Tight oil and gas resources are widely distributed and play an important role in the petroleum industry. Due to its nanoscale pore-throat characteristics, the capillary effect is remarkable, and spontaneous imbibition is very beneficial to the development of low-permeability reservoirs. In this study, the imbibition experiments of 2D nano blackcard, nanoemulsion, and water were carried out, respectively. The pore-throat fluid distribution characteristics before and after core imbibition were analyzed with nuclear magnetic resonance technology, and the enhanced oil recovery effects of 2D nano blackcard nanoemulsion, and water were comprehensively evaluated. The results show that the final recovery factors of cores soaked in 2D nano blackcard (0.005 ωt%) and nanoemulsion (0.02 ωt%) or imbibed in water are 32.29%, 26.05%, and 7.19%, respectively. It can be found that 2D nano blackcard is the fluid with the best imbibition effect. In this work, a new type of 2D nano blackcard was proposed and identified as a functional imbibition fluid for enhanced oil recovery in tight reservoirs, providing a practical reference for the effective development of tight, low-permeability oil and gas reservoirs.

The exploitation of Block L within the Tarim Basin oilfield commenced in 1989 and it has transitioned from the natural energy development stage to the current water injection development stage. Despite this, the efficacy of water flooding remains suboptimal, with the low degree of control, uneven utilization of reserves, and subpar mining outcomes. The block still contains substantial remaining oil resources, necessitating continued extraction. Notably, the primary oil produced in this block is condensate oil, which commands a high economic value. To enhance the oil recovery efficiency of the block reservoir, a development plan employing alternating and water-natural gas flooding has been proposed. The objective of this study is to evaluate the feasibility of the proposed alternating displacement scheme involving natural gas and water in this reservoir. The specific steps include PVT fitting, historical matching, residual oil evaluation, and the optimization of gas injection parameters. Results show that for this reservoir the water-natural gas flooding (WAG) is the optimal option. And this article has the application of WAG flooding simulation, simulating 15 years of operation. Compared with the original development scheme of the original well pattern, the recovery of this reservoir is increased by 12.05%, which provided a reference basis for the on-site application of WAG in this reservoir.

Particle-laden flow through rough confined fractures is controlled by the coupled evolution of particle packing, load-bearing contacts, and rough-wall flow channels. In this study, conductivity experiments were performed on rough split-core fractures prepared from downhole tight-sandstone cores from the Tarim Basin, China, to examine how proppant size mixing and placement sequence regulate flow capacity under closure. Single-size 40/70 and 70/140 proppants and mixed-size systems with different size ratios were tested under staged and uniformly mixed placement schemes. Two equivalent placement levels, denoted as 1 mm and 2 mm, were considered. Three-dimensional laser scanning before and after conductivity testing was used to quantify rough-wall morphology using $R_a$, $R_q$, and $R_z$. The results show that fracture conductivity decreased with increasing closure pressure for all particle systems, indicating progressive narrowing and rearrangement of preferential flow channels. Coarse-particle-dominated systems consistently retained higher conductivity, with an overall ranking of 40/70 > 3:1 > 1:1 > 1:3 > 70/140 at both placement levels. Increasing the placement level from 1 mm to 2 mm markedly enhanced conductivity, especially for systems rich in 40/70 proppant. Staged placement yielded higher conductivity than uniformly mixed placement for the 3:1 and 1:1 systems, but this effect was negligible for the fine-particle-dominated 1:3 system. Post-test roughness changes indicate that sparse placement induced competing smoothing and roughening, whereas sufficient placement caused systematic roughening after closure. The proposed morphology-aware experimental workflow provides a laboratory-scale basis for interpreting the coupled evolution of fracture conductivity and rough-wall morphology in propped rough fractures. Although the workflow can be extended to other lithologies and fracture systems, quantitative field-scale prediction requires further calibration with larger datasets and reservoir-specific conditions.

A tight reservoir has low permeability, low porosity, poor pore-throat connectivity, and strong heterogeneity. Hydraulic fracture is an effective technology to develop such reservoirs. However, in the process of fracturing, fracture fluid will cause damage to the formation. This formation damage can be reduced by nanomaterials due to their nano-level structure. In this paper, experimental studies on the use of nanoemulsion to reduce formation damage caused by fracture fluid are performed through pressure conduction experiments. A low-damage nanofracture fluid system that is suitable for tight reservoirs is optimized, and the injection time is optimized. Finally, a high-efficiency and low-damage nanofracture fluid system that meets the development needs of tight reservoirs is formed. This system provides support for the application of nanomaterials in tight reservoir fracture fluid. Experimental results show that the nanoemulsion fracture fluid can reduce the permeability damage caused by conventional slick water fracture fluid with a removal rate of 16.36% and a recovery rate of 80.00%. The damage rate of nanoemulsion fracture fluid to the fracture surface is 20.33%. The damage rate of the fracture surface under the synergistic effects of nanoemulsion fracture fluid and conventional slick water fracture fluid is between 20.92% and 31.89%. The optimal injection time of nanoemulsion fracture fluid is 2 h.

Continental shale oil reservoirs contain multiscale pore–fracture systems with strong heterogeneity and fractal characteristics, which complicate oil mobilization during post-fracturing shut-in imbibition. In this study, shale cores from the LGS Formation (a lacustrine continental shale oil formation in China) were used to investigate capillary-force-regulated pressurized shut-in imbibition by integrating interfacial tension measurements, apparent contact angle tests, capillary pressure calculation, time-lapse nuclear magnetic resonance (NMR), NMR-based fractal characterization, visual observations, and pre-/post-imbibition permeability measurements. Two surfactant-based imbibition agents with different capillary-force regulation mechanisms were compared to represent different capillary-force regulation pathways. Agent 1 mainly modified apparent wettability, increasing the contact angle from 51.0° to 66.1°, whereas Agent 2 reduced the oil–water interfacial tension from 31.85 to 22.12 mN/m while maintaining a favorable apparent contact angle of 49.3°. Time-lapse NMR results showed that oil recovery increased with shut-in time and reached approximately 12–30% after 144 h. Agent 2 generally produced higher recovery than Agent 1, with the optimum response at 0.15 wt%. NMR-derived fractal dimensions ranged mainly from 2.32 to 2.61, confirming the multiscale heterogeneity of the LGS shale pore system. Pore-size-resolved recovery further showed that oil mobilization was dominated by pores larger than 20 nm and microfracture-related spaces, whereas pores smaller than 20 nm contributed only limited bulk recovery. This indicates an apparent nanopore mobilization threshold near 20 nm, controlled by fractal pore complexity, pore-throat connectivity, oil adsorption, capillary pressure, and molecular accessibility of imbibition agents. Visual and permeability evidence further showed that pressurized imbibition can selectively activate connected pore–fracture pathways. Post-imbibition dry-core permeability increased in all tested samples, although the enhancement was highly heterogeneous. These results demonstrate that shut-in imbibition in LGS shale is governed by coupled interfacial regulation, fractal pore heterogeneity, pore-size-dependent oil accessibility, and selective pore–fracture structural modification.

Bedding fractures strongly influence pore structure and anisotropic flow capacity in laminated shale oil reservoirs, but conventional porosity–permeability relationships cannot adequately explain permeability differences caused by bedding orientation and fracture connectivity. This problem represents an important gap in shale oil reservoir evaluation because cores with similar porosity may exhibit markedly different permeability when bedding-fracture connectivity and flow direction differ. The main question addressed in this study is how bedding-fracture structures in paired horizontal and vertical LGS shale oil cores selected from the same depth intervals influence porosity, permeability, and permeability anisotropy. To answer this question, this study establishes a quantitative framework linking X-ray computed tomography-derived bedding-fracture structure, three-dimensional fractal dimension, and stress-sensitive permeability anisotropy in LGS shale oil cores. Paired horizontal and vertical cores from the same depth intervals were tested under confining pressures of 10–50 MPa. X-ray computed tomography reconstruction was used to extract bedding-fracture volume fraction $V_f,$ fracture number $N_b$, fracture density ${\rho }_b$, connectivity index $C_b$, and three-dimensional box-counting fractal dimension $D_3$. The H-series cores exhibit much higher bedding-parallel permeability than the V-series cores, although their porosity ranges partly overlap. At 10 MPa, the average permeability of the H-series is 0.24402 mD, approximately 21.7 times that of the V-series 0.01127 mD. As confining pressure increases from 10 to 50 MPa, the average permeability decreases by approximately 97.1% for the H-series and 96.5% for the V-series, indicating strong stress sensitivity of bedding-fracture-controlled flow channels. The $D_3$ values range from 2.16 to 2.63 for the H-series and from 2.12 to 2.56 for the V-series. Higher $D_3$, $V_f$, and $C_b$ enhance permeability when bedding fractures are aligned with the flow direction, whereas complex but discontinuous bedding structures may still result in low bedding-normal permeability. A fractal-corrected porosity–permeability model incorporating $\phi$, $V_f$, $C_b$, and $D_3$ is proposed to improve permeability interpretation beyond porosity alone. This study demonstrates that permeability anisotropy in LGS shale oil cores is controlled by the combined effects of pore–fracture volume, directional connectivity, fractal complexity, and stress-induced fracture closure.