Shale Oil Exploration Research Articles

Evaluation of Organic Carbon Logging in the Chang 7 Section of the Yanchang Formation, Huanjiang Area, Ordos Basin

During the early stages of shale oil exploration, challenges such as limited coring of source rocks and the discontinuous distribution of measured samples arise. Logging data can be used to quantitatively evaluate source rocks. Organic-rich source rocks typically exhibit characteristics such as high gamma radiation, low density, high sonic lag, high resistivity, and high neutron porosity on logging curves. This paper systematically introduces two quantitative evaluation methods for source rocks based on logging data: the Δlog R method and the BP neural network model. Corresponding prediction models were developed to forecast the organic carbon content of source rocks in the Chang 7 section of the Yanchang Formation in the Huanjiang area of the Ordos Basin. The predicted TOC (total organic carbon) data were copared with measured TOC data. The results indicate that both the ΔlogR model and the BP neural network model are effective for the study area, with the BP neural network model showing significantly better fitting performance than the ΔlogR model. The study also predicts the plane distribution of TOC content in the source rocks of the study area.

Key Technologies for Volume Fracturing of Yingxiongling Shale Oil in the Qaidam Basi

Abstract The Yingxiongling shale oil in the Qaidam Basin is the preferred choice for Qinghai Oilfield to enter the field of unconventional oil and gas resources, and volume fracturing is the core technology for shale oil exploration and development. Through the analysis of the geological and engineering characteristics of the Yingxiongling shale oil, it is found that there are difficulties in volume fracturing of the Yingxiongling shale oil, such as frequent changes in vertical mechanical properties and limited vertical control range; large stress differences, making it difficult to form complex artificial fractures; difficulty in opening multiple clusters of perforation holes; high water shortage in the plateau, high mineralization of the formation backflow fluid, and difficulty in reusing the backflow fluid. By iteratively modeling three-dimensional geomechanics, a high-resolution three-dimensional geomechanical model is established to guide the optimization of volume fracturing schemes. Through the integration of geological and engineering selection and clustering, three-stage active control technology for cracks, and the dual temporary plugging process of boreholes and cracks, the targeted and complex degree of artificial crack transformation can be improved. Through the study of high salinity fracturing fluid system, it has been found that high salinity backflow fluid can replace slick water and alleviate the demand for fresh water in volume fracturing. The article analyzes the difficulties of shale oil volume fracturing and studies the formation of an effective set of key techniques for volume fracturing, achieving the goal of improving the degree and effectiveness of transformation, and providing support for the exploration and development of the Yingxiongling shale oil in the Qaidam Basin.

Differential hydrocarbon generation characteristics of organic matter with green algae and cyanobateria origins in the Permain Lucaogou Formation of the Santanghu Basin

Organic-rich fine-grained rocks are key carriers of unconventional oil and gas resources, making it crucial to understand their hydrocarbon generation and evolution characteristics. This study examines the fine-grained rocks of the second member of the Lucaogou Formation (P2l2) in the Tiaohu and Malang Sags of the Santanghu Basin, focusing on how different organic matter (OM) backgrounds - primarily green algae and cyanobacteria - affect hydrocarbon generation and crude oil properties. Kinetic analysis and hydrous pyrolysis experiments on shales rich in green algae, cyanobacteria, and their mixtures revealed that green algae - derived OM requires lower activation energy to initiate hydrocarbon generation, results in an earlier oil generation peak, and has a broader oil window. Conversely, cyanobacteria - derived OM needs higher activation energy to start hydrocarbon generation, has a later oil peak, and a more concentrated generation period. These findings led to two models: the "green algae origin - early hydrocarbon generation - early oil peak - broad oil window model" and the "cyanobacteria origin - late hydrocarbon generation - late oil peak - concentrated oil generation model." Correlation analysis showed that aromatic hydrocarbons, resins, and asphaltenes significantly degrade crude oil quality. Hydrous pyrolysis experiments indicated that the heavy component content (aromatic hydrocarbons + resins + asphaltenes) in liquid hydrocarbons follows the order: residual oil > absorbed oil > expelled oil, with content initially increasing and then decreasing with maturity, and the color change of liquid hydrocarbons in dichloromethane reflects heavy component content changes effectively. Calculations of density and viscosity of liquid hydrocarbons, based on heavy component content and crude oil properties, were compared with the longitudinal distribution of crude oil properties in the study area. Results show that the hydrocarbon generation characteristics of green algae and cyanobacteria control crude oil properties, highlighting significant intra-source differentiation in the P2l2 shale and validates the phase separation approach in hydrous pyrolysis experiments. The P2l2 shale, with its high OM content and substantial hydrocarbon generation, holds great potential for shale oil exploration, but both reservoir quality and crude oil property evolution under different OM backgrounds should be considered when selecting favorable areas.

Shale Oil Generation Conditions and Exploration Prospects of the Cretaceous Nenjiang Formation in the Changling Depression, Songliao Basin, China

Low-maturity shale oil predominates in shale oil resources. China’s onshore shale oil, particularly the Cretaceous Nenjiang Formation in the Songliao Basin, holds significant potential for low-maturity shale oil, presenting promising exploration and development prospects. This study delves into the hydrocarbon generation conditions, reservoir characteristics, and oil-bearing property analysis of the mud shale from the Nen-1 and Nen-2 sub-formations of the Nenjiang Formation to pinpoint favorable intervals for shale oil exploration. Through the integration of lithology, pressure, and fracture distribution data in the study area, favorable zones were delineated. The Nen-1 sub-formation is widely distributed in the Changling Depression, with mud shale thickness ranging from 30 to 100 m and a total organic content exceeding 2.0%. Type I kerogen predominated as the source rock, while some samples contained type II kerogen. Organic microcomponents primarily comprised algal bodies, with vitrinite reflectance (Ro) ranging from 0.5% to 0.8%. Compared to Nen-1 shale, Nen-2 shale exhibited less total organic content, kerogen type, and thermal evolution degree, albeit both are conducive to low-maturity shale oil generation. The Nen-1 and Nen-2 sub-formations predominantly consist of clay, quartz, feldspar, calcite, and pyrite minerals, with minor dolomite, siderite, and anhydrite. Hydrocarbons primarily reside in microfractures and micropores, including interlayer micropores, organic matter micropores, intra-cuticle micropores, and intercrystalline microporosity, with interlayer and intra-cuticle micropores being dominant. The free oil content (S1) in Nen-1 shale ranged from 0.01 mg/g to 5.04 mg/g (average: 1.13 mg/g), while in Nen-2 shale, it ranged from 0.01 mg/g to 3.28 mg/g (average: 0.75 mg/g). The Nen-1 and Nen-2 sub-formations are identified as potential intervals for shale oil exploration. Considering total organic content, oil saturation, vitrinite reflectance, and shale formation thickness in the study area, the favorable zone for low-maturity shale oil generation is primarily situated in the Heidimiao Sub-Depression and its vicinity. The Nen-2 shale-oil-enriched zone is concentrated in the northwest part of the Heidimiao Sub-Depression, while the Nen-1 shale-oil-enriched zone lies in the northeast part.

Total organic carbon content estimation for mixed shale using Xgboost method and implication for shale oil exploration

In this study, the Xgboost method is employed for TOC estimation in mixed carbonate and siliciclastic shale from the Hashan area, Junggar Basin. The results show that this approach is effective for TOC estimation in this area although the model performance is not very excellent with a correlation coefficient of 0.54 between measured TOC and predicted TOC values, likely due to a small samples dataset. Therefore, the PCA method is applied to debase dimension of well log data from five dimensional to two-dimensional data, which enhances the correlation coefficient between the predicted and measured TOC from 0.54 to 0.68. Based on the model, the isopleth maps of TOC distributions in Fengcheng Formation were redrawn showing two shale oil exploration targets, which likely correspond to two depositional centers of this strata. All the same, the model in this work provides reliable data for shale oil evaluation in the study area and a good example under similar geological setting.

Pore structure of the mixed sedimentary reservoir of Permian Fengcheng Formation in the Hashan area, Junggar Basin

The Permian Fengcheng Formation (P1f.) in the Hashan area, situated on the southwestern margin of the Junggar Basin, has witnessed a remarkable breakthrough in shale oil exploration in recent years with nearly 789 million tons of shale oil resources. As a unique set of mixed sedimentary shales, the Fengcheng Formation in the Hashan area is characterized by mixed sedimentation of terrigenous siliciclastic sediments, authigenic minerals, and tuffaceous materials. However, the understanding of pore characteristics in the mixed sedimentary reservoir still remains limited, prohibiting accurate estimation of the oil content and insights into oil mobility. Scanning electron microscopy (SEM), X-ray diffraction (XRD), mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), X-Ray Computer Tomography (X-CT), and geochemical analysis were performed to investigate the pore size distribution and main controlling factors of the mixed sedimentary reservoir. Results showed that the main pore types in the mixed sedimentary reservoir are intergranular pores and dissolution pores. The pores of the P1f. mixed shales in the Hashan area were classified into II-micropores (< 25 nm), I-micropores (25–100 nm), mesopores (100–1000 nm) and macropores (> 1000 nm). In general, the mixed sedimentary rocks of P1f. formation feature few macropores but a large number of micropores and mesopores. The CS exhibits the most favourable physical properties among all lithofacies. It is concluded that the abundance and maturity of organic matter, mineral composition, sedimentary structure, and diagenesis of reservoir together impact the pore structure in the mixed sedimentary reservoirs. The maturity of organic matter and the content of tuffaceous minerals are the most significant in influencing the pore structure of P1f. shales. Overall, the pore structure of complex lithologic reservoir formed by mixed deposition and its influence on physical properties are studied, and the characteristics of the microscopic pore-throat system of the dominant lithofacies in the Hashan area are clarified, which is of great significance as a guide for the exploration and development of mixed sedimentary reservoirs in continental shale oil in China.

Sedimentary dynamics and depositional model for mud accumulation in deep lake basins: A case study in the Upper Triassic Chang-7 Member, Ordos Basin, northern China

Shales in deep lake basins have become the main focus of continental shale oil and gas exploration. In order to highlight the sedimentary dynamics of mud deposition in deep lake basins, a combination of core observation, thin section examination, X-ray diffraction, and QEMSCAN (quantitative evaluation of minerals by scanning electron microscopy) was used to analyze the depositional characteristics of mudrocks in the Chang-7 Member from the Yanchang Formation (Upper Triassic) in Ordos Basin, and to establish a depositional model for mud accumulation in deep lake basins. This study recognizes four mudrock lithofacies in the Chang-7 Member: (1) the laminated silt-bearing mudstone, which generally develops a binary composition of “silt–clay” or a ternary composition of “silt–clay–organic matter”; (2) the graded mudstone, mainly composed of dark gray and gray-black mudstone sandwiched by silt-bearing mudstone; (3) the massive mudstone, internally showing a uniform distribution of quartz, clay, and carbonate minerals, with also a small amount of organic detritus; and (4) the laminated shale, which is generally composed of clay laminae, and organic laminae of the former two. Sediment supply, topographic slope, and flood intensity combine to control the evolution of gravity flows and the transport and deposition of the mudrock in the Chang-7 Member. The influence of orogeny provides terrain gradient, water depth, abundant sediments at source areas, and triggering mechanism for the formation of gravity flows. Floods triggered by wetting events provide the impetus for sediment transport. Mud deposition in the Chang-7 Member was mainly related to the transport and sedimentation of mud by hyperpycnal flows and rapid sedimentation by buoyant plume flocculation. A comprehensive evolutionary model for shale accumulation in the deep lake basin is established by integrating various triggering mechanisms and mud transport sedimentary processes.

Study on the relationship between shale organic matter development and paleowater depth—A new understanding of the condensed section

Recent studies dispute the long-standing belief that highly organic-rich shales are predominantly linked to condensed section (CS) at the maximum flooding surface (MFS), proposing instead that they more commonly develop in shallow waters along basin margins. This hypothesis, however, has not been thoroughly investigated. Our study, focusing on the pivotal regions of the Longmaxi Formation and the Chang 7 Member for marine and continental shale exploration in China, integrates sequence stratigraphy with analyses of total organic carbon (TOC) and elemental geochemistry to pinpoint the environments conducive to the formation of organic-rich shales. The most organic-rich intervals, specifically the bottom of the Longmaxi Formation and the mid-to-lower Chang 73 sub-member, are located within the transgressive systems tract (TST), showing higher TOC levels in the middle to lower TST, compared to the CS of the MFS. The formation of high organic matter shale is related to warm, humid, and dysoxic shallow waters with minimal terrigenous influx and high primary productivity. We found a pronounced inverse relationship between organic matter concentration and water depth, with deeper waters promoting the decomposition and recycling of organic matter during sedimentation, thereby diminishing the TOC content. Moreover, volcanic activity also affected the organic enrichment in the Chang 7 Member. With high primary productivity, organic matter tends to accumulate in dysoxic slope zones. Consequently, high-organic content shale intervals are generally situated in shallow, dysoxic water environments, suggesting that the CS of the MFS may actually represent organic-poor intervals with limited source rock potential. The results of this study are of great significance for shale oil and gas exploration in China, and provide a new direction for the discovery of shale oil and gas sweet spots.

Pore evolution modeling in natural lacustrine shale influenced by mineral composition: Implications for shale oil exploration and CO2 storage

Pore evolution modeling in natural lacustrine shale influenced by mineral composition: Implications for shale oil exploration and CO2 storage

Formation temperature of microcrystalline dolomite in oil-rich black shale: Implications for hydrocarbon accumulation in a volcanic-lacustrine rift basin

Lacustrine microcrystalline dolostones in the ancient records have been commonly interpreted as of an evaporitic origin, on the basis of their numerous occurrences in modern evaporative shallow lakes. This interpretation obscures the forming mechanisms of dolostones formed in a deep lacustrine setting, where dolostones interbedded with shale become a focus of hydrocarbon source rocks in recent years. In this study, an alternative non-evaporitic origin of dolomite is interpreted for a Permian lacustrine laminated dolostone. The dolostones are thinly intercalated with tuffaceous shales and composed mainly of volumetrically abundant, low-ordered, subhedral to euhedral, microcrystalline dolomites with a variable amount of pyroclastics. Evidence for evaporation (e.g., the presence of halite, gypsum and shrinkage cracks) and typical methanogenic microfossils is absent. Instead, our dolostones are unevenly and locally distributed as thin beds or lenses and intercalated with tuffaceous shale and have a formation temperature ranging from 31.4 to 73.8 °C, as estimated from dolomite clumped oxygen? isotope thermometry. In addition, the dolostones have a87Sr/86Sr ratio similar to that of the mantle (0.705154 on average) and extremely negative δ18O (−2.9‰ to −24‰) and positive δ13C (5.1‰–10.8‰) values. A lateral trend of increasing formation temperature of the dolostone toward the volcanic center correlates with the trends of: 1) an increasing amount of pyroclastics, euhedral dolomite crystals, Fe, and TOC, and an increasingly positive δEu value, and 2) decreasing values of 87Sr/86Sr and δ18O. The correlation suggests that a local temperature increase and frequent elemental (Fe and Mg) cycling between the conditions of dolomite supersaturation and undersaturation, which are controlled by episodic volcanic-hydrothermal activities are the causes for dolomite nucleation and growth, resulting in the formation of massive dolostone during deposition and shallow burial. The process also affected organic matter accumulation and local transformation to immature or early mature hydrocarbon during deposition and early burial. The results establish a volcanism-controlled temperature range for primary dolomite nucleation and growth, as well as hydrocarbon generation in a deep lake environment during the period of deposition and early burial, and provide insights on shale oil exploration in petroliferous rift basins.

Geologic characteristics, exploration and production progress of shale oil and gas in the United States: An overview

We present a systematic summary of the geological characteristics, exploration and development history and current state of shale oil and gas in the United States. The hydrocarbon-rich shales in the major shale basins of the United States are mainly developed in six geological periods: Middle Ordovician, Middle–Late Devonian, Early Carboniferous (Middle–Late Mississippi), Early Permian, Late Jurassic, and Late Cretaceous (Cenomanian–Turonian). Depositional environments for these shales include intra-cratonic basins, foreland basins, and passive continental margins. Paleozoic hydrocarbon-rich shales are mainly developed in six basins, including the Appalachian Basin (Utica and Marcellus shales), Anadarko Basin (Woodford Shale), Williston Basin (Bakken Shale), Arkoma Basin (Fayetteville Shale), Fort Worth Basin (Barnett Shale), and the Wolfcamp and Leonardian Spraberry/Bone Springs shale plays of the Permian Basin. The Mesozoic hydrocarbon-rich shales are mainly developed on the margins of the Gulf of Mexico Basin (Haynesville and Eagle Ford) or in various Rocky Mountain basins (Niobrara Formation, mainly in the Denver and Powder River basins). The detailed analysis of shale plays reveals that the shales are different in facies and mineral components, and “shale reservoirs” are often not shale at all. The United States is abundant in shale oil and gas, with the in-place resources exceeding 0.246×1012 t and 290×1012 m3, respectively. Before the emergence of horizontal well hydraulic fracturing technology to kick off the “shale revolution”, the United States had experienced two decades of exploration and production practices, as well as theory and technology development. In 2007–2023, shale oil and gas production in the United States increased from approximately 11.2×104 tons of oil equivalent per day (toe/d) to over 300.0×104 toe/d. In 2017, the shale oil and gas production exceeded the conventional oil and gas production in the country. In 2023, the contribution from shale plays to the total U.S. oil and gas production remained above 60%. The development of shale oil and gas has largely been driven by improvements in drilling and completion technologies, with much of the recent effort focused on “cube development” or “co-development”. Other efforts to improve productivity and efficiency include refracturing, enhanced oil recovery, and drilling of “U-shaped” wells. Given the significant resources base and continued technological improvements, shale oil and gas production will continue to contribute significant volumes to total U.S. hydrocarbon production.

Controls and Geological Significance of Macerals in Hybrid Shales: A Case Study on the Gaoyou Sag, Subei Basin, East China.

In the Gaoyou Sag located within the Subei Basin, the hybrid shales from the second member of the Funing Formation (E1f2) have been identified as a prolific source of shale oil production, despite their characteristically low organic matter content (TOC < 1.5%). This observation suggests that specific macerals within these hybrid shales demonstrate a pronounced hydrocarbon generation potential, thus unveiling a new frontier for shale oil exploration endeavors. In this study, 16 samples were rigorously extracted from both mudstone and hybrid shale strata within the E1f2. An exhaustive suite of organic and inorganic geochemical analyses was conducted on these specimens. The analyses elucidated several key findings: (1) The maceral composition within the hybrid shales is predominantly comprised of alginite, solid bitumen, and inertinite. Remarkably, the variability of alginite content within the hybrid shales is more pronounced than that observed in high-TOC mudstones. High-TOC mudstones are characterized by a preponderance of lamalginite and a paucity of telalginite, leading to a diminished aggregate hydrocarbon potential. (2) Biomarker ratios (e.g., sterane/hopane, C23 tricyclic terpane/αβ C30 hopane, C24 tetracyclic terpane/C26 tricyclic terpane, etc.) suggest a primary derivation from lower aquatic organisms, with a secondary contribution from terrigenous organic matter within the hybrid shales. (3) The accretion of macerals is governed by an intricate set of factors, including the input of terrigenous detritus, paleosalinity, and paleoproductivity. (4) Alginite is identified as the principal constituent responsible for hydrocarbon genesis in hybrid shales. The proliferation of alginite facilitates the concurrent enrichment of shale oil and organic matter within the hybrid shales of the Subei Basin, illustrating a cooperative mechanism underlying the accumulation of shale oil and organic matter. This indicates that even hybrid shales with scant organic content exhibit considerable potential for shale oil exploration.

Paleogene-Neogene ring-shaped sedimentary system and reservoir characteristics in the Western depression of the Qaidam Basin

The Paleogene-Neogene strata in the Western Depression of the Qaidam Basin represent a primary focus for oil and gas exploration and development. Influenced by both terrigenous clastic influx and endogenic carbonate deposition, these strata exhibit significant variation in sedimentary systems and reservoir characteristics. This study comprehensively examines the depositional patterns and reservoir properties of the Paleogene-Neogene sequence across the inner, middle, and outer belts of the basin, employing core analysis, thin section petrography, and physical property assessment of reservoirs. Key findings include 1) The development of a concentric sedimentary system in the Western Depression during the Paleogene-Neogene period, characterized by increased carbonate mineral content and decreased clastic material from the periphery to the center of the basin. 2) Varied sedimentary facies associations across different zones, with the outer belt dominated by fan delta and braided river delta deposits, and the middle and inner belts characterized by near-shore shallow lacustrine carbonates and algal mat deposits, and offshore semi-to deep-lacustrine fine sediments, respectively. 3) The outer belt exhibits reservoirs with favorable physical properties and connectivity, while the inner and middle belts show high heterogeneity, indicating potential for lithological traps and shale oil exploration. These insights offer scientific guidance for further investigation into the depositional systems of lacustrine basins in the Western Depression of the Qaidam Basin and for identifying promising reservoirs.

Chemofacies characterization of lacustrine shale based on machine learning classification: A case study from the Dongying depression, Bohai bay basin, China

The rapid lithofacies transitions and compositional heterogeneities inherent in lacustrine shale posed significant challenges to accurately characterizing it, thus impeding the optimization of shale oil exploration and extraction. This study employed a multifaceted methodology to address these obstacles, integrating principal component analysis (PCA), K-means clustering, and geochemical trend analysis to precisely identify and characterize nine distinct chemofacies. A comprehensive analysis of petrological characteristics and depositional environments was accomplished by examining core samples, thin sections, scanning electron microscopy (SEM), mineralogical compositions, and total organic carbon (TOC) content. The identification of favorable locations was supported by meticulously considering variables, including TOC, porosity, permeability, and the mineral brittleness index (MBI). This investigation revealed the presence of nine distinct chemofacies within the targeted layer. Specifically, Chemofacies 5, characterized by calcite vein laminations, was identified within Unit 2 parasequence, and Chemofacies 6, enriched with feldspar-quartz mineral laminations, was located within Unit 4 parasequence. Both chemofacies exhibited elevated TOC, enhanced porosity and permeability, and favorable brittleness, qualifying them as ideal sweet spots for shale oil exploration. The insights from this study align with the characteristics of traditionally optimal reservoirs, validate the robustness of the employed methodologies, and carry significant implications for the accurate prediction of terrestrial shale oil sweet spots in future explorations.

Development characteristics and controlling mechanism of different microfracture combinations in shale reservoir: A case study of silurian longmaxi formation in Weiyuan area

Fractures in organic-rich shale are important reservoir spaces and seepage channels of shale gas, and they are closely related to the gas-bearing properties of shale. The development characteristics and laws of fractures are of great significance in the exploration and development of shale oil and gas. This study examines organic-rich shales of the Wufeng–Longmaxi Formation in the Weiyuan area of the Sichuan Basin. On the basis of two-dimensional large-area multi-scale combination electron microscopy characterization and digital core platform technology, the development degree and distribution of different fractures are quantitatively characterized. The results show the following. (1) The shale of the Wufeng and Longmaxi formations developed a variety of fractures with different occurrences, sizes, and origins. According to the number and combination relationship between fractures of different occurrences, the shale can be divided into four fracture combination types: horizontal bedding fractures; vein fractures; reticular fractures; and ring fractures. Of these, the horizontal bedding fracture group has the largest number of samples and a higher average fracture surface porosity. (2) The degree of fracture development in the shale is affected by many factors, such as the laminar type, mineral composition, mineral particle size, mineral distribution, and total organic carbon, and the controlling mechanisms of different fracture combination types differ. Factors such as horizontal stratification, high clay mineral content, and uneven mineral particle size are conducive to the development of horizontal bedding joints. (3) Differences in the sedimentary environment affect the variation laws of the vertical fracture combination types and density. The total organic carbon and organic quartz content of the Long111 layer with deeper sedimentary water is higher, and the vein fracture formation is more developed than in other small layers, while the clay mineral content of the Long112 and Long114 layers with shallower sedimentary water is higher and the horizontal layer is more developed; the fracture combination type is dominated by the horizontal bedding fracture combination. At the same time, the fractures at the junction of each layer of the Long11 sub-member are the most developed because sea level rise and fall make the mineral particle size heterogeneity most prominent at the junction of the small layer.

Paleo-Sedimentary Environment and Formation Mechanism of the Organic-Rich Shale of the Permian Lucaogou Formation, Jimsar Sag, Junggar Basin, China

The Jimsar Sag is an important shale oil exploration target area in the Junggar Basin, northwestern China. The Permian Lucaogou Formation, with a thickness of 200–300 m, is the primary exploration target. High-frequency variation in lithology is a typical feature of the Lucaogou Formation, reflecting the fluctuation of the depositional environment and organic matter enrichment. The evolution of the depositional environment and accumulation mechanism of organic matter still need to be elucidated for the Lucaogou Formation. High-resolution sampling of the entire Lucaogou Formation was applied to a 248 m long core from Well JX in the Jimsar Sag to examine the depositional environment and organic matter enrichment. The findings unveiled that the Lucaogou Formation was deposited under a hot and arid climate, within the confines of a closed saline paleo-lake, where sediments endured an extended period of anoxic conditions, displayed periodic oscillations in paleo-temperature and paleo-salinity values over time, alongside a continuous rise in paleo-water depth. The predominant source lithology of the Lucaogou Formation is felsic igneous rock. Small-scale transgression and hydrothermal sedimentation occurred during the deposition of the Lucaogou Formation. The prevailing hot climate and enduring reducing environment fostered ideal circumstances for the enrichment of organic matter in the Lucaogou Formation. Due to different sedimentary environments and enrichment mechanisms, organic matter is enriched in two modes in the Lucaogou Formation.

Coupling of Paleosedimentary Environment and Lithofacies: Implications for Shale Oil Enrichment in the Lianggaoshan Formation, Northeastern Sichuan Basin, China.

The sedimentary environment is paramount in dictating depositional processes, ecological settings, and hydrodynamic conditions, all of which are pivotal to the aggregation of organic-rich sediments. A synergistic interplay is observed among the paleosedimentary environment, lithofacies, and enrichment of shale oil. Utilizing an analysis of elemental geochemistry and organic geochemical parameters-such as total organic carbon (TOC) content-this study endeavors to identify the predominant factors that govern the enrichment of organic matter (OM). It reconstructs the evolutionary trajectory of the paleosedimentary environment and introduces a dynamic model for shale oil enrichment within the Jurassic Lianggaoshan Formation of the Sichuan Basin. The results indicate that the Lianggaoshan Formation shale can be categorized into five lithological types, including high TOC felsic-rich shale (A), moderate TOC felsic-rich shale (B), moderate TOC felsic-rich mudstone (C), low TOC felsic-rich shale (D), and low TOC felsic-rich mudstone (E), and high TOC felsic-rich shale has the highest TOC and oil content. The shales of the Lianggaoshan Formation were deposited in an environment characterized by abundant terrestrial input, humid climate, freshwater conditions, reduced oxygen levels, and thriving primary productivity. OM enrichment is mainly controlled by the combination of a humid paleoclimate, high primary productivity, and other factors. The paleoenvironment deposited by lithofacies A coincides with the paleoenvironment conducive to OM enrichment, which makes lithofacies A become the dominant lithofacies for shale oil enrichment. Additionally, the sedimentary environment evolution characteristics and shale oil enrichment model of the Lianggaoshan Formation were established based on geochemical parameters. The paleosedimentary environment of the Lianggaoshan Formation from bottom to top is more and more unfavorable. The No.1 submember of the Lianggaoshan Formation is the most potential shale submember for shale oil exploration due to the paleosedimentary environment that promoted the deposition of lithofacies A and OM enrichment.

Geochemical Characteristics of Mature to High-Maturity Shale Resources, Occurrence State of Shale Oil, and Sweet Spot Evaluation in the Qingshankou Formation, Gulong Sag, Songliao Basin

The exploration of continental shale oil in China has made a breakthrough in many basins, but the pure shale type has only been found in the Qingshankou Formation, Gulong Sag, Songliao Basin, and the evaluation of shale oil occurrence and sweet spot faces great challenges. Using information about the total organic carbon (TOC), Rock-Eval pyrolysis, vitrinite reflectance (Ro), kerogen elemental composition, carbon isotopes, gas chromatography (GC), bitumen extraction, and component separation, this paper systematically studies the organic geochemical characteristics and shale oil occurrence at the Qingshankou Formation. The G1 well, which was cored through the entire section of the Qingshankou Formation in the Gulong Sag, was the object of this study. On this basis, the favorable sweet spots for shale oil exploration are predicted. It is concluded that the shale of the Qingshankou Formation has high organic heterogeneity in terms of organic matter features. The TOC content of the source rocks in the Qingshankou Formation is enhanced with the increase in the burial depth, and the corresponding organic matter types gradually changed from Ⅱ2 and Ⅱ1 types to the Ⅰ type. The distribution of Ro ranges from 1.09% to 1.67%, and it is the mature to high-mature evolution stage that generates a large amount of normal crude oil and gas condensate. The high-quality source rocks of good to excellent grade are mainly distributed in the Qing 1 member and the lower part of the Qing 2 member. After the recovery of light hydrocarbons and the correction of pyrolytic heavy soluble hydrocarbons, it is concluded that the occurrence state of shale oil in the Qingshankou Formation is mainly the free-state form, with an average value of 6.9 mg/g, and there is four times as much free oil as adsorbed oil. The oil saturation index (OSI), mobile hydrocarbon content, Ro, and TOC were selected to establish the geochemical evaluation criteria for shale oil sweet spots in the Qingshankou Formation. The evaluation results show that interval 3 and interval 5 of the Qingshankou Formation in the G1 well are the most favorable sections for shale oil exploration.

Laminae Characteristics and Their Relationship with Mudstone Reservoir Quality in the Qingshankou Formation, Sanzhao Depression, Songliao Basin, Northeast China

Lamination is the predominant and widely developed sedimentary structure in mudstones. Similar to organic pores in shale gas reservoirs, the inorganic pores in the laminae of shale oil reservoirs are equivalently important high-quality reservoir spaces and flow channels. The laminae characteristics are strongly heterogeneous, being controlled by both deposition and diagenesis. However, the origin of this diversity is poorly understood. A detailed examination of cores, thin sections, and scanning electron microscopy analyses were conducted on the lacustrine mudstone of the Qingshankou Formation in the Songliao Basin to study the influence of deposition and diagenesis on laminae characteristics and their relationship to reservoir quality. Three types of laminae are mainly developed, namely thick siliceous laminae, thin siliceous laminae, and thin siliceous and argillaceous mixed laminae. Deposition controls the type and distribution of laminae. The thin siliceous and argillaceous mixed laminae are controlled by climate-driven seasonal flux variations. The thick siliceous laminae and thin siliceous laminae are controlled by bottom current or gravity-driven transport processes due to increased terrestrial input. The thin siliceous laminae have the optimum reservoir properties, followed by the thin siliceous and argillaceous mixed laminae, while the thick siliceous laminae have the worst properties. Diagenesis controls the pore evolution of the laminae. Different laminae have different paths of diagenesis. The thin siliceous laminae are mainly cemented by chlorite, preserving some primary porosity. The clay mineral content of the thin siliceous and argillaceous mixed laminae is high, and the primary pores are mainly destroyed by the strong deformation of the clay minerals during compaction. The thick siliceous laminae are intensely cemented by calcite, losing most of the porosity. The present study enhances the understanding of reservoir characteristics in laminae and provides a reference for shale oil exploration.

Visualization of dynamic micro-migration of shale oil and investigation of shale oil movability by NMRI combined oil charging/water flooding experiments: A novel approach

Investigating the micro-migration processes of hydrocarbons within interbedded shale reservoirs, and quantitatively characterizing the movability of shale oil, are highly important for the exploration and development of continental shale oil. However, due to complex pore-fracture structures, the characterization of the micro-migration and movability of shale oil presents significant difficulties, and the lack of suitable technology restricts the understanding of shale oil accumulation mechanisms and the evaluation of movability. This study employs nuclear magnetic resonance imaging (NMRI) technology in conjunction with oil charging and water flooding experiments, to innovatively visualize and quantitatively characterize the dynamic micro-migration features and movability of hydrocarbons within the pore-fracture structures of shale. The results indicate a significant increase in oil saturation within the interbedded shale oil reservoir during the oil charging process, with the oil phase primarily accumulating in larger pores (T2 = 1–100 ms). The micro-migration and accumulation process of interbedded shale oil can be divided into three stages: the initial stage dominated by water phases in the pore spaces due to insufficient oil filling pressure, the intermediate stage marked by a rapid increase in hydrocarbons in the pore spaces, and the final stage where oil fills the entire pore system resulting in high oil saturation. The movability of different types of shale oil during water flooding varies significantly and is mainly influenced by pore-fracture structures. Interbedded shale oil reservoirs with larger pores exhibits a higher movable oil saturation (approximately 36.94%), while matrix-type shale oil reservoirs shows greater heterogeneity and lower fluid movability (approximately 14%). However, the shale oil movability of matrix-type shale oil reservoir with developed microfractures can reach 40%. More specifically, the fluid movability in smaller pore-microfracture structures (T2 < 0.5 ms) is as high as 56.88%, surpassing that in larger pores (T2 > 0.5 ms) (32.78%). Larger pores and microfractures substantially enhance the movability of hydrocarbons in the shale matrix, thus improving shale oil recoverability. In contrast, due to the higher capillary pressure (Pc) and flow resistance (Pv), smaller pores contribute less to the movability of shale oil. Overall, the outcomes of this study not only advance our understanding of the micro-migration and accumulation patterns of interbedded shale oil but also offer new insights for geological and engineering integration research on shale oil.