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29 October 2025, Volume 46 Issue 5

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Petroleum Geology

Geological conditions for tight oil enrichment and its exploration potential of gravity-flow deposits from the 7th to 9th oil groups of the Triassic Yanchang Formation， Ordos Basin： Discussion on the petroleum exploration paradigms of downwarped lacustrine basins

Jingzhou ZHAO, Zhendong GAO, Xuangang MENG, Weitao WU, Yubin BAI, Lei CAO, Zilong ZHAO

2025, 46(5):  1367-1391.  doi:10.11743/ogg20250501

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The lower oil play， namely the 7th to 10th oil groups， of the Yanchang Formation in the Dingbian-Wuqi-Zhidan-Ganquan-Fuxian area of northern Shaanxi within the Ordos Basin， has emerged as a key target for the exploration of the Yanchang oilfield in recent years. In this study， we investigate this oil play by integrating observations of approximately 2 115 meters of cores from 125 wells， grain-size data from more than 400 wells， and a systematic analysis of logging facies. The results indicate that gravity-flow deposits are widely distributed across the 7th to 9th oil groups of the Yanchang Formation （also referred to as the Chang 7‒9 oil groups） in the study area. These deposits are dominated by sandy debris-flow deposits， followed by turbidity-current deposits. The gravity-flow deposits exhibit excellent source rock-reservoir-cap rock conditions and hold great potential for tight oil exploration， with possible petroleum initially-in-place （PIIP） estimated at about 2.5 × 10⁹ t. The type of source rock-reservoir-seal assemblages is identified as a major factor controlling the accumulation and enrichment of tight oil in the Chang 7‒9 oil groups in the study area， and theses assemblages therein can be classified into four categories with a total of 11 specific types. The configurations featuring reservoir interbedded with source rocks and vertically-stacked source and reservoir， among others， represent two most favorable assemblage categories for tight oil accumulation. Moreover， new evaluation criteria for source rocks of the Yanchang Formation in the Ordos Basin are established. These criteria highlight the predominance of excellent source rocks across the Chang 7‒9 oil groups in the study area. Within this interval， the Chang 7 oil group is recognized as containing the most favorable source rocks， followed by the Chang 9 and Chang 8 oil groups. Furthermore， a new sweet spot assessment method is proposed based on the grading of well production， and the analysis of enrichment factor （EF） and associated geological controlling factors. China’s hydrocarbon exploration paradigms are undergoing significant shifts， with a shift from shallow-water deposits to deep-water gravity-flow deposits representing a major trend in the hydrocarbon exploration of downwarped lacustrine basins. Specifically， gravity-flow deposits exhibit favorable hydrocarbon accumulation conditions in downwarped lacustrine basins. Particularly， sandy debris-flow deposits exhibit a larger scale， favorable physical properties， and better oil-bearing properties compared to the turbidity-current deposits， establishing them as a major target for petroleum exploration and exploitation of deep-water gravity-flow deposits.

Enrichment factors and patterns of tight oil in the 8th oil group of the Yanchang Formation， Dingbian-Fuxian area， Ordos Basin

Weitao WU, Tianyu LI, Xinzhi YAN, Kai ZHOU, Lu YIN, Lei CAO

2025, 46(5):  1392-1409.  doi:10.11743/ogg20250502

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Research on tight oil enrichment patterns under the condition of multi-source hydrocarbon supply is a key component of hydrocarbon enrichment theory. This study examines tight oil reservoirs in the 8th oil group of the Yanchang Formation （also referred to as the Chang 8 oil group） in the Dingbian-Fuxian area， Ordos Basin. By integrating data from drilling， well logging， core observations， thin-section observations， geochemical analysis， well tests， and production tests， we systematically evaluate the hydrocarbon generation potential of source rocks including the Zhangjiatan shales of the Chang 7 oil group， Lijiapan shales of the Chang 9 oil group， and the shales of the Chang 8 oil group. Accordingly， the general characteristics of tight oil reservoirs are clarified， the factors for tight oil enrichment in different oil plays are discussed， and thereby corresponding tight oil enrichment patterns are built. The results indicate that the Dingbian-Fuxian area contains three suites of good to excellent source rocks： the Chang 7， Chang 8， and Chang 9 oil groups. The widespread Zhangjiatan shales at the bottom of the Chang 7 oil group， among others， exhibit the greatest hydrocarbon generation potential， with an average total organic carbon （TOC） content of 6.1%. They are followed by the Lijiapan shales at the top of the Chang 9 oil group and shales in the Chang 8 oil group， which have average TOC contents of 5.3% and 3.9%， respectively and are distributed in the Ganquan-Fuxian-Zhidan area. Reservoirs in the Chang 8 oil group are dominated by fine-grained sandstones and siltstones， with measured peak porosity ranging from 4% to 12% （average： 7.9%） and measured permeability from 0.10 × 10⁻³ μm² to 0.40 × 10⁻³ μm² （median： 0.26 × 10⁻³ μm²）， establishing them as tight reservoirs. The tight-sandstone oil reservoirs in the area mostly show lenticular， zonal， and clustered distributions and are characterized by quasi-continuous accumulation. Shale tight oil enrichment in oil reservoirs in the 1st oil sub-group of the Chang 8 oil group （also referred to as the Chang 8¹ oil sub-group） is primarily controlled by the properties of the Chang 7³ oil sub-group， including the hydrocarbon supply capacity of source rocks， the thickness of the thin mudstones between source rocks and reservoirs， and the sealing performance of the strong floor. In the Chang 8¹ oil sub-group， the single-source direct oil play in the Chang 7³ oil sub-group， characterized by the configuration of upper source rocks and lower reservoirs， proves the most favorable， followed by the dual-source oil plays in the Chang 7³ and 8² oil sub-groups， where reservoirs are sandwiched between source rocks. In contrast， the dual-source oil plays in the Chang 7³ and 9¹ oil sub-groups， also characterized by reservoirs sandwiched between source rocks， represents the least favorable oil plays. Shale tight oil enrichment in the Chang 8² oil sub-group largely relies on the properties of the Chang 9¹ oil sub-group， including the hydrocarbon supply of source rocks， high-quality reservoir conditions， and the sealing performance of cap rocks. Within this oil sub-group， the single-source direct oil play in the Chang 9¹ oil sub-group， characterized by the configuration of upper reservoirs and lower source rocks， proves the most favorable. It is followed by the dual-source oil plays in the Chang 9¹ and 8² oil sub-groups， where reservoirs are again sandwiched between source rocks. Three distinct tight oil enrichment patterns are identified in the oil reservoirs of the Chang 8 oil group： （1） efficient enrichment pattern in the Chang 8¹ oil sub-group in the Dingbian-Wuqi area， driven by strong hydrocarbon supply from source rocks and high sealing performance； （2） complementary enrichment pattern in the Chang 8² oil sub-group in the Ganquan-Fuxian area， marked by the combination of excellent source rocks， high-quality reservoirs and cap rocks； and （3） synergistic enrichment pattern in the Chang 8 oil group in the Zhidan area， characterized by multiple hydrocarbon sources and high-quality reservoirs. This study aims to facilitate the efficient development and exploitation of tight oil in the Chang 8 oil group while advancing the tight oil enrichment theory.

Geochemical characteristics， distribution， and shale oil resource potential of source rocks in the 8th and 9th oil groups of the Yanchang Formation， northern Shaanxi， Ordos Basin

Lei CAO, Xinzhi YAN, Hui LI, Weitao WU, Yubin BAI, Zilong ZHAO

2025, 46(5):  1410-1429.  doi:10.11743/ogg20250503

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Using data from core observations， geochemical analysis， logging， crude oil physical properties， and well tests， we investigate the geochemical characteristics and spatial distribution of hydrocarbon source rocks in the 8th and 9th oil groups of the Yanchang Formation （also referred to as the Chang 8 and Chang 9 oil groups， respectively） in northern Shaanxi， Ordos Basin. The implications of tight oil accumulation within the lower hydrocarbon play of the Yanchang Formation in the study area are explored， and shale oil resources in the area are calculated. The results indicate that the silty mudstones， mudstones， and shales of the Chang 8 and Chang 9 oil groups contain total organic carbon （TOC） content ranging from 1.0% to 16.0% （average： 4.8%）， suggesting that they represent source rocks with organic matter abundance of good to excellent level. The kerogen of the source rocks exhibits type index （TI） values ranging from 47 to 92 （average： 70） and δ¹³C_kerogen values from -25.9‰ to -29.8‰ （average： -27.8‰）， indicating a predominance of type Ⅱ₁ kerogen. The source rocks show peak hydrocarbon pyrolysis temperature （T_max） ranging from 444 ℃ to 470 ℃ （average： 456 ℃） and R_o values from 0.72% to 1.56% （average： 1.16%）， indicating that the organic matter is primarily in the mature to highly mature stage. Effective source rocks with TOC content > 1.0% and R_o values > 0.70% are identified across all oil sub-groups of the Chang 8 and Chang 9 oil groups. Among them， the Lijiapan shale of the Chang 9 oil group represents the most favorable source rocks， followed by shales of the 2nd and 1st oil sub-groups of the Chang 8 oil group （also referred to as the Chang 8² and Chang 8¹ oil sub-groups， respectively）， as well as the Chang 9 oil group. The Lijiapan shale of the Chang 9 oil group thickens progressively from Dingbian to Ganquan， with thicknesses ranging from 4.0 m to 17.0 m （average： 7.5 m）. Its primary depocenters are located in Ganquan and southern Ansai， where zones with shale thicknesses exceeding 10.0 m cover an area of approximately 3 574 km². In the Ganquan area， the Lijiapan shale of the Chang 9 oil group shows a thickness of up to a maximum of more than 35.0 m. The source rocks of the Chang 8 oil group are extensively developed in the Zhidan， Ganquan， and Fuxian areas， with those of the Chang 8¹ and Chang 8² oil sub-groups showing maximum single-layer continuous thicknesses exceeding 10.0 m and 30.0 m， respectively. Vertically， four types of source rock assemblages are identified within the lower hydrocarbon play of the Yanchang Formation： the Zhangjiatan shale （type A）， the Zhangjiatan shale + the Lijiapan shale （type B）， the Zhangjiatan shale + source rocks at the base of the Chang 8₂ oil sub-group + the Lijiapan shale （type C）， and the Zhangjiatan shale + source rocks in the middle Chang 8 oil group + the Lijiapan shale （type D）. Since source rocks act as both oil source rocks and cap rocks， the tight oil reservoirs of the Chang 8 oil group with source rock assemblages of types B， C， and D manifest favorable oil sources and strong sealing performance， which contribute to high tested oil production rates. Effective source rocks are further subdivided based on the oil saturation index （OSI） values， free hydrocarbon content （S₁）， chloroform bitumen “A” content， saturated hydrocarbon content， and aromatic hydrocarbon content of source rocks， as well as experience in the exploration and exploitation of the Gulong shale oil in the Daqing oilfield and international analogues. Specifically， effective source rocks with OSI values of greater than 100 mg/g， 70 ~ 100 mg/g， and less than 70 mg/g are categorized as resources with readily movable （class Ⅰ）， potentially movable （class Ⅱ）， and hardly movable （class Ⅲ） shale oil， respectively. Silty mudstones are found bearing class Ⅰ shale oil due to their high hydrocarbon generation capacity and better reservoir spaces than mudstones and shales. The classes Ⅰ， Ⅱ， and Ⅲ shale oil resources in the study area are calculated at 0.38 × 10⁹ t， 0.75 × 10⁹ t， and 2.95 × 10⁹ t， respectively.

Impacts of terrigenous inputs on organic matter type： A case study of shales in the Chang 7³ oil sub-group of the Triassic Yanchang Formation， Ordos Basin

Chuang ER, Hongbo GUAN, Wei LIU, Ni CHENG, Jie BAI, Chong HU

2025, 46(5):  1430-1445.  doi:10.11743/ogg20250504

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This study aims to explore the impacts of terrigenous inputs on the organic matter type of semi-deep- to deep-lacustrine shales. Focusing on shales in the 3rd sub-group of the 7th oil group of the Triassic Yanchang Formation （also referred to as the Chang 7³ oil sub-group） in the Ordos Basin， we conduct comprehensive petrological， sedimentological， and geochemical analyses on core samples from four wells located in the northeastern， northwestern， and southwestern parts of the lacustrine basin during the deposition of the Yanchang Formation. Accordingly， the impacts of terrigenous inputs on the organic matter type are delved into. The results indicate that the samples involved are all rich in organic matter， with maturities ranging from 0.91% to 1.03%， suggesting medium to low maturity. The organic matter comprises types Ⅱ₁ and Ⅱ₂ kerogens， with kerogen macerals dominated by sapropelinite， followed by vitrinite. Notably， maceral types differ greatly across different wells. Shales in the Chang 7³ oil sub-group comprise seven lithofacies types： layered shale， shale with discontinuous to continuous laminae， silt-bearing shale with massive-discontinuous laminae， silty shale with massive-discontinuous laminae， layered silty shale， laminated silty shale， and massive silty shale. The layered shale， among others， is the least affected by terrigenous inputs， whereas the last four lithofacies are strongly affected. Shales from well W336 are weakly influenced by terrigenous clastic inputs. Correspondingly， type Ⅱ₁ kerogen occurs in this well， with macerals dominated by sapropelinite （with a content of 64% ~ 83%）. In contrast， shales from the other three wells are more strongly affected by terrigenous clastic inputs. In these wells， type Ⅱ₂ kerogen predominates， with vitrinite content ranging from 15% to 42%. Despite the strong influence of terrigenous inputs， the parent materials of organic matter in the semi-deep to deep lacustrine environment remain dominated by aquatic organisms， producing favorable organic matter types. However， in the anoxic bottom water， higher plant debris accompanied by terrigenous inputs such as quartz and feldspar coexist with algae， leading to the formation of mixed type Ⅱ₁-Ⅱ₂ kerogen and comparatively less favorable organic matter types.

Origin and distribution of deep-water gravity-flow tight-sand reservoirs in the oil layer group of the 7th member of the Yanchang Formation， Fuxian area， Ordos Basin

Jun ZHANG, Yubin BAI, Hai ZHANG, Jingzhou ZHAO, Ning XU

2025, 46(5):  1446-1465.  doi:10.11743/ogg20250505

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Deep-water gravity flow reservoirs are widely distributed in the oil layer group of the 7th member of the Yanchang Formation （also referred to as the Chang 7 oil layer group） in the Fuxian area， Ordos Basin. However， the tightening mechanisms of these reservoirs remain unclear. Using test methods and technologies including X-ray diffraction （XRD）， petrophysical analysis， granulometry， casting thin section observation， scanning electron microscopy （SEM）， high-pressure mercury intrusion porosimetry， and oil layer interpretation， we analyze the fundamental characteristics of gravity flow reservoirs in the Chang 7 oil layer group， highlighting the tightening mechanisms and distribution patterns of the reservoirs. The results indicate that the Chang 7 oil layer group consists primarily of fine-grained feldspathic sandstone and lithic feldspathic sandstone， with a porosity ranging from 0.5% to 18.4% （average： 8.44%） and a permeability from 0.01 × 10^-3 µm² to 14.1 × 10^-3 µm² （average： 0.36 × 10^-3 µm²）. Within this member， sandy debris flow reservoirs exhibit the most favorable pore structures and the best physical properties， with an average porosity of 8.94% and a permeability of 0.39 × 10^-3 µm². Slide-slump reservoirs come the second， which have an average porosity of 8.28% and a permeability of 0.40 × 10^-3 µm². In contrast， turbidite reservoirs show the poorest physical properties， with an average porosity of 6.90% and a permeability of 0.28 × 10^-3 µm². The gravity flow reservoirs are poorly sorted and characterized by fine grain sizes， high matrix content， and weak resistance to compaction. Furthermore， these reservoirs exhibit high carbonate cement content， which is identified as the primary reason for reservoir tightening. Week dissolution in the late stage failed to change the overall tightness of reservoirs in the Chang 7 oil layer group. Diagenetic evolution places the Chang 7 Oil layer group in the meso-diagenetic stage A， having undergone a single-phase hydrocarbon charging， with the homogenization temperatures of inclusions ranging primarily from 110 ℃ to 120 ℃. Large-scale hydrocarbon accumulation in this oil layer group occurred during the late Early Cretaceous （105 ~ 120 Ma）. In the Chang 7 oil layer group， high-quality Class Ⅰ reservoirs occur in sandy debris flow deposits. In contrast， moderate Class Ⅱ reservoirs are found in intervals consisting of sandy debris flow and turbidity current deposits， and poor Class Ⅲ reservoirs appear in turbidity current deposits. The comprehensive analysis suggests that the section with sandy debris flow deposits in the 1st and 2nd oil layer sub-groups represent play fairways for the exploration and exploitation of deep-water tight-sand oil reservoirs.

Characteristics and oil-bearing properties of deep-water gravity-flow deposits in the 7th-9th oil groups of the Yanchang Formation， Zhidan area， Ordos Basin

Weitao CHEN, Jingzhou ZHAO, Zhendong GAO, Zhe LI, Xuangang MENG, Xinzhi YAN, Xu Dong

2025, 46(5):  1466-1484.  doi:10.11743/ogg20250506

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Based on the centimeter-scale characterization of cores from 15 cored wells， grain size analyses of 117 sampled wells， observations of thin sections from 11 wells， and production test data from 23 wells， we systematically investigate the characteristics of deep-water gravity-flow deposits in the 7th‒9th oil groups of the Triassic Yanchang Formation （also referred to as the Chang 7‒9 oil groups） in the Zhidan area， Ordos Basin， as well as their controlling effects on hydrocarbon distribution. The results indicate that the study area primarily exhibits three types of deep-water gravity-flow deposits： sandy debris-flow deposits， turbidity current deposits， and slide-slump deposits， with the first type predominating. The sandy debris-flow deposits contain thick-bedded massive sandstones， with rip-up clasts and mud-coated intraclasts observed. They are generally well sorted and rounded， and their grain-size cumulative probability curves show short-tailed two-segment or one-segment patterns with a coarse-skewed distribution， exhibiting slightly coarser grains than those observed in the turbiditic sandstones. The turbidity current deposits feature incomplete Bouma sequences， displaying flame structures， sole marks， and small single-layer sand thicknesses. Their grain-size cumulative probability curves primarily show a fine-skewed one-segment pattern. The slide-slump deposits are typically characterized by the presence of convolute beddings， deformation structures， and synsedimentary stepped faults. Analyses of reservoir properties reveal that the sandy debris-flow deposits generally possess better physical properties than the turbidity current deposits. Furthermore， the oil-bearing grades of the sandy debris-flow deposits are dominated by oil stains to oil immersion， resulting in relatively high oil saturation and high daily oil production during production tests. In contrast， the turbidity current deposits exhibit poorer oil-bearing properties， primarily limited to oil stains to oil traces. These findings suggest that the sandy debris-flow deposits are more favorable to hydrocarbon enrichment and production than the turbidite-flow counterparts. Overall， the comprehensive analysis indicates that within the Chang 7‒9 oil groups， Zhidan area， Ordos Basin， the widely distributed sandy debris-flow deposits represent the most favorable oil-bearing sand body type and should therefore be prioritized as significant targets for future hydrocarbon exploration.

The configuration characteristics of delta and gravity flow sand bodies and their control on reservoir distribution—Chang 7 of Triassic Yanchang Formation in Ganquan area of Ordos Basin Oil layer group as an example

Xiaolong LI, Yubin BAI, Shanshan CHEN, Gang ZHANG, Cong’e WANG

2025, 46(5):  1485-1503.  doi:10.11743/ogg20250507

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The oil layer group of the 7th member of the Yanchang Formation （also referred to as the Chang 7 oil layer group） in the Ganquan area of the Ordos Basin hosts tight oil reservoirs of the delta-front and gravity-flow origin. This study aims to determine the differences in reservoir properties across varying sedimentary architectural units and the mechanisms through which these units control oil reservoir distribution and hydrocarbon enrichment. Using data from core observations， logging， and production performance， we analyze the architectural characteristics， vertical contact relationships， and distribution patterns of individual sand bodies within the deltaic and gravity-flow deposits in the Chang 7 oil layer group and explore the role of sand body architectures in controlling oil reservoir distribution. By combining data from well and production tests， we establish the hydrocarbon accumulation models associated with sand body architectures. The results indicate that the Chang 7 oil layer group contains four primary vertical sand body architecture types： continuously superimposed， intermittently superimposed， thinly interbedded， and single-layer types. Meanwhile， three lateral sand body architecture types are identified in the oil layer group： stable， swinging， and migrating. Vertically， the 1st subgroup of the Chang 7 oil layer group （also referred to as the Chang 7¹ oil layer subgroup） primarily exhibits the continuously superimposed sand body architecture， followed by the intermittently superimposed type. In contrast， the Chang 7² oil layer subgroup is dominated by the intermittently superimposed sand body architecture， succeeded by thinly interbedded type， while the Chang 7³ oil layer subgroup predominantly contains the thinly interbedded and single-layer architectures. Literally， continuously and intermittently superimposed sand body architectures are widely seen in the northern and northeastern parts of the study area. In contrast， thinly interbedded architectures are mainly found in the south-central part of the study area， whereas the single-layer architecture is concentrated in the southern part. Continuously and intermittently superimposed sand bodies exhibit the most favorable reservoir properties， with the continuously superimposed sand bodies yielding the highest hydrocarbon production. Different types of sand body architectures exhibit varying superposition relationships with source rocks， with four types of source rock-reservoir configurations detected in the study area. The continuously superimposed sand bodies in the Chang 7¹ oil layer subgroup， among others， show the highest degree of hydrocarbon enrichment， followed by the intermittently superimposed sand bodies in the Chang 7² oil layer subgroup. The Chang 7³ oil layer subgroup consists primarily of source rocks， while the continuously superimposed sand bodies in the Chang 7¹ oil layer subgroup are identified as the most promising target for future hydrocarbon exploration.

Types of deep-water gravity-flow deposits and comparison of their oil-bearing properties： A case study of the 7th-9th oil groups in the Triassic Yanchang Formation， Fuxian area， Ordos Basin

Linxi WANG, Jingzhou ZHAO, Zhendong GAO, Fanrong WEI, Shiqi ZHOU, Xuangang MENG, Xinzhi YAN, Ning XU

2025, 46(5):  1504-1521.  doi:10.11743/ogg20250508

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In the Fuxian area of the Ordos Basin， the 7th‒9th oil groups in the Triassic Yanchang Formation （also referred to as the Chang 7‒9 oil groups） hold great petroleum resource potential. Previous studies mostly hold that sandstones in these oil groups are dominated by deltaic deposits. Although gravity-flow deposits have been discovered in the Chang 7 oil group in recent years， some issues remain unclear， including their existence and distribution range across the Chang 7‒9 oil groups. Using core observations， grain size analysis， and thin section observations， we identify the primary types of gravity-flow deposits and their distributions， together with the comparison of reservoir characteristics and oil-bearing properties within. The results indicate that gravity-flow deposits are widely distributed across the Chang 7‒9 oil groups in the Fuxian area， including sandy debris-flow deposits， turbidite-flow deposits， and slide-slump deposits. The sandy debris-flow deposits， among others， feature great thicknesses and massive beddings， with rip-up clasts visible. Their grain-size cumulative probability curves exhibit three primary patterns： a coarse-skewed single-segment pattern， a short-tailed two-segment pattern， and a two-segment pattern with high suspended component content. In contrast， the turbidite-flow deposits are thin， with incomplete Bouma sequences observable in cores. Their grain-size cumulative probability curves primarily show a fine-skewed single-segment pattern. In contrast， the slide-slump deposits are characterized by wrinkling deformation， convolute beddings， and stepped faults. The comparison reveals that the sandy debris-flow deposits are generally superior to the turbidite-flow deposits， exhibiting high reservoir quality， favorable oil-bearing properties， and high daily oil production from well tests. Among the widespread gravity-flow deposits in the Chang 7‒9 oil groups in the Fuxian area， the sandy debris-flow deposits show the most extensive distribution， as well as the most favorable reservoir physical properties and oil-bearing properties. Therefore， they should be prioritized as significant targets for future exploration and development of tight oil in the Fuxian area.

Characteristics and mechanisms of deposition under joint action of contour current and gravity flow in the Ordovician Yingtaogou Formation along the western margin of the Ordos Basin

Jize WU, Hua LI, Youbin HE, Chunwei JIANG, Yiming HE, Fengnan YAO, Xiankun ZHANG

2025, 46(5):  1522-1535.  doi:10.11743/ogg20250509

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Based on the analyses of lithologies， paleocurrents， and grain sizes， we investigate the characteristics， formation processes， and controlling factors of deposition under the joint action of contour current and gravity flow. The results indicate the presence of six lithofacies and corresponding four types of sedimentary origins in the study area： （1） silty mudstone （shale） facies， indicative of deep-water autochthonous deposits； （2） calcirudite facies with massive bedding， representing debris flow deposits （debrites）； （3） sandstone facies with graded bedding， reflecting turbidity current deposits （turbidites）； and （4） sandstone facies with wavy bedding， lenticular bedding， and bi-directional cross-bedding， corresponding to the contour current-reworked gravity flow deposits （also referred to as reworked sands）. Among these sedimentary types， the reworked sands exhibit five distinct characteristics. First， the reworked sands exhibit favorable sorting coefficients ranging from 0.63 to 0.70， sub-angular to sub-rounded morphologies， and multiple grain-size subpopulations. Second， paleocurrents moved in the NW and NE directions. Specifically， the turbidity currents moved in the NW direction downward along slopes， while the contour currents moved in the NE direction parallel to slopes. Third， the cumulative probability curves of grain sizes present a pattern of one to three segments， suggesting the characteristics of gravity flow and traction current deposits. Fourth， the grain sizes of sediment decrease gradually from bottom to top， forming normally graded bedding， with scour surfaces developed within layers and erosion extensively occurring at the top. Fifth， a variety of sedimentary structures are identified， typified by wavy bedding， lenticular bedding， and bi-directional cross-bedding. From the bottom up， the study area exhibits sedimentary types of reworked sands， turbidites， reworked sands， and debrites sequentially. In this area， turbidity currents moved in the NW direction northwestward along slopes， while contour currents moved northeastward roughly parallel to slopes. In the case where the turbidity currents have higher energy than the contour currents， turbidites predominate. While when they are equal in strength， the contour currents could transport， modify， and redeposit original sediment （e.g.， turbidites）， leading to the formation of reworked sands. The reworked sands exhibit a porosity of 7.56% and a permeability of 2.1 × 10^-3 µm². In contrast， the turbidites display a porosity of 2.42% and a permeability of 1.74 × 10^-3 µm². Therefore， the reworked sands deliver more favorable reservoir performance than the turbidites. The deep-water autochthonous deposits exhibit favorable source rocks. These deposits are interbedded with reworked sands， forming a source rock-reservoir-cap rock assemblage that facilitates hydrocarbon accumulation and preservation.

Shale lithofacies， differential shale oil occurrence and its microscropic migration and accumulation features in the 3rd sub-group of the 7th oil group of the Triassic Yanchang Formation， Ordos Basin

Yifan ZHANG, Kelai XI, Yingchang CAO, Bo ZHANG, Xiujuan WANG, Yuan YOU, Wenzhong MA, Yuxuan WANG, Qihui SUN

2025, 46(5):  1536-1553.  doi:10.11743/ogg20250510

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The shale lamina type， reservoir space type， and shale oil occurrence state represent major factors influencing the microscopic migration and accumulation of shale oil. This study focuses on shales in the 3rd sub-group of the 7th oil group of the Triassic Yanchang Formation （also referred to as the Chang 7³ oil sub-group） in the Ordos Basin. By integrating a series of qualitative and quantitative analysis methods， including thin section observation， scanning electron microscopy （SEM）， geochemical analysis， advanced mineral identification and classification system （AMICS）， nitrogen （N₂） adsorption experiments， high-pressure mercury intrusion （HPMI）， two-dimensional nuclear magnetic resonance （NMR）， and confocal laser scanning microscopy （CLSM）， we categorize the laminae and micropores in the shales and determine the occurrence states and distribution characteristics of shale oil. Accordingly， the microscopic migration and accumulation process of shale oil is discussed. The results indicate that shales in the Chang 7³ oil sub-group primarily contain four lamina types （organic-rich， tuff-rich， silt-sized felsic， and clay laminae） and three lamina assemblages （organic-rich + silt-sized felsic lamina assemblage， organic-rich + tuff-rich lamina assemblage， and massive mudstones）. These lamina types show significantly different pore types and contents. Specifically， the silt-sized felsic laminae exhibit an average areal porosity of 6.59%， with well-developed feldspar dissolution pores. The tuff-rich laminae have an average areal porosity of 3.50%， which are dominated by intercrystalline pores， with some containing microfractures. Based on the organic matter characteristics and pore-fracture configuration of the laminae， the shale lithofacies of the Chang 7³ oil sub-group are further subdivided into the “organic-rich + tuff-rich” combination （types Ⅰ and Ⅱ） and “organic-rich + silt-sized felsic” combination （type Ⅲ）， with types Ⅰ and Ⅱ differing primarily in fracture density. Type Ⅰ shales feature high oil mobility but moderate oil-bearing properties， with shale oil migration and accumulation occurring within thickly layered shales. In contrast， both types Ⅱ and Ⅲ shales exhibit moderate oil mobility， while type Ⅲ shales present excellent oil-bearing properties. This creates favorable conditions for the shale oil migration from type Ⅱ to type Ⅲ shales in cases when both types occur in vertical contact. Through lamina classification and the fine-scale characterization of reservoir spaces across different lamina types， this study elucidates differential shale oil occurrence patterns and characterizes shale oil migration among various shale lithofacies， providing a foundation for understanding the mechanisms behind the microscopic migration and accumulation of shale oil.

Pore and microfracture characteristics and shale oil exploration prospects of shale reservoirs in the 8th to 9th oil groups of the Triassic Yanchang Formation， Ordos Basin

Jiaqi ZHANG, Jingzhou ZHAO, lei CAO, Qingyuan YE

2025, 46(5):  1554-1581.  doi:10.11743/ogg20250511

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Shales are well-developed in the 8th to 9th oil groups of the Triassic Yanchang Formation （also referred to as the Chang 8‒9 oil groups） in the Ordos Basin. However， their mineral composition and pore and microfracture characteristics， as well as the impacts of these factors on shale oil enrichment and mobility， remain insufficiently understood. In this study， we comprehensively investigate the shale reservoir characteristics and their controlling effects on shale oil in the Chang 8‒9 oil groups using data from a series of analyses and tests， including X-ray diffraction （XRD）， field emission scanning electron microscopy （FE-SEM）， CO₂ adsorption， low-temperature N₂ adsorption， high-pressure mercury injection （HPMI）， and geochemical analyses. The results indicate that the shales in the two oil groups exhibit three lithofacies： felsic clayey shales， clayey felsic shales， and clayey-felsic mixed shales. The Chang 8 oil group is dominated by felsic clayey shales and clayey felsic shales， while all the three lithofacies types are relatively well-developed in the Chang 9 oil group. A comprehensive assessment of pore and microfracture characteristics， fracability， and shale oil mobility reveals that clayey felsic shales are the most favorable lithofacies， followed sequentially by clayey-felsic mixed shales and felsic clayey shales. The shale reservoirs in the two oil groups contain organic pores， intercrystalline pores， intergranular pores， dissolution pores， and microfractures. There are distinct positive correlations between total organic carbon （TOC） content and the volumes of micropores and mesopores. Compared to the Chang 7 oil group， organic pores are less developed in the Chang 8‒9 oil groups. Microfractures are well-developed in both oil groups， primarily including bedding-parallel fractures induced by abnormally high-pressure from hydrocarbon generation， followed by pressure dissolution-induced bedding-parallel fractures and shrinkage fractures in organic matter. Key factors contributing to the development of pores and microfractures in the study area include high TOC content， high organic matter maturity， and high brittle mineral content. Specifically， high TOC content and high organic matter maturity promote the development of organic pores and the formation of bedding-parallel fractures induced by abnormally high-pressure from hydrocarbon generation. In contrast， carbonate cementation inhibits pore development and fills fractures with cements. A high clay mineral content favors micropore development but adversely affects mesopore and macropore growth. Primary factors controlling movable oil enrichment include TOC content （< 4%）， organic matter maturity （vitrinite reflectance （R_o） > 1.2%）， brittle mineral content （> 60%）， and fracture density （> 1.6 × 10⁴/m）. As the assessment criteria for shale oil sweet spots in the study area shown， type Ⅰ sweet spots should have oil saturation index （OSI） values of greater than 100 mg/g， possess the highest shale oil mobility and are primarily distributed in the Fuxian， Ganquan， and eastern Zhidan areas. These areas represent the most favorable shale oil enrichment regions， holding promising exploration prospects. In contrast， type Ⅱ sweet spots are characterized by OSI values ranging from 70 mg/g to 100 mg/g， and exhibit a moderate mobility， while type Ⅲ sweet spots， with OSI values below 70 mg/g， show the lowest mobility. The type Ⅲ shale oil predominates across the study area.

Component characteristics and mobility assessment of shale oil： A case study of the Permian Fengcheng Formation， Mahu Sag， Junggar Basin

Yubin BAI, Haijiao REN, Jun ZHANG, Shaorong CHEN, Weitao WU, Xinmei ZHAO, Heyuan WU, Yang ZOU

2025, 46(5):  1582-1596.  doi:10.11743/ogg20250512

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Continental saline lacustrine basins in China hold considerable potential for mixed-type shale oil resources， exhibiting promising exploration prospects. Determining the component characteristics of the produced oil can lay a foundation for the mobility assessment and production increase of shale oil. In this study， we investigate the mixed shale oil in the Permian Fengcheng Formation， Mahu Sag， Junggar Basin. Through comparison of components in produced oil and residual hydrocarbons， we determine that the shale oil is characterized by component-dependent flow. Furthermore， we explore the relationship between movable oil and produced oil. The results indicate that for shales in the Fengcheng Formation in the Mahu Sag， produced oil exhibits higher hydrocarbon content than residual oil obtained through solvent extraction. With an increase in the time of shale oil recovery， the produced oil shows elevated heavy hydrocarbon content， verifying its component-dependent flow. Gas chromatograms indicate that the saturated hydrocarbons in the produced oil are dominated by n-alkanes with medium to low carbon numbers. Regarding residual hydrocarbons， calcareous/dolomitic shales and mixed shales show a high proportion of saturated hydrocarbon compounds with low carbon numbers， while felsic shales contain relatively well-developed saturated hydrocarbon compounds with medium to high molecular weights. After the light hydrocarbon loss correction and the heavy hydrocarbon recovery by pyrolysis method， in-situ residual hydrocarbon content in the Fengcheng Formation shales is calculated at 1.39 ~ 14.25 mg/g （average： 2.87 mg/g）. The average movable oil content of this formation is estimated at 1.60 mg/g， which accounts for up to 55.8% of the residual hydrocarbons， indicating high mobility of shale oil. The comparison of the movable oil and produced oil from the perspective of molecular geochemistry reveals that the intervals with a high oil saturation index （OSI）， high movable hydrocarbon content， and low total organic carbon （TOC） content hold greater potential for shale oil exploration. This study is significant for the in-depth understanding of the mobility and recoverability of shale oil in saline lacustrine basins and enhancing its production.

Diagenetic fluid system evolution and genesis of deep overpressured tight reservoirs： A case study of the hinterland of the Junggar Basin

Jun LI, Chengzhuo YUAN, Xiaoqing SHANG, Tao WU, Maimaitimin WUERNISAHAN, Chenhang XU, Zeyang XU, Huiyong XU

2025, 46(5):  1597-1613.  doi:10.11743/ogg20250513

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Deep overpressured tight hydrocarbons represent a significant resource type for additions to reserves from reserve growth in the Junggar Basin. This study aims to determine the origin and primary controlling factors of tight reservoirs in the hinterland of the basin. Based on data from laboratory tests of reservoirs， drilling and logging， and well tests， combined with basin simulation results and integrated geological interpretation， we characterize mechanical and chemical compaction processes in the reservoirs and determine the temporal evolution of overpressure development. By examining the formation mechanisms of the semi-closed to closed diagenetic fluid system， we further reveal the genetic mechanisms and primary controlling factors of deep overpressured tight reservoirs in the hinterland of the Junggar Basin. The results indicate that at burial depths ranging from 0 to 2 400 m， the reservoirs are predominantly subjected to mechanical compaction， which induces porosity reduction rates of up to 70% ~ 90% and the formation of a semi-closed to closed diagenetic fluid system. At burial depths of greater than 2 400 m， chemical compaction predominates， with dissolution products mostly precipitating in situ or nearby as cements since their migration is significantly hindered. This results in limited dissolution-induced porosity enhancement in the absence of other constructive diagenetic processes. Overpressure originating from different mechanisms enhances reservoir quality to varying degrees. Specifically， overpressure induced by chemical compaction plays a minor role in preserving primary pores and forming secondary pores. In contrast， overpressure formed by hydrocarbon generation and pressure transmission can intensify dissolution， thereby improving reservoir physical properties. Overall， the degree of openness of the diagenetic fluid system， determined by early-stage mechanical compaction， plays a significant role in controlling the diagenetic evolutionary pathway， the evolutionary pattern of pores， and the formation of high-quality reservoirs （sweet spots） during late-stage deep burial stage.

Pressure distribution prediction and genetic mechanism analysis of the Jurassic undersaturated tight oil reservoirs in an area with differential denudation in the hinterland of the Junggar Basin

Zeyang XU, Jun LI, Tao WU, Jiacheng DANG, Zilong ZHAO

2025, 46(5):  1614-1629.  doi:10.11743/ogg20250514

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In the Mosuowan area of the hinterland of the Junggar Basin， the Jurassic low-saturation tight oil reservoirs display significant spatial variations in overpressure intensity. Investigating the genetic mechanisms and distribution patterns of overpressure under the differential denudation setting in the area holds great significance for understanding the tight oil distribution. In this study， we establish an overpressure prediction model by revising Bowers’ method to incorporate the differential denudation effect. By integrating geophysical data analysis， experimental results， and basin numerical simulations， we establish a quantitative reconstruction method for pressure throughout the whole process from chemical compaction to pressure transfer and then to later-stage tectonic uplift. The results indicate that the new model overcomes the limitations of traditional models， which tend to overestimate the formation pressure in denudation areas， yielding an average prediction error of about 5%. The overpressure origins vary from north to south. In the Mosuowan Uplift， overpressure is primarily attributed to chemical compaction and pressure transfer. In contrast， in the Mobei Uplift， pressure transfer is the dominant mechanism， while in the Shixi Uplift， plastic deformation makes a minor contribution to overpressure. The qualification of the contributions from different origins reveals that in the Mosuowan Uplift and the central and southern Mobei Uplift， where overpressure arises primarily from mixed origins， the contribution ratios of elastic to plastic deformation primarily range from 5∶2 to 2∶1. In contrast， in the Shixi Uplift， plastic deformation contributes far less to overpressure， which is predominantly governed by elastic deformation. Basin simulations reveal that the degree of match between the timing of chemical compaction-induced pressurization and hydrocarbon charging stages directly determines the threshold pressure gradient （TPG） for reservoir fluid flowing. Specifically， chemical compaction-induced pressurization occurred in stages， and the time difference between its onset and hydrocarbon charging stages plays a direct role in determining the TPG. Although the late-stage tectonic uplift inhibited chemical compaction， fault activation facilitated the vertical migration of deep fluids， resulting in a dynamic equilibrium between pressurization and pressure transfer. The spatiotemporal coupling characteristics of overpressure origins reveal the presence of three distinct hydrocarbon accumulation patterns in the Mosuowan area： （1） gas reservoirs predominating with subordinate oil reservoirs in the Mosuowan Uplift， attributed to chemical compaction-induced continuous pressurization； （2） the coexistence of oil and gas reservoirs in the Mobei Uplift， associated with chemical compaction-induced slow pressurization； and （3） oil reservoirs predominating with subordinate gas reservoirs in the Shixi Uplift， corresponding to low-temperature-related weak chemical compaction.

Effects of the fault-sandbody configuration evolution model on differential enrichment of far-source tight sand gas： A case study of the Jurassic Shaximiao Formation， central Sichuan Basin

Mingjie LIU, Hengyu LIU, Yao XIAO, Linke SONG, Jixiang CAO, Tanglyu LI, Jinxi WANG, Chen LIANG

2025, 46(5):  1630-1645.  doi:10.11743/ogg20250515

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This study aims to determine the differential enrichment patterns of far-source tight sand gas in the Jurassic Shaximiao Formation， central Sichuan Basin. By conducting seismic interpretation of source rock-rooted faults， characterizing sand bodies， and reconstructing paleostructures during hydrocarbon accumulation， we analyze the fault-sandbody configuration modes in the Shaximiao Formation both during the hydrocarbon accumulation period and in the present day. Furthermore， the evolutionary model and spatial distribution of the configuration from the hydrocarbon accumulation period to the present are identified. Based on these， as well as the distribution characteristics of current gas producers， we explore the influence of the evolutionary model on differential natural gas enrichment. The results reveal the presence of three distinct modes of fault-sandbody configuration in the Shaximiao Formation， that is， juxtaposition of fault against near-horizontal sandbodies （mode 1）； juxtaposition of fault against gently dipping sandbodies with consistent dip directions （mode 2）； and juxtaposition of fault against gently dipping sandbodies with opposite dip directions （mode 3）. From the hydrocarbon accumulation period to the present， the fault-sandbody configuration modes have experienced three types of evolutionary patterns： inherited （type Ⅰ）， adjusted （type Ⅱ）， and reversed （type Ⅲ）. Specifically， type Ⅰ can be further divided into type Ⅰ₁ （mode 3 persisting both during the hydrocarbon accumulation period and in the present day） and type Ⅰ₂ （mode 1 persisting during both periods）. Type Ⅱ is characterized by a transition from mode 1 during the hydrocarbon accumulation period to mode 3 at present， while type Ⅲ represents a shift from mode 3 during the hydrocarbon accumulation period to mode 2 in the present day. These three types of evolutionary patterns exert different influences on natural gas enrichment. Specifically， the type Ⅰ₁ inherited evolutionary pattern enables natural gas to accumulate primarily in the hanging wall blocks of faults and remain preserved to the present day. Consequently， most gas producers located in these blocks show high or moderate productivity. In this evolutionary pattern， only a small amount of natural gas accumulates in the footwall blocks of faults and remains preserved to date， leading to low productivity in most wells in these blocks. The type Ⅰ₂ inherited evolutionary pattern allows natural gas to accumulate and remain preserved to date primarily in both the hanging wall and footwall blocks， with most gas producers in these blocks showing moderate or low productivity. The type Ⅱ adjusted evolutionary pattern facilitates the accumulation， adjustment， and modification of natural gas in both the hanging wall and footwall blocks. Consequently， natural gas may further accumulate or get enriched in the hanging wall blocks， where gas producers show high， moderate， or low productivity. In contrast， natural gas may escape from the footwall blocks after adjustment， resulting in low or ultra-low productivity in most gas producers in the footwall blocks. The type Ⅲ reversed evolutionary pattern leads to natural gas enrichment in the hanging wall blocks but dissipation to date due to reversal， with only a small amount of natural gas accumulating in the footwall blocks and reaccumulating there to date after reversal. In this pattern， most gas producers in the hanging wall and footwall blocks show low or ultra-low productivity. The Jinqiu block， located in the northern part of the central Sichuan Basin， contains two types of natural gas accumulation： （1） natural gas accumulation in the hanging wall blocks， characterized by inherited preservation and enrichment， under the type Ⅰ₁ inherited evolutionary pattern； and （2） natural gas accumulation in the hanging wall blocks， featuring adjustment， modification， and enrichment， under the type Ⅱ adjusted evolutionary pattern. Therefore， this block be prioritized as a key target area for future exploration of far-source tight sand gas in the Shaximiao Formation.

Exploring the sedimentary evolution processes and hydrodynamic mechanisms of typical mouth bars

Junwei ZHAO, Jian ZHOU, Jianwei ZOU, Haihang SUN, Xiaoli ZHENG, Mingchen ZHANG

2025, 46(5):  1646-1663.  doi:10.11743/ogg20250516

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Mouth-bar sand bodies serve as significant hydrocarbon reservoirs in the deltaic sedimentary system. However， due to the limitations of the dimensions， scales， and resolutions of data on outcrops， modern deposits， and underground reservoirs， the systematic characterization of both the internal sedimentary evolution processes and the architectural characteristics of the mouth-bar sand bodies remains challenging. By integrating sedimentary numerical simulations and modern sediment observations， we analyze the sedimentary evolution of typical mouth bars， reveal their internal architectural patterns， and thoroughly explore the hydrodynamic mathematical models and mechanisms in their development areas. The results indicate that the sedimentary evolution of typical mouth bars can be divided into five stages： vertical aggradation， progradation， lateral aggradation， stabilization， and the formation of composite mouth bars. These mouth bars exhibit varying morphological characteristics across these evolutionary stages， appearing small elongated tongue-shaped， nearly rhombus， triangular or V-shaped， mid-channel bar-shaped， and long ellipse-shaped sequentially. The sedimentary evolution of mouth bars is governed by hydrodynamic variations. The combined action of jets， basin-floor friction， and water buoyancy， results in the formation of varying aggradational styles and diverse planar morphologies of the existing mouth bars. Additionally， variations in hydrodynamic conditions lead to differentiation in the internal architectural patterns of mouth bars. Accordingly， their internal aggradational styles can be classified into vertical aggradation， progradation， and lateral aggradation. For an individual mouth bar， the developmental model of its internal architecture shows spatial differentiation， featuring vertical aggradation-predominated central part， progradation-dominated front end， and lateral draping and aggradation-prevalent side wings. This study provides a theoretical basis for the fine-scale characterization of the internal architectures of mouth bars in fluvial-dominated deltas while also serving as a guide for analyzing the subsurface architectures of mouth-bar reservoirs.

Methods and Technologies

Practices and research for enhanced shale oil recovery in the Qingcheng oilfield， Ordos Basin

Xiaobing NIU, Jianming FAN, Chao ZHANG, Yilin REN, You’an HE, Rui CHANG, Liangbing CHENG

2025, 46(5):  1664-1681.  doi:10.11743/ogg20250517

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Shale oil production through quasi-natural depletion faces a key challenge of low crude oil recovery due to a rapid decline in reservoir pressure and a marked decrease in oil production. Over more than a decade of persistent efforts， the Changqing oilfield has carried out systematic theoretical research， laboratory simulations， pilot tests， and large-scale field applications. These initiatives have led to the development of differential enhanced oil recovery （EOR） techniques tailored to newly developed and mature blocks. Specifically， for newly developing blocks， an innovative well pattern-fracture network collaborative optimization technology is proposed， featuring “small well spacing， small cluster spacing， and large-scale cross fracturing design.” Techniques developed for the stimulation of mature blocks include a multi-media energy replenishment technique integrating “fine-scale division of injection intervals， high gas injection rates， and structured displacement” and a regional energy replenishment-based refracturing technique. The field application results of these techniques indicate that in newly developing blocks， the collaborative optimization technology can enhance shale oil recovery by more than 4% under the well pattern during primary recovery. For mature blocks， the integrated application of the EOR techniques can enhance shale oil recovery by 3% to 5%. The collaborative optimization of techniques for both newly developing and mature blocks is projected to increase the calibrated recovery of shale oil reservoirs in the Qingcheng oilfield， Ordos Basin， to over 15% from the present 7.5%. The results of this study provide an important theoretical basis and technical reference for EOR of shale oil reservoirs in the Ordos Basin and other similar reservoirs worldwide.

Microfluidic experimental study on imbibition-displacement mechanism of tight oil reservoirs using fracture-matrix etched chips

Liu YANG, Guangtao DONG, Xiaoyu JIANG, Mingjun LI, Fei GONG, Kai ZHU, Yijie PEI

2025, 46(5):  1682-1699.  doi:10.11743/ogg20250518

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Hydraulic fracturing serves as a primary technique for developing tight sandstone oil reservoirs. Investigating the microscopic seepage mechanism and flow dynamics of residual oil helps guide the exploitation of tight oil reservoirs with high water cut. To explore fluid migration patterns and the imbibition-displacement coupling mechanism during fracturing fluid injection， we conduct visual flooding experiments using microfluidic models based on fracture-matrix laser-etched chips （also referred to as the dual-medium microfluidic models）. We analyze the movement of the oil-water interfaces， the stripping of oil droplets， and the microscopic distribution of residual oil under the influence of imbibition-displacement coupling. The results indicate that， following the injection of fracturing fluids into a dual-medium microfluid model， the flow process involved fracture fingering， pore-fissure interactive imbibition， and pore displacement. A lower injection rate corresponded to a stronger dominance of imbibition， resulting in a broader sweep range of oil in dead-end pores near the fractured zone. With an increase in the injection rate， the interactive imbibition weakened， leading to a gradual reduction in sweep range and oil recovery， which was primarily attributable to pore oil displacement. The addition of surfactants enhanced the ability of fracturing fluids to strip oil droplets and residual oil clusters adhering to pore walls. Moreover， fracturing fluids containing surfactants significantly impacted residual oil and promoted its drainage. Consequently， a substantial amount of residual oil was stripped from the pore walls. Following fluid breakthrough， residual oil on pore walls continued to be stripped during the stable displacement stage， significantly enhancing the overall flooding effect. Residual oil remained in the imbibition and flooding processes due to variations in wall roughness and the impact of flow rates and pressure across different pores. Based on its morphology and distribution， residual oil can be categorized into six types： spherical， single-wall-adhered membranous， pore-throat columnar， double-wall-adhered membranous， wall-adhered bent columnar， and inter-wall contiguous types. The columnar and membranous types， among others， are extensively distributed.

Characteristics and genesis of high-gamma sandstones in the 6th to 9th oil groups of the Triassic Yanchang Formation， Wuqi area， Ordos Basin

Hao DIAO, Xinzhi YAN, Jingzhou ZHAO, Rong MA

2025, 46(5):  1700-1716.  doi:10.11743/ogg20250519

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Sandstones with high natural gamma-ray （GR） values （also referred to as high-gamma sandstones） occur in the 6th to 9th oil groups of the Yanchang Formation （collectively referred to as the Chang 6‒9 oil groups） in the Wuqi area， Ordos Basin. By conventional log interpretations， these sandstones are often mistakenly identified as siltstones or even mudstones， leading to an underestimation of the effective reservoir thickness. In this study， we conduct a fine-scale lithological division by combining core observations with grain size data. Accordingly， the logging responses， petrological characteristics， physical properties， and oil-bearing properties of high-gamma sandstones in the study area are summarized， followed by an analysis and exploration of their origin. The results indicate that the high-gamma sandstones exhibit significant conventional logging responses， including high GR values， elevated sonic interval transit time， and pronounced negative spontaneous potential （SP） anomalies. In the spectral GR logs， these sandstones show the characteristics of high uranium （U） and thorium （Th） concentrations， along with low potassium （K） concentration. Compared to common sandstones， the high-gamma sandstones generally contain higher contents of feldspar， mica， and clay minerals. Despite comparable porosity， the high-gamma sandstones show slightly lower permeability and oil saturation than common sandstones. Furthermore， their oil-bearing properties tend to decrease with an increase in the concentrations of radioactive elements such as U， Th， and K. The primary factors controlling the formation of the high-gamma sandstones include volcanic activity， sedimentary environment， and clay mineral type. The debris produced by volcanic eruptions supplies abundant radioactive materials for the study area. The northeastern and southwestern parts of the study area show differences in the migration， accumulation， and preservation conditions of radioactive elements， especially U and Th， which exhibit distinct degrees of enrichment under different sedimentary environments. Clay minerals exhibit varying adsorption capacities for radioactive elements. Specifically， illite and mixed-layered illite-montmorillonite demonstrate higher adsorption capacities， whereas kaolinite and chlorite exhibit limited adsorption capacities. Fine-scale investigations of the lithological and developmental characteristics of high-gamma sandstones in the Wuqi area hold great practical significance for increasing hydrocarbon reserves and enhancing productivity in the Ordos Basin， while also providing a key geological basis and theoretical guidance for the exploration and exploitation of similar reservoirs in other basins of China.

Methods for classification and evaluation of low-permeability tight reservoirs： A case study of the lower Yanchang Formation， Ordos Basin

Weimin SHEN, Jingzhou ZHAO, Meili ZHAO

2025, 46(5):  1717-1730.  doi:10.11743/ogg20250520

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The classification and evaluation of low-permeability tight reservoirs remain a pressing challenge in hydrocarbon exploration and exploitation. Traditional approaches are either tailored to conventional reservoirs or oversimplify the categorization of low-permeability tight reservoirs， limiting their practical applicability. Although some recently developed evaluation methods have shown promising results， their broad adoption is hindered by difficulties in parameter acquisition and high implementation costs. In this study， we examine the general reservoir characteristics in the study area using casting thin section observations， scanning electron microscopy （SEM）， and high-pressure mercury injection （HPMI）. Based on these results， combined with extensive data processing and multiple clustering algorithms， we propose a K-means clustering-based classification and evaluation method for low-permeability tight reservoirs. Furthermore， we mathematically define the classification boundaries using porosity-permeability cross plots. The proposed classification and evaluation system offers several advantages. By adopting an algorithm-driven approach， it overcomes the limitations of traditional experience-based criteria， thus providing more scientifically robust classification results. Although the proposed method integrates eight key parameters that capture reservoir physical properties and pore structure characteristics （i.e.， porosity， permeability， sorting coefficient， median pressure， median pore radius， displacement pressure， maximum mercury saturation， and mercury withdrawal efficiency）， the final classification and evaluation results rely solely on porosity and permeability， which are both the most indicative of reservoir quality and the most accessible. Therefore， this method addresses the limitations of traditional ones， including difficulty in acquiring evaluation parameters and challenges associated with widespread application. Employing mathematically defined classification boundaries， it avoids the oversimplified “one-size-fits-all” cut-offs inherent to traditional classifications. The method has been applied to the classification and play fairway prediction of low-permeability tight reservoirs in the Chang 7-9 oil groups in the lower Yanchang Formation， Dingbian-Fuxian area， Ordos Basin， providing a reliable basis for sweet spot evaluation in this area.

Fault stability assessment for the safe operation of the Lei 61 underground gas storage facility in the Liaohe Basin

Chao WANG, Xiaofei FU, Yejun JIN, Lingdong MENG, Xianxue CHEN, Tianguang ZHANG, Haidong SHI

2025, 46(5):  1731-1744.  doi:10.11743/ogg20250521

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The safe operation of underground gas storage （UGS） facilities is crucial for ensuring a stable gas supply， achieving seasonal peak shaving， and securing strategic energy reserves. Fault stability is， in turn， a critical to keeping the UGS integrity. Therefore， it is essential to assess the stability of faults in a UGS facility and determine the critical pressure for fault instability. In this study， we explore the stability of faults in the Lei 61 UGS facility within the Liaohe Basin. Conventional method that assumes the frictional coefficient of faults is a fixed value， tends to overestimate the fault stability， as shown by the research results. Given that clay minerals can reduce the frictional strength， we examine the relationships of clay minerals of various types with the frictional coefficient of faults. By integrating theoretical calculations with the experimental calibration of the frictional strength， we develop a model for quantitatively characterizing the heterogeneity in the frictional strength of faults tailored to the study area. This approach enhances the scientific rigor of fault stability assessment and enables a more accurate fault stability assessment for the Lei 61 UGS facility. According to the comparison of the assessment results， the conventional assessment method predicts that all faults in the UGS facility remain highly stable under the current stress field， at a minimum activation pressure of 20.04 MPa； in contrast， the improved assessment method indicates a minimum activation pressure of 16.68 MPa， with a decrease of 3.36 MPa， despite the absence of any fault activation.