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Shale oil content prediction is currently the focus of exploration. Traditional prediction methods are less accurate, and a large number of analytical tests can increase the cost of exploration. Therefore, new methods need to be introduced to accurately predict sweet spot intervals. In this study, a quick and novel convolutional neural network (CNN) method to predict oil content parameters (TOC, S 1 and S 2) is provided based on well logs (SP, GR, CAL, RT, and AC) in the Dongpu Depression, Bohai Bay basin, China. The results showed that the CNN model showed high accuracy in predicting TOC (R2 = 0.73) than the ΔlogR method (R2 = 0.132). The validation sets for S 1 (R2 = 0.72) and S 2 (R2 = 0.67) also show high prediction accuracy. In addition, Well Wen 318 (located in the same formation) was selected as a blind well to test the performance of the model. The micromigration evaluation method is based on the principle of mass balance, which reflects the changes of the original hydrocarbon generation potential (HGP O) and the real hydrocarbon generation potential (HGP R). Combined with the established CNN model and the micromigration evaluation method, we predicted and evaluated the oil content in lower Mbr 3 of the Shahejie Fm and divided four sweet spots. The differential enrichment of shale oil is controlled by micromigration. Samples with high saturated/aromatic ratio and small main peak carbon of saturated hydrocarbon chromatography are more likely to undergo micromigration, which in turn affects the oil content of shale. Shales with high organic matter abundance and good pore connectivity are more susceptible to micromigration, leading to the differential enrichment of shale oil. This study provides a new idea for evaluating hydrocarbon micromigration of shale oil and predicting favorable zones and the grading evaluation of oil content in petroliferous basins around the world. • A novel CNN method to predict oil content parameters is provided based on well logs. • A micromigration evaluation model was established based on hydrocarbon generation & retention. • 4 sweet spots intervals were predicted combined with micromigration evaluation and CNN model. • The differential enrichment of shale oil is explained from the micromigration perspective. [ABSTRACT FROM AUTHOR]

Complex fluid occurrence states and structures of shale reservoirs greatly affect shale oil productivity. For lacustrine shales with strong heterogeneity, it is important to identify oil movability, occurrence states and pore structures in different lithofacies in order to efficiently develop shale oil. This study combines conventional core analysis, X-ray diffraction (XRD), argon ion milled-scanning electron microscopy (AIM-SEM), multiple isothermal stages (MIS) pyrolysis and high-frequency nuclear magnetic resonance (HF-NMR) to create maps for samples in native, saturated, centrifuged, and dried states. A new T 1 -T 2 map interpretation scheme is proposed, and fluid occurrence models for different shale lithofacies are established. Four oil species can be identified on the T 1 -T 2 map. Free oil and adsorbed oil in macropores are located in the centers and edges of intergranular/intercrystalline pores, respectively. Oil in mesopores is located in intragranular/intracrystalline dissolution pores. Adsorbed oil exists in the pores of dispersed organic matter and in the marginal fractures of organic matter laminae. NMR and pyrolysis correlate well in the oil contents that they define. The occurrence state of shale oil in the Fengcheng Fm is closely related to minerals and organic matter. Siliceous minerals are beneficial to the occurrence of free oil that is usually a highly movable. The fluid-holding capacity of calcareous shale is limited, especially for adsorbed oil and restricted oil. Clay minerals (>10%) are not conducive to shale oil enrichment and flow, and mixed shale almost exclusively contains bound water. Organic matter is conducive to increasing oil content and to the movable oil saturation of siliceous shale and mixed shale. • Four oil species are divided and localized in HF-NMR T 1 -T 2 map. • Connection between NMR and MIS pyrolysis for movable oil content parameters are revealed. • Fluids occurrence behavior in shale is indicated by NMR T 2 spectra, T 1 -T 2 maps and AIM-SEM. • Oil movability of different lithofacies is quantitatively evaluated. [ABSTRACT FROM AUTHOR]

As the Ordos Basin is the largest gas-producing area in China, its central and eastern Paleozoic Carboniferous Benxi Formation is poised to become a significant source for increasing reserves and production within the basin. However, the extreme diagenesis, complex pore structure, and strong heterogeneity of this formation hinder the exploration of its "sweet spots". The reasons are usually considered to be its large burial depth (>3000 m), differential uplift, highly acidic environment and strong hydrocarbon supply in the coal-bearing strata of this area. In this study, we performed qualitative and quantitative analyses of thin sections of Benxi Formation rocks, combined with scanning electron microscopy, X-ray diffraction, and fluid inclusion analyses to determine the development, type, and evolution sequence of secondary porosity from the diagenesis of the Benxi Formation. The main reservoir type of the Benxi Formation is characterized by secondarily dissolved pores (>0.5 μm) and micropores (<0.5 μm) within clay aggregates; the low porosity and permeability of <5.8% and <1 × 10−3 μm2 indicating a tight sandstone reservoir. Throughout the reservoir formation, its porosity has decreased by strong compaction and cementation, and also increased primarily by dissolution. Quantitative analyses of the thin-section porosity of the rocks based on the Scherer initial porosity recovery model and pore evolution parameters defined by Paxton and Ehrenberg showed 39.8% recovery of original porosity and a porosity increase due to dissolution of 1.0–5.4% (mean, 4.1%); this constituted 40–250% of the porosity prior to dissolution. The model-simulated results were closely correlated with the experimental measurements. The lithology, diagenetic fluid, and organic acids of the source rocks jointly controlled the development of secondary pores in the Benxi Formation. These findings indicate that the evolution and controlling factors of secondary pore development must be clarified to identify favorable areas for gas exploration. The results will provide a basis for predicting favorable reservoirs in the tight sandstones of the Benxi Formation in the central and eastern Ordos Basin. • Dissolution-dominated pore space type of Benxi Formation was confirmed. • A quantitative model of secondary dissolution pores was established. • Dissolved porosity in tight sandstones was quantified. • Effects of rock types, diagenetic fluids, and source rocks were discussed. [ABSTRACT FROM AUTHOR]

Organic shales deposited in a continental environment are well developed in the Ordos Basin, NW China, which is rich in hydrocarbons. However, previous research concerning shales has predominantly focused on marine shales and barely on continental shales. In this study, geochemical and mineralogical analyses, high-pressure mercury intrusion and low-pressure adsorption were performed on 18 continental shale samples obtained from a currently active shale gas play, the Chang 7 member of Yanchang Formation in the Ordos Basin. A comparison of all these techniques is provided for characterizing the complex pore structure of continental shales. Geochemical analysis reveals total organic carbon (TOC) values ranging from 0.47% to 11.44%, indicating that there is abundant organic matter (OM) in the study area. Kerogen analysis shows vitrinite reflectance (Ro) of 0.68%–1.02%, indicating that kerogen is at a mature oil generation stage. X-ray diffraction mineralogy (XRD) analysis indicates that the dominant mineral constituents of shale samples are clay minerals (which mainly consist of illite, chlorite, kaolinite, and negligible amounts of montmorillonite), quartz and feldspar, followed by low carbonate content. All-scale pore size analysis indicates that the pore size distribution (PSD) of shale pores is mainly from 0.3 to 60 nm. Note that accuracy of all-scale PSD analysis decreases for pores less than 0.3 nm and more than 10 μm. Experimental analysis indicates that mesopores (2–50 nm) are dominant in continental shales, followed by micropores (<2 nm) and macropores (50 nm–10 μm). Mesopores have the largest contribution to pore volume (PV) and specific surface area (SSA). In addition, plate- and sheet-shaped pores are dominant with poor connectivity, followed by hybrid pores. Results of research on factors controlling pore structure development show that it is principally controlled by clay mineral contents and Ro, and this is different from marine systems. This study has important significance in gaining a comprehensive understanding of continental shale pore structure and the shale gas storage–seepage mechanism. [ABSTRACT FROM AUTHOR]

The Qibei sag (QS), at the western region of the Bohai Bay Basin (BBB), eastern China, has made significant progress in the deep gas exploration recently, indicating that the deep gas reservoirs have good exploration prospects. The deep gas reservoirs within the second member of the Shahejie Formation of the Paleogene (E 2 s 2 ) are buried at approximately 5000 m. The sources and hydrocarbon accumulation mechanisms were investigated by analyzing the regional structure, integrating geologic and geochemical parameters of source rocks and natural gas. Analyzing results show that, in the QS and adjacent areas (QSAA), three sets of source rocks (E 2 s 1 , E 2 s 2 , E 2 s 3 ) were developed, which differ in organic chemical characters, but have abundant organic matters in fair-good standard. Affected by burial history, E 2 s 3 source rocks have entered into the high mature-over mature stage and E 2 s 1 source rocks are mainly in mature stage. The methane content of natural gas (78%∼91%), the methane carbon isotope value (−41.3‰∼−34.6‰) and the positive carbon isotope sequence (δ 13 C 1 <δ 13 C 2 <δ 13 C 3 <δ 13 C 4 ) indicate that the deep gas is organic origin and mainly from thermogenic gas. The relationship between light hydrocarbon character parameters and thermal evolution degree indicates that the deep gas in the QS is mainly from E 2 s 2 and E 2 s 3 source rocks of the sag. Since the different hydrocarbon generation history, there exist two hydrocarbon accumulation periods in QS, and the early period is characterized by oil accumulation, which occurs at the shallows, such as the Binshen6 block; the late period is characterized by gas accumulation, which happens in the depth mostly, such as the Binshen22 block. The different hydrocarbon generation history results in the relative enrichment of gas in the depth and the phenomenon of oil–gas inversion. [ABSTRACT FROM AUTHOR]

The Lower Permian Taiyuan Formation is a lithic-abundant, tight gas sandstone reservoir in the Kangning field, northeastern Ordos Basin. To clarify the gas accumulation process in tight gas sands, the relationship between the densification of Taiyuan Formation sandstones and gas charging is analyzed. Core porosities of the Taiyuan Formation are mostly below 10%, and air permeabilities are below 1 mD. The sandstone reservoirs are characterized by strong heterogeneity. Dissolution pores and large amounts of micropores in clay minerals dominate the storage space. This porosity is the result of the impact of diagenesis. Porosity evolution modeling confirmed well the prediction of the period of sandstone densification (225-215 Ma) based on the basin analysis as well as diagenetic calibration. Strong compaction dominated the physical property (porosity and permeability) reduction with cementation as a subordinate factor. The integration of burial history and fluid inclusion data suggested that large quantities of gas migrated into the Taiyuan sandstone reservoirs from 176 Ma to 80 Ma when the reservoirs were already tight (porosity <10%). Gas expansion forces provided by source rocks were the main driving force for gas charging instead of buoyancy. Since the late Cretaceous, uplift activity had little influence on Taiyuan tight gas-sands due to self-generation and self-storage. Overlapping sandstone bodies interbedded with high-thickness and good-quality source rocks jointly determined development of tight gas sands. These study results may explain the gas accumulation process and provide insights into gas exploration and development when this method is applied elsewhere. • A new method to indicate the type of gas accumulation. • Three stages of gas accumulation process for Taiyuan Formation in Kangning area. [ABSTRACT FROM AUTHOR]

Abstract The Ordos Basin is a significant gas-producing region in China. Previous studies have shown that a large amount of the gas discovered in the upper Paleozoic strata originated from Carboniferous–lower Permian coal and its interbedded coal measure mudstone. To compare the hydrocarbon generation characteristics and process, two coal and coal measure mudstone samples from the Shanxi Formation in the Shenfu area were used in confined gold tube pyrolysis experiments. The analytical results revealed that both samples had poor oil generation potential, with maximum C 6+ yields of 171.65–175.67 mg/g TOC for the coal and 50.12–51.86 mg/g TOC for the coal measure mudstone at the heating rate of 2 °C/h and 20 °C/h. However, their gas generation potentials are good, and the coal exhibited higher values than the mudstone, with final laboratory C 1 –C 5 yields of 154.71–173.32 mg/g TOC for the coal and 82.52–98.96 mg/g TOC for the coal measure mudstone. Based on a comprehensive analysis of the indicators lnC 2 /C 3 , lnC 1 /C 2 and δ 13C 1 – δ 13C 2 , the hydrocarbon generation process can be divided into three stages. The results of extrapolation to geological conditions revealed that the main gas generation stages of both source rocks in the Shanxi Formation began in the Early Cretaceous. Because of the regional tectonic uplift and the decrease in the geothermal gradient in the Late Cretaceous, the C 1 –C 5 volume yields of the coal and the coal measure mudstone reached plateaus of 78.4 ml/g TOC and 32.7 ml/g TOC, respectively, in the Late Cretaceous, and the current transformation ratios of C 1 –C 5 for the coal and the coal measure mudstone are only 32.1% and 22.8%, respectively. Highlights • Geochemical characteristics of the lower Permian Shanxi Formation coal and coal measure mudstone were analysed. • Confined pyrolysis experiments were performed on the two selected sample types. • Hydrocarbon generation process were determined based on the indicators of yields and carbon isotopes. • Kinetic parameters were used to simulate the hydrocarbon generation history of the coal and coal measure mudstone. [ABSTRACT FROM AUTHOR]

The Middle Eocene Wenchang (WC) formation in the Huizhou depression of the Pearl River Mouth basin is an important geological element for petroleum exploration in the South China Sea. In this study, the geological and geochemical characteristics of the WC source rocks, including the distribution, sedimentary environment, organic matter type, hydrocarbon generation potential and thermal maturity were investigated. Hydrocarbon generation history and hydrocarbon expulsion intensity and quantities were evaluated through one dimensional basin modelling and an improved hydrocarbon generation potential methodology. The WC source rocks are widely distributed and have an elevated thickness (mostly thicker than 200 m, with a maximum thickness greater than 1000 m); they were deposited in a lacustrine weak oxidation–weak reduction sedimentary environment with low salinity. The source rocks have low to high organic matter abundance (TOC mainly ranges from 0.27 to 3.59 wt% with an average of 1.39 wt%) dominated by II 1 –type and II 2 –type kerogen, resulting in significant hydrocarbon generating potential under moderate–high thermal evolution (R o mainly ranges from 0.65% to 1.2% on the margins of sags and greater than 1.2% in the centre of sags). The source rocks became mature (R o = 0.5%) in the early Miocene and began to generate hydrocarbons. They reached the hydrocarbon expulsion threshold at 0.8% R o and the hydrocarbon expulsion rate became greatest at 1.1% R o . The expulsion intensities in the H26 sag, H21 sag, X24 sag and X23 sag are relatively large, with their greatest expulsion intensities being 104 × 10 6 , 71 × 10 6 , 62 × 10 6 and 53 × 10 6 t/km 2 , respectively. The comprehensive hydrocarbon expulsion efficiency was approximately 75%. About 690.1 × 10 8 t of hydrocarbons were expulsed from the WC source rocks in the Huizhou depression. [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]

The middle Eocene was a key period of global climate change from a warm "greenhouse" to a cooling "doubthouse". At the middle Eocene, an extensive arid climate in China was recorded in the mudstones and shales interbedded with salinastone which formed good hydrocarbon source rocks, especially in the Bohai Bay Basin. The sedimentary paleoenvironment and its variations affected the source rock quality and distribution. Based on successive and dense sampling of the middle Eocene Shahejie Formation shale (MES shale) in Nanpu Sag of Bohai Bay Basin, petro-mineralogical tests, geochemical methods and spectrum analysis were performed to analyse the palaeoenvironmental fluctuations and the responses to Milankovitch cycles. Element analysis on MES shale shows that the middle Eocene climate was arid and the sediments were deposited under dysoxic/suboxic conditions with relatively high salinity. Based on the Δlog R method, the organic matter (OM) abundance was evaluated and ranged from 0.18 to 3.55 wt % for MES shale. The mean primary productivity of 545 g C m−2 yr−1 shows a eutrophic environment in middle Eocene Nanpu paleolake. Wavelet analysis performed on gamma logging and palaeoenvironmental proxies revealed clear Milankovitch cycles for MES shale, and the cyclostratigraphic and palaeoenvironmental fluctuations were effected by astronomical oscillation periods of the short eccentricity cycle (100 k.y.), obliquity cycle (39 k.y.) and precession cycle (19 k.y.). The depositional rate of MES shale was corrected to 0.43 m/k.y. The sedimental process of MES shale was associated with palaeoenvironmental variation, which have been divided into four stages affecting OM accumulation. A hypothesis that the vast carbon of "greenhouse" gases in the Palaeocene and early Eocene was fixed in organic matters during middle Eocene and enriched in the hydrocarbon source rocks of the sedimentary basins formed at early Eocene was proposed to explain the "doubthouse" world in the Eocene. • Clear Milankovitch cycles exist in mid-Eocene lacustrine shale of Bohai Bay Basin. • Pale-climate integration effects on organic matter enrichment in lacustrine shale. • Carbon fixation in shales was critical to decline greenhouse gases at mid-Eocene. [ABSTRACT FROM AUTHOR]