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 application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations. To optimize the shale gas development, the transient gas flow in a shale formation is of great research interest. Due to anano-scale pore radius, the gas flow in 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 shales. In this paper, we introduce a novel numerical simulation scheme to depict the above phenomena and predict the gas production from a multi-stage fractured horizontal well, which is crucial for the shale gas development. Instead of Darcy's equation, we implement the apparent permeability in the continuity equation to depict the gas flow (viscous flow, slip flow and Knudsen diffusion) in shale matrix. An adsorption/desorption term is included in the continuity equation as an accumulation term. A sink which is based on Peaceman's well model is placed at the center of the fracture cell. Uniform fluid flow from matrix to fractures is assumed. Only viscous flow is considered in the fractures and the permeability of the fractures doesnot change with pressure. The model is validated via comparing with an infinity-conductivity fracture model. Moreover, the lab data of Eagle Ford shale which provides the relationship between matrix permeability and the effective stress is integrated into the two-way coupling geomechanical process to simulate a stress-sensitive shale formation. Furthermore, the Langmuir and BET models will be compared to investigate the detailed adsorption/desorption process. This methodology examines the influence of each mechanism for the transient shale gas flow. Instead of conventional pressure-independent Darcy permeability, the apparent permeability increases with the development of a shale gas reservoir, which leads to higher productivity. With the gas adsorption/desorption, the reservoir pressure is maintained via the supply of released gas from nano-scale pore wall surfaces, which also leads to higher gas production. In addition, it yields a 5% difference for the cumulative production for one yearbetween the Langmuir and BET models. With the consideration of geomechanics, the apparent permeability is decreased due to the compaction of nano-scale pores, which leads to a decrease in productivity. Due to the difference of compaction magnitude for each grid block, geomechanics creates additional heterogeneity for anano-pore network in a shale formation, which we should pay more attention to. A novel methodology is introduced to examine the crucial phenomena in a shale formation, which simultaneously takes into account the influence of flow regimes, gas adsorption/desorption and stresssensitivity. On top of that, the productivity of a multi-stage fractured horizontal well is quantified. We provide an effective way to quantify the above effects for the transient gas flow in shale formations.
The gas flow in shale matrix is of great research interest for optimizing shale gas reservoir 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, the adsorbed and free gas is stored in nano-scale organic pores. The gas molecules are attached as a monolayer to pore walls to form a film of gas which is the thickness of the adsorbed layer. When a reservoir is depleted, the attached gas molecules will be released so that the radius of organic pores in which the free gas flows is changeable. Thus a sorption-dependent radius will be introduced to the apparent permeability which represents the flow regimes. Stress sensitivity will also be investigated via a two-way coupling geomechanics process. In this paper, we introduce a novel integrated numerical simulation scheme to quantify the above phenomena which is crucial for the shale gas reservoir development. Instead of Darcy's equation, we implement the sorption-dependent apparent permeability in the continuity equation to depict the gas flow (viscous flow, slip flow and Knudsen diffusion) in shale matrix. The methodology which was developed by Vasina et al. and validated through comparing with molecular simulation will be implemented to determine the thickness of an adsorbed layer at each time step. The Langmuir adsorption/desorption term is included in the continuity equation as an accumulation term. In addition, lab data for 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 stress-sensitive shale formation. This methodology examines the influence of each mechanism for the shale gas flow in the matrix. Overall, the sorption-dependent apparent permeability is smaller than the sorption-independent apparent permeability, which leads to the pressure maintenance for the sorption-dependent apparent permeability case. The sorption-dependent apparent permeability will lead to additional heterogeneity. The apparent permeability near a wellbore is bigger than the one far away from the wellbore, which causes the pressure transmit more easily around the production side. With the consideration of geomechanics, the apparent permeability is decreased due to the compaction of a nano-scale pore radius, which leads to the maintenance of reservoir pressure. Due to the difference of compaction magnitude for each grid block, geomechanics also creates additional heterogeneity for a nano-pore network in shale matrix, which we should pay more attention to. The sorption-dependent radius is incorporated into the apparent permeability model to depict the sorption-dependent apparent permeability of shale matrix. We provide a novel integrated methodology to quantify the crucial transient phenomena in the shale matrix, which includes flow regimes, gas adsorption/desorption and stress sensitivity.
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