Jihoon Kim

Numerical Studies on Two-way Coupled Fluid Flow and Geomechanics in Hydrate Deposits

Coupled flow and geomechanics play an important role in the an alysis of gas hydrate reservoirs under production. The stif fness of the rock skeleton and the deformation of the reservoir, as well as porosity and permeability, are directly influenced b y (and interrelated with) changes in pressure, temperature and flu id (water and gas) and solid (hydrate and ice) phase saturati ons. Fluid and solid phases may coexist, which, coupled with steep temp erature and pressure gradients, result in strong nonlinear ities in the coupled flow and mechanics processes, making the descriptio n of system behavior in dissociating hydrate deposits excep tionally complicated. In previous studies, the geological stability of hydrate-b earing sediments was investigated using one-way coupled an alysis, in which the changes in fluid properties affect mechanics wit hin he gas hydrate reservoirs, but with no feedback from geo mechanics to fluid flow. In this paper, we develop and test a rigor ous two-way coupling between fluid flow and geomechanics, in which the solutions from mechanics are reflected in the sol ution of the flow problem through the adjustment of affected hydraulic properties. We employ the fixed-stress split meth od, which results in a convergent sequential implicit schem e. In this study of several hydrate reservoir cases, we find noti ceable differences between the results based on oneand two way couplings. The nature of the elliptic boundary value pro blem of quasi-static mechanics results in instantaneous co mpaction or dilation over the domain, through loading from reservoir fluid production. This induces a pressure rise or drop at earl y times (low pressure diffusion), and consequently changes the eff ective stress instantaneously, possibly causing geologic al instability. Additionally, the pressure and temperature regime affects the various phase saturations, the rock stiffness, porosit y, and permeability, thus affecting the fluid flow regime. These changes a re not captured accurately by the simpler one-way coupling. The tightly coupled sequential approach we propose provides a r igorous, two-way coupling model that captures the interrel ationship between geomechanical and flow properties and processes, ac curately describes the system behavior, and can be readily a pp ied to large-scale problems of hydrate behavior in geologic med ia. Introduction Background. The interrelationship between fluid flow through porous medi a and the geomechanical status of the system is controlled by the properties of the specifics of flow, various phases present in the pores (e.g., gas, aqueous, oil/organi c, ice, etc.) and of the solid system (i.e., the individual grains of the ge ologic medium and the reservoir skeleton). Under certain co nditions, the interrelationship is strong, and coupling of the flow pro cesses with geomechanics is necessary to accurately descri be the system behavior. In such cases, changes in pressure brought abo ut by flow (e.g., in the process of fluid production from reserv oirs) alter the stress fields, resulting in changes in porosity and permeability, and potentially leading to yielding, failur es and fracture evolution or closures; these processes can in turn affect th flow behavior of the entire system. Reservoir engineering i s replete with examples of such strongly coupled flow-geomechanics pr ocesses with a significant impact on production and economic consequences: stability of borehole and surface facilitie s, hydraulic fracturing for fluid production from low-perme ability reservoirs, reservoir compaction (especially in highly compres sible systems) and land surface subsidence, sand productio n during reservoir fluid production from unconsolidated or unstable formation, system responses during geologic CO2 sequestration, gas production from hydrate accumulations, etc. see Baghe ri and Settari (2008), Merle et al. (1976), Lewis and Schrefle (1998), Kosloff et al. (1980), Freeman et al. (2009), Rutqvi st et al. (2010b), and Rutqvist and Moridis (2009). Hydrate reservoirs are considered as potentially substant ial fu ure energy resources (Moridis, 2003; Moridis et al., 2009a, 2011) because of the vast quantities of hydrocarbon gas (mai nly CH4) they trap (Sloan and Koh, 2008). Hydrate deposits that are desirable gas production targets almost invariabl y involve coarse, unlithified, unconsolidated media (such a s s nds and gravels). In such deposits, it is the hydrate that impart s mechanical strength to the medium, and hydrate dissociati n for gas production drastically changes the geomechanical stat us of the system. Additionally, the system undergoes signifi cant temperature changes because dissociation is a strongly end othermic reaction. Thus, fluid flow, heat transport and geome chanics are inexorably intertwined and need to be considered togeth er as strongly coupled processes in hydrate accumulations u nder production because the inevitable significant changes in pr essureP , temperatureT and saturationsSJ of the various phases J (aqueous, gas, hydrate, ice) during dissociation directly affect the stiffness of the solid skeleton and the stress and strain fields, resulting in deformation of the reservoirs and poten tially large changes in the porosity and permeability (Rutq vist and Moridis, 2009; Rutqvist et al., 2009). Thus, in the study of g as production from hydrate deposits, the geomechanical sta bi ity and integrity of both the hydrate-bearing sediments (HBS) a nd the wellbore need to be considered. Gas hydrates are solid crystalline compounds in which gas mo lecules are trapped within the lattice of ice crystals (Mori dis, 2003). Trapped gases and the ice crystals are called gu stsandhosts, respectively. Given the availability of appropriate gas sources, hydrates evolve according to the exothermic equat ion G + NH H2O = G · NH H2O + QH , (1)

Development of the T+M coupled flow-geomechanical simulator to describe fracture propagation and coupled flow-thermal-geomechanical processes in tight/shale gas systems

We developed a hydraulic fracturing simulator by coupling a flow simulator to a geomechanics code, namely T+M simulator. Modeling of the vertical fracture development involves continuous updating of the boundary conditions and of the data connectivity, based on the finite element method for geomechanics. The T+M simulator can model the initial fracture development during the hydraulic fracturing operations, after which the domain description changes from single continuum to double or multiple continua in order to rigorously model both flow and geomechanics for fracture-rock matrix systems. The T+H simulator provides two-way coupling between fluid-heat flow and geomechanics, accounting for thermo-poro-mechanics, treats nonlinear permeability and geomechanical moduli explicitly, and dynamically tracks changes in the fracture(s) and in the pore volume. We also fully account for leak-off in all directions during hydraulic fracturing. We first test the T+M simulator, matching numerical solutions with the analytical solutions for poromechanical effects, static fractures, and fracture propagations. Then, from numerical simulation of various cases of the planar fracture propagation, shear failure can limit the vertical fracture propagation of tensile failure, because of leak-off into the reservoirs. Slow injection causes more leak-off, compared with fast injection, when the same amount of fluid is injected. Changes in initial total stress and contributions of shear effective stress to tensile failure can also affect formation of the fractured areas, and the geomechanical responses are still well-posed.

Numerical Studies on Two-Way Coupled Fluid Flow and Geomechanics in Hydrate Deposits

Numerical Studies on Two-way Coupled Fluid Flow and Geomechanics in Hydrate Deposits J. Kim, SPE; G. J. Moridis, SPE; Lawrence Berkeley National Laboratory; D. Yang, SPE, Texas AM J. Rutqvist, SPE, Lawrence Berkeley National Laboratory Abstract Coupled flow and geomechanics play an important role in the analysis of gas hydrate reservoirs under production. The stiffness of the rock skeleton and the deformation of the reservoir, as well as porosity and permeability, are directly influenced by (and interrelated with) changes in pressure, temperature and fluid (water and gas) and solid (hydrate and ice) phase saturations. Fluid and solid phases may coexist, which, coupled with steep temperature and pressure gradients, result in strong nonlinearities in the coupled flow and mechanics processes, making the description of system behavior in dissociating hydrate deposits exceptionally complicated. In previous studies, the geological stability of hydrate-bearing sediments was investigated using one-way coupled analysis, in which the changes in fluid properties affect mechanics within the gas hydrate reservoirs, but with no feedback from geome- chanics to fluid flow. In this paper, we develop and test a rigorous two-way coupling between fluid flow and geomechanics, in which the solutions from mechanics are reflected in the solution of the flow problem through the adjustment of affected hydraulic properties. We employ the fixed-stress split method, which results in a convergent sequential implicit scheme. In this study of several hydrate reservoir cases, we find noticeable differences between the results based on one- and two- way couplings. The nature of the elliptic boundary value problem of quasi-static mechanics results in instantaneous compaction or dilation over the domain, through loading from reservoir fluid production. This induces a pressure rise or drop at early times (low pressure diffusion), and consequently changes the effective stress instantaneously, possibly causing geological instability. Additionally, the pressure and temperature regime affects the various phase saturations, the rock stiffness, porosity, and perme- ability, thus affecting the fluid flow regime. These changes are not captured accurately by the simpler one-way coupling. The tightly coupled sequential approach we propose provides a rigorous, two-way coupling model that captures the interrelationship between geomechanical and flow properties and processes, accurately describes the system behavior, and can be readily applied to large-scale problems of hydrate behavior in geologic media. Introduction Background. The interrelationship between fluid flow through porous media and the geomechanical status of the system is controlled by the properties of the specifics of flow, various phases present in the pores (e.g., gas, aqueous, oil/organic, ice, etc.) and of the solid system (i.e., the individual grains of the geologic medium and the reservoir skeleton). Under certain conditions, the interrelationship is strong, and coupling of the flow processes with geomechanics is necessary to accurately describe the sys- tem behavior. In such cases, changes in pressure brought about by flow (e.g., in the process of fluid production from reservoirs) alter the stress fields, resulting in changes in porosity and permeability, and potentially leading to yielding, failures and fracture evolution or closures; these processes can in turn affect the flow behavior of the entire system. Reservoir engineering is replete with examples of such strongly coupled flow-geomechanics processes with a significant impact on production and economic consequences: stability of borehole and surface facilities, hydraulic fracturing for fluid production from low-permeability reser- voirs, reservoir compaction (especially in highly compressible systems) and land surface subsidence, sand production during reservoir fluid production from unconsolidated or unstable formation, system responses during geologic CO 2 sequestration, gas production from hydrate accumulations, etc. - see Bagheri and Settari (2008), Merle et al. (1976), Lewis and Schrefler (1998), Kosloff et al. (1980), Freeman et al. (2009), Rutqvist et al. (2010b), and Rutqvist and Moridis (2009). Hydrate reservoirs are considered as potentially substantial future energy resources (Moridis, 2003; Moridis et al., 2009a, 2011) because of the vast quantities of hydrocarbon gas (mainly CH 4 ) they trap (Sloan and Koh, 2008). Hydrate deposits that are desirable gas production targets almost invariably involve coarse, unlithified, unconsolidated media (such as sands and gravels). In such deposits, it is the hydrate that imparts mechanical strength to the medium, and hydrate dissociation for gas production drastically changes the geomechanical status of the system. Additionally, the system undergoes significant temperature changes because dissociation is a strongly endothermic reaction. Thus, fluid flow, heat transport and geomechanics are inexorably intertwined and need to be considered together as strongly coupled processes in hydrate accumulations under production because the inevitable significant changes in pressure P , temperature T and saturations S J of the various phases J (aqueous, gas, hydrate, ice) during dissociation directly affect the stiffness of the solid skeleton and the stress and strain fields, resulting in deformation of the reservoirs and potentially large changes in the porosity and permeability (Rutqvist and Moridis, 2009; Rutqvist et al., 2009). Thus, in the study of gas production from hydrate deposits, the geomechanical stability and integrity of both the hydrate-bearing sediments (HBS) and the wellbore need to be considered. Gas hydrates are solid crystalline compounds in which gas molecules are trapped within the lattice of ice crystals (Moridis, 2003). Trapped gases and the ice crystals are called guests and hosts, respectively. Given the availability of appropriate gas sources, hydrates evolve according to the exothermic equation G + N H H 2 O = G · N H H 2 O + Q H ,

Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight- and Shale-Gas Reservoirs: Material Failure and Enhanced Permeability

We investigate coupled flow and geomechanics in gas production from extremely low permeability reservoirs such as tight and shale gas reservoirs, using dynamic porosity and permeability during numerical simulation. In particular, we take the intrinsic permeability as a step function of the status of material failure, and the permeability is updated every time step. We consider gas reservoirs with the vertical and horizontal primary fractures, employing the single and dynamic double porosity (dual continuum) models. We modify the multiple porosity constitutive relations for modeling the double porous continua for flow and geomechanics. The numerical results indicate that production of gas causes redistribution of the effective stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs not only near the fracture tips but also away from the primary fractures, which indicates generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which in turn causes a change in distribution of geomechanical variables. From various numerical tests, we find that shear failure is enhanced by a large pressure drop at the production well, high Biots coefficient, low frictional and dilation angles. Smaller spacing between the horizontal wells also contributes to faster secondarymorexa0» fracturing. When the dynamic double porosity model is used, we observe a faster evolution of the enhanced permeability areas than that obtained from the single porosity model, mainly due to a higher permeability of the fractures in the double porosity model. These complicated physics for stress sensitive reservoirs cannot properly be captured by the uncoupled or flow-only simulation, and thus tightly coupled flow and geomechanical models are highly recommended to accurately describe the reservoir behavior during gas production in tight and shale gas reservoirs and to smartly design production scenarios.«xa0less

Fracture Propagation, Fluid Flow, and Geomechanics of Water-Based Hydraulic Fracturing in Shale Gas Systems and Electromagnetic Geophysical Monitoring of Fluid Migration

Author(s): Kim, Jihoon; Um, Evan; Moridis, George | Abstract: We investigate fracture propagation induced by hydraulic fracturing with water injection, using numerical simulation. For rigorous, full 3D modeling, we employ a numerical method that can model failure resulting from tensile and shear stresses, dynamic nonlinear permeability, leak-off in all directions, and thermo-poro-mechanical effects with the double porosity approach. Our numerical results indicate that fracture propagation is not the same as propagation of the water front, because fracturing is governed by geomechanics, whereas water saturation is determined by fluid flow. At early times, the water saturation front is almost identical to the fracture tip, suggesting that the fracture is mostly filled with injected water. However, at late times, advance of the water front is retarded compared to fracture propagation, yielding a significant gap between the water front and the fracture top, which is filled with reservoir gas. We also find considerable leak-off of water to the reservoir. The inconsistency between the fracture volume and the volume of injected water cannot properly calculate the fracture length, when it is estimated based on the simple assumption that the fracture is fully saturated with injected water. As an example of flow-geomechanical responses, we identify pressure fluctuation under constant water injection, because hydraulic fracturing is itself a set of many failure processes, in which pressure consistently drops when failure occurs, but fluctuation decreases as the fracture length grows. We also study application of electromagnetic (EM) geophysical methods, because these methods are highly sensitive to changes in porosity and pore-fluid properties due to water injection into gas reservoirs. Employing a 3D finite-element EM geophysical simulator, we evaluate the sensitivity of the crosswell EM method for monitoring fluid movements in shaly reservoirs. For this sensitivity evaluation, reservoir models are generated through the coupled flow-geomechanical simulator and are transformed via a rock-physics model into electrical conductivity models. It is shown that anomalous conductivity distribution in the resulting models is closely related to injected water saturation, but not closely related to newly created unsaturated fractures. Our numerical modeling experiments demonstrate that the crosswell EM method can be highly sensitive to conductivity changes that directly indicate the migration pathways of the injected fluid. Accordingly, the EM method can serve as an effective monitoring tool for distribution of injected fluids (i.e., migration pathways) during hydraulic fracturing operations

Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight and Shale Gas Reservoirs: Material Failure and Enhanced Permeability

Author(s): Kim, Jihoon; Moridis, George | Abstract: We investigate coupled flow and geomechanics in gas production from extremely low permeability reservoirs such as tight and shale gas reservoirs, using dynamic porosity and permeability during numerical simulation. In particular, we take the intrinsic permeability as a step function of the status of material failure, and the permeability is updated every time step. We consider gas reservoirs with the vertical and horizontal primary fractures, employing the single and dynamic double porosity (dual continuum) models. We modify the multiple porosity constitutive relations for modeling the double porous continua for flow and geomechanics. The numerical results indicate that production of gas causes redistribution of the effective stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs not only near the fracture tips but also away from the primary fractures, which indicates generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which in turn causes a change in distribution of geomechanical variables. From various numerical tests, we find that shear failure is enhanced by a large pressure drop at the production well, high Biots coefficient, low frictional and dilation angles. Smaller spacing between the horizontal wells also contributes to faster secondary fracturing. When the dynamic double porosity model is used, we observe a faster evolution of the enhanced permeability areas than that obtained from the single porosity model, mainly due to a higher permeability of the fractures in the double porosity model. These complicated physics for stress sensitive reservoirs cannot properly be captured by the uncoupled or flow-only simulation, and thus tightly coupled flow and geomechanical models are highly recommended to accurately describe the reservoir behavior during gas production in tight and shale gas reservoirs and to smartly design production scenarios.

Rigorous Coupling of Geomechanics and Multiphase Flow with Strong Capillarity

We study sequential formulations for coupled multiphase flow and reservoir geomechanics. First, we identify the proper definition of effective stress in multiphase-fluid systems. Although the average pore-pressure p—defined as the sum of the product of saturation and pressure of all the fluid phases that occupy the pore space—is commonly used to describe multiphase-fluid flow in deformable porous media, it can be shown that the “equivalent” pore pressure pE —defined as p minus the interfacial energy—is the appropriate quantity (Coussy 2004). We show, by means of a fully implicit analysis of the system, that only the equivalent pore pressure pE leads to a continuum problem that is thermodynamically stable (thus, numerical discretizations on the basis of the average pore pressure p cannot render unconditionally stable and convergent schemes). We then study the convergence and stability properties of sequentialimplicit coupling strategies. We show that the stability and convergence properties of sequential-implicit coupling strategies for single-phase flow carry over for multiphase systems if the equivalent pore pressure pE is used. Specifically, the undrained and fixed-stress schemes are unconditionally stable, and the fixed-stress split is superior to the undrained approach in terms of convergence rate. The findings from stability theory are verified by use of nonlinear simulations of two-phase flow in deformable reservoirs.