaluated geomechanics effects on fracture conductivity degradation. We also performed sensitivity analysis in the framework of the history-matched model to study the impact of geomechanics and fluid rheology parameters on flowback efficiency.

Influence of geomechanical effects during the reservoirs development on the risks of drilling, development and field production enhanced

Influence of geomechanical effects during the reservoirs development on the risks of drilling, development and field production enhanced

Consideration of geomechanical effects in reservoir simulation for hydrocarbon field development

This paper presents a review of mathematical models and functionality for consideration of geomechanical effects during hydrocarbon field development provided by modern flow simulation software (reservoir simulators). The discussed features include variation of reservoir properties with changes in fluid pressure; modular and coupled approaches to joint simulation of fluid flow and geomechanical processes; and available options for special geomechanical effects – such as erosion or formation of new fractures and impact on characteristics of existing fractures. Possible directions for further developments in this area of reservoir simulations are underlined.

A new theoretical model incorporating geomechanical effects for hydrate dissociation in sediments under thermal stimulation

Previous analytical models for hydrate dissociation under thermal stimulation usually focused on heat and mass transfer while ignoring geomechanical effects. However, it is accepted that hydrate dissociation under thermal stimulation involves multifield coupling problems, and the effect of a stress field on hydrate dissociation cannot be ignored. Thus, in this paper, based on a classic analytical model for predicting hydrate dissociation under thermal stimulation derived by Selim and Sloan, we propose a novel model that takes the geomechanical behavior into account to simulate hydrate dissociation. Specifically, we applied an incremental solution scheme to solve this coupled system. Afterwards, we validated our derived model and compared the influence of different porosity strategies (i.e., Lagrange's porosity and true porosity) on the coupled system. The result shows that, at small strains, porosity strategies have little influence on the coupled system. Moreover, parametric analysis was conducted to study the effects of relative parameters on hydrate dissociation. Compared with previous studies, our model not only is more efficient but also reveals more mechanisms of hydrate dissociation under thermal stimulation.

Mechanical formation damage control in permeability Biot’s effective stress-sensitive oil reservoirs with source/sink term

Geomechanical effects monitoring on reservoir rock and fluid properties response during the oil production curve are essential to improve oil recovery in a petroleum field. Incorporating geomechanics to flow models become the mathematical formulation regarding well-test and reservoir engineering more realistic because geomechanical parameters, e.g., in situ and overburden stress, as well as Biot’s coefficient, play a fundamental role in pressure response. Hence, permeability stress-sensitive oil reservoirs are the scope of various research in the petroleum industry for minimizing formation damage during drilling, completion, and stimulation operations. In this context, mechanical formation damage control plays a key role in preventing early-permeability loss that may result in reservoir compaction and oil field disinvestments. This work develops a new analytical solution for the nonlinear hydraulic diffusivity equation (NHDE) with instantaneous point-source/sink effects in permeability effective stress-sensitive oil reservoirs. The proposed model considers Biot’s effective stress change in the permeability response, and a new deviation factor is derived from comparing the nonlinear effect concerning the constant permeability classical solution and a decoupled case available in the literature. The calibration methodology is performed using a numerical simulator named IMEX®, widely used in formation evaluation works, and the results presented high convergence. The findings of this study allowed us to notice the role of overburden stress, oil flow rate, deviation factor, and Biot’s coefficient in permeability change during production in the diagnostic plots. Thereby, the modeling developed in this paper becomes a useful and attractive tool for predicting and monitoring permeability loss, oil flow rate specification, and reservoir history matching.

Analysis of fracture interference – Coupling of flow and geomechanical computations with discrete fracture modeling using MRST

A new discrete fracture model (DFM) is implemented in the MATLAB Reservoir Simulation Toolbox (MRST) – an open-source reservoir simulation software – to couple flow and geomechanical computations. Unstructured meshing is used to discretize the gridding domain. The matrix-to-matrix, fracture-to-fracture, and fracture-to-matrix fluxes are computed explicitly in the computational domain following the control volume formulation. The flow calculations and the geomechanical computations are solved sequentially: the governing equations for poroelasticity are incorporated, and the fixed stress splitting coupling methodology is employed. The results are compared with an uncoupled model, where the geomechanical effects are ignored.Several case studies demonstrate the utility of the proposed coupling strategy for analyzing production performance and stress evolution in hydraulically fracturing formations. This model considers the effects of poroelasticity and stress or strain variation in the fractured domains, and factors influencing the behaviour of fracture interference are examined. Finally, an analysis of the computational costs is also presented.This simulation approach can more accurately capture the dynamic behaviour of stress evolution and fracture interference in hydraulically fractured wells. This flexible framework can incorporate more functional modules, including fracture propagation, in future works. The results illustrate the significance of incorporating geomechanical effects in the flow simulation process. Insights pertinent to the operational strategies are also highlighted based on the simulation results.

A Geocoupling Simulation Method for Fractured Reservoir Production

Reservoir simulation is critical to the design of reservoir development plan and has been extensively used. However, it is challengeable for to simulate the production process for fractured reservoirs, because of the fracture geometry and the fracture deformation. Specifically, three problems need to be solved. First, there is a lack of mathematical models that can predict the fracture deformation with acceptable precision. Second, the fracture deformation is stress-dependent; therefore, a geocoupled equation should be used to quantify the stress change, but the solution is extremely expensive. Third, the fracture geometries pose great challenges to traditional gridding techniques. This paper proposes a new geocoupling simulation method that is capable of modeling the complex fracture geometry as well as the fracture mechanical behavior. The geomechanical effects and the reservoir production performance are modeled through an implicit geocoupled model, which is developed based on the poro-mechanics theory. The fixed stress strategy is used to solve the geocoupled equations. Moreover, a comprehensive fracture modeling method is proposed, in terms of the fracture deformation model and the fracture gridding technique to model the fracture effects. Ultimately, this method is used to analyze two field-scale cases. The results demonstrate that this method exhibits good practicability and has practical significance for fractured reservoir development.

Geomechanical effects of natural fractures on fluid flow in a pre-salt field

The discovery of carbonate reservoirs in the Brazilian pre-salt field has raised several engineering challenges. These reservoirs are naturally fractured and much stiffer than conventional reservoirs. Thus, the study of fluid flow through natural fractures has received significant attention from the petroleum industry because the production capacity of these fields is associated with the hydraulic behavior of such fractures. However, pressure changes induced by the oil recovery alter the fracture aperture. In turn, changes in the fracture aperture affect the fluid flow inside the fracture channels, increasing or reducing the production capacity of the reservoir. This work investigates the hydromechanical effect of natural fractures on the reservoir behavior at the production unit Tupi pilot of the Brazilian pre-salt. The enhanced dual-porosity/dual permeability model (EDPDP) is adopted to simulate more realistically the hydromechanical behavior of fractured carbonate rock formation. This approach updates the stiffness and permeability tensors considering the fracture orientation and the stress-induced aperture changes. The shape factor is also improved to represent multi-block domains formed by several multiscale fracture sets with different orientations, apertures, and spacing. The hydromechanical formulation of EDPDP implemented in an in-house framework GeMA (Geo Modeling Analysis) is adopted to study the hydromechanical effect of fractures with multiple lengths on the Tupi pilot. The numerical results demonstrate that the complex fracture network is responsible for fluid migration through a preferential pathway. A parametric analysis of the main parameters that affect reservoir behavior was carried out. The parametric study shows higher pore pressure dissipation for smaller dip angles. Then, horizontal fractures are more sensitive to vertical displacements. In addition, smaller spacing and larger fracture aperture enhance permeability, increasing pore pressure dissipation and mechanical deformation. Finally, numerical results were compared against field measurements showing excellent agreement, demonstrating the applicability of the EDPDP model to simulate naturally fractured reservoirs.

Study of hybrid thermal recovery process and geomechanics on heavy oil production performance

Cyclic steam injection, electric heating and air injection are commonly used as enhanced oil recovery method for heavy oil production. Previous studies have found that oil production rates decrease with the number of steam injection cycles. In this study, the potential of three hybrid thermal recovery processes: air assisted steam injection, electric heating assisted air injection and cyclic steam injection was investigated. Different hybrid thermal injection scenarios were simulated to examine the production performance of heavy oil reservoirs. The results revealed that air-assisted steam injection outperforms other approaches. It was observed that the cyclic steam with air injection obtained the highest oil recovery, while electric heating combined with cyclic air injection yielded the lowest oil recovery. The key factors controlling heavy oil production performance are the size and temperature of the heated chamber. As there are no conclusive remarks regarding the geomechanical effect on well deliverability, thermally induced geomechanical effect in the hybrid injection process was considered in this study. The behavior of cyclic injection and production causes the redistribution of in situ stresses. The geomechanical displacement was influenced by the injected steam and air volume. It was clearly observed that the reservoir vertical uplift occurred in the injection period which was caused by thermal injection.

Modeling of natural gas self-diffusion in the micro-pores of organic-rich shales coupling sorption and geomechanical effects

A significant amount of the natural gas in shale formations is contained in the micro- and mesopores as dissolved (absorbed) phase and on the surfaces of associated microcracks as (adsorbed) phase. The transport of natural gas in such confined spaces is primarily governed by self-diffusion as could be deduced from Knudsen number. Self-diffusion is governed by the pressure and the space confinement. In this study, realistic kerogen structures possessing both tortuous micropores and larger microcracks were formed and used to assess self-diffusion behavior during the depletion of shale reservoirs through some comprehensive molecular simulation workflow. Analysis of the transport modes revealed transition self-diffusion as the primary transport mechanism in these micropores. The sorption behavior and the mechanical properties were analyzed and incorporated to derive a transition diffusion model that is sensitive to changes in the pore pressure and the stress field. The proposed model was compared and validated against similar work in the literature. The results showed that during a typical production span, a pressure drop influences the sorption profile, the net overburden stress on the pores, and the mean free path, altering the magnitude of self-diffusivity. The calibrated pore scale model produced decent predictive ability with a relative error of 2.5–16%. The implications of structure tortuosity, sorption profile, and pore pressure on the effective diffusion coefficient and gas desorption are discussed in depth. This work provides a novel methodology for studying the effect of coupled multiphysics processes on methane transport in a realistic kerogen geometry, which could be used to calibrate a suitable pore scale model for upscaled reservoir simulation applications and accurate assessment of reservoir dynamics and ultimate recovery.

Full coupling of CO2–CH4 transport and sorption with solid deformation in gas shale enhances natural gas recovery and geological CO2 storage capacity

A thermodynamically rigorous constitutive model is used to describe the full coupling among the nonlinear processes of transport, sorption, and solid deformation in organic shale where the pore fluid is the binary mixture of carbon dioxide and methane. The constitutive model is utilized in a numerical solution that simulates injection of carbon dioxide in shale before producing carbon dioxide and methane from the same. The solution considers advection and diffusion as viable mechanisms of pore fluid transport where the latter comprises molecular, Knudsen, and surface diffusion in ultralow permeability shale. Results indicate that gas adsorption would be the main storage mechanism of sequestration in shale which may comprise up to 70% of the stored CO2 mass. A third of this storage capacity could be due to the geomechanical effects. Therefore, complete or partial exclusion of the coupling between sorption and solid phase deformation from the solution would result in underestimation of carbon dioxide storage capacity and natural gas recovery factor of the rock. Surface diffusion, sorption-induced deformation, as well as strain-induced changes in gas sorption capacities, are all conducive to both outcomes. Sensitivity analysis shows that the solution results are most sensitive to changes in adsorption capacities, followed by initial permeability, Young's modulus, Poisson's ratio, surface diffusivities, and initial pore radius.

Building 1D and 3D static reservoir geomechanical properties models in the oil field

Reservoir geomechanical models provide valuable information for various applications ranging from the prediction of surface subsidence to the determination of pore pressure and induced stress changes, wellbore stability, fault reactivation, and caprock integrity. Three-dimensional geological modeling of reservoir geomechanics is an essential tool to predict reservoir performance by considering the geomechanics effects. Thus, this study focuses on the application of 3D static reservoir geomechanical model workflow by using 3-D seismic and well log data for proper optimization in the Volve oil field, Norway. 3D Seismic data are applied to generate the interpreted horizon grids and fault polygons. The horizon which cut across the nine wells is used for the detailed topographic analysis. The workflow includes 1D geomechanical and petrophysical models which are calculated at well locations by using log data. Structural and property modeling (pore pressure, vertical and horizontal stresses, elastic properties, porosity, permeability, and hydrocarbon saturation) is distributed by geostatistical methods such as Kriging and Gaussian. This study indicates the effectiveness of the three-dimensional static modeling technique as a tool for better understanding of the spatial distribution of reservoir geomechanical properties, hence, providing a framework for analyzing future activities in the reservoir such as proposal position and trajectory of new wells for future field development and assessing arbitrary injection-production schedules.

Fully coupled modeling of two-phase fluid flow and geomechanics in ultra-deep natural gas reservoirs

Efficiently and accurately understanding the fluid flow behavior in ultra-deep natural gas reservoirs is very challenging due to the complex geological environment and the intricate gas properties at high pressure. In this study, a fully coupled fluid flow and geomechanical model was developed to simulate complex production phenomena in ultra-deep natural gas reservoirs. Stress-dependent porosity and permeability models were applied, and then the governing equations of the model were incorporated into COMSOL Multiphysics. Furthermore, the model was verified by the reservoir depletion from the Keshen gas field in China, and the effects of reservoir properties and geomechanics on gas production were discussed. The results showed that the reservoir pressure and water saturation exhibited a significant funnel-shaped decline during the reservoir depletion. The higher relative permeability of the gas phase results in more methane gas production, thereby reducing the average pore pressure and gas saturation near the wellhead. When considering geomechanical effects, the production behavior significantly changes. The predictive value of gas production was higher when the reservoir rock deformation was ignored. The gas production exhibited strong positive correlations with reservoir porosity, fracture permeability, elastic modulus, and Poisson's ratio. Larger porosity, elastic modulus, and Poisson's ratio resulted in smaller deformation, while a smaller fracture permeability leads to larger deformation in ultra-deep natural gas reservoirs.

Message Passing Interface (MPI) Parallelization of Iteratively Coupled Fluid Flow and Geomechanics Codes for the Simulation of System Behavior in Hydrate-Bearing Geologic Media. Part 2: Parallel Performance and Application

Summary The reservoir geomechanics simulator (RGMS or RGM simulator), a geomechanics simulator based on the finite element method 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 to investigate the geomechanical responses associated with gas production from hydrate accumulations. In the second paper of this series, the parallel performance of the codes is tested on the Texas A&M University Ada Linux cluster using up to 512 processes and on a Mac Pro computer with 12 processes. The investigated problems are: Group 1: Geomechanical problems solved by RGMS in 2D Cartesian and cylindrical domains and a 3D problem, involving 4×106 and 3.375×106 elements, respectively; Group 2: Realistic problems of gas production from hydrates using pT+H V1.5 in 2D and 3D systems with 2.45×105 and 3.6×106 elements, respectively; Group 3: The 3D problems in Group 2 solved with the coupled RGMS-pT+H V1.5 simulator, fully accounting for geomechanics. Two domain partitioning options are investigated on the Ada Linux cluster and the Mac Pro, and the code parallel performance is monitored. On the Ada Linux cluster using 512 processes, the simulation speedups (a) of RGMS are 218.89, 188.13, and 284.70 in the Group 1 problems, (b) of pT+H V1.5 are 174.25 and 341.67 in the Group 2 cases, and (c) of the coupled simulators are 134.97 and 331.80 in the Group 3 cases. The results produced in this work show the necessity of using full geomechanics simulators in marine hydrate-related studies because of (a) the associated pronounced geomechanical effects on production and displacements and (b) the effectiveness of the parallel simulators developed in this study, which can be the only realistic option in these complex simulations of large multidimensional domains.

Coupled hydro-mechanical analysis of seasonal underground hydrogen storage in a saline aquifer

Hydrogen is promising an efficient and viable solution for low-carbon fuel for different purposes, such as transportation, manufacturing, and electricity. Fluctuating renewable energy production, however, can lead to a temporary imbalance between demand and supply. Nonetheless, it is feasible to mitigate this mismatch by converting the surplus wind power to hydrogen and storing it in geological (subsurface) systems. This work investigates the applicability of underground hydrogen storage in a saline aquifer at the Powder River Basin of Wyoming State. Thus, a 3D coupled hydro-mechanical simulation is presented to evaluate the hydraulic and geomechanical effects during three annual injection-reproduction cycles. A fully calibrated one-dimensional mechanical model has been constructed to characterize the 3D geomechanical model. The simulated results show that the designed storage scenario can be operated with reasonable recovery efficiency such that 78% of injected hydrogen can be extracted to meet 16.7% of household summer electricity consumption for the considered scenario in this study. The surface uplift is highly correlated with the cumulative amount of hydrogen injection and production, and a maximum magnitude of 1.6 cm has been estimated. Integrity analysis of subsurface rock and caprock based on the Mohr-Coulomb criterion demonstrates the safety of underground hydrogen storage at the selected site.

A comprehensive study of the effect of Brinkman flow on the performance of hydraulically fractured wells

The most recent study shows that a rigorous Darcy flow does not exist in hydraulic fractures due to the effect of viscous shear from fracture walls, and the Brinkman equation can be a more accurate method to characterize the fracture flow (Teng et al., 2020). For Darcy flow, the fracture permeability is equivalent to the proppant-pack permeability, whereas, for the Brinkman flow, the fracture permeability is related to the fracture width as well as to the proppant-pack properties. In this work, the authors conducted a comprehensive study of the effect of Brinkman flow on the performance of fractured wells by use of a proposed semi-analytical model. In addition to the Brinkman flow, this proposed semi-analytical model also can account for the geomechanical effect to describe the stress-dependent proppant-pack properties and fracture width. The calculated results in this work show that the fracture permeability is lower than the proppant-pack permeability ascribing to the effect of Brinkman flow. As the production proceeds, the Brinkman flow will play a more important role in influencing the fluid transport within propped fractures. The effect of Brinkman flow on the well performance is significant only if the geomechanical effect is considered. If the fracture volume is sufficiently large or the proppant-pack permeability is sufficiently high, a longer fracture can be more favorable for improving the well productivity. If the Darcy parameter (defined in Eq. (22)) of the hydraulic fracture is less than 0.001, the long-term cumulative production of the fractured wells will not be influenced by the Brinkman flow. If the Darcy parameter is larger than 0.001, the effect of Brinkman flow cannot be neglected unless the Darcy-flow dimensionless conductivity is sufficiently large.

Hydro-thermo-chemo-mechanical modeling of carbon dioxide injection in fluvial heterogeneous aquifers

Understanding geological sequestration of carbon dioxide (CO2) requires fully-coupled simulation of thermal-hydrological-mechanical-chemical (THMC) processes within well-characterized subsurface heterogeneity. A CO2 injection pilot project was performed in the Cranfield site, Mississippi, USA, where subsurface heterogeneity reflects fluvial deposition. During the project, CO2 was injected through an injection well and was monitored using two observation wells. We incorporate high-resolution three-dimensional heterogeneity model of the site into multiphase and multi-component flow and transport models. We validate our models and evaluate how bottom-hole pressure (BHP) in injection well, CO2 breakthrough times at observation wells, and efficiency of trapping mechanisms (i.e., dissolution, snap-off trapping, mobile CO2) are controlled by (1) non-isothermal CO2 injection, (2) geochemical reactions, (3) capillary pressure heterogeneity, (4) geomechanical effects, and (5) permeability enhancement close to the injection well. Results suggest that neglecting thermal effects lowers BHP, shortens breakthrough times, overestimates dissolution, and underestimates snap-off trapping. The BHP remains unchanged, breakthrough times are overestimated, and solubility and snap-off trapping are underestimated when geochemical reactions are ignored. Ignoring capillary pressure heterogeneity results in underestimation of BHP and dissolution and overestimation of breakthrough times. Ignoring geomechanical process results in lower BHP, shorter breakthrough times, increased dissolution, and decreased snap-off trapping. Ignoring permeability enhancement results in underestimation of breakthrough times and solubility trapping, and overestimation of snap-off trapping. Our results have important practical implication for designing effective field scale experiments and numerical simulations of geological carbon sequestration. Other multiphase flow problems in which subsurface heterogeneities are the main controlling factor (e.g., hydrogen storage) may benefit from this work.