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Evaluating residual hydrocarbons is crucial for assessing shale oil and gas reservoirs, significantly impacting resource evaluation and exploration prospects. Previously regarded as lacking hydrocarbon generation potential, the Ediacaran Dengying Formation (Fm) microbial dolomite in the Sichuan Basin has been re-evaluated for its hydrocarbon generation capabilities. While understanding source rock characteristics is vital for petroleum resource assessment, a comprehensive analysis of the dolomite's source rocks, encompassing hydrocarbon generation and residual features, remains undocumented. In this study, we thoroughly analyze the total organic carbon and vitrinite reflectance and extensively utilize pyrolysis analysis, gas chromatography and isotopic analysis of the organic kerogen from the Ediacaran Dengying Fm dolomite samples. The findings affirm that the Ediacaran Dengying Fm dolomite indeed serves as a source rock with moderate hydrocarbon generation and residue capabilities. This microbial dolomite was formed in a reducing marine environment with high salinity. Characterized by an averaging TOC of 0.82%, the kerogen is primarily identified as type I, with a minor presence of type II, and underwent thermal maturation up to the post-maturity stage. Throughout its geological history, the maximum intensities for hydrocarbon generation and residues were 4.5 × 107 t/km2 and 3.2 × 107 t/km2, respectively. Additionally, cumulatively generated and residual hydrocarbon quantities amounted to 2.7 × 1012 t and 1.67 × 1012 t, respectively. This study indicates significant exploration potential for the Ediacaran Dengying Fm microbial dolomite. Consequently, the central region in the Sichuan Basin has been identified as a promising area for future exploration endeavors. Our study provides valuable insights for the understanding of shale gas exploration in high-maturity source rock areas. [ABSTRACT FROM AUTHOR]

Hydrocarbon potential evaluation is a high priority in oil/gas exploration which is significantly influenced by evaluation methods and subjective cognition. With the aim of quantitatively establishing a hydrocarbon generation and expulsion (HGE) model of source rocks, a data-driven approach is proposed based on abundant and readily available Rock-Eval/total organic carbon content (TOC)/vitrinite reflectance (VRo) datasets. This approach takes into account the original hydrocarbon generation potential (GPIo) and the loss of TOC. Hydrocarbon generation simulation was also adopted in this study. This data-driven method was applied to the Lower Paleogene Shahejie Formation (Es4), which has three sets of superior source rocks (average thickness > 250 m, TOC > 3%). The GPIo of the Es4 low-maturity source rock was 600 mg HC/g TOC. The initial maturity values of hydrocarbon generation and expulsion were 0.36% and 0.46%, respectively. The Gaosheng sub-member of the Es4 source rock had the largest amount of hydrocarbon generation but a limited amount of hydrocarbon expulsion, implying a favorable exploration of shale oil resources. By contrast, the values of the conventional, unconventional tight, and shale oil resource potentials of the Niuxintuo sub-member were 3.20 × 107, 7.70 × 107, and 5.93 × 108 t, respectively, indicating good prospects for tight oil and shale oil exploration. A comparison between the previous method and the data-driven method showed considerable differences in the restoration of GPIo and TOC, and both had their own limitations. This data-driven approach provides a quick and valid source rock evaluation method and can greatly enhance the accuracy of resource assessment. [ABSTRACT FROM AUTHOR]

Gas-bearing property evaluation and main controlling factor analysis have remained a concern in shale gas research. The application of principal component analysis, an important mathematical statistical method, in gas-bearing property evaluation and main controlling factor analysis of the Longmaxi shale in the Weirong area, Sichuan Basin, was examined. The Longmaxi shale exhibits high heterogeneity, manifested in the organic matter abundance, mineral composition, and pore structure. Seven geological factors, including the temperature, pressure, TOC content, clay content, brittle mineral content, pore volume, and specific surface area (SSA), were selected in principal component analysis. Four principal components with geological significance, such as mineral composition, formation condition, pore structure, and organic matter abundance, were extracted through principal component analysis, and further constituted a comprehensive factor. Shale gas-bearing properties were evaluated according to the score of the comprehensive factor. The Longmaxi shale could be identified as exhibiting good, medium, and poor gas-bearing properties based on the comprehensive factor scores of these samples. According to each geological factor's contribution to the comprehensive factor, combined with geological analysis, it could be considered that gas-bearing properties are primarily controlled by pore volume, SSA, and clay content, followed by TOC content, brittle mineral content, temperature and pressure. [ABSTRACT FROM AUTHOR]

Abstract Shale oil has gradually become the predominant target for unconventional hydrocarbon exploration in recent years. Unlike marine shales that have been extensively studied, lacustrine shales are not adequately characterized in the literature. In this study, we examined Shahejie Formation shales in the Nanpu Sag in the Bohai Bay Basin of China, and performed organic geochemistry, mineralogy, scanning electron microscopy (SEM), and N 2 and CO 2 gas adsorption analyses. The results show that the Shahejie shale can be divided into four lithofacies: siliceous shale, calcareous shale, argillaceous shale, and mixed shale. Calcareous shale was deposited in deep lacustrine environment, and usually has the highest total organic carbon (TOC) content with type I kerogen. Mixed shale, which was deposited in the transitional zone, has moderate TOC values. Argillaceous shale and siliceous shale were deposited in shallow lacustrine environment or near shore, and always have the lowest TOC values. Inorganic mineral pores are the dominant type of pore in all four shale groups. Argillaceous shale has a large amount of intraparticle pores with low average pore size and poor connectivity compared with calcareous shale. Limited organic matter pores are present in low matured lacustrine shales, whereas the porosity of some lacustrine shales may increase due to the occurrence of large number of organic pores leading to significant increase of total porosity. Micro-fissures within calcareous shale greatly improve reservoir quality. Overall, siliceous shale and argillaceous shale usually have low TOC, low residual hydrocarbon, relatively strong adsorption capacity, and poor connectivity of pores, which contain little free oil and are unfavorable for shale oil exploration. Calcareous shale has high TOC, high residual hydrocarbon, large pore size, and excellent fracturing nature, and should be the best target for lacustrine shale oil exploration. Highlights • Pore characterization in an argillaceous-siliceous-calcareous shale system was studied. • Inorganic mineral pores play the dominant role in the micro- and mesopores of lacustrine shales with low maturity. • Calcareous shale is the most favorable target for shale oil exploration. [ABSTRACT FROM AUTHOR]

Large shale oil resources were recently been found in lacustrine organic-rich shale with strong heterogeneity, however, few studies have been conducted to examine their oil contents, resulting in considerable risks in lacustrine shale oil exploration. The Middle Permian Lucaogou Formation (P 2 l) shale in Jimusaer Sag is a typical lacustrine deposit with strong heterogeneity, and its shale oil resource shows great potential. Integrated geochemical characterization of 265 core samples were conducted and results show that the P 2 l shale developed in an anoxic lacustrine with stratified salty water and the organic matter in the upper sub-member shale of the P 2 l is more oil-prone than that in the lower sub-member shale of the P 2 l. The hydrocarbon generation potential of the P 2 l shale decreases with the kerogen types changing from Type I to Type III, however, the residual hydrocarbon contents of the P 2 l shale increases from Type I to II 1 kerogen, and then decreases from Type II 1 to III kerogen, this is mainly due to differentiated hydrocarbon expulsion efficiencies among different kerogen types. Based on S 1 and TOC values and the S 1 /TOC ratios, considering the oil enrichment degree, this study classified the shale oil resources in the P 2 l shale into four categories: enriched, moderately enriched, less efficient, and invalid resources. The enriched and moderately enriched resources are mainly shales with Type II 1 kerogen, followed by Type II 2 kerogen, and the middle interval of the Lower P 2 l shale is the most favourable target for further shale oil exploration. The improved evaluation criteria are applicable for evaluating shale oil plays with strong heterogeneity qualitatively and quantitatively in terrestrial lacustrine basins in other parts of the world. [ABSTRACT FROM AUTHOR]

Jurassic strata along the southern margin of Junggar Basin are important petroleum system elements for exploration in northwest China. The Lower and Middle Jurassic source rock effectiveness has been questioned as exploration progresses deeper into the basin. These source rocks are very thick and are distributed widely. They contain a high total organic carbon composed predominantly of Type III kerogen, with some Type II kerogen. Our evaluation of source rock petroleum generation characteristics and expulsion history, including one-dimensional basin modeling, indicates that Jurassic source rocks are gas prone at deeper depths. They reached peak oil generation during the Early Cretaceous and began to generate gas in the Late Cretaceous. Gas generation peaked in the Paleogene-Neogene. Source rock shales and coals reached petroleum expulsion thresholds at thermal maturities of 0.8% and 0.75% vitrinite reflectance, respectively, when the petroleum expulsion efficiency was ∼40%. The petroleum generated and expelled from these source rocks are 3788.75 × 108 and 1507.55 × 108 t, respectively, with a residual 2281.20 × 108 t retained in the source rocks. In these tight reservoirs, a favorable stratigraphic relationship (where tight sandstone reservoirs directly overlie the source rocks) indicates short vertical and horizontal migration distances. This indicates the potential for a large, continuous, tight-sand gas resource in the Lower and Middle Jurassic strata. The in-place natural gas resources in the Jurassic reservoirs are up to 5.68 × 1012 − 15.14 × 1012 m3. Jurassic Badaowan and Xishanyao coals have geological characteristics that are favorable for coal-bed methane resources, which have an in-place resource potential between 3.60 × 1012 and 11.67 × 1012 m3. These Lower and Middle Jurassic strata have good shale gas potential compared with active US shale gas, and the inferred in-place shale gas resources in Junggar Basin are between 20.73 × 1012 and 113.89 × 1012 m3. This rich inferred conventional and unconventional petroleum resource in tight-sand, coal-bed, and shale gas reservoirs makes the deeper Jurassic strata along the southern margin of Junggar Basin a prospective target for future exploration. [ABSTRACT FROM AUTHOR]

Lacustrine shale oil resources are abundant and play important roles in maintaining a sustainable economy. The uncertainty in the movable oil content of organic-rich shales with strong heterogeneity is the greatest risk in their exploration. Various methods exist for movable oil content evaluation, but they present many challenges, especially insufficient accuracy, complicated test procedures, high costs, and limited application. In this study, an extensive review of the theories, techniques, and methods of movable oil content evaluation and their merits and demerits for lacustrine shales were conducted. Then, taking the lacustrine shale of the Paleogene Shahejie Formation (50.5–33 Ma) of the Dongpu Depression, Bohai Bay Basin, as an example, the multi-step Rock-Eval pyrolysis method combined with light hydrocarbon calibration was utilized to evaluate the movable oil content Subsequently, key factors controlling movable oil content were investigated, including organic matter richness, type, and thermal maturity, quartz content, clay mineral content, pore volume, and specific surface area. Both the systematic cluster analysis results and regression standardization coefficients indicate that the total organic carbon content, pore volume, and specific surface area are the main controls on movable oil content. Finally, a quantitative estimation model for movable oil content was established and validated using a statistical product and service solutions modeling. This study improves the understanding of shale oil enrichment laws and provides a novel and practical quantitative model for movable oil content estimation in lacustrine organic-rich shales across the world. [ABSTRACT FROM AUTHOR]

Saline lacustrine shales are widely developed in the Es3 strata of the Dongpu Depression. Recently, a high-yield oil flow from the upper sub-member of Es3 (Es3U) of the PS18-1 well first confirmed the presence of shale reservoirs. However, the detailed difference of geochemistry, hydrocarbon generation potential, and reservoir quality between the upper (Es3U), middle (Es3M), and lower (Es3L) sub-members of Es3 saline shales remained unclarified. Both geochemical and petrophysical analyses were performed to answer above questions in this study. The results indicate that compared with Es3U and Es3M shales, Es3L shale has a higher TOC content (mean 1.94%). Oil-prone type I-II kerogen is the main kerogen type of Es3U and Es3L shales, while Es3M shale is dominated by type II-III kerogen. Es3L shale shows a relatively higher original hydrocarbon generation potential (mean 10.26 mg HC/g Rock) with an average original total organic carbon (TOC o) value of 1.62%, and a higher generated hydrocarbon (Q HC) than other two sets of shales. Compared with the dual organic matter source of marine and terrestrial organisms of Es3M shales, the main organic matter of Es3U and Es3L shales derived from aquatic organisms, and developed in saline water and brackish–saline water, respectively, with strong reducing environment. Organic-matter pores are undeveloped in Es3 shales, whereas interparticle and intraparticle pores are easily to be found. Higher brittle minerals are found in Es3U and Es3L shales, which are beneficial to form fracturing fractures during the development process, and widely developed bedding plane fractures can provide good conditions for hydrocarbon migration. Based on discussion, Es3L shales with present-day TOC over 1.5%, higher brittle minerals and gypsum salt around can be considered to be the most promising area for further shale oil exploration in the northern Dongpu Depression. • Difference of saline shale geochemical and petrophysical characteristics was compared. • Es3 shales deposited in a strong reducing to reducing environment. • TOC r of 0.4% and 1.5% are threshold of effective and high-quality source rocks, respectively. • Es3L shale with higher S 2o , producible oil content, brittle minerals and gypsum-salt surrounding is favorable for exploration. [ABSTRACT FROM AUTHOR]

Evaporative loss of light hydrocarbons during shale core collection and sample preparation makes it challenging to characterize hydrocarbon retention and accurately evaluate petroleum resources in a shale layer with high thermal maturity. Here, semi-open system pyrolysis experiment was applied to investigate the evolution of hydrocarbon in shales during thermal maturation, using an immature lacustrine shale with total organic carbon (TOC) of 2.13 wt% from the Es 3 Member in Dongpu Depression, Bohai Bay Basin, China. Moreover, Ro measurement, solvent extraction, kinetic study, open-system pyrolysis, thermovaporization-gas chromatography (Tvap-GC) and pyrolysis-gas chromatography (Py-GC) were also conducted on the products from semi-open system pyrolysis experiments. Retained oil in shales consists of free oil (pyrolysis S1) and sorbed oil (involved in pyrolysis S2). A preponderance of sorbed oil retained in the studied lacustrine shale is observed, with its content reaching to more than 4 times larger than that of free oil at a given thermal maturity. As thermal maturity increases, molecular weights of n- alkanes in free oil show a more obvious reduction than sorbed oil. In addition, compared to sorbed oil, free oil is more likely to be retained at higher thermal maturity. Despite of the larger oil generation potential than gas of the immature shale sample, residual hydrocarbon generation potential of heated lacustrine shales is dominated by gaseous hydrocarbon, and consists of >90% of the potential losses before entering into gas window. Change of TOC in lacustrine shales, which roughly characterizes hydrocarbon generation process, is attributed to both the loss of hydrocarbon generation potential and the formation of pyrobitumen. Although hydrocarbon retention in shales is affected by many complex processes and is controlled by various factors, it can be virtually considered as a status when hydrocarbon generation, expulsion and retention during thermal maturation come to a balance. A "retention ratio (RR)" index is thus suggested in this study, based on experimental results from semi-open system and open-system pyrolysis. Application of RR in resource evaluation in a shale play is reasonable especially in high-mature shales, because evaporative loss of light hydrocarbon is considered in this method. • Sorbed hydrocarbon dominates retained hydrocarbons in lacustrine shales. • Oils in free phase tend to be retained at higher maturity than those in sorbed phase. • Compositional changes of free and sorbed oil follow different paths during thermal maturation. • Suggest an "RR" index to estimate retained hydrocarbon in shales. [ABSTRACT FROM AUTHOR]

Evaluating absorbed gas content (AGC) in shales is crucial for accurately characterizing shale gas reservoirs and calculating resource potential. To investigate geological factors influencing AGC, 15 shale samples collected from the Yanchang Formation underwent related experiments. Then geochemistry features, mineral compositions, pore structure parameters and external factors were analyzed. The actual AGC was calculated using the Langmuir equation. Single geological factors acting on the AGC were discussed by the single-factor correlation analysis. Finally, four main influence factors (total organic carbon, S1, quartz content and formation temperature) were selected out from the 12 influence factors to establish the mathematical prediction model through the multi-factor regression statistical analysis method using SPSS software. The model was verified as being reliable with R2 as high as 0.8046 and relative error less than ±20%. Comparisons show that both the CH4 isothermal adsorption experimental method and the multi-factor regression analysis method have their own applicability and disadvantages, and they can complement each other in evaluating AGC in shales. Synthetic evaluation of AGC indicates that the Yanchang shale has an overall moderate AGC occupying about 58% of the total, which is helpful to extend shale gas production time of the Yanchang reservoir. Though under the present conditions, economic benefits of the continental shale gas are not obvious, the shale resource potential of Yanchang formation can't be ignored. [ABSTRACT FROM AUTHOR]

[Display omitted] • The formula of the 2D molecular kerogen (Nanpu shale) structure was C 199 H 240 O 20 N 6 S 2. • The kerogen is a network composed mainly of aliphatic and aromatic structures. • At over 5000 K (250 ps), kerogen pyrolysis is less affected by temperature. • H 2 O and H 2 yields are temperature sensitive, CO 2 yield is less affected by temperature. Shale can be both a source rock and a reservoir rock, which is a typical self-generating and self-storing type of oil accumulation. Its main organic component is kerogen. Using molecular dynamics (MD), a realistic kerogen molecular structure model is an alternative to experimental and analytical-only approaches for studying shale organic matter's microscopic properties. Therefore, it is useful to establish an average molecular structure model for shale kerogen. Moreover, the pyrolysis mechanism of shale kerogen is of great significance for developing and utilizing shale mineral resources. In this study, geochemical and spectroscopic measurements such as the elemental analysis, 13C nuclear magnetic resonance spectroscopy (13C NMR), Fourier transform infrared spectroscopy (FTIR), and X-ray photoelectron spectroscopy (XPS) were used to obtain information about the carbon skeleton, aliphatic structures, and aromatic structures of the kerogen. Following information analysis and molecular fragment splicing, a 2D molecular structure model of kerogen from the Nanpu shale, with the chemical formula C 199 H 240 O 20 N 6 S 2 and molecular weight of 3096 Daltons was constructed. After that, the accuracy of the 2D structure was verified by comparing the 13C NMR spectra simulated by the 2D structure to the experimental spectra. Using MD simulation, based on the kerogen density, 10 2D structures are then combined to create a realistic 3D molecular structure model of kerogen. Finally, pyrolysis analysis was performed based on the established 3D molecular structure model of kerogen to determine the effect of temperature on pyrolysis. Using the advantages of various technologies, this study not only provides a systematic method for establishing a realistic 3D molecular structure model of kerogen but also contributes to in-depth research on the reaction mechanism of kerogen pyrolysis, providing a reliable foundation for future research on the properties of shale at the molecular scale. [ABSTRACT FROM AUTHOR]

Abstract: In the prolific Zhanhua Depression of the Bohai Bay Basin, eastern China, over 76% of the proven petroleum reserves occur in the Neogene Guantao and Minhuazhen formations. Detailed geological and geochemical mapping of the Phanerozoic strata in this area reveals that oil shales and dark mudstones in the Es4, Es3 and Es1 members of the Eocene–Oligocene Shahejie Formation have excellent potential as petroleum source rocks. Regional distributions of total organic carbon content, kerogen type and thermal maturation indicate that abundant mature source rocks are present in several discrete sag areas bounded by extensive basement-related fault networks. In contrast, source rocks along the paleo-topographic highs are currently immature with respect to the generation of conventional oils. This study examined the key molecular characteristics for the common isoprenoid, hopanoid and steroid biomarkers, in relation to source facies variations in lacustrine sediments. The hydrocarbon source potential and expulsion efficiency for each of the source rock units were evaluated, which integrated the source rock characteristics with regional thermal subsidence and sediment burial. An important observation made during this study is the striking contrast between the source potential and proven oil reserves within each stratigraphic section, illustrating how significant the migration of hydrocarbon fluids derived from deep mature source kitchens through over 2000 m of fine-grained formations must have been to form several giant oil accumulations in the shallow strata. These results support the concept of the “Neogene fault-fracture mesh petroleum plays” proposed by Zhang et al. (2004) [Marine & Petroleum Geology, 21, 651–668] and the vital role that the faults and fracture systems have in controlling hydrocarbon migration conduits and accumulation habitat in this rift basin. [Copyright &y& Elsevier]