CO₂ flooding recovery strongly depends on the minimum miscibility pressure (MMP). Conventional tests to determine gas–oil MMP such as rising bubble apparatus and slim tube displacement are either costly or time consuming. In order to propose a quick and accurate model to determine MMP, a back-propagation neural network is presented for MMP prediction during pure and impure CO₂ injections. Five new variables were screened as input parameters to the network. Next, the network was optimized using five evolutionary algorithms, and this work highlights that three of these evolutionary algorithms (e.g. Mind Evolutionary, Artificial Bee Colony, and Dragonfly) are firstly used to predict MMP. Then, data from the literature were input to the optimized network to train it. Statistical evaluation and graphical analyses were used to evaluate the performance of the proposed models and for comparison with published MMP correlates to obtain the optimal model for predicting MMP. The back-propagation model optimized using the dragonfly algorithm exhibited the highest accuracy among all those considered and MMP correlates; its coefficient of determination, average absolute percent relative error, root mean square error, and standard deviation were 0.965, 5.79%, 206.1, and 0.08, respectively. In addition, reservoir temperature was determined as the strongest MMP predictor (Pearson correlation = 0.63) based on sensitivity analysis.

The fault block hydrocarbon reservoirs developed by water flooding in Shengli Oilfield have entered into the period of high water cut and low oil recovery. The residual oil to be recovered is challenging by using the unidirectional water or gas displacement method in producing oil from the reservoirs because of water invasion or gas channeling. A novel method of bidirectional displacement with artificial nitrogen gas cap and edge water is presented to improve the oilfield development recovery efficiency. This novel method refers to the nitrogen gas injection at the top of the inclined reservoir and the edge water injection at the bottom of the reservoir simultaneously. The experiments of the sandpack model are performed to explain the benefits of nitrogen gas flooding and to evaluate quantitatively the production performance of the bidirectional displacement process. A numerical simulation technique based on the proposed method is employed to find out befitting reservoirs for implementation of this new novel method. The X48 inclined fault block hydrocarbon reservoir in Dongxin production area, Shengli Oilfield, is selected as the actual research block to verify the benefits of bidirectional displacement with artificial nitrogen gas cap and edge water. The results indicate that the oil recovery by bidirectional displacement of nitrogen gas injection in the X4841 injection well and edge water injection in the X48CXN9 injection well cooperatively is higher than that of unidirectional water flooding or gas flooding in the X4841 injection well. The oil recovery factor increases by 11.2% than that by the original water injection development in the X48CXN9 injection well. Another interesting finding in this work was that, for the oil recovery, an appropriate ratio relationship is established between the nitrogen injection rate and the water injection rate regardless of production rate.

In the background of the strong oil wettability and low production by water flooding in carbonate reservoirs, low-salinity water containing sulfate ions can significantly change the surface wettability of carbonate rocks and thus increase the sweeping area; however, the absorption and desorption mechanisms of the oil film in the carbonate rock surface remain unclear. This paper analyzed the wettability alternation of carbonate rocks' surface in pure water and sodium sulfate solution. At the same time, MD (Materials Studio) software was used to simulate the formation process of the oil film and the effect of sulfate ions on the desorption of the oil film on the surface of carbonate rocks. The experimental results showed that sodium sulfate solution could accelerate the rate from oil-wet to water-wet and the final contact angle (49°) was smaller than that in pure water. The simulation results showed that dodecane molecules moved to the surface of calcite to form a double layer of the oil film and that the oil film near the calcite surface had a high-density stable structure under the van der Waals and electrostatic action. The hydrating sulfate ions above the oil film broke through the double oil film to form a water channel mainly under the action of electrostatic force and a hydrogen bond and then adsorbed on the calcite surface. A large number of water molecules moved down the water channel based on a strong hydrogen bonding force and crowded out the oil molecules on the surface of the calcite, resulting in the oil film detachment. This work aims to explain the interaction of oil molecules, water molecules, and SO₄^2- ions at the molecular scale and guide the practical application of low-salinity water flooding in carbonate reservoirs.

In the process of long-term water flooding in the Gaoqian Southern Area with an average porosity of 30% and an average permeability of μm², the fluid-solid interaction among oil, water, and rock has a great influence on the pore structure. It has resulted in changes in reservoir parameters with the extension of time. This paper used electron microscopy scanning, mercury injection, X-ray diffraction, physical properties, and oil-water relative permeability curves to study the variation of clay mineral content, pore throat structure, porosity, permeability, and relative permeability curves of high-permeability sandstone after high-pressure water flooding. The results showed that clay minerals such as montmorillonite and kaolinite were dissolved, hydrated, and migrated after long-term water flooding, which resulted in the decrease of clay mineral content in fine sandstone and medium sandstone, the increase of pore throat radius, and the decrease of displacement pressure, median pressure, and separation coefficient. The saturation of the isotonic point of the oil-water relative permeability curve was obviously shifted to the right, the hydrophilicity was significantly enhanced, and the porosity and permeability were effectively improved, but there was a blockage of the throat less than 2 μm in the fine sandstone. In addition, this paper established the equations of water injection, permeability, irreducible water saturation, residual oil saturation, and oil-water relative permeability curve coefficient and establishes the initial permeability model with the well data before water flooding. The logging interpretation results of development wells in the process of water flooding as verification data were used, and the relative error of permeability far lower than the general requirement of permeability error within an order of magnitude was less than 30%, which verified the rationality of the method.