Table of Content

01 December 2023, Volume 44 Issue 6

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Petroleum Geology

Mechanisms for lacustrine shale oil enrichment in Chinese sedimentary basins

Xusheng GUO, Xiaoxiao MA, Maowen LI, Menhui QIAN, Zongquan HU

2023, 44(6):  1333-1349.  doi:10.11743/ogg20230601

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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 1^st member of the Upper Cretaceous Qingshankou Formation （K₂qn¹ section） in the Songliao Basin and the 7^th 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.

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

2023, 44(6):  1350-1365.  doi:10.11743/ogg20230602

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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.

Shale oil resource potential in the Bohai Sea area

Lijun MI, Jianyong XU, Wei LI

2023, 44(6):  1366-1377.  doi:10.11743/ogg20230603

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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 3^rd and 1^st members of the Shahejie Formation and the 3^rd 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.

Difficulties and countermeasures for fracturing of various shale gas reservoirs in the Sichuan Basin

Guangfu WANG, Fengxia LI, Haibo WANG, Tong ZHOU, Yaxiong ZHANG, Ruyue WANG, Ning LI, Yuxin CHEN, Xiaofei XIONG

2023, 44(6):  1378-1392.  doi:10.11743/ogg20230604

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The Sichuan Basin and its periphery are rich in shale gas resources. However， diverse sedimentary facies and intricate structures result in significant variations in shale gas productivity across shale gas wells during fracturing tests. Consequently， some fracturing techniques that are effective in high-productivity wells may be subjected to limited popularization. Therefore， there is an urgent need to develop specialized fracturing schemes for different types shale gas. To achieve efficient shale gas recovery， we compare the geological and engineering parameters of blocks with proven shale gas reserves within the Sichuan Basin. These parameters， along with the sedimentary facies types， lithofacies assemblages， burial depths， and pressure systems， are used to classify the shale gas into six types： marine overpressured type of medium-shallow burial depth （burial depth less than 3 500 m）， deep overpressured marine type （burial depth more than 3 500 m）， deep normally pressured marine type， new marine type， deep overpressured type of transition from continental to marine sedimentation， and overpressured continental type of medium-shallow burial depth. Our findings， obtained from numerical simulations and experiments， are as follows： （1） Natural fractures and complex in-situ stress distributions cause uneven fracture propagation and merging. Optimizing perforation parameters and employing the temporary plugging technique can effectively control fracture morphologies and enhance stimulated reservoir volume （SRV）； （2） Interlayers and laminae affect vertical fracture height growth， as well as the proppant migration and placement morphology. Increasing the amount of preflush of high viscosity for fracturing and small-particle-size proppant， is conducive to the fracture longitudinal penetration layers and balanced proppant support； （3） Strong hydration of shales with high clay content can lead to the deterioration of shale mechanical properties and exacerbation of proppant embedment， while optimizing the type and dosage of additives in fracturing fluid systems can inhibit shale hydration. We formulate the optimal design principles and techniques for volume fracturing of horizontal wells in various shale gas reservoirs. The methodology has been successfully applied to the development of deep high-pressure shale gas reservoirs with complex tectonic stress field in the Dingshan block， deep normally pressured shale gas reservoirs in the Lintanchang block， the new-type shale gas reservoirs in marine clastic rocks in the Jingyan-Qianwei block， the shale gas reservoirs of the marine-continental transitional facies in the Dalong Formation in Puguang area， and lacustrine shale gas reservoirs in the Qianfoya Formation， resulting in significant improvement in single well productivity. This study provides valuable experience and reference for efficient fracturing and commercial exploitation of various complex shale gas reservoirs.

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

2023, 44(6):  1393-1404.  doi:10.11743/ogg20230605

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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.

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

2023, 44(6):  1405-1417.  doi:10.11743/ogg20230606

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Shales in the lower sub-member of the 3^rd member of the Paleogene Shahejie Formation （Es^3l 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 Es^3l 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.

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

2023, 44(6):  1418-1429.  doi:10.11743/ogg20230607

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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.

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

2023, 44(6):  1430-1441.  doi:10.11743/ogg20230608

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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.

Molecular dynamics simulation of shale oil adsorption in kerogen and its implications

Min WANG, Changqi YU, Junsheng FEI, Jinbu LI, Yuchen ZHANG, Yu YAN, Yan WU, Shangde DONG, Yulong TANG

2023, 44(6):  1442-1452.  doi:10.11743/ogg20230609

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Investigating the adsorption behavior in organic matter and its associated pores holds critical significance for revealing the occurrence states and mechanisms of shale oil. Differing from the previous method of replacing the organic matter model with the graphene model， a realistic kerogen molecular model， the Type Ⅱ-C model， is employed to simulate the adsorption behavior of multi-component shale oil within organic pores based on the general Amber force field （GAFF）. The results are as follows. （1） Unlike graphene， which can only be used to simulate surface adsorption， kerogen has the dual functions of both adsorption and absorption. Competitive shale oil adsorption transpires on kerogen walls， dominated by the adsorption of polarity and heavy components， while the kerogen skeleton is characterized by absorption of small molecules moving far away. The shale oil adsorption on the surface and absorption in the skeleton with migration are influenced by the interaction energy between shale oil and kerogen， as well as the molecular size. Specifically， heavy components of shale oil are subjected to strong adsorption but weak absorption， while its light components undergo weak adsorption but strong absorption； （2） The absorption of shale oil components leads to the deformation of the kerogen skeleton and pores， manifested as the formation of new pores and the expansion and partial collapse of original pores. The plasticity of kerogen plays a significant role in its shale oil absorption and further skeleton swelling. Highly plastic kerogen （with low maturity） is more prone to absorb shale oil and swell significantly in skeleton. In contrast， weakly plastic kerogen swells slightly with absorption； （3） An increase in temperature enhances the absorption of aromatic hydrocarbon molecules （like naphthalene） and non-polar molecules （e.g.， formic acid， ethanol， and thiophene） in kerogen skeleton， which reduces the adsorption on kerogen surface， and is conducive to the desorption of saturated hydrocarbon molecules. Additionally， pressure produces insignificant effects on the shale oil adsorption and absorption in kerogen. In this study， the realistic kerogen molecular model is innovatively applied to simulate kerogen’s adsorption and absorption of shale oil components， which is of great help in objectively revealing the shale oil occurrence state and mechanism in kerogen.

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

2023, 44(6):  1453-1467.  doi:10.11743/ogg20230610

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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 （R_o）， 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 R_o 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.

Geological characteristics and exploration of continental fault-block shale oil reservoirs in the Subei Basin

Zhixiong FANG, Qiusheng XIAO, Dianwei ZHANG, Hongliang DUAN

2023, 44(6):  1468-1478.  doi:10.11743/ogg20230611

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Continental faulted basins in eastern China contain multiple suites of significantly thick lacustrine organic-rich shales of the Mesozoic and Cenozoic， thus boasting abundant shale oil resources. However， these organic-rich shales are extensively dissected by faults， resulting in multiple isolated fault blocks. This is a big difference compared with the shale strata in North America in continuous and stable distribution， and poses the challenge to obtain stable commercial oil flow in exploration. Based on the investigation and comprehensive assessment of the lithology， and quality of source rocks and reservoir of shales in the 2^nd member of the Funing Formation （also referred to as the Fu 2 Member） in the Gaoyou Sag， Subei Basin， we hold that three suites of thick target intervals are developed in the Fu 2 Member， which can be explored and exploited as a whole. Given the current geological conditions of the target intervals， faults， and fault blocks in the Fu 2 Member， we propose an idea for fault-block shale oil reservoir exploration， that is， to have long laterals landed within a single or across multiple target intervals within a single or multiple fault blocks. Considering the correlation between fault throw and target interval thickness， we divided the fault-block shale oil reservoirs into three types for exploration， that is， the continuous and stable reservoir， reservoir dissected by micro-faults， and the reservoir spanning multiple fault blocks with multiple sweet spots. It has been verified through practical exploration that all these exploration targets can yield stable commercial oil flow. The study results have expanded the exploration targets and reservoir types for continental shale oil in China， thus serving as a significant reference for shale oil exploration in continental faulted basins.

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

2023, 44(6):  1479-1498.  doi:10.11743/ogg20230612

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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 1^st 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 4^th 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 3^rd sub-member of the 7^th 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.

Types and genesis of horizontal bedding of marine gas-bearing shale and its significance for shale gas： A case study of the Wufeng-Longmaxi shale in southern Sichuan Basin， China

Zhensheng SHI, Shengxian ZHAO, Tianqi ZHOU, Shasha SUN, Yuan YUAN, Chenglin ZHANG, Bo LI, Ling QI

2023, 44(6):  1499-1514.  doi:10.11743/ogg20230613

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Shale has horizontal bedding of diverse origins in differential permeability. An integrated analysis of core data， full-diameter images of enlarged thin section and scanning electron microscope （SEM） images of argon-ion-milled samples， shows that the gas-bearing Wufeng-Longmaxi shale in southern Sichuan Basin develops four types of horizontal bedding， that is， grading type composed of claystone， grading type composed of siltstone and claystone， alternating siltstone and claystone type， and page type. The grading type of claystone constitutes the multi-layer superimposed siltstones in parallel， with siltstone and claystone depositing in graded bedding. The grading type composed of siltstone and claystone is composed of parallelly alternating silty and clayey beds， where the silty beds mainly in clast-supported texture， has abrupt boundary at the bottom and gradual contact with the clayey bed on top， featuring normal grading as a whole. The alternating siltstone and claystone type features abrupt contact between both beds and lamina with no grading. The page type constitutes parallel bedding of very thin clayey lamina with weakly normal grading. The four types of horizontal bedding are of different genesis. The grading type of claystone and grading type of siltstone and claystone are of relatively low-energy turbidite origin， with the former derived from even weaker hydrodynamic conditions； the alternating siltstone and claystone is of contourite origin such as shelf facies； and the page type is of pelagic origin from suspended sediment deposition. The horizontal bedding serves to directly affect shale permeability. The page type is characterized by the abundance of organic matter and organic pores， ranking top in permeability； the alternating siltstone and claystone type takes the second place in permeability with better sorting； while the two grading types come at last in permeability with poor sorting and low organic matter content.

Types， characteristics， and exploration targets of deep shale gas reservoirs in the Wufeng-Longmaxi formations， southeastern Sichuan Basin

Ruikang BIAN, Chuanxiang SUN, Haikuan NIE, Zhujiang LIU, Wei DU, Pei LI, Ruyue WANG

2023, 44(6):  1515-1529.  doi:10.11743/ogg20230614

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The southeastern Sichuan Basin serves as a major region for the exploration of deep shale gas reservoirs in the Wufeng-Longmaxi formations to the Sinopec. Due to the constraints of engineering technology， the current drilling depth has focused on the layers at depth less than 4 500 m， while no substantial exploration breakthroughs have been made in the ultra-deep layers with depth exceeding 4 500 m. The structural type acts as a dominant factor governing the local depth differences of shales in this region. Furthermore， it significantly influences shale gas preservation conditions and the applicability of available engineering technologies. Therefore， determining the structural types of deep shale gas reservoirs therein， as well as the characteristics and the overall depth distribution of various types， can provide critical references for subsequent exploration elevation and exploration well emplacement. In this study， the deep shale gas reservoirs in the study area are classified into four major types in terms of structure： the basin-margin-anticline type， the basin-margin-slope type， the highly-steep-structure type， and the basin-interior-syncline type. We determine the characteristics and target areas of these various types of deep shale gas reservoirs. The most favorable exploration targets concluded include the Yangchungou， western Xinchang， Dingshan， Lintanchang， and Guihua structure of the basin-margin-anticline type， as well as the eastern Xinchang， eastern Dongxi， northern Liangcun， and Yongle-Gulin structure of the basin-margin-slope type. The structural type has a certain control effect on the gas-bearing capacity and production of reservoirs. Structure of the basin-margin-anticline type is the best in terms of both gas-bearing capacity and production， followed by the basin-margin-slope type and the highly-steep-structure type. Moreover， the structural type governs the depth distribution of deep shale， thus indirectly controlling the fracturing performance and resource potential. Deep shale gas layers at depth interval 3 500～4 500 m with a great fracturing performance primarily include those of the basin-margin-anticline and basin-margin-slope types， the resources of which accounts for a relatively small proportion. The ultra-deep reservoirs at depth exceeding 4 500 m are seen in these four types of structures， accounting for a large portion in resources. By combining the structural types， depth segmentation， estimated in-place gas， and engineering technology conditions， it is recommended that the deep shale gas reservoirs in the study area should be explored progressively in three stages： （1） targeting shale gas reservoirs of the basin-margin-anticline and basin-margin-slope types at depth interval 3 500～4 500 m for exploration benefit； （2） targeting shale gas reservoirs of the basin-margin-anticline， basin-margin-slope， and highly-steep-structure types at depth interval 4 500～5 000 m for exploration breakthrough； and （3） targeting shale gas reservoirs of the basin-interior-syncline type at depth interval over 5 000 m for exploration appraisal.

Hyperpycnal flow deposits of the Permian Lucaogou Formation in the Jimusaer Sag and its peripheries， Junggar Basin

Xuan CHEN, Xin TAO, Jianhua QIN, Changfu XU, Yingyan LI, Yuan DENG, Yang GAO, Taiju YIN

2023, 44(6):  1530-1545.  doi:10.11743/ogg20230615

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The sedimentary origin of the Permian Lucaogou Formation reservoirs in the Jimusaer Sag， Junggar Basin has long been a controversial topic. Based on data from outcrop and core observations， logging， and seismic surveys， as well as lab tests of the Lucaogou Formation， we conduct sedimentary analysis， obtaining the following results： （1） The reservoirs of the Permian Lucaogou Formation in the study area are of siltstone/fine-grained sandstone and argillaceous siltstone. They feature well-developed paired graded bedding sequences with internal erosion surfaces， massive bedding， and terrestrial plant fragments， which can be an interpretation of a sedimentary origin of lacustrine hyperpycnal flows； （2） The channel subfacies of hyperpycnal flow deposits consists primarily of massive- and cross-bedding siltstone/fine-grained sandstone， with a single-layer thickness of 0.8～2.8 m， averaging 1.6 m and NMR-derived porosity of 6 %～12 %， averaging 9.5 %. In contrast， the lobe subfacies of hyperpycnal flow deposits predominantly comprises siltstones showing graded bedding and climbing-ripple bedding， with a single-layer thickness of 0.5～1.4 m， averaging 0.9 m and NMR-derived porosity of 3.5 %～7.8 %， averaging 5.2 %； （3） The channel subfacies showing seismic reflections featuring lensoid filling presents a stacking pattern of aggradation with thick laminated accretionary fillings that are in the shape of bands or tongues on the plane， with a lateral width of 1～3 km. In contrast， the lobe subfacies displays draping seismic reflections， the sand bodies of which are of thinly laminated lateral-accretion and progradational bedding in the shape of fan on the plane， with both length and width exceeding 10 km； （4） During the deposition of the Lucaogou Formation， terrigenous clastics and organic matter， carried by frequent flood-induced hyperpycnal flows in the mountainous area of the southern Jimusaer Sag， were rapidly deposited in the sag， forming sandstone reservoirs and high-quality source rocks， and leading to the extensive contact and frequent alternation between the sand bodies of channel and lobe subfacies and the source rocks of hyperpycnal flow deposits of marginal and deep lacustrine facies. Such a sedimentary pattern of lacustrine hyperpycnal flows characterized by the coexistence of coarse- and fine-grained sandstones and paragenetic source rock-reservoir sequences， provides a novel sedimentary interpretation on the origin of high-quality shale oil reservoirs in the Jimusaer Sag.

Characteristics and helium-generating potential of helium source rocks in the Ordos Basin

Chenglin LIU, Zhengang DING, Jianfa CHEN, Liyong FAN, Rui KANG, Haidong WANG, Sijie HONG, Anqi TIAN, Xueyong CHEN

2023, 44(6):  1546-1554.  doi:10.11743/ogg20230616

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Helium sources act as the primary element in generating helium resources. Potential helium source rocks encompass basement metamorphic rocks and various sedimentary rocks， such as mudstone， argillaceous dolomite， coal， and bauxite， in basins. Based on field geological surveys， gravity-magnetic data interpretation， core description， and major- and trace-element analyses， we investigate five suites of potential helium source rocks of two categories in the Ordos Basin and their helium-generating potential. The results show that two categories of potential helium source rocks， namely basement metamorphic rocks and sedimentary rocks， are developed in the studied basin. The helium source rocks of the basement type are found in the Archean land block and the superimposed Paleoproterozoic strata， dominated by high-grade metamorphic gneiss， granulite， marble， migmatite， and granitic gneiss， with average abundances of U and Th of 3.15×10^-6 and 12.38×10^-6， respectively， and a helium-generating intensity of 0.735×10^-6 cm³/（a·g）. On the other hand， the helium source rocks of the sedimentary type are primarily found in Changchengian metasedimentary rocks of the Mesoproterozoic strata and the Paleozoic sedimentary rocks. The Changchengian black slate is widely seen in the northern and southwestern Ordos Basin， and exhibits average abundances of U and Th of 2.36×10^-6 and 8.28×10^-6， respectively， and a helium-generating intensity of 0.522×10^-6 cm³/（a·g）. The argillaceous dolomite in the Lower Ordovician Majiagou Formation of the Lower Paleozoic strata， found in the central and eastern Ordos Basin， displays average abundances of U and Th of 1.71×10^-6 and 9.80×10^-6， respectively， and a helium-generating intensity of 0.487×10^-6 cm³/（a·g）. The Carboniferous-Permian mudstones and coals of the Upper Paleozoic strata are extensively distributed throughout the Ordos Basin. The Taiyuan Formation mudstones， among others， show average abundances of U and Th of 9.69×10^-6 and 22.68×10^-6， respectively， and a helium-generating intensity of 1.82×10^-6 cm³/（a·g）， while its coals exhibit average abundances of U and Th of 16.12×10^-6 and 44.13×10^-6， respectively， and a helium-generating intensity of 3.21×10^-6 cm³/（a·g）. The Carboniferous bauxite of the Upper Paleozoic strata， primarily occurring in the eastern and southwestern Ordos Basin， demonstrates average abundances of U and Th of 7.14×10^-6 and 38.57×10^-6， respectively， and a helium-generating intensity of 1.97×10^-6 cm³/（a·g）. Various helium source rocks are discovered in the southwestern Ordos Basin， suggesting a multi-source helium supply. Overall， this study lays the foundation for helium resource exploration in the Ordos Basin.

Hydrocarbon accumulation conditions and exploration targets of the Triassic subsalt ultra-deep sequences in the western Sichuan Depression， Sichuan Basin

Shuangjian LI, Zhi LI, Lei ZHANG, Yingqiang LI, Xianwu MENG, Haijun WANG

2023, 44(6):  1555-1567.  doi:10.11743/ogg20230617

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The Triassic subsalt marine sequences in the western Sichuan Depression， with burial depths generally exceeding 7 000 m， have been subjected to limited oil and gas exploration. Nonetheless， these sequences boast superior conditions for hydrocarbon accumulation， showing great exploration potential. Based on the latest drilling and seismic data， we conduct a comprehensive analysis of the ultra-deep source rocks， reservoirs， and structural deformation styles， as well as their effect on dynamic hydrocarbon accumulation in the western Sichuan Depression. Accordingly， we delineate favorable exploration targets in the depression. The key findings of this study are as follows： （1） Three suites of regional source rocks， namely the Lower Cambrian Qiongzhusi Formation， the Middle Permian Maokou Formation and the Upper Permian Longtan Formation， are developed in the ultra-deep layers of the western Sichuan Depression. Three suites exhibit hydrocarbon-generating intensities exceeding 2.0×10⁹ m³/km²， enabling the western Sichuan Depression to have the resource potential to form large- or medium-sized oil and gas fields； （2） The depression hosts the platform-margin mound shoals of the Sinian Dengying Formation and the grain shoal dolomite reservoirs of the Permian Qixia and Maokou formations， which are influenced by high-energy facies tracts and multi-stage karstification. All these lay the foundation for the formation of large-scale reservoirs； （3） Subsalt， parautochthonous anticline structures are developed in the footwall of nappes in the piedmont zone. Meanwhile， highly-steep faults and strike-slip transpressional structures are found in the piedmont depressed zone. All these structures act as favorable traps for hydrocarbon accumulation； （4） The piedmont buried structures and the tectono-lithologic composite traps within the depression were both formed during the Indosinian， matching well with the main hydrocarbon-generating period of the Cambrian source rocks and the basement fault activity， suggesting favorable conditions for early hydrocarbon accumulation. As revealed by a comprehensive assessment， favorable targets for future oil and gas exploration in the western Sichuan Depression include the platform-margin zone of the Sinian Dengying Formation and the Permian high-energy facies tracts connected to highly-steep basement faults in the depression， as well as the autochthonous structures in the footwall of nappes in the piedmont zone.

Pressure evolution of gas-bearing systems in the Upper Paleozoic tight reservoirs at the eastern margin of the Ordos Basin

Yong LI, Zhitong ZHU, Peng WU, Chenzhou SHEN, Jixian GAO

2023, 44(6):  1568-1581.  doi:10.11743/ogg20230618

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Multiple tight gas reservoirs are well developed in the Upper Paleozoic sequences at the eastern margin of the Ordos Basin. An accurate understanding of the pressure evolution process of gas reservoirs will be of guiding value to gaining more insights into tight gas accumulation and achieving high and stable gas production in this region. In this study， drilling， logging， and core fluid inclusion test data， as well as simulations of burial and thermal evolution histories are integrated to reveal the pressure evolution of the Upper Paleozoic gas-bearing systems at the eastern margin of the Ordos Basin. The results show that reservoirs in the study area exhibit underpressure， slightly underpressure， and normal pressure systems from bottom to top. The homogenization temperature and salinity of fluid inclusions exhibit continuous distributions overall， suggesting a continuous hydrocarbon charging process. The Taiyuan， Shanxi， and Lower Shihezi formations demonstrate a positive correlation between the homogenization temperature and salinity of fluid inclusions， suggesting a rapid hydrocarbon charging process following near-source hydrocarbon generation. In contrast， the Upper Shihezi and Shiqianfeng formations exhibit a negative correlation between the homogenization temperature and salinity due to the long-distance fluid migration and charging， as well as the rebalancing of fluid inclusions in gas reservoirs under the influence of the Zijinshan tectono-thermal event. During the Mid-Cretaceous， the study area experienced the generation of large quantities of hydrocarbons， leading to the anomalously high reservoir pressure ranging from 34.89 ~ 38.26 MPa， followed by a decrease at later stages under the uplifting of strata. For the pressure drop， 50.31 % ~ 57.85 % was caused by the decline in formation temperature， 28.25 % ~ 41.95 % by natural gas swelling-induced gas migration （predominantly in upper strata）， and 0.37 % ~ 0.79 % by pore rebound. The findings of this study systematically reveal the pressure system evolution of the Upper Paleozoic tight gas reservoirs in the Ordos Basin and the origin of the current reservoir pressure formation. These will be of referential value to understanding the enrichment and accumulation patterns of tight gas in the Ordos Basin and the like.

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

2023, 44(6):  1582-1594.  doi:10.11743/ogg20230619

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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.

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

2023, 44(6):  1595-1608.  doi:10.11743/ogg20230620

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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.