The southwest margin of Ordos Basin has developed faults and fractures to varying scales, significantly enhancing the permeability of tight reservoirs and forming high-quality fault-fracture reservoirs against a backdrop of low permeability reservoir types. However, this also complicates the reservoir's homogeneity and the variability of its capacity, posing challenges for fine characterization of the reservoir's internal structure and for researching capacity control factors. To address these issues, the study employs spatial characterization of the fracture system, fracture classification, and capacity comparative analysis. Further, the development characteristics of the fault-fracture reservoir are defined through joint well-seismic and reservoir research. Key findings from this research include: 1） Establishment of the “binary four zones” model for fault-fracture reservoirs, which divides the reservoir into four distinct zones: the core fracture zone, the induced fracture zone, the micro-fracture transformation zone, and the matrix pore zone. Among these, the core fracture zone is identified as the primary contributor to production yield. 2） It is observed that the longer the fault extension length and the higher the solid drilling structure position, the higher the single well production capacity in the core fracture zone. The induced fracture zone's proximity to the fault correlates with higher production capacity, demonstrating the spatial impact of fault structures on reservoir productivity. 3） The production characteristics of fracture wells are categorized into three stages: ① the fracture system acts as the high yield stage; ② the fracture system serves as the storage stage and plays the role of diversion; ③ the fracture's primarily function in diversion. This research significantly increases the proportion of high-yield wells in the fault-fracture reservoir, providing crucial insights for guiding efficient, ongoing exploration and development activities in the Mesozoic reservoirs on the southwest margin of the basin. This strategic approach enhances understanding and management of fault-fracture reservoirs, optimizing resource extraction and improving operational efficiencies.

Significant progress has been made in shale oil exploration within the second member of the Funing Formation in the Qintong Sag, Subei Basin. However, geologists have noted that the measured Total Organic Carbon（TOC） contents are generally below 2%. Despite this, it is believed that source rocks in saline lacustrine basins can generate substantial amounts of petroleum even with low organic matter abundance, a concept known as the “low TOC” and highly efficient hydrocarbon generation mode of saline lacustrine source rocks. As hydrocarbon generation and expulsion occur during thermal maturation, the TOC levels in source rocks decrease. Therefore, accurately restoring the original TOC of these source rocks is crucial for a proper understanding of their hydrocarbon generation capacity, as well as for evaluating petroleum resources and supporting reserve growth and production enhancement. This study focuses on the typical mudstones and shales of the second member of the Funing Formation in the Qintong Sag. Techniques such as hydrocarbon generation simulation experiments, rock pyrolysis data, TOC and productive carbon content evolution during thermal simulation, and an element mass conservation method were employed to restore the original TOC of these mudstones and shales. The findings reveal that the TOC recovery coefficient of these saline source rocks can exceed values between 3 to 4, and this coefficient is significantly influenced by the lithology. The study found that: the TOC recovery coefficient increases with thermal maturity, the coefficient for laminated shale is higher than that for massive mudstone, and the TOC recovery coefficients for mudstones in the Ⅳ sub-member and shales in the Ⅰ to Ⅲ sub-members of the second member of the Funing Formation range from 1.1~1.5 and 1.5~3.0, respectively. These variations are attributed to differences in the type of organic matter and the hydrocarbon generating activation energy, leading to a higher hydrocarbon transformation rate and TOC recovery coefficient in shales compared to mudstones.

The objective of this study is to delve deeper into the hydrocarbon generation potential and oil-bearing characteristics of various source rocks within the second section of the Funing Formation in Qintong Sag, Subei Basin, and to assess the degree of shale oil enrichment. Through geochemical analysis and simulation experiment research, this investigation proposes a method for characterizing shale oil content that is adapted to the geological features of the second section of the Funing Formation. The study establishes the oil content, occurrence state, and distribution characteristics of shale oil within this section. Findings indicate that the mudstone and calcium mudstone of the fourth and fifth sub-members demonstrate higher total oil content, lower free hydrocarbon content, medium to high adsorbed hydrocarbon content, and limited mobility. Meanwhile, the calcium shale, calcareous shale, and laminated marlstone of the first to third sub-members exhibit higher total oil content and free hydrocarbon content, but lower adsorbed hydrocarbon content, which enhances their mobility. The calcium mudstone and calcareous mudstone of the first to third sub-members display a moderate level of total oil content and adsorbed hydrocarbon content but relatively low free hydrocarbon content. The marlstone from these sub-members shows comparatively low levels of total oil content as well as free and adsorbed hydrocarbon contents. The study also reveals the distribution of shale oil enrichment intervals. Class Ⅰ and Class Ⅱ shale oil enrichment intervals are primarily located in the middle and lower sections of the first and second sub-members in the deep depression zone. In contrast, the slope zone features limited development of shale oil enrichment strata but contains Class Ⅱ and Class Ⅲ shale oil.

The identification and classification of shale lithofacies are crucial for both theoretical understanding and practical applications in shale gas exploration and exploitation. This study focuses on the shale of the second member of the Paleogene Funing Formation in the Qintong Sag, Subei Basin, using core samples from a typical drilling well, Well-Qinye-1. The research involves whole rock/clay X-ray diffraction analysis on these core samples and employs a previously developed three-terminal diagram of shale mineral components to categorize the types present in this area. Additionally, a BP neural network method optimized by the ASO（Atom Search Optimization） algorithm was utilized to perform data mining on logging information. This process aimed to establish a prediction model for the relative content of clay minerals, siliceous minerals, and carbonate minerals, achieving quantitative characterization of shale mineral content through natural gamma ray spectrometry. Ultimately, the model was applied to predict lithology and identify lithofacies in the second member of Well-Qinye-1 and Well-Shaduo-1. The identification results closely aligned with the data measured from the samples, demonstrating high consistency. This study provides an economical, rapid, and efficient method for predicting shale lithofacies and main mineral components. It also offers a foundational approach for identifying well facies in scenarios where coring and direct testing data are unavailable.

The mud shales of the second member of the Paleogene Funing Formation in the Gaoyou Sag of Subei Basin are distinguished by their complex pore structures, well-developed bedding, and pronounced heterogeneity. These characteristics complicate the accurate evaluation of pore and fluid types using conventional well logging techniques. However, two-dimensional nuclear magnetic resonance（2D NMR） logging presents distinct advantages in fluid identification. The study incorporates the “Blind Source Separation” signal processing technique to perform data clustering analysis. Subsequently, a fluid zone model is applied to determine the fluid content with different movable properties in the reservoir space of the Huazhuang area. The findings demonstrate that 2D NMR logging significantly improves the accuracy of reservoir fluid evaluation, yielding reliable estimates of total porosity, effective porosity, oil saturation, and movable oil volume content. When compared to core analysis, the average absolute errors for effective porosity and oil saturation are minimal, at 0.4% and 7.3%, respectively. Further analysis of fluid properties within the primary lithologies of the second member of the Funing Formation reveals that the felsic-calcitic-dolomitic-mixed shales possess superior physical properties, oil volume content, and mobility. These characteristics render them as prime targets for shale oil exploration in the region. The successful application of 2D NMR logging in the Huazhuang area not only addresses the challenges associated with evaluating shale oil porosity and saturation but also provides essential insights for selecting “sweet spot” districts and forecasting reservoir production.

The intercalated shale oil within the first member of the Qingshankou Formation in the southern Songliao Basin exhibits significant exploration potential, primarily influenced by the quality of its intercalations, which impacts both oil content and productivity. The physical properties of these interlayers are notably heterogeneous, highlighting the necessity to characterize and describe interlayer reservoirs comprehensively and establish a suitable classification scheme. This study utilized advanced techniques such as field emission scanning electron microscopy, high-pressure mercury injection, and nuclear magnetic resonance to characterize the reservoir. Employing the fractal theory associated with mercury injection, a physical property classification standard tailored for sandstone interlayers was developed. This standard was combined with logging data to predict the physical property parameters of the reservoirs, facilitating the identification and mapping of high-quality interlayer reservoirs. The results delineate the first member of the Qingshankou Formation in the Daqingzijing area into regions of varying source rock maturity: low maturity areas with a vitrinite reflectance（R_o） of less than 1.0% and areas with middle to high maturity source rocks（R_o greater than 1.0%）. It was found that interlayer physical properties deteriorate as the maturity of the source rock increases. A grading standard for interlayer physical properties was established, categorizing the sandstone interlayers into Class Ⅰ to Ⅲ, and deeming some as invalid reservoirs. From Class Ⅰ to invalid reservoirs, there is a sequential decrease in the content of large and medium pores, with reservoir space transitioning from intergranular pores and intergranular solution pores to intragranular solution pores and intergranular pores. The mercury injection profiles evolve from weak platforms and slow straight lines to convex shapes, indicating a gradual degradation in oil content. High-quality interlayer reservoirs are predominantly situated along the main body of the estuary bar and the underwater distributary channels, with the thickness decreasing from southwest to northeast. The findings of this research provide crucial insights for targeting interbedded shale oil prospects within the first member of the Qingshankou Formation in the southern Songliao Basin, assisting in the strategic selection of exploration and development sites.

To address the issue of low natural imbibition recovery in horizontal wells within tight reservoirs and the challenge of replenishing formation energy during extended depletion phases, a strategy involving water injection huff and puff in large displacement horizontal wells was proposed. This approach builds on the fundamental characteristics of reservoirs and the established mechanisms of water injection huff and puff oil production in tight reservoirs. The research focused on the Chang-7 tight reservoir in Ordos Basin, employing a combination of natural and artificial cores. This study explored the range of natural imbibition and the dynamics of water injection and huff and puff across various displacements. Methods like nuclear magnetic resonance were used to analyze the characteristics of microscopic pore production, the impact of displacement on pore productivity, and the effects of soaking time. The findings reveal that with smaller displacements, mainly large pores are utilized for water injection, resulting in minimal engagement of small and medium pores. Conversely, higher water injections significantly enhance the involvement of small and medium-sized pores, thus substantially boosting the overall recovery rate. Additionally, as the simmering time is extended, the oil-water displacement effect increases, enhancing the degree of recovery through water injection huff and puff, though the rate of improvement eventually stabilizes. Numerical simulation was used to optimize the parameters for water injection huff and puff development in fracturing horizontal wells. For Well-A9, the optimal parameters were identified as a daily water injection rate of 900 m³ and a simmering time of 24 days. The field test confirmed the effectiveness of these parameters, with an initial daily oil increase of 2.11 tons, an effective period of 365 days, and a cumulative oil increase of 770 tons.

Continental shale oil horizontal wells have fast decreasing natural production and low recovery, for which single well water injection huff-n-puff can effectively replenish formation energy and improve recovery. Taking Ordos Chang7 shale oil as an example, numerical simulation method is used to carry out the optimisation study of water injection huff-n-puff in horizontal wells of continental shale oil. To enhance the accuracy of the numerical simulation model for shale reservoirs after volume fracturing, the Embedded Discrete Fracture Model（EDFM） is introduced. This model characterizes both natural and hydraulic fractures resulting from volume fracturing. Additionally, a conceptual model that considers imbibition and reservoir stress sensitivity is established. The timing, volume, and speed of injection, as well as the soaking period and huff-n-puff cycle, are optimized based on simulation results. These results indicate that a too-rapid injection rate causes water to flow along the fractures, decreasing the utilization rate of the injected water. As the huff-n-puff cycle increases, the oil increment per cycle tends to decrease. For the specific case of a shale reservoir in Ordos, the optimization of huff-n-puff parameters is as follows: Water injection should commence when the pressure coefficient drops to 0.706, with an optimal injection volume of 4 000 m³ at a rate of 300 m³/d. The recommended soak period is 15 days, with a total of six huff-n-puff rounds. This approach can increase the recovery rate by 4.95% and achieve a total oil-water replacement rate of 6.65%. This study provides valuable insights for water injection huff-n-puff strategies in shale reservoirs.