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Storage characteristic comparison of pores between lacustrine shales and their interbeds and differential evolutionary patterns Zongquan HU, Ruyue WANG, Jing LU, Dongjun FENG, Yuejiao LIU, Baojian SHEN, Zhongbao LIU, Guanping WANG, Jianhua HE Oil & Gas Geology    2023, 44 (6): 1393-1404.   DOI: 10.11743/ogg20230605 Abstract （196）   HTML （6）    PDF（pc） （4277KB）（783）       Knowledge map    Save Unlike marine shales， lacustrine shale sequence in China exhibits intricate source rock-reservoir configuration and coupling relationships， as well as significantly different storage characteristics between shales and their interbeds. Therefore， it is necessary to ascertain the evolutionary patterns of shales and their interbeds， which will provide critical guidance on the exploration of lacustrine shale oil and gas. Using data on mineral compositions， organic geochemistry， and physical properties， as well as data from the analyses and observations of cores， thin sections， and scanning electron microscopy （SEM） images， we conduct a comprehensive study of the lacustrine shales in the Triassic Yanchang Formation of the Ordos Basin， the Jurassic Ziliujing Formation of the Sichuan Basin， and the Cretaceous Yingcheng Formation of the Songliao Basin， which vary in thermal evolution. By analyzing the storage space types and physical properties of shales and their interbeds in these formations， we explore the formation and evolutionary processes of pores in both shales and their interbeds and establish differential evolutionary patterns of the pores. The results are as follows： （1） The lacustrine shales in China are of diverse lithofacies types， primarily consisting of mixed， clayey， and silty shales， which tend to alternate with carbonate， sandstone， and tuff， suggesting complex lithofacies assemblages. The storage spaces in the shales are dominated by inorganic pores， followed by organic pores， with microfractures developed locally. In contrast， the storage spaces in the interbeds are dominated by inorganic pores such as residual intergranular （dissolved） pores， intragranular （dissolved） pores， and microfractures； （2） The evolution of pores in the lacustrine shales and their interbeds is influenced by both diagenesis and hydrocarbon generation. The shales， with high clay content and weak anti-compaction capacity， undergo a rapid decrease in inorganic pores before hydrocarbon generation. After entering the oil generation window， these shales experience a gradual increase in organic pores， clayey intergranular/intercrystalline pores， dissolved pores， and microfractures. Prior to the late diagenetic stage， the shale porosity tends to decrease before the peak oil generation and increase afterward. In contrast， the interbeds become increasingly tight under compaction and cementation， leading to a gradual decrease in their storage capacity； （3） The Yanchang Formation shale in the oil generation window， contains underdeveloped organic pores and thus exhibits poor storage capacity. In contrast， the sandstone interbeds in the formation present more favorable shale oil enrichment conditions. The Ziliujing Formation in the mature to highly mature stage， exhibits oil and gas coexistence， characterized by well-developed organic and inorganic pores in the shale， more favorable for storage， while the interbeds serve as secondary reservoirs or barriers. The Yingcheng Formation in the highly mature to overmature stage， is the most favorable for the formation of shale gas and organic pores， boasting the optimal storage conditions in shales. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Mechanisms for lacustrine shale oil enrichment in Chinese sedimentary basins Xusheng GUO, Xiaoxiao MA, Maowen LI, Menhui QIAN, Zongquan HU Oil & Gas Geology    2023, 44 (6): 1333-1349.   DOI: 10.11743/ogg20230601 Abstract （302）   HTML （29）    PDF（pc） （4379KB）（545）       Knowledge map    Save By analyzing the tectonic and sedimentary environments for the formation of organic-rich shales in China’s continental lacustrine basins， we identify significant differences in the development of high-quality continental source rocks across various types of lacustrine basins. For shale sequences deposited in fresh-water lacustrine basins， the main lithofacies are felsic and clayey shales， as observed from the 1st member of the Upper Cretaceous Qingshankou Formation （K2qn1 section） in the Songliao Basin and the 7th member of the Triassic Yanchang Formation （T3yc7 section） in the Ordos Basin. For shale sequences developed in a saline lacustrine environment， however， carbonates and evaporites are dominant lithofacies， as represented by the Paleogene Shahejie Formation in the Jiyang Depression. There are three types of lithofacies assemblages for Chinese lacustrine shales， that is， the shale interbedded/intercalated with sand， mixed shale， and clayey shale. These lithofacies assemblages determine the hydrocarbon source-reservoir coupling characteristics， differential evolution of hydrocarbon generation， and property differences of in-situ fluids in the lacustrine organic-rich shales. The shale interbedded/intercalated with sand assemblage is characterized by source-reservoir separation and near-source migration. The mixed shale assemblage shows macroscopic integration and microscopic separation between source rock and reservoir. In contrast， the clayey shale acts as both the source and reservoir of in-situ generated hydrocarbons， featuring pervasive oil distribution. As revealed by evidence， inorganic pores provide the most favorable storage space for lacustrine shale oil in medium-low maturity， and form effective pore-fracture networks for hydrocarbon transport together with multi-type and multi-scale microfractures. Self-sealing capacity of shale is conducive to the in-situ or proximal preservation of shale oil and gas. Comparison of typical continental shale sequences in the Chinese sedimentary basins indicates that favorable source-reservoir coupling， suitable thermal maturity level， and self-sealing capacity of shale are the major controls for oil enrichment in lacustrine shale. This study also presents a preliminary model for differential enrichment of lacustrine shale oil in China. Therefore， the laminated shales in medium-low maturity in gentle slope zones and the clayey shale-rich strata in medium-high maturity in deep sags should be prioritized in lacustrine shale oil exploration in downfaulted lacustrine basins. Moreover， both the shale interbedded/intercalated with sand and the clayey shale in medium-high maturity are crucial to making breakthroughs in lacustrine shale oil exploration therein. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Investigation of deposition rate of terrestrial organic-rich shales in China and its implications for shale oil exploration Rui ZHANG, Zhijun JIN, Rukai ZHU, Mingsong LI, Xiao HUI, Ren WEI, Xiangwu HE, Qian ZHANG Oil & Gas Geology    2023, 44 (4): 829-845.   DOI: 10.11743/ogg20230403 Abstract （180）   HTML （18）    PDF（pc） （2974KB）（512）       Knowledge map    Save 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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Classification of lacustrine shale oil reservoirs in China and its significance Zhijun JIN, Qian ZHANG, Rukai ZHU, Lin DONG, Jinhua FU, Huimin LIU, Lu YUN, Guoyong LIU, Maowen LI, Xianzheng ZHAO, Xiaojun WANG, Suyun HU, Yong TANG, Zhenrui BAI, Dongsheng SUN, Xiaoguang LI Oil & Gas Geology    2023, 44 (4): 801-819.   DOI: 10.11743/ogg20230401 Abstract （358）   HTML （44）    PDF（pc） （3874KB）（509）       Knowledge map    Save 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 Ro 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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Predictive stratigraphy： From sequence stratigraphy to source-to-sink system Changgui XU, Chenglin GONG Oil & Gas Geology    2023, 44 (3): 521-538.   DOI: 10.11743/ogg20230301 Abstract （340）   HTML （44）    PDF（pc） （9454KB）（384）       Knowledge map    Save Predictive stratigraphy with the ability to predict sedimentary fills and high-quality reservoirs has been widely applied to basin analysis and hydrocarbon exploration， and has undergone the evolutionary process from sequence stratigraphy to source-to-sink system for reservoir quality prediction. In response to the challenge of predicting favorable play elements （i.e. reservoir and seal）， geologists of ExxonMobil established the sequence stratigraphic methodology and theory. To answer why the sequences do not necessarily control sandstone development and lowstand systems tract does not necessarily result in fan deposits， the geologists adopted the source-to-sink hypothesis in predicting high-quality reservoirs， creating the source-to-sink-based sandstone mapping methodology. The present study reviews the status quo of sequence stratigraphy and major advances in application to marine and lacustrine sequences， and introduces major progress in the application of source-to-sink-based methodology to predict high-quality reservoirs in both continental-marine and continental-lacustrine systems. A source-channel-sink-diagenesis coupling technique to predict high-quality reservoirs is proposed in the study to solve the difficulty encountered in exploring why the source-to-sink system serves to control sandstone development， but not necessarily determine reservoir formation. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Oil & Gas Geology    2024, 45 (1): 309-.   Abstract （367）      PDF（pc） （1076KB）（379）       Knowledge map    Save Related Articles | Metrics | Comments（0）

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Complex gas-water contacts in tight sandstone gas reservoirs： Distribution pattern and dominant factors controlling their formation and distribution Jianhui ZENG, Yaxiong ZHANG, Zaizhen ZHANG, Juncheng QIAO, Maoyun WANG, Dongxia CHEN, Jingli YAO, Jingchen DING, Liang XIONG, Yazhou LIU, Weibo ZHAO, Kebo REN Oil & Gas Geology    2023, 44 (5): 1067-1083.   DOI: 10.11743/ogg20230501 Abstract （288）   HTML （49）    PDF（pc） （4999KB）（366）       Knowledge map    Save In recent years， extensive exploration and exploitation activities in tight sandstone gas reservoirs have highlighted the common phenomenon of water production， indicating complex gas-water contacts. Exploring gas layers while avoiding water layers has become critical to the efficient exploration and exploitation of tight sandstone gas reservoirs. This study presents comprehensive geological analyses of gas-water contacts in simple gentle tectonic zones （tight sandstone gas reservoirs in the Sulige and Daniudi areas in the Ordos Basin）， a transition zone of simple gentle to complex uplift （Hangjin Banner in the Ordos Basin）， and complex uplift zones （tight-gas reservoirs in the western Sichuan Basin）. Combined with the core-scale and pore-scale physical simulations of gas-water contact in tight sandstone， we clarify the types and characteristics of gas-water contacts in tight-gas sandstone reservoirs， reveal the dominant factors controlling the formation and distribution of intricate gas-water contacts based on the sand bodies， cores， and pores， and establish corresponding gas-water distribution patterns. Key findings are as follows. In terms of sand body， there are primarily six types of gas-water contacts within， including （1） the simple type of gas layer without water layer； （2） the normal type with gas layer underlain by water layer； （3） the inverted type with gas layer overlaid by water layer； （4） the hybrid type with gas and water in the same layer； （5） the isolated type with water layer within a gas layer； and （6） the simple type of water layer without gas. The distribution range， style， and boundary of gas-water contacts are governed by hydrocarbon-generating intensity， reservoir heterogeneity， and a combination of source rock-reservoir pressure differences and tectonic activity， respectively. At core-scale， permeability coupled with charging dynamics of the tight sandstone governs the critical conditions for the formation and distribution of gas-water contacts. At pore-scale， the coupling of pore throat size and coordination number with charging pressure dictates the fluid occurrence and seepage characteristics， determining the critical conditions for the formation and distribution of gas-water contacts. Owing to the collective effects of dominant factors from sand body， core-scale， and pore scale and their differences， tight-gas reservoirs with different source rock-reservoir assemblages exhibit different gas-water distribution patterns. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Mechanical characteristics and fracture propagation mechanisms of the Gulong shale He LIU, Siwei MENG, Suling WANG, Kangxing DONG, Liu YANG, Jiaping TAO, Lihao LIANG Oil & Gas Geology    2023, 44 (4): 820-828.   DOI: 10.11743/ogg20230402 Abstract （288）   HTML （34）    PDF（pc） （9060KB）（348）       Knowledge map    Save 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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Natural fractures in deep to ultra-deep tight reservoirs： Distribution and development Lianbo ZENG, Lei GONG, Xiaocen SU, Zhe MAO Oil & Gas Geology    2024, 45 (1): 1-14.   DOI: 10.11743/ogg20240101 Abstract （263）   HTML （36）    PDF（pc） （4516KB）（311）       Knowledge map    Save Natural fractures serve as effective storage spaces and primary seepage pathways in deep to ultra-deep tight reservoirs， affecting the hydrocarbon migration and enrichment， single-well productivity， and exploitation methods and outcomes of the reservoirs. Based on the summary of latest research results and literature review on fractures in tight reservoirs， this study delves into the distribution characteristics and developmental patterns of natural fractures in deep to ultra-deep tight reservoirs. The results show that the natural fractures are of large， meso， small， and micro scales， following a power law distribution. In other words， a larger scale corresponds to a smaller number of fractures， and vice versa. Large- and meso-scale fractures primarily facilitate seepage； small-scale ones mainly enable seepage and storage； and micro-scale ones principally serve as storage spaces. The type， occurrence， and mechanical properties of the natural fractures formed across different periods are determined by the evolution of stress regime during stratigraphic burial. The formation， distribution， and developmental degree of multi-scale fractures are subjected to the magnitude of tectonic stress， the mechanical properties of rock mechanical stratigraphy， and the thickness differences in mechanical layers. Structural deformation results in varied local stress and strain distribution at different structural locations， increasing fracture heterogeneity. Thrust faults control the distribution of faulted fracture zones by controlling the deformation of strata on the hanging walls. The combination style and movement mode of strike-slip faults， along with rock mechanical stratigraphy， jointly dictate the three-dimensional spatial distribution of related fractures. Furthermore， the crack-seal patterns of the fractures during formation and evolution determine their storage spaces and record the evolutionary history of their effectiveness. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Well-logging evaluation of in-situ stress fields and its geological and engineering significances Jin LAI, Tianyu BAI, Lu XIAO, Fei ZHAO, Dong LI, Hongbin LI, Guiwen WANG, Ronghu ZHANG Oil & Gas Geology    2023, 44 (4): 1033-1043.   DOI: 10.11743/ogg20230418 Abstract （124）   HTML （9）    PDF（pc） （2486KB）（302）       Knowledge map    Save 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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Deep architecture of hyperextended marginal basin and implications for hydrocarbon exploration：A case study of Qiongdongnan Basin Keqiang WU, Xinong XIE, Jianxiang PEI, Jianye REN, Li YOU, Tao JIANG, Yongbin QUAN Oil & Gas Geology    2023, 44 (3): 651-661.   DOI: 10.11743/ogg20230310 Abstract （151）   HTML （10）    PDF（pc） （5166KB）（282）       Knowledge map    Save The passive continental margin basin in the northern South China Sea is an important oil and gas base in China’s offshore area. This paper reveals depositional filling characteristics and stratigraphic patterns of hyperextended continental margin rift basins based on coupling analysis of the deformation of deep crust and basin filling in the passive continental margin through comprehensive analyses of massive seismic and drilling data from the Qiongdongnan Basin of South China Sea. The results show that the Qiongdongnan Basin， located on the western tip of the northwest sub-basin of the South China Sea， is once a failed continental margin rift basin and presents now as a neck and distal zone along the central depression belt after lithospheric detachment and thinning. The rifting period contains three stretching stages. During the early stage， the formation of isolated rifted basin is characterized by high-angle positive faults. During the detachment active stage， the formation of detachment rifted basin is characterized by low-angle detachment faults with their active time obviously characterized by an east-west migration. And during the late rifting-depression stage， the depocenter is located in the center of the depression. The migration characteristics of differential deformation tectonic movement define the unique deep structure pattern of the Qiongdongnan Basin and lead to obvious differences in depositional fillings and stratigraphic patterns in different tectonic units， especially in depositional systems， where fan delta deposits dominate the main detachment fault side and braided delta deposits occupy the opposite rolling anticline. These factors restricted the distribution of source rocks and deep reservoirs during the rifting period， which in turn constrained geological conditions of hydrocarbon generation and accumulation. Therefore， the deep architecture of hyperextended continental marginal rift basins established based on non-transient breaking-up process of the lithosphere and depositional filling characteristics have important guiding significance for hydrocarbon exploration in the Qiongdongnan Basin， and may serve as reference for the study of deep stratigraphic pattern and depositional filling in passive continental margin basins. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Remarkable issues of Rock-Eval pyrolysis in the assessment of shale oil/gas Qian ZHANG, Zhijun JIN, Rukai ZHU, Quanyou LIU, Rui ZHANG, Guanping WANG, Wanli CHEN, Ralf Littke Oil & Gas Geology    2023, 44 (4): 1020-1032.   DOI: 10.11743/ogg20230417 Abstract （222）   HTML （10）    PDF（pc） （3233KB）（273）       Knowledge map    Save 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 （Tmax）， and the ratio of S2/S3 to discriminate kerogen of diverse types should target source rocks with maturity less than 1.35 % Ro； the feasibility of the technique to highly-to-over-mature source rock samples is limited. Second， the validity of Tmax depends on the area of S2 and whether it is in normal distribution， and the accuracy of Tmax relies on kerogen type and thermal maturity； moreover， residual hydrocarbon and pyrite content have some effects on the accuracy of Tmax. To obtain accurate Tmax values， the maturity of source rocks of types Ⅰ， Ⅱ， and Ⅲ should not be larger than 1.70 % Ro. 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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Sedimentary evolution pattern and architectural characteristics of mid-channel bars in sandy braided rivers： Understanding based on sedimentary numerical simulation Tao LEI, Guanglei REN, Xiaohui LI, Wenjie FENG, Huachao SUN Oil & Gas Geology    2023, 44 (6): 1595-1608.   DOI: 10.11743/ogg20230620 Abstract （124）   HTML （14）    PDF（pc） （5340KB）（273）       Knowledge map    Save Mid-channel bars in sandy braided rivers， boasting a large scale， high connectivity， and favorable physical properties， serve as a significant type of hydrocarbon reservoirs. Complex and variable hydrodynamic conditions endow mid-channel bars with multiple types and complex internal architectures， which constrain efficient oil and gas exploitation. This study aims to explore the sedimentary evolution pattern and architectural characteristics of mid-channel bars in sandy braided rivers， with a specific focus on the influence of the sedimentary process. To this end， we conduct the dynamic simulation and process analysis of the sedimentary evolution of sandy braided rivers using a sedimentary numerical simulation method based on the real-time solution in hydrodynamic fields. The results are as follows： （1） Mid-channel bars in sandy braided rivers evolve in five stages， namely the sequential formation and continuous conversion of lozenge-shaped bars， tongue-shaped bars， unit bars， composite bars， and reworked composite bars. These bars differ significantly in planar morphology， cross-sectional structure， and scale； （2） Interactions between water currents and mid-channel bars act as the predominant mechanism governing the sedimentary evolution of sandy braided rivers. Specifically， the constant changes in the convergence and divergence characteristics and distribution styles of water currents facilitate the formation， accretion， migration， and deformation of the mid-channel bars， which are under frequent and complex superimposition and cutting. In turn， the evolutionary dynamics of the mid-channel bars further induces the above-mentioned changes in water currents； （3） Three types of accretion stemming from progradation， lateral accretion， and aggradation occur within the mid-channel bars. In the process from the formation of lozenge-shaped bars to the emergence of reworked composite bars， the accretion within mid-channel bars evolves from an initial dominance of progradation to the coexistence of progradation and lateral accretion， culminating in a combination of all three accretion types. During the transitional phase， the length and width of the mid-channel bars experience a rapid increase， followed by a slow increase， and finally stabilize. As revealed by sedimentary records， reservoirs of the mid-channel bar microfacies terminating at different evolutionary stages differ significantly in planar distribution pattern， internal architectural characteristics， and scale. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Formation mechanisms of nano-scale pores/fissures and shale oil enrichment characteristics for Gulong shale， Songliao Basin Longde SUN, Xiaojun WANG, Zihui FENG, Hongmei SHAO, Huasen ZENG, Bo GAO, Hang JIANG Oil & Gas Geology    2023, 44 (6): 1350-1365.   DOI: 10.11743/ogg20230602 Abstract （139）   HTML （11）    PDF（pc） （9306KB）（257）       Knowledge map    Save The Cretaceous Gulong shale oil reservoirs in the Songliao Basin are composed of organic-rich continental shales with high clay content， interbedded with minor amounts of thinly laminated calcareous sandstones and dolomites. Currently， there is a lack of studies on the pore-fissure system and shale oil enrichment pattern of these reservoirs. Based on the data from experiments and analyses including argon ion milling-field emission scanning electron microscopy （FE-SEM）， energy-dispersive X-ray spectroscopy （EDS）， high-pressure mercury injection analysis， low-temperature nitrogen adsorption experiment， fluorescence thin section observation， X-ray diffraction （XRD） mineralogy of whole rock， and geochemical analysis， we investigate the organic-inorganic pore-fissure system in the Gulong shale and its relationship with shale oil enrichment. The results are as follows： （1） The Gulong shale hosts a dual-porosity reservoir system consisting of matrix pores and microfissures. Matrix pores serve as shale oil enrichment spaces， while microfissures provide both storage spaces and seepage pathways for shale oil； （2） Influenced by multiple factors such as mineral evolution， hydrocarbon generation， and cracking and conversion of crude oil， the Gulong shale exhibits varying pore-fissure combinations at different evolutionary stages. At the mature stage， the shale predominantly contains micron-scale dissolved pores and organo-clay complex pores/fissures （i.e.， pores/fissures with clay minerals as framework and formed as a result of hydrocarbon generation）. In contrast， the highly mature stage is characterized by nano-scale organo-clay-complex pores/fissures and bedding fissures； （3） There exists a coupling relationship between the shale oil enrichment and the evolution of pore-fissure combinations for the Gulong shale. The shale oil primarily accumulates within inorganic intergranular and intercrystalline pores at the low mature stage， while it is relatively heavy and predominantly concentrates in dissolved pores and organo-clay complex pores/fissures at the mature stage. At the highly mature stage， the shale oil becomes lighter and largely gets enriched in organo-clay complex pores/fissures and bedding fissures. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Experiment and numerical simulation of hydraulic fracturing in lacustrine shale： Taking the Ordos Basin as an example Xiao LI, Peng GUO, Yanzhi HU, Shixiang LI, Weiwei YANG Oil & Gas Geology    2023, 44 (4): 1009-1019.   DOI: 10.11743/ogg20230416 Abstract （196）      PDF（pc） （6426KB）（246）       Knowledge map    Save The 7th 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. Reference | Related Articles | Metrics | Comments（0）

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The impact of volcanism on eutrophication and water column in a freshwater lacustrine basin： A case study of Triassic Chang 7 Member in Ordos Basin Jiahong GAO, Zhijun JIN, Xinping LIANG, Shixiang LI, Weiwei YANG, Rukai ZHU, Xiaoyu DU, Quanyou LIU, Tong LI, Lin DONG, Peng LI, Wang ZHANG Oil & Gas Geology    2023, 44 (4): 887-898.   DOI: 10.11743/ogg20230407 Abstract （117）   HTML （15）    PDF（pc） （3214KB）（241）       Knowledge map    Save 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 FeHR/FeT ≥ 0.38 and Fepy/FeHR ≤ 0.8 in organic-rich shale but with Fepy/FeHR up to 0.8 with the increase of TOC. The （EFMo/EFU） （auth） ratios is 1-3 when the TOC is greater than 6 %. Both the iron speciation and （EFMo/EFU） （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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Exploration discoveries and implications of well Zheng 10 in the Zhengshacun area of the Junggar Basin Huimin LIU, Guanlong ZHANG, Jie FAN, Zhiping ZENG, Ruichao GUO, Yajun GONG Oil & Gas Geology    2023, 44 (5): 1118-1128.   DOI: 10.11743/ogg20230504 Abstract （131）   HTML （9）    PDF（pc） （2735KB）（239）       Knowledge map    Save The expansion toward deep-to-ultra-deep oil and gas exploration is strategically vital for reserve growth and production addition in the Junggar Basin. Well Zheng 10 drilled in the Zhengshacun area in the hinterland of the Junggar Basin underscores the significant potential of the basin’s central part for ultra-deep oil and gas exploration. This study first presents the characteristics of hydrocarbon reservoirs in the area， emphasizing the elements of pertroleum system， such as source rocks， reservoirs， and migration pathways， that contribute to hydrocarbon accumulation. Accordingly， it identifies the determinants of hydrocarbon accumulation in the area and establishes the hydrocarbon accumulation mode. Furthermore， this study presents the implications of these factors for deep-to-ultra-deep oil and gas exploration in the area. The results reveal three major factors influencing the hydrocarbon accumulation therein： （1） A mechanism driven by low geothermal gradients and overpressure for hydrocarbon-generating evolution. This mechanism extends the oil window and elevates the transformation ratio， thereby significantly enriching hydrocarbon resources； （2） A four element （including low geothermal gradient， overpressure， chlorite coating， and zeolite dissolution） -controlled reservoir formation. This pattern redefines the lower depth limit for the development of conventional clastic reservoirs， thus broadening the scope for hydrocarbon exploration. （3） A migration mechanism governed by both faults and overpressure. This mechanism provides high-energy pathways for hydrocarbon migration and determines the vertical differential hydrocarbon migration， thus ensuring efficient hydrocarbon charging in ultra-deep reservoirs. By integrating superimposed factors including ultra-deep source rock evolution， pressure changes， tectonic shifts， diagenetic sequences， and hydrocarbon accumulation periods， we establish a hydrocarbon accumulation mode for the study area. This mode incorporates the temperature-pressure control over hydrocarbon-generating evolution， four element-controlled reservoir formation， and hydrocarbon migration governed by both faults and overpressure. This study aims to provide theoretical guidance and a scientific basis for new exploratory well emplacement and the delineation of potential new play fairways in the area. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Evaluation of the compositions of lacustrine shale oil in China’s typical basins and its implications Ming LI, Min WANG, Jinyou ZHANG, Yuchen ZHANG, Zhao LIU, Bin LUO, Congsheng BIAN, Jinbu LI, Xin WANG, Xinbin ZHAO, Shangde DONG Oil & Gas Geology    2023, 44 (6): 1479-1498.   DOI: 10.11743/ogg20230612 Abstract （122）   HTML （9）    PDF（pc） （5007KB）（233）       Knowledge map    Save Shale oil composition serves as both a basis for revealing the shale oil enrichment mechanism and an essential parameter used to explore the interactions among oil， water， and rocks in the pores. We investigate the shale oil reservoir of pure shale type in the 1st member in the Qingshankou Formation in the Gulong Sag， Songliao Basin； the shale oil reservoir of transitional type in the Chunshang interval of the upper sub-member of the 4th member of the Shahejie Formation in the Dongying Sag， Jiyang Depression， Bohai Bay Basin； and the shale oil reservoir of pure shale type in the 3rd sub-member of the 7th member of the Yanchang Formation， Ordos Basin. Shale samples taken bypressure-retained coring and conventional coring， as well as oil produced from the three shale intervals and the products of autoclave-based thermal simulation experiment， are subjected to composition analysis. The composition of shale oil of diverse types and with varying maturity is characterized through chromatography to determine the total petroleum hydrocarbons （TPH） and pyrolysis-gas chromatography （PY-GC）. The methods for deriving shale oil compositions are comprehensively summarized and compared in terms of result， and the factors affecting the composition after evaporative loss are discussed. The assessment scheme is proposed at last. Consequently， we identify the compositional differences for the produced oil， thermally desorbed hydrocarbons， shale extracts， and products from thermal simulation experiment， as well as clarify the limitations of the above-mentioned evaluation methods. Additionally， the phenomenon that shale intervals with high total organic carbon （TOC） content tend to be of high oil content is illustrated， as revealed in previous studies. However， these intervals of high oil content do not necessarily reflect a high ratio of mobile to total oil volume. Shale maturity directly determines the composition of shale oil， while the abundance of organic matter and pore structures exert certain effects on the composition of residual hydrocarbons in shales. As indicated by the results of this study， it is necessary to consider hydrocarbon evaporativeloss in evaluating oil content in shales and exploring fluid occurrence state and shale oil enrichment mechanism， especially for shales of medium to high maturity. The composition evaluation of shale oil at varying maturity can provide new insights for revealing the fluid occurrence characteristics in shale nanopores. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Source-to-sink system and hydrocarbon source rock prediction of underexplored areas in rifted lacustrine basins： A case study on northern lows in Zhu Ⅰ Depression， Pearl River Mouth Basin Hao LIU, Changgui XU, Yangdong GAO, Heming LIN, Xinwei QIU, Yongtao JU, Xudong WANG, Lei LI, Jun MENG, Xiaoming QUE Oil & Gas Geology    2023, 44 (3): 565-583.   DOI: 10.11743/ogg20230304 Abstract （153）   HTML （21）    PDF（pc） （9417KB）（232）       Knowledge map    Save Hydrocarbon source rock is one of the key factors controlling oil/gas accumulation in petroliferous system of a sedimentary basin. Focusing on the challenges facing hydrocarbon source rock prediction in basins or lows with relatively low exploration maturity， sparsely distributed drilling wells and insufficient source rock index， we take the underexplored areas in northern Zhu Ⅰ Depression in the Pearl River Mouth Basin （PRMB） as an example to systematically analyze the source-to-sink system and predict source rocks from the perspectives of “searching for lake （deep-to-semi-deep lake）”， “recognizing mudstones （deep-to-semi-deep lacustrine mudstones）”， and “identifying hydrocarbon （hydrocarbon source rock prediction and evaluation）”. First， the original basin features and location of the paleo-lacustrine basin are illustrated by restoring multi-stage tectono-palaeogeomorphology to “find the lake”； and the deep-to-semi-deep lake is identified in the underexplored area together with preliminary selection of potential lows with well-developed hydrocarbon source rocks in combination with analyses including “identifying the lacustrine basin boundary by seismic progradational reflection， determining the scope of the deep-to-semi-deep lake by slope break system， illustrating paleo-environment characters by biochemical index， and defining the lacustrine basin scale by tectonic intensity”. The results indicate that five lows formed during the Wenchang depositional period， and five lows formed during the depositional period of the lower Enping Formation have the potential of developing deep-to-semi-deep lacustrine mudstones. Second， the reconstruction of source-to-sink system and the geological analysis of deep-to-semi-deep lacustrine mudstone development are conducted through analyses of paleo-provenance， paleo-environment and depositional systems， as well as tectono-palaeogeomorphology features； various configuration elements simulation results of the source-to-sink system show that basins characterized by medium sediment supply intensity， fine-grained source materials， high lake level， large accommodation space and under-equal or equal compensation are favorable for the deposition of mud-rich lacustrine facies. Finally， based on data of exploratory wells encountering high-quality hydrocarbon source rocks in mature exploration areas， we analyze four types of deep-to-semi-deep seismic facies and their geologic backgrounds corresponding to hydrocarbon source rock intervals， establish the “hydrocarbon source rock facies （seismic facies of hydrocarbon source rocks）” of the mature exploration areas. Coupled with the systematic summary of hydrocarbon-enrichment factors in main hydrocarbon-rich lows of the Zhu Ⅰ Depression， we assess and rank the high-quality hydrocarbon source rocks in the underexplored areas with multiple factors and from multi-dimensional points of view. The research results also indicate that the first-order potentially hydrocarbon-rich lows include LF22， HF33， and HZ24 （with the lower and upper Wenchang Formation as source rocks）， as well as the LF7 and HF10 （with the lower Wenchang Formation as source rocks）； the second-order potentially hydrocarbon-rich ones are HZ5 and HZ11 （with the lower Enping Formation as source rocks）， with the hydrocarbon source rock prediction and evaluation results of some lows having been testified in practical exploration. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Limits of critical parameters for sweet-spot interval evaluation of lacustrine shale oil Zhiming LI, Yahui LIU, Jinyi HE, Zhongliang SUN, Junying LENG, Chuxiong LI, Mengyao JIA, Ershe XU, Peng LIU, Maowen LI, Tingting CAO, Menhui QIAN, Feng ZHU Oil & Gas Geology    2023, 44 (6): 1453-1467.   DOI: 10.11743/ogg20230610 Abstract （111）   HTML （7）    PDF（pc） （2569KB）（231）       Knowledge map    Save Determining the limits of critical parameters for sweet-spot intercal evaluation of lacustrine shale oil is the key to commercial shale oil exploitation. Based on the on-site observations and lab analysis of lacustrine shale oil exploratory wells， supplemented by previous research results and achievements in exploration and development practices， we try to determine the limits of critical parameters for sweet-spot intervals of diverse shale oil types， including the total organic carbon （TOC） content， vitrinite reflectance （Ro）， pyrolytic hydrocarbon content （S1）， porosity and permeability， oil saturation index （OSI）， and brittle mineral content. Findings suggest that for the shale oil sweet-spot intervals of the mixed type with source rock-reservoir integrated and the pure shale type， the lower limit of TOC content is greater than 1.0 % or 2.0 %， and the upper limit should not exceed 6.0 %. For sweet-spot intervals in the source rock measures of brine-saline， saline-brackish， and brackish-fresh lacustrine basins， the lower limits of Ro are 0.50 %， 0.60 %， and 0.80 %， respectively. Regarding S1， two scenarios are recommended considering factors such as sample preparation： for low limit of TOC content at 1.0 %， the lower limit of S1 is 1.0 mg/g （conventional pyrolysis） or 2.0 mg/g （pyrolysis of sealed and frozen crushed samples）； for low limit of TOC content at 2.0 %， the lower limit of S1 is 2.0 mg/g （conventional pyrolysis） or 4.0 mg/g （pyrolysis of sealed and frozen crushed samples）. The lower limits of porosity and permeability are 5.0 % and 0.01×10-3 μm2， respectively for the intercalated-type sweet-spot intervals of shale oil， and are 4.0 % and 0.01×10-3 μm2， respectively for the pure shale-type and mixed-type sweet-spot intervals with laminated and layered textures and well-developed fractures. The lower limit of OSI is 100 mg/g or 200 mg/g for the pure shale-type and mixed-type and is 300 mg/g or 400 mg/g for intercalated-type. The lower limit of the brittle mineral content is 65.0 %. These findings can lay the foundation for genuine shale oil sweet-spot interval development to achieve commercial shale oil exploration and exploitation in low-oil-price environment. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Quantitative reconstruction， hierarchical division and coupling mode establishment for ancient source-to-sink systems in continental basins Hongtao ZHU, Changgui XU, Xiaofeng DU, Qianghu LIU, Zhongheng SUN, Zhiwei ZENG Oil & Gas Geology    2023, 44 (3): 539-552.   DOI: 10.11743/ogg20230302 Abstract （188）   HTML （24）    PDF（pc） （4861KB）（227）       Knowledge map    Save Quantitative reconstruction， hierarchical division and coupling mode establishment are important means to restore the erosion and sedimentation processes for depth-time ancient source-to-sink systems in continental basins. The main difficulties in quantitative reconstruction of provenance lie in paleo-geomorphology reconstruction and paleo-drainage reconstruction. New techniques for paleo-geomorphology reconstruction use a “three-zone and five-step” restoration method based on the framework of denudation， overlap-denudation and overlap zones as well as steps of residual geomorphology reconstruction， differential subsidence correction， overlap-denudation zone restoration， denudation zone restoration and depositional paleo-geomorphology restoration. In terms of paleo-drainage system reconstruction， a quantitative restoration and picking method is resorted to based on the ArcGIS system. The division of ancient source-to-sink systems in continental basins is usually realized by using the “three-line and three-level” method， of which， picking up watersheds， water dividing lines and ridge lines are very critical before a further division of first-order， second-order， and third-order source-to-sink systems. According to the area， geometric configuration and coupling relationship of the drainage unit and sedimentary body within the reconstructed ancient source-to-sink system， this paper puts forward four types of source-sink coupling modes， i.e.， “dumbbell”， “racket”， “trophy” and “javelin” modes， and thus may serve as a valuable reference for quantitative study of source-to-sink system and prediction of deep exploration targets. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Characteristics of passive strike-slip structure and its control effect on fracture development in Bozi-Dabei area， Tarim Basin Honghui GUO, Jianwei FENG, Libin ZHAO Oil & Gas Geology    2023, 44 (4): 962-975.   DOI: 10.11743/ogg20230413 Abstract （130）   HTML （6）    PDF（pc） （8801KB）（226）       Knowledge map    Save 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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Oil & Gas Geology    2023, 44 (4): 1067-1068.   DOI: 10.11743/ogg20230421 Abstract （154）   HTML （29）    PDF（pc） （854KB）（223）       Knowledge map    Save Reference | Related Articles | Metrics | Comments（0）

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Shale oil resource potential in the Bohai Sea area Lijun MI, Jianyong XU, Wei LI Oil & Gas Geology    2023, 44 (6): 1366-1377.   DOI: 10.11743/ogg20230603 Abstract （124）   HTML （10）    PDF（pc） （4799KB）（219）       Knowledge map    Save The Paleogene Shahejie and Dongying formations in the Bohai Sea area are rich in shale oil resources. However， limited explorations， as well as a lack of systematic investigation of the potential evaluation and endowment differences of shale oil resources， have constrained the exploration deployment and favorable play fairway selection in the area. Based on the actual exploration and exploitation conditions in the area， we ascertain the resource potential and favorable exploration targets of shale oil through the geochemical experiments， and whole-rock mineralogical analysis of source rocks. The results are as follows： （1） High-quality source rocks are widespread in the five hydrocarbon-rich sags in the Bohai Sea area. These source rocks exhibit moderate maturity， conducive to generating shale oil. The shale oil in the area can be classified into three types： scattered （ineffective） resources， low-efficiency resources， and enriched resources. The evaluation results show consistent enriched resources across various sags， predominantly with total organic carbon （TOC） content >1.8 % and pyrolysis hydrocarbon content （S1） > 2.0 mg/g； （2） Shale oil-rich intervals are distributed across the five hydrocarbon-rich sags. Two shale oil-rich intervals with varying burial depths are found in the Huanghekou and Bozhong sags， with the interval in the Huanghekou Sag exhibiting smaller burial depth of around 2 800 m. In contrast， shale oil-rich intervals in the Liaozhong， Qikou， and Qinnan sags have burial depths ranging from 2 800～3 200 m； （3） For the 3rd and 1st members of the Shahejie Formation and the 3rd member of the Dongying Formation in the Bohai Sea area， each of these members have shale oil play fairways covering an area exceeding 10 000 km2. The five hydrocarbon-rich sags all boast shale oil resource potential beyond 15 × 109 t， to which moderately to highly mature shale oil contributes more than 6.6 × 109 t. Among these sags， the Huanghekou and Liaozhong sags， enjoying organic matter of high abundance and favorable types， shallow shale oil enrichment， and considerable resource potential， serve as the most favorable targets for current exploration. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Classification， origins， and evolution of macerals in the Precambrian-Eopaleozoic sedimentary rocks Qingyong LUO, Ningning ZHONG, Meijun LI, Jin WU, Imran Khan, Ye ZHANG, Qing CHEN, Xiangzhong YE, Wenhao LI, Wenming JI, Anji LIU, Jingyue HAO, Lipeng YAO, Jia WU Oil & Gas Geology    2023, 44 (5): 1084-1101.   DOI: 10.11743/ogg20230502 Abstract （163）   HTML （26）    PDF（pc） （14761KB）（217）       Knowledge map    Save This study delves into the intricate organic macerals found in ancient Precambrian-Eopaleozoic sedimentary rocks， despite their simple biotic sources. Based on the observation and analysis of a vast array of naturally- and artificially-matured rock samples from domestic and international locations， we classify the macerals according to four dominant factors， namely biogenesis， origin， sedimentary transformation， and thermal maturation. The key classe determined include vitrinite-like macerals， sapropelinites， solid bitumen， zooclasts， and inertinites. The macerals in low-maturity marine source rocks are chiefly composed of lamalginite， bituminite， and mineral-bituminous matrix. In contrast， high- to over-mature marine source rocks predominantly contain in-source solid bitumens. Notably， graptolite periderms， as significant components of organic matter， are prevalent in the shales of the Wufeng-Longmaxi formations. We provide deeper insights into the origins of the most typical macerals prone to be overlooked previously， including vitrinite-like maceral particles and in-source solid bitumens. The vitrinite-like maceral particles in the Precambrian rock samples may arise from the microbial degradation of lower aquatic organisms during early diagenesis. In-source solid bitumens form either as solid residues arising from the cracking of soluble organic matter that remained within source rocks after primary migration or as solid-phase products during the thermal evolution of the residual kerogen of sapropelinites after absorbing and assimilating soluble organic matter. Lastly， as indicated by integrated research on the naturally- and artificially-matured rock samples， the preexisting organic matter in high to over mature Precambrian， Cambrian， and Ordovician-Silurian graptolite-bearing shales in China resemble the present-day organic matter in the Mesoproterozoic Xiamaling Formation， Cambrian Alum Shale Formation， and Ordovician graptolite-bearing Alum Shale Formation， respectively. The reflectance of graptolite periderms， vitrinite-like maceral particles， and in-source solid bitumens can be utilized to characterize the thermal maturity of organic matter in the Precambrian-Eopaleozoic marine source rocks. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Discovery of the Qijiang shale gas field in a structurally complex region on the southeastern margin of the Sichuan Basin and its implications Dongfeng HU, Zhihong WEI, Ruobing LIU, Xiangfeng WEI, Wei WANG, Qingbo WANG Oil & Gas Geology    2023, 44 (6): 1418-1429.   DOI: 10.11743/ogg20230607 Abstract （81）   HTML （8）    PDF（pc） （6043KB）（212）       Knowledge map    Save Following the discovery of the Fuling shale gas field， shale gas exploration in the Sichuan Basin has expanded into the structurally complex region on its southeastern margin， where the Qijiang shale gas field has benn discovered. The findings achieved in the study are as follows. （1） The Qijiang shale gas field is generally similar to the Fuling shale gas field in terms of geological features， as shown with high total organic carbon （TOC） content （average：2.62 %）， high porosity （average： 4.53 %）， and high gas content （average：5.43 m3/t）. It is a typical self-sourced dry gas reservoir of continuity. Furthermore， the Qijiang shale gas field exhibits complex surface and subsurface conditions， including a large burial depth range involving moderately deep to deep layers with a medium depth of 3 354 m， low geothermal gradients （average：2.99 ℃/100 m）， and extensive formation pressure coefficient in a range of 0.98 to 1.98 （average：1.50） spanning normal to ultra-high pressure. （2） A shale gas enrichment model for basin-margin nose-like faulted anticlines in the structurally complex region is established featuring enrichment at deep burial areas as controlled by major fault zone， and this specifies that the shale gas enrichment in the anticlines， the critical features of shale gas sweet spots encompass high-quality shale， high fluid pressure， well-developed microfractures， and low in-situ stress. （3） Technologies applicable to deep shale gas reservoirs are developed， including sweet spot prediction technology and volume fracturing to form intricate fracture networks， providing a firm guarantee for high， stable gas flow in the Qijiang shale gas field. In November 2022， estimated shale gas in-place of 1 459.68×108 m3 from the Wufeng-Longmaxi formations in the Dingshan block was booked for the first time. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Fluid phases and behaviors in ultra-deep oil and gas reservoirs， Tarim Basin Wei HU, Ting XU, Yang YANG, Zengmin LUN, Zongyu LI, Zhijiang KANG, Ruiming ZHAO, Shengwen MEI Oil & Gas Geology    2023, 44 (4): 1044-1053.   DOI: 10.11743/ogg20230419 Abstract （112）   HTML （4）    PDF（pc） （3057KB）（205）       Knowledge map    Save 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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Geological heterogeneity of shale sequence and evaluation of shale oil sweet spots in the Qingshankou Formation， Songliao Basin Bin BAI, Chaocheng DAI, Xiulin HOU, Liang YANG, Rui WANG, Lan WANG, Siwei Meng, Ruojing DONG, Yuxi LIU Oil & Gas Geology    2023, 44 (4): 846-856.   DOI: 10.11743/ogg20230404 Abstract （124）   HTML （17）    PDF（pc） （3117KB）（204）       Knowledge map    Save 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. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Source-to-sink system during rifting-depression transition period and its exploration significance： A case study of the Upper Enping Formation at southeastern margin of Huizhou 26 sub-sag， Pearl River Mouth Basin Guangrong PENG, Xucheng WANG, Weitao CHEN, Yaoyao JIN, Fei WANG, Wenyong WANG, Han QUAN Oil & Gas Geology    2023, 44 (3): 613-625.   DOI: 10.11743/ogg20230307 Abstract （178）   HTML （14）    PDF（pc） （8898KB）（201）       Knowledge map    Save Rifting-depression transition period is a significant stage of transition for a rifted basin from extension to subsidence， during which the tectonic activities get stable along with declining extension， affecting the sedimentary system and favorable reservoir distribution in the late rifting period. With the guidance of the “source-to-sink” coupling ideology and based on the analysis of petrological characteristics， logging and seismic facies， we propose the idea of “tectonic activity-controlling facies， and valley/fault-controlling reservoir” to analyze the origin and distribution pattern of favorable reservoirs according to the differential activities of boundary faults during the rifting-depression transition period of the Upper Enping Formation at southeastern margin of Huizhou 26 sub-sag. The major conclusions can be drawn as follows. First， the Mesozoic intrusive rocks of the Dongsha uplift serve as the provenance to the upper member of the Enping Formation in the study area， with five major catchment units developed during the rifting-depression transition period. The supply capacity can be characterized by the quantitative analysis of the area and head of these catchment units. Second， the sediment-transport pathways are composed of the valleys and boundary faults. The morphology and scale of valleys within provenance affect the water kinetic energy of each drainage， and the planar combination pattern of boundary faults （i.e. the concave corner type， the straight and flat slope type， and the straight and flat fault type） and their vertical throws serve to influence the way of sediments converging in lake， as well as the distribution of sand bodies. Third， the “source-to-sink” coupling with four elements including source， valley， boundary fault and sedimentary system helps establish a sedimentary framework of “fan deltas in the south and braided deltas in the north” resulting from the differential activities of boundary faults at the tectonically quiet stage of the rifting-depression transition period. Sedimentary characteristics are finely depicted to disclose favorable facies zone and quality reservoir distribution， that is， the coarse-grained deposits of channel sub-facies， braided river delta plain facies， that is formed by sediments transported along the “valley-boundary faults” to lake， and characterized by well-developed primary pores and high permeability. These new understandings serve to promote the exploration progress of the Enping Formation and manifest exploration direction of the Paleogene deep strata at the southwestern area of Huizhou Sag. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Factors controlling the development of deep and ultra-deep coarse-grained siliciclastic reservoirs with high quality in the steep slope zone of the Minfeng sub-sag， Dongying Sag， Bohai Bay Basin Jiageng LIU, Yanzhong WANG, Yingchang CAO, Shuping WANG, Xuezhe LI, Zhukun WANG Oil & Gas Geology    2023, 44 (5): 1203-1217.   DOI: 10.11743/ogg20230510 Abstract （109）   HTML （5）    PDF（pc） （5271KB）（200）       Knowledge map    Save Deep and ultra-deep layers within petroliferous basins have emerged as new targets in global oil and gas exploration. However， the major factors influencing the development of high-quality reservoirs within these layers remain poorly understood， posing challenges for effective exploration. This study focuses on the coarse-grained siliciclastic reservoirs in the nearshore subaqueous fan in the lower submember of the 4th member of the Shahejie Formation in the steep slope zone of the Minfeng sub-sag， Dongying Sag. By combining methodologies including casting thin section observation， scanning electron microscopy （SEM）， cathodoluminescence microscopy-based identification of minerals in thin sections， fluid inclusion thermometry， and paleopressure reconstruction， as well as the analytical results of the burial and thermal history， we comprehensively examine the reservoirs’essential characteristics， hydrocarbon charging history， pressure evolution， and factors controlling the development of high-quality reservoirs. The findings include： （1） The coarse-grained siliciclastic reservoirs in the study area are predominantly lithic arkoses and feldspathic litharenites. They exhibit medium to strong compaction and are dominated by ferrodolomite cementation， followed by quartz overgrowth. They show overall weak dissolution dominated by feldspar dissolution. The reservoir spaces comprise mostly primary pores， along with some others developed from feldspar dissolution. （2） Two oil charging stages and one natural gas charging stage were identified： an early mature-oil charging between 37.2～25.8 Ma and a later highly-mature-oil charging from 12 Ma onwards. The natural gas charging has lasted till now since 3.6 Ma. （3） The reservoirs have experienced two distinct pore pressure-increasing cycles： 45～24.6 Ma and from 24.6 Ma to present， corresponding to the two hydrocarbon charging stages. （4） Favorable lithofacies lay the foundation for the development of high-quality reservoirs dominated by primary pores in the study area. The inhibitive effects of overpressure hydrocarbon charging on compaction and cementation are crucial to the development of high-quality reservoirs. The weak dissolution of feldspar and carbonate minerals in the deep closed system leads to a low increment in porosity. However， the reduction rate of the reservoir porosity with depth declines significantly at burial depths beyond 3 750 m， and the development of deep high-quality reservoirs dominated by primary pores expands the lower limit of depth for exploration. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Exploring the dynamic hydrocarbon accumulation process of the Enping 17 sub-sag in the Enping Sag， Pearl River Mouth Basin Yuling SHI, Zulie LONG, Xiangtao ZHANG, Huahua WEN, Xiaonan MA Oil & Gas Geology    2023, 44 (5): 1279-1289.   DOI: 10.11743/ogg20230516 Abstract （91）   HTML （8）    PDF（pc） （3884KB）（196）       Knowledge map    Save In this study， we determine the hydrocarbon sources and distribution in the Enping 17 sub-sag， Pearl River Mouth Basin （PRMB） through geochemical analyses. Using the selected optimal fault attributes， we quantitatively evaluate the hydrocarbon transport capacity of faults during different geologic periods. Furthermore， we reproduce the paleotectonic morphologies of primary seismic reflectors in the Enping 17 sub-sag since 23.03 Ma with the aid of the MOVE software， revealing the influence of the paleotectonic morphological changes of seismic reflector T{}_{\mathrm{7}}^{\mathrm{0}} on hydrocarbon redistribution in the vertical direction and among various tectonic zones. Finally， we reconstruct the dynamic hydrocarbon accumulation process and predict potential hydrocarbon exploration targets. The results are as follows. （1） The crude oil of the Enping 17 sub-sag originates primarily from source rocks in the 3rd， 4th， and 5th members of the Eocene Wenchang Formation. Faults with throws ranging from 100—130 m can transport hydrocarbons to the Enping Formation， while those with throws exceeding 130 m may create conducive conditions for hydrocarbons to migrate vertically toward the medium and shallow reservoirs through the Enping Formation. （2） The hydrocarbons in the sub-sag underwent three migration and accumulation stages： the migration and accumulation near sources in the early stage， the southward migration and accumulation in the middle stage， and the S-N two-way migration and accumulation in the late stage. Due to the weak vertical hydrocarbon transport capacity of faults in the late stage， the Enping Formation served as a hub for hydrocarbon redistribution in the vertical direction and among various tectonic zones. Prior to 10.00 Ma， hydrocarbon migration and accumulation primarily occurred near sources under the paleostructural surface on seismic reflector T{}_{\mathrm{7}}^{\mathrm{0}}. From 10.00 Ma to 5.33 Ma， hydrocarbons migrated to and accumulated in the southern tectonic zones along the carrier beds of the Enping Formation. After 5.33 Ma， hydrocarbon migration was diverted northward under the paleostructural surface on T{}_{\mathrm{7}}^{\mathrm{0}}， signaling the general commencement of S-N two-way migration and accumulation. In conclusion， the favorable exploration targets in the Enping 17 sub-sag include the Paleogene structural traps along NW-trending structural ridges， as well as the tectono-lithologic or stratigraphic-lithologic traps in the Enping Formation at the edge of the northern paleo-uplift. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Filling patterns and reservoir property of the Ordovician buried-river karst caves in the Tabei area， Tarim Basin San ZHANG, Qiang JIN, Jinxiong SHI, Mingyi HU, Mengyue DUAN, Yongqiang LI, Xudong ZHANG, Fuqi CHENG Oil & Gas Geology    2023, 44 (6): 1582-1594.   DOI: 10.11743/ogg20230619 Abstract （91）   HTML （4）    PDF（pc） （7510KB）（189）       Knowledge map    Save An integration of outcrop observations， as well as data from drilling， logging， and seismic surveys in an oilfield is applied to analyze the filling types and filling cycle assemblages of karst caves associated with paleokarst buried rivers； accordingly， the filling sequences and patterns of the paleokarst buried rivers， as well as the discussion on their petroleum geological implications. The results show that the Ordovician buried-river karst caves with a filling rate of 89.9 % in the Tahe oilfield， are predominantly filled with sandy mudstones and collapse breccias. These karst caves host multiple combination cycles featuring coarse-grained lower parts and fine-grained upper parts， which can be classified into polycyclic sedimentary assemblages and polycyclic collapse-sedimentary assemblages for filling. The former is distributed in the karst slope’s lower reaches of flat landform， where wells with lost circulation and stringers account for small and high proportions， respectively. In contrast， the latter is situated in the karst slope’s upper reaches featuring landform of great drops， where wells with lost circulation are of high proportion together with multiple high-yielding wells. The following conclusions can be reached through analysis： （1） The tortuous spatial structure of buried rivers， combined with their strong runoff transport capacity， facilitate the filling of large amounts of karst detrital materials， resulting in an extremely high filling rate； （2） The seasonal fluctuations in the phreatic surface lead to the formation of cyclic and comparable fillings. This， coupled with water erosion and tectonic activities， gives rise to multi-phase collapses of karst caves. Consequently， polycyclic collapse-sedimentary filling assemblages are formed in the upper reaches， with unfilled spaces developed； （3） The relatively closed underground environment supersaturated with calcium carbonate， results in severe calcareous cementation of fillings， decreasing the intergranular porosity； （4） The unfilled spaces serve as the major targets with potential for oil and gas exploitation. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Phase evolution and accumulation mode of hydrocarbons in deep coarse-grained clastic reservoirs in the Yanjia area， Dongying Sag， Bohai Bay Basin Yongshi WANG, Jianqiang GONG, Dongxia CHEN, Yibo QIU, Shuwei MAO, Wenzhi LEI, Huaiyu YANG, Qiaochu WANG Oil & Gas Geology    2023, 44 (5): 1159-1172.   DOI: 10.11743/ogg20230507 Abstract （109）   HTML （9）    PDF（pc） （4209KB）（188）       Knowledge map    Save Deep hydrocarbon reservoirs in the Yanjia area in the northern steep slope zone of the Dongying Sag experienced complex thermal evolution. The resultant multiple hydrocarbon phases pose challenges for the exploration and exploitation of deep hydrocarbons. Using basin modeling， pressure-volume-temperature （pVT） phase simulation， and the analysis of hydrocarbon fluid inclusions， we reveal the evolutionary process of deep hydrocarbon phases in the Yanjia area and establish the hydrocarbon accumulation modes of different types of reservoirs. Findings indicate that deep hydrocarbons in the 4th member of the Shahejie Formation in the Yanjia area exhibit an orderly phase distribution in the vertical direction， with reservoirs of light oil， condensate gas， and dry gas found from shallow to deep. While thermal evolution predominantly governed the formation of hydrocarbon phases in deep coarse-grained clastic rocks， the phase evolution in condensate gas reservoirs stemmed from hydrocarbon generation from kerogen， crude oil cracking， and external natural gas charging. By integrating insights into the hydrocarbon phases， characteristics， and temperature and pressure evolutionary histories of different hydrocarbon reservoirs， we propose a hydrocarbon accumulation mode for deep coarse-grained clastic rocks in the Yanjia area. This mode encompasses multi-stage hydrocarbon generation， migration via superimposed sand beds within middle fans while sealed by mudstone within root fans， and the orderly phase distribution of hydrocarbons. This study seeks to provide theoretical guidance for the efficient exploration of deep hydrocarbons in continental downfaulted basins. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Sequence filling and evolutionary model of the Lower Cambrian Maidiping-Qiongzhusi formations in Sichuan Basin and on its periphery Dong WU, Hucheng DENG, Liang XIONG, Kaixuan CAO, Xiaoxia DONG, Yong ZHAO, Limin WEI, Tong WANG, Ruolong MA Oil & Gas Geology    2023, 44 (3): 764-777.   DOI: 10.11743/ogg20230318 Abstract （158）   HTML （18）    PDF（pc） （4996KB）（188）       Knowledge map    Save The Lower Cambrian Qiongzhusi Formation in the Sichuan Basin and on its periphery is rich in shale gas resources and has been proven to be one of the important shale gas pay zones in the basin. Due to the deep burial depth， few data and complex geological conditions， the research on its sequence stratigraphy has been relatively weak， having seriously restricted the follow-up research and development. The study on the Early Cambrian tectono-sedimentary setting of the Sichuan Basin and on its periphery， coupled with lithology， rock color， logging curve， trace elements， paleontology， seismic reflection event and other characteristics， is carried out to further explore the sequence stratigraphy of the Maidiping-Qiongzhusi formations， with the idea for the sequence division proposed. As a result， the Maidiping-Qiongzhusi formations are divided into four third-order sequences from bottom to top. By revealing the spatial distribution pattern of the sequence stratigraphy， we establish a sequence evolutionary model of “differential sedimentation in early narrow basin， and stable sedimentation in later wide basin” for the Maidiping-Qiongzhusi formations in the Sichuan Basin and on its periphery under the control of global plate extensional activity. The sequence evolutionary model will be of help to deepening understanding of the Cambrian tectono-sedimentary setting in the Sichuan Basin， promoting geological research on sedimentary reservoirs， and serving the exploration and development of deep shale gas. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Characteristics of the source-to-sink system for the Paleogene Sha 2 Member of northern Liaoxi Sag， offshore Bohai Bay Basin and its control on beach bar sands Xiaogfeng DU, Xiaojun PANG, Xiaobo HUANG, Bingjie WANG Oil & Gas Geology    2023, 44 (3): 662-674.   DOI: 10.11743/ogg20230311 Abstract （160）   HTML （675）    PDF（pc） （5076KB）（185）       Knowledge map    Save The beach-bar deposits developed in the 2nd member of the Paleogene Shahejie Formation （Sha 2 Member， Es2） in the northern Liaoxi Sag， have great exploration potential as proved by the testing results of exploratory wells. However， there is little insight obtained on the mechanism of beach-bar deposition， seriously restricting the exploration and evaluation of this kind of deposits. Therefore， it is necessary to analyze the controlling factors of beach-bar sand deposition from the perspective of source-to-sink system. The source-to-sink system of the Es2 in the northern Liaoxi Sag and its control on beach-bar deposition are studied by integrating the data of core observation， logging， grain size and casting thin section， combined with 3D seismic and regional geological data. The results are shown as follows. First， during the deposition of the Es2 in the study area， the Xingchenghe river system and the Yuehe river system in the Yanshan uplift transported sediments to the braided river deltas， which in turn served to supply sediments for the beach bar. Because the relatively small catchment area of the two river systems together with the shorter length of main river， the braided river deltas formed are relatively small in scale， and their capability to provide sediments for beach bars is thereby relatively weak. Second， during the deposition of Es2， a wide and gentle palaeo-uplift was developed in the northern Liaoxi Sag， providing favorable sedimentary palaeo-geomorphic conditions for beach bar deposition. Third， during the same period， the study area was characterized by shallow water body and weak sediment supply capacity， resulting in the transportation of sand from the braided river delta front towards the lacustrine basin with waves. Blocked by the higher landform of the palaeo-uplift zone， the sand bodies deposited in the palaeo-uplift zone and formed fine-grained sandy beach bars， dominated by fine-grained sandstone and siltstone. As the lake level gradually rises， the development of the beach bars gets weakened. Fourth， Yanshan uplift， Xingchenghe-Yuehe river systems， palaeo-uplift in the central Liaoxi Sag and lake level fluctuation jointly control the lithology and scale of beach-bar sands， and they are the key factors in making breakthrough in hydrocarbon exploration in the study area. The understanding obtained in the study is of referential significance to the prediction of beach-bar sandstone reservoirs in the Paleogene hydrocarbon exploration in the Bohai Sea. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Influence of sand-mud assemblages in tight sandstones on reservoir storage spaces： A case study of the lower submember of the 3rd member of the Paleogene Shahejie Formation in the Linnan sub-sag， Bohai Bay Basin Junliang LI, Xin WANG, Weiqing WANG, Bo LI, Jianhui ZENG, Kunkun JIA, Juncheng QIAO, Kangting WANG Oil & Gas Geology    2023, 44 (5): 1173-1187.   DOI: 10.11743/ogg20230508 Abstract （105）   HTML （11）    PDF（pc） （6672KB）（184）       Knowledge map    Save The swift shifts in sedimentary water bodies in continental petroliferous sedimentary basins result in frequent intercalation of sandstone and mudstone layers. Various sandstone-mudstone intercalation patterns （sand-mud assemblages） lead to significant differences in the storage spaces in sandstone reservoirs. Focusing on the lower submember of the 3rd member of the Paleogene Shahejie Formation in the Linnan sub-sag， Huimin Sag， Bohai Bay Basin， we first analyze the spatial assemblages and single-layer thickness of sandstone and mudstone layers. Using casting thin section observations， physical property tests， and micro-CT scanning， we systematically elucidate the physical properties， pore types， and pore structures of sandstone reservoirs with different sand-mud assemblages. As indicated by the findings， the lower submember contains nine types of sand-mud assemblages， namely thick mudstone interbedded with thin sandstone， medium mudstone interbedded with thin sandstone， thick mudstone interbedded with medium sandstone， intercalated thin sandstone and thin mudstone， intercalated medium sandstone and medium mudstone， intercalated thick sandstone and thick mudstone， medium sandstone interbedded with thin mudstone， thick sandstone interbedded with medium mudstone， and thick sandstone interbedded with thin mudstone. The ionic interactions between sandstones and mudstones lead to strong heterogeneity in the storage capacity of sandstone reservoirs with different sand-mud assemblages. For sand-mud assemblages with low net-to-gross ratios， mudstones supply ample CO32-， Ca2+， Fe2+， and Mg2+ to sandstones， and sandstones are completely filled with cements. Consequently， the sandstone reservoirs become extremely tight. However， when this ratio rises， mudstones cannot provide sandstones with sufficient ions mentioned above. In this case， sandstones near the sand-mud interfaces exhibit strong carbonate cementation， forming extremely tight reservoirs. In contrast， the interior of the sandstones shows weak carbonate cementation， with a small number of primary pores present. Additionally， the sand-mud assemblages with relatively thick sandstones promote organic acid infiltration， enhancing reservoir quality through the formation of numerous intergranular dissolution pores. Based on the differences in sand-mud assemblages， we reveal the influence of sand-mud assemblages on the evolutionary path and model of the storage spaces in sandstone reservoirs. Our insights are pivotal for predicting sweet spots in tight sandstone reservoirs. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Enrichment characteristics， exploration and exploitation progress， and prospects of deep shale gas in the southern Sichuan Basin， China Hongyan WANG, Shangwen ZHOU, Qun ZHAO, Zhensheng SHI, Dexun LIU, Pengfei JIAO Oil & Gas Geology    2023, 44 (6): 1430-1441.   DOI: 10.11743/ogg20230608 Abstract （128）   HTML （6）    PDF（pc） （5526KB）（184）       Knowledge map    Save Deep shale gas reservoirs are vital for the future development of China’s natural gas industry. Presently， China has achieved preliminary industrial exploitation in this regard， as evidenced by the successful drilling of several high-yielding wells， the delineation of the second gas production growing area with estimated gas-in-place of around one trillion cubic meters and gas production of around ten billion cubic meters， and innovative breakthroughs in research on shale gas enrichment pattern together with exploration and exploitation technologies. These have facilitated the large-scale， effective shale gas production growth in China. Meanwhile， the United States has achieved industrial exploitation of four major deep shale gas blocks， leading to constant rise of the shale gas production from deep reservoirs reaching 313.2×109 m3 in 2021， which accounts for up to 41 % of its total natural gas production. Through systematical summary， we determine six major shale gas enrichment characteristics for deep marine reservoirs： （1） deepwater shelf deposits in a strong reducing environment， which are favorable for organic matter enrichment and preservation； （2） high-quality reservoirs with stable thicknesses and a continuous distribution in large scale； （3） prevalent ultra-high pressure with good sealing capacity of faults； （4） well-developed organic pores and fractures， resulting in favorable reservoir physical properties； （5） superior gas-bearing property of deep shales where shale gas resources are available； and （6） a high proportion of free gas in deep shales， leading to high single-well production in the initial stage. Despite these characteristics as well as advancements in the exploration and exploitation of deep shale gas reservoirs in China， three challenges are posed in the study along with corresponding countermeasures for profitable shale gas extraction from deep reservoirs. Prospects show that deep marine shale gas reservoirs in the Sichuan Basin hold discovered shale gas in place of （3～5）×1012 m3， suggesting potential gas production growth of （30～50）×109 m3. It is suggested to persist in tackling key problems， and accurately build a “transparent geological body” for shale reservoirs by adhering to the philosophy of maximizing producing reserves. Furthermore， we should focus on the optimal engineering techniques and production systems to maximize single-well estimated ultimate recovery （EUR）， to continually reduce exploitation costs and consistently surpass current shale gas production limits， with the ultimate purpose of driving further progress in China’s shale gas industry. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Geology of shales in prolific shale-oil well BYP5 in the Jiyang Depression， Bohai Bay Basin Huimin LIU, Zheng LI, Youshu BAO, Shouchun ZHANG, Weiqing WANG, Lianbo WU, Yong WANG, Rifang ZHU, Zhengwei FANG, Shun ZHANG, Peng LIU, Min WANG Oil & Gas Geology    2023, 44 (6): 1405-1417.   DOI: 10.11743/ogg20230606 Abstract （110）   HTML （8）    PDF（pc） （7497KB）（182）       Knowledge map    Save Shales in the lower sub-member of the 3rd member of the Paleogene Shahejie Formation （Es3l section） in prolific shale-oil well BYP5 in the Jiyang Depression are of typical carbonate-rich type with high maturity. Research on their geological characteristics is of analogy and reference significance for the exploration of similar shales. We delve into the basic characteristics of these shales in terms of mineral composition， thin layer structure， hydrocarbon-generating condition， hydrocarbon fluid property， and reservoir space type. Based on the anomalies of geochemical parameters， we discuss the micro-migration adjustment and accumulation mechanism of shale oil， determine the lower limit of the oil saturation index （OSI）， total organic carbon （TOC） content， and porosity for shale oil mobility. Therefore， the geological conditions favorable for high shale oil production are concluded. As revealed by this study， shales in the Es3l section in well BYP5 is predominantly of carbonate-rich type， characterized by thin layer structure dominated by argillaceous and micritic calcite thin layers. With TOC content ranging from 0.58 % to 7.98 % （average： 4.52 %） and Type Ⅰ organic matter predominating， the shales in the study area are at the stage of light oil and condensate gas generation. With porosity between 2.2 % and 6.9 % （average： 3.22 %）， the dominant storage spaces are matrix pores， followed by inter-layer and cross-cutting fractures. The lower limit of the shales’ OSI for oil prodution is less than 50 mg/g， while that of their TOC content and porosity for oil prodution is 1 % and 2.2 %， respectively. The geological conditions favorable for high shale oil production are as follows： （1） High organic matter abundance and high hydrocarbon-generating potential as a result serve to lay a solid material foundation for oil enrichment and flow； （2） High hydrocarbon mobility significantly reduces the lower limit of effective reservoir properties for hydrocarbon storage； （3） Abnormally high pressures provide sufficient natural energy for oil production； （4） The lamellar/layered structures of shales determine the high efficiency of hydrocarbon generation， storage， and permeability of the reservoir； （5） Multiple types of fractures like inter-layer and cross-cutting fractures can effectively connect matrix pores on both sides of the fractures， facilitating the oil recovery from the matrix pores. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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Development model and significance of favorable lithofacies association of sandy braided river facies of the Cretaceous Bashijiqike Formation in Zhongqiu 1 well block， Kuqa Depression， Tarim Basin Zhiyong GAO, Yongping WU, Zhaolong LIU, Cong WEI, Yongzhong ZHANG, Cuili WANG, Qunming LIU Oil & Gas Geology    2023, 44 (5): 1141-1158.   DOI: 10.11743/ogg20230506 Abstract （101）   HTML （15）    PDF（pc） （7764KB）（181）       Knowledge map    Save The deep Cretaceous Bashijiqike Formation in well Zhongqiu 1 in the Kuqa Depression tested high flow rate of natural gas. However， due to the small number of wells， large burial depth， and strong reservoir heterogeneity， it is difficult to evaluate the favorable reservoirs in the area and analyze the control factors of differential well productivity. Based on the isochronous characteristics of flood surface， we establish an isochronous stratigraphic framework of Bashijiqike Formation through the analysis of core sedimentary facies and identification of facies markers. The evolution process of progradation （lake level descending） of braided river delta front， plain， and alluvial plain braided river is established from bottom to top in the three internal sedimentary units. In Zhongqiu 1 well block， the reservoir intervals showing productivity difference occur in the upper Ba 2 Member and Ba 1 Member which are mainly deposited in the sandy braided rivers on alluvial plain above the maximum flooding surface， and the main river channel has been in different positions in different periods during their deposition. Taking into account factors such as sedimentary microfacies， coarse and fine structure of detrital particles， pore types and characteristics， porosity and permeability data， and fracture intensity， the sandy braided river sedimentary bodies of the Bashijiqike Formation can be divided into nine types in terms of lithofacies combination， with the differences in sedimentary microfacies serving as the basis， and types I—V being favorable lithofacies combinations. A favorable lithofacies combination development model is built for the sandy braided river facies of the Bashijiqike Formation in the Zhongqiu 1 well block. The proportion of favorable lithofacies combinations in this area featuring high in the east and low in the west， serves to determine the differences in gas bearing properties. It is predicted that the SN-trending area between the eastern line across wells Zhongqiu 101， Zhongqiu 1， and Zhongqiu 104 and the western line across wells Zhongqiu 102 and Zhongqiu 2， is favorable for the development of large-scale effective reservoir， especially on the north and northeast sides. Table and Figures | Reference | Related Articles | Metrics | Comments（0）

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The influence of hydrothermal activities on shale oil reservoirs during the burial period of the Upper Triassic Chang 7 Member， Ordos Basin Ziyi WANG, Jinhua FU, Xianyang LIU, Shixiang LI, Changhu ZHANG, Xinping LIANG, Lin DONG Oil & Gas Geology    2023, 44 (4): 899-909.   DOI: 10.11743/ogg20230408 Abstract （116）   HTML （7）    PDF（pc） （3600KB）（181）       Knowledge map    Save 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%Ro 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 （Ro = 0.70 %）. Table and Figures | Reference | Related Articles | Metrics | Comments（0）