The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations, which launches the energy revolution from conventional resources to unconventional resources. With the progress of understanding the nature of shale reservoirs, we find that some shale methane is stored as an adsorbed phase on surfaces of organic carbon. Meanwhile, laboratory and theoretical calculations indicate that organic-rich shale adsorbs CO2 preferentially over CH4. Shale gas reservoirs are recently becoming the promising underground target for CO2 sequestration. In the paper, systematic numerical simulations will be implemented to investigate the feasibility of CO2 sequestration in shale gas reservoirs and quantify the associated uncertainties. First, a multi-continua porous medium model will be set up to present the matrix, nature fractures and hydraulic fractures in shale gas reservoirs. Based on this model, we will investigate a three-stage flow mechanism which includes convective gas flow mainly in fractures, dispersive gas transport in macro pores and multi-component sorption phenomenon in micro pores. To deal with this complicated three-stage flow mechanism simultaneously, analytical apparent permeability which includes slip flow and Knudsen diffusion will be incorporated into a commercial simulator CMG-GEM. A Langmuir isotherm model is used for CH4 and the multilayer sorption gas model, a BET model, is implemented for CO2. In addition, a mixing rule is introduced to deal with the CH4-CO2 competitive adsorption phenomenon. In the paper, an integrated methodology is provided to investigate the CO2 sequestration process. Simulation results indicate that a shale gas reservoir is an ideal target for the CO2 sequestration. Even with the reservoir pressure maintenance due to the injection of CO2, the reservoir productivity is not enhanced. Hydraulic fracking which creates freeways for gas flow is the key to improve the reservoir performance. The multicomponent desorption/adsorption is a very important feature in a shale gas reservoir, which should be fully harnessed to benefit the CO2 sequestration process. In addition, we cannot ignore the contribution of slip flow and diffusion to the reservoir performance. Based on the methodology provided in this paper, we can easily deal with the apparent permeability effect using a commercial simulator platform.
The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations, which launches the energy revolution from conventional resources to unconventional resources. Some of the shale reservoirs, particularly the Eagle Ford shale, contain a wide range of hydrocarbon fluids covering from low GOR black oil and volatile oil to the rich and lean gas-condensate. With the progress of understanding the nature of shale reservoirs, we find that some hydrocarbons are stored as an adsorbed phase on surfaces of organic carbon. Meanwhile, laboratory and theoretical calculations indicate that CO2 has significantly greater sorption capability compared with some lighter hydrocarbons like CH4 and C2H6. Shale gas reservoirs are recently becoming the promising underground target for CO2 sequestration. In the paper, systematic numerical simulations will be implemented to investigate the feasibility of CO2 sequestration in Eagle Ford liquid-rich shale gas reservoirs and quantify the associated uncertainties. First, a multi-continua porous medium model will be set up to present the matrix, nature fractures and hydraulic fractures in shale gas reservoirs. Based on the Eagle Ford gas condensate data, 14 components will be simulated in the compositional model. Meanwhile, we will investigate a three-stage flow mechanism which includes convective gas flow mainly in fractures, dispersive gas transport in macro pores and multi-component sorption phenomenon in micro pores. To deal with this complicated three-stage flow mechanism simultaneously, analytical apparent permeability which includes slip flow and Knudsen diffusion will be incorporated into a commercial simulator CMG-GEM. In addition, multicomponent adsorption/desorption lab data will be included in the model. A mixing rule is introduced to deal with the competitive adsorption phenomenon between the different components. In the paper, an integrated methodology is provided to investigate the CO2 sequestration process. Simulation results indicate that the Eagle Ford liquid-rich shale gas reservoir is an ideal target for the CO2 sequestration. To some extent, the average reservoir pressure is maintained due to injection of CO2. But most of the pressure is trapped around an injector due to the tight formation. That is why the reservoir productivity is enhanced by the injection process. But the increment is very small. Hydraulic fracking which creates freeways for gas flow is the key to improve the reservoir performance. The pressure maintenance around the injector reduces the effect of the liquid blockage, which is a good sign to implement the cyclic inert gas injection to reduce the effect of the liquid blockage and enhance the reservoir performance ultimately. The multicomponent desorption/adsorption is a very important feature in a shale gas reservoir, which should be fully harnessed to benefit the CO2 sequestration process. Meanwhile, the multicomponent desorption/adsorption process will increase the condensate production, which will lead to severer liquid blockage. In addition, it will limit the gas production. Furthermore, we cannot ignore the contribution of slip flow and diffusion to the reservoir performance during the sequestration process. Based on the methodology provided in this paper, we can easily deal with the apparent permeability effect based on a commercial simulator platform.
The gas flow in shale matrix is of great research interest for optimizing shale gas development. Due to a nano-scale pore radius, the gas flow in the shale matrix may fall in flow regimes which include viscous flow, slip flow and Knudsen diffusion. On top of that, gas adsorption/desorption and stress-sensitivity are some other important phenomena in shale. In this paper, we introduce an integrated multi-scale numerical simulation scheme to depict the above phenomena which is crucial for the shale gas development. Instead of Darcy's equation, we implement the apparent permeability in the reservoir-scale continuity equation to depict the gas flow (viscous flow, slip flow and Knudsen diffusion) in shale matrix. A Langmuir adsorption/desorption term is included in the reservoir-scale continuity equation as a generation term. To ensure the real-time desorption and adsorption equilibrium with gas production, an iterative mass balance check of pore wall surfaces (pore scale) is introduced. At each time step, the pore-scale and reservoir-scale mass balance should be satisfied simultaneously in each grid block. On top of that, the lab data of a Bakken reservoir which provides a relationship between a matrix pore radius reduction and the effective stress is integrated into the two-way coupling geomechanical process to simulate a stresssensitive shale formation. This methodology examines the influence of each mechanism for the shale gas flow in the matrix. Instead of conventional pressure-independent Darcy permeability, the apparent permeability increases with the development of a shale gas reservoir. With the gas adsorption/desorption, the reservoir pressure is maintained via the supply of released gas from nano-scale pore wall surfaces. With the consideration of geomechanics, the apparent permeability is decreased due to the compaction of nano-scale pore radii, which leads to the maintenance of reservoir pressure. Due to the difference of compaction magnitude for each grid block, geomechanics create additional heterogeneity for a nano-pore network in shale matrix, which we should pay more attention to. A novel integrated multi-scale methodology is introduced to examine the crucial phenomena in the shale matrix, which simultaneously takes into account the influence of flow regimes, gas adsorption/desorption and stress-sensitivity. An effective way is provided to quantify the above effects for the transient gas flow in shale matrix.
In order to analysis of the mechanical properties of geogrid-reinforced granular soil, a simulation model of unconfined compression tests is proposed based on the laboratory tests conducted before by the author. This numerical method, after modified by the laboratory test data, is adopted to carry out a simulation of unconfined compression tests using large specimens of geogrid-reinforced granular soil. Each large specimen, with the diameter of 175cm and the height of 300cm, varies in reinforcement spacing of 30 cm, 37.5cm, 50 cm or 75 cm. For comparison, the same simulation test is also demonstrated for the granular soil without geogrid. A series of simulated compression stress-strain relationship curves are presented, on which a detail analysis is carried out. The following conclusions are obtained: (1) The geogrid-reinforced granular soil is a strain-hardening mass if the reinforcement spacing is less than about 50 cm. (2) While the reinforcement spacing is smaller enough, there is no sliding at the geogrid-soil interface and, therefore, the geogrid-reinforced granular soil may be taken as a composite material.
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