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Shale oil and gas are currently the major fields of unconventional hydrocarbon exploration and development. The Fengcheng Formation (FF) shale in the Mahu Sag of the Junggar Basin is an alkaline lacustrine organic-rich shale with an extremely prospective shale oil potential. However, its strong heterogeneity and complex pore structure greatly influence the development of shale oil. It is significant to investigate the pore and geochemical characteristics of shale reservoirs for shale oil extraction. In this study, the pore structure and geochemical characteristics of FF have been investigated using core analysis, Rock-Eval pyrolysis, X-ray diffraction (XRD), field-emission scanning electron microscopy (FE-SEM), mercury injection capillary pressure (MICP), low-temperature gas adsorption (LTGA), and X-ray computed tomography (X-ray CT). The results show that the shale of FF has moderate organic matter abundance, and the kerogen is mainly of Type II, which is now at the peak of oil generation. Shale minerals are mainly composed of carbonate (dolomite and calcite) and siliceous (quartz and feldspar) minerals, with extremely low clay mineral content. The pore types are mainly intergranular pores (inter-P), intragranular pores (intra-P), and microfractures associated with mineral particles. The pore space is contributed predominantly by micropores of 0.5–1.2 nm and mesopores of 10–50 nm, whereas macropores are underdeveloped. The pores are mostly ink bottle- and slit-shaped, and the pore connectivity is relatively poor. The pore development of shale in the FF is influenced by organic matter abundance, thermal maturity, mineral composition, etc. Organic matter content (TOC), thermal maturity (Ro), and carbonate minerals have a positive effect on pore development, and the pore volume (PV) increases with TOC, Ro, and carbonate minerals. While clay minerals show a negative effect, the PV decreases with clay minerals. Additionally, the influence of the clay mineral content on the pore morphology of shale should not be ignored. This study investigates the pore structure and geochemical characteristics of the alkaline lacustrine shale of FF in Mahu Sag, which is significant to deepen the understanding of alkaline lacustrine shale and to improve the production of shale oil. [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]

The fine-grained rocks in the Paleogene Shahejie Formation in Nanpu Sag, Huanghua Depression, Bohai Bay Basin, are extremely important source rocks. These Paleogene rocks are mainly subdivided into organic-rich black shale and gray mudstone. The average total organic carbon contents of the shale and mudstone are 11.5 wt.% and 8.4 wt.%, respectively. The average hydrocarbon (HC)-generating potentials (which is equal to the sum of free hydrocarbons (S1) and potential hydrocarbons (S2)) of the shale and mudstone are 39.3 mg HC/g rock and 28.5 mg HC/g rock, respectively, with mean vitrinite reflectance values of 0.82% and 0.81%, respectively. The higher abundance of organic matter in the shale than in the mudstone is due mainly to paleoenvironmental differences. The chemical index of alteration values and Na/Al ratios reveal a warm and humid climate during shale deposition and a cold and dry climate during mudstone deposition. The biologically derived Ba and Ba/Al ratios indicate high productivity in both the shale and mudstone, with relatively low productivity in the shale. The shale formed in fresh to brackish water, whereas the mudstone was deposited in fresh water, with the former having a higher salinity. Compared with the shale, the mudstone underwent higher detrital input, exhibiting higher Si/Al and Ti/Al ratios. Shale deposition was more dysoxic than mudstone deposition. The organic matter enrichment of the shale sediments was controlled mainly by reducing conditions followed by moderate-to-high productivity, which was promoted by a warm and humid climate and salinity stratification. The organic matter enrichment of the mudstone was less than that of the shale and was controlled by relatively oxic conditions. [ABSTRACT FROM AUTHOR]

Pore development and the location of retained hydrocarbons are key topics to understand the shale oil system. In an attempt to investigate pore network characteristics and oil retention in lacustrine shales, 24 samples from the Es 3 shales in the Dongpu Depression, Bohai Bay Basin were subjected to mineralogical, petrological, geochemistry and pore structure investigations using X-ray diffraction (XRD), thin section, field emission-scanning electronic microscope (FE-SEM), N 2 adsorption-desorption. After removing retained oil by solvent extraction, 12 selected samples were again analyzed by Rock-Eval pyrolysis and N 2 adsorption-desorption experiment. According to the mineral compositions and petrological characteristics, six types of lithofacies are identified in the Es 3 shales in the Dongpu Depression: laminated calcareous shales, lenticular calcareous shales, laminated argillaceous shales, massive argillaceous shales, laminated siliceous shales, and massive siliceous shales. Geochemical characteristics of these shales are quite different, as calcareous/laminated shales have higher TOC contents than massive argillaceous and siliceous shales. Interparticle pores, intraparticle pores, organic matter pores and fracture pores are observed in the studied samples, while bitumens were found retaining in well-connected pore network. The N 2 adsorption-desorption experiments on samples before and after solvent extraction reveal the different pore structure characteristics in six lithofacies and the occurrence of oil in lacustrine shales. In general, pore volumes within pore diameter range of 1.7–10nm and 10–200nm of samples show increase after solvent extraction, indicating that large and small pores in shales both play important roles in oil retention. Oil retained in shales can be divided as free and heavy fractions, as from the pyrolysis results. In lacustrine shales, larger pores are main storage space for hydrocarbon. Larger pores in different lithologies have similar capacity for free oil retention, while those in calcareous and argillaceous shales are more efficient for heavy oil retention. For both free and heavy oil, small pores in argillaceous shales are efficient for their storage. [ABSTRACT FROM AUTHOR]

[Display omitted] • Mesopores are the most developed in the over-mature Longmaxi shale. • The contribution of OM pores to pore area increases with increasing TOC content. • The clay mineral pores contribute the most pore area and volume in OM-poor shale. Pore types significantly affect the pore properties of shale reservoirs, but their contribution to shale pore space in over-mature marine shale remains controversial because organic and inorganic pores fail to be quantitatively characterized. In this study, mercury intrusion porosimetry, low-temperature N 2 and CO 2 adsorption, and image analysis were conducted on over-mature marine shale in the Lower Silurian Longmaxi Formation to quantify the contribution of pore types to pore volume (PV) and surface area (SA). The full-scale pore size distribution of over-mature shale indicates that mesopores account for the largest PV, while macropores are developed in organic matter (OM)-poor shale. By analyzing the influence of multiple factors and heterogeneity of different pore types, OM pores, pyrite framboid pores, clay mineral pores, and dissolution pores are identified as dominant types in OM-poor/moderate/rich shale. The PV and SA of these four pore types are quantitatively characterized by extracting parameters of shale components and pores using image analysis. In OM-poor shale, clay mineral pores contribute the most to the PV and SA, followed by OM pores and dissolution pores, and finally pyrite framboid pores. In OM-rich/moderate shale, the contribution of OM pores to the PV and SA is dominant and increases with the increasing total organic carbon content. The evolution of pore types throughout the maturation sequence is revealed based on previous studies. Especially at the over-mature stage, clay mineral pores contribute the most to pore space in OM-poor shale, while OM pores make a major contribution to pore space in OM-rich/moderate shale. [ABSTRACT FROM AUTHOR]

The wettability of rock affects the interaction between CO 2 , brine, and shale formation, which affects CO 2 sequestration with enhanced gas recovery (CS–EGR) project. However, under reservoir conditions, there is limited research on the surface wettability of shale organic matter, and its internal interaction mechanism is unclear. In this study, the effects of temperature, pressure, mineralization, and concentration ratio of CO 2 to CH 4 on the contact angle were studied using molecular dynamics (MD), and the results were compared with the previous experimental data. Under a certain pressure, the water wettability increases with the increase in temperature. At a fixed temperature, the contact angle of water on graphene increases with the increase of CO 2 pressure. Above the critical pressure, water at different temperatures is wetted by CO 2 on the surface of graphene, and the wettability reversal occurs. The water wettability decreases with the increase in solution salinity. Under the same concentration of droplets, Mg2+ and Ca2+ have a greater effect on the wetting angle than Na+. The adsorption capacity of the graphene surface for CO 2 is stronger than that of CH 4. Finally, the order of wettability is verified by interaction energy. This study will contribute to alleviating the greenhouse effect. • The influencing factors of wettability were studied by molecular dynamics. • This study will help to optimize the design of CS–EGR technology. • Temperature, pressure, and CO 2 /CH 4 concentration ratio affect the contact angle. • On the micro level, the order of wettability is verified by interaction energy. [ABSTRACT FROM AUTHOR]

Nitrogen and oxygen (NO) compounds are important compositions in shale source rocks, and they carry an abundance of geochemical information for hydrocarbon generation. Due to technical limitations, the significance of NO compounds has not been paid enough attention. In this paper, the NO compounds from shale rocks of the Dongpu Depression are analyzed to explore the compositional characteristics and geochemical significance of using geological and organic geochemical ways of rock-eval, gas chromatography-mass spectrometry (GC/MS), and Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS). The results show that shale rocks are rich in NO compounds, with twelve types of compounds that were detected: N1, N1O1, N1O2, N1O3, N1S1, N1S2, N2O1, O1, O2, O3, O3S1, and O4. Of these compounds, O2 and O3 predominated, followed by N1 and N1O1. Of the N1 species, the most abundant classes are DBE of 9, 12, 15, and 18, which changed with maturity. Of the O2 species, compounds of DBE of 1 (fatty acids) are the predominant class. Classes of DBE 5 and 6 in the O2 species are naphthenic acids with special biological skeleton structures, which are usually appear in immature and low-mature oils. N1, O2, and N1O1 compounds are affected by their maturity and they often run to polarization with enhanced DBE species and a shorter carbon chain as their maturity increases. The parameters of DBE18–25/DBE9–18-N1 and DBE12–20/DBE5–12-O2 increase with the increase of buried depth and maturity. The NO compounds that were revealed by FT-ICR MS may have a promising application in distinguishing between the different depositional environments. Source rocks of saline lacustrine are rich in O2 and N1O1, but less N1 and O1 compounds. The research results are of vital importance for expanding the application of the NO molecular compounds in petroleum exploration. [ABSTRACT FROM AUTHOR]

The decline of proven conventional petroleum resources in the shallow portions of the Nanpu sag has shifted attention to the exploration of deep unconventional oil and gas resources there, especially the shale oil resources in the middle Eocene shales of the Shahejie Formation (MES shales). In this study, to assess the oil potential of the MES shales, we carried out a systematical geochemical and basin modeling characterization. The results show that the MES shales have low maturity and are at the early stage of hydrocarbon generation, with a mean vitrinite reflectance of 0.64% and low ratio of C 27 18α(H)-22, 29, 30-trisnorneohopane to C 27 17α(H)-22, 29, 30-trisnorhopane (0.44–1.18). The MES shales contain abundant organic matter (OM), with an average total organic carbon content of 2.21 wt %. Biomarker analyses show that the OM in the MES shales derived mainly from floating macrophyte and aquatic algae, microalgae and bacteria. The sapropelinite group in the MES shales is predominant in the organic macerals, and the kerogen is sapropelic and dominated by types I and II 1. Biomarker analyses also reveal that the MES shales were deposited in the stratified water column as suggested by the presence of gammacerane, under relatively warm and wet climatic conditions. The anoxic conditions built up in the water column facilitated the OM preservation, although slight microbial degradation resulted in relatively high carbon preference index values. Modeling results based on geochemical data and basin analyses show that considerable quantities of hydrocarbons remain in the low-maturity MES shales. The preliminary estimate of the quantity of shale oil resources in the Gaoliu area of Nanpu sag is approximately 1.78 × 108 t. Nanpu sag have good shale oil potential, and shale oil exploration may be more feasible for MES shales, especially in the context of in-situ heating technology. • Middle Eocene Shale in Nanpu Sag of the Bohai Bay Basin are typical early mature. • MES shale deposited under a warm and wet climate with slight microbial degradation. • Middle Eocene lacustrine shale in Nanpu Sag contains good shale oil potential. [ABSTRACT FROM AUTHOR]

In recent years, significant progress and breakthroughs have been made in the exploration of conventional and unconventional natural gas in the Lower Cambrian petroleum system in the Sichuan Basin in Central China, showing excellent exploration prospects. However, detailed evaluation of the Qiongzhusi shale, the main source rocks in the Lower Cambrian petroleum system, including their hydrocarbon generation and expulsion characteristics, is lacking, even though such evaluation is critical for understanding conventional and unconventional natural gas resource potential. To investigate the geological and geochemical characteristics of the Qiongzhusi shale, experiments including pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) were conducted. Based on modeling work and fluid inclusion analysis, the hydrocarbon generation and expulsion characteristics of the Qiongzhusi shale and their control on hydrocarbon accumulation was analyzed, and the conventional and unconventional natural gas resource potential of the Lower Cambrian petroleum system was systematically evaluated. The results indicate that the organic matter of the Qiongzhusi shale is mainly derived from bacteria and algae deposited in a saline, reducing marine environment. The shale is predominantly composed of type I kerogen with an average TOC value of 1.85 wt%, and is widely distributed in the basin with an average thickness of 212.7 m. The Qiongzhusi shale is primarily post-mature with an average vitrinite reflectance (Ro) of 2.53%. Modeling work suggests the Qiongzhusi shale reached the hydrocarbon expulsion threshold (HET) at Ro = 0.9%, and the main hydrocarbon expulsion stages are Triassic, Jurassic, and Cretaceous. The maximum hydrocarbon generation and expulsion intensities at present day are 32 × 106 t/km2 and 18 × 106 t/km2, respectively. The conventional natural gas resource potential of the Longwangmiao Formation derived from the Qiongzhusi shale is estimated to be between 9.51 × 1012 m3 and 19.03 × 1012 m3. The unconventional shale gas resource potential of the Qiongzhusi shale is predicted to be 1.4 × 1012 m3, showing significant prospects for natural gas exploration. • Geochemistry characteristics of the Qiongzhusi Formation were systemically evaluated. • Hydrocarbon generation and expulsion characteristics of the Qiongzhusi Formation were first analyzed. • Conventional and unconventional natural gas resource potentials of ancient Lower-Cambrian petroleum system were calculated. [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]

Almost 70 years after shale oil was first studied, "self-souring" was widely regarded as an essential feature of shale oil. Recently, micromigration, which is a bridge connecting hydrocarbon generation, expulsion and enrichment in shale, has been discovered and confirmed as shale oil exploration deepens. However, due to strong heterogeneity, quantitative evaluation of hydrocarbon micromigration in shale remains unclear, making scientific understanding of shale oil enrichment mechanisms highly challenging. Based on the mass balance principle, we provide a quick and novel method to quantify hydrocarbon micromigration with the most commonly available geochemical data from Rock-Eval/total organic carbon (TOC) analysis by subtracting the real hydrocarbon generation potential (HGP R) from the original hydrocarbon generation potential (HGP O). The HGP R is calculated from pyrolysis parameters after light hydrocarbon calibration. Based on a kerogen kinetic theory, the HGP O is restored by utilizing a data-driven model with IBM-SPSS statistics. The results show that the Fengcheng Formation (P 1 f) shale features medium TOC contents, mixed kerogen types, mature to overmature levels, and high oil contents. Sixty-five percent of the P 1 f shale samples exhibit hydrocarbon intramicromigration, while the rest exhibit hydrocarbon extramicromigration. Shale oil contents and composition are closely related to hydrocarbon micromigration. The greater the hydrocarbon intramicromigration is, the higher the shale oil content. Micromigration occurs due to differences in hydrocarbon expulsion, pore space, and capillary pressure among shales. This method has a worldwide application for shale oil evaluation, and the findings will help to uncover shale oil differential enrichment mechanisms. • A quick and novel method is developed to quantify hydrocarbon micromigration in shale. • Micromigration is induced by differences in hydrocarbon expulsion, pore space, and capillary pressure. • The novel method provides a new perspective with which to investigate shale oil enrichment mechanisms. [ABSTRACT FROM AUTHOR]