陕西延长石油(集团)有限责任公司

Objective The Benxi Formation in the East Yanchuan Block of the southeastern Ordos Basin has emerged as a significant exploration target for tight gas reservoirs. Despite its strategic importance, the sandstone reservoirs in this interval are typically characterized by low porosity, poor permeability, strong heterogeneity, and complex diagenetic histories. These characteristics limit their development potential and make accurate reservoir prediction challenging. This study aims to thoroughly investigate the reservoir characteristics and diagenetic evolution of the Benxi Formation sandstones, with the goal of clarifying how multi-stage diagenetic processes control pore evolution and reservoir quality differentiation. Methods An integrated analytical approach was applied, including casting thin section petrography, scanning electron microscopy (SEM), and high-pressure mercury intrusion (HPMI). These techniques were used to examine pore types, mineral assemblages, diagenetic alterations, and pore-throat distributions, allowing for a detailed reconstruction of the diagenetic evolution and its influence on petrophysical properties. Results The study reveals: (1) The Benxi Formation sandstones have undergone a multi-stage diagenetic evolution involving three principal phases: mechanical compaction, cementation enhancement, and dissolution modification. Each stage had a distinct influence on the pore structure and reservoir performance. (2) Quartz-rich sandstones showed relatively high resistance to mechanical compaction but experienced substantial porosity loss during the middle diagenetic stage due to the pervasive precipitation of quartz and carbonate cements. This stage led to the formation of a rigid framework, where the intergranular pores were severely occluded, significantly reducing effective porosity and permeability. (3) Lithic quartz sandstones exhibited a much more favorable diagenetic trajectory. These rocks experienced strong dissolution of unstable components, such as feldspar and lithic fragments, resulting in the formation of secondary intragranular and intergranular pores. This process markedly improved pore connectivity and storage capacity, making this lithofacies the most favorable for tight gas accumulation. (4) Lithic sandstones suffered from intense early-stage compaction and cementation, which drastically reduced both primary and secondary porosity. As a result, these rocks exhibit extremely poor reservoir quality and are considered the least favorable reservoir type. (5) Based on the observed differences in diagenetic intensity and pore evolution characteristics, four distinct diagenetic facies types were identified. Conclusion (1) The reservoir quality of the Benxi Formation sandstones is primarily controlled by the intensity and sequence of compaction, cementation, and dissolution. (2) Different mineral compositions lead to divergent diagenetic pathways and contrasting pore evolution patterns. (3) Lithic quartz sandstones hold the highest potential due to extensive dissolution, while quartz sandstones are more susceptible to cementation. (4) Lithic sandstones, dominated by early-stage densification, represent poor-quality reservoirs. (5) The proposed four-type diagenetic facies framework effectively reflects the reservoir heterogeneity and offers practical criteria for facies-based reservoir prediction. [Significance] This study advances the understanding of diagenetic control on pore structure in tight sandstone reservoirs and provides a robust geological foundation for classifying and predicting reservoirs and targeting sweet spots in future exploration efforts.

CO2 sweep efficiency and gas channeling are key factors restricting the effectiveness of CO2 flooding in low-permeability tight reservoirs. To address the technical issues of low sweep efficiency and gas susceptibility to channeling in CO2 flooding, a viscoelastic fluid system (CMS) was proposed to improve CO2 flooding in low-permeability tight reservoirs. A systematic study was conducted on the viscoelasticity, interfacial activity, injectivity, plugging performance, and oil displacement performance of CMS under oil reservoir conditions. The synergistic flooding performance of CO2-CMS was explored, and field trials were carried out. Experimental results demonstrated that at reservoir temperatures ranging from 30-80 ℃, CMS with a mass fraction of 0.5% showed certain viscoelasticity, with elasticity as the dominant characteristic, and both viscosity and elasticity decreased as temperature increased. At an oil reservoir temperature of 45 ℃, the viscosity of CMS was 3.27 mPa·s, and it exhibited strong elasticity. Furthermore, CMS could effectively reduce the oil-water interfacial tension to 2.68×10-2 mN/m. After core samples were immersed in the CO2-CMS system, the water-phase contact angle decreased to 8.75°, indicating enhanced hydrophilicity. The CO2-CMS system demonstrated good injectability in low-permeability tight cores, with smaller slug sizes yielding better injection performance. In long-core displacement experiments, using a 0.3 PV slug of CMS followed by CO2 flooding increased the recovery rate by up to 27.79%. In double-tube parallel core displacement experiments, alternating CMS and CO2 proved most effective, as it successfully sealed the high-permeability cores and mobilized low-permeability cores, resulting in a 26.28% increase in recovery. Field trial data from well groups indicated that after applying CMS, the overall liquid and oil production increased, and the CO2 volume fraction in gas-channeling wells significantly decreased. This research provides new technical insights and practical solutions for improving the efficiency of CO2 flooding in low-permeability tight reservoirs.

Recycled old oil-based drilling fluids generally contain high concentrations of detrimental solids which result in performance deterioration of the drilling fluids.These detrimental solids can be removed through flocculation.In this study,an oil-based drilling fluid flocculant XN-1 was characterized for its performance in flocculating detrimental drilled solids,the flocculation mechanism of XN-1 was investigated,and the effectiveness of removing drilled solids and optimizing the properties of the oil-based drilling fluids through a combination of flocculation,screening and centrifugation was evaluated.Laboratory study and field experiment show that XN-1 has a good flocculating action in the old oil-based drilling fluid:the sizes of the flocs increase from submicron to 60 μm.After flocculation and screening,about 20%of the detrimental drilled solids are removed from the drilling fluid.After flocculation and centrifugation,70.50%of the detrimental solids can be removed from the drilling fluid.The old mud,with the detrimental solids being removed,can be used to formulate new muds with significantly optimized properties.The application of the flocculant XN-1 effectively improves the reuse of old oil-based drilling fluids,realizes the effective recycling of old oil-based drilling fluids and greatly reduces of amount of hazardous and waste drilling fluids,and effectively solves the difficulty of removing detrimental solids from oil-based drilling fluids.

The pore-throat of the fractured sandstone reservoir matrix with ultra-low permeability is fine,and micro fractures are developed,which provides favorable conditions for the role of imbibition and oil displacement;surfactant solution can change the interface reaction between rock and fluid,enhance imbibition effect,and have an important impact on enhanced oil recovery.Through interface tension experiments,wettability determinations,and spontaneous imbibition experiments,the interface tension,wettability,and spontaneous imbibition and oil displacement efficiency of the anionic non-ionic surfactant YCSX-1 solution with different mass fractions were studied,as well as the influence of the injection mass fraction and injection rate of the surfactant on the oil displacement efficiency.A matrix-fracture dual-medium core was innovatively designed based on the Warren-Root model,and a dual-medium mathematical model considering the effects of surfactants and imbibition was constructed.Physical and numerical simulation methods were comprehensively employed to investigate the oil displacement laws under different injection mass fractions and injection volumes of surfactants.The experimental results demonstrate that the interfacial tension and wetting contact angle decrease first and then increase with the increase in surfactant mass fraction,which are the key factors affecting the imbibition's oil displacement efficiency.The surfactant system with a mass fraction of 0.4%has the strongest imbibition effect and the highest oil displacement efficiency,and the enhanced imbibition effect improves the mobilization of crude oil in the matrix.The oil displacement efficiency shows a trend of increasing first and then decreasing with the increase in injection rate.The optimal injection rate is 1.2 mL/min.Based on the experimental results,the constructed dual-medium mathematical model was used for simulation calculation,and the injection parameters were optimized.The optimal injection mass fraction is 0.4%,and the optimal single-well injection volume is 12 m3/d.The simulation result was applied to the water injection development in the X Block,yielding an obvious effect,and the maximum increase in daily oil production is up to 54%.The technology of controlling injection rate and increasing imbibition effect to enhanced oil recovery changes the interfacial tension and wettability of matrix pores through the mass fraction optimization of surfactant solution;it simultaneously controls the water injection rate to ensure that the meniscus of the two-phase fluid remains in an ideal dynamic state during the oil displacement process,exerting the dual dynamic effects of capillary force and displacement pressure,further enhancing the relative contribution of flow and absorption in the oil displacement process,and increasing the flow capacity of crude oil in the small-pores of matrix.More crude oil in the pores of the matrix is recovered,improving the oil displacement efficiency.

Negative pressure wave method is suitable for CO2 pipeline leakage location detection in CCUS technology,but the noise generated by the surrounding environment and the high pressure in the supercritical CO2 pipeline affects the positioning accuracy.In this paper,the wavelet transform was applied to decompose and denoise the pressure signal with noise,and the CO2 pipeline leakage model was established by TGNET simulation software,the feasibility of the leakage model was verified by comparing the shock tube discharge test of Botros.The leakage model was used to denoise the pressure signal with noise using wavelet denoising method,then,the denoised data was processed using the pressure difference conversion and cross-correlation analysis.Finally,the specific time difference of the pressure signal received by each group of pressure sensors was obtained.The leakage model was also applied to the 360 000 t/a supercritical CO2 pipeline transportation scheme in Yanchang Oilfield,and the wavelet noise reduction and cross-correlation analysis of artificially set leakage port pressure noise were carried out.The research shows that the pressure signal after wavelet denois-ing is more stable and accurate,and the accurate time difference can be obtained,which provides a basis for the subsequent negative pressure wave method to accurately locate the leakage point.