The CO2 displacement is one of the gasflooding Enhanced Oil Recovery (EOR) methods. The application from volatile oil to black oil is popular mainly because CO2 requires a relatively low miscibility pressure, which is suitable to most reservoir conditions. However, CO2 always contains some impurity, such as CH4, H2S and N2, leading to the change of phase behavior and flooding efficiency. Whether the gasflooding achieves successfully miscible displacement depends on the reservoir pressure and temperature, injected solvent and crude oil compositions. So three different types of oil samples from the real field are selected and mixtures of CH4, H2S and N2 with various CO2 concentrations as the solvent are considered. After a series of experimental data are excellently matched, three nine-pseudocomponent models are generated based on the thermodynamic Equation-of-State (EoS), which are capable of accurately predicting the complicated phase behavior. Three common tools of pressure–temperature (P–T), pressure–composition (P–X) and pseudoternary diagrams are used to display and analyze the alteration of phase behavior and types of displacement mechanism. Simulation results show that H2S is favorable to attain miscibility while CH4 and N2 are adverse, and the former can reduce the Multiple Contact Miscibility (MCM) pressure by the maximum level of 1.675 MPa per 0.1 mol. In addition, the phase envelope of the mixtures CO2/H2S displacing the reservoir oil on the pseudoternary diagram behaves a triangle shape, indicating the condensing-dominated process. While most phase envelopes of CO2/CH4 and CO2/N2 exhibit the trump and bell shapes, revealing the MCM of vaporization.

The abnormally high-pressure carbonate dual-medium reservoir of the Kenkiyak Pre-salt oilfield in the littoral Caspian Basin has strong stress sensitivity. With the development of the oil field, the formation pressure drops and the fractures gradually close, resulting in a decrease of the effective permeability of the dual-media reservoir over time. So it is necessary to establish three-dimensional geological models of the dual-medium reservoirs at different times, which is the 4-D geological model. Firstly, the reservoir matrix and fracture permeability model under the original conditions is established by using the dual-medium three-dimensional geological modeling method; Secondly, the formation pressure model for a given period is established by taking the measured well-point formation pressure in a certain period as hard data and combining with the formation pressure change trend in different zones; Thirdly, the carbonate reservoir types are identified by borehole imaging and conventional logging, and the geological model of the reservoir types in the original state is established. Finally, using the relationship between confining pressure and permeability reduction rate of different types of reservoirs obtained by core stress sensitivity experiments, and based on the original matrix and fracture permeability models, the matrix and fracture permeability models of different types of reservoirs at a given period are obtained. Using the method proposed in this paper, the original matrix and fracture permeability model can be corrected to the matrix and fracture permeability model after the formation pressure drops at a certain period, and the 3D geological model of carbonate reservoir in any given periods can be obtained. Newly drilled wells at present confirmed that the geological model established by this method is reasonable and reliable. Taking the data of new wells completed during this period as hard data and the above three-dimensional geological model as soft data, an updated dual-medium model is established, which is more in line with geological reality. Based on the updated geological model, the deployment of oilfield adjustment schemes and well location optimization studies are carried out. The match between the new drilling data and the prediction results reached more than 90%. The method solves the problem of updating the 3D geological model caused by the permeability change of the stress-sensitive reservoir, ensures that the geological model truly reflects the underground geological characteristics, and can be widely applied to the 3D geological modeling of stress-sensitive reservoirs.

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The effect of bottom-hole pressure and formation pressure due to a partially penetrating well (PPW) is different from that for an open hole well. In order to analyze the effect of imperfection on pressure response type curves, this paper presents a 3D symmetry porous flow model for circularly partially penetrating wells. Laplace transform and Fourier transform and Bessel functions are applied to obtain the analytical solution of the model. The pressure response and pressure distribution are obtained and the influence on flow regime surrounding the well and pressure response caused by partial penetration are analyzed. Research results show that when the imperfect area tends to zero, the solution of the model can be reduced to the traditional model of the perfect wells presented by Theis, demonstrating the correctness of the solution. The early-time pressure is significantly lower than the case of complete well. The pressure difference between a partially penetrating well and a completely penetrating well decreases with time increasing. Without considering the variation of spatial distribution of flow field due to imperfect well it may bring about errors of formation parameters calculated by perfect well model. Those conclusions improve the seepage model and provide theoretical guidance for the transient pressure data interpretation, formation parameters calculation and productivity prediction of partially penetrating wells. The presented research content furthers the theory of well test analysis, and builds theoretical foundation for the technologies of well testing interpretation and reservoir numerical simulation.