The Benxi Formation coal-measure strata in the Ordos Basin exhibit extensive distribution and high gas content， serving as a principal target for current exploration activities. However， the spatial-temporal coupling mechanisms governing hydrocarbon generation and reservoir evolution remain unclear， thereby constraining efficient exploration of deep coal-rock gas. This study investigates the Benxi Formation coal through semi-closed system pyrolysis experiments integrated with multi-scale characterization techniques including rock pyrolysis， carbon isotope analysis， low-temperature CO₂/N₂ adsorption， nuclear magnetic resonance （NMR）， and field emission electron microscopy， aiming to elucidate the co-evolutionary patterns between hydrocarbon products and pore structure. Results demonstrate that： （1） When R O<1.08%， the hydrocarbon generation yield is low. Compared with the original low-rank coal rock， pore development shows minimal change and is insignificant. （2） When 1.08%≤R O≤1.3%， liquid hydrocarbons dominate the products， representing the peak oil generation stage. Concurrently， liquid hydrocarbons begin cracking， accompanied by the generation of gaseous hydrocarbons. During this stage， the volume of gaseous hydrocarbons generated is relatively small； consequently， the porosity created by gaseous hydrocarbon generation is limited. However， scanning electron microscopy （SEM） and nuclear magnetic resonance （NMR） characterizations reveal a substantial increase in macropores compared to the previous stage， which is attributed to hydrocarbon-generation pressurization occurring in this oil window. （3） When R O>1.3%， thermal cracking of hydrocarbons and thermal degradation of kerogen continue. The yield of gaseous hydrocarbons increases rapidly. The content of micropores and macropores increases significantly， while the overall growth of mesopores is relatively minor. This indicates that micropores and macropores constitute the primary pore types generated during the hydrocarbon generation process in coal rocks. Actual geological samples show comparability with simulation results. The coal rocks primarily develop micropores and macropores. Micropore development is notably influenced by thermal effects， with pore volume exhibiting a strong positive correlation with R O. Macropore volume initially increases （R O<2.0%） and subsequently decreases （R O>2.0%） as thermal maturity progresses. This simulation study on hydrocarbon generation and pore evolution in low-rank coal rocks provides a theoretical foundation for deep coalbed methane exploration in the Ordos Basin.
The Zigong area in the southern part of the Sichuan Basin has been affected by multi-stage and multi-directional tectonic stresses， developing natural fracture systems with multiple scales and types， which have an important impact on the enrichment， preservation and development of shale gas. By comprehensively utilizing data such as core samples， thin sections， dipole sonic logs and image logs， the types and development characteristics of natural fractures in the Long 1-1 sub-member shale reservoir in the Zigong area were quantitatively characterized. Combined with experimental analyses such as fluid inclusion analysis and acoustic emission testing， the fracture formation mechanism was clarified， and a comprehensive evaluation of fracture openness was carried out. The research results show that the Long 1-1 sub-member shale reservoir in the study area has developed structural fractures， diagenetic fractures and overpressure fractures. Among them， high-angle structural fractures in the NNE and NEE directions are dominant， with a high degree of fracture development and good effectiveness. In different tectonic units， the fracture development patterns change regularly. The shale in the Long 1-1 sub-member has experienced three stages of fracturing and three stages of cementation events. The first two stages of structural fractures have undergone multiple stages of filling and have relatively poor effectiveness； the late-stage structural fractures are hardly filled and have relatively good effectiveness. The CFF （Coulomb Failure Function） value of fractures in the study area is generally less than 0， and under the in-situ stress state， the fractures are in a stable state. From the northwest to the southeast and then to the north， the CFF value gradually increases， reflecting the gradual increase in fracture openness. Two stress mechanisms， namely normal faulting and strike-slip faulting， are mainly developed in the study area. Under different stress mechanisms， the orientations of preferentially opened fractures are different. Under the normal faulting stress mechanism， the NWW-SEE trending fractures parallel to the direction of the current maximum principal stress are preferentially opened. Under the strike-slip faulting stress mechanism， the high-angle NEE-SWW and NW-SE trending fractures with an angle of 30° to the current maximum principal stress are preferentially opened. The research results have provided a theoretical basis for the optimization of shale gas sweet spots， the prevention and control of fracture stringing and casing deformation， and the optimization of horizontal well trajectories in the study area.
The geological resource conditions of shale gas form the foundation， while engineering implementation factors are crucial for formulating reasonable development technical strategies and fully unlocking production capacity. Carrying out geology-engineering characteristics analysis and evaluation is a necessary task for the efficient development of shale gas. Carrying out geology-engineering characteristics analysis and evaluation is a necessary task for the efficient development of shale gas. This study on deep shale gas in the western Chongqing area considers reservoir scale， reservoir quality， and engineering intervention intensity. Based on the integrated geology-engineering concept， key indicators such as structural fracture characteristics， Class I reservoir thickness， gas-bearing characteristics， and in-situ stress are selected to classify geological. The results show that： （1） The deep shale gas reservoirs in the western Chongqing area exhibit favorable quality， with a porosity of 3.5%-6.4% and gas content of 4-9 m³/t. The reservoir scale shows significant variation， with Class I reservoirs measuring 4-16 m in thickness and Class I+II reservoirs 15-65 m， reflecting favorable geological resource conditions supported by substantial reservoir thickness. （2） The shale exhibits good fracturability， yet the degree of natural fracture development is relatively low. The horizontal stress difference ranges from 13-22 MPa， and the in-situ stress Q-value increases from north to south， resulting in gradual instability of the geological mass. This trend is attributed to enhanced stress anisotropy， which correlates with the degradation of subsurface structural stability. （3） The study area can be subdivided into five geology-engineering types. The “double excellent area” features superior geological foundations and low engineering implementation risks； the “thin reservoir and low-stress” area has poor resource foundations but low engineering risks， having basically adapted to the “long horizontal section + high-intensity stimulation” model； the “thick reservoir and medium-risk” area possesses the best geological resource foundations and should adhere to the principle of “ensuring stimulation effects while prioritizing risk prevention and control” to minimize construction risks and enhance gas well productivity； meanwhile， the “complex fault” and “strong strike-slip high-risk” areas exhibit the highest engineering risks， and to address this， measures such as fine-scale characterization of multi-level faults should be fully implemented to reduce stresses associated with stress field instability.
The ideal gas adsorption potential equation widely used at present is not suitable for the theoretical study of shale gas and coalbed methane adsorption potential. In this paper， on the basis of assuming that the adsorption phase is a compressible gas， the real gas equation of state （R-K equation） is introduced into the adsorption potential definition formula to construct the adsorption potential equation of supercritical gas， in which the adsorption phase pressure is calculated using the Amankwah equation. In view of the uncertainty of the parameter K value of the Amankwah equation， a K value determination method based on the consistency of the adsorption characteristic curve and the accuracy of the prediction results of the isothermal adsorption curve was proposed， and the adsorption phase pressure was calculated. At the same time， based on the comparative analysis of the adsorption potential of ideal gas and supercritical gas， the simplified adsorption potential equation of supercritical gas was proposed. It is found that the optimal K value of the Holme shale adsorption CH4 system is 2.9， the adsorption phase pressure is 17.11-32.19 MPa in the range of 300-373 K， and the supercritical gas adsorption characteristic curve is consistent. At 373 K the average relative error of the prediction results of the rising section of the excess adsorption capacity curve based on the adsorption characteristic curve is only 1.77%， which proves the rationality of the adsorption potential equation of supercritical gas. At the same time， although the characteristic curve obtained based on the ideal gas adsorption potential equation can meet the consistency requirements， it lacks reasonable theoretical basis， and there is an abnormal phenomenon that the adsorption potential is less than 0 at the high adsorption phase volume. The simplified equation of supercritical gas adsorption potential is simple in form and easy to be popularized and applied.
To investigate the causes of the abnormal gas logging values in Well Xiangandi-1， a molecular model of the Lower Cambrian black shale in western Hunan Province was constructed using molecular simulation， and the controlling factors of its gas content were systematically studied. The results indicate that water molecules and CH4 exhibit a pronounced competitive adsorption effect within shale pores. As water content increases from 5.5% to 20%， CH4 adsorption decreases by 26.64%-90.04%， demonstrating that water content is one of the key factors controlling shale gas content. Geological evolution correction results reveal that two large-scale uplift and denudation events significantly disrupted the reservoir pressure-temperature conditions and sealing capacity of the Lower Cambrian black shale in western Hunan， leading to extensive gas desorption and loss. At the present burial depth of 778 m， the CH4 content is nearly zero， consistent with the measured logging results. Moreover， although the diffusion coefficient is relatively low （-0.78 km²/Ma）， the cumulative diffusion distance during the -540 Ma geological history reaches about 421 km²， which is sufficient to cause large-scale gas loss. The development of tectonic fractures further accelerated this process. This study elucidates the microscopic mechanisms and controlling factors underlying the reduction of shale gas content in the Lower Cambrian black shale， highlights the synergistic effects of water inhibition， tectonic evolution， and long-term diffusion， and provides a new perspective for understanding deep shale gas preservation and enrichment mechanisms， as well as an important reference for unconventional natural gas potential assessment and favorable area selection.
The newly discovered fault-controlled fracture-cavity hydrocarbon reservoir in the ultra-deep carbonate formations of the Shunbei-Fuman area， located within the Shuntuoguole low uplift of the Tarim Basin， represents a unique new type of oil and gas reservoir. This reservoir is controlled by strike-slip faults， mainly consisting of light oil and condensate gas， with characteristics of deep burial （over 7 300 m） and multi-stage accumulation. This study employs a fine dissection approach， based on the geological characteristics of the ultra-deep Ordovician fault-controlled fracture-cavity reservoirs in the Shunbei–Fuman area， and follows the technical specifications for calibrated units dissection. Nine key parameters are established for calibrated units analogy， including basin type， exploration area， reservoir lithology， reservoir type， pore combination， reserve abundance， resource abundance， migration-accumulation coefficient， and recovery coefficient. The evaluation results indicate that in the carbonate field of the Shuntuoguole low uplift in the Tarim Basin， the oil reserve abundance of the Ordovician fault-controlled fracture-cavity reservoirs ranges of （25-60）×104 t/km2， and the gas reserve abundance ranges of （1.5-6.5）×108 m3/km2. Additionally， the oil resource abundance is （12.5-14.5）×104 t/km2， the gas resource abundance is （0.45-1.0）×108 m3/km2， the oil recovery is 12%-16%， and the gas recovery is 30%. This research conducted a detailed dissection of calibrated units and constructed key analogy parameters for fault-controlled fracture-cavity hydrocarbon reservoirs. The findings not only expand the types of calibrated units but also provide an effective reference for analogy and resource evaluation in ultra-deep carbonate rock fields within China's three major craton basins.
The Permian Pingdiquan Formation in the Shushugou Sag has favorable conditions for the formation and enrichment of shale oil. Multiple wells have produced industrial oil flows， making it an important interval for shale oil production construction in the Junggar Basin. Taking the middle member of the Pingdiquan Formation （P2 p 2） in the Shishugou Sag as an example， the type I-VI source-reservoir combination types were divided according to the lithologic assemblage characteristics， and the source rocks， reservoirs， oil-bearing properties and distribution characteristics of different source-reservoir assemblages were clarified， and the favorable areas for shale oil exploration were determined. The results show that six types of source-reservoir combinations are developed in the study area. Type I source-reservoir combination： the lithological assemblage is characterized by sandstone wrapping mudstone. The source rocks have weak hydrocarbon generation potential， mainly developing ultra-low porosity-ultra-low permeability reservoirs with poor oil-bearing properties. Type II source-reservoir combination： similar to type I， but with developed black shales， showing good oil-bearing properties. Type III source-reservoir combination： the lithological assemblage is sandstone-mudstone interbedding. The source rocks have relatively strong hydrocarbon generation potential， mainly developing ultra-low porosity-ultra-low permeability and tight reservoirs with poor oil-bearing properties. Type IV source-reservoir combination： different from type III， it is characterized by developed black shales， showing better oil-bearing properties. Type V and type VI source-reservoir combinations： the lithological assemblages exhibit the feature of mudstone wrapping sandstone， mainly developing tight reservoirs. Type VI has developed black shales， with stronger hydrocarbon generation potential than type V， showing good oil-bearing properties， while type V has poor oil-bearing properties. The types II， IV， and VI source-reservoir combinations with better oil-bearing properties are mainly distributed in the middle-lower part of the P2 p 2. In the distribution areas of types II and IV source-reservoir combinations in the northeast， multiple wells have obtained industrial oil flows， serving as the main current production construction areas of the sag. Each well in the distribution area of type IV source-reservoir combination in the south shows good oil-bearing indications， being favorable areas for further exploration in the sag. The study on the source-reservoir combinations of the P2 p 2 has guiding significance for the exploration and development of shale oil in the Pingdiquan Formation of the Shishugou Sag， and can also provide effective references for the large-scale exploitation of continental shale oil in the Zhundong area.
Conglomerate reservoir of Permian Lower Wuerhe Formation in Manan area is the key exploration and development target in Junggar Basin. However， the insufficient judgment of diagenetic fluid properties leads to the uncertainty of high-quality reservoir prediction. In order to definite the source of diagenetic fluids in conglomerate reservoir and its reservoir-forming effect， the diagenetic characteristics and geochemical characteristics were comprehensively studied by means of polarizing microscope， scanning electron microscopy， BSE， trace element （ e.g. Fe and Mn）， and stable isotopes （ e.g. C and O ）. The three genetic types of calcites are subdivided， and the identification index of diagenetic fluids from different sources and its reservoir-forming effect on conglomerate reservoirs are further clarified. The results show that diagenetic fluids can be divided into three types： mixed syndepositional water-meteoric freshwater fluid （δ18O （PDB） is characterized by weakly negative bias， δ13C （PDB） is within the range from -5‰ to 0‰）， hydrocarbon fluids （δ18O is within the range from -20‰ to -15‰，δ13C is within the range from -30‰ to -10‰） and hydrocarbon oxidizing fluids （δ18O is within the range from -20‰ to -15‰，δ13C is within the range from -65‰ to -30‰）. Mixed syndepositional water-meteoric freshwater fluid in early diagenesis primarily facilitated the formation of cements， occluding primary pores， with their reservoir effect being predominantly destructive. Hydrocarbon fluids， rich in organic acids and CO2， dissolved cements， increasing rock porosity， thus exhibiting constructive effects. Hydrocarbon oxidizing fluids led to methane oxidation， thereby hindering large-scale methane accumulation， making them destructive fluids for oil and gas reservoirs. The index of diagenetic fluids of conglomerate reservoir established in this paper is universal to continental sedimentary conglomerate reservoir. At the same time， it provides ideas for the study of reservoir-forming effect of diagenetic fluids from different sources.
The Permian is an important exploration stratum in the Junggar Basin at present. The Xiazijie Formation， which overlies the Fengcheng high-quality hydrocarbon in Well Pen-1 West Sag， has excellent hydrocarbon charging conditions. However， the previous understanding is relatively limited. especially the lack of systematic research on the sequence stratigraphy classification and sedimentary system， which has restricted the exploration and discovery process. By applying the T-R cycle theory and integrating the latest drilling and seismic data， the key sequence boundaries of the Xiazijie Formation were identified， the types and characteristics of sedimentary facies were clarified， and the distribution and evolution characteristics of sedimentary systems within the T-R cycle sequence framework of the Xiazijie Formation were determined. Research shows that： （1） In Well Pen-1 West Sag， two types of key sequence boundaries， namely third-order sequence boundaries and transgressive-regressive surfaces， can be identified in the Xiazijie Formation， which delimit two third-order sequences （SQ1 and SQ2） and the development of four systems tracts （LTST1-LRST2）. （2） The Xiazijie Formation is the first set of basin-type lacustrine sedimentary in Well Pen-1 West Sag. From early to late， the lake area continuously expanded. The main sedimentary facies types are fan deltas and lakes， which can be further divided into four subfacies and eight microfacies. （3） Within the T-R cyclicity sequence stratigraphic framework， the pre-existing topographic differences formed in the Early Permian and the episodic tectonic activities in the Middle Permian have a significant control on the distribution and evolution of the sedimentary system of the Xiazijie Formation： the transgressive systems tract is mainly characterized by compensation sedimentation， while the regressive systems tract is accompanied by changes in the main source areas， with fan delta constantly prograding and spreading out.
The Fengcheng Formation in the Mahu Sag of the Junggar Basin exemplifies a typical whole petroleum system， characterized by abundant hydrocarbon resources and promising exploration potential. Previous research extensively investigated the sedimentary environment， petrology， pore structure， and physical properties of the Fengcheng Formation within the study area. However， studies on diagenetic evolutionary sequences and quantitative reservoir pore evolution remain notably limited. Integrating thin-section microscopy， scanning electron microscopy （SEM）， X-ray diffraction （XRD）， and high-pressure mercury injection data， this study conducted a refined analysis of diagenetic sequences and pore evolution in the Fengcheng Formation of the northern Mahu Sag slope. We quantitatively assessed the differential impacts of each diagenetic process on three reservoir types and examined the coupling between pore evolution and hydrocarbon accumulation processes within this whole petroleum system. Results reveal that shale oil reservoirs in the northern slope’s Fengcheng Formation predominantly comprise felsic shale， tight oil reservoirs consist mainly of felsic siltstone， and conventional oil reservoirs are primarily lithic arkose. The formation underwent a complex diagenetic process involving alternating phases of mechanical compaction， multi-stage cementation， devitrification， and multi-stage dissolution. Compaction and cementation critically degraded reservoir quality in this whole petroleum system： compaction reduced porosity by 26.67% in shale oil reservoirs， 29.41% in tight oil reservoirs， and 23.84% in conventional oil reservoirs， while cementation uniformly decreased porosity by 2.5% across all three reservoir types. Dissolution partially enhanced reservoir properties， increasing porosity by 0.78% in shale oil reservoirs， 1.75% in tight oil reservoirs， and 2.68% in conventional oil reservoirs. This research definitively establishes the diagenetic sequences and quantitative pore evolution of the whole petroleum system in the Fengcheng Formation in northern slope， providing a critical foundation for evaluating its resource potential.
In recent years， significant progress has been made in Cambrian natural gas exploration in the Longdong area of the Ordos Basin. However， the genetic types and sources of the Cambrian gas remain unclear， severely constraining the exploration and development of deep natural gas in the Ordos Basin. This study provides a detailed analysis of the composition and carbon isotope characteristics of Cambrian natural gas in the Longdong area， comparing it with Upper Paleozoic coal-type gas from the Sulige area and Taiyuan Formation bauxite gas in Longdong area. The study investigates the genetic types， maturity characteristics of Cambrian natural gas， and analyzes its sources in combination with potential source rock features. The results show that the Cambrian natural gas in Longdong area is predominantly oil-type gas. Only Well L20 exhibits higher carbon isotope value in ethane and propane， indicating distinct coal-type gas characteristics， while other Cambrian gas samples show lower ethane and propane isotope value characteristic of typical oil-type gas. Except for Well L20， methane， ethane and propane carbon isotopes along with compositional characteristics further demonstrate that Cambrian natural gas in Longdong area mainly represents secondary cracked oil-type gas. All Cambrian natural gas in Longdong area has reached the over-mature dry gas stage， showing significant carbon isotope reversal features. Based on geochemical characteristics including genetic types and maturity， combined with potential source rock distribution， it is concluded that Cambrian oil-type gas in Longdong area primarily originates from high-abundance marine source rocks in the Cambrian Dongpo Formation of the Fuping–Luochuan Gulf in the southern part of the basin， while the coal-type gas in Well L20 derives from overlying Permian coal source rocks.
Based on the semi-closed thermal simulation system， evolution of composition and carbon isotope of light hydrocarbons from pyrolysis gas of sapropelic and humic source rocks were studied， which laid a foundation for the study of natural gas genesis in the Junggar Basin. The results show that pyrolysis gas from source rocks of Fengcheng Formation and Pingdiquan Formation is sapropelic gas. The carbon isotopes of ethane and propane are negatively deviated， with δ13C2<-32.0‰ and δ13C3<-31.1‰. The composition of C7 light hydrocarbons is： n-heptane > methylcyclohexane > dimethylcyclopentane， the content of n-heptane is greater than 40%， and the relative content of C5-7 normal alkanes is greater than 40%. The pyrolysis gas from source rocks of Carboniferous and Jiamuhe Formation is humic gas. The carbon isotope values of ethane and propane are relatively high， with δ13C2>-28.5‰ and δ13C3>-26.6‰. The composition of C7 light hydrocarbons is： methylcyclohexane > n-heptane > dimethylcyclopentane， the content of n-heptane is less than 40%， and the relative content of C5-7 normal alkanes is less than 40%. There are obvious differences in carbon isotope characteristics of light hydrocarbons from pyrolysis gas between sapropelic and humic source rocks. The distribution of carbon isotope of light hydrocarbons is less affected by temperature， which can be used for identification of natural gas source. The carbon isotopes of light hydrocarbons in sapropelic gas are negatively deviated， which are <-24‰ for benzene and toluene， <-26‰ for cyclohexane and methylcyclohexane， <-28‰ for n-hexane and n-heptane， and <-29‰ for 3-methylcyclopentane and 3-methylcyclohexane are. The carbon isotope values of light hydrocarbons in humic gas are high， which are >-24‰ for benzene and toluene， >-26‰ for cyclohexane and methylcyclohexane， >-27‰ for n-hexane and n-heptane， and >-28‰ for 3-methylcyclopentane and 3-methylcyclohexane.
In recent years， the deep coal rock gas in the Ordos Basin have entered the stage of large-scale commercial development. However， the rapid changes in the characteristic areas of deep coal reservoirs， as well as the large differences in fracturing construction technology and parameters， have led to significant differences in the productivity indicators of horizontal wells. The unclear main controlling factors for high production severely restrict the productivity improvement and cost reduction of deep coalbed methane wells. Therefore， this study takes the deep 8# coal seam in Jiaxian area on the northeast edge of the Ordos Basin as an example， and combines drilling， logging， core well analysis and testing， development dynamics and other data to carry out the subdivision of the 8# small layer and fine evaluation of the reservoir. The key geological engineering elements that affect the productivity of horizontal wells are screened， and the correlation evaluation of different geological engineering factors is carried out. The research results indicate that： （1） Proposing an initial capacity index can improve the rationality and accuracy of capacity evaluation； （2） The 8-1# coal in Jiaxian area has developed bright coal， with the best coal quality and gas content， and more developed cleavage， making it the optimal target location for horizontal well drilling. The proportion of gas content and free gas content， the drilling encounter rate of 8-1# coal， and the relative position of the trajectory to the coal seam top are the main geological factors controlling the high production of horizontal wells. The sand addition intensity， liquid use intensity， and the proportion of small particle sand are the main engineering factors controlling the high production of horizontal wells； This research can provide reference for the scale benefit development of deep coalbed methane in the Ordos Basin.
Distributed acoustic sensing （DAS） technology has been widely used in dynamic monitoring of horizontal well production. However， the downhole acoustic signal is complex and interfered. At present， the understanding of the acoustic response law of gas-water two-phase flow in horizontal wells is insufficient. It is still very difficult to quantitatively diagnose the production profile of horizontal gas wells through DAS data. In this paper， through indoor physical simulation experiments， the acoustic wave profiles in the production process of horizontal wells with different production and water-gas ratio are simulated and tested. Through fast Fourier transform and digital filtering， the effective frequency amplitude characteristics of DAS data under different simulation conditions are extracted， and the acoustic wave response law of gas-water two-phase flow in horizontal wells is analyzed. The relationship chart between DAS acoustic energy and wellbore velocity is drawn， and the model library of the relationship between DAS acoustic energy and wellbore velocity in gas-water two-phase flow horizontal wells is established by data regression. The quantitative relationship between wellbore velocity and DAS response under different simulation conditions is realized， which lays a model foundation for DAS data inversion and provides a new technical idea for solving the quantitative interpretation of gas-water two-phase flow profile in horizontal wells.
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