CO₂ geological sequestration in shale is a promising method to mitigate global warming caused by greenhouse gas emissions as well as to enhance the gas recovery to some degree, which effectively addresses the problems related to energy demand and climate change. With the data from the New Albany Shale in the Illinois Basin in the United States, the CMG-GEM simulator is applied to establish a numerical model to evaluate the feasibility of CO₂ sequestration in shale gas reservoirs with potential enhanced gas recovery (EGR). To represent the matrix, natural fractures, and hydraulic fractures in shale gas reservoirs, a multicontinua porous medium model will be developed. Darcys and Forchheimers models and desorption-adsorption models with a mixing rule will be incorporated into the multicontinua numerical model to depict the three-stage flow mechanism, including convective gas flow mainly in fractures, dispersive gas transport in macropores, and CH₄-CO₂ competitive sorption phenomenon in micropores. With the established shale reservoir model, different CO₂ injection schemes (continuous injection vs. pulse injection) for CO₂ sequestration in shale gas reservoirs are investigated. Meanwhile, a sensitivity analysis of the reservoir permeability between the hydraulic fractures of production and injection wells is conducted to quantify its influence on reservoir performance. The permeability multipliers are 10, 100, and 1,000 for the sensitivity study. The results indicate that CO₂ can be effectively sequestered in shale reservoirs. But the EGR of both injection schemes does not perform well as expected. In the field application, it is necessary to take the efficiency of supplemental energy utilization, the CO₂ sequestration ratio, and the effect of injected CO₂ on the purity of produced methane into consideration to design an optimal execution plan. The case with a permeability multiplier of 1,000 meets the demand for both CO₂ sequestration and EGR, which indicates that a moderate secondary stimulation zone needs to be formed between the primary hydraulic fractures of injection and production wells to facilitate the efficient energy transfer between interwell as well as to prevent CO₂ from channeling. To meet the demand for CO₂ sequestration in shale gas reservoirs with EGR, advanced and effective fracking is essential.

The reservoir anisotropy, perforating skin, and the compressibility of rock and fluids are important factors affecting horizontal well productivity. In this research, the finite volume method is adopted to develop a three-dimensional unsteady productivity prediction model for horizontal wells. An improved Peaceman well model is used to predict the productivity of horizontal wells. The influence of parameters, including the plane anisotropy, horizontal well length, and perforation skin on productivity were studied and the production law for horizontal wells was further analyzed. The accuracy of the model is verified by CMG reservoir simulation software. The following conclusions are obtained from study: first, the speed of pressure propagation in homogeneous and isotropic reservoir is faster than the anisotropic reservoir. Second, the flow rate of the horizontal well is U-shaped along the horizontal wellbore, and the contribution of perforation sections at both ends of horizontal wells to the total production is greater than that in the middle of horizontal wells. With the continuous production, the contribution of perforation sections at both ends gradually increases. Third, the accumulative production of a horizontal well increases with an increase in rock compressibility. The main reason is that with the increase of the elastic energy in reservoir, the accumulative production of the horizontal well under the same conditions gets higher. The proposed model can be used to predict pressure and production distribution for horizontal well in anisotropic reservoirs.

Complex fracture networks are easily developed along the horizontal wellbore during hydraulic fracturing. The water phase increases the seepage resistance of oil in natural fractured reservoir. The flow regimes become more intricate due to the complex fractures and the occurrence of two-phase flow. Therefore, a semi-analytical two-phase flow model is developed based on the assumption of orthogonal fracture networks to describe the complicate flow regimes. The natural micro-fractures are treated as a dual-porosity system and the hydraulic fracture with complex fracture networks are characterized explicitly by discretizing the fracture networks into multiple fracture segments. The model is solved according to Laplace transformation and Duhamel superposition principle. Results show that seven possible flow regimes are described according to the typical curves. The major difference between the vertical fractures and the fracture networks along the horizontal wellbore is the fluid “feed flow” behavior from the secondary fracture to the main fracture. A natural fracture pseudo-radial flow stage is added in the proposed model comparing with the conventional dual-porosity model. The water content has a major effect on the fluid total mobility and flow capacity in dual-porosity system and complex fracture networks. With the increase of the main fracture number, the interference of the fractures increases and the linear flow characteristics in the fracture become more obvious. The secondary fracture number has major influence on the fluid feed capacity from the secondary fracture to the main fracture. The elastic storativity ratio mainly influences the fracture flow period and inter-porosity flow period in the dual-porosity system. The inter-porosity flow coefficient corresponds to the inter-porosity flow period of the pressure curves. This work is significantly important for the hydraulic fracture characterization and performance prediction of the fractured horizontal well with complex fracture networks in natural fractured reservoirs.

Geothermal energy, as a clean, low-carbon, widely distributed, renewable and environmentally friendly energy source, plays an important role in the transition from traditional energy sources dominated by coal and oil to clean energy. Ground source heat pump technology is a key technological tool for developing geothermal energy for widespread use. Coaxial-cased heat exchangers are the core component of the ground source heat pump system, and their heat transfer performance directly affects the heat transfer efficiency and service life of the ground source heat pump system. According to the actual working conditions of coaxial-cased heat exchangers in fractured aquifers, the coupled pressure–temperature model of the heat transfer outside the borehole was created by considering the influence of the Joule–Thompson effect. For heat transfer inside the wellbore, a multi-layer long concentric cylinder wall model was developed to obtain the fluid temperature distribution within the wellbore. Results show that the heat transfer efficiency increases with the increase of thermal conductivity, water production and effective permeability of fractures. The positive and negative values of the Joule–Thompson coefficient reflect the trend of fluid temperature changing with pressure. The larger the absolute value is, the greater the temperature change is. The increase in the initial temperature of the injected water will lead to a decrease in the theoretical heat transfer. With the increase of the water injection rate and horizontal wellbore length, the heat recovery power will also increase significantly, but the optimal value needs to be considered comprehensively. The findings of the study can not only lay a theoretical foundation for the performance evaluation and optimal design of coaxial-cased heat exchangers but also have great significance in promoting the efficient development of geothermal energy.

The pressure transient behavior of water injection well has been extensively investigated under single-phase flow conditions. However, when water is injected into formation, there are saturation gradients within the water flooded area. Additionally, water imbibition is essentially important for oil displacement in dual-porosity and dual-permeability (DPDP) reservoirs. In this work, a novel semianalytical two-phase flow DPDP well test model considering both saturation gradient and water imbibition has been developed. The model was solved by the Laplace transform finite difference method. Type curves were generated, and flow regimes were identified by the model. The model features and effect of parameters were analyzed. Results show that water imbibition reduces the advancing speed of water drive front in the fracture system and slows down the water cut raising rate and the expansion speed of the two-phase zone in the fracture system. Therefore, the fluid exchange between the fracture and matrix systems becomes more sufficient and more oil will be recovered from the DPDP reservoir. The shape of pressure curves is similar for the single-phase and two-phase flow DPDP model, but the position of the proposed model is above the curves of the single-phase model. Shape factor mainly influences the interporosity period of the pressure derivatives. Water imbibition has a major effect on the whole system radial flow period of the curves. The findings of this study can help for better understanding of the oil/water two-phase flow pressure transient behavior in DPDP reservoirs considering saturation gradients and water imbibition.