In situ upgrading of oil shale by Steamfrac in multistage transverse fractured horizontal well system

We conduct numerical simulations of kerogen pyrolysis by the in situ upgrading process of Steamfrac, which entails the steam or hot-water injection into multistage transverse fractured horizontal well systems, by using a fully functional simulator developed to describe the in situ upgrading process. We first conduct simulation cases of a huff-n-puff method to analyze the sensitivity of temperature distribution of the reservoir to the positions of horizontal wells. Then, we conduct continuous hot-water injection and simultaneous fluid production cases, and analyze the productivity by applying two different irreducible saturations of aqueous phase in the rock matrix

A comprehensive simulation model of kerogen pyrolysis for the in-situ upgrading of oil shales

Oil shale, which comprises 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 using 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 Texas A&M Flow and Transport Simulator (TAMU FTSim), which is a variant of TOUGH + simulator (Moridis and Freeman 2014), we develop a fully functional capability that describes kerogen pyrolysis and accompanying system changes with a minimum of simplifications and assumptions. The simulator describes coupled process of mass transport and heat flow through porous and fractured media and includes all known physics and chemistry 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 using 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 rock. In addition, we consider interaction between fluids and porous media, diverse equations of state for computation of fluid properties, and numerical modeling of fractured media. We intensively validate the simulator by reproducing the field production data from Shell In-situ Conversion Process implemented in Green River Formation. We conduct sensitivity analyses of diverse reservoir parameters, such as presence or absence of a pre-existing fracture system, oil shale grade, permeability of the pre-existing fracture system, and thermal conductivity of a reservoir formation. We analyze the effects of the reservoir parameters on productivity and find a model that shows a similar production rate curve to the field production. The simulator is successfully validated and provides a powerful tool to evaluate effectiveness of in-situ upgrading processes and corresponding amount of recoverable hydrocarbons

In situ upgrading of oil shale by Steamfrac in multistage transverse fractured horizontal well system

We conduct numerical simulations of kerogen pyrolysis by the in situ upgrading process of Steamfrac, which entails the steam or hot-water injection into multistage transverse fractured horizontal well systems, by using a fully functional simulator developed to describe the in situ upgrading process. We first conduct simulation cases of a huff-n-puff method to analyze the sensitivity of temperature distribution of the reservoir to the positions of horizontal wells. Then, we conduct continuous hot-water injection and simultaneous fluid production cases, and analyze the productivity by applying two different irreducible saturations of aqueous phase in the rock matrix

Numerical simulation of diverse thermal in situ upgrading processes for the hydrocarbon production from kerogen in oil shale reservoirs

We investigate the productivity and product selectivity of diverse thermal in situ upgrading processes in oil shale reservoirs. In situ upgrading processes applying the ideas of Shell In situ Conversion Process, ExxonMobil Electrofrac, and Texas A&M Steamfrac are simulated by using sector models with the assumption of symmetric patterns. In-house fully functional simulator is used, which has been developed for the kerogen pyrolysis and hydrocarbon production. In the simulation cases, sensitivity analyses to the factors having major influence on the productivity and product selectivity are conducted. The effects of the temperature of vertical heaters, the spacing of hydraulic fractures, and the position of horizontal production wells are analyzed in the applied In situ Conversion Process, Electrofrac, and Steamfrac, respectively. In the applied In situ Conversion Process cases, hydrocarbon production increases with the increasing heater temperature. In the applied Electrofrac cases, hydrocarbon production increases with the increasing spacing of hydraulic fractures, even though longer time period for the process is needed. In the applied Steamfrac cases, the case of production well located at the same depth to the injection well shows the least hydrocarbon production. Among the processes, the applied In situ Conversion Process cases show the highest weight percentage of total hydrocarbon components in the produced fluid, and the applied Electrofrac cases follow it. The applied Steamfrac cases show far lower weight percentage of hydrocarbon production than the other methods. In terms of the mass ratio of produced hydrocarbon to decomposed kerogen, the applied Steamfrac cases show the largest value among the processes by aqueous phase sweeping liquid organic phase, but they also show the huge water oil mass ratio by the continuous injection of hot water. All the applied In situ Conversion Process cases and the Electrofrac case with the short spacing of hydraulic fractures show good heating efficiency by decomposing whole kerogen in the system

Compositional simulation of hydrocarbon recovery from oil shale reservoirs with diverse initial saturations of fluid phases by various thermal processes

We have studied the hydrocarbon production from oil shale reservoirs filled with diverse initial saturations of fluid phases by implementing numerical simulations of various thermal in-situ upgrading processes. We use our in-house fully functional, fully implicit, and non-isothermal simulator, which describes the in-situ upgrading processes and hydrocarbon recovery by multiphase-multicomponent systems. We have conducted two sets of simulation cases—five-spot well pattern problems and Shell In-situ Conversion Process (ICP) problems. In the five-spot well pattern problems, we have analyzed the effects of initial fluid phase that fills the single-phase reservoir and thermal processes by four cases—electrical heating in the single-phase-aqueous reservoir, electrical heating in the single-phase-gaseous reservoir, hot water injection in the single-phase-aqueous reservoir, and hot CO2 injection in the single-phase-gaseous reservoir. In the ICP problems, we have analyzed the effects of initial saturations of fluid phases that fill two-phase-aqueous-and-gaseous reservoir by three cases—initial aqueous phase saturations of 0.16, 0.44, and 0.72. Through the simulation cases, system response and production behavior including temperature profile, kerogen fraction profile, evolution of effective porosity and absolute permeability, phase production, and product selectivity are analyzed. In the five-spot well pattern problems, it is found that the hot water injection in the aqueous phase reservoir shows the highest total hydrocarbon production, but also shows the highest water-oil-mass-ratio. Productions of phases and components show very different behavior in the cases of electrical heating in the aqueous phase reservoir and the gaseous phase reservoir. In the ICP problems, it is found that the speed of kerogen decomposition is almost identical in the cases, but the production behavior of phases and components is very different. It is found that more liquid organic phase has been produced in the case with the higher initial saturation of aqueous phase by the less production of gaseous phase

A comprehensive simulation model of kerogen pyrolysis for the in-situ upgrading of oil shales

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 A&M 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

Numerical simulation of diverse thermal in situ upgrading processes for the hydrocarbon production from kerogen in oil shale reservoirs

We investigate the productivity and product selectivity of diverse thermal in situ upgrading processes in oil shale reservoirs. In situ upgrading processes applying the ideas of Shell In situ Conversion Process, ExxonMobil Electrofrac, and Texas A&M Steamfrac are simulated by using sector models with the assumption of symmetric patterns. In-house fully functional simulator is used, which has been developed for the kerogen pyrolysis and hydrocarbon production. In the simulation cases, sensitivity analyses to the factors having major influence on the productivity and product selectivity are conducted. The effects of the temperature of vertical heaters, the spacing of hydraulic fractures, and the position of horizontal production wells are analyzed in the applied In situ Conversion Process, Electrofrac, and Steamfrac, respectively. In the applied In situ Conversion Process cases, hydrocarbon production increases with the increasing heater temperature. In the applied Electrofrac cases, hydrocarbon production increases with the increasing spacing of hydraulic fractures, even though longer time period for the process is needed. In the applied Steamfrac cases, the case of production well located at the same depth to the injection well shows the least hydrocarbon production. Among the processes, the applied In situ Conversion Process cases show the highest weight percentage of total hydrocarbon components in the produced fluid, and the applied Electrofrac cases follow it. The applied Steamfrac cases show far lower weight percentage of hydrocarbon production than the other methods. In terms of the mass ratio of produced hydrocarbon to decomposed kerogen, the applied Steamfrac cases show the largest value among the processes by aqueous phase sweeping liquid organic phase, but they also show the huge water oil mass ratio by the continuous injection of hot water. All the applied In situ Conversion Process cases and the Electrofrac case with the short spacing of hydraulic fractures show good heating efficiency by decomposing whole kerogen in the system

Application of the flow dimension concept for numerical drawdown data analyses in mixed-flow karst systems

A numerical discrete conduit-continuum model is employed to investigate large-scale groundwater abstraction in karst aquifers. The application of large-scale experiments is one approach to deal with the scale problem in hydraulic parameter assessment, caused by significant contrasts of hydraulic parameters in a karst aquifer. Here, conduit drawdown is evaluated by diagnostic plots and by considering the apparent flow dimension. These tools are frequently used for the interpretation of hydraulic borehole tests by analytical solutions. In contrast to existing analytical solutions, a numerical groundwater model allows the incorporation of the effect of complex parameter distributions. The objective is to demonstrate the application of diagnostic plots and flow dimension analysis for a systematic analysis of the effect of different boundary conditions as well as sink/source terms for idealized two-dimensional mixed karst aquifer systems, which ultimately extends existing analytical solutions and, therefore, contributes to the interpretation of measured field data. The analysis is focused on the apparent flow dimension and shows the extension of the cross-sectional flow area for selected models. The results are used to evaluate the large-scale pumping test of the karstified Cent Fonts catchment (Languedoc, France). The inverse calibration of two realistic, but still simplified, catchment models reveals that the apparent flow dimension supplies useful information about the general flow pattern during the Cent Fonts pumping test. The flow dimension after the end of the storage period can be explained by a large contribution of exchange flow resulting in a strong influence of radial flow on regional, i.e., kilometer scale

Last chance for carbon capture and storage

Anthropogenic energy-related CO2 emissions are higher than ever. With new fossil-fuel power plants, growing energy-intensive industries and new sources of fossil fuels in development, further emissions increase seems inevitable. The rapid application of carbon capture and storage is a much heralded means to tackle emissions from both existing and future sources. However, despite extensive and successful research and development, progress in deploying carbon capture and storage has stalled. No fossil-fuel power plants, the greatest source of CO2 emissions, are using carbon capture and storage, and publicly supported demonstration programmes are struggling to deliver actual projects. Yet, carbon capture and storage remains a core component of national and global emissions-reduction scenarios. Governments have to either increase commitment to carbon capture and storage through much more active market support and emissions regulation, or accept its failure and recognize that continued expansion of power generation from burning fossil fuels is a severe threat to attaining objectives in mitigating climate change