In naturally fractured reservoirs, fractures are the main flowing channels, while matrix is the dominant storage space. The oil/water relative permeability curve for the fracture in this kind of reservoir is very important for water-injection field development. In this study, we conducted experiments on the oil/water relative permeability of carbonate cores from Kenkiyak oil field and compared the differences in relative permeability curves between natural matrix cores and artificial-fractured cores. After the fracturing process, the two-phase flow area of tested cores becomes narrower, the permeability of the equal-permeability point gets higher, the relative permeability curve rises or drops more rapidly, and the displacement recovery efficiency decreases. The stress-sensitivity characteristics of the relative permeability curves were also studied on the basis of experiments on naturally fractured cores. With increasing effective confining pressure, the irreducible water saturation increases, the residual-oil saturation changes slightly, the equal-permeability point moves downward, and the displacement recovery efficiency declines. Numerical-simulation results indicate that for a given recovery factor, the water cut would increase more slowly but ultimate recovery factor would decrease using the relative permeability curve under higher confining pressure. Therefore, the water injection should be operated when the reservoir pressure is relatively higher to maintain formation pressure during waterflooding and lower the impact of stress sensitivity accordingly.

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SUMMARYBased on Green's functions and Newman's product principle, pressure drop formula was derived for considering simultaneous production of fractures and horizontal wellbore in unsteady state. A reservoir/fractured horizontal well coupling model is developed for finite conductivity condition that can be solved by the combination of quasi-Newton method and PSO (Particle Swarm Optimization) algorithm. The solution of a practical example shows that lots of factors can affect the productivity of the fractured horizontal well. The number of the fractures has an optimizing range. Different fractures have different flow rates and the production in the central fracture is the lowest. The distribution of production rate in the wellbore has a wave-like shape due to the influence of fractures. The closer fractures are the lower flow rate in well segments. Considering the horizontal wellbore production, the production rates in the fractures are asymmetric and the corresponding pressure drop curve is smoother.

This paper investigated fractal characteristics of microscale and nanoscale pore structures in carbonates using High-Pressure Mercury Intrusion (HPMI). Firstly, four different fractal models, i.e., 2D capillary tube model, 3D capillary tube model, geometry model, and thermodynamic model, were used to calculate fractal dimensions of carbonate core samples from HPMI curves. Afterwards, the relationships between the calculated fractal dimensions and carbonate petrophysical properties were analysed. Finally, fractal permeability model was used to predict carbonate permeability and then compared with Winland permeability model. The research results demonstrate that the calculated fractal dimensions strongly depend on the fractal models used. Compared with the other three fractal models, 3D capillary tube model can effectively reflect the fractal characteristics of carbonate microscale and nanoscale pores. Fractal dimensions of microscale pores positively correlate with fractal dimensions of the entire carbonate pores, yet negatively correlate with fractal dimensions of nanoscale pores. Although nanoscale pores widely develop in carbonates, microscale pores have greater impact on the fractal characteristics of the entire pores. Fractal permeability model is applicable in predicting carbonate permeability, and compared with the Winland permeability model, its calculation errors are acceptable.