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Eurasia map showing the sampling locations of the Semiluksk Formation (Vola-Ural Basin) and the Longmaxi Formation (Sichuan Basin).
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Due to the depletion of conventional hydrocarbon resources, both China and Russia are giving more attention to the exploration and production of unconventional oil and gas resources, especially those generated and accumulated within source rocks. In an attempt to further understand the mechanisms of these resources, detailed mineralogical, litholog...
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Context 1
... and geochemical analyses were used to compare the common features shared by source rocks or oil/gas reservoirs in the two regions. It should be noted that the source rocks of the Sichuan Basin are currently actively developed as gas fields, whereas those of the East European Platform are mostly developed as oil deposits. The Sichuan Basin (Fig. 1) is located in southwestern China and covers an area of more than 2.6 Â 10 5 km 2 . It sits on a Proterozoic basement ( He et al., 2017) and is confined to folded Paleozoic structures in an intermountain depression of western Yangtze Platform. Three structural and lithological complexes can be recognized in the 12-km-thick sedimentary ...
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... source rocks in the Semiluksk Formation in the East European Platform are called Domanik deposits. They are very widespread and form a wide and elongated meridional band extending to the west of the Urals (Fig. 1). In Russian, the most original form of the Domanik deposits is called the Domanikites with the average thickness of 20e30 m ( Liang et al., 2020). These deposits form a sequence attributable to the Semiluksk Formation of the Frasnian stage of the Upper Devonian. Recent research has revealed that the deposits have a predominantly ...
Citations
... Characterizing the spatial distribution of tight oil is to understand the development of tight oil [1][2][3], where logging with a vertical resolution of 0.125 m is required and the results are reliable [4][5][6][7]. In recent years, experts have found a large number of tight reservoirs with crude oil production prospects in the Bohai Bay Basin, Ordos Basin, and Sichuan Basin, etc., and have made achievements in the theoretical study of tight oil in China [6,8,9]. Some studies have systematically summarized the characteristics, formation mechanisms, and main controlling factors of tight oil reservoirs in the Ordos Basin, and redefined the concept of "tight oil" [10,11]. ...
The Chang 8 reservoir of the Huanjiang Oilfield in the Ordos Basin is a tight sandstone reservoir with poor reservoir physical properties and uneven oil distribution. In this study, the effective reservoirs developed on a large scale under the condition of horizontal well volume fracturing technology of the Chang 8 Member was identified based on the data of core observation, experimental analysis, logging, oil test, and production dynamics, and the identification standard of effective reservoirs in terms of reservoir physical properties, oil content, and comprehensive logging characteristics of gas logging was established. This scheme allows for a thorough identification of the effective reservoirs for horizontal well development in tight sandstone reservoirs. The findings indicate that the study area’s tight oil resources can be successfully produced. The well logging results show that the oil-bearing property of sand bodies with oil stains is better than that of oil spots. The bottom limit of the acoustic wave time difference is 210 μs/m, the permeability is 0.03 mD, the porosity is 6.0%, the rock resistivity is 30 Ω m, and the total hydrocarbon gas measurement value exceeds five times the baseline. At the same time, the total oil thickness is greater than 6 m, and the thickness of a single sand body is above 4 m. We have defined the lower limit standard of high-efficiency reservoir of Chang 8 tight oil in L289 block of Huanjiang oilfield. According to the analysis of oil-bearing property, comprehensive logging display, and reservoir thickness, the geological “sweet spots” is optimized to provide reference for subsequent mining. Through comparative analysis, the rules and trends are found to provide a basis for selecting mining strategies. With the help of technical means such as numerical simulation and geological modeling, the prediction accuracy and decision-making effect are improved. By clarifying the lower limit standard of reservoir, optimizing geological “sweet spots” and avoiding risk areas, the mining efficiency is improved and the cost is reduced, which provides reference for similar oilfield development.
... The Early Frasnian initiated with coastal marine and alluvial-deltaic clastic facies (Afanasieva, 2011). From Middle Frasnian to Early Carboniferous time, the sedimentary basins covering the eastern part of the East European craton hosted the accumulation of bituminous rich marl, oil shale, and chert sediments of Domanik facies (Morozov et al., 2021;Ibrahem et al., 2022), which had the largest areal extent during Middle Frasnian Semiluksk horizon to be gradually replaced by shallowwater carbonate platform deposits from Late Frasnian to Tournaisian (Liang et al., 2015;Stupakova et al., 2015;Stupakova et al., 2017;Liang et al., 2020). To the NW of Orenburg high ( Fig. 1 B), the typical Late Devonian deposition was disrupted by periodically alternating prograding deltaic sediments and limestones resulting in a clastic-carbonate Kolganian suite Pavlinova and Usova, 2012;Nikitin et al., 2014). ...
The evolution of intraplate sedimentary basins located in the vicinity of an active convergent plate boundary is often controlled by the collisional dynamics of the adjacent orogen. The transfer of compression from the orogen to the platform's interior results in the formation of complex structural geometry and kinematics that often reactivate older crustal faults, focus far-field stresses and control the evolution of associated sedimentary basins. One place where this localisation can be optimally understood is the Precaspian Basin, situated at the SE periphery of the East European Craton and bordered to the east by the Uralian orogen. The Precaspian Basin and its northern margin experienced long-term extension and subsidence interrupted by several short-lived shortening episodes. To understand the impact and role of pre-existing basement structures on the geometry and kinematics of the subsequent deformation, we analysed subsurface data from the northern margin of the Precaspian Basin by the means of 3D seismic interpretation correlated with wells and structural modelling. The analysis results provide new insights into the kinematic effects of the Late Devonian contraction event. The superposition of stratigraphic units above and below the angular unconformity suggests an intra-Famennian age of the deformation event. Steeply dipping bi-verging reverse fault zones associated with variable amounts of sinistral strike-slip movement component display an arcuate geometry, trending from WSW-ENE to NW-SE. The distribution of deformation indicates that this complex kinematic pattern was driven by a NE-SW oriented contraction and transpression, where faults show the characteristics of a restraining bend area. This area is interpreted as part of a regional transcurrent fault system developed on the northern periphery of the Precaspian Basin. Furthermore, the study results suggest that intralithospheric stress localisation transmitted by the Paleouralian subduction zone resulted in the reactivation of pre-existing basement structures, propagation of faults, and localized short-term exhumation of the Precaspian Basin north margin. Generated by the collision of Magnitogorsk volcanic arc with East European Craton, far-field stress transfer produced a zone of oblique deformation. These data and interpretation demonstrate that the northern margin of the Precaspian Basin is an excellent natural setting to investigate and better understand mechanisms of far-field strain localisation and reactivation of deformational structures in stable platform areas resulting in the intracratonic mountain building process.
... The Domanik-type formations of the Volga-Ural petroleum province that stratigraphically belong to the Middle Frasnian of the Upper Devonian to the Lower Carboniferous have an estimated mean undiscovered, technically recoverable continuous resources of 2.8 billion barrels of oil and 34 trillion cubic feet of gas. Carbonate rocks, which account for about 70% of the Volga-Ural Basin reservoirs, are significant target facies for oil and gas exploration, production, and development in the basin fields (Morozov et al., 2021;Korshunov and Boguslavskiy, 2022). ...
The results of integrated sedimentology, petrography, and petrophysical study of the Upper Devonian (Middle Famennian) Dankovo-Lebedyansky carbonates from Southeast Tatarstan of the Volga-Ural Basin revealed a variety of microfacies and diagenetic events that impacted the reservoir quality. Although our earlier study documented microfacies analysis and depositional environments, none of the studies focused on diagenesis, microfacies interaction, and their controls on the studied sediment's reservoir quality. Based on petrographic and microfacies analyses, the seven identified microfacies types are peloidal grainstone MF 1, cemented bioclastic peloidal grainstone MF 2, echinoderm-concentrated packstone MF 3, algae packstone MF 4, bioclastic wackestone MF 5, whole-fossil wackestone MF 6, and dolomite MF 7. For the investigated sediments, a gently deepening carbonate ramp depositional model with an inner, middle, and outer ramp setting is proposed. The observed diagenetic events in this study include micritization, calcite cementation (six cement types), dolomitization (six dolomite types), dissolution (fabric and non-fabric-selective dissolution), compaction, and microfracturing. The identified microfacies were classified into three distinct classes based on their petrophysical characteristics. MF 1 and MF 7 are microfacies types with the best reservoir quality. MF 3 and MF 4 are microfacies types of moderate reservoir quality. MF 2, MF 5, and MF 6 are microfacies types with poor or non-reservoir quality. Calcite cementation, micritization, and compaction are the primary diagenetic modifications responsible for porosity reduction. Moldic pores created by dissolution are a significant porosity-improving process. Porosity is locally enhanced by stylolite and microfractures. Dolomitization improved reservoir quality by creating intercrystalline and vuggy porosity. Understanding the impact of microfacies and diagenesis on reservoir quality is crucial for understanding reservoir properties in nearby fields with similar settings.
... Using ethane carbon isotopes to identify the origin and source of natural gas has certain limitations, especially for gas reservoirs formed by mixing coal-derived and oil-derived gases [34][35][36][37]. Heavy hydrocarbon gases such as methane and ethane may have different origins [38][39][40]. Therefore, there are some drawbacks in using only the carbon isotope characteristics of ethane to determine the origin of methane-based natural gas [6]. ...
In recent years, the geochemical characteristics, genesis and sources of natural gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin have received extensive attention, but their genesis and sources are still controversial. In this study, taking the natural gas from the Xujiahe Formation in the Sichuan Basin as an example, the source and genesis of the natural gas have been systematically analyzed. The results show that the natural gas of the Xujiahe Formation in the Sichuan Basin is dominated by methane, followed by a small amount of CO 2 and N 2 ; only the southern Sichuan area contains a small amount of H 2 S, which comes from the supply of the underlying carbonate source rocks. Except for the western Sichuan Basin, the drying coefficient of the natural gas is generally less than 0.95 (wet gas). Furthermore, the composition of the natural gas is mainly controlled by the maturity of source rocks. The carbon isotope of ethane in natural gas ranges from −33.9 to −21.5‰, and the hydrogen isotope of methane ranges from −188‰ to −151‰. The carbon and hydrogen isotope values are higher in the western Sichuan Basin than in the central, northeastern and southern Sichuan Basin. The identification of the origin of natural gas and the comparison of gas sources show that the natural gas in the Xujiahe Formation is mainly coal-derived gas from its own coal-measure source rocks; the natural gas in the northern part of the southern Sichuan Basin is oil-derived gas originating from the Changxing Formation and the Silurian marine source rocks; however, the natural gas in the northeastern Sichuan Basin is a mixture of coal-derived and oil-derived gases. In addition, the carbon and hydrogen isotopes in some natural gas samples from the Xujiahe Formation have inversions of δ ¹³ C 1 > δ ¹³ C 2 , δ ¹³ C 2 > δ ¹³ C 3 , δ ¹³ C 3 > δ ¹³ C 4 , and δD 2 > δD 3 , and the magnitude of the inversions is small. It is considered to be caused by the mixing of gases from the same source, as well as the mixing of coal-derived and oil-derived gases.
... The amount of natural gas generated is far less than the storage space of sandstone. Therefore, the charging of natural gas is insufficient, the gas reservoirs are independent of each other and the separation of gas and water is insufficient (Ni et al., 2011;Zhou et al., 2019;Morozov et al., 2021). It can be seen from Figure 8 that the high-yield wells are mainly distributed in the regions with gas saturation greater than 57.5%. ...
The enrichment law of tight sandstone gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin has not been fully revealed. In this study, the controlling effect of source-reservoir assemblage on gas accumulation in the Xujiahe Formation was systematically investigated. The results show that pores and fractures are developed in the tight sandstone reservoirs of the Xujiahe Formation. The main pore types are intragranular dissolved and intergranular pores. The quality of sandstone reservoirs in the Xujiahe Formation is controlled by sedimentation, diagenesis and tectonic processes. Underwater distributary river channels and estuary bars are favorable microfacies for reservoir development, and chlorite cemented facies and dissolution-kaolinite cemented facies are the most favorable diagenetic facies. In addition, the natural gas composition and carbon isotope characteristics of the Xujiahe Formation are significantly different in different intervals of the same gas field and the same interval of adjacent gas fields. This shows that the natural gas has no obvious vertical mixing and lateral migration, and it has the distribution characteristics of “local enrichment”. Then, the natural gas will be preferentially charged in the feldspar lithic sandstone and feldspar quartz sandstone with large thickness and good physical properties by means of short-range migration. According to the research, the hydrocarbon supply capacity of the single layer in each interval is weak, and it leads to the low filling degree of the gas reservoir and the insufficient separation of gas and water. On the whole, four sets of extra-source “lower generation and upper storage” assemblages and two sets of “self-generation and self-storage” source-reservoir assemblages are developed in the Xujiahe Formation. The development scale of natural gas is mainly controlled by the type of source-reservoir combination, and the areas with close source-reservoir contact and high hydrocarbon generation intensity are high-quality reservoir development areas.
... The Volga-Ural petroleum province is one of the most oil-rich basins in the world, with considerable amounts of oil and gas trapped in the clastic and carbonate strata of the basin (Kontorovich et al., 2016;Liang et al., 2019Liang et al., , 2020. It supplied more than half of Russia's oil output until West Siberia surpassed it in 1978 (Morozov et al., 2021;Ibrahem et al., 2022). Dankovo-Lebedyansky sediments ( Fig. 1c and d), as they are referred to in a number of literary works (Liang et al., 2015(Liang et al., , 2019(Liang et al., , 2020Stoupakova et al., 2017;Morozov et al., 2021), were first identified in the Volga-Ural petroleum province and named by Strakhov (1939). ...
... It supplied more than half of Russia's oil output until West Siberia surpassed it in 1978 (Morozov et al., 2021;Ibrahem et al., 2022). Dankovo-Lebedyansky sediments ( Fig. 1c and d), as they are referred to in a number of literary works (Liang et al., 2015(Liang et al., , 2019(Liang et al., , 2020Stoupakova et al., 2017;Morozov et al., 2021), were first identified in the Volga-Ural petroleum province and named by Strakhov (1939). ...
... The Dankovo-Lebedyansky sediments were part of the Domanik Formation, which extends stratigraphically from the Upper Devonian (Upper Frasnian) to the Lower Carboniferous (Tournaisian) in the Volga-Ural petroleum provinces (Liang et al., 2015(Liang et al., , 2019(Liang et al., , 2020Morozov et al., 2021;Ibrahem et al., 2022). However, the Dankovo-Lebedyansky sediments are no longer considered part of the Domanik Formation due to difference in sediment lithology, the Domanik Formation consists of interbeds of limestone and siliceous carbonate rocks rich in organic matter, which are regarded as source rocks and reservoir rocks, while the Dankovo-Lebedyansky sediments consist of carbonates without silica, which are only regarded as reservoir rocks (Liang et al., 2020;Ibrahem et al., 2022). ...
The Upper Devonian, Middle Famennian Dankovo-Lebedyansky sediments in Southeast Tatarstan territory are a carbonate sequence composed of limestone and dolomite, which is important hydrocarbon reservoir units, therefore, it is necessary to conduct in-depth study on its microfacies and depositional environment. In this study, a multidisciplinary approach that combines core observation with thin section examination is used. The limestone contains abundant skeletal grains (echinoderms, foraminifera, algae, gastropods, and calcispheres), as well as non-skeletal grains (intraclasts and peloids). On the basis of detailed petrographic investigations, six sedimentary microfacies can be identified, including (i) peloidal grainstone (MF 1), (ii) cemented bioclastic peloidal grainstone (MF 2), (iii) echinoderm-concentrated packstone (MF 3), (iv) algae packstone (MF 4), (v) bioclastic wackestone (MF 5), (vi) whole-fossil wackestone (MF 6), as well as dolomite or dolostone as diagenetic facies (MF 7). Based on microfacies analysis, the Dankovo-Lebedyansky sediments were deposited in three distinct sedimentary facies belts (shoal, lagoon and open marine environment). In order to reflect dispositional energy condition, the microfacies were grouped into facies associations: (i) low-energy microfacies associations including MF 5 and MF 6, (ii) moderate energy microfacies associations including MF 1, MF 2, MF 3, and MF 4. The dolomite, or diagenetic facies (MF 7), is the result of slightly to extensively dolomitization of limestone in the Dankovo-Lebedyansky sediments. Most of frequent dolostone types are euhedral planar-e and subhedral planar-s. According to petrographic characteristic of the dolostone, a seepage reflux model can be used to explain the dolomitization process of Dankovo-Lebedyansky sediments.
... However, the exploration and development of interbedded continental tight sandstone and shale gas is still at the early stage, and the understanding of the initiation and failure modes of hydraulic fractures is still insufficient (Xie et al., 2008;Shi et al., 2013). The dynamic and static mechanical properties of interbedded sand and shale are the internal factors affecting rock ruptures (Gao, 2021;Morozov et al., 2021). Moreover, previous studies have not conducted a comparative study on the dynamic and static mechanical properties of interbedded sand and shale. ...
High variability in diagenetic strength and rock mechanical properties in interbedded sand and shale necessitates a sustained interest in the study of the dynamic and static rock mechanical behavior and failure modes. We have analyzed the rock mechanical behavior, rupture characteristics, and sequences of the clastic reservoirs of the Xu 5 member, Western Sichuan Depression, China. The results indicate that the Xu 5 shale can produce longer plastic creep behavior than tight sandstone at the same load rate. This causes greater stresses to build up inside the shale than in adjacent sandstone formations. The average internal friction angle of sandstone is 43°, whereas the average internal friction angle of shale is 33°. The failure modes of the Xu 5 member sandstone are mainly brittle-tensile failure and brittle X-type shear failure. We observed that the tensile rupture is dominant, accounting for approximately 75.2%. Shale failure forms mainly include plastic-tensile failure and X-type shear failure, in which shear failure accounts for approximately 67.9%. The sequence of failures of similar clastic reservoirs is generally tensile failure or tensile-shear failure to extension failure. We found that the Xu 5 shale has high plasticity, and the stress conditions required for its failure are higher and more complicated. In addition, our test results indicate that, for the same lithology, the tensile failure is the initial rupture rather than shear failure.
... There is no unified understanding of the cause of formation overpressure in the Xujiahe Formation (Leng et al., 2011;Wang P. et al., 2019). Generally, the overpressure of the formation is related to mechanical compaction, aquathermal pressuring, dehydration of clays, hydrocarbon generation, and cementation of the pore space (Wangen, 2001;Radwan et al., 2020;Santosh and Feng, 2020;Wang et al., 2020;Morozov et al., 2021). However, these factors will also affect the ion and salinity of the formation water, thereby affecting the identification of the origin of the formation water (Thyne et al., 2001;Lei et al., 2013;Zhao et al., 2020). ...
Formation water represents an important driving force and carrier for the migration and accumulation of oil and gas; thus, research on its origin is a hot spot in petroleum geology. The Upper Triassic Xujiahe Formation in the Xiaoquan-Fenggu Structural Belt in the western Sichuan Depression, China, has developed thick tight sandstone gas reservoirs. However, previous studies have provided different conclusions on the origin of the formation water in the Xujiahe tight sandstone reservoir. In this paper, the origin of the formation water in the Xujiahe Formation was determined based on the latest major and minor elemental concentration data, hydrogen and oxygen isotopes data of formation water, and carbon and oxygen isotope data of carbonate cements. The results show that the salinity of the formation water of the Xujiahe Formation in the study area is generally greater than 50 g/L. The water type is mainly the CaCl2 type, although a small proportion of NaHCO3 type water with high salinity is observed, which is related to hydrocarbon expulsion by overpressure. Moreover, the formation water in the sandstone of the Xujiahe Formation is obviously rich in Br, which is related to membrane infiltration, overpressured hydrocarbon expulsion of shale and diagenesis of organic matter. The composition of Cl⁻ and Na⁺ ions in the formation water in the Xujiahe tight sandstone reservoir is consistent with the seawater evaporation curve, which deviates significantly from the freshwater evaporation curve. The hydrogen and oxygen isotopes of condensate water in the Xujiahe Formation tight sandstone are similar to those of atmospheric precipitation water, while the hydrogen and oxygen isotopes of the formation water in the Xujiahe Formation show that it is of seawater origin. Therefore, to use hydrogen and oxygen isotopes to determine the origin of formation water, condensate water must be accurately differentiated from formation water. Otherwise, if the condensate water is misjudged as formation water, then incorrect conclusions will be drawn, e.g., that the formation water of the Xujiahe Formation originated from fresh water. Affected by organic carbon, the carbon isotope Z value of the carbonate cements in the Xujiahe Formation is low (mainly distributed between 110 and 130). A Z value of less than 120 does not indicate that the ancient water bodies formed by cements were fresh water or mixed water bodies. However, Z values greater than 120 correspond to a formation temperature lower than 80 C, which indicates that carbonate cement was not affected by organic carbon; thus, the Z value can reflect the origin of ancient water bodies. The results of this study indicate that the formation water of the Xujiahe tight sandstone in the study area is of seawater origin. The determination of the origin of the formation water and seawater of the Xujiahe Formation provides strong evidence for the determination of the marine sedimentary environment of the Xujiahe Formation in the study area, and can provide scientific guidance for the search for high-quality reservoirs.
... Internal factors include organic matter abundance, kerogen type and maturity; and external factors include mineral components (brittle minerals, clay minerals and FeS) and diagenesis. Organic carbon is the material basis of organic pores (Morozov et al., 2021). The higher the degree of thermal evolution of organic matter, the more developed the organic pores in shales (Wu et al., 2021). ...
Research on microscopic pore and fracture system of shale is a hot spot in the field of unconventional petroleum geology. Micro- and nano-scale organic matter pores in shale play a vital role in the accumulation of hydrocarbons. Research on the types, evolution rules and controlling factors of organic matter pore-fracture system in shale reservoirs can provide scientific guidance for the prediction of shale “sweet spots”. In this paper, taking the shales from the Napo Formation, Oriente Basin, the Shahejie Formation, Zhanhua Sag, Bohai Bay Basin, and the Longmaxi and Wufeng Formations, Sichuan Basin as an example, the developmental characteristics of organic matter pore-fracture system were systematically studied using thin section, argon ion profiling scanning electron microscopy, X-ray diffraction, N2 adsorption and desorption, geochemistry experiments, and image processing technology. The types of shale organic matter pores were divided into kerogen-hosted pores, organic matter microfractures (intra-organic matter and organic matter edge microfractures), and asphalt pores (or intra-asphalt pores). The circumferences of organic pore were generally within 100 nm, and the areas of most pores were smaller than 1,000 nm². Face rates of the organic pores were generally less than 1.5%, and the proportion of shale samples with a shape factor of 1 reached more than 50%. In addition, the deviation angles of organic matter pores at (0°, 45°) reached 90%, which showed that most of the organic matter pores tended to be oriented pores. The increase in the degree of thermal evolution provided driving force for the formation of circular pores in the organic matter. Internal factors (abundance of organic matter, kerogen types, and maturity) and external factors (diagenesis and mineral composition) controled the development of shale organic matter pores. Maturity, TOC content and inorganic minerals such as clay and pyrite content were positively correlated with the development of organic matter pores. However, brittle minerals caused a decrease in the face ratio of organic matter pores. Diagenetic compaction caused the organic matter pores being deformed or eventually disappeared. This research can provide scientific guidance for the high-efficiency exploration of hydrocarbons in shale.
