Summary: Due to the low porosity and permeability of the shale matrix, multi-fractured horizontal well (MFHW) is one of the most well-known technologies to promote the withdrawal of shale oil. It is a great challenge to characterize the flow behavior by coupling pre-Darcy flow in pores of the shale matrix and Darcy flow inside fractures, particularly in the radial composite shale reservoir with stimulated reservoir volume (SRV). Because the semi-analytical method can contribute to revealing the flow mechanism of the MFHW, the approach to efficiently obtain a suitable and exact semi-analytical solution becomes a key issue. In this work, to couple the modified point-source solution of the shale matrix with the numerical solution of fractures,we developed a semi-analytical solution to analyze the impact of pre-Darcy flow and SRV properties on the pressure behavior of the MFHW. Moreover, we used a local grid refinement method to verify the accuracy of the newly developed semi-analytical solution. The results show that the radial flow regime in the dimensionless pressure derivative will obviously disappear due to the pre-Darcy flow. Pre-Darcy flow in the SRV zone is adverse to the late production of the MFHW after the pseudolinear flow regime, while pre-Darcy flow in the unstimulated reservoir volume (USRV) zone is beneficial to increase the production during the regional interporosity flow regime. Meanwhile, the “groove” can be recognized from the pressure derivative curves, which mainly depend on the mobility ratio and the storage capacity ratio. In addition, due to the uneven distribution of fractures, the pressure derivative during the pseudoradial flow regime significantly deviates from 1/(2N).

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.

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.

In order to investigate energy supply capacity and oil production contribution of near-fracture and fracture-free zone in fractured tight oil reservoirs, a series of CO₂ huff-and-puff tests were designed and carried out in different experimental conditions. A fracture-matrix long-core system was established to simulate the near-fracture zone and matrix zone of tight oil reservoirs. The NMR technique was utilized to identify the microscopic remaining oil of certain core samples. The effects of fracture length, soaking time, depressurization method, and asphaltene precipitation on the oil recovery performance of CO₂ huff-and-puff process were evaluated, respectively. The results indicated that the dissolution and diffusion range of the injected CO₂ can be apparently increased from both macro and micro aspects through increasing the length or density of the fractures and extending the soaking time; and, during puff period, the slow depressurization method has better recovery effect on near-fracture zone, while the step depressurization method has better recovery effect on distal fracture-free matrix. After CO₂ huff-and-puff process, the oil recovery of the medium pores near fracture could be close to oil recovery of the large pores, which is higher than 60. But, in the distal matrix, the oil recovery of the medium pores was only a little higher than depletion development. The remaining oil of medium pores in distal fracture-free matrix still has great potential to be developed after CO₂ huff-and-puff process.

Polymer flooding has been proved by many scholars for use in heavy oil reservoirs. However, due to mobility control effects and injectivity, selecting the appropriate solution viscosity is essential. It is difficult to form a deep understanding of the effect and mechanism of polymer flooding using conventional experimental methods with oil recovery as the reference standard, so it is necessary to conduct further study with the aid of simulation methods. In this study, a one-dimensional displacement mathematical model based on the Buckley–Leverett theory was established, and in the range of water–oil viscosity ratio from 0.1 to 0.6, the variation of water saturation along the flow caused by polymer solution was studied. The research results showed that under the action of a polymer solution, compared with water flooding, there was a decreasing region of water saturation along the flow due to oil phase accumulation. The larger the water–oil viscosity ratio, the larger the area of water saturation decline and the greater the degree of water saturation decline, resulting in a better the displacement effect. However, under the condition of oil–phase viscosity of 70 mPa·s, when the water–oil viscosity ratio reached 0.4, the range and degree of water saturation decline along the way no longer changed, all the crude oil that could be swept had been displaced, and the outlet end was close to producing only water, not oil; therefore, further increasing the water–oil viscosity ratio could not increase the oil recovery. At the same time, the increase in pressure had not changed, that is, the increase in pressure had not resulted in the same increase in oil recovery. When the viscosity of oil phase increased to 140 mPa·s, the same rule was displayed, the appropriate water–oil viscosity ratio was also 0.4. The paper analyzed the action mechanism of polymer solution through process description, and the results provided a clear selection method for selecting reasonable polymer solution concentration, as well as a reference for polymer solution range under different crude oil viscosity conditions.