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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]

Abstract In a petroleum accumulation system, the source rock plays a significant geological role in controlling hydrocarbon distribution, because it provides the material basis for hydrocarbon accumulation. Thus, quantitative evaluations of source rock control on hydrocarbon distribution are useful for predicting future hydrocarbon discoveries. Using the Huizhou Depression in the Pearl River Mouth Basin, China, as a case study, geostatistical methods and probability calculation were employed to analyze the controlling effect of source rocks. The Huizhou Depression can be divided into five petroleum accumulation systems of which the Huixi contains the largest known amount of hydrocarbons. A probability model of hydrocarbon accumulations is established for quantitative evaluation of potentially favourable hydrocarbon distribution. In each petroleum accumulation system, the larger the hydrocarbon expulsion intensity, the larger the amount of hydrocarbons that accumulates; the longer the distance from the hydrocarbon expulsion centre, the lower the amount of hydrocarbon accumulates. The hydrocarbon distribution limit controlled by the source rock is 3.5 times the radius of the source kitchen in the Huizhou Depression. In the current state of exploration, oil fields in the Huizhou Depression are mainly observed in the areas 1.5 to 2 times the source kitchen radius. Based on the prediction model, structural highs around hydrocarbon source kitchens are potentially favourable zones for structural hydrocarbon reservoirs, and the interiors of source kitchens are potentially targets for subtle hydrocarbon reservoirs and unconventional resources. Highlights • Quantitative evaluation of source rock control on hydrocarbon distribution is built. • Geochemical characteristic of source rocks is investigated. • Petroleum accumulation systems of Huizhou Depression are divided. [ABSTRACT FROM AUTHOR]

Abstract The Dongpu Depression, especially the northern part, is an important natural gas-rich area in the Bohai Bay Basin, China. The gases found in Es3M, Es3L and Es4 are mainly distributed in the western part of Qianliyuan, in Weicheng, and in the middle of the Wenliu area, respectively. However, few studies have been conducted on the relationship between the development of source rock and the enrichment of gas in different hydrocarbon-generating sags. In this paper, gas genetic types, distribution characteristics and gas-source correlations were analyzed using data from molecular and stable carbon isotope components of natural gas, biomarkers and thin sections. The results indicate that Es3M gas is predominantly oil-type gas and that Es3L gas is mainly mixed gases dominated by coal-type gas, with average dryness coefficients (C 1 /C 1–5) of 0.877 and 0.920, respectively. By contrast, Es4 gas is dry with an average dryness coefficient of 0.970 and displays the typical characteristics of coal-type gas from Carboniferous-Permian coal measures. Carbon isotope reversals are common in the gas samples, while their causes are different. The mixing of coal-type gas and oil-type gas is the main reason for the gas carbon isotope reversals in Es3M and Es3L. By contrast, the widely existing carbon isotope reversal in Es4 gas in the central part of Wenliu is related to the long-term migration and enrichment of coal-type gas from Carboniferous-Permian rocks. Gas-source correlations indicate that Es3M gas is predominantly from the in situ cracking of Es3M oil and that coal-type gas mixed within Es3L gas is from the Carboniferous-Permian coal measures. Highlights • Genetic types of natural gas in the northern Dongpu Depression were summarized. • Gas carbon isotope reversals in different target layers were analyzed. • Es3M gas is predominantly from in situ cracking of Es3M oil. • Coal-type gas mixed within Es3L gas is from the Carboniferous-Permian coal measures. [ABSTRACT FROM AUTHOR]

Three rounds of exploration in Marsel, Kazakhstan show that the area has good petroleum geological conditions; however, the exploration degree is low and the resource potential is unclear. The total organic carbon ( TOC ) content is the criteria for effective source rocks and is also the key parameter to calculate the amount of resources; while previous evaluations of the effective source rocks and calculated amounts of resources were based on residual TOC , which gradually decreases with mass hydrocarbon expulsion; therefore, this will inevitably produce errors. For greater accuracy, the TOC recovery coefficient formula was used to recover the residual TOC in Marsel; then, the criteria of the effective source rocks were revised to calculate the Carboniferous and Devonian resources in Marsel. The results are as follows: for the source rocks in Marsel, the TOC recovery coefficient of the Carboniferous source rocks is approximately 1.6, while that for the Devonian is approximately 2.0; the revised lower limit of TOC for the effective source rocks is 0.3% and 0.25% for the Carboniferous and Devonian, respectively; after TOC recovery, the total amount of hydrocarbon expulsion is 26.7 × 10 12 m 3 , the total amount of recoverable resources is 2.62–5.10 × 10 12 m 3 , and the mean is 3.79 × 10 12 m 3 for the main source rocks. The effective source rocks evaluated based on the recovered TOC and the latter resources could reflect the quantity of source rocks and actual resource potential of Marsel more accurately. This has certain significance for the exploration of areas that have low levels of exploration with an unclear understanding of the resource potential as well as a high degree of thermal evolution and a low quantity of residual TOC . [ABSTRACT FROM AUTHOR]

Tight sandstone gas is regarded as a significant unconventional resource. One intriguing problem for tight sandstone gas accumulation is how gas was trapped in the tight-sandstone reservoirs. In this paper, we attempted to look for a reasonable explanation for this, which has attached great theoretical and practical significances. In this study, a dynamic equilibrium equation characterizing the critical buoyancy threshold (CBT) was established based on physical experiments, and the formation mechanism of tight gas and CBT were discussed. The explanations were further testified through the tight-gas reservoirs of the Upper Paleozoic Ordos Basin. A dynamical CBT occurs during the charge process in tight-gas reservoirs, and water- gas inversion with separating phases is dominated before natural gas reaches the CBT. At this stage, the driving force for gas movement is abnormal gas pressure, and almost no buoyancy exists. The pore throats, smaller than those corresponding to the CBT, enable the formation water to resist the gas to move upward. As a result, with no water-gas displacements, the gas migrates upward in a piston-like style forming continuous gas reservoir. The corresponding pore throat and depth of the CBT are geologically significant, which indicates a critical condition. However, the CBT condition is not constant and varies significantly according to the geologic setting. The case study of the tight-gas reservoirs of the Upper Paleozoic Ordos Basin indicates that the critical pore-throat radius was 1.77 µm by the end of the Early Cretaceous, with the corresponding critical permeability and porosity value of 0.686 mD and 10.6%, respectively. In contrast, its current counterparts are 1.33 µm, 0.39 mD, and 8.6%, respectively, which indicates that the original tight sandstone gas reservoir has shrunk during the geologic history. [ABSTRACT FROM AUTHOR]

The petroliferous Permian system of the Junggar Basin in northwest China is predominantly a conventional oil exploration region. To assist in the unconventional tight oil reservoir exploration, the hydrocarbon expulsion potential of source rocks and its influence on the tight oil distribution of the Middle Permian Lucaogou Formation (P 2 l) in the Jimsar Sag are discussed. The researches are based on geological and geochemical characteristics such as the distribution, abundance, type, thermal maturity of source rocks, and “sweet spots”. Meanwhile, hydrocarbon expulsion intensity and quantity were evaluated with hydrocarbon generation potential method. The Middle Permian Lucaogou source rocks have wide distribution and high thickness (mostly thicker than 100 m). The source rocks exhibit low to high TOC (mainly ranges from 1.0 wt% to 5.0 wt%) and primarily contain type-II kerogen, resulting in significant hydrocarbon expulsion potential under moderate mature thermal evolution (R o mainly ranges from 0.55% to 1.05%). According to the hydrocarbon expulsion modelling, the source rocks reached the hydrocarbon expulsion threshold at 0.73% R o and the hydrocarbon expulsion rate became greatest at 0.9% R o . The comprehensive hydrocarbon expulsion efficiency was approximately 48%. About 18.7×10 8 t of hydrocarbons were expulsed from the Lucaogou source rocks in the Jimsar Sag. The hydrocarbon expulsion intensities are relatively large and rang from 150×10 4 t/km 2 to 400×10 4 t/km 2 in the center and west area of the Sag, where is the superimposed area of source rock thicker than 200 m, TOC greater than 3.5% and R o higher than 0.85% in the sag. There are 17 exploratory wells obtaining commercial oil flow in the Sag. 16 of the 17 exploratory wells are located in the area with hydrocarbon expulsion intensity greater than 50×10 4 t/km 2 . By contrast, other exploratory wells outside the hydrocarbon expulsion coverage area have slight show of oil, even dry. In addition, there is positive correlation between the hydrocarbon expulsion intensity and the daily output of well testing. It is concluded that the tight oil exploration should focus on the area with hydrocarbon expulsion intensity greater than 100×10 4 t/km 2 , which is a favorable area for commercial hydrocarbon accumulation and exploration. [ABSTRACT FROM AUTHOR]

Effective reservoirs in petroliferous basins are generally defined as rocks that have relatively high porosity and permeability, which have the capacity for accumulating and storing hydrocarbons under the conditions of sufficient hydrocarbon supply. Previous studies show that the lower limit of porosity of effective reservoirs decreases with increasing burial depth. However, the existing assessment methods for effective reservoirs mainly use well test data or petrophysical properties of a reservoir, without considering the influence of depth. These methods are not practical for petroleum exploration. In this study, the dynamic mechanism of hydrocarbon accumulation was studied using physical simulation experiments, which revealed that capillary force is a basic control for hydrocarbon accumulation. The relationship between the capillary force ratio of surrounding rock to reservoir rock and their oiliness was statistically analyzed. Finally, a novel discriminating standard and quantitative evaluation for determining effective reservoirs was established and its reliability was confirmed. This study shows that the capillary force ratio of surrounding rock to reservoir rock determines the reservoir effectiveness. Moreover, a reservoir is more effective when the ratio is larger, thus more favorable for hydrocarbon accumulation. The reservoir potential index (RPI) ranging from 0 to 1 is introduced to characterize the hydrocarbon-bearing property of a reservoir. Rservoirs are classified as effective reservoirs when RPI <1 and ineffective reservoirs when RPI >1. The effective reservoirs are further divided into four grades based on the RPI value: Grade I: 0 ≤ RPI ≤0.25; Grade II: 0.25 < RPI ≤0.5; Grade III: 0.5 < RPI ≤0.75; Grade IV: 0.75 < RPI <1, in which the grade I refers to the most favorable reservoir. It is conformed as a practical and reliable method. • Dynamic mechanism of hydrocarbon accumulation is simulated. • Discriminating standard of effective reservoirs is established. • Capillary force difference inside and outside of rock is intrinsic for effectiveness. [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]

In this paper, the Oligocene reservoirs in the Nanpu Sag of the Bohai Bay Basin are studied by scanning electron microscopy (SEM), thin section observation, XRD, nuclear magnetic resonance (NMR), and mercury injection. The purpose is to judge the microscopic pore structure of the reservoir in the study area through: 1) Combining nuclear magnetic resonance technology with fractal dimension to analyze the pore structure characteristics of sandstone; 2) using mercury injection experiments to judge the connectivity of pore throats; and 3) combining petrophysical properties-NMR-fractal dimension-mercury injection to predict reservoir quality. The results show that the sandstones of the Ed 3 and Es 1 members in the Nanpu Sag of the Bohai Bay Basin have good physical properties, medium porosity (5.2%–18.7%, average 11.70%) and permeability (0.08mD-111mD, average 22.68mD). Using the T 2 spectrum, the fractal dimension of the bound fluid pore and the fractal dimension of the movable fluid pore are determined. The movable fluid pore is more complicated than the bound fluid pore. There is a connection between fractal dimension and mineral composition. High clay mineral content leads to a complex pore network, and the larger the fractal dimension, the more complex the pore shape and the lower the permeability. • Combining NMR technology with fractal dimension to analyze the pore structure characteristics of sandstone. • Use mercury injection experiments to explain the reasons for the higher porosity and permeability. • The pore combination characteristics can be judged by the smoothness of the pore throat surface. • The combination of fractal dimension and mineral composition can be used to judge the genesis of the rock framework. • Combine the fractal dimension with component maturity and structural maturity, and use laws to predict reservoir quality. [ABSTRACT FROM AUTHOR]

The Sinian Dengying Formation is a key target for deep oil and gas exploration in the Sichuan Basin, China. Natural gas was mainly distributed in the Ziyang–Weiyuan area (ZWA) and the Gaoshiti–Moxi area (GMA). At present, the genetic types and sources of natural gas are still unclear and controversial. The chemical composition, stable carbon isotopes, and biomarkers were used to analyze geochemical characteristics, genetic types, and gas–source relations. The results showed that the composition and content of hydrocarbon gas in the ZWA and GMA were similar. Natural gas was a typical dry gas with an average dry coefficient (C 1 /C 1 +) of 0.9991, which reflected higher methane (CH 4) content and lower heavy hydrocarbon gas (C 2 +) content. For nonhydrocarbon gas, CO 2 (0.01%–26.34%), N 2 (0.03%–24.95%), H 2 S (0.10%–3.19%), and He (0.01%–0.37%) were mainly distributed. Compared with the GMA, the ZWA was characterized by higher N 2 content and lower CO 2 content. Although the carbon isotopes had not been reversed, the values of δ13C 2 –δ13C 1 were different between the ZWA and GMA, with the GMA having the higher value. The assemblage relation between the natural gas composition and carbon isotopes indicated that the natural gas type was dominated by oil-cracking gas. Mud-shale in the high maturity stage of thermal evolution greatly influenced on the content of N 2 and He. H 2 S mainly belonged to thermochemical sulfate reduction (TSR), and most of CO 2 was formed by deep carbonate metamorphism and TSR. The gas–source relation showed that natural gas in the ZWA was derived from the Cambrian Qiongzhusi Formation and that the gas in the GMA mainly originated from the Sinian Dengying Formation and the Cambrian Qiongzhusi Formation. The established hydrocarbon generation model indicated that the Sinian Dengying Formation is potentially gas-rich. • The Sinian Dengying Formation natural gas was a typical dry gas, dominated by oil-cracking gas. • Source rocks of the Qiongzhusi Formation and Dengying Formation were the mainly gas source for gas reservoirs. • The resource potential was qualitatively evaluated by the established hydrocarbon generation model. [ABSTRACT FROM AUTHOR]

Studying the lower limits of petrophysical properties is important to evaluate the exploration and development potentials of tight oil reservoirs. At present, the evaluation criteria are based on a large number of cores and logging data, and rules are based on collections of empirical statistics and displacement pressure experiments. However, there have been few studies on the lower limits of the petrophysical properties of tight reservoirs based on force balance conditions for the hydrocarbon charging process. In this paper, the critical condition for hydrocarbon charging is determined using the oil expansion pressure as the main driving force, with the capillary pressure as the major resistance, via an analysis of the dynamic mechanism of tight oil reservoirs. A force-balance model for judging the lower limits of the petrophysical properties of tight reservoirs can be established by assuming that the oil expansion pressure is equal to the capillary force. This discriminant method is applied to calculate the critical pore-throat radius of the effective reservoirs of the Lower Permian Fengcheng Formation in the Fengcheng area, Junggar Basin, which are 0.310 μm, 0.248 μm, 0.208 μm, and 0.135 μm, when the buried depths are 2500–3000 m, 3000–3500 m, 3500–4000 m, and 4000–4500 m, respectively. The corresponding critical porosities are 6.15%, 4.84%, 3.81%, and 1.20%, respectively. The lower limits of the petrophysical properties of effective tight reservoirs gradually decrease with increasing burial depth. This method is of great significance for resource evaluations of tight oil reservoirs and the selection of exploration zones. • Built a mathematical model to determine the lower limit of petrophysical properties for effective tight reservoirs. • Calculated lower limit of petrophysical properties for effective tight reservoirs in the Fengcheng area quantitatively. • Discussed the effectiveness and impacts on Fengcheng Formation tight reservoirs. [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]

Abstract The Upper Triassic Xujiahe Formation is a key target layer for development of tight sandstone gas reservoirs in the Sichuan Basin. Most of the previous work focused on the main reservoirs such as T 3 x2 and T 3 x4 with lack of research attention on T 3 x5, an equally important source-reservoir unit. Here we examine the organic matter and source rock distribution in the T 3 x5 using rock pyrolysis, asphalt extraction, and gas chromatography. The thickness of T 3 x5 source rocks reduces from west and northwest Sichuan Basin to east and southeast Sichuan Basin. The main sedimentary facies are salt lakes and deltas, of which the organic matter originated from aquatic organisms and a small amount of terrestrial matter. The abundance of total organic carbon (TOC) in T 3 x5 is relatively high, at values of 0.07%–7.2%. According to the vitrinite reflectance (R o), pyrolysis, and gas chromatography measurement results, the T 3 x5 source rocks are at the stage of mature to over-mature, and their hydrocarbon expulsion threshold and hydrocarbon expulsion peak correspond to Ro of 1.05% and 1.23%, respectively. Furthermore, a hydrocarbon generation center and a hydrocarbon expulsion center are formed horizontally, with the maximum hydrocarbon generation intensity of 50 × 108 m3/km2 and the maximum hydrocarbon expulsion intensity of 48 × 108 m3/km2. The natural gas resource is 3.19–5.36 × 1012 m3, indicating great exploration potential. Highlights • Evaluate of T 3 x5 source rocks in detail from 5 aspects: sedimentary environment, thickness and distribution, organic matter abundance, organic matter type and organic matter thermal maturity. • Clarify the hydrocarbon generation and expulsion features of T 3 x5 source rocks. • Predict resource potential of the T 3 x5 in Sichuan Basin. [ABSTRACT FROM AUTHOR]

The study on the secondary migration of hydrocarbons in Ordovician carbonate reservoirs in the Lunnan area has been a challenge caused by limited geologic records as direct physical evidence, and physical simulations are difficult to conduct since the parameters of realistic geologic conditions are rare. Based on the analysis of the regional structure, and by integrating the study on the fluid properties and benzocarbazole nitrogen compounds parameters, the secondary hydrocarbon migration in Ordovician carbonate reservoirs in the Lunnan area, Tarim Basin, were investigated. The results indicated oil density show gradually increasing trends from Lungudong Fault to the Middle Slope in eastern Lunnan Uplift; while the trend is converse from southwest of Lunxi and Sangtamu Faults to the Middle Slope in western area. The benzocarbazole nitrogen compounds contents of Ordovician reservoir oil exhibit gradually increasing trends from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope. The wax contents, gas dryness coefficients and gas/oil ratios show decreasing trends from east to west and away from the Lungudong Fault and Sangtamu Fault. The crude oil generated at the late Hercynian stage (about 290 Ma ago) in the Lunnan area migrated along the directions from southwest of Lunxi and Sangtamu Faults and southeast of Lungudong and Sangtamu Faults to the Middle Slope; the gas formed at the late Himalayan stage (about 208 Ma ago) migrated from the east to west laterally, and along the natural gas invasion faults Lungudong Fault and Sangtamu Fault upwards vertically. • The Ordovician oil and gas properties were analysed in the Lunnan area. • Carbazole nitrogen compound distribution was studied. • Secondary migration direction of Ordovician oil and gas was identified. [ABSTRACT FROM AUTHOR]

Substantial progress has been made in the exploration of the tight petroleum resources in Bohai Bay Basin, as a series of tight oil reservoirs were discovered. Among these reservoirs, a new breakthrough was achieved in the Nanpu Sag, proving a previously unconfirmed prospect of tight oil. Mineralogical, petrographic and fluid inclusions analyses were performed to investigate physical properties (composition, pore system, porosity, and permeability), controlling factors, and features of tight sandstones of the Upper Paleogene Es3 (the third member of the Shahejie Formation) in the Gaoshangpu Structural Belt of the Nanpu Sag. Our study indicates that the Es3 tight sandstones are mainly feldspathic litharenites and had low values for porosity (average value 10.1%) and permeability (average value 0.8 mD). The pore system is dominated by secondary dissolution pores (average thin porosity 3.1%). The deterioration of porosity is greater due to compaction (average compaction rate 68.8%) rather than cementation (average cementation rate 16.3%). Two peaks in the homogenization temperature were observed; the first ranges from 116 °C to 136 °C and exhibits yellow fluorescence, while the other peak varies from 156 °C to 165 °C, showing blue fluorescence, which indicates two stages of hydrocarbon charging at 26 Ma and 3 Ma, respectively. Tight sandstone is identified during the Mesodiagenesis phase. Eodiagenesis included compaction, precipitation of calcite cements and quartz overgrowth. Mesodiagenesis mainly exhibited compaction and grain dissolution (mainly feldspar). The main controlling factors can be summarized as follows, with the second factor being the most important: (a) a high energy deposition environment (distributary channels); (b) intense dissolution; and (c) early hydrocarbon charging and overpressure. This study provides a new prospect of the tight sandstone petroleum system in northeastern China. • The physical (composition, porosity, permeability, and pore systems) and diagenetic properties are detailed of the Es3 of the Nanpu Sag. • Quantify the influence of diagenetic processes to reservoir, reconstruct the porosity evolution history. • Summarize the main controlling factors of high-quality tight sandstone reservoir. [ABSTRACT FROM AUTHOR]

The Dongpu Depression has abundant oil and gas resources, but the distribution of hydrocarbon resources and enrichment degrees of organic matter (OM) in the northern and southern Dongpu Depression have significant differences due to the diverse sedimentary environment. To gain deep insight into the effects of sedimentary environment on OM accumulation and preservation, a series of experiments including element geochemistry, organic geochemistry and isotope geochemistry were performed on core samples collected from the fresh, brackish and saline regions of the third member of the Eocene Shahejie Formation (Es 3). The lacustrine closure, paleo-salinity, redox conditions, hydrodynamic conditions, paleo-climate and paleo-productivity were quantitatively evaluated. Controlling factors and OM enrichment models were evaluated and established. The results show that the Es 3 Formation was deposited as the lake experienced closed saline to transitional and then fresh lake stages. The lacustrine deposits were accompanied by climate changes from dry to humid and strongly rifting during Es 3 deposition. The weak hydrodynamic conditions (Zr/Rb) and paleo climate indices (δ18O, climate index, Fe/Mn, Sr/Cu and Al/Mg) imply that moderate humid and dry climate can encourage OM development and preservation. The paleo productivity indices (δ13C, P/Al, P/Ti and P content) are positively related to TOC indicating that high productivity promotes OM accumulation. All the paleo salinity indices (Z value, Sr/Ba and B/Ga) have positive correlations with TOC content, suggesting that OM enrichment increases with salinity to some extent. The positive relationships between the redox indices (V/Cr, V/Sc, U/Th, and δU) and TOC indicate that redox conditions are the most important for OM preservation. This study not only advances the theory of OM enrichment mechanism in saline basins, but also provides guidance for predicting the distributions of high-quality source rocks in the Dongpu Depression. • Integrated varieties methods to recover paleo sedimentary environment. • Compared the effect of sedimentary environment on the organic matter enrichment. • Reconstructed the organic matter enrichment models. [ABSTRACT FROM AUTHOR]

The proposed functional-element constraint hydrocarbon distribution model consists of four basic functional elements including regional cap rock (C), favorable sedimentary facies (D), interfacial potential (P) and source kitchen (S). The combination of the four functional elements controls the formation and distribution of stratigraphic reservoirs in a basin. Regions with spatial and temporal overlaps of the four functional elements are the favorable zones for stratigraphic reservoirs. The geometric mean of the frequency of the four functional elements could indicate the possible distribution of stratigraphic reservoirs in a target zone. This paper describes constraint functions of the four functional elements on the hydrocarbon accumulations and their quantitative characterization. The hydrocarbon distribution model based on functional elements can predict development of stratigraphic reservoirs using T-CDPS, and the possibility for reservoir formation is determined by the index, T cdps , in this paper. Based on the model, we have predicted seven areas of the Paleogene E d 3 in Nanpu Sag, which are favorable or moderately favorable for stratigraphic reservoir distribution. Among all the seven areas, five areas located in the Gaoshangpu structural belt, south of Laoyemiao structural belt and Nanpu I, II, V structural belt were favorable areas. Two moderately favorable areas were located in Nanpu III structural belt and Nanpu IV structural belt. [ABSTRACT FROM AUTHOR]

The Middle–Upper Ordovician carbonate source rocks in the Tabei Uplift, Tarim Basin, are at highly mature evolution stage with relatively low present-day TOC (TOC pd). It is significant to study the hydrocarbon expulsion characteristics for the marine hydrocarbon exploration in Ordovician carbonate reservoirs. Due to similar depositional environment and same kukersite kerogen, two groups of Ordovician source rocks (468 sets of data from the highly mature Middle–Upper Ordovician source rock (O 2+3) in the Tarim Basin and 27 sets of data from the lowly–medium mature Upper Ordovician Yeoman Formation (O 3 y , Canadian Williston Basin)) are selected as analogue to research the hydrocarbon expulsion characteristics by the approach of mass balance. The result indicates that the two sets of source rocks (O 2+3 and O 3 y) have similar hydrocarbon generation kinetics with the original hydrocarbon index of 900 mg HC/g TOC and a narrow T max window; the kerogen transformation ratio reaches 90% at calculated VR E of 1.10%. The hydrocarbon expulsion threshold of the O 2+3 source rock is at calculated VR E of 0.9%, the maximum expulsion intensity can reach 20 × 104 t/km2, and the cumulative volume of expulsion is 9.3 ✕ 109 tons. The restored TOC o values of the O 2+3 can reach approximately 2%, showing a good original potential. The distribution of high quality oil discovered in the Tabei Uplift is in accordance with that of high hydrocarbon expulsion intensity of the O 2+3 carbonate source rocks, implying that the regions with high hydrocarbon expulsion intensity in the southern slope of Tabei Uplift would be favorable exploration areas for the marine hydrocarbons in the Ordovician carbonates in the Tarim Basin in the future. • Two Ordovician carbonate source rocks from the Tarim Basin and Canadian Williston Basin were analogized. • Hydrocarbon generation kinetics of kukersite carbonate source rock were analyzed. • Hydrocarbon expulsion features of the O 2+3 source rock in the Tabei were evaluated. [ABSTRACT FROM AUTHOR]