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For the change in unpropped fracture conductivity after fracturing in tight sandstone gas reservoirs, an experimental method for unpropped fracture conductivity evaluation with fracture wall simulation was established to investigate the damage mechanism of conductivity in terms of the microscopic morphology, roughness, strength and other aspects of the fracture wall, and to clarify the variation law of fracture conductivity. The study shows that after the fracture was exposed to water, the wall clay was hydrated and compacted under stress, and the average height of the wall was decreased by 8. 5%; meanwhile, the fracture wall was softened and the average hardness decreased by 34. 3%. The more frequent the change in production nozzle size, the higher the conductivity of the unpropped frac- ture under high stress; the fracture conductivity of the third well opening was 91. 7%-98. 5% lower than that of the first well opening; the conductivity of misaligned fractures was 18. 1-140. 4 times that of non-misaligned fractures. With the formation water displacing fracturing fluid after fracturing, the conductivity of the final fracture was 3. 45 times that of the original fracture. In this paper, the conductivity damage mechanism in the production of tight gas reservoirs was defined, and the variation law of unpropped fracture conductivity under the action of different factors was clarified, which provides a basic theoretical basis for the protection of unpropped fractures in tight sandstone gas reservoirs. [ABSTRACT FROM AUTHOR]

AbstractW/O emulsification in the J-7 reservoir has been regarded as the main reason for enhancing oil recovery. Therefore, in this article, the chemical structures of SARA fractions of JD-1 crude oil were obtained through characterization experiments, and the effect of the influence of SARA fractions on the W/O emulsification and the oil recovery by using emulsification experiments, interfacial experiments, emulsification experiments, and water flooding experiments. Results showed from emulsification experiments that the emulsification degree of the simulated oil containing asphaltenes was higher than other simulated oils. All emulsions of SARA fractions after emulsifying were W/O emulsions, but compared with other components, the performance of emulsions of asphaltenes was the best. The viscosity of emulsions reached 8.16–18.38 times that of simulated oil, the average size of was only 0.68 μm, and the stability was also very good. From interface tension and expansion modulus experiments, it can be seen that after adding asphaltenes, the decrease degree of interface tension and the increased degree of expansion modulus were the most. The result of molecules dynamic simulations showed that the adsorption force on the oil-water interface of asphaltenes was greater than other components. The water flooding experiments found the recovery of the simulated oil containing asphaltenes reached 43.81%, which was higher than other simulated oil, indicating that the easier W/O emulsification was formed, the recovery rate was higher. [ABSTRACT FROM AUTHOR]

The technology of CO 2 -enhanced gas recovery (CO 2 -EGR) plays a pivotal role in the CCUS (Carbon Capture, Utilization, and Storage) industry, which helps to achieve a win-win situation of economic benefit and environmental benefit for gas fields. Shale gas reservoirs, with their unique geological and surface engineering advantages, are one of the most promising options for CCUS implementation. Focusing on shale formations within the mid-deep blocks of the Sichuan Basin, this study conducted competitive adsorption experiments using multicomponent gases. Through physical simulations and single-well numerical modeling, factors such as injection volume, timing, shut-in time, and huff-n-puff rounds were examined for their impact on recovery. The results show that the higher the CO 2 content in the injected medium, the more pronounced advantage in gas adsorption on shale surfaces. Optimal performance was achieved with a CO 2 content in the injection medium of 80% to 100%, an injection volume of 0.2-0.3 PV, a shut-in time exceeding 6 h, and a relatively delayed injection timing. The recovery in the first round of huff-n-puff was increased by 24.2% to 47.8%, which gave a full play to the role of huff-n-puff and achieved favorable benefits. Based on the middle-deep geological parameters, a single-well numerical simulation was established, which demonstrates that single-well EUR (estimated ultimate recovery) can be increased by 14.2% to 19.8% compared to gas wells without CO 2 injection. This study provides essential guidance for the enhanced recovery in shale gas reservoirs through CO 2 huff-n-puff., Competing Interests: The authors declare no competing financial interest., (© 2024 The Authors. Published by American Chemical Society.)