CO 2 miscible injection is generally one of the most efficient enhanced oil recovery (EOR) methods and widely used in the conventional oil reservoirs. The applicability of CO 2 EOR technology for unlocking the resources from unconventional tight and shale formations and the mechanisms of miscible flooding in these reservoirs still remain unclear. An important parameter used to evaluate the feasibility of CO 2 miscible flooding is the minimum miscibility pressure (MMP). Even though experimental approaches, empirical correlations and theoretical methods have performed well in measuring or predicting MMP between CO 2 and crude oil in conventional reservoirs, they may not be suitable for unconventional formations as phase behavior and MMP can be significantly affected by confinement effect in small pores (e.g., nanopores) in such formations.In this study, a new MMP prediction model based on the modified Parachor Model associated with the Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT) is developed to determine CO 2 MMP both in the bulk phase and nanopores. The Parachor Model is modified to account for the confinement effect of nanopore walls on the equilibrium interfacial tension (IFT). The Equilibrium IFT reduction in nanopores is related to a temperature-dependent and slit pore width-dependent modification term. The parameters of the new Parachor Model are determined by matching the vapor-liquid surface tension values for CH 4 , C 2 H 6 , C 3 H 8 , n-C 4 H 10 , and n-C 8 H 18 in nanopores, respectively. The prediction ability of the new model is verified by comparing the predicted MMP in the bulk phase with the results of other theoretical approaches and slim-tube experimental data. Finally, the new model is applied to estimate the MMP between Bakken oil and CO 2 stream. The effect of temperature, slit pore width, and impure components in the injected CO 2 on the MMP are also studied. The newly developed model successfully reproduces MMP in bulk phase as compared with both other methods and experimental data. The overall average absolute relative deviation (AARD) for MMP is within 8 %. The calculated equilibrium IFT for liquid-vapor phase has a good agreement with molecular simulation results. For Bakken oil-CO 2 system, if the slit pore width is larger than 10 nm, MMP is independent on pore width; otherwise, it decreases significantly with the decrease of the pore width. If pore width decreases to 3 nm, 67.5 % decrease in the IFT is observed and 23.5% reduction is achieved for MMP between Bakken oil and CO 2 stream, indicating that it is easier to reach miscibility in nanopores, and CO 2 miscible flooding might be a promising enhanced oil recovery (EOR) technology for tight oil and shale oil reservoirs. Furthermore, MMP increases with an increase of temperature in bulk phase, whereas IFT and MMP decrease with an increase of temperature in nanopores.

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Pressure-transient analysis in dual-porosity media is commonly studied by assuming a constant reservoir permeability. Such an assumption can result in significant errors when estimating pressure behavior and production rate of naturally fractured reservoirs as fracture permeability decreases during the production. At present, there is still a lack of analytical pressure-transient studies in naturally fractured reservoirs while taking stress-sensitive fracture permeability into account.In this study, an approximate analytical model is proposed to investigate the pressure behavior and production rate in the naturally fractured reservoirs. This model assumes that fracture permeability is a function of both permeability modulus and pressure difference. The pressure-dependent fracture system is coupled with matrix system with an unsteady-state exchange flow rate. A nonlinear diffusivity equation in fracture system is developed and solved by Pedrosa's transformation and a perturbation technique with zero-order approximation. A total of six solutions in the Laplace space are presented for two inner-boundary conditions and three outer-boundary conditions. Finally, pressure behavior and production rate are studied for both infinite and finite reservoirs.Pressure behavior and production rate from the models with and without stress-sensitive permeability are compared. It is found that, for an infinite reservoir with a constant-flow-rate boundary condition, if permeability modulus is 0.1, dimensionless pressure difference at the well bottom from the model with fracture-permeability sensitivity is 80% higher than that of the constant fracture-permeability model at a dimensionless time of 10 6 . Such difference can be as high as 216% if permeability modulus increases to 0.15. On the contrary, for the infinite reservoirs with a constant-pressure boundary, the constant fracture-permeability model tends to overestimate the flow rate at wellbore and cumulative production. The proposed model not only provides an analytical and quantitative method to investigate the effects of fracturepermeability sensitivity on reservoir-pressure distribution and production, but it also can be applied to build up analysis of well test data from stress-sensitive formations.

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