Coupled Geomechanics Research Articles

Fully coupled THM modeling of CO2 sequestration in depleted gas reservoirs considering the mutual solubilities in CO2-Hydrocarbon gas-brine systems

In recent years, CO2 geological sequestration has gained significant traction as a viable solution for mitigating global emissions. However, assessing such processes has been challenging due to its inherent complexity. Given the extensive temporal and spatial scales, numerical modeling has emerged as the most efficient and cost-effective means of evaluating them. At present, most existing models are tailored for CO2 sequestration in saline aquifers. There are relatively few models available for depleted gas reservoirs, and only a fraction of them possess the capability to account for geomechanical coupling or complex natural gas compositions.CO2 sequestration in depleted gas reservoirs is considered a promising technique for combating global warming. The use of depleted gas reservoirs has several advantages over saline aquifers, such as the availability of existing facilities and the proven capacity and stability of gas storage. It is believed that CO2 storage in depleted petroleum reservoirs can provide intermediate-scale storage until large-scale storage in saline aquifers becomes mature.Here we propose an Equation of State (EOS) module for CO2 sequestration in depleted gas reservoirs or CO2-enhanced gas recovery. It takes into consideration the mutual solubilities in the CO2-hydrocarbon gas-brine system based on the equality of the chemical potentials of the aqueous and non-aqueous phases. In such a way, it can properly address CO2 dissolution into brine when hydrocarbon gas is present. Hydrocarbon gas includes methane, ethane, and propane. It employs well-recognized approaches to calculate the thermodynamic properties of the gaseous and aqueous phases. This EOS module has been applied to our in-house simulator, TOUGH2-CSM, to enable thermo-hydrological-mechanical modeling. Our research could fill the gap and provide a reference for future studies in this regard.

Numerical study of the impact of stress concentration on shale gas production

Predicting the production amounts has great significance for exploitation of oil and gas resources. The flow–geomechanical coupling effect plays an important role in predicting production. Shale rocks and the stress-dependent permeability model are critical for representing this coupling effect. The pore network of shale rock is not abundant like that of coal rock, and the matrix blocks of shale rock are not completely separated by the pore network. There is stress concentration around the pores when shale rock is deformed. Based on previous studies, the stress-dependent permeability model considering the impact of stress concentration is used in this study to build a numerical simulation model for flow–geomechanical coupling in a shale gas reservoir and validation using field data. Sensitivity studies are conducted to discuss the difference in production prediction between the new and common models. The main conclusions of this study are as follows: 1) The new model can fit both the field and experimental data well; the average error in daily production rate between the numerical solution and field data is 8%, which indicates that the new model can be used to predict shale gas production. 2) Under the geomechanical condition of a real reservoir, the difference in predicted production between models with and without stress concentration can be large and increase with the ratio of a to b. If this ratio is less than 50, the impact of stress concentration is not significant. Otherwise, the impact of stress concentration on production increases sharply and can exceed 20%. 3) The adsorption-induced strain enhances the impact of stress concentration on production. When the Langmuir pressure exceeds 1 MPa and Langmuir strain exceeds 0.01, the impact magnitude of stress concentration can exceed 10%.

Coupled Geomechanics and Chemistry Model for Acid Stimulation of Naturally Fractured Carbonate Reservoirs

Summary Treatments of naturally fractured carbonate formations typically involve acid injection when damage of natural fractures (NFs) occurs mechanically and chemically. Coupled modeling of both mechanisms is often neglected. We build a quantitative model of damageable reservoir, where the permeability depends on the shear and tensile activation of NFs, as well as acid transport and reaction. Simulations demonstrate model applicability to NF acidizing and acid fracturing. Particularly, we show that strong pressure drawdowns in tight carbonates result in steep production declines because of NF pinching.

Impact of Exposure to Supercritical Carbon Dioxide on Reservoir Caprocks and Inter-Layers during Sequestration

The long-term exposure of rocks to supercritical carbon dioxide (scCO2) during sequestration creates structural and chemical changes. In turn, these lead to changes in the permeability of inter-layers and caprocks that can alter plume migration behaviour and/or lead to the loss of the sealing efficiency of caprocks. This review first surveys experimental studies of changes to the pore structure and mass transport properties of caprocks and interlayers, including novel experimental protocols and data analysis methods. These methods provide more accurate measures of basic parameters, such as surface area, as well as new information on pore network features that are essential to properly understanding changes to mass transport properties. The subsequent evolution of rocks exposed to scCO2 involves a complex coupling of geomechanics, geochemistry, and mass transport processes over different length and time scales. The simultaneous combination of all three factors together is rarely considered and this review also surveys such fully integrated work to understand the complex interplay and feedback arising between the different processes. We found that it was necessary to include all three coupled processes to obtain truly representative behaviour in reservoir simulations; otherwise, counter-intuitive effects are missed. These include the unexpected greater sealing efficiency of thin shale layers.

Integration of Electromagnetic Geophysics Forward Simulation in Coupled Flow and Geomechanics for Monitoring a Gas Hydrate Deposit Located in the Ulleung Basin, East Sea, Korea

We investigate the feasibility of electromagnetic (EM) geophysics methods to detect the dissociation of gas hydrate specifically from a gas hydrate deposit located in the Ulleung Basin, East Sea, Korea via an integrated flow-geomechanics-EM geophysics simulation. To this end, coupled flow and geomechanics simulation is first performed with the multiple porosity model employed, where a mixed formulation with the finite volume (FV) and finite element (FE) methods are taken for the flow and geomechanics, respectively. From the saturation and porosity fields obtained from the coupled flow and geomechanics, the electrical conductivity model is established for the EM simulation. Solving the partial differential equation of electrical diffusion which is linearized using the 3D finite element method (FEM), the EM fields are then computed. For numerical experiments, particularly two approaches in the configuration for the EM methods are compared in this contribution: the surface-to-surface and the surface-to-borehole methods. When the surface-to-surface EM method is employed, the EM is found to be less sensitive, implying low detectability. Especially for the short term of production, the low detectability is attributed to the similarity of electrical resistivity between the dissociated gas (CH4) and hydrate as well as the specific dissociation pattern within the intercalated composites of the field. On the other hand, when the surface-to-borehole EM method is employed, its sensitivity to capture the produced gas flow is improved, confirming its detectability in monitoring gas flow. Hence, the EM geophysics simulation integrated with coupled flow and geomechanics can be a potential tool for monitoring gas hydrate deposits.

Coupled Geomechanics and Flow Modeling of Fractured Reservoirs considering Matrix Permeability Anisotropy

The effect of geomechanics is crucial in the modeling of fractured reservoirs since fractures can be more stress-sensitive than the rock matrix. In fractured reservoirs, the microscale fractures are often homogenized into the matrix continuum leading to matrix permeability anisotropy. The embedded discrete fracture model (EDFM) is becoming increasingly popular for numerical simulation of fractured reservoirs and has been successfully employed in the simulation of coupled geomechanics and flow systems. However, the anisotropic permeability of matrix cannot be considered in traditional EDFM. An approach of coupled geomechanics and flow modeling is proposed for fractured reservoirs considering anisotropic matrix permeability. In order to calculate the fluid exchange between fractures and rock matrix in an anisotropic formation, an integrally embedded discrete fracture model (IEDFM) is used. The geomechanics model of the proposed approach uses an equivalent continuum approach, which introduces an equivalent material to represent the overall deformation of the fractured rock under normal and shear stresses. The constitutive relations of the equivalent continuum are derived rigorously from stress-strain analysis, where the stress-dependent moduli of natural fractures are included. The coupled geomechanics and flow system is solved using the fixed-stress split iterative coupling strategy with the dynamic hydraulic parameters of matrix and fractures updated separately. Several examples are performed to demonstrate the applicability of the proposed approach for modeling the coupled geomechanics and flow system in fractured reservoirs considering anisotropic permeability. The effect of anisotropy is investigated, which indicates that the dynamic behavior of a fracture is highly orientation-related due to initial stress anisotropy and matrix permeability anisotropy. Simulations also show that the anisotropic matrix permeability affects the compaction in the reservoir domain, which reflects on the performance of production.

Coupled reservoir geomechanics with sand production to minimize the sanding risks in unconsolidated reservoirs

Sand production in unconsolidated reservoirs has become a cause of concern for production engineers. Issues with sand production include increased wellbore instability and surface subsidence, plugging of production liners, and potential damage to surface facilities. A field case in southeast Iraq was conducted to predict the critical drawdown pressures () at which the well can produce without sanding. A stress and sanding onset models were developed for Zubair reservoir. The results show that sanding risk occurs when rock strength is less than 7,250 psi, and the ratio of shear modulus to the bulk compressibility is less than 0.8 × 1012 psi2. As the rock strength is increased, the sand free drawdown and depletion becomes larger. The of the upper and lower sand units are 3,900 and 5,400 psi at zero depletion rate, respectively. This indicates that the sanding risk may initiate earlier at the upper sand unit. The sanding potential occurs at the perforated interval within the upper sand unit when drawdown pressures reach 2,160 psi. The sensitivity analysis shows a wide range of when the uncertainty of rock strength is considered. This study will assist in optimizing the type of completion and minimize the sanding risk in unconsolidated reservoirs.

Development of coupled two phase flow and geomechanics model to predict stress evolution in unconventional reservoirs with complex fracture geometry

Understanding stress changes associated with reservoir depletion is very important for developments of unconventional reservoirs such as completion of infill well. Fluid flow in reservoir often contains multiple phases mostly a mix of oil and water phase. Multiphase flow in porous media also involves in many applications including water injection. In this paper, we have upgraded our coupled fluid flow and geomechanics with Embedding Discrete Fracture Model (EDFM) to two phase flow using OpenFOAM, an open-source platform for CFD, in order to expand the model to wider range of applications including characterization of stress evolution associated with depletion of two-phase flow in unconventional reservoirs with complex fracture geometries. Coupled geomechanics and fluid-flow was developed based on well-known fixed-stress split, which is unconditionally stable and computationally efficient to simulate how stress changes during reservoir depletion. EDFM was coupled to the model to gain capability of simulating complex fracture geometries using structured grids. The two phase model is based on Implicit Pressure Explicit Saturation (IMPES) method. Validations of our single phase model and EDFM were conducted in our previous paper. Validation of two phase model was done against analytical solution of Buckley-Leverett and Capillary-gravity equilibrium problems. In addition, validation of EDFM part was conducted against local grid refinement. The model was used to run performance test on water injection-oil production problem with geomechanics and capillary effect. Non-planar fractures under production was also used to test for EDFM part. Finally, we applied our model in simulation of 3D multiple fractures under production in a fully 3D reservoir. The results indicate that created fracture geometries have a significant effect on stress distribution and reorientation induced by depletion. Characterization of stress evolution due to reservoir depletion in two phase flow will provide critical guidelines for optimization of completion designs especially in infill well drilling and further development in unconventional reservoirs.

Infill well wellbore stability analysis by considering plasticity, stress arching, lateral deformation and inhomogeneous depletion of the reservoir

The traditional way of analyzing wellbore stability of infill wells relies on the analytical solution of the stress path, which assumes uniaxial strain, homogenous depletion, constant overburden stress, and linear elastic condition. The objective of this study is to re-evaluate all the above four assumptions and analyze the plasticity, stress arching, lateral deformation and inhomogeneous depletion of the reservoir. Coupled geomechanics and fluid flow analysis is conducted to get the time and location dependent stress field and pressure field, which serve as inputs for wellbore stability analysis for infill wells. Considering four cases, the ranking according to the width of the safe drilling mud weight windows is 1) plasticity, 2) elasticity, 3) plasticity with stress arching, and 4) elasticity with stress arching. This coupled geomechanics and fluid flow can provide dynamic information concerning where to drill, when to drill, and how to drill for infill wells.

Efficient History Matching of Thermally Induced Fractures Using Coupled Geomechanics and Reservoir Simulation

Waterflooding is a common recovery method used to maintain reservoir pressure and improve reservoir oil sweep efficiency. However, injecting cold water into a reservoir alters the state of in-situ formation stress and can result in the formation fracturing. In other words, it can cause the initiation and growth of thermally induced fractures (TIFs), even when the original fracture propagation pressure is not exceeded. TIFs can cause non-uniform distribution of the fluid flow in wellbores, a reduction in sweep efficiency, and early water breakthrough in nearby production wells. Modelling and history matching workflows that consider the dynamic nature of the TIF problem are critical. These workflows improve and validate reservoir and geomechanical models, identify and confirm observed TIF onset and propagation periods, and provide a history-matched sector model with the rock mechanical and thermal properties and stress gradients that can be used with confidence for subsequent studies. Modelling and the underlining assumptions of fluid flow in the TIF and reservoir matrix, as well as geomechanical changes due to cooling of the reservoir during injection, are detailed below. A 3D reservoir simulator coupled with 2D finite element TIF and geomechanical models were used to manually history match an injector (NI6) in the N Field sector reservoir model in which a TIF was observed. In this study, history matching workflows were developed to consider the dynamic nature of TIF development during waterflooding. The reservoir and geomechanical models were improved and validated via the observed TIF onset and propagation periods. The history-matched models produced can be used with confidence in subsequent studies. The practical workflows and guidelines developed here can be used in waterflooding operations during the modelling, design, and planning stages. The novelty of this study is the coupling approach of different complex processes done in order to capture dynamic changes during waterflooding operations. A similar history matching study could not be found in the literature.

Global/local model order reduction in coupled flow and linear thermal-poroelasticity

Coupled flow and geomechanics computations are very complex and require solving large nonlinear systems. Such simulations are intense from both runtime and memory standpoint, which strongly hints at employing model order reduction (MOR) techniques to speed them up. Different types of Reduced-Order Models (ROM) have been proposed to alleviate this computational burden. MOR approaches rely on projection operators to decrease the dimensionality of the problem. We first execute a computationally expensive “offline” stage, during which we carefully study the full order model (FOM). Upon creating a ROM basis, we then perform the cheap “online” stage. Our reduction strategy estimates a ROM using proper orthogonal decomposition (POD). We determine a family of solutions to the problem, for a suitable sample of input conditions, where every single realization is so-called a “snapshot.” We then ensemble all snapshots to determine a compressed subspace that spans the solution. Usually, POD employs a fixed reduced subspace of global basis vectors. The usage of a global basis is not convenient to tackle problems characterized by different physical regimes, parameter changes, or high-frequency features. Having many snapshots to capture all these variations is unfeasible, which suggests seeking adaptive approaches based on the closest regional basis. We thus develop such a strategy based on local POD basis to reduce one-way coupled flow and geomechanics computations. We partition the time window to adequately capture regimes such as depletion/build-up and decreasing the number of snapshots per basis. We focus on linear elasticity and consider factors such as the role of the heterogeneity. We also assess how to tackle different degrees of freedom, such as the displacements (intercalated and coupled), pressure, and temperature, with MOR. Preliminary 2- and 3-D results show significant compression ratios up to 99.9% for the mechanics part. We formally compare FOM and ROM and provide time data to demonstrate the speedup of the procedure. Examples focus on linear and nonlinear poroelasticity. We employ continuous Galerkin finite elements for all of the discretizations.

Stability of multirate explicit coupling of geomechanics with flow in a poroelastic medium

We consider single rate and multirate explicit schemes for the Biot system modeling coupled flow and geomechanics in a poro-elastic medium. These schemes are widely used in practice that follows a sequential procedure in which the flow and mechanics problems are fully decoupled. In such a scheme, the flow problem is solved first with time-lagging the displacement term followed by the mechanics solve. The multirate explicit coupling scheme exploits the different time scales for the mechanics and flow problems by taking multiple finer time steps for flow within one coarse mechanics time step. We provide fully discrete schemes for both the single and multirate approaches that use Backward Euler time discretization and mixed spaces for flow and conformal Galerkin for mechanics. We perform a rigorous stability analysis and derive the conditions on reservoir parameters and the number of finer flow solves to ensure stability for both schemes. Furthermore, we investigate the computational time savings for explicit coupling schemes against iterative coupling schemes.

Integrated approach for fracture characterization of hydraulically stimulated volume in tight gas reservoir

Hydraulic fracturing is conducted on unconventional reservoir which has very low permeability. It increases the production from unconventional oil and gas reservoirs through the creation of a connected stimulated rock volume (SRV) with higher conductivity. The permeability and the SRVs dimension are important parameters which increase the performance of hydraulically fractured wells. Microseismic monitoring is used to estimate the seismically stimulated volume within the reservoir, which can provide a proxy for the SRV. Finite element analysis was used in this study in the determination of SRV characteristics by utilizing field data from a horizontal well hydraulic-fracturing program in the Hoadley Field, Alberta, Canada. Coupled fluid-flow geomechanics finite element (FE) model was used. The permeability of the SRV is altered to match the field bottom-hole pressure. The pressure drop and in situ stress changes within the SRV are determined through the matching of the FE model. Fracture aperture, number and spacing in the SRV are then inferred from the estimated reservoir parameters by using a semi-analytical approach.

Community Code for Simulating Co2 Storage: Modelling Multiphase Flow with Coupled Geomechanics and Geochemistry Using the Open-Source Multiphysics Framework Moose

Community Code for Simulating Co2 Storage: Modelling Multiphase Flow with Coupled Geomechanics and Geochemistry Using the Open-Source Multiphysics Framework Moose

A new sequential method for three-phase immiscible flow in poroelastic media

A new computational model is developed to solve three phase immiscible compressible flow in strongly heterogeneous poroelastic media. Within the context of the iterative coupled formulation based on the fixed stress split algorithm the governing equations are decomposed into three subsystems associated with the geomechanics, hydrodynamics and transport problems. The hydrodynamics involves an overall compressibility which plays essential role in the magnitude of additional source in the pressure equation associated the time derivative of the total mean stress. We show that the additional coefficients in the source can be decomposed into a rock/grain and fluid components involving the formation volume factors of each phase. The flow equations are written in a proper conservative form for application of mixed-hybrid formulation whereas the nonlinear coupling between flow and transport is handled by a proper sequential iterative scheme. A new post-processing approach is proposed to update the Lagrangian porosity based on the freezing of the total mean stress which reproduces the one-way formulation in a straightforward fashion under the stationarity of the total mean stress. The geomechanical subsystem is also discretized by a mixed formulation based on the decomposition of the effective stress into spherical and deviatoric components in order to handle the nearly-incompressible undrained limit. The system of conservation laws for the liquid saturations is rephrased in an alternative form for an appropriate operator splitting method, leading to the appearance of an extra source term arising from the transient behavior of the Lagrangian porosity induced by the geomechanical coupling. Within the framework of a predictor–corrector scheme, the predictor step is discretized by an extended version of a higher order central-upwind scheme whereas the corrector, which captures the influence of rock skeleton deformation upon transport, is captured by a Godunov splitting. The potential of the new computational model is illustrated in numerical simulations of water-flooding and of WAG (Water Alternating Gas) injection problems in poroelastic media. Numerical results illustrate precisely the role of the transient nature of the total stress upon subsidence, rock compaction, oil and gas production and finger grow in primary and secondary recovery regimes.

Hydraulic Fracturing and Production Optimization in Eagle Ford Shale Using Coupled Geomechanics and Fluid Flow Model

With increasing production from shale gas and tight oil reservoirs, horizontal drilling and multistage hydraulic fracturing processes have become a routine procedure in unconventional field development efforts. Natural fractures play a critical role in hydraulic fracture growth, subsequently affecting stimulated reservoir volume and the production efficiency. Moreover, the existing fractures can also contribute to the pressure-dependent fluid leak-off during the operations. Hence, a reliable identification of the discrete fracture network covering the zone of interest prior to the hydraulic fracturing design needs to be incorporated into the hydraulic fracturing and reservoir simulations for realistic representation of the in situ reservoir conditions. In this research study, an integrated 3-D fracture and fluid flow model have been developed using a new approach to simulate the fluid flow and deliver reliable production forecasting in naturally fractured and hydraulically stimulated tight reservoirs. The model was created with three key modules. A complex 3-D discrete fracture network model introduces realistic natural fracture geometry with the associated fractured reservoir characteristics. A hydraulic fracturing model is created utilizing the discrete fracture network for simulation of the hydraulic fracture and flow in the complex discrete fracture network. Finally, a reservoir model with the production grid system is used allowing the user to efficiently perform the fluid flow simulation in tight formations with complex fracture networks. The complex discrete natural fracture model, the integrated discrete fracture model for the hydraulic fracturing, the fluid flow model, and the input dataset have been validated against microseismic fracture mapping and commingled production data obtained from a well pad with three horizontal production wells located in the Eagle Ford oil window in south Texas. Two other fracturing geometries were also evaluated to optimize the cumulative production and for the three wells individually. Significant reduction in the production rate in early production times is anticipated in tight reservoirs regardless of the fracturing techniques implemented. The simulations conducted using the alternating fracturing technique led to more oil production than when zipper fracturing was used for a 20-year production period. Yet, due to the decline experienced, the differences in cumulative production get smaller, and the alternating fracturing is not practically implementable while field application of zipper fracturing technique is more practical and widely used.

Modeling fracture propagation and seafloor gas release during seafloor warming‐induced hydrate dissociation

AbstractThe stability of marine methane hydrates and the potential release of methane gas to the ocean and atmosphere have received considerable attention in the past decade. Sophisticated hydraulic‐thermodynamic models are increasingly being applied to investigate the dynamics of bottom water warming, hydrate dissociation, and gas escape from the seafloor. However, these models often lack geomechanical coupling and neglect how overpressure development and fracture propagation affect the timing, rate, and magnitude of methane escape. In this study we integrate a geomechanical coupling into the widely used TOUGH + Hydrate model. It is shown that such coupling is crucial in sediments with permeability ≤10−16 m2, as fracture formation dramatically affects rates of dissociation and seafloor gas release. The geomechanical coupling also results in highly nonlinear seafloor gas release, which presents an additional mechanism for explaining the widely observed episodic nature of gas flares from seafloor sediments in a variety of tectonic and oceanographic settings.

Vertical Equilibrium Flow Models with Fully Coupled Geomechanics for CO2 Storage Modeling, Using Precomputed Mechanical Response Functions

Vertical equilibrium (VE) models have proved to be attractive for simulation of CO2 storage scenarios. Their primary advantage is a substantial reduction in computational requirements compared to standard 3D simulation tools. In this work, we aim to include the effects of geomechanics on aquifer flow while preserving computational efficiency. When fluids are injected into a geological formation, changes in pore pressure leads to rock deformation, which influence the flow properties of the formation. To fully model this effect, a two way coupling between flow and mechanics equations is generally necessary, including the full under- and overburden. This leads to a computationally expensive system, thus reducing the computational advantage of using VE models. Within a linear poroelastic framework, the full effect of deformation on flow is captured through changes in volumetric strain, which can be precomputed for a given pressure basis at grid generation time and used directly in the flow equations during simulation. This allow us to model the full effect of geomechanics on aquifer flow while eliminating the need for solving the mechanics equations at simulation time. We demonstrate the approach on 2D and 3D examples, and compare with results obtained from a standard VE flow models and a model that includes the full poroelastic set of equations. Compared to the latter, we observe a significant computational benefit using our proposed approach. On the other hand, the impact of geomechanics appears to be primarily captured by a well-chosen rock compressibility coefficient, suggesting that a fully coupled model might not be required in many practical cases.

Coupled geomechanics and flow modeling of thermally induced compaction in heavy oil diatomite reservoirs under cyclic steaming

Shallow, heavy oil diatomite reservoirs produced using cyclic steaming are often associated with significant subsidence. In cases where the pore pressure is not allowed to deplete noticeably, observed subsidence suggests a mechanism other than pressure decline is responsible. We perform coupled flow and geomechanics modeling to determine whether thermally induced compaction of the reservoir rock could play an important role in subsidence. First, we model laboratory-scale tests on diatomite samples subjected to mechanical and thermal loads. During these tests, substantial non-recoverable thermal compaction was measured. Using the modified Cam-clay model as a basis, thermally induced compaction is implemented by reducing the size of the yield surface as a function of temperature. This leads to a satisfactory modeling of the test results. Second, this new approach is used to model a symmetric pattern of wells in a generic heavy oil diatomite field produced using cyclic steaming. Results from simulations that consider or neglect thermally induced diatomite compaction show that thermal effects can potentially induce significant inelastic pore volume reduction and substantial subsidence.

Convergence of iterative coupling of geomechanics with flow in a fractured poroelastic medium

We consider an iterative scheme for solving a coupled geomechanics and flow problem in a fractured poroelastic medium. The fractures are treated as possibly non-planar interfaces. Our iterative scheme is an adaptation due to the presence of fractures of a classical fixed stress-splitting scheme. We prove that the iterative scheme is a contraction in an appropriate norm. Moreover, the solution converges to the unique weak solution of the coupled problem.