Pore structure affects gas storage performance of shale and is an important parameter for evaluating shale gas resource potential. Taking the coal-measure shale of Upper Permian Longtan formation in western Guizhou as an example, micro-pores and micro-fractures were qualitatively observed using scanning electron microscopy (SEM) and classified, and the microscopic pore structure and pore size distribution were quantitatively characterized through high-pressure mercury injection and low-temperature nitrogen adsorption experiments. Combining with organic geochemical parameters and mineral composition distribution characteristics, the factors controlling the pore structures of coal-measure shale reservoirs were identified. The results show that the matrix pores in coal-measure shale of the Longtan formation can be divided into six occurrence types: residual primary intergranular pores, mineral moldic pores, clay mineral intergranular pores, intergranular pores, intragranular dissolution pores, and organic pores, and the micro-fractures are mainly extensional, shear, bedding, and diagenetic shrinkage micro-fractures. Micro-pores (especially those with diameter <5 nm) and transitional pores provide the main pore space. The pore space types are dominated by ink bottle holes and V-shaped holes, with a certain amount of parallel slits, and the connectivity between pores is relatively good. Total organic carbon content (TOC), maturity of organic matter, and mineral composition are the main factors controlling the pore structure of the coal-measure shale reservoirs of Longtan formation in western Guizhou. The single-point pore volume and specific surface area of the shale increase with the increase of TOC. The degree of thermal evolution contributes positively to the increase of micro-pore and transitional pore volume. Clay minerals have complex impacts on the pore structure. High brittleness index has a positive effect on the development of meso-pores, macro-pores and micro-fractures, being conducive to shale gas flow.

In order to clarify the deep coal-forming environment and its controls on the microsopic pore structure and reservoir properties of coal rocks, the deep No.5 coal rock of Shanxi formation in southwestern Ordos Basin was selected for investigating the facies, pore structure and reservoir properties of deep coal rocks through macroscopic observations, coal quality measurements, scanning electron microscope (SEM), and gas adsorption tests. The results show that the No.5 coal rock features extra-low water yield, moderate ash yield, extra-low volatile yield, and moderate-high fixed carbon content, with the average vitrinite reflectance up to 2.38%. The content of vitrinite ranges from 42.09% to 72.49%, with an average of 60.60%, and the content of inertinite reaches 27.34% averagely, while exinite is rare in the coal. Desmocollinite, telocollinite and semifusinite are the dominant sub-macerals of the coal samples. The coal-forming environment was dominated by moist forest-swamp facies, with large overlying water depth and weak hydrodynamic force. The bedding fractures, gas pores and plant tissue pores serve as the dominant reservoir space types, and a small amount of intergranular pores and clay mineral intercrystalline pores are also observed. Micropores and mesopores with pore sizes less than 22 nm are the reservoir space, and the heterogeneity of pore structure containing larger mesopores is more significant. The coal-forming environment with strong water overburden and weak flow is conducive to the development of vitrinite, which also determines that micropores are the main reservoir space of the deep coal. Under the action of gelation, the adsorption and adhesion of terrigenous detritus by coal organic matters led to strong heterogeneity of pore structure containing larger mesopores.

The distribution of fault-controlled karst reservoirs in the Permian Maokou formation in the Jingyan area of southwestern Sichuan Basin remains unclear. A seismic identification model for faults and fault-karst bodies in the Maokou formation was established using drilling, geological, seismic and other data. The differences in seismic reflections between faults and fault-karst bodies were analyzed through forward modelling. On this basis, multi-stage superimposed faults were identified using seismic structural attributes such as coherence, maximum likelihood, dip angle and gradient structure tensor etc., and interlayer fault-karst bodies were recognized from seismic texture attributes such as entropy and energy. Then the distribution of Maokou formation fault-controlled karst reservoirs was accurately determined, and a geological development model was established. The results indicate that the study area mainly develops two types of fault-controlled karst reservoirs: multi-stage superimposed fault-karst bodies, which are observed in the southern part of the study area, and interlayer fault-karst bodies, which are developed in the eastern part of the study area. The seismic structural attributes can be used to accurately recognize high, steep and upright multi-stage superimposed fault-karst bodies that exhibit significant differences in the continuity of seismic waveforms, while the seismic texture attributes can be used to accurately represent gentle and low-angle interbedded fault-karst bodies with obvious changes in reflection amplitude energy of seismic waveforms. The predicted results are consistent with actual drilling results, and the research results can guide the future exploration deployment.

The Ordovician carbonate reservoirs are the main development targets in the Hetianhe gas field. Taking the Ma 4 block as an example, the paleokarst characteristics were investigated based on core, thin section, logging, drilling and fluid data. The relationship between fractures and paleokarstifcaiton or filling was analyzed, the main factors controlling gas well production were evaluated, and the favorable targets for tapping the potential of the karst reservoirs were clarified. The research results show that the characteristics of fracture development in the vertical flow zone are not only related to tectonic characteristics, but also to surface karstification and filling processes. The activity of bottom water in the gas reservoir is related to the burial dissolution. Karst zonation is the main cause for the dual structure of karst reservoirs. The fracture zone is not the active water zone. The production effect of a single well mainly depends on two factors, namely burial dissolution and fracture development in the vertical flow zone.

Edge and bottom water are found in the Jurassic oil reservoirs in the Ordos Basin. In this kind of reservoirs, rapid water cut rise and low recovery by water flooding occur after initital production. In order to explore new methods for enhanced oil recovery in such reservoirs and find new ways to increase production by carbon sequestration in near-abandoned reservoirs, a pilot test was conducted on top CO₂ injection for flow field reconstruction in the Y9 reservoir in the X1 block of Jiyuan oilfield. Through the mechanism analysis of CO₂-assisted gravity drainage, multiphase and multi-component numerical simulation was performed to understand the sensitivity and adaptability of the reservoir's geological parameters, and the reservoir engineering parameters were also optimized for the test area. The results show that the residual oil in the Jurassic bottom water reservoirs after waterflooding mainly exists in three forms: thick oil ring in the zone between injection and production wells after the invasion of bottom water, thin oil ring in the zone from the outer oil-bearing edge to the oil production well due to bottom water coning and edge water intrusion, and residual oil after waterflooding. Injecting CO₂ at the reservoir top is an effective way to inhibit bottom water coning. As an artificial gas cap forms and exaggerates, gas-oil contact moves downwards, and accordingly oil-water contact becomes lower, alleviating bottom water coning. The main factors affecting CO₂-assisted gravity drainage include formation dip, reservoir thickness, permeability, heterogeneity, crude oil properties, and oil saturation, etc. Simulation studies and pilot tests indicate that CO₂-assisted gravity drainage at the reservoir top can effectively reconstruct the flow field in waterflooding reservoirs, thereby enhancing the ultimate recovery.

In the western Sichuan depression of Sichuan Basin, the gas reservoir in the second member of Xujiahe formation (Xu-2 member) is a typical fault-fracture tight sandstone gas reservoir. Natural fractures are well developed in the reservoir, with a strong connectivity. The gas wells initially produce at high rates, but cannot maintain stable yield due to water invasion. To identify the causes of water production and determine the water invasion pathway, scale, and timing, gas wells were classified depending on their dynamic characteristics such as production rate and pressure. By analyzing the distribution of gas and water and the fracture characteristics of the reservoir, water invasion patterns were identified, and a numerical simulation model which can reflect these patterns was established. Based on the results of the numerical simulation, criteria for determining water invasion patterns were established, and the simulation results were verified using water analysis data from gas wells.

Existing flow unit classification is primarily conducted under static conditions, making it difficult to reflect the dynamic changes in reservoir properties during water injection. To investigate the dynamic changes in reservoir flow units during water injection for optimizing the dynamic detection and development plans, this study takes the Yan-8₁ layer in the Jiyuan area of Ordos Basin as an example. The static evaluation parameter of the flow unit is defined as the flow zone index (FZI). By fitting the relationship between the cumulative water injection volume and the change in FZI (ΔFZI), the change in FZI caused by water injection is combined with the static evaluation parameter of the flow unit to form a dynamic evaluation parameter of flow units. The results show that as a standard for flow unit classification, FZI is correlated with the results of injection profile tests. Using FZI as the static evaluation parameter, the flow units are classified into three types (i.e. Ⅰ, Ⅱ, Ⅲ). By comparing the reservoir properties at various stages, it can be seen that as water injection continues, the reservoir properties are gradually improved to facilitate fluid flow. Given the same water injection rate, the increase in FZI for Type Ⅲ flow units is significantly higher than those for Type Ⅰ and Type Ⅱ, but its increase rate is lower than those of Type Ⅰ and Type Ⅱ.

In order to determine the oil-water relationship and its controlling factors in the shallow heavy oil reservoirs of the Qigu formation in Block HQ1, Karamay oilfield, the study focuses on the h-4 well area, which exhibits significant oil-water distribution complexities at the reservoir margins. Using the data of dense well pattern and test analysis, the influences of sand body distribution, hydrodynamic conditions, reservoir properties, hydrocarbon charging pressure, and tectonic activities on the oil-water contact (OWC) are identified. The h-4 well area demonstrates distinctive OWC characteristics, where the water boundary is parallel with the structural line in the east, and the water boundary obliquely intersects the structural line in the west, resulting in a tilted OWC. This tilted OWC is believed to have been resulted from the periodical fracture opening due to tectonic activities and the OWC adjustment hysteresis is caused by oil viscosity variation, indicating a coupled mechanism of tectonism and unsteady reservoir formation. The fracture opening in the western part of the study area provided oil migration pathways, facilitating oil accumulation in the Qigu formation. Subsequent fracture sealing and reactivation events led to reservoir compartmentalization, creating a OWC that is high in west and low in east. Oil biodegradation shaped a similar viscosity feature. The combined effects of tectonic activities and viscosity variations significantly retard horizontal adjustments of OWC, characterizing the reservoir as a unsteady hydrocarbon accumulation system.

The CO₂ storage and enhanced gas recovery (CS-EGR) technology represents a promising option for boosting production in the context of “dual carbon” goals. However, its application in tight sandstone gas reservoirs has been scarcely studied, and its field performance remains unclear. This study establishes a reservoir-scale numerical model based on a comprehensive analysis of gas-water two-phase flow mechanisms and stress sensitivity across three reservoir types. Using this model, the adaptability of CO₂ injection to reservoirs, CO₂ migration behaviors, CO₂ trapping mechanisms, impacts of movable water on the CS-EGR process, and optimization of engineering parameters for CS-EGR are analyzed. It is indicated that CS-EGR is viable only for Class Ⅰ reservoirs, but less performed in Class Ⅱ and Class Ⅲ reservoirs. In terms of CO₂ trapping mechanism, both structural trapping and residual trapping account for 95.8%, while CO₂ mineralization and storage contributes 0.15%. For Class Ⅰ reservoirs, the optimal CO₂ injection rate is 10,000 m³/d, the cumulative production of CH₄ is 0.146×10⁸ m³ when CO₂ breaking through, and the cumulative storage of CO₂ is 0.794×10⁸ m³. Movable water significantly hinders CO₂ migration and increases the risk of gas well flooding.

Accurate evaluation of performance decline is crucial for efficient development of gas fields and ensuring stable energy supply. Production decline rate and productivity decline rate are two commonly used parameters for presenting performance decline in gas fields from different perspectives, but their definitions are different. In order to understand the physical meanings of production decline rate and productivity decline rate and clarify their inherent relationship and influencing factors, the calculation method of gas field decline rate was analyzed, and the influencing factors were identified. The results indicate that, for exponential decline, the productivity decline rate are consistent with the production decline rate, while for hyperbolic decline, the productivity decline rate is always greater than the production decline rate, and the difference between the two decline rates increases with the increase of decline index and initial decline rate, and the two rates gradually tend to be consistent with each other with the extension of production time. The concept of gas field exploitation intensity was introduced to eliminate the fluctuations in production decline rate caused by downstream gas consumption changes. A new method of production/productivity prediction was proposed. Specifically, an exponential decline model is used at the early stage of decline, and a harmonic decline model is used at the mid to late stage of decline; then, the average of the two model results is taken as the lower limit, and the result obtained from the harmonic decline model as the upper limit. The research results are of great significance to accurately analyze the decline behaviors of gas fields and scientifically formulate development plans.

Flue gas-assisted steam flooding is an economically viable enhanced oil recovery (EOR) technology for heavy oil reservoirs. To address the complex mechanisms of synergy between flue gas injection and steam injection, and the unclear impacts of injection process and reservoir properties on development performance, experiments and numerical simulations were performed on flue gas-assisted steam flooding following conventional steam flooding. Taking a heavy oil reservoir as an example, core flooding experiments were conducted to compare oil displacement efficiencies under different injection media. A mechanistic model of flue gas-assisted steam flooding for heavy oil reservoirs was established to systematically investigate its underlying mechanism and performance. The research results show that flue gas-assisted steam flooding improves oil recovery efficiency by 5.84% compared to pure steam flooding, attributed to multiple mechanisms such as thermal viscosity reduction by steam, pressurization effect of flue gas, enhanced thermal sweep efficiency via gis-liquid Jamin effect, and oil mobilization by flue gas flow. The injected flue gas forms a gas zone at the steam chamber front, prolonging steam-oil interaction time while mitigating steam override, thereby expanding thermal sweep area. An optimal steam-to-flue gas molar ratio of 7∶3 during injection can achieve a favorable balance between enhanced oil recovery and reduced steam consumption. Slug injection generates periodic pressure differentials in the reservoir, further improving displacement efficiency over co-injection. These findings provide theoretical and practical guidance for designing flue gas-assisted steam flooding schemes in heavy oil reservoirs.

The significant heterogeneity of the carbonate reservoirs in the Sinian Dengying formation in the Sichuan Basin poses substantial challenges to interpretation of microresistivity scanning image logging for the fractured-vuggy reservoirs. To enhance the accuracy of imaging logging in evaluating fractured-vuggy carbonate reservoirs, a core surface electric field measurement device was customized based on AutoScan-Ⅱ core planar resistivity scanning experiments. Using this device, experiments on rock surface resistivity measurement and imaging were conducted to quantitatively analyze the imaging response characteristics of vugs and fractures. A calibration method for fracture-vug parameters based on rock surface resistivity distribution was established. The results show that the computed vug diameter and plane porosity increase linearly as the core-measured vug diameter and plane porosity increase, and the computed fracture width and the surface fracture ratio increase logarithmically as the core-measured fracture width and surface fracture ratio increase. The laboratory-based rock surface resistivity experiments effectively reduce the discrepancies between core measurements and imaging logging calculations, enabling precise calibration and quantitative evaluation of plane porosity of fractures and vugs. This study provides a methodological framework for improving the reliability and accuracy of imaging logging in evaluating fractured-vuggy reservoirs, and offers technical support for the evaluation and development of carbonate reservoirs.

Offshore low-permeability reservoirs are characterized by fine lithology, poor physical property, and strong heterogeneity, making permeability prediction highly challenging. To address this issue, a regression committee learning machine (RCLM) driven by both data and physics was developed for predicting permeability based on logging data for low-permeability reservoirs. On this basis, sweet spot evaluation and dynamic permeability prediction were conducted. The results show that compared with a simple learning machine, the RCLM not only guarantees the prediction accuracy but also achieves higher prediction stability; in comparison with conventional porosity-permeability models, the RCLM obtains superior accuracy (up to 94% within half an order of magnitude). The comprehensive logging-based sweet spot index established using logging curves and petrophysical parameters can be used to effectively identify sweet spots in reservoirs. The newly drilled wells have verified the applicability of the dynamic-static permeability transformation model, which can be used to predict well test-derived permeability during regionally progressive exploration and development. The proposed method has been successfully applied in reservoir evaluation in the Dongfang gas field of the Yinggehai Basin, demonstrating its practical value. This method may provide robust support for efficiently designing exploration and development plan for offshore gas fields.

Ball-and-stick model is widely employed in simulating pore network within reservoirs. However, given a broad range of pore scales and diversity of structural types in reservoirs, whether this model is universally applicable remains inadequately validated. Constant-rate mercury intrusion (CRMI) is one of the key methods for studying pore-throat structures. By employing the configuration theory and analytic hierarchy process (AHP), the configurations of CRMI curves were classified, the corresponding hierarchical architectures of reservoir pore systems were interpreted, and the applicability of ball-and-stick model in reservoir pore network simulation was examined. The results indicate that CRMI curves can be divided into Configuration A and B regions, corresponding to micron-scale pores and nano-scale pores, respectively. In Configuration A region, as the mercury injection pressure increases, the mercury injection saturation in pore network, pores, and throats rises monotonically, indicating a binary pore-throat structure in the micron-scale pores, with a pore/throat ratio higher than 1. Here, the ball-and-stick model is applicable. In Configuration B region, as the mercury injection pressure increases, the mercury injection saturation in pore network and throats increases monotonically, while the mercury injection saturation in pores remains constant. This suggests that nano-scale pores have no binary pore-throat structure, and are dominated by throats, with a pore/throat ratio of 1. In this region, the ball-and-stick model is inapplicable, while a capillary tube model is more suitable. The ball-and-stick model and capillary tube model can be combined to fully simulate reservoir pore networks. The poorer the reservoir physical properties, the more applicable the capillary tube model for pore network simulation.

Paleoweathering crusts are of significant importance for understanding the interactions between the lithosphere and the atmosphere, as well as the rock-water reactions within weathering profiles during burial diagenesis process. This study systematically analyzed petrological, mineralogical, and geochemical characteristics of various igneous rock basements, including gabbro-diorite (GA1 basement), basaltic andesite (GA1 effusive rock interval), quartz diorite (TB8 basement), and granite (BK2/05 basement). The mobility offsets of easily migrating elements such as K, Ca, and Na were quantified using the degree of migration, and the results were cross-referenced with mineral quantitative analysis data from whole-rock X-ray diffraction (XRD) and the petrological features to clarify the burial diagenetic characteristics of the paleoweathering crust in the study area. Subsequently, based on the mineral and element contents, a quantitative correction was applied to Ca content, followed by a correction for K content. The corrected results displayed a well-defined weathering trend in the A-C-K triangular chart, validating the methodology for correction. Using the corrected parameters, the chemical index of alteration (CIA) was employed to quantify the degree of chemical weathering. Additionally, corrections for the original weathering products were performed by integrating protolith characteristics and paleoclimate features, revealing the original weathering characteristics of the paleoweathering profile. Finally, after normalization using weathering indices, the corrected weathering characteristics of each profile exhibited strong correlations with the climatic evolution trends during the Early to Middle Permian.