In view of reservoirs with low pressure, medium porosity, and low permeability in Changqing Oilfield, along with the “double high stage” in the middle and late development featuring a sharp rise in water cut and a low comprehensive water flooding recovery rate, a study of a composite surfactant flooding system was conducted. It is found that there is a synergistic effect between dodecyl hydroxypropyl sulfobetaine (HPSB) and naphthenic petroleum sulfonate (NPS). When the ratio of HPSB to NPS is 8:2, the best interfacial activity is exhibited in the formation water of the target block, which can reduce the interfacial tension of oil–water equilibrium to 1 × 10⁻³ mN/m and has strong salt tolerance. The synergistic effect of the two makes the composite system have good anti-adsorption performance, with little adsorption loss on the sand surface, and no significant chromatographic separation in the formation. The composite system also has good stability under reservoir conditions. The 0.2% composite surfactant system can reduce the water injection pressure from 1.52 to 1.16 MPa, a decrease of 23.7%; and increase the oil recovery ratio from 45.71 to 63.33%, an increase of 17.62%. These results demonstrate that the composite system (HPSB:NPS = 8:2) has a positive impact on pressure reduction and production increase in the low permeability reservoirs of Changqing Oilfield.

Welan gum is one of the most promising polymers used in polymer flooding for enhancing oil recovery, due to its excellent temperature resistance and salt-tolerance performance. However, welan gum, as a polymer with higher molecular weight, can be adsorbed and detained in the pore throat of the reservoir, which is characterized by a smaller size. Montmorillonite, a kind of clay mineral with high content in reservoir rocks, has strong adsorption capacity. Therefore, the adsorption behavior of welan gum on montmorillonite, as well as its influencing factors, are studied in this paper. The results show that the adsorption capacity is 2.07 mg/g. The adsorption capacity decreased with the increase in temperature. Both acidic and alkaline conditions reduced the adsorption capacity. The existence of inorganic salt affected the adsorption capacity. In addition, the higher the cation value, the lower the adsorption capacity. The characterization tests showed that the adsorption of welan gum on montmorillonite was characterized by physical adsorption and surface adsorption, indicating that there were no changes in the internal structure of montmorillonite. This study provides feasible methods to reduce the amount of welan gum adsorbed on montmorillonite, which is of great significance for reducing the permeability damage caused by welan gum adsorption and promoting the application of welan gum in polymer flooding for enhancing oil recovery.

The evaluation of the basic properties and hydrocarbon generation potential of medium-low maturity shale oil serves as a critical link between geological resources and engineering development. This study focuses on JY oil shale, utilizing analytical techniques including vitrinite reflectance (R₀), total organic carbon (TOC), thermogravimetric analysis (TGA), and Rock-Eval pyrolysis to systematically characterize its geochemical properties. Based on sample characteristics, an in-situ upgrading simulation system was developed and optimized. By comparing nuclear magnetic resonance (NMR) T₁-T₂ spectrum and pyrolysis-gas chromatography/mass spectrometry (PY-GC-MS) results before and after thermal cracking, the research further elucidates the mechanism by which thermal cracking influences the occurrence state of organic matter. Results indicate that the JY shale samples have a TOC content ranging from 1.94% to 2.57%, a total hydrocarbon generation potential (S₁ + S₂) of approximately 21 mg/g, R₀ between 0.66% and 1.18%, and a sapropelinite content in kerogen as high as 90.33%. These parameters classify the kerogen as Type0 I, belonging to medium-low maturity source rocks with high organic matter abundance, favorable pyrolysis characteristics, and significant hydrocarbon generation potential, thus qualifying for in-situ upgrading development. Simulation experiments conducted within the temperature range of 400 °C to 600 °C show that under isothermal conditions at 450 °C for 12 h, the organic carbon degradation rate can reach about 40%, and fracturing measures can enhance the in-situ upgrading effect. After thermal cracking, the proportion of kerogen decreases by approximately 10%, the proportion of adsorbed hydrocarbons increases by about 5%, and the proportion of free hydrocarbons increases by roughly 3%. PY-GC-MS analysis further reveals that the proportion of light hydrocarbons increases significantly by about 20%, while the proportion of heavy hydrocarbons decreases by over 20%, validating the conversion sequence of "heavy hydrocarbons → medium hydrocarbons → light hydrocarbons" during thermal cracking. This study methodologically integrates multi-scale analysis with a self-developed simulation system and mechanistically clarifies the evolution pathway of the three-phase state of organic matter and the trend toward lighter hydrocarbon compositions. It provides theoretical and experimental support for assessing the feasibility of in-situ upgrading development and optimizing techniques for medium-low maturity shale oil, offering valuable insights for mitigating development risks.

Matrix permeability is the primary transport property for shale gas recovery, due to the special production process of gas from matrix to wellbore. With the micro pore size of shale matrix, it is necessary to consider micro transport mechanisms for the obtained permeability from macro experimental techniques. In this study, the macro experimental permeability was investigated in micro way, by the analyzation of pressure drop curves of shale matrix at high- and low-pressure experimental conditions, with modified numerical model containing micro transport mechanisms. As selected parameters, porosity, pore radius and tortuosity were regressed to obtain apparent permeabilities of three samples. The analysis shows that, tortuosity is much higher than macro one, and has been proved to be necessary and reasonable. The Knudsen diffusion and slippage effect control the micro transport of shale matrix at low and high pressure, separately, which is the main difference of macro and micro transports. Slippage flow weight factor helps to increase of slippage flow proportion with pressure. Higher pore radius and tortuosity both could weaken the effect of Knudsen diffusion, and slippage flow appears positive relationship with pore size at high pressure. This research provides an inspiration to shale transport study and a micro perspective theoretical guidance for the macro recovery of in-site shale gas reservoir.

Fractured shale oil reservoirs possess ultra-tight matrix pores and suffer unsatisfactory oil recovery under conventional exploitation, while systematic comparisons among CO₂ flooding, CO₂/CH₄ mixed gas flooding, and multi-component thermal fluid (MTF) flooding remain insufficient for guiding field-parameter design. This work establishes a matrix–fracture coupled dual-porosity compositional model and adopts a single-variable method to quantitatively clarify how injection composition, reservoir permeability, injection pressure, and temperature govern sweep efficiency and the oil recovery factor, as well as the synergistic EOR mechanisms of different displacement fluids. The results show that CH₄ acts as a weak active component with limited crude-oil-swelling and displacement capacities; MTF yields the maximum recovery via thermal viscosity reduction, molecular diffusion, and crude oil swelling, whereas pure CO₂ is reported to have comprehensive cost advantages according to field-scale practical experience (no quantitative techno-economic calculation is carried out in this work). An injection miscibility threshold of 20–30 MPa is identified, with declining incremental oil yield beyond this range. According to published engineering observations, excessively high injection temperatures may trigger liquid-phase permeability impairment, which is not captured in the present model. The oil recovery factor positively correlates with permeability within 0.02–0.1 mD, and volumetric fracturing is indispensable for ultra-low-permeability matrices to expand seepage pathways. This study delivers quantitative theoretical references for displacing-agent screening and injection–production parameter optimization in fractured shale oil reservoirs.

The efficient recovery of shale oil is severely hindered by the strong oil–solid interactions and nanoscale confinement within shale reservoirs, which substantially restrict crude oil mobility. Although surfactant flooding has emerged as an effective enhanced oil recovery technique, the microscopic mechanisms by which cationic surfactants promote oil detachment in nanopores remain insufficiently understood. In this study, molecular dynamics simulations are performed to systematically investigate the interfacial mechanisms of cetyltrimethylammonium bromide (CTAB)-induced oil droplet detachment from nanopore surfaces. The effects of temperature and crude oil composition on the detachment behavior are further evaluated. The results demonstrate that CTAB exhibits the highest oil displacement efficiency among the four investigated surfactants, characterized by the lowest interaction energy and the formation of the most stable interfacial adsorption layer. The CTAB-induced oil detachment process proceeds through three successive stages. CTAB molecules initially migrate to the oil–water interface through hydrophobic interactions, followed by their directional migration toward the oil–solid interface driven by electrostatic interactions, where they induce the formation of hydration channels. Subsequently, hydrogen-bond networks stabilize and expand these hydration channels, ultimately leading to the complete detachment of oil droplets and the formation of stable oil-in-water emulsions. Increasing temperature significantly enhances the interfacial adsorption of CTAB and improves oil displacement efficiency. In addition, crude oil composition exerts a pronounced influence on the detachment process. CTAB exhibits the highest detachment efficiency for the medium crude oil. In contrast, the detachment of heavy oil follows a distinctive two-stage mechanism involving initial aggregate disintegration, followed by interfacial stabilization. This study provides molecular-level insights into the interfacial regulation mechanisms of CTAB in shale nanopores and offers a theoretical foundation for the rational design of high-performance surfactant systems for enhanced shale oil recovery.