RESUMO
As gas reservoir pressure decreases, edge and bottom water irregularly flow into the reservoir through storage and permeability spaces. Water influx poses a significant challenge for the development of gas reservoirs, impacting development efficiency and the ultimate recovery rate. Therefore, exploring rational optimization methods for gas well allocation is essential. This study utilizes the vertical well productivity equation considering two-phase flow and employs the net present value (NPV) to evaluate the economic benefits of gas well production. A parallel-structured genetic algorithm (GA) is developed to account for dynamic reservoir inflow, wellbore conditions, and surface facilities engineering. The new model is applied to investigate the optimal allocation of the B-21 well in the Amu Darya right bank gas reservoirs in Turkmenistan. Results indicate a match of over 90% between the cumulative gas production and water/gas ratio calculated by the proposed method and those calculated by a numerical simulation model. Compared with the traditional genetic algorithm, the new approach reduces the number of iterations to approximately 2100 (a 72.4% decrease) and significantly improves the convergence rate.
RESUMO
Proven oil and gas reserves in carbonate rocks comprise a high proportion of oil and gas fields, but these reservoirs have high heterogeneity. It is of great importance to study the micropore structures and percolation characteristics of carbonate rocks for the development of oilfields. In this paper, reservoirs are studied by means of casting sections, high-pressure mercury injection, and water and gas flooding oil phase permeability experiments. Reservoirs are classified into three categories, I, II, and III, by the k-means cluster analysis method. The results show that class I reservoirs are mainly composed of biolimestone with strong dissolution, displacement pressure of 0.016 MPa, median pressure of 0.135 MPa, mercury removal efficiency of 17.15%, well-developed pore throats, and good connectivity. They have the highest reservoir quality index and strong percolation ability. Class II reservoirs are mainly biogenic limestone and granular limestone with intergranular pores, a displacement pressure of 0.098 MPa, a median pressure of 6.026 MPa, and a mercury removal efficiency of 25.82%. The pore throat class is complex, and the sorting is poor. Class III reservoirs are mainly clastic limestone with residual intergranular pores, poor connectivity, displacement pressure of 0.403 MPa, median pressure of 3.77 MPa, mercury removal efficiency of 14.01%, small median radii, and good sorting performance. Relative permeability experiments show that water drive permeability at the isopermeability point is (0.049 10-3 µm2) higher than that of gas drive (0.041 10-3 µm2). The permeability of oil and water phases in class I reservoirs is obviously higher than those of class II and III reservoirs. When gas flooding is used, the phase permeability characteristics of class I and II reservoirs are no different than when water flooding is used. The permeability of gas flooding is slightly lower than that of water flooding. Because of the high proportion of micropores in class III reservoirs, gas can easily enter the pores, so the relative permeability of the gas phase increases rapidly. With increases in injection volume, the ultimate oil displacement efficiency of class I reservoirs can reach 53.2%, while those of class II and III reservoirs are 50.7 and 46.1%, respectively. This study provides important guidance for formulating oilfield development plans.