China has significant potential for the exploration of lacustrine shale oil， which serves as an important alternative resource for conventional oil and gas. However， the development and recovery of lacustrine shale oil face significant constraints due to the lack of fundamental research， unclear mechanisms of its formation and accumulation， and the absence of standardized criteria for evaluating “sweet spots”. To address these issues， the authors proposed a set of simplified standards for lacustrine shale oil classification， taking into account previous research and the practical conditions of exploration and development. Based on the storage space and type of reservoir rocks， shale oil reservoirs are commonly classified into three major types， namely interbedded sand-shale， fractured shale， and pure shale， with the last type being taken as the focus of discussion in this paper. The pure shale type can be classified into laminated， bedded and massive shale oil reservoirs based on the sedimentary structure. Although the grain size was not taken as one of the parameters for shale oil classification， we kept the traditional three terminal element category and mixed category of minerals， and removed further subdivided subcategories； the Rock-Eval S₁ was used instead of TOC and R_o to divide shale oil reservoirs into three types： low oil content， medium oil content and high oil content； the formation pressure coefficient less than 0.8 is defined as abnormally low pressure， 0.8 ~ 1.2 is classified as normal pressure， and greater than 1.2 is classified as abnormally high pressure； the crude oil viscosity is not involved in the classification of shale oil reservoir types. In addition， this study designated type Ⅰ， Ⅱ and Ⅲ sweet spots， and discussed the representative types of shale oil reservoirs in typical continental basins in China. This paper enhances our understanding of the assessment standards， the type of rocks and the distribution of “sweet spots” in shale oil reservoirs. As a result， this research contributes to the advancement of shale oil exploration and development， providing valuable insights for future endeavors in this field.

The Gulong shale oil represents China’s first attempt at large-scale exploration and exploitation of the oil contained in shale sequences without intercalations. Clarifying the rock mechanical characteristics and fracture propagation mechanisms of the Gulong shale is vital for guiding the selection of landing zones and fracturing design and engineering parameter optimization. In this study， the mineral distribution， thin section observation and rock mechanics tests are performed to clarify the Gulong shale as “fine layered” texture in mechanics and reveal the fracture propagation mechanisms under the control of multiple geological and engineering factors. It is shown that the Gulong shale is characterized by high clay mineral content （Avg. 46.6 %）， strong plasticity， a foliation intensity of up to 1 000～3 000 stripes per meter and strong mechanical anisotropy. Unlike the brittle fracturing of conventional shale， the typical rock samples from Gulong exhibit high-frequency fluctuation in mechanical property， with a fluctuation frequency of 3.33 times per cm for a compressive strength greater than 20 MPa. The fracturing process is observed as a steady gradual process with a slow post-peak stress decline， and along a random path in a zigzagged shape. Meanwhile， in the case of high-density foliation fractures， the hydraulic fractures in the Gulong shale are of complex morphology， with their height and length being significantly constrained. The limited vertical and horizontal extension of hydraulic fractures has been a major constraint for the effective stimulation of the Gulong shale oil reservoir. It is thereby suggested that the hydraulic stimulation of the Gulong shale oil reservoir should follow the principle of controlling near-wellbore fracture branching and further extending distal fracture networks， while placing the fracturing treatment under more effective control to suppress the development of near-wellbore fractures and boost the extension of main fractures to sufficiently expand the stimulated reservoir volume.

The abundance of organic matter and the types of shale laminae are the key in shale oil exploration. The sedimentary facies of terrestrial shales features complex variation and strong heterogeneity， making accurate identification of deposition rate facing more challenges. The deposition rates of organic-rich shales in typical terrestrial basins of China are mostly above 5 cm/kyr， and those of the organic-rich shales in saline lacustrine basins may reach up to 40 cm/kyr. The high-precision chronostratigraphic framework combined with the statistical tuning of cyclostratigraphy can trace the variation of deposition rate with burial depth. The relative deposition rate of shales can be determined by the rare earth element （REE） assemblage pattern， crystal size distribution， and the abundance of typical interstellar dust elements， etc. Comparison of deposition rates of different types or ages of stratigraphic sequences has to take perturbations such as stratigraphic integrity and differential compaction into consideration. Deposition rate is an important factor influencing the enrichment of organic matter in shale， and the critical threshold for organic matter dilution by deposition rate is usually less than 5 cm/kyr. The flocculation of sediment particles is usually under the effect of hydrodynamic conditions and water salinity， and the various deposition rates for different types of fine-grained sediment are conducive to the formation of shale laminae. The study of deposition rate requires an integration of advanced theories and methods， including geochronology， petrology， cyclostratigraphy， geochemistry， and physical simulation of sedimentation， to gain a deeper understanding of the mechanisms of shale deposition and evolution. Revealing the interrelationship between terrestrial shale deposition rate and shale oil accumulation is of certain guiding significance to shale oil exploration.

The lacustrine sediment of the Cretaceous Qingshankou Formation in the Songliao Basin is rich in organic shale， and the well Guye 1 has achieved a breakthrough in oil exploration of Gulong shale of deep lake facies. To further evaluate the geological characteristics of the shale sequence in different facies zones of the lacustrine basin and evaluate the characteristics of shale oil sweet spots in the continental lacustrine basin， we study the geological heterogeneity of shale sequences in different facies zones of the lacustrine basin regarding the environmental difference for lacustrine shale formation in the Qingshankou Formation. It is suggested that the shale sequences deposited in the freshwater lacustrine basin can be divided into seven types according to lithofacies， namely the organic-rich lamellar clayey shale （TOC>3 %）， lamellar clayey shale， felsic shale， lamellar shell shale， massive mudstone， limestone and dolomite respectively， which are evaluated in terms of total hydrocarbon generated and retained， hydrocarbon mobility， reservoir property， compressibility and oil production capacity. The geological and engineering sweet spots of shale oil are thereby proposed. Based on the contents of TOC and S₁ （pyrolysis hydrocarbon content）， we group the geological sweet spots of the Qingshankou Formation shale into TypeⅠ，Ⅱ， and Ⅲ. The TypeⅠ sweet spot is generally characterized by TOC content greater than 3 % and S₁ greater than 4 mg/g； the Type Ⅱ by TOC content ranging between 1.5 % and 3 %， and S₁ between 1.0 and 4 mg/g； the Type Ⅲ by TOC content less than 1.5 % and S₁ less than 1.0 mg/g. The semi-deep lacustrine and deep lacustrine facies are dominated by sweet spots of TypeⅠ and Ⅱ， while the shales of shallow lacustrine facies by sweet spots of Type Ⅱ and Ⅲ. The Qingshankou Formation shale in Songliao Basin is selected as the major oil pay zone after a comprehensive analysis of the oil-bearing property， percolation coefficient， compressibility， characteristics of source rocks and physical properties of different facies zones.

Identification of target intervals and delineation of favorable areas for exploration and development of the Gulong shale oil require better reconstruction of the paleowater environment during deposition of the shale of interest. Paleontological communities were used as indicators to trace the paleowater environment of ancient lakes to perform a comprehensive analysis of paleotological evidence （including fish， clam shrimp， ostracoda and algae） of the Qingshankou Formation from the Well GY8HC. The results show that Manchurichthys and clam shrimp only occur in the Q7 oil layer with large abundance but single species. Compared with the lower Q1—Q6 oil layers， there is a significant increase in the species and abundance of ostracods in the upper Q7—Q9 oil layers. Three abundance peaks of dinoflagellate fossils appear in Q1， Q2 and Q7 oil layers. The biological assemblage indicates a whole freshwater-brackish water feature of the Songliao Basin during the deposition of the Qingshankou Formation. The significant increase in diversity of fossil record and peak abundances of dinoflagellate fossils in Q7 oil layer indicates relatively definite marine transgression events， while the abundance peaks of dinoflagellate fossils in Q1 and Q2 oil layers suggest possible marine transgression event（s） in the early stage of lake-level rising. Through the comparison with the modern Maracaibo Lake， it is proposed that the appearance of marine organisms in the paleo-Songliao Lake during the deposition of the Qingshankou Formation might be the result of temporary or occasional lake-sea connection under unique paleogeographic and climatic backgrounds. However， the lake-sea connection did not cause any obvious change in the nature of water body and the components of ecosystem.

The Qingshankou Formation shale， Gulong Sag， Songliao Basin， has been gushing out oil in a rate stunning the Chinese oil industry. However， further prediction of sweet spots in the formation remains a challenge due to the highly uneven distribution of organic matter and confusion in the understanding of controlling factors. This study adopted the concepts of “hierarchy in sequence stratigraphy” and “transgressive-regressive （T-R） sequences”， with updated astronomical cycle research results to determine the accurate duration of sequences and re-establish an isochronous sequence stratigraphic framework specifically for lacustrine deep-water shale based on core， outcrop， and thin section observation， as well as seismic profile， well-logging， geochemical， and paleontological data analyses from a microcosmic to macroscopic scale. Subsequently， using modern lakes sedimentation as an analogy made it possible to propose qualitative and quantitative indexes for identifying paleo-water environment， and probe into the origin of the heterogeneity of organic matter enrichment under the sequence stratigraphic framework on the basis of the coupling relation among paleoproductivity， redox conditions， and sedimentation rate. The main conclusions are as follows： 1） There are four third-order sequences in Qingshankou Formation Shale， Gulong Sag， Songliao Basin. Among them， SQ1 and SQ2 consist of two T-R sequences of 13 parasequence sets （made up of 52 parasequences）. The durations of parasequence and parasequence set are approximately 40 kyr and 170 kyr， respectively. 2） Three types of lithofacies， four types of laminae， five laminae combinations， eleven laminae combination patterns， and three sedimentary microfacies have been recognized under the sequence stratigraphic framework. T-R cycles control the vertical distribution of laminae combination， lithofacies and sedimentary microfacies. The argillaceous shales deposited in deep-lake stagnant water and mud flow are prospective lithofacies. 3） T-R cycles control the enrichment of organic matter and different orders of flooding surfaces are the favorable locations for organic matter enrichment. Parasequence set 2 in Gulong Sag and parasequence sets 1 to 4 in Sanzhao Sag have been evaluated to be the most promising exploration targets. This study aims to provide sedimentological evidence for shale oil target area and “sweet spots” prediction.

Large-scale organic-rich shales are usually formed in saline basins rather than freshwater basins. However， the Ordos Basin， as a typical freshwater lacustrine basin， has a maximum total organic carbon content （TOC） of 30 % in its Triassic Chang 7 Member shale， way above the average TOC content of shales in saline basins， leaving the main controlling factors a hot topic for discussion. The multiple tuff layers occurred frequently in high TOC sections of the member indicate intense volcanic events and a subtle connection between the events and the high TOC value. Analysis of main and trace elements of the shale confirms the impact of volcanic events as indicated by the relatively higher content of elements enriched in clay minerals like Al and K， of elements as proxy of paleo-productivity and reducing environment including Ni， Cr and V， as well as of high field strength elements （Zr， Th， and Hf）. The upper parts of these tuff are even richer in organic matter with increasing hydrocarbon generation intensity that indicates the elevated paleoproductivity. There are trends of Fe_HR/Fe_T ≥ 0.38 and Fe_py/Fe_HR ≤ 0.8 in organic-rich shale but with Fe_py/Fe_HR up to 0.8 with the increase of TOC. The （EF_Mo/EF_U） （auth） ratios is 1-3 when the TOC is greater than 6 %. Both the iron speciation and （EF_Mo/EF_U） （auth） ratios indicate that there was an euxinic environment for Mo and Fepy enrichment， but the sulfate reduction strength was low （SRI ≤ 1.375）. In summary， the input of volcanic materials and inorganic elements into the freshwater increased paleoproductivity and promoted the formation of a reducing environment. This is favorable for the organic-rich matter accumulation and preservation. The upper shales of the tuff-bearing section are suggested to be one of the key targets for future exploration and development in the basin.

The hydrothermal activity of the Upper Triassic Chang 7 shale in the Ordos Basin has been extensively studied in previous studies， with a focus on hydrothermal sedimentation during the depositional period of Chang 7 Member. However， there is limited research on the impact of hydrothermal activities during the corresponding burial stage. This study aims to investigate the stages and ages of hydrothermal activities and their impact on shale oil reservoirs during the burial stage of the Chang 7 shale. An integration of multiple techniques， including optical/electronic microscopy， electronic probe， micro-laser Raman spectrum and inclusion homogenization temperature analysis is applied to study the hydrothermal pyrite and solid phases and fluid inclusions in the Chang 7 Member. The results reveal that there contains many types of pyrite with Co/Ni greater than 1 exhibiting a variety of morphologies， including veins， lumps， lenticular shape as well as xenomorphic-hypidiomorphic scattered and hypidiomorphic-euhedral massive forms， indicating hydrothermal origin. Based on the analyses of microscopic observation， regional tectonic history， as well as the simulation of burial-thermal evolution history， it is inferred that there were at least two phases of hydrothermal activities during the burial period of the Chang 7 Member， with one of them occurring in the Early Cretaceous. The maximum temperature of the hydrothermal fluid injected into the Chang 7 shale in well Yy1 may reach up to 270.5 ℃ based on the homogenization temperatures of aqueous inclusions associated with pyrite inclusions. The calculation based on the Easy%R_o kinetic model indicates that the Chang 7 shale underwent a rapid cooling process after hydrothermal injection， which may be one of the important reasons for the lower-degree thermal evolution of shale organic matter （R_o = 0.70 %）.

The lacustrine shale samples were selected from the second member of the Funing Formation in Gaoyou Sag， Subei Basin， to precisely and quantitatively evaluate the free oil content and its controlling factors of lacustrine shale. The mineral composition， hydrocarbon generation capacity， pore structure， oil-bearing properties， and other characteristics of the samples were analyzed using X-ray diffraction tests， TOC content measurement， multistep rock-eval pyrolysis， high pressure mercury injection， organic matter extraction and 2D NMR. The results show that the shale is rich in quartz， feldspar， calcite， dolomite， clay， and other minerals. The TOC is between 0.61 % and 3.70 %. The R_o is between 0.70 % and 0.72 %， indicating the source rocks being in the mature stage. The reservoir space is mainly composed of intergranular and organic pores. Two-dimensional NMR， which can efficiently detect and characterize the occurrence of free oil， was employed to help extracting free light and heavy hydrocarbons as well as soluble organic matter from the samples， and performing spectra analysis before and after the extraction， on which light oil zone， solid organic matter zone， hydroxyl compound zone， and water zone were identified. Post-extraction solid organic matter content was found to have a good correlation with TOC. Pre-extraction NMR-based light hydrocarbon content and NMR-based differential light hydrocarbon content between pre-extraction and post-extraction show a relatively strong linear connection with pyrolysis free oil content. The free oil content rises initially and then fall as the felsic mineral content rises， and it is positively correlated with TOC as a whole. The free oil contents in type Ⅰ and Ⅱ₁ kerogen source rocks are higher than those of other kinds. The right degree of thermal evolution of source rocks increases the ratio of light hydrocarbons and mobility of kerogen-generated hydrocarbons， as well as free oil content. Shale reservoirs with high porosity， specific pore volume， and median value of pore throat radius are conducive to free oil enrichment.

Weixinan Sag， an important area for the exploration and development of both conventional and unconventional hydrocarbon in the Beibu Gulf Basin， South China Sea， has witnessed the success of well WY-1 which tested commercial oil and gas flow after fracturing in July， 2022， marking a major breakthrough in offshore shale oil development in China. An integration of the analysis of core， thin section， mineral composition， organic geochemistry， scanning electron microscope （SEM）， matrix porosity and permeability and fine logging， is applied to study the heterogeneous signatures of shale oil reservoirs in well WY-1， Weixinan Sag. The results are shown as follows. Four types of lithofacies can be identified in the lower submember of the second member of Liushagang Formation （E₂l^2（1）） in well WY-1， including highly siliceous clayey mudstone， mixed mudstone， clay-rich siliceous siltstone and （mixed） siliceous sandstone. Lithofacies is key to the reservoir heterogeneity. An analysis of the physical properties， pore throat characteristics， mobility and brittleness of the four types of lithofacies， indicates that the reservoir space is dominated by intergranular pores， and the （mixed） siliceous sandstone facies is of the highest porosity and permeability， the best compressibility and the highest mobility， a favorable lithofacies， followed by clay-rich siliceous siltstone， and the mixed mudstone and highly siliceous clayey mudstone coming at last though the compressibility and mobility of mixed mudstone are relatively better than the highly siliceous clayey mudstone. It is found that the favorable lithofacies for reservoir development can be sorted as （mixed） siliceous sandstone the first， followed by clay-rich siliceous siltstone， mixed mudstone and highly siliceous clayey mudstone in order. In terms of the vertical distribution of reservoir properties， the bottom interval of the E₂l^2（1） dominated by （mixed） siliceous sandstone interbedded with clay-rich siliceous siltstone， is the best in reservoir property， mobility and compressibility； the brittleness and compressibility of the interbedded mixed mudstone and highly siliceous clayey mudstone in the middle interval of the E₂l^2（1） are better than the upper interval. In all， it can be concluded that the sweet-spot section in well WY-1 is mainly composed of （mixed） siliceous sandstone interbedded with clay-rich siliceous siltstone in the lower interval of the E₂l^2（1）， followed by the middle interval where mixed mudstone is well developed.

Wells encountering the Miocene marine source rocks in the Yinggehai Basin are mostly confined to the edge and slope areas， leaving the overall forming environment and distribution of these high-quality source rocks in the basin a puzzle to be cracked. This paper， from the perspective of biogeochemistry and environmental geochemistry， reveals the main controlling factors of the formation and distribution of the source rocks through a systematical analysis of paleo-productivity， terrestrial organic matter input and redox conditions of the rocks in the basin. The P/Ti values of the source rocks indicate relatively low paleo-productivity， with only that of the Ledong area showing an increasing trend. The supply of terrestrial organic matter is relatively sufficient because of several rivers around the basin. Oleanane derived from angiosperms is widely occurring in the source rocks， especially those in the Sanya Formation. The Ni/Co ratios of the rocks from the Yingbei， Yingdong Slope， Dongfang and Ledong areas indicate an oxic environment with the redox conditions in the Ledong area better than the rest. The relationship between TOC values and P/Ti and Ni/Co ratios shows that the paleo-productivity and redox conditions only control the formation of the source rocks from L30-1 wellblock in the Ledong area. TOC values of the source rocks have a positive correlation with the oleanane index （oleanane/C₃₀ hopane）， showing that terrestrial organic matter input has a significant control effect on the development of marine source rocks. The H29-1 wellblock of the Yingbei area， provided with sufficient supply of terrestrial organic matter from both Hainan Island and the Red River， serves as a perfect location for enrichment of high orgnic marine source rocks. While the D29-2 and L30-1 wellblocks with fine paleo-productivity and redox conditions are relatively good for the formation of endogenous high-quality source rocks.

Fine-grained sedimentary rocks， in which low-resistivity oil and gas reservoirs are well developed， have become a significant target in unconventional hydrocarbon exploration. The study serves to reveal the genetic mechanism of typical low-resistivity oil reservoirs of fine-grained sedimentary rocks in applying the data from logging， seismic and thin-section electron microscopy （EM）， as well as well facies-controlled reservoir parameter distribution， while proposing three sweet-spot distribution patterns under low resistivity. The research results are shown as follows. First， the origin of low-resistivity reservoirs mainly includes the large specific surface area， high content of mixed layer illites/smectites， well-developed micropore network and high bound water content， high-salinity water and high content of conductive minerals. Second， we propose three typical types of fine-grained sedimentary rocks with low resistivity， including tight low-resistivity oil reservoir with high mud content （i.e.， tight reservoir of low resistivity）， low-resistivity oil reservoir with high content of conductive minerals （i.e.， conducive mineral-dominant reservoir of low resistivity） and water network low-resistivity oil reservoir with well-connected loose sandstones （i.e.， well-connected water network conductive reservoir of low resistivity）. Meanwhile， their genetic mechanisms are analyzed built on this. Third， the sweet-spot distribution patterns in subtle low-resistivity reservoirs are clarified. The tight reservoir of low resistivity has the sweet spots mainly developed in those of relatively higher resistivity； the conductive mineral-dominant type has the sweet spots mainly grown in the dissolved section of the dolomitic siltstone matrix and the section with well-developed dolomitic mud/shale fractures； meanwhile， the well-connected water network conductive reservoir of low resistivity has the sweet spots mainly developed in the ultra-fine-grained rocks with dual-mode pore structure. The results are of great significance to guiding the exploration of fine-grained sedimentary oil/gas reservoirs.

The Kuqa Depression is of complex structural pattern under multi-stage orogeny， basal pre-existing structure and salt structure in the Meso-Cenozoic South Tianshan Mountains. It is of great significance to clarifying the control effect of such complex structural systems on fracture development. Based on the research results of predecessors， combined with the latest seismic data， outcrop survey， imaging data and core data， we systematically summarize and analyze the structural pattern and fracture distribution characteristics of the Bozi-Dabei area. The results show that since the Cenozoic， under the joint control of the orogeny of the Tianshan Mountains and the rotation of the Tarim plate， the structural system has passively slipped after thrusting. Under the control of multiple NEE-trending thrust faults， the structural system in the study area shows significant differences from south to north， showing obvious zonation； and under the control of the strike-slip adjustment structure， the strike-slip and thrust structures occur alternatively from east to west， showing obvious structural segmentation. Passive fault strike-slipping serves as the main factor controlling effective fracture development， resulting in zonation of fracture development under the control of strike-slip fault disturbance stress field. The fault-fracture system formed by the action of fault strike-slipping is key to increasing well productivity. This study discusses the fracture development pattern and well productivity characteristics under the control of passive strike-slip structure in the Bozi-Dabei area， which is of a basis to further research on the fracture development mechanism and of certain referential significance to the exploration and development of similar oil and gas fields.

An integration of core observation， casting thin section identification， scanning electron microscopy （SEM） observation， porosity-permeability test of samples and mercury intrusion porosimetry （MIP）， in combination with the local burial and hydrocarbon charging history， is applied to the study on the diagenesis， differential lithofacies-based diagenesis mechanism and reservoir pore structure of the Sangonghe Formation in Moxizhuang area， Junggar Basin. The results show that the Sangonghe Formation mainly experienced mechanical compaction， cementation and dissolution during the diagenetic evolution. Reservoirs of diverse lithofacies are significantly different in diagenetic mechanism： the calcareous sandstone facies， argillaceous carbonaceous sandstone facies and volcanic tuffaceous matrix sandstone facies tend to get tight in the early diagenetic stage， while featuring weak diagenesis intensity in the middle stage； the pores of the massive sandstone facies are well preserved in the early diagenetic stage with smooth fluid migration in the middle stage， and there are multi-stage cementation and dissolution occurring in between； and the conglomeratic sandstone and conglomerate facies feature high gravel content， resulting in poor fluid migration， and weak compaction in the early diagenetic stage， while characterized by weak cementation and weak dissolution in the middle stage. The different diagenetic mechanisms for the lithofacies serve to determine the pore structure. The calcareous sandstone facies and argillaceous carbonaceous sandstone facies of lamination texture have poor pore connectivity， complex structure and poor overall physical properties， which are not conducive to oil and gas enrichment； the pore throat of the massive sandstone facies is well sorted， and the pores of the facies are the most developed with strong connectivity， resulting in good overall physical properties， conducive to oil and gas enrichment； the particles of conglomeratic sandstone and conglomerate facies are poorly sorted and in close contact， limiting the pore connectivity to some extent， but the destructive diagenesis intensity is weak， and the overall physical properties are good， conducive to forming effective oil and gas reservoirs.

The distribution characteristics， sedimentary setting and reservoir formation conditions of the Gufeng Member of the Middle Permian Maokou Formation in the eastern Sichuan Basin were studied by means of macroscopic and microscopic observation， as well as the measurement of major and minor elements and rare earth elements （REEs）， total organic carbon （TOC） content and vitrine reflectance， while considering the lithologic and electrical properties and outcrop characteristics， combined with regional depositional-tectonic framework. The results are as follows. First， the existence of Gufeng Member of the Maokou Formation in eastern Sichuan Basin confirms that a trough and platform pattern existed in the middle and late depositional stages of the Maokou Formation under the tectonic-sedimentary differentiation. During the deposition of the B sub-member of the second member of the Maokou Formation （i.e.， the deposition of Mao 2B sub-member）， the Gufeng Member mainly occurred in the northeast corner of the eastern Sichuan Basin. During the deposition of Mao 2A sub-member， the Gufeng Member extended southward to Quxian， Dazhu， and Liangping counties in a NW-SE-striking strip pattern with a thickness of 0.8 to 26.6 m. The Gufeng Member corresponds to the Mao 3 and 4 members in northwest and north Sichuan Basin. Second， the siliceous shale in Gufeng Member is rich in siliceous radiolaria and has high organic matter content， which is typical of deep-water trough facies deposition. The geochemical test data show that the siliceous shale is developed in a deep-water anoxic reducing environment with high salinity， with biogenic silica as the main siliceous source. Third， the source rocks in the Gufeng Member are of high quality and rich in organic matter， with the total organic carbon （TOC） content being relatively high as a whole but in a wide variety， ranging from 1.69 % to 38.27 %， with an average value of 11.51 %， and in the mature to over-mature stage. Fourth， the high-quality source rocks of the Gufeng Member can communicate with the reef-shoal reservoir of Kaijiang-Liangping trough through faults， forming an “upper source rock-lower reservoir” assemblage； and it can also form a juxtaposed “source rock- reservoir” association with the favorable beach reservoir of Maokou Formation. The Gufeng Member in eastern Sichuan is expected to be a successor target for high-quality source rock exploration in the region， which is of great significance to future oil/gas exploration and development in the study area.

The 7^th member of the Triassic Yanchang Formation in Ordos Basin is rich in shale oil and has been regarded as one of the key targets for reserve growth and production increase. However， the oil-bearing lacustrine shale with its broad lamination and bedding， high content of clay minerals， and heterogeneity in terms of structure and mechanism， responds poorly to hydraulic fracturing， calling for a better understanding to the evolution characteristics of hydraulic fracture network. In this paper， the effects of in-situ stress difference and fracturing fluid viscosity on hydraulic fracture propagation in lacustrine shale are determined through laboratory fracturing tests and numerical simulation analysis. The results show that the hydraulic fracture propagation is mainly controlled by weak bedding planes with fracture height being limited when the vertical stress difference is 15 MPa and gradually increasing when the vertical stress difference is larger than 20 MPa. Fluid with higher viscosity enhances the vertical propagation of hydraulic fractures across weak bedding planes. The rock mass of lacustrine shale reservoirs is the basis for the generation of complex hydraulic fracture networks of mostly activated natural fractures. The hydraulic fracture network is mainly composed by activated horizontal bedding-parallel fractures and nearly bedding-perpendicular fractures.

Rock-Eval pyrolysis has been widely used in assessing source rocks from the very beginning. Although this approach can evaluate oil content， hydrocarbon generation， as well as the abundance， type， and thermal maturity of organic matter in a simple and rapid way， it is noteworthy that this technique has some limitations in application， and improper interpretation of pyrolytic data may bring more risks to shale oil/gas exploration. This study summarizes three main pitfalls commonly seen in previous publications based on massive experimental results. First， the use of hydrogen index （HI）， oxygen index （OI）， the temperature of maximum pyrolysis yields （T_max）， and the ratio of S₂/S₃ to discriminate kerogen of diverse types should target source rocks with maturity less than 1.35 % R_o； the feasibility of the technique to highly-to-over-mature source rock samples is limited. Second， the validity of T_max depends on the area of S₂ and whether it is in normal distribution， and the accuracy of T_max relies on kerogen type and thermal maturity； moreover， residual hydrocarbon and pyrite content have some effects on the accuracy of T_max. To obtain accurate T_max values， the maturity of source rocks of types Ⅰ， Ⅱ， and Ⅲ should not be larger than 1.70 % R_o. Third， the oil saturation index （OSI） has been used to indicate the mobility of shale oil， and a value larger than 100 mg/g TOC suggests sweet spots of shale oil. However， it should be noted that OSI could not directly provide information on the saturation of oil in shale. OSI values are generally smaller than 100 if the rocks are very organic-rich， and a small TOC value could also lead to a large OSI value （more than 100 mg HC/g TOC）. Besides， only a few shales bear OSI higher than 100 mg HC/g TOC， although many of the shales have been proven commercially successful. Therefore， the applicability of OSI larger than 100 mg HC/g TOC as a parameter for shale oil mobility merits further consideration. We suggest using individual OSI criteria for different types of sedimentary basins and shale formations. Moreover， the loss of light hydrocarbons during the storage and preparation of rock samples is strongly dependent on rock lithofacies， and thus， classified assessment should be adopted for shale oil reservoirs of multiple lithofacies.

Research of the in-situ stress field can provide theoretical guidance and technical support in well design， fracture stimulation of wells and fracture effectiveness evaluation. It is crucial to summarize the in-situ stress field analysis and related loging evaluation methods. The study summarizes the components of in-situ stress field and its well-logging response mechanism， and presents the log suite consisting of sonic transit time， resistivity and image logs as the most sensitive to in-situ stress responses. The time and magnitude of paleotectonic stress field can be determined by acoustic emission experiment. The maximum paleotectonic stress magnitude can be recovered by using resistivity log， sonic transit time log and fracture density. The in-situ stress field can be described in respect of orientation and magnitude. The orientation of in-situ stress field can be determined by using the image logs to pick up borehole breakouts and induced fractures， and the array acoustic logs to derive shear wave splitting. The magnitude of the in-situ stress field can be determined through hydraulic fracturing combined with acoustic emission experiment. The in-situ stress can be calculated through models or methods including the combined spring model built on the in-situ stress field description， realizing in-situ stress field analysis. The analytical results can better help analyze fault properties， evaluate reservoir quality and fracture effectiveness， predict reservoir distribution， as well as be of practical value to the engineering fields like hydraulic fracturing of unconventional hydrocarbon reservoirs.

The complex geological conditions of ultra-deep reservoirs lead to the diversity and variability of fluid phase characteristics， imposing great challenges to oil and gas exploration and development. This study established a method for studying the fluid phase behaviors of ultra-deep oil and gas reservoirs in the Shunbei area of Tarim Basin through the equal-time-interval downhole sampling to obtain formation fluid samples at different production stages. During the process， the causes of asphaltene deposition in gas condensate wells were revealed by experiments of asphaltene deposition during commingled recovery of hydrocarbon fluids charged in two stages， and suggestions for optimal recovery scheme were put forward from the point of view of fluid phase change. The results show that the fault-karst bodies encountered by Well D1 in the Shunbei No.4 fault zone are receivers of deep oil supply， showing a vertical composition gradient with gas upon oil. The hydrocarbon fluid phase changes first from condensate gas to gas of near critical condensate saturation and finally to gas condensate （volatile oil）， with the latter being the result of mixing of hydrocarbon fluids charged in two stages： the crude contained in condensate gas and the light components extracted by gas from deep crude. The fault-karst body penetrated by Well D2 contains only a closed gas reservoir with hydrocarbon fluid phase changing in a way similar to that of a conventional condensate gas reservoir. The asphaltene deposition in Well D1 is suggested to be related to its commingled production with deep crude， which could lead to the significant increase in initiation pressure and volume of asphaltene deposition within the reservoir and the wellbore. A production scheme that extracts oil before gas with reservoir pressure well controlled is therefore recommended for such gas-over-oil fault-karst reservoirs. The results are of great reference value for the exploration and production of ultra-deep oil and gas reservoirs.

Restoration of paleogeomorphology plays a very important role in guiding the search for high-quality reservoirs and dominant source rocks of oil and gas， during which the calculation of denudation thickness is the vital step. In this study， the abundant GR curves together with the main frequency and astronomical time scale of the Carboniferous Kalashayi Formation in the Bamai area， Tarim Basin， were used to establish the “floating” astronomical chronological scale with relative time concept and high-precision stratigraphic sequence frame using spectral analysis， wavelet transform and EMD. The results show that a complete Milankovich cycle presents in the formation as a result of astronomical orbit control during the deposition of the formation； and the astronomical chronological scale and the stratigraphic sequence frame is based on the understanding that the imf₃ component calculated by EMD method is basically consistent with the number of stratigraphic cycles under the control of e₁. Based on the results of EMD method， the relationship between the number of missing cycles and the average cycle thickness revealed by drilling in different regions was used to accurately calculate the denudation thickness of the Carboniferous Kalashayi Formation. The erosion thickness of the Kalashayi Formation of the Carboniferous in the study area varies between 0 and 390 m with the overall denudation characterized by “intensive in the west and mild in the east”. The slope area near the BT5 well in the middle of the study area is suggested to be a potential exploration target for oil and gas. The ideas and methods proposed provide a reference for the construction of high-frequency stratigraphic sequence framework， the establishment of “floating” astronomical chronological scales， and the precise calculation of formation erosion thickness in not only the study area， but also areas with similar geological settings.