The elastic two-phase method, also known as the pseudo-steady-state method or reservoir limit testing method, is a pivotal dynamic technique for estimating the original gas in place（OGIP）in well-controlled scenarios. This method is primarily employed in the initial testing of gas wells and for the OGIP assessment in varied lithologies, fault blocks, and fracture types of gas reservoirs. Since 1994, the pressure squared variant of this method has been recognized in the Chinese national oil and gas industry standards across four editions: SY/T 6098—1994，SY/T 6098—2000，SY/T 6098—2010，SY/T 6098—2022. This method, based on the pressure squared calculation, offers a robust approximation compared to its pseudo-pressure counterpart. The theoretical derivation of the elastic two-phase equation for pseudo-pressure, originally proposed by AL-HUSSAINY（1966）, and further simplified using WATTENBARGER's（1968）study on the relationship between μ_gZ and p, allows for representations using both pressure to the first and second powers. Notably, while the pressure to the first power method tends to under-estimate OGIP, the pressure squared method is inclined to over-estimate, as evidenced by practical applications. Currently, there is a lack of substantial literature on the pseudo-pressure elastic two-phase method both domestically and internationally.

The transition from depletion mining to gas flooding in deep low permeability condensate gas reservoirs poses significant adaptability challenges. To address these, a series of evaluation studies were conducted using the Pressure-Volume-Temperature（PVT）analyzer, long core displacement physical simulation technology, and numerical simulation calculations. This research specifically examines the impacts of CO₂ injection, natural gas（associated gas or pure CH₄）, and nitrogen（N₂）on the high-pressure physical properties of condensate gas systems and their potential to improve condensate oil recovery. Comparative analyses reveal that CO₂, due to its high solubility and favorable gas-oil dissolution ratio in condensate oil, significantly reduces the saturation pressure and dew-point pressure of condensate gas reservoirs, thereby offering the most substantial improvement in oil recovery rates. Further optimization studies using long core physical simulation technology focused on injection timing, modes, and rates for CO₂ flooding. It was determined that pulsed gas injection strategies are particularly effective when implemented above the dew-point pressure. These findings provide essential data to support the formulation of technical policies and field plans for gas injection development in such challenging reservoir conditions.

Shale oil reservoirs present complex pore structures and ultra-low permeability, making the evaluation of flow capacity in both the reservoir matrix and various fracture types after fracturing crucial for developing effective work systems. In this study, the Brazilian splitting method was utilized to simulate different fracture morphologies. We constructed a set of methods for evaluating matrix and fracture flow capacity based on nuclear magnetic resonance（NMR）technology. This evaluation was conducted on shale cores from the second member of Funing Formation of Gaoyou Sag in Subei Basin（referred to as the Fu-2 member）. Techniques including NMR, Brazilian fracturing, and high-pressure saturation were applied to develop these evaluation methods. The experimental results indicate that the minimum flow pore size of the shale reservoirs is 10 nm. Under stress conditions, the flow pattern exhibits a two-stage equation: nonlinear and linear. Factors affecting the fracture system’s conductivity include crack type, opening degree, stress magnitude, and driving pressure difference. Higher stress levels result in greater permeability loss, reaching up to 95%. The more complex the fracture network and the larger the opening, the greater the permeability loss. During production, it is essential to manage the pressure difference between the formation fluid and the bottomhole flow based on the crack development and effective stress characteristics of the overlying strata to ensure stable oil well production and uniform pressure propagation. For the shale oil in Fu-2 member of Gaoyou Sag, it is recommended to maintain an effective stress range of 7 MPa to 10 MPa and a flow pressure difference range of 10 MPa to 15 MPa as optimal for pumping or reservoir energy replenishment. These research findings significantly contribute to the theoretical understanding and practical application of the shale seepage mechanism.

The exploration of Well-Fuye-10 in the Dongyuemiao section has provided valuable characteristic parameters of typical continental shale, revealing a reservoir with well-developed mesopores and macropores and significant heterogeneity. The predominant pore sizes are around 10 nm. Notably, deviations in the critical parameters of the confined fluids alter the condensate gas properties within these nanopores, differentiating them from conventional laboratory results. This study combines indoor phase state experiments, critical parameter migration calculations, and numerical simulations of confined fluids to analyze the phase state characteristics and extraction properties of shale condensate gas. The findings elucidate the phase state transformation and extraction dynamics of the condensate gas. Adjustments in the calculations for condensate gas phase characteristics to account for critical parameter offsets indicate that as pore radius decreases, there is a corresponding reduction in critical temperature and pressure of the system components. This results in a contraction of the phase diagram towards the lower left, a decrease in dew point pressure, reduced gas phase viscosity, an increase in deviation factor, and a gradual decrease in retrograde condensate saturation. Additionally, a mechanism model was employed to assess the impact of critical parameter shifts on depletion extraction effectiveness. Results demonstrate that while the recovery rate of natural gas remains relatively unchanged, the recovery rate of condensate oil shows a significant increase, rising by 9.93% as the pore radius decreases to 10 nm. These insights offer pivotal guidance for the development of shale condensate gas reservoirs, particularly in managing the unique phase behavior and optimizing recovery strategies.

The deployment of horizontal well groups for shale oil development represents an innovative approach to fracturing, addressing the constraints observed in single horizontal wells. This study focuses on the fracturing dynamics within groups of horizontal wells, where the interplay of multiple wells and artificial fractures introduces complex variations in stress around the fractures and the in-situ stress distribution between wells. Such complexities significantly influence the morphology of fracture propagation. A comprehensive investigation into the stress field dynamics under various fracturing methods in horizontal well groups was conducted using a hydraulic fracturing numerical model. This research is crucial for manipulating fracture morphology and enhancing fracture complexity. The study systematically explored the stress distribution during the shale oil reservoir fracturing reconstruction, analyzed fracture morphologies, and quantitatively assessed the fracturing outcomes. Key findings include: ① Synchronous fracturing effectively alters inter-well ground stress, with the staggered pattern inducing a 24% higher stress compared to the opposite pattern, thereby influencing the direction and reversal of ground stress under identical well spacing. ② Staggered layout exhibit superior shape and fracturing effects than those under the opposite layout, significantly increasing the length, width, surface area, and volume of fractures by 4.6% and 21.1%, respectively. ③ Zipper fracturing enhances fracture dimensions more effectively than synchronous fracturing, increasing the total surface area and volume of the fractures by 1.3% and 0.1%, respectively.

The efficient evaluation of the oil properties, capabilities, and compressibility of reservoirs using conventional logging data is essential for the large-scale development of shale oil in northern Jiangsu. Utilizing conventional logging data alongside core experiment data, this study develops a robust model to calculate several critical reservoir characteristics. These include total organic carbon content, effective porosity, bedding fracture density, and mineral composition content. The model employs a variety of mathematical methodologies such as physical concept analysis, optimization, fitting, and both forward and backward numerical simulations. Furthermore, this research classifies the sedimentary structure and lithofacies of the reservoir. Results indicate that the shale within the second member of Funing Formation in Qintong Sag predominantly consists of organic-rich layered/laminated mudstone and block mudstone. Among these, the layered or laminated mudstone represents the favorable lithofacies, intersecting vertically with non-favorable rock types. The “sweet spot” layers identified by the model correlate well with the layers analyzed using specialized logging techniques, and field applications have yielded positive outcomes. This technology has been successfully applied in identifying geological and engineering “sweet spots” within the shale oil reservoirs of the Subei Basin, offering significant guidance for the strategic development of shale oil in the region.

Significant progress has been made in the exploration and development of shale gas within the Lower Silurian Longmaxi formation of the thrust-nappe tectonic belt in the Nanchuan block. By the end of 2022, this area saw the drilling of 170 wells, achieving a cumulative gas production of 51.6 billion cubic meters. As development has progressed, the focus has shifted from the structurally simpler main area to the more complex peripheral regions. Previously, the structural interpretation of the Nanchuan block primarily identified faulted anticlines constrained by major reverse faults, without adequately addressing the structural deformation across the entire belt. Recent evaluations have revealed significant discrepancies between well data and seismic interpretations, leading to numerous drilling failures and hindering further shale gas development. This study revisits these challenges using advanced drilling insights and forward modeling analysis. It suggests that the apparent thrust faults with large displacements and high angles in the seismic profiles of the Longmaxi formation are likely structural misinterpretations, rather than true geological features. Instead, the fault areas are characterized by high-steep knee-fold structures with smaller fault distances and steeply inclined strata. By integrating high and steep structural illusion analysis with fault-related fold theory, the well-seismic joint structural modeling has been refined to better represent the structural characteristics of the Longmaxi formation gas reservoir in the Nanchuan block. This improved understanding has identified the high-steep knee fold zone as a potentially favorable target for further exploration and development, supported by positive results from five recently deployed evaluation well groups.

Distinct sedimentary environments lead to notable disparities between marine-continental transitional shale and purely marine shale. This study develops a numerical model to evaluate the productivity of horizontal wells in vertically multi-lithologic superimposed reservoirs, focusing on the marine-continental transitional shale reservoirs at the eastern margin of the Ordos Basin. The model analyses the dynamic characteristics of single-stage gas well production under various lithologic combination modes. It particularly investigates key parameters such as coal seam permeability, the superposition relationships of reservoirs, and the impact of the production system on output characteristics. The findings indicate that: ① In the early stages of combined extraction from coal-rich shale reservoirs, both gas and water are produced simultaneously. The gas primarily originates from the free gas in the sandstone and shale reservoirs, while the water is predominantly sourced from fracturing fluid and coal seam water. Notably, higher coal seam permeability correlates with increased cumulative gas and water production. ② The optimal spatial stacking sequence for combined layer mining in coal-bearing superimposed reservoirs is identified as page-sand-coal. This sequence minimizes the interference of coal seam water production on the overall mining process. ③ The production from coal seams exhibits significant stress sensitivity, impacting overall gas output.