Showing papers by "George J. Moridis published in 2014"

Numerical Predictions of Experimentally Observed Methane Hydrate Dissociation and Reformation in Sandstone

Abstract: Numerical tools are essential for the prediction and evaluation of conventional hydrocarbon reservoir performance. Gas hydrates represent a vast natural resource with a significant energy potential. The numerical codes/tools describing processes involved during the dissociation (induced by several methods) for gas production from hydrates are powerful, but they need validation by comparison to empirical data to instill confidence in their predictions. In this study, we successfully reproduce experimental data of hydrate dissociation using the TOUGH+HYDRATE (T+H) code. Methane (CH4) hydrate growth and dissociation in partially water- and gas-saturated Bentheim sandstone were spatially resolved using Magnetic Resonance Imaging (MRI), which allows the in situ monitoring of saturation and phase transitions. All the CH4 that had been initially converted to gas hydrate was recovered during depressurization. The physical system was reproduced numerically, using both a simplified 2D model and a 3D grid involving ...

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

Abstract: 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

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 Biot's coefficient, low frictional and dilation angles. Smaller spacing between the horizontal wells also contributes to faster secondarymore » 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.« less

Effect of Confinement on PVT Properties of Hydrocarbons in Shale Reservoirs

Abstract: Shale reservoirs play an important role as a future energy resource of the United States. Numerous studies have been performed to describe the storage and transport of hydrocarbons through ultra-small pores in the shale reservoirs. Most of these studies were developed by modifying techniques used for conventional reservoirs. The common pore size distribution of the shale reservoirs is approximately 1-20 nm and in such confined spaces the interactions between the wall of the container (i.e., the shale and kerogen) and the contained fluids (i.e., the hydrocarbon fluids and water) may exert significant influence on the localized phase behavior. We believe this is due to the fact that the orientation and distribution of fluid molecules in the confined space are different from those of the bulk fluid; causing changes in the localized thermodynamic properties. This study provides a detailed account of the changes of PVT properties and phase behavior (specifically, the phase diagrams) in a synthetic shale reservoir for pure hydrocarbons (methane and ethane) and a simple methane-ethane (binary) mixture. Grand Canonical Monte Carlo (GCMC) simulations are performed to study the effect of confinement on the fluid properties. A graphite slab made of two layers is used to represent kerogen in the shale reservoirs. The separation between the two layers, representing a kerogen pore, is varied from 1 nm to 10 nm to observe the changes of the hydrocarbon fluid properties. In this paper, the critical properties of methane and ethane as well as the methane-ethane mixture phase diagrams in different pore sizes are derived from the GCMC simulations. In addition, the GCMC simulations are used to investigate the deviations of the fluid densities in the confined space from those of the bulk fluids at reservoirs conditions. While not investigated in this work, such deviations may indicate that significant errors for production forecasting and reserve estimation in shale reservoirs may occur if the (typical) bulk densities are used in reservoir engineering calculations.

Krauklis wave in a trilayer

Abstract: The Krauklis wave is a slow dispersive wave mode that propagates in a fluid layer bounded by elastic media. The guided properties of this wave and its ability to generate very short wavelengths at seismic frequency range predict possibility of resonances in fluid-filled rock fractures. Study of Krauklis wave properties at laboratory scales requires evaluation of its propagation velocities in models with finite and thin elastic walls. Analysis of an exact solution for a fluid-filled trilayer with equal thickness plates reveals existence of the Krauklis waves in such a model, as well as another mode which propagates mostly in the solid part. Both propagation modes exist at all frequencies. We derived and verified various asymptotic solutions by comparing their dependencies on layer thicknesses and frequency with the exact numerical solution. Analytical and computational results demonstrate that in a 60-cm-long model, the first resonant frequency can be below 10 Hz. This result suggests that the Krau...

Evaluation of Well Performance for the Slot-Drill Completion in Low- and Ultralow-Permeability Oil and Gas Reservoirs

Abstract: Lowto ultralow-permeability formations require “special” treatments/stimulation to make them produce economical quantities of hydrocarbon, and at the moment, multistage hydraulic fracturing (MSHF) is the most commonly used stimulation method for enhancing the exploitation of these reservoirs. Recently, the slotdrill (SD) completion technique was proposed as an alternative treatment method in such formations (Carter 2009). This paper documents the results of a comprehensive numerical-simulation study conducted to evaluate the production performance of the SD technique and compare its performance to that of the standard MSHF approach. We investigated three lowpermeability formations of interest—namely, a shale-gas formation, a tight-gas formation, and a tight/shale-oil formation. The simulation domains were discretized with Voronoi-gridding schemes to create representative meshes of the different reservoir and completion systems modeled in this study. The results from this study indicated that the SD method does not, in general, appear to be competitive in terms of reservoir performance and recovery compared with the more traditional MSHF method. Our findings indicate that the larger surface area to flow that results from the application of MSHF is much more significant than the higher conductivity achieved by use of the SD technique. However, there may exist cases, for example, a lack of adequate water volumes for hydraulic fracturing, or very high irreducible water saturation that leads to adverse relative permeability conditions and production performance, in which the lowcost SD method may make production feasible from an otherwise challenging (if not inaccessible) resource.

Evaluation of Strategies for Enhancing Production of Low-Viscosity Liquids From Tight/Shale Reservoirs

Abstract: Production of low-viscosity liquids (including condensates) from tight reservoirs (such as shales) is severely restricted by the ultra low-permeability of such formations, limiting production to a very small fraction (usually less than 5 percent) of the liquids-in-place. In this study, which is part of a wider investigation, we evaluate by means of numerical simulation several possible strategies to enhance low-viscosity liquids production from such reservoirs. These strategies include (a) physical displacement processes, (b) non-thermal processes to reduce the viscosity and the critical saturation of the liquids, (c) thermal processes, (d) enhanced reservoir stimulation, (e) novel well configurations and (f) combinations thereof. The objectives of this effort are to (1) to remove from further consideration potential production strategies that hold limited (if any) promise, and (2) to identify production strategies that appear to have potential for further study and development. We first determine the baseline production performance of such reservoirs corresponding to several reference production regimes that involve minimal or no reservoir stimulation, standard displacement fluids (H2O or CH4), standard well configurations and no thermal treatment. We then evaluate the efficiency of several production strategies: (a) traditional continuous gas flooding using parallel horizontal wells and using the currently abundant shale gas, (b) water-alternating-gas (WAG) flooding, (c) huffand-puff injection/production strategies using lean gas/rich gas in a traditional (single) horizontal well with multiple fractures, (d) flooding using appropriate gases (e.g., CO2, N2, CH4) using appropriate well configurations (mainly horizontal), with the viscosity reduction resulting from the gas dissolution into the liquids, and (e) thermal processes, in which the viscosity reduction is achieved by heating, possibly to the point of liquid vaporization and transport through the matrix to the production wells as a gas. Our study includes an analysis of the sensitivity of the liquids production to the main parameters defining each of the strategies listed above in an effort to determine the critically important parameters and factors that control the production performance and efficiency.