Showing papers by "George J. Moridis published in 2015"
TL;DR: In this article, a case in which a horizontal injection well intersects a steeply dipping fault, with hydraulic fracturing channeled within the fault, during a 3-h hydraulic fracturing stage was simulated, and the authors showed that the rupture zone associated with tensile and shear failure extended to a maximum radius of about 200m from the injection well.
128 citations
TL;DR: In this article, the authors performed numerical studies on vertical fracture propagation induced by tensile hydraulic fracturing for shale gas reservoirs and found that fracture propagation is sensitive to factors such as initial condition of saturation, a type of the injection fluid, heterogeneity, tensile strength, elastic moduli, and permeability models.
107 citations
TL;DR: This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, and concludes that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature.
Abstract: Hydrocarbon production from unconventional resources and the use of reservoir stimulation techniques, such as hydraulic fracturing, has grown explosively over the last decade. However, concerns have arisen that reservoir stimulation creates significant environmental threats through the creation of permeable pathways connecting the stimulated reservoir with shallower freshwater aquifers, thus resulting in the contamination of potable groundwater by escaping hydrocarbons or other reservoir fluids. This study investigates, by numerical simulation, gas and water transport between a shallow tight-gas reservoir and a shallower overlying freshwater aquifer following hydraulic fracturing operations, if such a connecting pathway has been created. We focus on two general failure scenarios: (1) communication between the reservoir and aquifer via a connecting fracture or fault and (2) communication via a deteriorated, preexisting nearby well. We conclude that the key factors driving short-term transport of gas include high permeability for the connecting pathway and the overall volume of the connecting feature. Production from the reservoir is likely to mitigate release through reduction of available free gas and lowering of reservoir pressure, and not producing may increase the potential for release. We also find that hydrostatic tight-gas reservoirs are unlikely to act as a continuing source of migrating gas, as gas contained within the newly formed hydraulic fracture is the primary source for potential contamination. Such incidents of gas escape are likely to be limited in duration and scope for hydrostatic reservoirs. Reliable field and laboratory data must be acquired to constrain the factors and determine the likelihood of these outcomes.
99 citations
TL;DR: In this paper, the authors use the massively parallel Tough+HYDRATE code (pT+H) to assess the production potential of a large, deep ocean hydrate reservoir and develop strategies for effective production.
Abstract: The quantity of hydrocarbon gases trapped in natural hydrate accumulations is enormous, leading to a significant interest in the evaluation of their potential as an energy source. It has been shown that large volumes of gas can be readily produced at high rates for long times from some types of methane hydrate accumulations by means of depressurization-induced dissociation, and using conventional horizontal or vertical well configurations. However, these resources are currently assessed using simplified or reduced-scale 3D or 2D production simulations. In this study, we use the massively parallel TOUGH+HYDRATE code (pT+H) to assess the production potential of a large, deep ocean hydrate reservoir and develop strategies for effective production. The simulations model a full 3D system of over $$38\hbox { km}^{2}$$
extent, examining the productivity of vertical and horizontal wells, single or multiple wells, and explore variations in reservoir properties. Systems of up to 2.5 M gridblocks, running on thousands of supercomputing nodes, are required to simulate such large systems at the highest level of detail. The simulations reveal the challenges inherent in producing from deep, relatively cold systems with extensive water-bearing channels and connectivity to large aquifers, mainly difficulty of achieving depressurization and the problem of enormous water production. Also highlighted are new frontiers in large-scale reservoir simulation of coupled flow, transport, thermodynamics, and phase behavior, including the construction of large meshes and the computational scaling of larger systems.
70 citations
28 Sep 2015
TL;DR: In this paper, a random walk fracture model was proposed to capture the complexity of a fracture/fracture network and to characterize this fracture network using reservoir performance signatures. But, the authors did not consider the effect of the number of branching stages on fracture performance.
Abstract: This study introduces a novel approach to model the hydraulic fractures in a shale reservoir using a common stochastic method called “random-walk.” The goal of this work is to capture part of the “complexity” of a fracture/fracture network that has been generated by a hydraulic fracturing treatment and to attempt to characterize this fracture network using reservoir performance signatures. The steps involved in this work are: ● Stochastic generation of a “random-walk” fracture pattern constructed as a scaled numerical model. ● Assessment of the “random-walk” fracture using sensitivity analyses which consider the following elements: — The tortuosity (i.e., the actual length to ideal length ratio) — The tendency to branch (or split). — The number of branching stages — the number of branches was held constant for a given set of cases. ● Comparison of the mass rate and beta mass rate-derivative performance of the various “randomwalk” fracture cases compared to the “standard” model of a planar fracture. The primary results of this work are: ● Generation of pressure distributions (maps) at given times (i.e., “time slices”) to qualitatively assess each complex-pattern during transient production. The pressure distribution figures (i.e., maps) are used to qualitatively determine the presence of fracture interference(s) and to identify a time interval where those interferences occur. ● Creation of a graphical correlation of reservoir performance in terms of cumulative recovery as a function of the fracture volume and “fracture complexity” (i.e., the number of branches). ● Creation of an empirical correlation between the number of branches in a given fracture pattern and the value of the mass rate beta-derivative during transient flow (we observed that the mass rate beta-derivative is essentially constant during transient flow regardless of the fracture network configuration, as such this constant value of the mass rate beta-derivative was selected for correlation). This work provides an alternative description of hydraulic fractures in unconventional shale-gas reservoirs which, in concept, captures the complexity of the hydraulic fracture as a stochastic fracture network. Early-time rate performance is believed to be an indicator of the geometry of the hydraulic fracture pattern. A fracture with a higher level of “complexity” yields higher values of mass rate beta-derivative when the fractures components are interfering with each other. Therefore, mass rate curves could be used as a diagnostic tool that helps the identification of the fracture geometric features.
10 citations
23 Feb 2015
TL;DR: Lee et al. as discussed by the authors extended the Texas AaM Flow and Transport Simulator (FTSim) with a fully functional capability that describes kerogen pyrolysis and accompanying system changes.
Abstract: Author(s): Lee, K; Moridis, GJ; Ehlig-Economides, CA | Abstract: Oil shale, which is composed of abundant organic matter called kerogen, is a vast energy source. Pyrolysis of kerogen in oil shales releases recoverable hydrocarbons. Here, we describe the pyrolysis of kerogen with an in-situ upgrading process, which is applicable to the majority of oil shales. The pyrolysis is represented by six kinetic reactions resulting in 10 components and four phases. Expanding the Texas AaM Flow and Transport Simulator (FTSim), which is a variant of the TOUGH +simulator (Moridis 2014), we develop a fully functional capability that describes kerogen pyrolysis and accompanying system changes. The simulator describes the coupled process of mass transport and heat flow through porous and fractured media and includes physical and chemical phenomena of reservoir systems. The simulator involves a total of 15 thermophysical states and all transitions between them and computes a simultaneous solution of 11 mass- and energy-balance equations per element. The simulator solves the equations in a fully implicit manner by solving Jacobian matrix equations with the Newton-Raphson iteration method. To conduct a realistic simulation, we account for geological structure of oil-shale reservoirs and physical properties of bulk-oil shale rocks by considering phases and components in the pores. In addition, we involve interaction between fluids and porous media, diverse equations of state (EOSs) for computation of fluid properties, and numerical modeling of fractured media. We intensively reproduce the field-production data of Shell Insitu Conversion Process (ICP) implemented in the Green River formation by conducting sensitivity analyses for the diverse reservoir parameters, such as initial effective porosity of the matrix, oil-shale grade, and the spacing of the natural-fracture network. We analyze the effect of each reservoir parameter on the hydrocarbon productivity and product selectivity. The simulator provides a powerful tool to quantitatively evaluate production behavior and dynamic-system changes during in-situ upgrading of oil shales and subsequent fluid production by thoroughly describing a reservoir model, phases and components, phase behavior, phase properties, and evolution of porosity and permeability.
9 citations
TL;DR: The TOUGH family of numerical simulators as discussed by the authors is a family of models designed for the simulation of a wide range of coupled processes that include in their simplest realization the transport of fluids and heat in porous and/or fractured geologic media.
Abstract: This Special Issue of Transport in Porous Media features selected papers from the 2012 TOUGH Symposium, which took place on September 17–19, 2012, in Berkeley, California, USA. Such symposia are held every 3years and are a forum where users of the TOUGH family of numerical simulatorsmeet for an open exchange on the code applications and recent enhancements. The acronym “TOUGH” stands for “Transport of Unsaturated Groundwater and Heat” and reflects the original geothermal focus of the code, which has over the years expanded into a family of multi-dimensional, multi-component models that are designed for the simulation of a wide range of coupled processes that include in their simplest realization the transport of fluids and heat in porous and/or fractured geologic media, and extend to a wide range more complex coupled processes such as chemical, geomechanical, geophysical, etc. Since its first release in 1987 by a team of researchers at the Lawrence Berkeley National Laboratory headed by Karsten Pruess, the TOUGH family has been enriched by a large number of modules that describe a variety of important Equations-Of-State (EOS, involving various mass components), and has evolved to include several derivatives and descendants (e.g., EOS modules for multi-component volatile organic compounds; decay chains of multiple radionuclides, gas hydrates, tight and shale gas behavior, and supercritical CO2; modules for coupledmulti-phase flowand reactive transport, and coupled thermo-hydrologicmechanical processes; inverse modeling for parameter estimation, sensitivity analysis, and uncertainty quantification; parallelization formulti-core PCs,workstation clusters, and supercomputers, etc). The TOUGH family of codes is currently used to address a wide spectrum of problems, which includes applications to geothermal reservoir engineering, nuclear waste disposal in geologic formations, geologic carbon sequestration, vadose zone hydrology, environmental remediation, oil and gas reservoir engineeringwith an emphasis on unconventional resources (such as hydrates, tight and shale gas and oil), and other coupledmass transport and
1 citations