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The Chang 7, Chang 8, and Chang 9 members of the Triassic Yanchang Formation in the Fuxian–Ganquan area of the Ordos Basin all develop lacustrine shales. However, current geological research and shale oil and gas exploration mainly focus on Chang 7 shale, with little attention given to Chang 8 and Chang 9 shale formations. Based on the experimental data from whole-rock mineral analysis, organic geochemical analysis, field-emission scanning electron microscopy analysis, and hydrocarbon generation simulation experiments, combined with well-logging data, the shale distribution, mineral composition, source rock characteristics, reservoir properties, and oil and gas contents of Chang 7, Chang 8, and Chang 9 shales were comprehensively analyzed. Moreover, the effect of integrated exploration of multilayer shales was evaluated based on a specific example. The results indicate that three sets of shales are extensively developed in the Yanchang Formation in the study area, but their thicknesses and distribution ranges vary greatly, and Chang 7 shale has the largest thickness and distribution range. Their clay mineral contents are relatively high, reaching an average of 46.7%. Also, the types of their organic matter are mainly Type I-II1, with high abundance and an average organic carbon content of 4.7%. Their vitrinite reflectance is between 0.7% and 1.3%, indicating that they are in the oil–gas symbiosis stage. Furthermore, they develop various types of nanoscale pores, such as intergranular pores, intragranular pores, and organic pores, and their porosity has an average value of 2.51% and increases significantly after crude oil is extracted. Oil and gas coexist in these three sets of shales, with an average free hydrocarbon content of 3.9 mg/g and an average gas content of 2.6 m3/t. Finally, in order to explore the integrated exploration and development of multilayer shale oil and gas formations, multilayer staged fracturing tests were carried out on six vertical wells for three sets of shales; the production results show that the gas production rate significantly increased by threefold, with a daily oil production rate of more than 1 ton. [ABSTRACT FROM AUTHOR]

Copyright of Acta Sedimentologica Sinica is the property of Acta Sedimentologica Sinica Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Pore structure is a key parameter used to evaluate reservoir quality. At present, experimental method is the most important method to analyze reservoir pore structure. However, coring data may be limited, and it is not possible to perform experimental analyses on all cores. Therefore, the researchers explored the use of logging techniques to study the pore structure of reservoirs. The relationship between pore geometry index (PGI), pore permeability and mercury injection parameters was analyzed based on mercury injection experiment, thin slice analysis, production test data and well logging data. These results can then determine the response characteristics of the logging parameters that correspond to different pore structures and establish a method of modeling the PGI through a multiple parameter regression and neural network method. This research shows that: (1) PGI can quantitatively characterize pore structure, and the maximum pore throat radius, displacement pressure and flow unit index have the highest correlation with PGI, which can be accurately characterized by practical formulas; (2) Natural gamma ray, natural potential amplitude difference, acoustic transit time, density, compensated neutron, deep and shallow resistivity logging data can reflect the quality of the reservoir pore structure. However, there are limitations in evaluating reservoir pore structure with a single logging parameter. Multi-parameter regression method and neural network method realize the quantitative calculation of pore structure from the perspective of multi-parameter and nonlinear. (3) The neural network method and multiple parameter regression method are used to study the pore structure of reservoir and realize the continuous quantitative calculation of pore structure index in a single well. It can be used in uncored analysis Wells and as one of the parameters to evaluate reservoir pore structure.

Predicting the thickness distribution of different types of continental lithofacies is a fundamental task for selecting and evaluating continental shale oil-rich zones. Research on oil-bearing conditions, reservoir characteristics, and mobility of different types of lithofacies plays an important role in target area selection and the deployment of horizontal well sections. Based on core observation and logging identification, spectrum analysis of logging data was carried out. Stable astronomical orbital time cycles were introduced to perform spatio-temporal tuning. A high-frequency sequence isochronous lattice for drilling well comparison was established and the planar thickness variation trends of different types of lithofacies in each sequence cycle were quantitatively calculated, providing insights into lithofacies distribution patterns. Research on the 7th member (Chang 7) of Triassic Yan-chang Formation in the Fuxian area of the southern Ordos Basin showed that the natural gamma logging curves contained several sets of astronomical cycle information, among which 6 complete stable 405 kyr long eccentricity astronomical cycles could be identified. Based on the observation of the whole core section of Chang 7 member in well R203 and logging facies characteristics analysis, a reasonable high-frequency isochronous lattice was established for well-to-well comparison. The results showed that mud shale and laminated shale mainly developed in the bottom cyclic strata from Chang 73 to Chang 72 sub-member, and the fine-grained sandstone and siltstone were mostly developed in strata of cycles Ⅳ to Ⅴ from the middle and upper parts of Chang 72 to the bottom of Chang 71. Lateral comparison between wells showed that the mud shale and laminated shale lithofacies in the early cycles were widely distributed. During cycle Ⅰ period, these facies were mainly distributed in the southwest of the study area, and during cycle Ⅱ period, they were distributed in the west and east-northeast, with thicker storage in the central area. The fine-grained sandstone thickness distribution in strata of cycles Ⅳ to Ⅴ was controlled by a northeast-southwest sedimentary system, with a planar distribution from the north-northeast to the south-southwest, further extending to the southwest along wells ZF 27 to ZF 32. Three types of source and reservoir combinations were formed in Chang 7 member. The combination of laminated shale and fine-grained sandstone lithofacies occurred from the middle and upper parts of Chang 73 and Chang 72 sub-members to the lower part of Chang 71 sub-member, primarily distributed in the central-north, north, and northeast parts of the Fuxian area. The shale lithofacies thickness was well developed in Chang 73 sub-member, mainly distributed in the northeast, east, and southwest regions of the Fuxian area.

Fine characterization of oil plane distribution in highly heterogeneous tight sandstone is a prerequisite for efficient reservoir development. This study systematically evaluated the distribution characteristics of tight oil in the Chang 7 Member of the Western Ordos Basin using a large number of experimental tests, logging interpretation, and 3D modelling methods. The logging interpretation models of shale content, porosity, permeability, and oil saturation were constructed, and the effective reservoir was identified by establishing the intersection identification pattern of reservoir acoustic wave time difference and deep lateral resistivity. The 3D numerical simulation results showed that the tight oil is distributed between injection and production wells. The areas with high tight oil content are mainly distributed along the WE direction, and a series of high remaining oil zones are formed locally. Under the influence of long-term injection and production, a high permeability zone will be formed between wells, which is similar to a high-speed channel and will be flooded quickly, and a banded remaining oil retention zone will be formed around it. For the horizontal well flooding area, the water flooding range of the water injection well is small, and a large amount of remaining oil is enriched between water injection wells. Finally, the classification standard of the remaining oil in the Chang 72 sub-member of the study area is proposed, and then, the strategy of adopting different development and adjustment schemes according to different types of reservoirs is formed.

Abstract Beach bar sand bodies are a relatively new type of reservoir in oil exploration where they can be found in the proximity of the source rock. In this study, the genetic type of sand bodies in the Upper Triassic Yanchang Formation in the southwest Ordos Basin is systematically studied through the observation of outcrops, core description, microscopic inspection of thin sections, along with petrophysical properties, mineralogy, and geochemical analysis of trace elements. The results showed that a new sedimentary type of beach bar sand bodies are developed in the Chang 82 submember of the Yanchang Formation, that are generally characterized with a flat bottom and convex top, where the contact interface between the bottom of the single sand body and mudstone is flat, and the bottom lacks erosion and filling structure. Moreover, a variety of wave‐induced sedimentary structures are developed, showing a reverse sedimentary sequence from fine to coarse grains. The structural and compositional maturity of the beach bar sand bodies are higher than that of the river channel sand body. Moreover, reservoir pore type is mainly comprised of intergranular pores, and the porosity and permeability of the samples retrieved from the sand body are much higher than that of the river channel sand body. Finally, the main controlling factors of the formation and preservation of beach bar sands are found to be the lake basin bottom topography, the base level cycle, and the stable paleo‐lake shoreline. During the Chang 82 submember depositional period, a large area where the beach bar sand bodies were deposited parallel to the lake shoreline in the southwest of the basin was created. Such depositional environments had suitable conditions to host large‐scale oil‐bearing reservoirs, as major exploration and development targets in the Ordos Basin in the future.

Copyright of Journal of Engineering Geology / Gongcheng Dizhi Xuebao is the property of Journal of Engineering Geology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

China shale oil can be classified as interlayer shale oil (in sandstone, carbonate, and diamictite) and genuine shale oil. Considering the characteristics and strong heterogeneity of continental shales, it is recommended to evaluate the interlayer shale oil resources using the elemental volume method based on pore volume, and the genuine shale oil resources using the elemental weight method based on oil content. Four key parameters for genuine shale oil resource evaluation (i.e., S1, TOC, Ro, and shale thickness) and three key parameters for interlayer shale oil resource evaluation (i.e., interlayer thickness, porosity, and oil saturation) are determined, and the lower limits of parameters are defined accordingly. The evaluation results show that the geological resources of genuine shale oil in Qing-1 member of Songliao Basin are 52.23 × 108 t; the geological resources of shale oil in Chang-73 sub-member of Ordos Basin are 66.80 × 108 t, including 27.73 × 108 t interlayer shale oil and 39.07 × 108 t genuine shale oil; the geological resources of shale oil in Lucaogou Formation of Junggar Basin are 15.62 × 108 t, including 11.99 × 108 t interlayer shale oil and 3.63 × 108 t genuine shale oil. This study provides a reference for exploration decision of shale oil in China. [ABSTRACT FROM AUTHOR]

In order to better understand pore–throat structure characteristics, the coupling relationship between micropore–throat structure and macro reservoir quality and influencing factors caused by authigenic minerals were studied. Petrographic analyses, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) were performed on a suite of tight reservoir samples from the Chang 8 Member of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. The results show that the pore–throat sizes obtained with the combination of PMI and NMR methods varied from nano- to microscale, revealing pore–throat sizes ranging from 0.001 μm to 70 μm, and showing that pore–throats with a radius larger than 1.0 μm are rare. Larger pore–throats with good connectivity (>rapex) account for a smaller part of the total pore volume, ranging from approximately 7.58% to 38.90% with an average of 22.77%, but account for more than 80% of contributions to permeability. The effective movable fluid porosity (φemp) measured by NMR, ranging from approximately 0.10% to 7.07% with an average of 2.56%, had a positive contribution to permeability. The contents of chlorite occurrence state, other than illite, are beneficial to pore–throat preservation. A new reservoir evaluation scheme of the Chang 8 reservoir is established. These research results provide a theoretical basis for the evaluation and development of tight sandstone oil and gas exploration. [ABSTRACT FROM AUTHOR]

The mineralogical development and diagenetic sequence of lacustrine shales in the Chang 7 Member of the Yanchang Formation in the Ordos Basin are detailed studied. A model of their depositional system and a diagenetic diagram are proposed in this study. Through detailed petrographic, mineralogical, and elemental analyses, four distinct shale types are identified: argillaceous shale, siliceous shale, calcareous shale, and carbonate, clay, and silt-bearing shale. The main diagenetic process in argillaceous shale is the transformation of illite to smectite, negatively impacting shale porosity. Siliceous shale undergoes carbonate cementation and quartz dissolution, contributing to increased porosity, particularly in mesopores. Calcareous shale experiences diagenesis characterised by carbonate formation and dissolution, with a prevalence of siderite. In carbonate, clay, and silt-bearing shale, the dissolution of K-feldspar contributes to illitization of kaolinite. Argillaceous shale, characterised by more clay minerals and lower mesopore volume, is identified as a potential hydrocarbon seal. Siliceous shale, with the highest pore volume and abundant inter-mineral pores, emerges as a promising shale oil reservoir. These findings contribute to a comprehensive understanding of shale properties, aiding in the prediction of shale oil exploration potential in the studied area. [ABSTRACT FROM AUTHOR]

Beach bar sand bodies are a relatively new type of reservoir in oil exploration where they can be found in the proximity of the source rock. In this study, the genetic type of sand bodies in the Upper Triassic Yanchang Formation in the southwest Ordos Basin is systematically studied through the observation of outcrops, core description, microscopic inspection of thin sections, along with petrophysical properties, mineralogy, and geochemical analysis of trace elements. The results showed that a new sedimentary type of beach bar sand bodies are developed in the Chang 82 submember of the Yanchang Formation, that are generally characterized with a flat bottom and convex top, where the contact interface between the bottom of the single sand body and mudstone is flat, and the bottom lacks erosion and filling structure. Moreover, a variety of wave‐induced sedimentary structures are developed, showing a reverse sedimentary sequence from fine to coarse grains. The structural and compositional maturity of the beach bar sand bodies are higher than that of the river channel sand body. Moreover, reservoir pore type is mainly comprised of intergranular pores, and the porosity and permeability of the samples retrieved from the sand body are much higher than that of the river channel sand body. Finally, the main controlling factors of the formation and preservation of beach bar sands are found to be the lake basin bottom topography, the base level cycle, and the stable paleo‐lake shoreline. During the Chang 82 submember depositional period, a large area where the beach bar sand bodies were deposited parallel to the lake shoreline in the southwest of the basin was created. Such depositional environments had suitable conditions to host large‐scale oil‐bearing reservoirs, as major exploration and development targets in the Ordos Basin in the future. [ABSTRACT FROM AUTHOR]

The lithofacies types, pore structure differences, and main controlling factors on the shale reservoirs are vital problems that need to be addressed in the process of shale oil exploration and development. This study explores the Luohe oilfield in the southern Ordos Basin, which is composed of organic-rich shale in the Chang 7 member, to clarify the reservoir properties and analyze major factors affecting the reservoir quality. The shale reservoir can be divided into five lithofacies using ternary diagrams of TOC, argillaceous minerals, and siliceous minerals: high organic-rich siliceous shale (HOSS), high organic-rich argillaceous shale (HOAS), medium organic-rich siliceous shale (MOSS), medium organic-rich argillaceous shale (MOAS), and low organic-rich shale (LOS). The type of organic matter in the studied samples is mainly Type I kerogen and Type II kerogen, predominantly Type II1 kerogen. The kerogen mostly lie within the mature zone in the study area. Various types of pores have been identified in the studied shale: intergranular pores, intragranular pores, intercrystalline pores, organic matter pores, and seams around organic matter. The pores are commonly nanoscale to micrometer in scale, with diameters ranging from 10 nm to several microns. The S1 content in shale is positively correlated with the macropore content, indicating that macropores in shale are the main effective oil storage spaces and are important for oil-bearing reservoirs. There is a good positive relationship between the macropore volume of shale and the content of organic matter. Organic matter in the shale can be beneficial for generating organic matter pores, dissolution pores, and seams at organic matter edge, resulting in better physical properties of shale reservoirs. There is a negative relationship between the quartz/feldspar content and macropores content, indicating that quartz and feldspar are detrimental for the macropore volume development. The lithofacies type is one of the important factors controlling the macropore volume. MOAS and HOAS are favorable lithofacies for the development of macropores. The findings of this study can be utilized for hydrocarbon exploration and development in the lacustrine shale formation of the Ordos Basin and other similar basins. [ABSTRACT FROM AUTHOR]

Fault-fracture bodies are developed in the southwestern margin of Ordos Basin， and thus， the study on the controlling effect of fracture bodies on sweet spot distribution of Yanchang Formation reservoirs needs to be deepened. In this paper， based on the extensive seismic and logging interpretation results， the characteristics of fault-fracture bodies are described from the point of view of their evolution mechanism， and then the controlling effect of fault-fracture bodies on oil and gas is systematically discussed. The results show that vertical strike-slip faults are developed in the southwest margin of Ordos Basin， with Y-shaped， flower-like， and negative flower-like structures. The faults usually pass through the bottom of Chang 7 Member， the bottom of Yan’an Formation， the bottom of the Cretaceous series， and the basement. Some of the faults retain the early reverse fault properties， indicating that the late inversion degree is not complete. The main fault has different shapes and migrations in different parts， and the section shows the cyclic transformation of tension-torsion and compression-torsion properties. On the plane， different types of fracture combinations appear alternately. The development model of strike-slip faults is established， and the strike-slip faults have typical characteristics of “multi-stage activity and inherited development”. Chang 8 Member mainly develops vertical fractures and horizontal bedding fractures. The development frequency of horizontal bedding fractures is 62.5%， while that of vertical fractures is 37.5%. The oil level of vertical fractures is relatively higher. Fractures are mainly developed in fine sandstone in distributary channels. When the distance from the main fault is greater than 1.25-1.5 km， the degree of fracture development decreases sharply， showing a fault-fracture body boundary. In addition， fractures are relatively developed in the single sand body within 6 m from the main fault. When the thickness of the single sand body exceeds 6 m， the degree of fracture development decreases sharply. The study shows that the index system based on sedimentation （foundation）， structure （dominant）， and fracture （effective） can effectively predict the favorable zones of Chang 8 fault-fracture body reservoir.

Objective To clarify the causes of the vertical difference of pore structure in low permeability-tight sandstone reservoirs. Methods Taking the WL area of the Ordos Basin as an example, using physical property tests, casting thin sections, scanning electron microscopy and high-pressure mercury injection, through the division of diagenetic facies and the analysis of vertical distribution differences of different diagenetic facies the characteristics, differences and causes of pore structure in different layers of the Yanchang Formation were discussed. Results The study showed that there were five types of pore structures in the main strata of the Yanchang Formation in the study area, and there were great differences in the pore structures between the same strata and different strata. The Chang 2 and Chang 3 oil layers of the upper combination mainly developed Ⅲa- and Ⅲb-type pore structures, the Chang 4+5 and Chang 6 oil layers of the middle combination mainly developed Ⅳa- and Ⅳb-type pore structures, andthe Chang 7, Chang 8 and Chang 9 oil layers of the lower combination mainly developed Ⅳb- and Ⅴ-type pore structures. With the increasing of burial depth, the pore structure and the porosity and permeability conditions in the reservoir gradually deteriorated overall. There were four types of diagenetic facies types in the reservoir of the Yanchang Formation in the study area. The vertical difference of pore structure was mainly controlled by the difference distribution of diagenetic facies types. The dissolution dominated by atmospheric water leaching in the upper combination was strong. The diagenetic facies types dominated by unstable component dissolution facies and chlorite cementation were developed, and the pore structure formed was dominated by relatively good types. The middle combination had strong cementation, and the diagenetic facies types dominated by chlorite cementation facies and carbonate cementation facies were developed, and the pore structure formed was mainly medium type.The lower combination had strong compaction and cementation, and the diagenetic facies types dominated by carbonate cementation facies and soft-rich compaction filling facies were developed, and the pore structure formed by them was mainly relatively poor. Conclusion The research results can provide favorable guidance for oil and gas exploration and development of the Triassic Yanchang Formation in the Ordos Basin.

The pore structure and mineral characteristics affect the accumulation and migration of hydrocarbons in shale, which determines the production capacity of shale oil. In this study, shale samples from the Chang 7 member of the Ordos Basin in China were selected to investigate the pore space characteristics, the effect of hydrocarbon accumulation on pore heterogeneity, and the hydrocarbon migration changes based on fractal theory, and a series of experiments were conducted involving X-ray diffraction (XRD), total organic carbon (TOC), Soxhlet extraction, and low-temperature nitrogen (N2) and carbon dioxide (CO2) adsorption. Then, the factors affecting extraction efficiency in shale pores were discussed. The interparticle pores contributed most to the accumulation of shale oil, and the organic matter (OM) pores contributed positively to the adsorption of hydrocarbons. The accumulation of hydrocarbons in the pore space did not increase the heterogeneity of the shale pore structure. The contents, states, and positions of hydrocarbons changed during the extraction process. Hydrocarbons were redistributed on the pore surface after Soxhlet extraction, and the heterogeneity of hydrocarbon adsorption and pore surface roughness were improved. Some heavy hydrocarbons and adsorbed components were pyrolyzed, resulting in the gradual escape of the adsorbed layer in the large pores. However, the free oil in the small pores diffused to the large pores and reaggregated on the surface, restoring a stable adsorption layer. The extraction rate was closely related to the pore throat structure and the wettability of mineral surfaces. The configuration between pores and throats had a crucial influence on the extraction rate. A high proportion of meso-pores, which effectively connect micro- and macro-pores, had a higher diffusion efficiency and a higher extraction rate. The OM pores with high energy adsorption were located in the micro-pores, and the shale oil existed in a dissolved state with high mobile capacity. The wettability of mineral surfaces affected the adsorption behavior during extraction, and strong oil wetting promoted hydrocarbon re-adsorption in clay minerals, so that the volume of micro-pores was smaller after extraction.

The Chang 7, Chang 8, and Chang 9 members of the Triassic Yanchang Formation in the Fuxian–Ganquan area of the Ordos Basin all develop lacustrine shales. However, current geological research and shale oil and gas exploration mainly focus on Chang 7 shale, with little attention given to Chang 8 and Chang 9 shale formations. Based on the experimental data from whole-rock mineral analysis, organic geochemical analysis, field-emission scanning electron microscopy analysis, and hydrocarbon generation simulation experiments, combined with well-logging data, the shale distribution, mineral composition, source rock characteristics, reservoir properties, and oil and gas contents of Chang 7, Chang 8, and Chang 9 shales were comprehensively analyzed. Moreover, the effect of integrated exploration of multilayer shales was evaluated based on a specific example. The results indicate that three sets of shales are extensively developed in the Yanchang Formation in the study area, but their thicknesses and distribution ranges vary greatly, and Chang 7 shale has the largest thickness and distribution range. Their clay mineral contents are relatively high, reaching an average of 46.7%. Also, the types of their organic matter are mainly Type I-II1, with high abundance and an average organic carbon content of 4.7%. Their vitrinite reflectance is between 0.7% and 1.3%, indicating that they are in the oil–gas symbiosis stage. Furthermore, they develop various types of nanoscale pores, such as intergranular pores, intragranular pores, and organic pores, and their porosity has an average value of 2.51% and increases significantly after crude oil is extracted. Oil and gas coexist in these three sets of shales, with an average free hydrocarbon content of 3.9 mg/g and an average gas content of 2.6 m3/t. Finally, in order to explore the integrated exploration and development of multilayer shale oil and gas formations, multilayer staged fracturing tests were carried out on six vertical wells for three sets of shales; the production results show that the gas production rate significantly increased by threefold, with a daily oil production rate of more than 1 ton.

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In order to gain a deeper understanding of the pressure relief characteristics of shale brittle fracture caused by large-scale tectonic uplift and its impact on shale oil enrichment, this paper, taking the Chang 73 sub-member of Yanchang Formation in Yan'an area of Ordos Basin as the research object, quantitatively analyzes the evolution of different lithological properties from overpressure to underpressure or near normal pressure, and further summarizes its influence on the enrichment of shale oil by utilizing the modified overpressure identification plate and numerical simulation techniques and taking into account the effects of temperature reduction, elastic rebound, and brittle rupture of overpressured shale in the process of tectonic uplift. The results show that the origins of overpressure at the end of the Early Cretaceous in the Chang 73 sub-member in the study area are mainly hydrocarbon generation and disequilibrium compaction, and the overpressure of the sandstone layer mainly originates from the overpressure transference from the neighboring source rocks; elastic rebound and temperature reduction due to tectonic uplift since the Late Cretaceous dominates the formation of underpressure in the Chang 73 sub-member sandstones in the study area, and brittle fracture pressure relief and temperature reduction lead to the formation of weak overpressure or near normal pressure in the Chang 73 sub-member shale. The timing of brittle fracture pressure relief of the top and bottom sets of organic-rich shale in the Chang 73 sub-member of the study area is not synchronized, resulting in large transport dynamics (source-reservoir excess pressure difference) between the top and bottom sets of organic-rich shale and their intercalated sandstones with magnitudes ranging from 16 to 22 MPa. Meanwhile, fractures in the top shale have closed during oil and gas preservation, and there is an excess pressure differential of about 1.42-6.80 MPa between it and the underlying sandstone, which strengthens the hydrocarbon containment capacity of the shale. Differential evolution of formation pressure under different source-reservoir configurations plays an important role in controlling shale oil enrichment.

This research paper focuses on the laminated shale oil reservoir in the third sub-member of the seventh member of Yanchang Formation (Chang 73 sub-member) in the Ordos Basin. The study aims to comprehensively analyze the lithofacies type, micro qualitative and quantitative pore structure parameters, and the main controlling factors of the pore structure in laminated shale. The analysis involves various techniques, including a comprehensive analysis of TOC, rock-eval, X-ray diffraction, polarized light and fluorescence microscope observation, field emission scanning electron microscope observation, and low-pressure N2 adsorption analysis. Based on the sedimentation characteristics, geochemistry, and mineral composition differences, the Chang 73 laminated shale can be classified into three lithofacies types: tuffaceous-organic matter binary laminated shale, clayey-organic matter binary laminated shale, and felsic-clayey binary laminated shale. The pore network consists primarily of organic hydrocarbon generation pressurization fractures, clay mineral felsic intergranular composite pores, and felsic plasmid intergranular pore fracture systems. Mesopores are the most developed pore type. The pore volume and specific surface area increase in the order of “tuffaceous-organic matter”, “clayey-organic matter”, and “felsic-clay”, while the heterogeneity of the pore network gradually weakens, and the roughness of the pore surface enhances. The overall development of organic matter pores is limited, with organic matter-pyrite-clay mineral composite pores being the main components of micropores. The primary intergranular pore system, associated with rigid quartz particles, dominates the mesopores and macropores, and acts as the main framework of the entire pore network. The development of feldspar dissolution pores is limited and contributes minimally to the pore network.

In order to better understand pore–throat structure characteristics, the coupling relationship between micropore–throat structure and macro reservoir quality and influencing factors caused by authigenic minerals were studied. Petrographic analyses, scanning electron microscopy (SEM), pressure-controlled mercury injection (PMI), nuclear magnetic resonance (NMR), and X-ray diffraction (XRD) were performed on a suite of tight reservoir samples from the Chang 8 Member of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. The results show that the pore–throat sizes obtained with the combination of PMI and NMR methods varied from nano- to microscale, revealing pore–throat sizes ranging from 0.001 μm to 70 μm, and showing that pore–throats with a radius larger than 1.0 μm are rare. Larger pore–throats with good connectivity (>rapex) account for a smaller part of the total pore volume, ranging from approximately 7.58% to 38.90% with an average of 22.77%, but account for more than 80% of contributions to permeability. The effective movable fluid porosity (φemp) measured by NMR, ranging from approximately 0.10% to 7.07% with an average of 2.56%, had a positive contribution to permeability. The contents of chlorite occurrence state, other than illite, are beneficial to pore–throat preservation. A new reservoir evaluation scheme of the Chang 8 reservoir is established. These research results provide a theoretical basis for the evaluation and development of tight sandstone oil and gas exploration.

The conclusion of "near-source accumulation" of tight oil is inferred based on the reservoir characte-ristics that crude oil is difficult to migrate laterally for a long distance in low-permeability reservoirs, yet there has been no direct geochemical evidence for a long time. Based on the analysis of the characteristics of source rocks and the source differences of oil in the near-source assemblage (Chang 6 member to Chang 81 sub-member) of the Tirassic Yanchang Formation in the Ordos Basin, this paper explores the geochemical basis of tight oil near-source accumulation and explains its cause. The results show that the crude oil in the near-source assemblage comes from the in-situ Chang 7 source rocks, and even the oil sources in the adjacent blocks are different. It is difficult for crude oil to undergo large-scale lateral migration in a tight reservoir. The biomarker compounds of Chang 7 source rocks in the Ordos Basin have significant differences in the plane and are distributed in a circularbelt along the sedimentary center. The oil source difference caused by the combination difference ofbiomarker compounds in different facies zones is the fundamental reason for the predecessors' discovery of "near-source accumulation" of tight oil. The "near-source accumulation" of tight oil has changed the previous view that oilsource correlation is a generalization of the whole basin and the source rocks of the same layer, and has important significance for the zoning and fine evaluation of different types of oil and gas resources in a single basin in the future.

Pore structure, as the focus of shale reservoir research, has important influence on the occurrence of shale oil. In this paper, 10 shale core samples from the 7th member of Triassic Yanchang Formation (Chang 7 member) in Huachi area, Ordos Basin were selected to carry out scanning electron microscope (SEM) observation and low-temperature nitrogen adsorption experiment, and the fractal dimension was calculated to quantitatively characterize the pore structure of shale in the research area combined with fractal FHH model. On this basis, the relationship between fractal dimension and pore structure parameters and oil-bearing parameters was discussed, and the main influencing factors of pore development of shale in the Chang 7 member were determined. The results show that the shale of the Chang 7 member in Huachi area has high organic matter abundance, which are good-to-excellent source rocks mainly composed of quartz and clay minerals, with good oil-bearing property (up to the middle oil-bearing level) and mobility. The reservoir space is dominated by intergranular pores, intragranular pores and a small amount of organic pores. There are two types of pore morphology, namely, parallel plate-shaped slit+unilateral slit and ink bottle-shaped + parallel plate-shaped slit. The pores are mainly micropores and mesopores, with macropores less developed. Most samples have fractal characteristics. The fractal dimension D1 of small pores is between 2.264 7 and 2.714 9, and the fractal dimension D2 of large pores is between 2.373 3 and 2.77 7. Among them, D2 has a good correlation with surface area, pore volume, average pore diameter and S1, which can characterize the development characteristics of pore structure and oil-bearing property of shale, while D1 can only characterize the mobility of shale oil. The pore development of shale is mainly controlled by TOC and quartz content, and has a certain relationship with feldspar content, while clay mineral content is not the main influencing factor.

In order to reveal the impact of fracturing fluid retention and flowback on the development effect after large-scale fracturing in shale oil wells, and to formulate a reasonable flowback policy, this paper employs a combination of core physical simulation experiments and theoretical analysis. We have designed a specially designed device that can evaluate the development effect of quasi-natural energy in oil reservoirs. The impact of fracturing fluid retention on development is simulated by changing the amount of fracturing fluid injected into the formation in a fractured horizontal well model (referred as injection volume), and the impact on development effect is analyzed by changing the properties of fracturing fluid to adjust the difference in the degree of flowback. Based on the experimental results, the mechanism of fracturing fluid retention and flowback after large-scale fracturing in shale reservoirs is further explored. The results of the experiments show that the flowback rate of fracturing fluid exhibits a monotonic decreasing trend with increasing the volume of injected fluid, as increasing the volume of injected fluid helps to enhance its retention in the formation and reduce the flowback rate. The degree of fracturing fluid flowback is critical to the mobility of crude oil in the tight reservoir. The entering of fracturing fluid into the reservoir slows down the rate of discharge in the fracture network, effectively extending the reach of the fracturing fluid in the tight reservoir and allowing more crude oil to be used, which in turn results in higher crude oil production. However, too much injection fluid may affect the fluid production. Simulation experiments reveal that the use of fracturing fluid retention or controlling the rate of flowback by changing the viscosity of fracturing fluid can be a way to enhance the development effect of horizontal shale oil wells. The results of this paper provide a basis for understanding the mechanism of shale oil development, exploring technical ideas to improve the development effect, and making decisions on the flowback parameters.

The sixth member of the Triassic Yanchang Formation (Chang 6 member) in the Dalugou area of the Jing'an Oilfield in the Ordos Basin is a typical ultra-low-permeability lithological reservoir. The Dalugou area has achieved some development progress in the past few years. With the development of the Chang 6 member in the Dalugou area, a better understanding of the sedimentary microfacies and depositional patterns is needed for precise oil development. The purpose of the study of the reservoir description is to understand the reservoir more accurately and provide a solid geological basis for the adjustment of the development strategy of the Chang 6 reservoir. The Chang 6 member of the Triassic Yanchang Formation in the Dalugou area of the Jing'an Oilfield belongs to the subfacies of the delta front, and the reservoir in the study area is mainly the underwater distributary channel deposition. There are two main depositional patterns in the study area: the dendritic sandstone depositional pattern and the lobate sandstone depositional pattern. The study on the sedimentary types and patterns of the Chang 6 member of the Triassic Yanchang Formation in the Dalugou Area of the Jing'an Oilfield can provide significant information for the evaluation of reservoir characterization. Furthermore, the heterogeneity of the Chang 6 reservoir under various depositional patterns has an important influence on oil enrichment. [ABSTRACT FROM AUTHOR]

Analysis of tectonothermal history of the Yanchang Formation in the western Weibei Uplift and in the northwestern Weihe Basin can reconstruct the cooling history of the southwest most remained Upper Triassic source rock of the North China Plate. Apatite fission-track (AFT) and (U-Th-Sm)/He (AHe) analysis were used to recover the cooling and uplift history of the Upper Triassic here. Ten sandstones from the Middle-Upper Triassic strata yield AFT ages between 179.8 ± 7.4 and 127.6 ± 8.1 Ma. AHe ages of two sandstones have the value of 37.7 ± 2.3–131.1 ± 8.1 and 45.7 ± 2.8–83.5 ± 5.2 Ma. Time-temperature modeling results showed that tectonothermal history of the Yanchang Formation was initially different in time-space relationships but then became almost identical through time followed by different cooling rate. Modeling results of the Triassic strata in the Qianyang area and the Yaojiagou area revealed three different uplift-cooling stages commencing in the Late Jurassic at ∼165 Ma and in Early Cretaceous at ∼110 Ma, respectively, both followed by first similar cooling histories to the Early Miocene at ∼20–23 Ma and then different since the Late Miocene. Uplift-cooling rate since the Late Miocene at ∼8 Ma were different between the Western Weibei Uplift and the Northwestern Weihe Basin. The timing, cooling-uplift rates of the Yaojiagou area, which was mainly controlled by movements related to the Liupanshan Mountains, the Qinling Orogens and the Weibei Uplift, had the earliest onset of uplift-cooling for the Upper Triassic series compared to other regions within the Weibei Uplift. Cooling paths for the Upper Triassic series became uniform regionally in the Early Cretaceous marking a key time for the tectonothermal evolutionary history of Upper Triassic series in the southwestern North China Plate. [ABSTRACT FROM AUTHOR]

Gravity flow deposits are important hydrocarbon reservoirs in deep lacustrine deposits. Previous studies have paid much attention to the hydrocarbon reservoirs in those intrabasinal classic turbidite deposits. However, relatively little is known about the distribution of oil reservoirs in those extrabasinal hyperpycnal flow deposits. With the help of cores and wireline logging data, the present study undertakes a description and interpretation of subsurface shale oil reservoirs in the deep lake deposits in Chang 7 member, Yanchang Formation, Ordos Basin. Parallel bedded fine sandstone (Sh), massive bedded fine sandstone (Sm), massive bedded fine sandstone with mud clasts (Smg), deformed bedded siltstone (Fd), wave-lenticular bedded siltstone (Fh) and black shale (M) were found and interpreted in those deep lake deposits. The deposits were interpreted as hyperpycnal flow deposits which developed in channel, levee and deep lacustrine facies. The development of the Chang 7 sand body increased gradually, and the sand body of Chang 71 was found to be the main position of sandy hyperpycnites. The fine description of the sand body indicated a channelized sedimentary pattern. The thick sandy hyperpycnites mainly developed in the middle of those channels, and the eastern part of the study area was found to be the main deposition position of the hyperpycnal flow deposits. From the perspective of plane overlap and single well analysis, a thick sand body is the favorable position for the development of an oil reservoir, which has a significant control effect on the reservoir scale and oil production. This research can aid in understanding the facies distribution of hyperpycnal flows and has implications for hydrocarbon reservoir exploration. [ABSTRACT FROM AUTHOR]

Pyrite is a widely developed mineral in organic-rich shale, which is of great significance to the identification of the depositional environment and hydrocarbon enrichment of organic-rich shale. By means of thin section identification, XRD (X-ray diffraction), argon-ion polishing, SEM, rock pyrolysis and gas sorption, the pyrite and its impacts of reservoirs in organic-rich shale in the Yanchang Formation of Ordos Basin and Qingshankou Formation of Songliao were analyzed. The results show these as follows. The content of pyrite and the particle size of pyrite framboid in the Ordos Basin are larger than those in the Songliao Basin, the average particle size of pyrite framboid in each group of samples in Yanchang group is 13. 79 ~ 18. 1 μm, and most are 10 ~ 22 μm. The average particle size of pyrite framboid in each group of Qingshankou Formation is 2. 83 ~ 14. 92 μm, and most are 2 ~ 8 μm. The pyrite content in the Ordos Basin and Songliao Basin is proportional to the value of TOC (total organic carbon) and S1 + S2 . The average pore diameter of the two basins is proportional to the content of pyrite and inversely proportional to the particle size of pyrite framboid. The pyrite framboid in the organic-rich shale of the Yanchang Formation in the Ordos Basin is in early sedimentary-burial diagenetic stage with a shallow water oxidation environment. In organic-rich shale of the Qingshankou Formation in the Songliao Basin, there are two types of pyrites framboid: post-diagenetic deep-buried pyrites and early shallow-buried pyrites. The depositional environment of pyrite is semideep water sulfide environment and shallow water sub-oxidation-oxidation environment. Pyrite can promote the enrichment of organic matter and the development of porosity, and the intercrystalline pores of pyrite framboid can also promote the enrichment of hydrocarbons, which has reference significance for shale oil exploration. [ABSTRACT FROM AUTHOR]

Chrysophyte cyst fossils were widely pyritized and preserved in black shales from the seventh member (Ch7 Mbr) of the Yanchang Formation in the Ordos Basin. The age, pyritization, and preservation model of these fossils have not been studied previously. In this study, the astronomical orbital cycles of the Ch7 Mbr were determined based on the gamma ray series of the Yan56 and Zhen 421 wells. An astronomical time scale (ATS) analysis revealed that the depositional duration of Ch7 Mbr was approximately 5 Ma. According to the 206Pb/238U radiometric dating of zircons using laser ablation inductively coupled plasma mass spectrometry (La-ICP-MS), the tuffs at the bottom of Ch7 Mbr were crystallized at 234 Ma, which served as a geological anchor. The ages of three submembers in Ch7 Mbr were estimated at 234.0–232.4 Ma, 232.4–230.8 Ma, and 230.8–229.1 Ma based on ATS analysis. In addition, chrysophyte cyst fossils were well preserved by pyritization in the Ch7 Mbr black shales. There were six types of microscopic morphologies with different pores, collars, and surface ornamentation under scanning electron microscopy (SEM). The age of the chrysophyte cyst fossils was at least 233.6 Ma in the Triassic Carnian Pluvial Episode (CPE) based on the 405 kyr tuned ATS. Moreover, the paleoredox conditions in Ch7 Mbr were reconstructed, and a preservation model of chrysophyte cyst fossils was established based on geochemical analyses. Fossil pyritization was caused by bacterial sulfate reduction near the water-sediment interface under suboxic to anoxic environmental conditions. Pyritization was initiated on the walls of the chrysophyte cysts by the formation of microcrystalline pyrite. Because of the gradual pyritization of the chrysophyte cyst wall, the organic matter in the interior of the fossil was well preserved. [ABSTRACT FROM AUTHOR]

This research paper focuses on the laminated shale oil reservoir in the third sub-member of the seventh member of Yanchang Formation (Chang 73 sub-member) in the Ordos Basin. The study aims to comprehensively analyze the lithofacies type, micro qualitative and quantitative pore structure parameters, and the main controlling factors of the pore structure in laminated shale. The analysis involves various techniques, including a comprehensive analysis of TOC, rock-eval, X-ray diffraction, polarized light and fluorescence microscope observation, field emission scanning electron microscope observation, and low-pressure N2 adsorption analysis. Based on the sedimentation characteristics, geochemistry, and mineral composition differences, the Chang 73 laminated shale can be classified into three lithofacies types: tuffaceous-organic matter binary laminated shale, clayey-organic matter binary laminated shale, and felsic-clayey binary laminated shale. The pore network consists primarily of organic hydrocarbon generation pressurization fractures, clay mineral felsic intergranular composite pores, and felsic plasmid intergranular pore fracture systems. Mesopores are the most developed pore type. The pore volume and specific surface area increase in the order of “tuffaceousorganic matter”, “clayey-organic matter”, and “felsic-clay”, while the heterogeneity of the pore network gradually weakens, and the roughness of the pore surface enhances. The overall development of organic matter pores is limited, with organic matter-pyrite-clay mineral composite pores being the main components of micropores. The primary intergranular pore system, associated with rigid quartz particles, dominates the mesopores and macropores, and acts as the main framework of the entire pore network. The development of feldspar dissolution pores is limited and contributes minimally to the pore network. [ABSTRACT FROM AUTHOR]

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This study focuses on the tuff intervals involving zircon U-Pb geochronology, which are located at the bottom of Yanchang Formation in Yonghe outcrop section, Shanxi Province. In conjunction with the field exploration and microscopic observation, they show obvious regional differences. They mainly occur in the Yonghe and Daning counties, the southeast margin of Ordos Basin, and in the Ningwu Basin, and show a trend of thinning from west to east. The weighted average ages of the dominant component in the two Yonghe tuff samples are (241±3) Ma (n=29) and (238±3) Ma (n=29), respectively. Combined with the different well data in Shaanxi Province (227~241 Ma), these results indicate that the eruption of tuff is dated at the late Early Triassic to early Middle Triassic.

The lithofacies types, pore structure differences, and main controlling factors on the shale reservoirs are vital problems that need to be addressed in the process of shale oil exploration and development. This study explores the Luohe oilfield in the southern Ordos Basin, which is composed of organic-rich shale in the Chang 7 member, to clarify the reservoir properties and analyze major factors affecting the reservoir quality. The shale reservoir can be divided into five lithofacies using ternary diagrams of TOC, argillaceous minerals, and siliceous minerals: high organic-rich siliceous shale (HOSS), high organic-rich argillaceous shale (HOAS), medium organic-rich siliceous shale (MOSS), medium organic-rich argillaceous shale (MOAS), and low organic-rich shale (LOS). The type of organic matter in the studied samples is mainly Type I kerogen and Type II kerogen, predominantly Type II1 kerogen. The kerogen mostly lie within the mature zone in the study area. Various types of pores have been identified in the studied shale: intergranular pores, intragranular pores, intercrystalline pores, organic matter pores, and seams around organic matter. The pores are commonly nanoscale to micrometer in scale, with diameters ranging from 10 nm to several microns. The S1 content in shale is positively correlated with the macropore content, indicating that macropores in shale are the main effective oil storage spaces and are important for oil-bearing reservoirs. There is a good positive relationship between the macropore volume of shale and the content of organic matter. Organic matter in the shale can be beneficial for generating organic matter pores, dissolution pores, and seams at organic matter edge, resulting in better physical properties of shale reservoirs. There is a negative relationship between the quartz/feldspar content and macropores content, indicating that quartz and feldspar are detrimental for the macropore volume development. The lithofacies type is one of the important factors controlling the macropore volume. MOAS and HOAS are favorable lithofacies for the development of macropores. The findings of this study can be utilized for hydrocarbon exploration and development in the lacustrine shale formation of the Ordos Basin and other similar basins.

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Copyright of Journal of Northeast Petroleum University is the property of Journal of Northeast Petroleum University Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

In the Yan'an area of the Ordos Basin, the lithological heterogeneity of Chang 7 Member shale is extremely strong. In addition, sandy laminae is highly developed within the Chang 7 Member shale system. In order to explore the gas generation and migration processes of Chang 7 Member shale, geochemical characteristics of desorption gas are comprehensively compared and analyzed. In this study, rock crushing experiments were carried out to obtain shale samples, and desorption experiments were carried out to obtain shale samples and sandy laminated shale samples. For the crushing gas and desorption gas, the volume contents of different gas components were obtained using gas chromatography experiments. The rock crushing experiments revealed that the average volume percentage of CH4 in Chang 7 Member shale is 61.93%, the average volume percentage of C2H6 and C3H8 is 29.53%, and the average volume percentage of other gases is relatively small. The shale gas in Chang 7 Member is wet gas; the gas is kerogen pyrolysis gas. Most of the shale gas hosting in Chang 7 Member shale is adsorbed gas. Porosity, permeability and organic matter content are the main geological factors controlling gas migration and gas hosting. Shale with a higher porosity, good permeability and a low organic matter content is conducive to gas migration. The shale gas in Chang 7 Member shale contains CH4, C2H6, C3H8, iC4H10, nC4H10, iC5H12, nC5H12, CO2 and N2. N2 migrates more easily than CH4, and CH4 migrates more easily than CO2. For hydrocarbon gases, gas components with small molecular diameters are easier to migrate. The desorption characteristics of shale might provide clues for guiding hydrocarbon exploration in the study area. The sandy laminated shale with a higher gas content may be the "sweet spot" of shale gas targets. In Chang 7 Member, the locations hosting both shale oil and CH4 may be the most favorable targets for shale oil production. [ABSTRACT FROM AUTHOR]

Low and ultra‐low permeability reservoirs are widely developed in the Upper Triassic Yanchang Formation in the Ordos Basin, and its intricate pore throat structure has a significant impact on the physical properties and heterogeneity of reservoirs. This paper conducted a series of experiments to investigate the petrology, pore structure, fractal characteristics of ultra‐low permeability sandstone reservoirs, and influencing factors of the physical properties. The results show the sixth member of the Yanchang Formation (Chang 6) reservoir in the Xiaojiahe area is dominated by feldspathic sandstone. The main pores are intergranular pores, followed by dissolution pores. The Chang 6 sandstone has been categorized into four types (type I–IV) based on the traits of mercury intrusion curves. The high content of quartz and feldspar in the detrital components is conducive to improving the physical properties of the reservoir. The pore‐throat structure parameters, such as displacement pressure, median pressure, and pore throat radius can characterize the change in physical properties and reservoir quality. According to the capillary pressure fractal model of rapex (Pittman's plot apex radius), demonstrating the ultra‐low permeability, sandstone has a binary structure. The fractal dimensions D2 and Dp are more appropriate for characterizing the heterogeneity of the pore structure. The effects of different pore‐throat size scales on the physical properties of the reservoir have a discrepancy. Relatively large pore throats (r > rapex), non‐nanoscale pore throats (Porr>0.1), and effective movable pore throats (Porem) have significantly positive control effects on permeability and reservoir quality. In contrast, the development of nanoscale pore throats (Porr<0.1) and micropore throats of failure to enter mercury (Porfem) are unfavourable to reservoir performance. In conclusion, combining detrital components, pore‐throat structure, fractal characteristics, and other factors controlled the reservoir quality of ultra‐low permeability sandstone. [ABSTRACT FROM AUTHOR]

The tight oil reservoir of the Chang 7 member, Yanchang Formation in the Yan'an area of the Ordos Basin has the characteristics of oil and gas "co-existence" and strong heterogeneity. Unclear understanding of special geological characteristics and reservoir characteristics hinders the exploration and development of continental shale oil and gas. In this paper, a large number of core observations, thin sections, scanning electron microscopy, conventional mercury injection, and nuclear magnetic resonance experiments were used to characterize the reservoir properties of the Chang 7 oil shale. The experimental results show that the main mineral types of shale in the study area are clay minerals, quartz and feldspar, in addition to a small amount of carbonate and pyrite. The average size of rigid particles in argillaceous shale is 5.4 μm, and there are no sand-grade particles. Mud particles (≥8) can account for more than 50% of the medium particles. The TOC difference of shale, laminar shale and laminar shale is obvious, indicating that the TOC of shale has strong heterogeneity. The gas-bearing porosity occupied by shale gas in silty laminae is larger than that of shale. Moreover, the pore development characteristics are mainly intergranular pores and intra granular pores. Before oil washing, the porosity ranges from 0.27% to 8.06%, with an average of 2.35%. The Chang 7 tight oil reservoir contains oil in the pores from macropores to nano-pores, and the pores from micropores to nano-pores are full of oil. The micro-cosmic understanding of the reservoir characteristics of the Chang 7 tight oil reservoir is of great significance to the exploration and development of unconventional oil and gas resources in the Ordos Basin. [ABSTRACT FROM AUTHOR]

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A large number of sandstone interlayers were developed in the shale strata of the 7th member of the Triassic Yanchang Formation (Chang 7 member) in the Ordos Basin. These sandstone interlayers are frequently accompanied by abnormally high natural gamma values as high as 330.5 API. As a result, they are undistingui shable from shale on well profile. To characterize the high-gamma sandstones, the clastic rocks of the Chang 7 member were classified into fine sandstone, siltstone, argillaceous siltstone, silty mudstone, mudstone and shale according to grain size and structural characteristics. Conventional logging data were recalculated and combined into two new parameters—A and B. The new intersection chart composed of parameters A and B and natural gamma logging data can effectively distinguish and identify normal sandstone and high-gamma sandstone in the Chang 7 member. The plane distribution of cumulative thickness of high-gamma sandstone in the Chang 7 member shows that the high-gamma sandstone is mainly located in the southwest of the study area. The finger-like distribution of high-gamma sandstone from the edge to the center of the lake basin indicates that its formation may be related to the volcanic eruption during sedimentary period.

Natural fractures play an important role for the exploration and development of low-permeability reservoirs in the Triassic Yanchang Formation of the Ordos Basin. Abundant hydrocarbon resources have been found in the Yanchang Formation of the Gufengzhuang area, showing good exploration prospects. However, only limited research results on fractures have been obtained, and the distribution law and active period are both unclear. Based on the analyses of core, imaging logging, carbon-oxygen isotope, homogenization temperature of fluid inclusion, acoustic emission, tectonic stress and fracture activity, the characteristics, formation stages and causes of natural fractures in the Chang 7 to Chang 9 members of the Yanchang Formation in the Gufengzhuang area were studied, and corresponding indications for petroleum accumulation were discussed. Natural fractures are well-developed in the Chang 7 to Chang 9 members of the Yanchang Formation, especially in the Chang 7 member. High-angle and vertical fractures are ubiquitously developed, mainly of NEE orientation, followed by NE, and finally NW and NWW. The fractures are generally unfilled or semi-filled by calcites, providing effective pathways for hydrocarbon migration. The fracture surface is flat, and obvious traces of oil migration such as oil invasion, oil stain and oil spot can be observed. The average values of oxygen isotopes of the Chang 7 to Chang 9 members are -15.8‰, -17.5‰ and -18.7‰, indicating that the factures were formed at depth of 1 675, 2 338 and 2 785 m. According to the homogenization temperature peaks of fluid inclusions of 90-100 ℃ and 120-130 ℃, the formation depth of fractures is 1 750-2 000 m and 2 500-2 750 m. The fractures in the Chang 7 to Chang 9 members were active during multiple stages, including the Indosinian, Yanshanian and Himalayan stages, with the Yanshanian and Himalayan as the main active stages. Effective fractures developed in multiple stages have improved the physical properties of low-permeability reservoirs in the study area. They provided important migration channels and storage spaces for the formation of multi-layer and deep-layer reservoirs such as Chang 7, Chang 8 and Chang 9, and affected the productivity of oil wells.

The Chang 7 oil-bearing layer of Yanchang Formation is rich in shale oil resources. However, the reservoir indicates strong reservoir heterogeneity and has obvious differences in productivity among wells. The brittleness acts as an important factor causing the above phenomenon. Studies on rock mechanical properties and brittleness evaluation can provide technical support for drilling and fracturing design, but current methods have many disadvantages such as difficulty in obtaining parameters. In this study, the neural network method is used to construct the relationship between elastic modulus, Poisson's ratio and logging curve on the basis of measured rock mechanical parameters, construct rock mechanics parameter profile in the whole well section of Chang 7 oil-bearing layer, and finally quantitative evaluate shale oil reservoir brittleness. The results indicate that, (1) the neural network method is an effective method for rock mechanical parameter prediction and brittleness evaluation. The error between the predicted and measured values of elastic modulus and Poisson's ratio is low, generally within 10%; (2) according to the brittleness evaluation results, on the whole, the brittleness index of the Chang 72 reservoir is high, and the brittleness index of the Chang 73 reservoir is low. The results can provide scientific guidance for benefit development of Chang 7 shale oil in the Ordos Basin.

The lack of seismic data and special log data on the Chang 7 Member of the Yanchang Formation in Block X of the Ordos Basin poses a major challenge to the study of the development characteristics and identification of fractures that greatly influence on-site production. To overcome this obstacle, this study determined the macroscopic characteristics of fractures in the study area based on field outcrop profiles and indoor core observations. The results are as follows: (1) Fractures in the study area are dominated by regional fractures in weakly deformed structural areas, with three sets of fractures mainly occurring. Core observations show that fractures in the study area have high dip angles, small extensions, and small openings; (2) The vertical extended lengths of these fractures are significantly controlled by rock mechanical layers; (3) Fractures show three types of extended morphologies when meeting weak planes. Vertically, there is an exponential correlation between the sand body thickness and the fracture linear density. The argillaceous shale thickness has a logarithmic relationship to the fracture linear density when it is

Ordos Basin is rich in shale oil resources. Fuxian area in the southern Ordos Basin is an important area where Sinopec is expected to make a breakthrough in the exploration and development of lacustrine shale oil. To further identify the exploration target of shale oil in Chang 7 Member of Fuxian area, Ordos Basin, this study systematically analyzed the sedimentary characteristics, source rock characteristics, reservoir characteristics, oil-bearing characteristics, fracability and preservation conditions of Chang 7 Member in this area. The results show that: (1) the organic matter abundance of shale in the Chang 7 Member is high, and its type is dominated by type I-II1; the maturity is also relatively high, with Ro generally greater than 0.8% in the central and western parts, which is favorable for the generation and accumulation of shale oil. The development of fractures is pretty low, and thus the structure preservation conditions are relatively favorable. Delta front deposits are mainly developed in the northeastern part, while deep lake - semi-deep lake mudstone and gravity-flow deposits are developed in the western part, and the shale oil types are mainly type II and III. (2) Comparing with the western Ordos Basin, the reservoir in Fuxian area has rapid lateral variation and relatively thin cumulative thickness; the thickness of high-quality shale and maturity are low, resulting in low intensity of hydrocarbon generation and low mobility of oil-bearing saturation. Therefore, there is still a need for further improvement and refinement in the exploration evaluation, effective development and engineering techniques. (3) Integrating sedimentary characteristics with shale oil types, source conditions, oil-bearing properties, mobility, fracability and preservation conditions, it is clarified that the Type II shale oil of Chang 72 sub-,Member in Fuxian area is the current realistic exploration type of shale oil, and its favorable target is located in the development area of delta front in the central part and gravity flow in the western part.

Understanding the pore system and the geological factors controlling the adsorption of gas in mudstones and shales is a key element in predicting the gas accumulation potential of an unconventional reservoir. A series of integrated methods, including basic geochemistry, X-ray diffraction, scanning electron microscopy, low-pressure gas (CO2 and Ar) physisorption, and high-pressure methane adsorption were performed on a set of mudstones from the Triassic Yanchang Formation in Ordos Basin, to characterize the pore system and gas adsorption capacity and their geological controlling factors. The results show that the studied Yanchang Mudstones are mainly siliceous rocks with high total organic carbon concentration (average of 7.63%) and low to moderate thermal maturity (vitrinite reflectance of 0.55–0.92 %). The microscopic visible pores are mainly intergranular pores between organic matter and rigid mineral grains, while organic matter pores are less well-developed. The pore volume is mainly contained in micropores (diameter

Taking lake basin shales of the Triassic Yanchang Formation in the Ordos Basin, NW China and the Cretaceous Qingshankou Formation in the Songliao Basin, NE China as research objects, the characteristics and origins of different types of silica in the shales have been studied by means of core observation, thin section identification, cathodoluminescence, X-ray diffraction analysis, scanning electron microscope (SEM), electron probe and rock pyrolysis. The results shows that the origins of silica include felsic mineral dissolution, tuffite devitrification, clay mineral transformation and siliceous mineral metasomatism. The silica formed by feldspar dissolution commonly appears as spots and veins, with low degree of crystallization, and is largely aqueous opal mineral, with an average SiO2 content of 67.2%. Silica formed by devitrification of tuffite mainly occurs in two forms, amorphous silica and authigenic quartz with better crystal shape. The authigenic silica formed during the transformation of clay minerals is embedded in the clay minerals in the form of micron-scale plates and small flakes, or mixed with clay minerals in a dispersed state. The authigenic quartz formed by siliceous mineral metasomatism is in better angular crystal shape, and has an average SiO2 content of 87%. The authigenic siliceous mineral content is positively correlated with the content of terrigenous felsic minerals. The pressure solution of felsic minerals is the main source of authigenic siliceous minerals, followed by the transformation of clay minerals, and the organic matter has some boost on the formation of authigenic silica. The authigenic siliceous materials of different origins have different geological characteristics and occurrence states from terrigenous quartz, which would affect the storage performance, seepage capacity and fracturing effect of continental shale. Although the organic-rich shale has high silica content, different from terrigenous quartz, authigenic silica in this kind of shale mostly floats and disperse in clay minerals, which would have negative effect on the formation of complex fractures in fracturing, fracture support ability after fracturing, and formation of effective seepage channels. Calculating the brittleness index of shale intervals only based on the composition of brittle minerals cannot accurately characterize mechanical characteristics of continental shale oil reservoirs, and would affect comprehensive evaluation and selection of continental shale oil “sweet spots”.

Analysis of reservoir sensitivity to velocity, water, salt, acid, alkali and stress is critical for reservoir protection. To study the tight sandstone reservoir sensitivity at different formation depths (effective stress) and formation water conditions (pH, salinity, and fluid velocity), a series of dynamic core flow tests under different pH, salinity, acid, and effective stress conditions were performed on samples from tight sandstone reservoirs of the Upper Triassic Yanchang 8 (T3y8) Member and conventional reservoirs of the Middle-Lower Jurassic Yan'an 9 (J1-2y9) Member in the Ordos Basin. The results indicate that, compared with the conventional reservoirs, the tight sandstone reservoirs are more sensitive to velocity and stress, less sensitive to water, alkali and salinity, and respond better to acid fracturing. In addition, the critical conditions (salinity, velocity, pH, and stress) for pumping drilling, completion, and fracturing fluids into tight sandstone reservoirs were investigated. A combination of scanning electron microscopy coupled with energy-dispersive spectrometry (SEM-EDS), cathodoluminescence (CL), casting thin section (CTS) and nuclear magnetic resonance (NMR) images, high-pressure mercury injection capillary pressure (MICP) measurements as well as X-ray fluorescence spectral (XRF) analyses were employed to analyze the damage mechanisms of the conventional reservoirs (J1-2y9) and tight sandstone reservoirs (T3y8) caused by fluid invasion. The results suggest that reservoir sensitivity is primarily conditioned by the composition of detrital components and interstitial fillings, petrophysical properties, pore-throat structure, and diagenetic facies. All these factors control the sensitivity types and extent of the reservoirs. Our results indicate that the poorer the reservoir physical properties, the stronger the reservoir heterogeneity and sensitivity, implying that tight sandstone reservoirs are more susceptible to changes in fluids than conventional reservoirs. This study offers insights into the reservoir damage types and helps to improve the design and implementation of protection measures for tight sandstone reservoir exploration.

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