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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.

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 (R 0 ), 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) T 1 -T 2 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 (S 1  + S 2 ) of approximately 21 mg/g, R 0 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.

In the development of heavy oil fields in the Bohai Sea, the “horizontal + directional” well pattern has significantly improved recovery rates. However, as the oilfield enters the ultra-high water cut stage, changes in waterflooding behavior and production characteristics lead to a more complex distribution of remaining oil, posing challenges for subsequent development. This study introduces a dynamic interference analysis method that integrates three-dimensional (3D) physical modeling with numerical simulation. The method optimizes the interference prediction model under the “horizontal + directional” well pattern, aiding in well placement optimization and enhancing development efficiency during the ultra-high water cut period. Additionally, a phenomenon was observed where remaining oil concentrates in the central segment during the displacement process. Through numerical simulations under varying permeability rhythms, the impact of the injection-production relationship on the distribution of remaining oil was revealed, providing a theoretical foundation for well pattern optimization. The findings offer technical support for the continued development of Bohai Oilfields under ultra-high water cut conditions and provide valuable guidance for other offshore heavy oil fields. The new methods proposed in this study can improve recovery rates in complex waterflood environments.

Shale reservoirs feature widely developed nanopores, and the diverse crystal structures and surface functional groups of constituent minerals induce pronounced wettability heterogeneity, rendering conventional experimental methods incapable of characterizing nanoscale interfacial evolution. This work aims to reveal the multi-factor regulated wettability mechanisms of typical shale minerals at the molecular scale. Coupled molecular dynamics (MD) and grand canonical Monte Carlo (GCMC) simulations are performed on four shale minerals (hydroxylated graphene, quartz, calcite, kaolinite) under single-factor conditions (313–373 K, 10–40 MPa, 4–10 nm pores) and coupled pressure–pore deformation scenarios (15–35 MPa, 4–9.1 nm), with wetting mechanisms elucidated from hydrogen bond evolution, water molecular packing, nanoconfinement effect, and mineral crystal structure. The results show that rising temperature linearly reduces contact angles (average 0.33–0.35°/K) by strengthening hydrogen bonding; elevated pressure impairs wettability, with calcite exhibiting the highest-pressure sensitivity; nanoconfinement dominates pore scale wetting; and quartz presents the strongest pore size dependence. Synchronous pressure–pore expansion generates a superimposed wettability deterioration effect. This study quantifies the wettability evolution laws of shale minerals under diverse conditions, providing microscopic theoretical support for reservoir stimulation and enhanced oil recovery.

The findings of this study can be applied to the development of shale oil reservoirs dominated by mesopores. Adding surfactants to fracturing fluids can enhance imbibition, thereby improving shale oil recovery. Spontaneous imbibition modified by surfactants is a key technology for enhancing shale oil recovery. Currently, relevant studies mainly concentrate on marine shale worldwide, while the pore–fluid coupling characteristics of widely distributed medium-TOC terrestrial shale remain poorly understood. Against this background, this paper takes typical Paleogene terrestrial shale as the research object and integrates N[sub.2]/CO[sub.2] adsorption and NMR T[sub.2] spectroscopy to jointly characterize multiscale pore structures and dynamic fluid evolution during imbibition. The results show that the shale is dominated by mesopores in terms of pore volume, while micropores provide most of the specific surface area. The zwitterionic surfactant HPSB can greatly reduce oil–water interfacial tension and alter rock wettability, thereby breaking the high capillary resistance of micropores. During imbibition, water invades macropores first, followed by mesopores and micropores, and the entire process exhibits remarkable nonlinear dynamics controlled by multiscale pores. The 0.15% HPSB solution shows the best effect on activating micropores. This study innovatively quantifies the influence of surfactant concentration on fluid migration across different pore scales and reveals the internal mechanism of staged imbibition and micropore lag activation in terrestrial shale. It not only complements the global research system of shale imbibition theory but also offers practical guidance for the optimization of fracturing fluid systems in mesopore-dominated shale oil reservoirs.

The efficiency of liquid unloading in dewatering wells directly affects the performance of the Liaohe Ma-19 gas storage facility—the first strongly water-flooded depleted reservoir in China converted for storage use. However, existing hydraulic jet pumps often exhibit low liquid-removal efficiency and capacity mismatches with field operating conditions. To address these limitations, a gas-powered negative-pressure pump system was developed based on gas dynamics principles. Using a custom-built flow loop with injection pressures up to 10 MPa and flow rates of 500–1200 m3/h, the effects of backpressure, nozzle-to-throat area ratio, and formation pressure on pump performance were systematically investigated. The results indicate that an optimal nozzle-to-throat area ratio of 0.19 achieves critical gas velocity at the throat, maximizing the negative pressure effect. Compared with conventional hydraulic jet pumps, the gas-driven system reduces start-up pressure by 87% and increases pressure drawdown by over 50%, while eliminating post-shut-in liquid accumulation through the use of compressed gas as the power fluid. This study demonstrates that the proposed system offers an efficient and reliable artificial lift solution for liquid unloading in gas storage operations.

Developing unconventional reservoirs through gas injection has become increasingly popular in recent years. Among the various injector gases, hydrocarbon gas is considered one of the most promising fluids for use in the EOR process. In this study, molecular dynamics simulations have been utilized to generate insights into the tight oil migration under six different hydrocarbon gas composition ratios. Simulation results indicate that the migration process of the oil-gas mixture occurs in stages, but the overall states of all systems remain relatively consistent. As the proportion of heavy components (ethane and propane) in the hydrocarbon gas increases, the threshold migration resistance of each system exhibits a pattern of initially decreasing and then increasing. The mechanism underlying the nonlinear evolutionary trend of migration resistance was clarified through analyzing dynamic interactions and interfacial tension characteristics. The essence lies in the fact that the hindrance effect caused by increasingly stronger oil/gas-pore interactions eventually outweighs the drag reduction effect induced by the gradual reduction of oil/gas-water interfacial tension. Based on migration characteristics and sensitivity factors, we propose that the optimal hydrocarbon gas composition ratio for methane/ethane/propane is in the range of 80/10/10 to 70/15/15. Overall, this study focuses on employing molecular dynamics simulations to analyze the oil-gas migration characteristics at the nanoscale, aiming to provide more detailed insights for microscopic analysis and theoretical support for tight oil development.

Shale oil reservoirs, as an unconventional hydrocarbon resource, have the potential to substitute conventional hydrocarbon resources and alleviate energy shortages, making their exploration and development critically significant. However, due to the low permeability and the development of nanopores in shale reservoirs, shale oil production is challenging and recovery efficiency is low. During the imbibition stage, fracturing fluid displaces the oil in the pores primarily under capillary forces, but the complex pore structure of shale reservoirs makes the imbibition mechanism unclear. This research studies the imbibition flow mechanism in nanopores based on the capillary force model and two-phase flow theory, coupled with numerical simulation methods. The results indicated that within a nanopore diameter range of 10–20 nm, increasing the pore diameter leads to a higher imbibition displacement volume. Increased pressure can enhance the imbibition displacement, but the effect diminishes gradually. Under the water-wet conditions, the imbibition displacement volume increases as the contact angle decreases. When the oil phase viscosity decreases from 10 mPa·s to 1 mPa·s, the imbibition displacement rate can increase by 72%. Moreover, merely increasing the water phase viscosity results in only a 5% increase in the imbibition displacement rate. The results provide new insights into the imbibition flow mechanism in nanopores within shale oil reservoirs and offer a theoretical foundation and technical support for efficient shale oil development.

The effective displacement of the shale oil from organic nanopores plays a significant role in development of the shale oil reservoirs. In order to deeply understand the microscopic displacement mechanism of alkane of shale oil by CO2 in organic nanopores, microscopic pore model of organic matter and molecular model of CO2 and n-dodecane were established to investigate the influences of key parameters on the displacement process by using the Monte Carlo and molecular dynamics simulation method. The instantaneous adsorption of molecules demonstrates that the displacement of n-dodecane and the adsorption of CO2 are proportional to the increase of the injection pressure of CO2 as well as the pore size. In addition, the results also show that the adsorption capacity of CO2 first increases and then decreases with the increase of the temperature, which indicates that the optimum temperature exists for the adsorption of CO2. This work can provide critical insights into understanding the microscopic displacement mechanism of shale oil by CO2 in organic nanopores in shale oil reservoirs and lay a solid foundation for the CO2 flooding in the shale oil reservoir and the CO2 storage.

Refracturing treatment is widely used to enhance the well productivity in shale gas reservoirs, particularly for initially fractured wells with low productivity. The principal of this work is based on the transient behavior of pressure and rate for a vertically refractured well in a shale gas reservoir, considering the fracture reorientation and adsorption and desorption property. Based on the point-source theory and Laplace transform, a semi-analytical solution for a refractured well is obtained by coupling the point-source solution of a shale gas reservoir and the solution of artificial fractures. The validation of this new solution is carried out smoothly by comparison with the results from the commercial software COMSOL. Five typical flow regimes are identified on the transient pressure curve, namely bi-linear flow regime, formation linear flow regime, mid-radial flow regime, inter-porosity flow regime, and pseudo-radial flow regime. A groove segment occurs on the transient-pressure derivative curve, and its width and depth largely depend on the adsorption and desorption constant and storativity ratio. Due to fracture reorientation, bi-linear flow regime, formation linear flow regime, and mid-radial flow regime may be significantly impacted. In addition, the transient rate of the refractured well in a shale gas reservoir is positively proportional to the storativity ratio, inter-porosity coefficient, and adsorption and desorption constant, while it is inversely proportional to fracture reorientation. These results provide important references for parameter design, property inversion, and productivity prediction of refracturing treatment in shale gas reservoirs.