CO₂-enhanced oil recovery (CO₂-EOR) is a crucial method for CO₂ utilization and sequestration, representing an important zero-carbon or even negative-carbon emission reduction technology. However, the low viscosity of CO₂ and reservoir heterogeneity often result in early gas breakthrough, significantly reducing CO₂ utilization and sequestration efficiency. A water-alternating-gas (WAG) injection is a technique for mitigating gas breakthrough and viscous fingering in CO₂-EOR. However, it encounters challenges related to insufficient mobility control in highly heterogeneous and fractured reservoirs, resulting in gas channeling and low sweep efficiency. Despite the extensive application and research of a WAG injection in oil and gas reservoirs, the most recent comprehensive review dates back to 2018, which focuses on the mechanisms of EOR using conventional WAG. Herein, we give an updated and comprehensive review to incorporate the latest advancements in CO₂-WAG flooding techniques for enhanced sweep efficiency, which includes the theory, applications, fluid displacement mechanisms, and control strategies of a CO₂-WAG injection. It addresses common challenges, operational issues, and remedial measures in WAG projects by covering studies from experiments, simulations, and pore-scale modeling. This review aims to provide guidance and serve as a reference for the application and research advancement of CO₂-EOR techniques in heterogeneous and fractured reservoirs.

Predicting carbon dioxide (CO₂) solubility in water and brine is crucial for understanding carbon capture and storage (CCS) processes. Accurate solubility predictions inform the feasibility and effectiveness of CO₂ dissolution trapping, a key mechanism in carbon sequestration in saline aquifers. In this work, a comprehensive data set comprising 1278 experimental solubility data points for CO₂-brine systems was assembled, encompassing diverse operating conditions. These data encompassed brines containing six different salts: NaCl, KCl, NaHCO₃, CaCl₂, MgCl₂, and Na₂SO₄. Also, this databank encompassed temperature spanning from 273.15 to 453.15 K and a pressure range spanning 0.06-100 MPa. To model this solubility databank, cascade forward neural network (CFNN) and generalized regression neural network (GRNN) were employed. Furthermore, three optimization algorithms, namely, Bayesian Regularization (BR), Broyden-Fletcher-Goldfarb-Shanno (BFGS) quasi-Newton, and Levenberg-Marquardt (LM), were applied to enhance the performance of the CFNN models. The CFNN-LM model showcased average absolute percent relative error (AAPRE) values of 5.37% for the overall data set, 5.26% for the training subset, and 5.85% for the testing subset. Overall, the CFNN-LM model stands out as the most accurate among the models crafted in this study, boasting the highest overall R² value of 0.9949 among the other models. Based on sensitivity analysis, pressure exerts the most significant influence and stands as the sole parameter with a positive impact on CO₂ solubility in brine. Conversely, temperature and the concentration of all six salts considered in the model exhibited a negative impact. All salts exert a negative impact on CO₂ solubility due to their salting-out effect, with varying degrees of influence. The salting-out effects of the salts can be ranked as follows: from the most pronounced to the least: MgCl₂ > CaCl₂ > NaCl > KCl > NaHCO₃ > Na₂SO₄. By employing the leverage approach, only a few instances of potential suspected and out-of-leverage data were found. The relatively low count of identified potential suspected and out-of-leverage data, given the expansive solubility database, underscores the reliability and accuracy of both the data set and the CFNN-LM model's performance in this survey.

Global oil and gas resources are declining continuously, and sustainable development has become a common challenge worldwide. In terms of environmental protection and economic benefits, the application of microemulsions for enhanced oil recovery often requires fewer chemical agents, showing distinct advantages. This paper analyzes the application prospects and trends of middle-phase microemulsions in tertiary oil recovery. The properties of middle-phase microemulsions are introduced, and an overview of the historical development, theoretical framework, influencing factors, and preparation methods of emulsions are provided. From the perspective of oil displacement systems, this paper reviews the selection and characterization methods of emulsions, as well as the interaction mechanisms between emulsions and reservoirs, proposing future research directions. The focus of the paper is on the evaluation and characterization of emulsions, the mechanisms of micro-oil displacement, and the application of advanced CT scanning technology, which gives a new understanding of wettability changes, capillary forces, and miscible solubilization processes, contributing to the reduction in displacement costs and the improvement of economic benefits. In conclusion, the middle-phase microemulsion flooding technique can significantly enhance oil recovery through the comprehensive action of various mechanisms and has been widely used in oil field development.

Oil reservoirs are one of the most important deep subsurface biospheres. They are inhabited by diverse microorganisms including bacteria and archaea with diverse metabolic activities. Although recent studies have investigated the microbial communities in oil reservoirs at large geographic scales, it is still not clear how the microbial communities assemble, as the variation in the environment may be confounded with geographic distance. In this work, the microbial communities in oil reservoirs from the same oil field were identified at a localized geographic scale. We found that although the injected water contained diverse exogenous microorganisms, this had little effect on the microbial composition of the produced water. The Neutral Community Model analysis showed that both bacterial and archaeal communities are dispersal limited even at a localized scale. Further analysis showed that both pH and nitrate concentrations drive the assembly of bacterial communities, of which nitrate negatively correlated with bacterial alpha diversity and pH differences positively correlated with the dissimilarity of bacterial communities. In contrast, the physiochemical parameters had little effect on archaeal communities at the localized scale. Our results suggest that the assembly of microbial communities in oil reservoirs is scale- and taxonomy-dependent. Our work provides a comprehensive analysis of microbial communities in oil reservoirs at a localized geographic scale, which improves the understanding of the assembly of the microbial communities in oil reservoirs.

Biosurfactants have significant applications in various industries, including microbial-enhanced oil recovery (MEOR). While the state-of-the-art genetic approaches can generate high-yield strains for biosurfactant production in fermenters, there remains a critical challenge in enhancing biosurfactant-producing strains for use in natural environments with minimal ecological risks. The objectives of this work are enhancing the strain’s capacity for rhamnolipids production and exploring the genetic mechanisms for its improvement. In this study, we employed atmospheric and room-temperature plasma (ARTP) mutagenesis to enhance the biosynthesis of rhamnolipids in Pseudomonas sp. L01, a biosurfactant-producing strain isolated from petroleum-contaminated soil. Following ARTP treatment, we identified 13 high-yield mutants, with the highest yield of 3.45 ± 0.09 g/L, representing a 2.7-fold increase compared to the parent strain. To determine the genetic mechanisms behind the enhanced rhamnolipids biosynthesis, we sequenced the genomes of the strain L01 and five high-yield mutants. A comparative genomic analysis suggested that mutations in genes related to the synthesis of lipopolysaccharides (LPS) and the transport of rhamnolipids may contribute to the improved biosynthesis. To the best of our knowledge, this is the first instance of utilizing the ARTP approach to improve rhamnolipid production in Pseudomonas strains. Our study provides valuable insights into the enhancement of biosurfactant-producing strains and the regulatory mechanisms of rhamnolipids biosynthesis.

The urgent problem to be solved in heavy oil exploitation is to reduce viscosity and improve fluidity. Emulsification and viscosity reduction technology has been paid more and more attention and its developments applied. This paper studied the viscosity reduction performance of three types of viscosity reducers and obtained good results. The viscosity reduction rate, interfacial tension, and emulsification performance of three types of viscosity reducers including anionic sulfonate, non-ionic (polyether and amine oxide), and amphoteric betaine were compared with Daqing crude oil. The results showed that the viscosity reduction rate of petroleum sulfonate and betaine was 75–85%. The viscosity reduction rate increased as viscosity reducer concentration increased. An increase in the oil–water ratio and polymer decreased viscosity reduction. When the concentration of erucamide oxide was 0.2%, the ultra-low interfacial tension was 4.41 × 10⁻³ mN/m. When the oil–water ratio was 1:1, the maximum water separation rates of five viscosity reducers were different. With an increase in the oil–water ratio, the emulsion changed from o/w emulsion to w/o emulsion, and the stability was better. Erucamide oxide and erucic betaine had good viscosity reduction and emulsification effects on Daqing crude oil. This work can enrich knowledge of the viscosity reduction of heavy oil systems with low relative viscosity and enrich the application of viscosity reducer varieties.