Polymer microspheres (PMs) are used as a new material to recover residual oil left in unswept oil areas after secondary recovery methods. The fact that the PMs plug the macropores causes the flow direction of the injection fluid to be transferred from macropores to micropores. In order to investigate the plugging and profile control mechanisms of PMs in reservoirs, four kinds of PMs with different particle sizes and four kinds of artificial cores with different permeability were selected for flooding tests, including plugging experiments and profile control experiments. The pore throat size distribution of cores was characterized by nuclear magnetic resonance (NMR) technology. The particle size distribution of PMs used in the experiment was characterized using a laser particle size analyzer. The results showed that there are six matching relationships existing simultaneously between pore throats and PMs based on theoretical analysis, which are completely plugging, single plugging, bridge plugging, smooth passing, deposition, and deformable passing. A key principle for optimizing PMs in profile control is that the particle size of the selected PMs can enter the high permeability layer well, but it is difficult for it to enter the low permeability layer. The results of this paper provide a theoretical basis for the optimal particle size of PMs during the oil field profile control process.

The geologic sequestration of carbon dioxide by coal beds leads to the swelling deformation of coal. In order to investigate the swelling deformation characteristics at the microscopic scale, X-ray computed tomography (CT) scanning technology was used. X-ray CT scanning technology detects the internal structure, deformation, and porosity of coal at different gas pressures. Results show that swelling deformation is nonuniform, which is caused by the heterogeneity of the coal structure. Through quantitative measurement of the distance between fractures and pseudocolor processing of CT images, we observed that fractures gradually close with the increase of adsorption pressure. As adsorption pressure increases, the porosity of coal decreases, and the density of coal increases.

The skin factor and additional pressure drop which are used to evaluate the formation damage of vertical wells can not accurately be applied to horizontal wells.A new model for evaluating formation damage of horizontal wells is presented.This method is derived by utilizing and modifying the concept of equivalent horizontal well length presented by Malekzadeh,where the permeability anisotropy is considered and a new calculation method of the equivalent productivity ratio is proposed.The results show that for a damaged horizontal well,the equivalent horizontal well length is shorter than the completed horizontal interval,while for a stimulated horizontal well the equivalent horizontal well length is longer than the completed horizontal interval.The fact that the longer the horizontal well is,the smaller the equivalent vertical well skin factor indicates that the horizontal well is more advanced than the vertical well in oilfield development.A longer horizontal well is more subjected to productivity loss when the well is damaged and it is more productive after stimulation.The application in the Bohai Oilfield indicates that the new method can directly and efficiently determine the magnitude of formation damage around horizontal wells and its impaction on productivity.It also sheds light on reservoir development and its evaluation standard.

Due to the high water saturation in high-water-cut tight sandstone gas reservoirs, factors such as threshold pressure gradient (TPG) and stress sensitivity (SS) cannot be overlooked in terms of their impact on seepage parameters. Therefore, this paper primarily investigates the seepage mechanisms in tight, high-water-cut sandstone gas reservoirs. While considering the influence of water saturation on various seepage mechanisms, it establishes a gas well productivity equation under stable seepage conditions and presents an analysis of the influencing factors. In a comparison of the unobstructed flow rates calculated using the productivity equation developed in this paper with those obtained from conventional gas well productivity equations and actual gas well productivity tests, the new equation demonstrates smaller errors. This provides a theoretical basis for evaluating productivity and making rational production allocation decisions in high-water-cut tight sandstone gas reservoirs.

Experimental Study on Stress Sensitivity Considering Time Effect for Tight Gas Reservoirs