Recovery mechanisms and formation influencing factors of miscible CO2 huff-n-puff processes in shale oil reservoirs: A systematic review

The goals of carbon neutrality and peak carbon have officially been proposed; consequently, carbon dioxide utilization and sequestration technology are now in the limelight. Injecting carbon dioxide into reservoirs and solidifying and sequestering it in the form of carbonates after a series of geochemical reactions not only reduces carbon emissions but also prevents carbon dioxide from leaking out of the formation. Carbon dioxide mineralization sequestration, which has good stability, has been considered the best choice for large-scale underground CO₂ sequestration. To provide a comprehensive exploration of the research and prospective advancements in CO₂ mineralization sequestration within Chinese oil and gas reservoirs, this paper undertakes a thorough review of the mechanisms involved in CO₂ mineralization and sequestration. Special attention is given to the advancing front of carbon dioxide mineralization, which is driven by microbial metabolic activities and the presence of carbonic anhydrase within oil and gas reservoirs. The paper presents an in-depth analysis of the catalytic mechanisms, site locations, and structural attributes of carbonic anhydrase that are crucial to the mineralization processes of carbon dioxide. Particular emphasis is placed on delineating the pivotal role of this enzyme in the catalysis of carbon dioxide hydration and the promotion of carbonate mineralization and, ultimately, in the facilitation of efficient, stable sequestration.

Shut-in after fracturing is generally adopted for wells in shale oil reservoirs, and imbibition occurring in matrix nanopores has been proven as an effective way to improve recovery. In this research, a molecular dynamics (MD) simulation was used to investigate the effects of wettability and pressure on nanopore imbibition during shut-in for a typical shale reservoir, Jimsar. The results indicate that the microscopic advancement mechanism of the imbibition front is the competitive adsorption between “interfacial water molecules” at the imbibition front and “adsorbed oil molecules” on the pore wall. The essence of spontaneous imbibition involves the adsorption and aggregation of water molecules onto the hydroxyl groups on the pore wall. The flow characteristics of shale oil suggest that the overall push of the injected water to the oil phase is the main reason for the displacement of adsorbed oil molecules. Thus, shale oil, especially the heavy hydrocarbon component in the adsorbed layer, tends to slip on the walls. However, the weak slip ability of heavy components on the wall surface is an important reason that restricts the displacement efficiency of shale oil during spontaneous imbibition. The effectiveness of spontaneous imbibition is strongly dependent on the hydrophilicity of the matrix pore’s wall. The better hydrophilicity of the matrix pore wall facilitates higher levels of adsorption and accumulation of water molecules on the pore wall and requires less time for “interfacial water molecules” to compete with adsorbed oil molecules. During the forced imbibition process, the pressure difference acts on both the bulk oil and the boundary adsorption oil, but mainly on the bulk oil, which leads to the occurrence of wetting hysteresis. Meanwhile, shale oil still existing in the pore always maintains a good, stratified adsorption structure. Because of the wetting hysteresis phenomenon, as the pressure difference increases, the imbibition effect gradually increases, but the actual capillary pressure gradually decreases and there is a loss in the imbibition velocity relative to the theoretical value. Simultaneously, the decline in hydrophilicity further weakens the synergistic effect on the imbibition of the pressure difference because of the more pronounced wetting hysteresis. Thus, selecting an appropriate well pressure enables cost savings and maximizes the utilization of the formation’s natural power for enhanced oil recovery (EOR).

Microemulsion flooding technology, known for significantly reducing interfacial tension, improving rock wettability, and providing strong driving forces at the microscopic level, has been widely applied in enhancing oil recovery in oil fields. This article summarizes the relevant literature and introduces the classification, formation mechanisms, research models, and factors affecting the performance of microemulsions. Particularly, it conducts a comparative analysis of microemulsion systems formed by surfactant molecules of different structures, aiming to provide new perspectives for the study of surfactant molecular structures and to further optimize the performance of microemulsion systems. The study finds that modifying surfactant molecules by adding benzene rings, increasing the length of hydrophobic tails, and enlarging hydrophilic heads can significantly increase the volume of the middle phase, exceeding 30%. These findings provide important guidance for optimizing microemulsion systems.

Study on the mechanism of surfactant flooding: Effect of betaine structure

Carbon dioxide flooding is a strategic replacement technology for greatly enhancing oil recovery in low-permeability oilfields, which includes social benefits resulting from carbon emission reduction and economic benefits owing to the improvement of oil recovery. Therefore, it is of great significance to develop and apply the technology of CO₂ flooding and storage in the petroleum industry. In reservoir conditions, CO₂ is usually under a supercritical state, presenting both low viscosity and high diffusivity of a gaseous state and high density of a liquid state. The special phase behavior of CO₂ directly affects its extraction capacity, resulting in the change of miscible behavior between CO₂ and crude oil. In this paper, the ultra-high-pressure–high-temperature pressure–volume–temperature (PVT) system was used to evaluate the phase characteristics of CO₂ during the process of reservoir development. The phase behaviors of the CO₂/CH₄/N₂ crude oil system were compared and analyzed. Moreover, the matching mechanism between supercritical CO₂ characteristics and oil–gas system miscibility was investigated and defined. This work deepened the understanding of the phase characteristics of CO₂ in the process of miscible flooding, providing both theoretical guidance for the application of CO₂ injection on oilfields and the essential scientific basis for the implementation of CCUS-EOR technology.