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A series of large-scale north-dipping faults and imbricate folding structures have developed in the Cretaceous ultra-deep tight sandstone reservoirs in Bozi-Dabei area of Kuqa Depression of Tarim Basin under the north-to-south thrust-nappe movement in this area. This complex structural morphology results in highly variable in-situ stress fields, leading to significant differences in reservoir modification effectiveness. Therefore, it is urgent to clarify the disturbance characteristics of the in-situ stress caused by the complex structures in the study area. In this study, multiple methods were combined for the accurate interpretation of the current in-situ stress of a single well. The disturbance effects of faults, folds, and fault-fold composite structures on the in-situ stress were analyzed separately. The relevant disturbance mechanisms were identified, and a zoning map of the disturbance characte-ristics of the in-situ stress for the study area was presented. Based on these disturbance characteristics, models of in-situ stress disturbance for different structures, as well as recommendations for well deployment and trajectory, were proposed. Faults exhibit an unloading effect on the in-situ stress, leading to varying degrees of reduction in the horizontal principal stress gradient near the faults, with the maximum reduced by about 0.3 MPa/hm. Near EW-oriented faults, the regional stress direction near SN exhibits a clockwise deflection, with the maximum deflection angle reaching 60°. The disturbance range of faults with different scales is approximately 60% of the fault throw. A disturbance of the in-situ stress appears when the strata curvature exceeds 0.4 km-1. The in-situ stress is lower than the regional stress in the upper tensile disturbance zone of the folded strata, while it increases in the lower compressive disturbance zone. In the tensile disturbance zone, the maximum decrease in the horizontal principal stress gradient is approximately 0.3 MPa/hm, with the stress direction deflecting counterclockwise, reaching a maximum deflection angle of 70°. The greater the fold deformation curvature, the thicker the tensile disturbance zone, and the more significant the disturbance. Under fault-fold composite structures, the superposition of fault disturbance zones and fold tensile disturbance zones further reduces the magnitude of the in-situ stress. After offsetting the disturbance effects of both, the in-situ stress direction deviates less or does not deviate at all from the regional stress. Considering the difficulty of reservoir modification and the characteristics of tight gas enrichment, drilling should be prioritized in the overlapping areas of faults and fold tensile disturbance zones within the fault-fold composite structure zone. It is recommended that the drilling depth should not exceed the neutral plane of the folds, and the horizontal well trajectory should be designed along the EW direction.

Fractures play a crucial role in tight sandstone gas reservoirs with low permeability and low effective porosity. If open, they not only significantly increase the permeability of the reservoir but also serve as channels connecting the storage space. Among numerous fracture identification methods, seismic data provide unique advantages for fracture identification owing to the provision of three-dimensional information between wells. How to accurately identify the development of fractures in geological bodies between wells using seismic data is a major challenge. In this study, a tight sandstone gas reservoir in the Kuqa Basin (China) was used as an example for identifying reservoir fractures using deep-learning-based method. First, a feasibility analysis is necessary. Intersection analysis between the fracture density and seismic attributes (the characteristics of frequency, amplitude, phase, and other aspects of seismic signals) indicates that there is a correlation between the two when the fracture density exceeds a certain degree. The development of fractures is closely related to the lithology and structure, indirectly affecting differences in seismic attributes. This indicates that the use of seismic attributes for fracture identification is feasible and reasonable. Subsequently, the effective fracture density data obtained from imaging logging were used as label data, and the optimized seismic attribute near the well data were used as feature data to construct a fracture identification sample dataset. Based on a feed-forward neural network algorithm combined with natural fracture density and effectiveness control factor constraints, a trained identification model was obtained. The identification model was applied to seismic multi-attribute data for the entire work area. Finally, the accuracy of the results from the training, testing, and validation datasets were used to determine the effectiveness of the method. The relationship between the fracture identification results and the location of the fractures in the target reservoir was used to determine the reasonableness of the results. The results indicate that there is a certain relationship between multiple seismic attributes and fracture development, which can be established using deep learning models. Furthermore, the deep-learning-based seismic data fracture identification method can effectively identify fractures in the three-dimensional space of reservoirs.

The Bozi-Dabei area in the Kuqa Depression host high-quality reservoirs in the Bashijiqike Formation and Baxigai Formation sandstones of the Lower Cretaceous, in which reservoirs yield significant industrial gas flow despite being situated at a considerable burial depth of 8200 m. The geological history of the target formation involves multiple phases of tectonic movements, resulting in the development of multi-genetic fractures that enhance the reservoir's storage and seepage capacity. Based on the results of the drilling core, field profile survey, imaging logging, and experimental analysis, this study presents an analysis of fractures in the Lower Cretaceous dense sandstone reservoir of the Bozi-Dabei area, andclarifies the characteristics and controlling factors of the multi-genesis and multi-period fractures. Additionally, it proposes an effective fracture development model that accounts for geo-stress control. In the Bozi-Dabei area, the prevailing high extrusion stress environment has led to the development of predominantly regional tectonic fractures and fault-related fractures, with relatively gentle deformation-related fractures. The results of a combination of multi-attribute data determination techniques, including fracture filling, inter-cutting relationship, fracture filling isotope, inclusions, and cathode luminescence tests, this study reveals that the reservoir fractures have experienced three major periods of tectonic movement. The regional tectonic fracture development is mainly controlled by stratigraphic lithology and thickness, while the proximity influences fault co-derived fractures to the fault and the relative positions of the upper and lower plates of the fault. The shift in the direction of the late horizontal maximum principal stress leads to the opening or closing of early fractures under different conditions in the Bozi-Dabei area, consequently affecting the degree of fracture opening and effectiveness. Notably, when the horizontal maximum principal stress is deflected to intersect with early fractures at a smaller angle or even superimpose, the fracture effectiveness of the related group system in the deflection direction improves, resulting in an overall coordination. The distribution characteristics of the fracture system in this highly productive reservoir are the result of dominant configurations from multi-phases of geological activities.

Objective The sedimentary palaeogeomorphology of the Permian Qixia Formation in Sichuan Basin has key influence over the distribution and evolution of carbonate reservoirs. Restoring and characterizing the sedimentary palaeogeomorphology of Gaoshiti area can gain further understanding of the distribution of favorable sedimentary facies and predict the distribution of high-quality reservoirs. Methods Based on the division of the third-order sequence, the high-resolution sequence stratigraphic framework was established by using geochemical proxies, petrological markers and logging markers. Two kinds of sedimentary microfacies, i.e. beach core and beach wing, were also identified. In addition, this study has calculated the difference of layer thicknesses in the sequence, and has identified different types of sedimentary sequences. A number of values including the beach core/beach wing value, Fe/Mn and MgO/Al2O3 ratios and other geochemical parameters were also calculated. The characteristics of the above parameters on the plane are analyzed and re-evaluated, which are all used to restore the palaeogeomorphic characteristics of the sedimentary period of the Qixia Formation in the study area. Results The result of research shows that the palaeogeomorphic characteristics of the 1st Member of Qixia are higher in the northwest and south, lower in the middle, and the palaeogeomorphic drop is obvious. Our new results show that the palaeogeomorphic highlands of the 2nd Member of Qixia are distributed in the middle of the study area, that the western palaeogeomorphology is low, and that the overall difference of palaeogeomorphology is small. Conclusion According to the results of ancient landform restoration, Gaoshiti-Moxi area forms a shallow water ring zone in the northeast-southwest direction where granular shoals are developed. Local micro-positive structures and granular shoals are developed in the south. However, the distribution of micro-positive structures is so limit that the extension range of granular shoals is limit. This study highlights that future exploration and development should focus on the development area of granular shoals in the northeast-southwest direction.

The Lower Cambrian Qiongzhusi Formation in Sichuan Basin and on its periphery is rich in shale gas resources, and it has become one of the important shale gas development intervals in Sichuan Basin. Controlled by complex sedimentary setting, the silty shale reservoir in Qiongzhusi Formation has various lithofacies and strong heterogeneity longitudinally, which restricts the exploration and development of shale gas. Therefore, it is urgent to study the sedimentary characteristics, sedimentary facies and sedimentary models. Based on the previous understanding of tectonic setting and sequence stratigraphy, and through detailed analysis of rock data, well logging data, geochemistry data and paleontology data, this paper clarifies the Early Cambrian sedimentary background of combined ocean-paleoland influence, moderate water depth and widespread reduction of Sichuan Basin and its periphery. The paper also believes that the Qiongzhusi Formation is mainly deposited in shore facies and continental shelf facies. The continental shelf facies are dominated, including shallow water continental shelf subfacies and deep water continental shelf subfacies. Based on the analysis of the combined action of wave and tide, seawater evaporation, suspension, rising ocean current, sedimentary paleogeomorphology and other fine-grained sedimentary influencing factors, and combined with the spatial distribution characteristics of sediments, the fine-grained sedimentary model of the Lower Cambrian Qiongzhusi Formation in Sichuan Basin and on its periphery is established, i.e., in the early stage of sedimentation, the effect of differential sedimentation is significant, the sequence thickness varies greatly, and the sedimentary characteristics and influencing factors differ greatly in different regions. In the middle stage of sedimentation, the effect of differential sedimentation is diminished and the difference of sequence thickness decreases continuously. In the late stage of sedimentation, with steady sedimentation, it enters the "open basin" stage, and the sequence thickness tends to be consistent.

The Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation in Lintanchang area of the southeastern Sichuan Basin has good exploration and development conditions, and clarifying the paleo-fluid pressure evolution is of great significance for revealing the process of shale gas accumulation and fugitive emission. Taking the shale tectonic fractures and fluid overpressure fracture veins of the Wufeng-Longmaxi formations in Lintanchang area as the research object, the paleo-fluid pressure evolution process in this area and its controlling impact were investigated using cathodoluminescence, inclusion temperature measurement, laser Raman analysis, and basin simulation. The study shows that: (1) Lintanchang area has experienced four stages: normal pressure, mild overpressure to normal pressure, overpressure, and pressure relief. Overpressure is mainly due to hydrocarbon generation. Pressure relief is mainly caused by shale gas fugitive emission. The gas reservoir pressure relief reaches 54% of the initial pressure during the pressure relief stage. (2) There are two stages of vein filling in the fractures at the bottom of the black shale in the Wufeng-Longmaxi formations. The first stage is formed in the sedimentation and burial stage at 131-118 Ma, the temperature is 178-205 ℃, and the trapping pressure of methane inclusions is 105.6-119.8 MPa. The second stage is formed in the tectonic uplift stage at 25-18 Ma, the temperature is 150-175 ℃, the methane inclusions have relatively low salinity and its trapping pressure is 80.8-92.1 MPa. The low pressure coefficient (1.37-1.49) indicates that mass fugitive emission has occurred. (3) The late tectonic movement, especially the rapid uplift in the late Himalayan period, is the root cause of the fugitive emission and pressure relief of the gas reservoirs. The decrease of the roundness and pore size of the organic pores indicates the deterioration of reservoir physical properties. However, due to the long formation and preservation time of the gas reservoirs, the shale in the Wufeng-Longmaxi formations in Lintanchang area still has good exploration potential. This study is helpful to deepen the understanding of the accumulation mechanism of the normal-pressure shale gas reservoirs in Lintanchang area and can provide theoretical guidance for optimal selection of favorable shale gas exploration areas.

In the Sichuan Basin, geologic conditions are complex in deep layers. Burial depth of shale reservoirs is high. Gas well productivity is widespread low, and hydraulic fracturing confronts with extremely large challenges. In order to search for "engineering sweet spots" of deep shale gas layers, Yongchuan and Dingshan areas were taken as the examples. In-depth discussion was conducted on affecting factors of hydraulic fracturing results in deep shale reservoirs by drilling, core, imaging logging and seismic data, based on measured rock mechanical parameters, development degree of natural fractures, natural fracture effectiveness, horizontal stress difference and included angle between horizontal well track and the minimum main horizontal stress. Study results demonstrated that No.31 sublayer of the first member of Longmaxi Formation in Yongchuan and Dingshan areas, southern Sichuan had the best brittleness as the first-choice target horizon for hydraulic fracturing. Shorter distance from the faults, higher pump pressure and operational pressure, and smaller reconstructed volume. Good extension and turning capacity of the fractures could beguaranteed when included angle between hydraulic and natural fractures was roughly 55°. In silicon-rich shale and faulting zones, lower minimum main horizontal stress, easier-diffused hydraulic fractures. Higher included angle between horizontal well track and maximum main horizontal stress azimuth, better fracturing results. Finally, evaluation index system of "engineering sweet spots" for marine shale gas in complex structural areas of Yongchuan and Dingshan was constructed. Class Ⅰ geologic and engineering "sweet spots" were optimized in Yongchuan and Dingshan areas.

The thin but widely distributed sandstones in the shallow-water deltas have the potential to hold large deposits of natural gas. The fluvial sand bodies formed from river channels with different sedimentary facies and sandstone architectures have remarkable heterogeneities. The results of this investigation suggest that the sandstone architectures of river channels have a significant impact on the hydrocarbon accumulation and production of sandstone reservoirs. Information regarding the sandstone origin and architecture of shallow-water deltas, especially of the fingered bar type, is still very limited. This investigation focused on the channel sandstones in the shallow-water delta of the Jurassic Shaximiao Formation on the eastern slope of the western Sichuan Basin in China. Based on data from cores and logs of sandstones, seven types of lithofacies and four sedimentary facies were identified. Sand-rich sedimentary facies, including distributary channels, mouth bars, and overbanks, have merged to form four types of compound sandbodies corresponding to the fourth-order architectural unit in the architectural classification. Four types of compound sand bodies were classified, including CS1 (variable distributary channel sand body), CS2 (diverting channel and residual overbank sand body), CS3 (diverting channel and residual mouth bar sand body), and CS4 (terminal channel and residual mouth bar sand body). Relatively good physical properties occur in the sandstone architectures of types CS3 and CS4, with an average porosity of 11.06% and an average permeability of 0.97 mD. Sandstone architectures from the Jurassic Shaximiao Formation of the study area were controlled by water depth and climate, tectonic subsidence, distance from provenance, erosion effect, and channel sinuosity and discharge. With strong lateral erosion, a shallow-water delta would have more sandstone architectures of types CS3 and CS4 in the high sinuosity of channels far from the provenance. Furthermore, sandstone architectures of types CS3 and CS4 are prone to form in connected channel sandbodies with relatively high contents of natural gas of approximately 4.48 × 104 m3/d. The results of this investigation are beneficial to improve the understanding of the characteristics of sandstone distributions in shallow-water deltas, especially in fingered bar types, and to guide oil and gas explorations in shallow-water delta systems.

Due to a great increase in the plasticity of deep marine shale reservoirs in southern Sichuan under high-temperature and high-pressure conditions, the single brittleness evaluation method is difficult to effectively characterize its fracability, which significantly limits the selection of sweet spots and fracturing reconstruction in the area. In the case of the deep marine shale reservoir of the Wufeng-Longmaxi formations in the southern Sichuan Basin, through triaxial high-temperature and high-pressure experiments, fracture toughness and X-ray diffraction experiments, the mechanical properties and its influencing factors in the shale reservoir are studied, and the rock fracture morphology under various loading conditions is quantified. According to the morphological characteristics of shale, the analysis of influencing factors and comprehensive quantitative evaluation of the brittleness has been carried out. The deep marine shale resource in the southern Sichuan Basin is likely to be characterized by its high elastic modulus and low I fracture toughness. The mineral composition, temperature, pressure, and degree of bedding development are the primary factors for determining the brittleness; with high quartz mineral content (>50%), low confining pressure (

Introduction: The Xujiahe Formation in the Yingshan-Longgang area of the Sichuan Basin has abundant tight oil and gas resources. However, the complex geological conditions and insufficient understanding of the magnitude and direction of in-situ stresses severely limit exploration and development of oil and gas resources in the region. This has made it difficult to carry out hydraulic fracturing and horizontal well deployment in the region.Methods: Based on experimental analyses, including acoustic emission experiments, wave velocity anisotropy experiments, and paleomagnetic experiments, this study evaluated the magnitude and direction of in-situ stresses, while also combining electrical imaging logging and acoustic wave logging data. This provides a basis for hydraulic fracturing in the research area.Results and Discussion: The experimental results indicate that the three-way stress state of the Xujiahe Formation is a strike-slip stress state, and the three-way stress value gradually increases with increasing burial depth. The Longgang area is particularly affected by the depth. The average azimuth angle of the maximum horizontal principal stress in the study area is N100°E, while tectonic deformation may cause a counterclockwise deviation of the maximum horizontal principal stress azimuth in the Yingshan area. Considering the influence of changes in the magnitude of in situ stress in the longitudinal direction on hydraulic fracturing extension mode, it is recommended to select the middle and upper sections of the Xu II for fracturing and transformation. Similarly, considering the distribution of natural fractures and the direction of the in situ stresses, it is suggested that the deployment azimuth angle for horizontal wells be between N20°–30°E.

The Daniudi Gas Field in the Ordos Basin has great natural gas potential, but a variety of fractures with complex origins was developed in the weathering crust karst reservoirs in the Middle Ordovician Majiagou Formation. In order to study the characteristics of fractures in the reservoirs, petrology and logging techniques were used to compare the differences between the fractures caused by steep ridges and structural fractures in terms of fracture development frequency, effectiveness, period, occurrence layer, shape, dip angle, etc. With elastic theory and fracture mechanics theory, the stress component at the end of fractures was analyzed, and the cause of the steep ridge fractures was discussed. Results show that the fractures caused by steep ridges are mainly vertical fractures and high-angle fractures. The fracture extension direction and fracture shape are irregular, and the fracture surface is uneven, with the characteristics of wide top and narrow bottom, and no bifurcation at the tail end. There is dissolution between the fractures, which is in a non- to semi-filled state, and the effectiveness of the fractures is high. The steep ridge fractures were controlled by factors such as ancient steep slope angle, rock layer inclination, initial fracture density and rock mechanical properties. Compared to structural fractures, the steep ridge fractures are more favorable for hydrocarbon migration. Studying the characteristics and causes of steep ridge fractures will help to further understand the distribution of weathered crust karst reservoirs, and identify favorable areas for the next exploration and development of the Daniudi Gas Field.

Carbonate reservoirs usually have a strong heterogeneity. The zones with relatively high permeability will form a channel through which fluids can easily flow. These channels are called thief zones. Thief zones have notable effects on oil or gas production, for example, high oil recovery rates at the early stage of the exploitation or an early water breakthrough during the later stage of water flooding development. Therefore, it is essential to have a precise identification of thief zones in carbonate reservoirs. In this research study, a simple approach to identify thief zones based on reservoir permeability gathered from well logging is developed. The thief zones are first identified at wells based on the lower limit value of the thief-zone permeability. This value is determined based on the dynamic production data, indicating that the thief zones identified by applying this criterion can reflect the product characteristics. Then, a zonal inter-well recognition method is adopted to identify the connectivity and distributions of thief zones in the regions far away from the well. This method is applied to identify thief zones for the Cretaceous Mishrif Formation in the H oilfield, Iraq. The reliability of the identification results is tested by the well-group injection test. The distributions of thief zones in the study region are discussed. In the study region, 12 members developed thief zones, while two members (i.e., MC1-3 and MC2-2) did not develop thief zones. Specifically, there are five members having a high level of thief-zone development. They are MB1-2C, MB2-1, MB2-2, MC2-3, and MC3-2. Comparing the distribution of thief zones with that of sedimentary microfacies, it is concluded that the thief-zone development is mainly controlled by the sedimentary microfacies and tends to occur in high-energy shoals.

The meteoric water has obviously changed the physical properties of dolostone reservoirs in the vertical vadose zone and the horizontal phreatic zone, but its influence on the dolostone reservoirs in the shallow burial zone beneath the phreatic surface is still unclear. This study aims to reveal the effect of meteoric water on the dolostone reservoirs in the shallow burial zone through X-ray diffraction, cathodoluminescence, C, O, and Sr isotope using the sample from Majiagou Formation in the Daniudi gas field, Ordos Basin. The diagenesis and paragenesis of the Ma 55 submember were identified and interpreted through petrological study, combined with data from electron probe, X-ray diffraction analysis, and geochemical parameters of diagenetic minerals. The color of the very fine crystalline dolomite under the cathodeluminescence is dark red and red. The order degree of dolomite ranges from 0.54 to 0.91, showing the origin of early seepage-reflux dolomitization. There are a large number of different calcite cements as fills within the pores and fractures. The color of the calcite cement under the cathodoluminescence is orange-yellow, with a zonal structure. Hydrothermal fluid during late diagenesis could be identified by the authigenic fluorite filling in the fractures. According to the assembly of diagenetic minerals, the very fine crystalline dolostones have experienced the seepage-reflux dolomitization, meteoric water dissolution, shallow burial cementation and late cementation. The void spaces of the very fine crystalline dolostones are intercrystalline pores and microfractures. Although a large number of dissolved pores and caves developed in the period of meteoric water dissolution, these caves and dissolved pores has been mostly filled by multi-stages of cementation. Therefore, the effect of meteoric water on dolostone reservoirs in the shallow burial zone beneath the phreatic surface is not obvious. The main controlling factor for the quality of dolostone reservoir was dolomitization. This study provides a new understanding of the influence of meteoric water on reservoir quality in the shallow burial zone during the paleokarst period.

The features and formation stages of natural fractures have significant influences on the fracturing of shale reservoirs and the accumulation of oil and gas. The characteristics and evolution of tectonic fractures in the Lianggaoshan Formation in Northeast Sichuan were investigated based on outcrops, drill cores, geochemical data, and acoustic emission test results. Our results demonstrated that the fracture types of the Lianggaoshan Formation were mainly low-degree bedding-slip fractures, followed by high-degree through-strata shear fractures and vertical tensile fractures. The influences of strike-slip faults on the fractures were stronger than those of thrust faults; fractures in thrust faults were concentrated in the hanging wall. The densities of tensile and shear fractures were inversely proportional to the formation thickness, while the density of interlayer slip fractures was independent of the formation thickness. The density of tectonic fractures was proportional to the quartz content. The fractures of the Lianggaoshan Formation were generated in three stages during uplift: (1) Late Yanshan–Early Himalayan tectonic movement (72~55 Ma), (2) Middle Himalayan tectonic movement (48~32 Ma), (3) Late Himalayan tectonic movement (15 Ma~4 Ma). Fractures greatly improve the oil and gas storage capacity and increase the contents of free and total hydrocarbons. At the same time, they also reduce the breakdown pressure of strata. This study facilitated the prediction of the fracture distribution and oil and gas reservoirs in the Lianggaoshan Formation and provided references for the selection of favourable areas for shale oil and the evaluation of desert sections in the study area.

Shale in the Jurassic Lianggaoshan Formation in central Sichuan exhibits strong heterogeneity. The study of the pore structure characteristics of different lithologies is crucial to the selection of the target interval. Shale samples of the Lianggaoshan Formation from well YS5 in the central part of the Sichuan Basin were analyzed using scanning electron microscopy, low-temperature nitrogen adsorption, high-pressure mercury injection (HPMI), and large -field splicing method -based scanning electron microscopy (LFS-SEM) to elucidate the pore structure characteristics of shale and their influencing factors. The mineral composition of the reservoir in the study area was diverse, primarily consisting of clay minerals, followed by quartz and calcite. The reservoir space comprised intergranular, granular, and organic matter pores, and oil was observed to fill the reservoir space. Reservoir characteristics varied with the lithological properties. In clayey shale, intergranular pores located in clay mineral particles and pores between pyrite and natural fractures were mainly observed, with a bimodal distribution of pore size and peak distribution of 10–50 nm and >100 nm. The storage space of ash-bearing shale mainly consisted of intragranular pores and intergranular (crystalline) micropores, with pore sizes primarily concentrated in the 10–50 nm range. The storage space in silty shale mainly developed in clastic mineral particles such as quartz, followed by clay mineral intergranular pores with a relatively wide distribution of sizes. Pores were mainly inkbottle-shaped and slit-type/plate-type pores, with an average specific surface area of approximately 6.9046 m2·g−1 and an average pore volume of approximately 0.0150 cm3·g−1. The full-pore capillary pressure curve was established using a combination of gas adsorption–desorption tests and HPMI. The fractal dimension of the sample pore structure was calculated, and a significant linear correlation was found between clay mineral content and the fractal dimension. Thus, the pore structure characteristics were mainly controlled by the content and distribution of clay minerals.

The Fengcheng Formation of the Mahu Sag is an unconventional reservoir that is of paramount importance for exploration and development of hydrocarbon resource. However, current research on natural fractures in the Fengcheng Formation remains limited, posing challenges for exploration of hydrocarbon resource in the region. This study is based on core observations, thin section identification, geochemical testing and the evolution of regional tectonic movements to investigate the characteristics and periods of formation of natural fractures to address this gap. According to the characteristics of natural fractures in the drilling core samples and microsections, the natural fractures in the Fengcheng Formation can be grouped into structural fractures and atectonic fractures. Structural fractures can be further divided into three subtypes: high-angle interlayer shear fractures, along-layer shear fractures, and tensile fractures. Additionally, non-tectonic fractures in this studied area are primarily bedding fractures, hydraulic fractures, and hydrocarbon-generating overpressure fractures. Vertically, fracture development is more prominent at the bottom of Feng #2 Formation and at the top of Feng #3 Formation. Results also indicate that natural fractures primarily formed during three distinct tectonic movement periods. The initial stage of fracture evolution pertains to the Late Permian period (243–266 Ma), filled with fibrous calcite, and exhibiting a uniform temperature of 70–100 °C. The second stage of fracture evolution occurred during the Late Indosinian to Early Yanshanian period (181–208 Ma), mostly filled or semi-filled with calcite, with a uniform temperature of 110–130 °C. The third stage of fracture development happened during the late Yanshanian to early Himalaya period (50–87 Ma), predominantly filled with calcite, and presenting a uniform temperature of 130–150 °C. Among the various types of structural fractures, the density of high-angle interlayer shear fractures demonstrates a positive correlation with daily gas production, indicating their vital role in promoting hydrocarbon resource production and transportation. Furthermore, microfractures generated by hydrocarbon-generating overpressure fractures exhibit small pore sizes and strong connectivity. These microfractures can create an effective permeability system by connecting previously isolated micropores in shale reservoirs, thus establishing interconnected pore spaces in the shale formation.

Unconventional shale reservoirs and typical fine-grained rocks exhibit complicated, oriented features at various scales. Due to the complex geometry, combination and arrangement of grains, as well as the substantial heterogeneity of shale, it is challenging to analyze the oriented structures of shale accurately. In this study, we propose a model that combines both multifractal and structural entropy theory to determine the oriented structures of shale. First, we perform FE–SEM experiments to specify the microstructural characteristics of shale. Next, the shape, size and orientation parameters of the grains and pores are identified via image processing. Then fractal dimensions of grain flatness, grain alignment and pore orientation are calculated and substituted into the structural entropy equation to obtain the structure-oriented entropy model. Lastly, the proposed model is applied to study the orientation characteristic of the Yan-Chang #7 Shale Formation in Ordos Basin, China. A total of 1470 SEM images of 20 shale samples is analyzed to calculate the structure-oriented entropy (SOE) of Yan-Chang #7 Shale, whose values range from 0.78 to 0.96. The grains exhibit directional arrangement (SOE ≥ 0.85) but are randomly distributed (SOE < 0.85). Calculations of samples with different compositions show that clay and organic matters are two major governing factors for the directivity of shale. The grain alignment pattern diagram analyses reveal three types of orientation structures: fusiform, spider-like and eggette-like. The proposed model can quantitatively evaluate the oriented structure of shale, which helps better understand the intrinsic characteristics of shale and thereby assists the successful exploitation of shale resources.

Electromagnetic radiation has been proposed to non-aqueously stimulate shale formations, which can generate fractures and enhance the porosity of the matrix. The proposed method consumes electricity and thereby possesses significant advantages for sustainable and environmental hydrocarbon production. In this study, we investigate the pore structure variations of marine shale during electromagnetic radiation. First, the prepared marine shale samples are exposed to electromagnetic radiation for different times; an infrared thermometer monitors the temperatures. Then, the nitrogen adsorption/desorption technique is applied to examine the evolutions of the pore structure. Next, a scanning electron microscope is adopted to reveal the morphology and identify newly developed pores. Lastly, fractal analyses are performed to quantify pore structure variations. The sample exhibits quick temperature rises, whose temperature reaches about 300 °C after 5 min of electromagnetic radiation. The elevated temperature causes clay dehydration, thermal expansion, and organic matter decomposition, leading to significant changes in pore structures. The nitrogen adsorption/desorption characteristics demonstrate enhancements in pore spaces, including volume, size, and surface area. Fractal analyses show that the pores become rougher and exhibit less heterogeneity after electromagnetic radiation. The obtained results demonstrate a great potential of using electromagnetic radiation to enhance the porosity of shale rocks.

The hydrothermal fluid–carbonate rock reaction is frequently regarded to occur in deep-burial diagenesis, and the hydrothermal dissolution is usually distributed and takes place along the faults. Previous studies have suggested that there was hydrothermal fluid activity locally in the Permian Qixia Formation in Sichuan Basin, likely related to the Emeishan basalt eruption. However, the effect of hydrothermal fluids on the carbonate rocks of the Qixia Formation in the central uplift of Sichuan Basin is still unclear. Based on the characteristics and geochemical parameters of the diagenetic minerals, this study aims to reveal the diagenetic alteration related to the hydrothermal fluid–rock reaction in the Qixia Formation and reestablish the diagenetic evolution by using the timing of diagenetic mineral precipitation. The methods include petrographic observation; trace and rare earth element (REE) analysis; C, O and Sr isotope measurement; fluid inclusion temperature measurement and cathodoluminescence analysis. According to the petrographic characteristics, the dolostones are mainly of crystalline structure, namely fine-medium crystalline dolostone, meso-coarse crystalline dolostone, and coarse crystalline dolostone, with the cathodoluminescence color becoming brighter in that order. The limestones from the Qixia Formation are of the bioclastic limestone type, with no cathodoluminescence color. Compared with dolostones, limestones have higher Sr content, lower Mn content, and heavier oxygen isotopes. With the crystalline size of dolostone becoming coarser, the oxygen isotopes of dolostones tend to become lighter. The meso-coarse crystalline dolostone has the highest Mn content and negative carbon isotope. Both limestones and dolostones have an obvious positive Eu anomaly in the Qixia Formation. However, the REE patterns of fine-medium crystalline dolostones are very different from those of meso-coarse crystalline dolostones. It is credible that there were two periods of hydrothermal fluid charging, with different chemical compositions. The first period of hydrothermal fluids could laterally migrate along the sequence boundary. Fine-medium crystalline dolostones were almost completely distributed below the sequence boundary and were dolomitized during the shallow burial period. As products of the hydrothermal fluid–dolostone reaction, the saddle-shaped dolomites in the meso-coarse crystalline dolostones were the evidence of the second period of hydrothermal fluids. As a result, the dolomitization model was established according to the timing of diagenetic mineral precipitation, which can improve that the geological understanding of the effect of hydrothermal fluid activities on the carbonate rocks in the Qixia Formation.

Tight sandstone oil and gas reservoirs are widely distributed, rich in resources, with a bright prospect for exploration and development in China. Due to multiple evolutions of the structure and sedimentary system, the gas–water distribution laws are complicated in tight sandstone gas reservoirs in the northern Ordos area. It is difficult to identify gas and water layers in the study area. In addition, in the development and production, various factors, such as the failure of the instrument, the difference in construction parameters (injected sand volume, flowback rate), poor test results, and multi-layer joint testing lead to unreliable gas test results. Then, the inaccurate logging responses will be screened by unreliable gas test results for different types of fluids. It is hard to make high-precision fluid logging identification charts or models. Therefore, this article combines gas logging, well logging, testing and other data to research the test and logging data quality classification. Firstly, we select reliable standard samples through the initial gas test results. Secondly, we analyze the four main factors which affect the inaccuracy of gas test results. Thirdly, according to these factors, the flowback rate and the sand volume are determined as the main parameters. Then, we establish a recognition chart of injected sand volume/gas–water ratio. Finally, we proposed an evaluation method for testing quality classification. It provides a test basis for the subsequent identification of gas and water through the second logging interpretation. It also provides a theoretical basis for the exploration and evaluation of tight oil and gas reservoirs.

It is generally difficult to identify fluid types in low-porosity and low-permeability reservoirs, and the Chang 8 Member in the Ordos Basin is a typical example. In the Chang 8 Member of Yanchang Formation in the Zhenyuan area of Ordos Basin, affected by lithology and physical properties, the resistivity of the oil layer and water layer are close, which brings great difficulties to fluid type identification. In this paper, we first analyzed the geological and petrophysical characteristics of the study area, and found that high clay content is one of the reasons for the low-resistivity oil pay layer. Then, the formation water types and characteristics of formation water salinity were studied. The water type was mainly CaCl2, and formation water salinity had a great difference in the study area ranging from 7510 ppm to 72,590 ppm, which is the main cause of the low-resistivity oil pay layer. According to the reservoir fluid logging response characteristics, the water saturation boundary of the oil layer, oil–water layer and water layer were determined to be 30%, 65% and 80%, respectively. We modified the traditional resistivity–porosity cross plot method based on Archie’s equations, and established three basic plates with variable formation water salinity, respectively. The above method was used to identify the fluid types of the reservoirs, and the application results indicate that the modified method agrees well with the perforation test data, which can effectively improve the accuracy of fluid identification. The accuracy of the plate is 88.1%. The findings of this study can help for a better understanding of fluid identification and formation evaluation.

The fractured-vuggy carbonate reservoirs display strong heterogeneity and need to be classified into different types for specific characterization. In this study, a total of 134 cores from six drilled wells and six outcrops of the Deng #2 and Deng #4 members of the Dengying Formation (Sichuan Basin, Southwest China) were selected to investigate the petrographic characteristics of void spaces in the fractured-vuggy carbonate reservoirs. Four void space types (VSTs) were observed, namely the solution-filling type (SFT), cement-reducing type (CRT), solution-filling breccia type (SFBT) and solution-enlarging fractures and vugs type (SEFVT). The CRT void spaces presented the largest porosity and permeability, followed by the SEFVT, SFBT and SFT. The VSTs presented various logging responses and values, and based on these, an identification method of VSTs using Bayes discriminant analysis (BDA) was proposed. Two test wells were employed for the validation of the identification method, and the results show that there is good agreement between the identification results and core description. The vertical distribution of VSTs indicates that the SFT and SEFVT are well distributed in both the Deng #2 and Deng #4 members. The CRT is mainly found in the Deng #2 member, and the SFBT occurs in the top and middle of the Deng #4 member.

The 5th sub-member in 5 Member Ordovician Majiagou Formation in Daniudi Gas Field, Ordos Basin, is deposited in an environment consisting of an ancient epicontinental sea, where very fine crystalline dolostone reservoir has developed. In this study, based on the petrological and geochemical characteristics, the genesis of the dolomite developed in M55 were studied by analyzing the properties and sources of the dolomitization fluids, and the influence of the paleogeomorphology differences on the distribution of dolostone was also discussed in order to clarify the distribution of the dolostone developed in the lime flat of the epicontinental sea. The dolostone of the M55 had a crystal structure, mainly including microcrystalline and very fine crystalline. The content of MgO and CaO in dolomite was negatively correlated, indicating that it was the result of replacement. The dolomite was dark red under cathode luminescence, and the distribution mode of rare earth elements showed the negative anomaly of Ce and Eu, indicating that the dolomitization fluid was sea-sourced fluid. The δ13C, δ18O, and 87Sr/86Sr isotope range of limestone was similar to that of Ordovician seawater in the study area, whereas the δ13C, δ18O, and 87Sr/86Sr of dolostone were obviously more positive than that of limestone. The substitute index of the salinity (Z) of the dolomitization fluid was higher than 122, which is higher than limestone (Z = 120.5), indicating that the dolomitization fluid was slightly evaporated seawater. The wormholes observed on the core and the gypsum in the penecontemporaneous period observed in the thin sections indicated that the dolostone was formed in a period when the sea level was relatively low, and it was the result of seepage–reflux dolomitization. By analyzing the correlation between the thickness of dolostone and the paleogeomorphology of the M55 of the sedimentary period, it was found that the thickness of dolostone at relatively high altitude was significantly larger than that of other areas. The development of dolostone was controlled by sea level, and the local paleogeomorphology controls the distribution of dolostone during the period of low sea level. There were many more limestone–dolostone cycles and larger cumulative thicknesses of dolostone at relatively higher topography. This study provides a theoretical basis for the prediction of the distribution of dolostone reservoirs in the carbonate tidal flat environment dominated by lime flats under the background of the ancient epicontinental sea.

The formation and evolution of (normal) fault affect the formation and preservation of some reservoirs, such as fault-block reservoirs and faulted reservoirs. Strain energy is one of the parameters describing the strength of tectonic activity. Thus, the formation and evolution of normal fault can be studied by analyzing the variation of strain energy in strata. In this work, we used physical simulation to study the formation and evolution of normal fault from a strain energy perspective. Based on the similarity principle, we designed and conducted three repeated physical simulation experiments according to the normal fault in the Yanchang Formation of Jinhe oilfield, Ordos Basin, China, and obtained dip angle, fault displacement, and strain energy via the velocity profile recorded by high-resolution Particle Image Velocimetry (PIV). As a result, the strain energy is mainly released in the normal fault line zone, and can thus serve as channels for oil/gas migration and escape routes connecting to the earth’s surface, destroying the already formed oil/gas reservoirs. One might need to avoid drilling near the fault line. Besides, a significant amount of strain energy remaining in the hanging wall is the reason why the normal fault continues to evolve after the normal fault formation until the antithetic fault forms. Our findings provide important insights into the formation and evolution of normal fault from a strain energy perspective, which plays an important role in the oil/gas exploration, prediction of the shallow-source earthquake, and post-disaster reconstruction site selection.

Multiple tests were conducted on graptolite shale samples from Middle Ordovician Pingliang Formation in three typical areas in Ordos Basin to investigate the relationship between micro-nano pore structure, graptolite content, rock composition, TOC, maturity, main and trace elements and gas content. The graptolite of Pingliang Formation concentrates in the black shale at the lower section of this layer. Pores in the shale are diverse in types, including pores made by extracellular polymeric substance (EPS), in bio-graptolite body, as inter-granular void of clay minerals, intra-granular, interstitial space between mineral crystals, micro-fractures, and intra-granular dissolution structures etc. Tests show that graptolite affected the sedimentary environment and shale gas accumulation; graptolites content is positively correlated to TOC, in a certain range, specific surface area is positively correlated to TOC and maturity, etc., as overall a lithologic inorganic and organic ratios. The rare earth elements (REE) patterns of the three areas are similar, indicating the same provenance. REE, Fe, Al and Ti content are negatively correlated to TOC, indicating the high REE content is not caused by organic matter enrichment, but related to the absorption of minerals particles. Gas content is positively correlated to specific surface area, TOC and maturity. The above factors contribute to space and size distribution of micro-nano pores in shale. Key words: graptolite shale, pore type, geochemical parameters, Ordovician Pingliang Formation, Ordos Basin

The exploration of shale gas in Fuling area achieved great success, but the reservoir characteristics and gas content of the lower Jurassic lacustrine in the northern Fuling areas remain unknown. We conducted organic geochemical analyses, Field Emission Scanning Electron Microscope (FE-SEM), X-ray diffraction (XRD) analysis, high-pressure mercury intrusion (MIP) and CH4adsorption experimental methods, as well as NMR logging, to study mineral composition, geochemical, pore structure characteristics of organic-rich shales and their effects on the methane adsorption capacity. The Da’anzhai shale member is generally a set of relatively thick (avg. 75 m) and high carbonate-content (avg. 56.89%) lacustrine sediments with moderate total organic carbon (TOC) (avg. 1.12%) and thermal maturation (Vitrinite reflectance (VR): avg. 1.19%). Five types of lithofacies can be classified: marl (ML), calcareous shale (CS), argillaceous shale (AS), muddy siltstone (MS), and silty shale (SS). CS has good reservoir quality with a high porosity (avg. 4.72%). The small pores with the transverse relaxation time of 0.6–1 ms and 1–3 ms comprised the major part of the porosity in the most lithofacies from Nuclear magnetic resonance (NMR) data, while the large pore (>300 ms) accounts for a small porosity proportion in the CS. The pores mainly constitute of mesopores (avg. 23.2 nm). The clay minerals with a large number of interparticle pores in the SEM contributes most to surface area in the shale lithofacies with a moderate TOC. The adsorption potential of shale samples is huge with an average adsorption capacity of 4.38 mL/g and also has high gas content (avg. 1.04 m3/t). The adsorption capacity of shale samples increases when TOC increases and temperature decreases. Considered reservoir properties and gas properties, CS with the laminated structures in the medium-upper section of the Da’anzhai member is the most advantage lithofacies for shale gas exploitation.

Shale gas is an effective gas resource all over the world. The evaluation of pore structure plays a critical role in exploring shale gas efficiently. Nitrogen adsorption experiment is one of the significant approaches to analyze pore size structure of shale. Shale is extremely heterogeneous due to component diversity and structure complexity. Therefore, adsorption isotherms for homogeneous adsorbents and empirical isotherms may not apply to shale. The shape of adsorption-desorption curve indicates that nitrogen adsorption on shale includes monolayer adsorption, multilayer adsorption, and capillary condensation. Usually, Langmuir isotherm is a monolayer adsorption model for ideal interfaces; BET (Brunauer, Emmett, Teller) adsorption isotherm is a multilayer adsorption model based on specific assumptions; Freundlich isotherm is an empirical equation widely applied in liquid phase adsorption. In this study, a new nitrogen adsorption isotherm is applied to simultaneously depict monolayer adsorption, multilayer adsorption, and capillary condensation, which provides more real and accurate representation of nitrogen adsorption on shale. In addition, parameters are discussed in relation to heat of adsorption which is relevant to the shape of the adsorption isotherm curve. The curve fitting results indicate that our new nitrogen adsorption isotherm can appropriately describe the whole process of nitrogen adsorption on shale.

The two-flash experiment, constant composition expansion experiment, saturation pressure measurement experiment, and phase transition observation experiment from well bottom hole to well head of four high CO2 content natural gas samples were carried out by using the JEFRI-PVT apparatus made from DBR Company of Canada. The experimental results show that in the four high CO2 content gas samples no phase transitions will take place at temperatures greater than 35°C. In the gas-liquid two-phase region, saturation pressures, critical pressure, critical temperature, and an integrated P-T phase diagram of different CO2 content natural gases are calculated by using the modified PR equation of state and modified (T) equation proposed by Saffari. The deviations between the saturation pressure calculated by using the model proposed in this study and experimental measured saturation pressure are very small; the average relative error is only 2.86%. Thus, the model can be used to predict the phase equilibrium parameters of high CO2 content natural gas.