The eastern Ordos Basin is one of the most significant regions in China for large-scale exploration and development of deep coal-rock gas， where horizontal wells are the primary development method. Previous studies have shown that the effective drilled length of coal rock is one of the most important factors affecting gas-well production， which highlights the critical importance of horizontal well geosteering. Compared with the geosteering of sandstone horizontal wells， there are a series of difficulties in the coal rock， such as low amplitude structure complexity， strong vertical heterogeneity， poor wellbore stability， high time-effectiveness in geosteering， high requirements for trajectory control， high guidance costs， and no well-established geosteering method exists for deep coal-rock gas horizontal wells. Based on the horizontal well geosteering cases of more than 60 Benxi Formation 8# coal reservoirs in the eastern Ordos Basin， this article proposes an innovative method for differential fine geosteering of horizontal wells based on the geological characteristics of coal reservoirs in two zones and three types， considering the differences in geological conditions and well control levels. This method divides the target area into “two districts and three categories”， including a high well control zone with gentle structures， a low well control zone with gentle structures， and a complex structural zone. With the core of “earthquake determines structure， geology carves cycle”，three differentiated geological guidance modes such as “3D seismic + conventional MWD （Measurement While Drilling）”，“3D seismic + azimuthal gamma ray”， and “3D seismic + near-bit azimuthal gamma ray” are applied for different geological conditions. In addition， 10 countermeasures are formulated for four geological risks and six layer cutting relationships. The promotion and application of this geosteering method have helped increase the drilling efficiency of coal-rock gas horizontal wells from 84.6% to 97.2%， and reduce the average drilling duration for the horizontal section from 12.6 days to 6.8 days. It has significantly lowered the geosteering costs for coal-rock gas horizontal wells and provided robust support for advancing key technologies in the effective development of coal-rock horizontal wells in the Ordos Basin.
In the depletion production process of tight gas wells， as the formation pressure declines， the production pressure gradient from the near-well region to the far-well region gradually diminishes. Meanwhile， the influence of low-velocity non-Darcy seepage on production becomes more pronounced. These dynamics complicate the evaluation of reserve utilization. In this work， through laboratory experimentation， the phenomenon of low-velocity non-Darcy seepage of gas under different pore pressures in tight water-bearing rocks is investigated. Using fractured horizontal wells as an example， a reserve utilization evaluation model based on dual-porosity seepage characterization is established. The variation law of reserve utilization and the recovery factor within the drainage area during the depletion process are quantitatively depicted， and the impact of different stimulation measures is probed. The results indicate that： （1） Incorporating the low-velocity non-Darcy seepage into the motion equation enables a more precise description of the nonlinear variation characteristics of gas flow with respect to the pressure difference. As a consequence， the established numerical simulation model can assess the dynamic reserves utilization with higher accuracy. （2） During the progression of single-well depletion production， the scope of exploited reserves expands. However， this expansion may result in inadequate reserve control. The recovery degree within the utilized scope initially exhibits an upward trend and subsequently a downward one. When the gas-well mining attains the maximum recovery factor， the recovery factor within the utilized scope decreases by over 6%. （3） From the perspective of enhancing the recovery degree of reserve utilization， the significance of stimulation measures can be ranked in the following order： shortening the fracture spacing > increasing the fracture half-length > improving the fracture conductivity > enhancing the bottom-hole flowing pressure. Lowering the bottom-hole flowing pressure and abandoned production condition can increase the reserve utilization and cumulative production； however， this will decrease the produced degree. Artificial fracturing is capable of increasing both the geological reserve utilization and the produced degree of a single well， which represents the primary approach to improving the mining efficiency of tight-gas wells.
The formation and evolution mechanism of carbonate reservoir is one of the key issues to be solved in oil and gas exploration. Taking the middle-lower Ordovician in the Yubei area， the Southwest Tarim Basin as an example， we utilized drilling cores， thin sections， FMI logs， conventional logs and geochemical data to obtain the diagenetic evolution process of carbonate reservoirs and reveal the controlling factors of reservoir development， based on the study of fracture-fluid chronology. According to the cutting relationship of core fractures containing different types of fillings， it is determined that the activities of Mg-rich fluid， silica-rich fluid， paleo oil and gas， calcium-rich fluids and mud-rich fluids occurred successively in the Middle-Lower Ordovician in Yubei area. Through the comparative analysis of core and thin-section dolomite-filling fractures， it is proposed that the Mg-rich fluid activity has occurred in the stage of microscopic-fracture development in the early Episode I of the middle Caledonian， which has led to excessive dolomitization. The analysis of elements and isotopes shows that the Mg-rich fluid leading to the excessive dolomitization is of hydrothermal origin， which may be related to the upward permeation and diffusion of high temperature magnesium-rich brine from the Cambrian gypsum strata due to gravity compaction. The occurrence characteristics of the dissolution cavities in the Penglaiba Formation-Yingshan Formation （lower member） in the Yubei area indicate that its formation is earlier than that of dolomitization. The dissolution resulted from subaerial exposure during sea-level fall in the third and fourth sedimentary cycles of the quasi-syngenetic period. The evolution of the Middle-Lower Ordovician reservoir in the Yubei area could be divided into three stages： the quasi-syngenetic dissolution of Penglaiba Formation-Yingshan Formation （lower member）， the joint interaction of hydrothermal dolomitization and structural fractures in the middle Caledonian Episode I and the late Hercynian， as well as the reservoir maintenance after the late Hercynian.
In order to finely understand the hydrocarbon production and drainage evolution of telalginite-rich source rock in Fengcheng Formation in the Middle and Lower Permian Alkali Lake Phase of the Mahu Sag， and then to guide the study of the hydrocarbon formation characteristics and hydrocarbon enrichment rules of the whole hydrocarbon system of the Fengcheng Formation. In this paper， after selecting the low-mature telalginite-rich source rocks， thermal pyrolysis experiments were conducted with water in closed containers， the evolutionary characteristics of pyrolysis liquid and gaseous hydrocarbon yields were analyzed， and the TOC and pyrolysis （Rock-Eval） analysis of the solid residue of the simulated samples were conducted， so as to the hydrocarbon generation and drainage evolutionary characteristics of telalginite-rich source rocks were clarified. The study concludes that telalginite-rich source rocks of the Fengcheng Formation， formed in the alkali lake background， have the characteristics of early generation and early discharge， and the total hydrocarbon discharge and oil discharge efficiency are relatively high， and their organic carbon recovery coefficient has rapidly peaks at ~1.5 at the peak of the oil generation， followed by a gradual rise to >1.7； the telalginite-rich source rocks mainly generate liquid oil in the oil generation window， and the gaseous hydrocarbon yield is low before the peak of the oil generation， and then gradually increases； the color changes of the products imply that the resin-asphaltene content of the oil generated from the telalginite-rich source rocks， as well as their density-viscosity parameters， firstly increase and then decrease with the degree of thermal evolution， and their high values are near the peak of oil production. This study deepens the understanding of the hydrocarbon formation and evolution of the source rocks of Fengcheng Formation in alkaline lake phase， which is an important guide for the selection of shale oil sweet sections and sweet spots， as well as for the in-situ reforming and production of shale oil in Fengcheng Formation， and even in other saline lake phase formations.
Multiple studies exist on the provenance of the Upper Triassic Xujiahe Formation， but controversies remain regarding the provenance in the northern margin of the Sichuan basin. This research combines sandstone grain point counting， heavy mineral assemblage analysis， and electron microprobe analysis of heavy mineral composition to study the provenance of the Xujiahe Formation in the Guangyuan， Wangcang， Nanjiang and Tuhuang sections of the northern Sichuan Basin. The results show that the sandstone composition， unstable heavy mineral types， and garnet composition are consistent among Guangyuan， Wangcang， and Nanjiang sections， characterized by an abundance of garnet and chromian spinel， with garnet types of almandine and pyrope derived mainly from amphibolite- to granulite-facies metasediments. Samples from the Tuhuang section lack chromian spinel and contain pyroxene （augite and diopside） derived from alkaline-subalkaline volcanic arc basalt or subalkaline mid-ocean ridge basalt magmas. Integrated analysis indicates that the provenance for the Guangyuan， Wangcang and Nanjiang sections includes Triassic turbidites from the Songpan–Ganzi fold belt and West Qinling Orogen， and Paleozoic strata from the Longmenshan thrust belt， while the provenance for the Tuhuang section involves the North China Block and Qinling Orogen. This study suggests two source-to-sink systems existed in the northern Sichuan Basin during the Late Triassic， consistent with previous provenance and sedimentary studies. This work highlights the limitations of detrital zircon U-Pb dating and the necessity of multi-method provenance analysis for discriminating between source-to-sink systems.
The granular beach of the Middle Permian Qixia Formation was developed during the depositional period in southern Sichuan Basin， and there were several sets of high quality source rocks underlying it， which had great potential for oil and gas resources. The process of oil and gas exploration in the Qixia Formation in southern Sichuan Basin is restricted by the complex conditions of oil and gas accumulation， the unclear understanding of reservoir potential and favorable controlling factors. On the basis of redefining the reservoir development characteristics of Qixia Formation in southern Sichuan region through drilling， seismic， logging and test analysis data， the natural gas sources and hydrocarbon supply capacity of main source rocks are identified， the characteristics of oil and gas transport system and oil and gas charging periods are identified， the accumulation potential is further understood in combination with oil and gas accumulation evolution， and the favorable controlling factors for reservoir formation are further discussed. The study shows that： （1） The reservoir distribution of the Qixia Formation is controlled by high-energy sedimentary facies belts， mainly developed at the top of the Qi-2 Member， with the Northern Slope zone， the low steep slope zone and the southern slope zone as the center in a circular distribution， featuring low porosity and low permeability， and the reservoir space is dominated by dissolution vugs. （2） The comparison of gas sources shows that the natural gas in Qixia Formation is dominated by crude oil cracking gas in the high to over-mature stage， which mainly comes from the underlying Silurian Longmaxi Formation source rock， forming favorable reservoir-forming conditions of “ear source hydrocarbon supply， lower generation and upper reservoir” in space. （3） The fault-type， transport bed type and disintegrated transport hydrocarbon system are identified， especially the fault-type transport system developed by the combination of class Ⅱ and class Ⅲ faults is more conducive to hydrocarbon migration and accumulation. （4） The reservoir of Qixia Formation has at least experienced three distinct hydrocarbon charging episodes： the end of Early Triassic， the beginning of Late Triassic， the beginning of Early Cretaceous and the end of Early Cretaceous. The present oil and gas distribution pattern is mainly influenced by the Himalayan orogeny on oil and gas adjustment. （5） The Qixia Formation in southern Sichuan Basin has favorable conditions for hydrocarbon accumulation， and the main controlling factor of reservoir formation is good preservation conditions， in which the parallel fault-clipped anticline has better preservation conditions than the up-dip direction of the reservoir with higher tectonic point and weaker structural transformation.
In the Jinqiu area of Central Sichuan， the tight sandstone gas of the Xujiahe Formation is widely developed， but sandstones are pervasively gas-bearing but exhibit heterogeneous enrichment. The controlling factors of gas accumulation and enrichment need to be clarified. Based on the logging data， the 3D seismic data and the gas testing data， etc.， this paper analyzed the horizontal distribution characteristics of source rock， reservoir， faults and paleotectonic， etc.， on this basis， the typical failed wells， low-yield wells and high-yield wells in the study area were dissected and studied to clarify the controlling factors of gas accumulation and enrichment in the lower submember of Xu3 Member， then the accumulation and enrichment model was summarized. The study shows that in the Jinqiu area， the source rock thickness and TOC values of Xu1+Xu2 members， are higher in the northwest and lower in the southeast. The reservoir thickness and energy storage coefficient are higher in the northwest and lower in the southeast. Faults are identified into favorable faults， unfavorable faults and adjusted faults， among which the favorable faults vertically penetrate the basal boundary of the lower submember of Xu3 Member but did not cut through the top boundary of the upper submember of Xu3 Member， and mainly developed in well area QL2-XC2， QL9-JH5 and JH8-PL5. The study shows that source-reservoir connection controls the accumulation of tight gas， and gas enrichment is mainly controlled by high-quality source rock， high-quality reservoir and favorable source-reservoir connection. Four types of combinations of gas accumulation factors， namely the high-quality source rock but low-quality reservoir low-yield model， the gas escapes along the fault low-yield model， the source rock-reservoir-fault triple-configuration high-yield type and the high-quality source rock with high-quality reservoir adjoined model， have been established. Therefore， the accumulation and enrichment model of “accumulation controlled by source-reservoir connection， enrichment controlled by high-quality source rock， high-quality reservoir and favorable source-reservoir connection” is summarized and established.
The high-quality volcaniclastic reservoirs in the Chengdu-Jianyang area at the northern edge of the Emeishan large igneous province are the deepest known volcaniclastic reservoirs in the world. A detailed characterization of the diagenetic sequence helps to systematically reveal the key mechanisms and prerequisites for the formation of this volcaniclastic reservoir， providing support for understanding its scale and spatial distributions. This paper takes the Well TF8 as a key study target， which has the most complete core samples and is representative of the volcaniclastic reservoir in the Chengdu-Jianyang area. By applying core observation， thin section identification， scanning electron microscopy， and electron probe microanalysis methods， this study establishes the diagenetic evolution sequence of the altered volcaniclastic reservoir in the Chengdu-Jianyang area for the first time. The results show that： （1）The main advantageous reservoir segments of the Well TF8 primarily develop in the upper autoclastic lava section of the volcanic sequence， with the main pore spaces being the dissolution pores and the chlorite-intercrystalline pores of generated from the reduction of pore space of volcanic glass after being replaced by chlorite. （2）The diagenetic evolution sequence of the volcaniclastic rocks in the research area includes devitrification， albite crystallization， asphalt cementation， calcite crystallization， clast dissolution， and chloritization. （3）This study utilized chlorite and albite thermometers for the first time to constrain the temperature variation range of the aforementioned diagenetic sequence，constraining the key processes of pore formation in the volcaniclastic reservoir of the Chengdu-Jianyang area to a temperature range from 300-400 ℃ to 237-290 ℃.By combining the constrained temperature range with regional burial thermal history of the Chengdu-Jianyang area， it was determined that such a thermal field could only exist synchronous to the magmatic activities of the Emeishan Large Igneous Province. Using the pyroxene thermometer to calculate the temperature of the magma chamber， constrained between 1 014 ℃ and 1 100 ℃， it is inferred that volcaniclastic rocks accumulation in the Chengdu-Jianyang area developed under the adjacent thermal field of the Emeishan large igneous province. Consequently， it was clarified that the volcaniclastic rocks in the Chengdu-Jianyang area of the Sichuan Basin result from the synergistic effects of： （i） primary eruptive mechanisms， （ii） syn-eruptive thermal diagenesis， and （iii） peripheral fluid systems. The volcaniclastic deposits deposited surrounding the volcanic edifice and being affected by the thermal field would be the target area for further exploration.
The Xujiahe natural gas in Northeast Sichuan Basin is one of the hot spots of oil-gas exploration. Based on the difference of geochemical characteristics of natural gas in different structural areas of Northeast Sichuan Basin， the paper defines the genetic type of natural gas and the difference of mixed source proportion. The Xujiahe natural gas in northeast Sichuan is highly over mature thermal gas. And the Xujiahe natural gas in Shaxi syncline weakly deformed structural area is mainly coal-type gas， almost not affected by marine strata. In the strongly deformed structural zones such as the Maluobei anticline， natural gas from the Xujiahe Formation exhibits light ethane carbon isotopic compositions（δ¹³C₂ = -36.2‰ to -28.2‰）， indicating a dual-sourced mixing between thermogenic coal-type and oil-type gases. The hydrocarbons originate from a dual-source supply of both marine and terrestrial facies， with multi-stage mixing of gases from the same source， including condensate oil/gas and dry gas derived from the marine Wujiaping Formation/Dalong Formation. The calculation results of mixed source ratio show that the proportion of coal type gas in the T3 x 2 of Malubei anticline and in the T3 x 4 of Hebachang anticline is 40%-50%. The proportion of marine condensates gas is about 2%-12%， and the proportion of dry gas is about 40%-50%. The proportion of coal type gas in T3 x 4 natural gas of Nanjiang slope and Xinglong fault fold belt is approximately 70%-80%， the proportion of marine condensates gas mixing is approximately 2%-5%， and the proportion of dry gas mixing is approximately 15%-25%.The calculation of the mixed source ratio provides a scientific basis for the evaluation of the favorable areas for multiple hydrocarbon supply.
The natural gas exploration of the Changxing Formation in the Pengxi-Wusheng shallow-water shelf， central Sichuan Basin is in low degree. The poor understanding of the natural gas source hinders its exploration and development. The total organic carbon（TOC）， kerogen carbon isotope and vitrinite（bitumen） reflectance were used to evaluate the potential Paleozoic source rocks in the Pengxi-Wusheng shallow-water shelf， and then the natural gas component and carbon isotope values and the biomarkers of source rocks and reservoir solid bitumen were applied to determine the sources of natural gas and solid bitumen in the Changxing Formation. The organic matter of source rocks in the Lower Cambrian Qiongzhusi Formation， the Lower Silurian Longmaxi Formation， and the Upper Permian Longtan Formation has a high content and is in overmature stage. These three sets of source rocks exhibit distinct distributions of regular sterane， pregnane and progesterane，tricyclic terpanes， gammacerane，and triaromatic steroid.The natural gas in the Changxing Formation of the Pengxi-Wusheng shallow-water shelf shows a spatially heterogeneous sourcing pattern， predominantly from the Qiongzhusi source rocks in the west and southwest and the Longmaxi source rocks in the east and northeast. The Changxing Formation natural gas in the central and southern study area is mainly sourced from the Longtan source rocks， with important contributions from the Qiongzhusi and Longmaxi source rocks. This study has clarified the hydrocarbon-generating characteristics of the Paleozoic source rocks and the sources of the Changxing Formation natural gas around the Pengxi-Wusheng shallow-water shelf， which can provide critical constraints for the future natural gas exploration.
In recent years， significant exploration breakthroughs have been made in the Yuanba area of northeastern Sichuan for shale oil and gas， yet no exploration progress has been achieved in the continental strata of the eastern margin of the Sichuan Basin. Through geochemical research on mudstone from the Lower Jurassic Ziliujing Formation in the Xianfeng area of western Hubei Province， the paleoenvironment and paleoclimate characteristics of the provenance area of the Early Jurassic basin in the study area were restored. Research indicates that the mudstone samples from the Ziliujing Formation in the study area exhibit a chemical alteration index （CIA） ranging from 75.84 to 81.29， a chemical composition variation index （ICV） between 0.68 and 0.87， a chemical weathering index （CIW） of 89.29 to 96.85， a plagioclase alteration index （PIA） of 89.15 to 96.06， and a chemical weathering index （CIX） of 78.97 to 82.93. Combined with a low Sr/Cu ratio， it is believed that the samples were deposited under a hot and humid climate； The high Al2O3/TiO2 ratios and low Cr/Zr ratios suggest that the provenance is mainly felsic upper crust； The oxidation-reduction index V/Cr value is 1.03-1.71， V/（V+Ni） value is 0.70-0.80， and Ni/Co value is 2.35-5.82. The lower V/Cr value， Ni/Co value and higher V/（V+Ni） value indicate that the study area was in an oxidation-weak reduction transition environment in the early Jurassic. The sample has low Sr abundance and Sr/Ba value， indicating that the water salinity is low at the time of deposition， which is a freshwater environment. Combined with the field work and other test results， it is considered that the Ziliujing Formation exhibits promising hydrocarbon potential， and the resource potential evaluation can be carried out in this section.
The gas-water distribution relationship of Cretaceous Bashijiqike Formation in Kelasu tectonic belt，Tarim Basin is complicated， the source and genesis of formation water is still unclear. Based on major and trace elements， hydrogen and oxygen isotopes， strontium isotope， combined carbonated cement carbon and oxygen isotopes， homogenization temperature and salinity of inclusions， the source and origin of formation water are deeply studied， The result show that the Bashijiqike Formation is a highly mineralized CaCl2 formation water， and the hydrochemical parameters indicate that the formation water has experienced strong metamorphism， and the formation is well sealed， which is conducive to oil and gas preservation. The original sedimentary water of the Cretaceous Bashijiqike Formation was affected by infiltration and mixing of atmospheric precipitation， evaporation and concentration， water-rock reaction， and salt-layer water. The present formation water is characterized by Na+ and Ca2+ enrichment， Mg2+ depletion， δ18O enrichment， elevated 87Sr/86Sr ratios and low 1/Sr values. Three stages of carbonate cement are mainly developed in Bashijiqike Formation， and the iron-bearing calcite/dolomite filled in late pores and fractures is formed via organic acid decarboxylation during mesodiagenesis， the formation temperature of the iron-bearing carbonate cement is consistent with the salinity desalination of fluid inclusions caused by late hydrocarbon charging. According to the analysis of burial history， oil-gas charging history and structural evolution history， the evolution of Cretaceous formation water goes through four main stages： （1）The original sedimentary water of Bashijiqike Formation in the early sedimentary period； （2）Atmospheric precipitation intrusion and mixing at the end of Cretaceous deposition； （3）Marine incursion and saline lacustrine infiltration； （4）Source rock desalinated water intrusion. The water-rock reaction during burial always affects the chemical properties of formation water.
Characterizing the occurrence characteristics of shale oil fluids presents considerable challenges. In this study， freshly frozen and wax-sealed shale samples from the Chang 73 sub-member of the Yanchang Formation in the Longdong area of the Ordos Basin were selected. Utilizing experimental techniques such as atomic force microscopy and two-dimensional nuclear magnetic resonance， an investigation into pore structure and fluid occurrence characteristics was conducted. The results indicate that： （1） The felsic pores （quartz-feldspar dominated） in the shale reservoir are highly developed with good connectivity and somewhat undulating surface topography. Interparticle pores， found at the contact points between organic matter particles and different mineral particles， are larger in size and more undulating in morphology. （2） There are significant differences in the absolute contents of the four fluid types-irreducible water， adsorbed oil， free oil， and solid organic matter-across different rock samples. The relative content of irreducible water is similar， with an average relative content of 52.20%， while the content of free oil is relatively low， averaging 8.03%. （3） Free oil is primarily distributed in pores with larger spaces and better connectivity， such as those in pyrite， fillings， and feldspathic pores. As the duration of frozen wax sealing increases， the relative content of free oil in the pore spaces of the core shows an overall decreasing trend. Frozen wax sealing effectively preserves the three shale oil fluid components-irreducible water， adsorbed oil， and solid organic matter-in the rock samples， and also has a good delaying effect on the volatilization of the easily volatile free oil component. The research results provide an experimental basis for core sampling at well sites and the analysis of fluid occurrence conditions in this area.
There are several sets of organic-rich shales in the Triassic of Ordos Basin， which have broad prospects for oil and gas exploration. It is of great significance to define the reservoir characteristics and main controlling factors of different shale lithofacies to study the law of shale oil enrichment and to find favorable areas. In this paper， by means of thin section observation， scanning electron microscopy， X-ray diffraction， rock pyrolysis analysis， high pressure mercury injection and nitrogen adsorption， the shale of the seventh member of Yanchang Formation （Chang 7 Member） was divided into lithofacies， and the difference of reservoir space among different lithofacies was compared to determine the dominant lithofacies and the controlling factors of pore structure. The shale of Chang 7 Member in the study area is characterized by complex lithology， developed laminae and high organic carbon content. As a whole， the shale belongs to low porosity and low permeability reservoir， and the physical properties of the reservoir are obviously different in different sedimentary environments. Therefore， based on the classification criteria of “lithology+TOC（<3%，3%-6%，>6%）+mineral composition （50% as the limit）”. The shale can be divided into seven rock facies： low organic siliceous shale （L-S）， high organic siliceous shale （H-S）， organic-rich siliceous shale （R-S）， high organic clay shale （H-C）， high organic mixed shale （H-M）， and organic-rich mixed shale（R-M）. H-S lithofacies are dominated by intergranular pores， dissolution pores and fractures， with optimal pore parameters， developed reservoir space and high oil saturation， which are the dominant lithofacies in the study area. Mineral composition， TOC and striation characteristics are the controlling factors of reservoir space， TOC plays an important role in controlling the development of shale micropores during the whole thermal evolution stage. The silty laminated reservoir has good physical properties， and the intergranular pores are well preserved by the mutual support between rigid clastic particles such as feldspar and quartz， which increases the number of large pores and is conducive to the enrichment of shale oil. The research results can provide some reference for the exploration and development of shale oil.
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