Gas injection is an effective method to enhance oil recovery of low-permeability and tight reservoirs, while the complicated fractures distributed in the formation have a noticeable effect on the performance of gas injection. In this study, three methods of gas injection were employed to conduct microfluidic experiments using micromodels simulating fractured reservoirs. The sweep efficiency and oil displacement efficiency of pores and throats, fractures, and the whole region were measured respectively to evaluate the oil displacement effects of the different gas injection methods. Moreover, the microscopic displacement process and the morphology of residual oil in porous media were analyzed to investigate the behavior of gas activated oil. The experimental results show that there are three stages of gas displacing oil: the oil in fractures was displaced first, then the oil in the pores and throats around the fracture was displaced, and finally the gas channeling occurred in fractures. Moreover, the sweep efficiency and oil displacement efficiency showed a tendency of increasing fast first and then reaching a steady state. Simultaneous injection of gas and water showed an optimal enhanced oil recovery effect among these three injection methods. Gas can invade deep throats, and those are difficult for water to sweep. However, the higher viscosity of water endowed it a smaller mobility than gas. And, the channeling in the two-phase mixing region was inhibited more obviously. The overall sweep efficiency and oil displacement efficiency increased about 18.4% and 13.4%, respectively.

High dip angle reservoirs are affected by gravity, resulting in poor sweep performance at the middle and high parts during waterflooding development. Previous studies have proposed top gas injection development for this type of reservoir, which has provided direction for improving the development effect of such reservoirs. However, current research efforts have mainly focused on the analysis of gas injection effects, rather than delving deeper into the gas injection mechanism and its influencing factors. Furthermore, the research methods adopted thus far have been primarily theoretical and fail to take into account the typical characteristics of high dip reservoirs in actual oilfields. Using a similarity criterion, this study establishes a high-temperature and high-pressure physical simulation device with variable inclination to analyze the impact of gas injection under various water injection conditions on the development of high dip reservoirs. The results suggest that the earlier the injection of water and gas, the slower the overall increase in water cut, and the more distinct the oil wall effect after gas injection, leading to a higher ultimate recovery. In the experiments, earlier injection timing can increase the final recovery rate by 9.59%. In addition, a visualized physical simulation device with an adjustable inclination angle has been established to analyze the sweep performance of high dip reservoirs under various gas injection timings. It is concluded that energy supplement in the early stage of pressure decline in the reservoir resulted in a more uniform movement of the oil-water interface at the bottom and the oil-gas interface at the top, and reduced the probability of water and gas channeling. The overall displacement efficiency is found to be improved with this approach. Earlier injection timing increased sweep efficiency by 5.95% and recovery efficiency by 13.2%, respectively. The injection gas source determined in this study, which is associated gas, is beneficial for low carbon plan and exhibits satisfactory oil recovery. The development of high dip reservoirs through top gas injection in combination with bottom water injection can generate a synergistic effect, which significantly enhances sweep efficiency and ultimate oil recovery. This finding provides theoretical guidance for practical implementation in the field.

Paleosalinity is one of the important properties of paleolake water and is crucial for paleoenvironmental and paleoclimatic reconstruction. However, the paleosalinity characteristics of the 1st Member in the Lower Cretaceous Prosopis Formation (P1 Member) from the Baobab North Sag have not been systematically reported until now. In this study, 16 representative mudstone samples were collected from three coring wells and detailed elemental geochemical investigations were presented to reconstruct the salinity and water types for the P1 Member. The results show that the Sr/Ba ratios range from 0.32 to 0.93, indicating fresh water and brackish water, while the B/Ga ratios range from 1.6 to 3.4, also exhibiting the presence of fresh water and brackish water. The equivalent boron contents range from 84.3 ppm to 185 ppm, with the cast point located in the freshwater interval. Moreover, salinity values ranging from 1.2‰ to 11.0‰ for the Adams’ paleosalimeter and from 6.1‰ to 9.3‰ for the Couch’s paleosalimeter are indicative of brackish water, precisely mesohaline water. After sufficiently eliminating the interferences of diagenesis from the results, combined evaluation of evolutionary profiles and cross-plots of paleosalinity proxies suggest that the B/Ga ratio is the most important proxies for distinguishing water salinity types within the studied interval. The results of the B/Ga ratio indicate that the presence of two main water salinity types: fresh water (mainly distributed in the P1⁴ and P1² sub-members) and brackish water (mainly distributed in the P1³ and P1¹ sub-members). Furthermore, high salinity records in the study area correspond to arid climates, while low salinity intervals correspond to semi-arid and humid pulses, which provides a useful reference for the reconstruction of paleosalinity in terrestrial closed lake basins during the Cretaceous global warming period.