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The source of oil and gas in the Tarim Basin's platform has always been controversial. The Lower Cambrian Yurtusi Formation and the Xidashan Formation–Xishanbulak Formation argillaceous source rocks are an important set of oil source series in the basin. Based on the principle of conservation of matter, this paper calculates the hydrocarbon expulsion amount of the source rock. Using a phase state hydrocarbon expulsion amount characterization model, the paper reconstructs the evolution process of the hydrocarbon expulsion phase state of the source rock. According to the characterization model of hydrocarbon expulsion dynamics, the relative contribution of each force to hydrocarbon expulsion is evaluated. The hydrocarbon expulsion geologic model of argillaceous source rocks in the Lower Cambrian in the Tarim Basin is established. The results show that this set of source rocks can serve the main source rocks in the basin. The hydrocarbon expulsion of the Lower Cambrian argillaceous source rocks in the Tarim Basin can be divided into three stages. In the first stage, the hydrocarbon expulsion phase is dominated by the water‐soluble and diffusion phases. The conversion of clay minerals into dehydration and diffusion forces is the main driving force for the hydrocarbon expulsion. In the second stage, the oil and gas expulsion present the characteristics of multiphase and multidynamic coexistence. In the third stage, the phase state of oil and gas expulsion is mainly free phase. The capillary force difference and the thermal expansion force of the fluid rock are the main driving forces for oil and gas expulsion. The research results of this paper can deepen the understanding of the hydrocarbon expulsion mechanism of the set of source rocks, and then guide oil and gas exploration. [ABSTRACT FROM AUTHOR]

The China Geological Survey successfully completed the second trial of natural gas hydrate (NGH) production in 2020, and the daily gas production and total gas production were greater than those in the first trial, but the evaluation of NGH resources in the South China Sea (SCS) is still in the evaluation stage, specifically for the gas content. In 2021, some scholars used different methods to more accurately evaluate NGHs in the SCS to aid in NGH exploration and evaluation in the SCS; some of them analysed the main factors controlling NGH resources, added several factors to the volume method for optimization, studied the sensitivity of the evaluation of resources to each of the main controlling factors (NGH stability zone area, NGH area coefficient, NGH stability zone thickness, NGH thickness coefficient, NGH reservoir porosity, NGH reservoir saturation, NGH volumetric ratio, NGH resource ratio coefficient and NGH recovery coefficient) and found that the effective thickness coefficient, effective thickness and effective area coefficient are the most sensitive; these values are 23.15%, 15.66%, 13.98%, and 13.95%, respectively, while the other values are 0%, 15.66%, 8.42%, 8.41%, 2.50%, and 13.92%; taking into account the influence of the main controlling factors, the range of the water resource potential evaluation results in the SCS is 2.4 × 107 m3–5.9 × 1014 m3, the modal value is 7.25 × 1011 m3, and the confidence level of the modal ±25% interval is 77.8%; these values provide a higher evaluation accuracy and higher resource level, which is consistent with the current results of NGH research in the SCS. Although the development of NGHs in the SCS is progressing rapidly, basic exploration is relatively scarce, and the number of samples of effective thickness obtained through dozens of exploratory wells is too few. It is recommended that China carry out more exploration and research projects in the Shenhu area and the entire SCS to obtain more accurate thickness data. [ABSTRACT FROM AUTHOR]

In recent years, exploration of tight oil in the Nanpu Sag has made significant progress in the third member of the Upper Palaeogene Shahejie Formation (Es3) in the Nanpu Sag, Bohai Bay Basin, Northeast China, showing excellent prospects. However, owing to insufficient understanding of the hydrocarbon generation and expulsion characteristics of Es3 source rocks and their matching relationship with the reservoir tightening time, the genetic type and resource potential of tight oil systems are not precise, which limits the further exploration of tight oil. In this study, the geological and geochemical characteristics of Es3 source rock are identified through a comprehensive geological and organic geochemistry analysis. In addition, hydrocarbon generation and expulsion patterns are established using a hydrocarbon generation potential model. On the basis of these results, combined with sandstone reservoir evolution histories, we have identified the genetic type and resource potential of the tight oil. The results show that the kerogen types of the Es3 source rocks of the Nanpu Sag, are widely distributed in an area of nearly 1,000 km2 and have a large thickness of more than 700 m, are mainly Types II and III with a high average total organic carbon (TOC) value of 1.63%. Moreover, the source rocks are primarily in the mature stage, with an average vitrinite reflectance (Ro) of 1.06%. The Es3 source rock reached the hydrocarbon expulsion threshold at Ro = 0.7%, and the hydrocarbon expulsion efficiency was approximately 70%. Two hydrocarbon generation and expulsion centres are identified, the Gaoshangpu and Laoyemiao structural belts, with maximum hydrocarbon generation and expulsion intensities of 100 × 106 t/km2 and 80 × 106 t/km2, respectively. In addition, two genetic types of tight oil are identified with accumulation before and after tightening, respectively. The resources of these types are 2.3 × 108 t and 20.4 × 108 t, respectively, with a total of 22.7 × 108 t, which indicates significant prospects for tight oil exploration. [ABSTRACT FROM AUTHOR]

Significant achievements have been reported for deep oil and gas exploration in the Bohai Bay Basin. Among them, the Nanpu Sag has achieved good deep (greater than 3.5 km) hydrocarbon exploration results. However, the hydrocarbon formation mechanisms and the diagenetic evolution of these high‐quality sandstone reservoirs remain unclear. Mineralogical, petrographic, and fluid inclusion data were selected to investigate the deeply buried sandstone reservoir physical properties, pore systems, and diagenetic features and the main formation mechanisms of the deep high‐quality reservoirs of the Es1 (the top member of the Paleogene Shahejie Formation) sandstones in the Nanpu Sag, eastern China. The results show that the Es1 sandstone reservoirs are dominated by lithic arkoses and have low porosities (average porosity 13.4%) but medium to high permeability (average permeability 188 mD). The pore systems consist of primary intergranular pores, secondary dissolution pores, and microfractures. Loss of porosity is greater due to compaction (average 20.89%) than due to cementation (average 4.82%), and dissolution contributes an improvement in porosity of approximately 5.85%. Two peaks in the inclusion homogenization temperatures were observed: The first fluid inclusion homogenization temperature term ranges from 130°C to 145°C and exhibits yellow fluorescence; the other peak occurs from 155°C to 165°C, showing green fluorescence. Eodiagenesis is due to mechanical compaction, precipitation of early calcite cements and quartz overgrowths, and dissolution of feldspar and carbonate cements. Mesodiagenesis occurs due to mechanical compaction, framework grain (mainly feldspar) dissolution, and precipitation of quartz and late carbonate cements. The main factors controlling the formation of the deep high‐quality reservoirs are the presence of a high hydrodynamic depositional environment (subaqueous distributary channel), the type of provenance (Archean granites), and the creation of secondary porosity by feldspar dissolution. [ABSTRACT FROM AUTHOR]

Reservoir quality is critical in tight gas exploration. A systematic study of the petrological, petrophysical, and diagenetic characteristics of the Shanxi Formation sandstones in the north‐eastern Ordos Basin (China) was undertaken to characterize the pore system of these tight sandstones and recognize the distribution of reservoirs favourable for hydrocarbon accumulation. The results suggest that the Shanxi Formation sandstone has low compositional and moderate textural maturity, with its porosity ranging from 0.7% to 11.8% (average 5.97%) and permeability ranging from 0.001 to 2.77 mD (average 0.36 mD). In addition, thin section and SEM observations suggest that the sandstone is dominated by secondary dissolution pores, primary intergranular pores as well as microfractures, and has undergone compaction, cementation, and dissolution. Diagenetic minerals, such as carbonate cements, authigenic quartz, clay minerals, and dissolved feldspar, are identified. Fluid inclusions are observed in healed microfractures of quartz grains and in quartz overgrowths, while the homogenization temperatures of fluid inclusions in healed microfractures and in quartz overgrowth are in the ranges of 92.8–179.1°C (average 134.8°C) and 104.7–169.1°C (average 145.7°C), respectively. Authigenic kaolinite is sourced from the process of K‐feldspar dissolution, authigenic illite is sourced from transformation of smectite and kaolinite, while sources for quartz cements include mineral alteration and pressure dissolution. Selective dissolution of K‐feldspar in the presence of carbonate minerals is observed in the Shanxi Formation tight sandstones due to the different equilibrium constants of carbonate minerals and K‐feldspar leaching, resulting in dissolution pores associated with K‐feldspar. Reservoir quality in the Shanxi Formation tight sandstones is greatly influenced by diagenesis, as compaction and cementation are responsible for the loss of porosity while dissolution accounts for the enhancement of secondary porosity. [ABSTRACT FROM AUTHOR]

The north‐eastern Ordos Basin in Central China has become an exploration target in recent years due to the potential of natural gas resources in the Upper Palaeozoic strata. In this study, by analysing the geochemical characteristics of the source rocks and the natural gas, the genesis of the Upper Palaeozoic natural gas was identified. In addition, the accumulation process was discussed by combining studies of hydrocarbon generation and burial/thermal history. The results reveal three sets of source rocks developed in the study area—Carboniferous Benxi (C2b), Permian Taiyuan (P1t), and Shanxi (P1s) formations—consisting of mudstones, carbonaceous mudstones, and coals. The source rocks contain abundant Type III organic matter and have entered mature to high‐mature stage, while source rocks in the south‐eastern part of the study area have entered the overmature stage due to the activity of Zijinshan magmatic rocks. The natural gas has a high content of methane (average 93.99%). The stable carbon isotope of methane (δ13C1) value (average −37.05‰) and that of ethane (δ13C2) value (average −26.4‰) and the composition of the light hydrocarbons reflect the idea that the natural gas is organic in origin, thermogenic, and mainly terrigenous‐sourced. The evolution of a transitional to continental depositional environment of the source rocks results in the variation in the geochemical characteristics of the Upper Palaeozoic gas in the study area. Analysis of fluid inclusions indicates a long and continuous period of natural gas charging in the study area from 165 to 65 Ma. Sandstone bodies close to or interbedded with the source rocks made the gas charging from the source rocks to the reservoirs over a short distance with high efficiency, while faults and fractures provided paths for the gas migrating to reservoirs vertically far from the source rocks. The huge gas generation potential of the source rocks and continuous distribution pattern of sandstone bodies provides favourable conditions for the development of a large‐scale natural gas reservoir. [ABSTRACT FROM AUTHOR]

Hydrocarbon migration mechanism in deep Ordovician reservoir of the Halahatang area, Tarim Basin, is investigated based on the analysis of the geological setting and geochemical parameters. The parameters successfully analyzed include oil–gas properties, crude oil maturity [Ts/(Ts + Tm) ratio], gas carbon isotopic ratios, and trace elements (B, V, Ni, and Cu) in crude oil. The results show that hydrocarbons migrate into the Ordovician of the Halahatang area from the Manjiaer Depression and the Halahatang area itself through unconformities and faults. The overall hydrocarbon migration orientation in the area is generally from south to north. The oil and gas migration process determine parameters vary regularly from south to north as follows: oil density, V/Ni ratio, Ni/Cu ratio, and concentrations of V, Ni and (Ni + B) in crude oil regularly increase, whereas Ts/(Ts + Tm), gas/oil ratio, and dryness coefficient gradually decrease, and methane show a trend toward depletion of heavy carbon isotopes. Additionally, there exist obvious anomalies of geochemical parameter values in the Repu3 well block, which indicates that a local fault intersection could provide a favorable hydrocarbon filling point. Based on these findings, further exploration activities in the deep Ordovician reservoir of the Halahatang area should be conducted in the southern part of the Halahatang area along the oil charging pathways, and fault intersection zones should be emphasized. [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]

Decrease in TOC of the carbonate source rock with low total organic carbon (CSRLTOC) contents with hydrocarbon generation and expulsion (a, b, c) and the lower limit of TOC (LLTOC) decreases (d) with the increasing T max or VR. • The CSRLTOC (carbonate source rocks with low total organic carbon) can be effective to oil/gas accumulation in China. • The LLTOC (lower limit of total organic carbon) for effective carbonate source rocks at various mature stages is determined. • Some oil/gas fields have derived partly or mostly from the CSRLTOC. • The CSRLTOC should be conducted for more in-depth studies in the future. Carbonate rocks with high maturity and low total organic carbon content are widely distributed in China. Whether they can be effective source rocks remains controversial, but they have great significance for the evaluation of hydrocarbon generation potential and exploration prospects of carbonate rocks. Dataset reveals that as the depth or maturity increases, total organic carbon (TOC) content, atomic H/C ratio, and hydrocarbon generation potential of carbonate source rocks with low total organic carbon (CSRLTOC) all decrease because of hydrocarbon expulsion. Moreover, some pyrolysis experiments also indicate that the CSRLTOC are able to generate and expel a quantity of hydrocarbons. The above studies indicate that CSRLTOC can be effective source rocks for oil/gas pools. The unique features of carbonate rocks and CSRLTOC demonstrate that they are easier to expel hydrocarbons and contribute to oil/gas reservoirs than shale, and thus, the lower limit of TOC (LLTOC) of effective carbonate source rocks could be smaller than shale (0.5%). The LLTOCs of effective carbonate source rocks with type I-II 1 kerogen (mainly sapropelic group) at the levels of immaturity and low maturity, maturity, high maturity and over maturity are TOC = 0.5%, 0.5–0.3%, 0.3–0.2%, and 0.2–0.1%, respectively. If the carbonate source rocks are at the high-over mature stage, we could take 0.2% as the LLTOC. The present organic-poor source rocks with high maturity are possibly moderate or good source rocks at the low mature level in the geological periods, especially carbonate source rocks if type I-II 1 kerogen. Some typical oil and gas fields in China derive partly or mostly from the CSRLTOC, proving that CSRLTOC could be effective source rock in China. [ABSTRACT FROM AUTHOR]

Reliably and conveniently predicting oil and gas prospects and avoiding costly drilling mistakes are the goals pursued by oil explorers and companies. In 2013, the Anyue gas field was discovered in Sichuan Basin, and it was the first discovery of a giant natural gas field in Precambrian strata attracting extensive attention since then. However, the complexity of geology in the Sinian-Lower Paleozoic makes prediction of oil and gas prospects very challenging. Based on the comprehensive review of the Anyue gas field, we identify four functional elements, i.e., a source kitchen (S), paleo-uplift (U), reservoir depositional facies (D), and regional cap rock (C). The combination of these four functional elements in time and space (T- CDUS) controls the Sinian-Lower Paleozoic hydrocarbon accumulation. The probability for hydrocarbon accumulation is determined by a proposed index, Tcdus. As a tectonic movement can damage oil and gas reservoirs formed prior to the movement, a model for calculating the hydrocarbon reservoir preservation probability is also established. The oil and gas prospects in Sinian-Lower Paleozoic are predicted with the combination of the hydrocarbon accumulation and preservation model. 137 wells drilled in the Sichuan Basin show that 88.9% of the successful wells are distributed in the predicted zones. • Four functional elements control the formation of oil and gas reservoirs. • Damage of tectonic movement to petroleum accumulations is analyzed. • The oil and gas prospects of the Sinian-Lower Paleozoic are predicted. [ABSTRACT FROM AUTHOR]

Despite the enormous potential of continental shale oil resources, only recoverable shale oil is economically valuable. Shale oil development decisions can greatly benefit from an accurate assessment of recoverable shale oil resources. Three crucial factors for evaluating shale oil recoverable resources are shale oil content, movable oil ratio, and recovery factor. However, because of the significant variety of continental shale, it is challenging to define the aforementioned characteristics. The methodologies and technology for determining the shale oil recoverable resource evaluation parameters, particularly the shale oil content, movable oil ratio, and recovery factor, are thoroughly discussed in this paper. Taking the Tertiary Sha-3 continental shale in Dongpu and Nanpu sags in Bohai Bay Basin, eastern China as an example, the shale oil content was obtained by the pyrolysis method with light and heavy hydrocarbon calibration comprehensively considered, and the main controlling factors of shale oil content were explored. Four geological parameters, including the sedimentary facies, pore structure, surrounding rock quality, and burial depth, primarily regulate the variation features of continental shale oil. The formation mechanism and primary governing variables of movable oil were then revealed using a physical simulation experiment. As porosity and permeability rise, clay mineral content falls, oil viscosity falls, and kerogen concentration rises, the movable oil ratio rises as well. Through stepwise linear regression, a quantitative estimation model for movable oil ratio was developed. After that, a literature search was used to determine the average recovery factor for continental shale oil. Finally, using the volume method model and the Monte Carlo methodology, the recoverable shale oil resources in the Gaoliu area of Nanpu Sag were assessed. The retention, movability, and resource potential of continental shale oil are better understood as a result of this study. [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]

Hydrocarbon evaporative loss evaluation is important for shale oil resource assessment. We propose a mass balance model to evaluate the hydrocarbon evaporative loss (S 1-loss ) in this study. The proposed method is applied to a large Rock-Eval pyrolysis dataset on source rock samples from the Lucaogou Formation in the Jimusaer Depression of the Junggar Basin, NW China, as a case study to evaluate the S 1-loss . The results indicate that the S 1-loss can range from 0.12 to 7.25 mg/g Rock, corresponding to 11%–89% loss of the generated hydrocarbons (S 1-loss /(S 1 +S 1-loss )) due to evaporation before lab analysis. It appears that when Ro ≤ 1.3%, S 1-loss and S 1-loss /TOC decreases gradually with increasing Ro, likely corresponding to increasing oil density as results of heterogeneous source rock compositions and increased accommodation space via the creation of organic pores of large specific surface for heavy and large hydrocarbon molecules in oil window. When Ro > 1.3%, S 1-loss /TOC begins to increase with increasing Ro as more oil crack to gaseous and light hydrocarbons that are more susceptible to evaporative loss. In the case of similar Ro, the relative S 1-loss /TOC varies little among the samples but the absolute S 1-loss amount increases with increasing TOC. Restricted by regional geological conditions in this study, we focused on the S 1-loss for lacustrine type I kerogen only, and quantification of evaporative loss for other kerogen types remains a subject for further study. [ABSTRACT FROM AUTHOR]

Jingbian gas field is yet the only Lower Paleozoic-hosted large gas field discovered in Ordos Basin. However, much debate still exists regarding the type and main source of natural gas in the Lower Paleozoic units. Previous studies on Jingbian gas field have mainly focused on the central and northern regions, whereas few studies have addressed the southern part. Basing on natural gas components and carbon isotope compositions of 33 gas samples from 28 wells in southern Jingbian gas field, we investigated the main gas source and phenomenon of carbon isotope reversal. The results indicate that natural gas from the Upper Paleozoic and Lower Paleozoic units are all at the high-mature and over-mature stages, with average dryness coefficients (C 1 /C 1-4 ) of 0.982 and 0.996, respectively. The Upper Paleozoic natural gas primarily comprises coal-derived gas from Carboniferous-Permian units, whereas the composition of the Lower Paleozoic natural gas is mostly a mixture of Upper Paleozoic coal-derived gas with additional oil-type gas produced by Upper Paleozoic marine limestone. The phenomenon of carbon isotope reversal mainly results from downward diffusion and migration of the mixed coal-derived gases; moreover, in the Upper Paleozoic unit, it is also related to secondary cracking. [ABSTRACT FROM AUTHOR]

Significant progress has recently been made in tight oil exploration within the Permian Lucaogou (P2l) Formation of the Jimusar Sag. However, current tight oil exploration deployment of the P2l Formation is mainly based on reservoir prediction, which is high risk for tight oil exploration. In this study, the geological and geochemical characteristics of the P2l Formation source rocks, including the distribution, sedimentary environment, organic matter abundance, kerogen types and thermal maturity were investigated. Hydrocarbon generation and expulsion intensity were evaluated through an improved hydrocarbon generation potential methodology, and the significance of source rocks in tight oil source and occurrence was systematically investigated. Results indicate that P2l Formation source rocks with total organic carbon >1.0 wt% occur widely (an area up to 1500 km2), are thick (up to 160 m), were deposited in a lacustrine weakly reducing sedimentary environment with relatively low salinity, have a high total organic content with a mean value of 3.12 wt%, are dominated by type II kerogen and have reached the early mature to mature stage. Modelling results indicate that the source rocks reached the hydrocarbon generation threshold and hydrocarbon expulsion threshold at 0.48% and 0.86% vitrinite reflectance, respectively. The comprehensive hydrocarbon expulsion efficiency was approximately 30%, and the maxima of hydrocarbon generation and expulsion intensities for P2l Formation source rocks are 1200 × 104 and 425 × 104 t/km2. The tight oil is sourced from adjacent source rocks that are interbedded with, or are close to, the reservoirs. The migration of oil generated from the source rocks occurs over very short distances. The oil filling degree index (oil bearing thickness/P2l Formation thickness) is higher at a closer proximity to the source rocks, and where it is higher the hydrocarbon generation intensity of the source rocks is also elevated. In addition, the greater the hydrocarbon expulsion intensity of the source rocks, the higher the daily oil production values (ton/day) from prospect wells. Copyright © 2016 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Shales from the Lower Silurian Longmaxi Formation in the Sichuan Basin are among the most important shale gas reservoirs in China, and have been investigated because of their great shale gas potential. To understand the pore structure and fractal characteristics of the shales, a series of experiments was conducted on core samples from the Lower Silurian Longmaxi Formation in the Sichuan Basin of China, including X-ray diffraction (XRD), total organic carbon (TOC) content and vitrinite reflectance (Ro) analysis, field emission-environmental scanning electron microscope (FE-ESEM) observation, and low-pressure N 2 adsorption-desorption experiments. Frenkel-Halsey-Hill (FHH) method was applied to calculate fractal dimensions. In addition, the pore genesis, the relationships between composition and thermal maturity, the pore structure parameters, and the fractal dimensions are discussed. FE-ESEM observation results show that the Longmaxi Formation shales are dominated by organic-matter (OM) pores along with interparticle (interP) pores, intraparticle (intraP) pores and fracture pores. This study identified the fractal dimensions at relative pressures of 0–0.45 and 0.45–1 as D 1 and D 2 respectively. D 1 ranged from 2.60 to 2.71 and D 2 ranged from 2.71 to 2.82. D 1 was typically smaller than D 2 , indicating that the smaller pores in shales were more homogeneous than the larger ones. The formation of these OM pores is owing to kerogen deformation during the thermal maturation, which results in a large number of nanopores. The pore structure of the Longmaxi Formation shales is primarily controlled by TOC content and thermal maturity. TOC content is a controlling factor on the fractal dimensions as it exhibited positive correlations with D 1 and D 2 . Fractal dimensions are useful for the characterization of the pore structures complexity of the Longmaxi Formation shales because D 1 and D 2 correlate well with pore structure parameters as they both increase with the increase of surface area and the decrease of average pore diameter. [ABSTRACT FROM AUTHOR]

Replacing coal with cleaner hydrocarbon resources is a viable solution to reach carbon neutrality goals over time, especially given the current lack of growth in green energy resources (e.g., hydro, solar, wind, geothermal) globally. Hydrocarbon resources offer a low-carbon, low-waste, large-scale, rapid solution. Dynamic continuous hydrocarbon accumulation (DCHA) exists widely in sandstone and shale reservoirs and has enormous resource potential. However, understanding the accumulation mechanisms and models of DCHAs in different structural locations is highly challenging. In this study, we first extensively review hydrocarbon resources derived from hydrocarbon accumulation and identify key scientific issues and theories. We then take the well-known typical DCHA in the Bohai Bay Basin in eastern China as a case, and combine multiple analytical methods, such as biomarker analysis, petroleum and aqueous inclusion analysis, quantitative fluorescence analysis, microscopic thin section observations, and basin modeling, to investigate petroleum sources, charging times, and charging forces. The results of our study show that the DCHA is a superimposed accumulation of multiple petroleum reservoir types with multiple petroleum sources, charging times, charging forces, and modes. Petroleum reservoirs at high structural locations are conventional trap reservoirs accumulated by buoyancy in the early stage, with long migration distances. Petroleum reservoirs at the sag location are deep unconventional petroleum reservoirs accumulated by the petroleum generation pressurization force in the middle stage, with short migration distances. Petroleum reservoirs at the slope location are superpositions of conventional traps and deep unconventional petroleum reservoirs in the middle and late stages, with moderate migration distances. [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 article discusses a study concerning the hydrocarbon generation and expulsion characteristics of Permian Lucaogou Formation source rocks in Jimusar Sag, Junggar Basin in China. Topics include the exploration practice in the basin, the organic matter abundance of the formation, and the maturity and characteristics of hydrocarbon generation and expulsion. Methods used in the study include well logging, core logging, and rock-evaluation.

Tight-sand gas in the Jurassic and shale gas within the fifth member of Xujiahe Formation (T3×5) in the Western Sichuan Basin (WSD) are currentiy regarded as the most proiific emerging unconventional gas plays in China. This study conducted a conventional evaluation of T3×5 source rocks in the WSD, and investigated their hydrocarbon generation and e×pulsion characteristics, including intensity, efficiency and amount. The results show that, the T3×5 source rocks are thick (generally >200 m), and have a high total organic content (TOC), ranging from 2.5 to 4.5 wt%. It is thus indivative of a great hydrocarbon generation potential when they underwent high thermal evolution (Ro>1.2%) in the area. In addition, an improved method of hydrocarbon generation potentiai is applied, indicating that the source rocks reached a hydrocarbon e×pulsion threshold with vitrinite reflectance (Ro) reaching 1.06%, and that the comprehensive hydrocarbon e×pulsion efficiency is about 60%. The amount of hydrocarbon generation and e×pulsion from T3×5 source rocks is 3.14×10 t and 1.86×10 t, respectiveiy, with a residual amount of 1.28×10 t within them. Continuous-type tight-sand gas is predicted to have developed in the Jurassic in the Chengdu Sag of the WSD because of the good source-reservoir configuration; the Jurassic sandstone reservoirs are tight, and the gas e×pelied from the T3x5 source rocks migrates for very short distances verticaliy and horizontaily. The amount of gas accumulation in the Jurassic reservoirs derived from T3x5 source rocks is up to 9.3×10 t. Geological resources of shale gas are up to 1.05×10 t. Small differences between the amounts calculated by the volumetric method and those obtained by hydrocarbon generation potential method may be due to other gas accumulations present within interbedded sands associated with gas shales. [ABSTRACT FROM AUTHOR]

Highlights: [•] Input parameters and boundary conditions were customized and simulated. [•] Hydrocarbon generation and migration was modeled on wells, cross-section, and maps. [•] Fluid potential and flow line modeling reveals that structural highs are directions of hydrocarbon migration. [Copyright &y& Elsevier]

Abstract: The superimposed basins in the Tarim Basin are characterized by multiple source-reservoir-caprock combinations, multiple stages of hydrocarbon generation and expulsion, and multi-cycle hydrocarbon accumulation. To develop and improve the reservoir forming theory of superimposed basins, this paper summarizes the progress in the study of superimposed basins and predicts its development direction. Four major progresses were made in the superimposed basin study: (1) widely-distributed of complex hydrocarbon reservoirs in superimposed basins were discovered; (2) the genesis models of complex hydrocarbon reservoirs were built; (3) the transformation mechanisms of complex hydrocarbon reservoirs were revealed; (4) the evaluation models for superimposed and transformed complex hydrocarbon reservoirs by tectonic events were proposed. Function elements jointly controlled the formation and distribution of hydrocarbon reservoirs, and the superimposition and overlapping of structures at later stage led to the adjustment, transformation and destruction of hydrocarbon reservoirs formed at early stage. The study direction of hydrocarbon accumulation in superimposed basins mainly includes three aspects: (1) the study on modes of controlling reservoir by multiple elements; (2) the study on composite hydrocarbon-accumulation mechanism; (3) the study on hydrocarbon reservoir adjustment and reconstruction mechanism and prediction models, which has more theoretical and practical significance for deep intervals in superimposed basins. [Copyright &y& Elsevier]

Abstract: Based on the distribution features of present formation pressure, analysis on logging data, and genetic mechanisms of abnormal pressure, the overpressure evolution was reconstructed using numerical basin simulation and other quantitative analysis methods. The phase differences of pressure increasing mechanisms, enhancement differences among different mechanisms, and the control of geopressure evolution on gas migration and accumulation were discussed. The causes of overpressure in the Xujiahe Formation include under-compaction (from early Late Triassic to the end of the Jurassic), hydrocarbon generation (from end of the Early Jurassic to the Neogene) and tectonic compression (since the Cretaceous). It is suggested that tectonic compression and hydrocarbon generation are the principal factors of the present overpressure in the Xujiahe Formation. Overpressure transmission is the main cause of overpressure in the Jurassic strata which occurred during the intense tectonic activity periods since the Cretaceous. The overpressure is the main force for hydrocarbon migration and overpressure-related microfractures are the major pathways for gas migration. Fault transport and overpressure driving caused the formation of Jurassic secondary gas reservoirs with distant sources. The areas with high pressure coefficient in the Jurassic and high-overpressure zones in the Xujiahe Formation are optimum targets for exploration. [Copyright &y& Elsevier]

The process of organic matter transformation into oil and gas is also a balance process of hydrocarbon transformation. This article probes to distinguish the oil expulsion history from gas expulsion history based on the hydrocarbon generation, hydrocarbon residual, and hydrocarbon expulsion processes of the source rocks. In this method, the first step is to study the hydrocarbon expulsion rate by means of hydrocarbon generation potential method; the second step is to study the oil generation rate by means of the heating-pressuring experiment method; the third step is to study the oil residual rate by means of the mathematical method. The difference between the values of oil generation rate and oil residual rate is defined as the oil expulsion rate, while that between the values of hydrocarbon expulsion rate and the gas expulsion rate is defined as the gas expulsion rate. Then, combined with the geological parameters of source rocks, the oil and gas expulsion history can be obtained. This study on Es Source rocks, Nanpu Sag, Bohai Bay Basin, China shows that the primary expulsion period of Es source rocks is Guantao-Minghuazhen period. [ABSTRACT FROM AUTHOR]

Abstract: Subtle traps have become an important petroleum play type for exploration in the Dongying Depression, Bohai Bay Basin, eastern China. The majority of the oil pools are in the middle interval of the Es 3 member of the Eocene–Oligocene Shahejie Formation, with the subtle traps being primarily in the lenticular, basin floor turbidite sands enclosed within basin floor mudstones. Detailed geochemical investigation of 68 oil and rock samples from the depression reveals that in contrast to previous models, the oils from the subtle traps correlate poorly with the surrounding source rocks. While the high pristane/phytane (Pr/Ph > 1) and low gammacerane/C30-hopane ratios in these source rocks represent a freshwater lacustrine setting, the oils feature low Pr/Ph ratios (<1) and relatively high gammacerane contents similar to the upper source rocks deposited in a brackish lacustrine setting. The compound-specific isotope ratios of n-alkanes in the oils have intermediate values between those observed in extracts from the lower Es 3 and upper Es 4 source rocks. Consequently, the oils in the subtle traps were most likely derived from mixed and sources, with the contribution from the source rocks being predominant. The oils generated from the source rocks must have migrated through a thick interval of the source rocks to reach the subtle traps in the , through which there are no apparent structural nor stratigraphic pathways. The traditional migration and accumulation model, i.e. indigenous crude oil with short migration distance to lenticular oil pools, should be revised to account for the charging of oils from source rocks. [ABSTRACT FROM AUTHOR]

Abstract: A total of 108 drill stem test (DST) crude oil samples and 10 reservoir fluid inclusion samples were investigated geochemically to identify the characteristics and origin of the crude oil in the Tazhong Uplift, Tarim Basin, NW China. Results show that the majority of oils share typical biomarker characteristics from the Middle-Upper Ordovician (O2+3) source rock and related crude oil features. These features include a distinct “V” shape in the relative abundance of C27, C28 and C29 regular steranes, and low abundances of dinosterane, 24-norcholestanes, triaromatic dinosteroids and gammacerane. Only a few oils display typical biomarker features indicating a Cambrian–Lower Ordovician (ϵ-O1) genetic affinity, such as linear or “anti-L” shape C27, C28 and C29 regular sterane distributions, and relatively high concentrations of dinosterane, 24-norcholestanes, triaromatic dinosteroids and gammacerane. It appears that most of the oils studied were derived from the O2+3 intervals, as suggested by previous studies. However, the δ13C values of individual n-alkanes indicate that most of the crude oils in the Tazhong Uplift represent a mixture of two end member oils, an O1-ϵ derived oil, such as from well TD2 (or TZ62 (S)), and an O2+3 derived oil, such as from well YM2. The data suggest that most of the oils in the uplift have a mixed origin, and do not originated from the Middle-Upper Ordovician strata alone. This conclusion is supported by data on the molecular composition of petroleum inclusions. This new oil mixing model is critical for reconstructing the hydrocarbon formation and accumulation history for the region, and may have important implications for further petroleum exploration in the Tarim Basin. [Copyright &y& Elsevier]

Abstract: The hydrocarbon migration and entrapment mechanism in the lower overlapped basins, occurring in the complex carbonate pore-fissure-fracture reservoirs, is one of the key problems that have to be solved for effective hydrocarbon exploration. The production, gas/oil ratio, and the composition of crude oils and natural gas in the TZ83 Well block are high at the intersection point of the NE and NW-strike faults and decrease gradually along the ridge of the structure. A basic model of the pore-fissure-fracture system is built according to the achievements in the research on carbonate karstification. Processes of hydrocarbon migration and entrapment in this system are analyzed, which indicate that an understanding of the complexness of differential hydrocarbon migration is the key to interpreting this phenomenon. The hydrocarbon must charge the nearest compartment before migrating further away to charge other compartments in its pathway in the complex pore-fissure-fracture system. As a result, the following two phenomena appear: (1) Gas is enriched near the hydrocarbon injection point and drives away the oil, which is enriched in the compartments farther from the injection point. (2) The complex gas–oil–water relationship is controlled by the lateral connecting networks. Based on this, this article shows that the fault intersection point is the injection point of the oil and gas, and the main pathway system is distributed along the ridge of the structure. The theory of deferential hydrocarbon migration in the pore-fissure-fracture system can be presented from two aspects: (1) In hydrocarbon exploration, the structure of the fissure-fracture system should be described first, and then the special distribution of gas–oil–water can be predicted according to the main charging point and the main pathway system. (2) Exploration should be confined to the hydrocarbon charging point and the main pathway systems. An explored area should not be abandoned merely due to failures in some wells. [Copyright &y& Elsevier]

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]

Abstract: A method to quantitatively estimate residual or palaeo-oil column heights is proposed using criteria based on the presence or absence of oil shows in a single heterogeneous reservoir rock sample. The residual or palaeo-oil column height below the sample is constrained through the determination of the displacement pressure of regions in the sample containing oil shows (P d-o) and the displacement pressure for regions that are devoid of any evidence of oil shows (P d-w). The height of the residual or palaeo-oil column below the sampling depth can then be estimated to be greater than the equivalent height corresponding to P d-o, but less than the height corresponding to P d-w. Three examples from two basins in China were investigated using the method to determine their residual and palaeo-oil column heights. [Copyright &y& Elsevier]

The chemical compositions of 28 representative crude oils and oil sand samples collected from the Bamianhe region of the Bohai Bay Basin, eastern China were studied in detail in order to understand their genetic relationships, biodegradation ranking and thermal maturity level. Molecular geochemical parameters indicate the presence of one single oil family in the Cenozoic reservoirs. A number of biomarker features support deposition of the source rocks for these oils under conditions of enhanced salinity/stratified water columns. The extremely low maturity levels of these “immature oils”, as indicated by sterane isomerization ratios, were not supported by other maturity parameters. The genetic relationship between the oils and the Es4 and Es3 members of the Eocene-Oligocene Shahejie Formation present in the deeper part of the Niuzhuang Sag, but not those along the Niuzhuang South Slope was suggested using a wide range of molecular parameters. Variation in the sterane concentrations observed from potential source rocks with different maturity levels in the study area suggests a high probability of migration contamination of mature oils by immature bitumens along migration pathways or from intra-reservoir shales. Variation in the level of oil biodegradation could also create anomalies in the use of gross oil compositions as an indicator of oil maturity. Although the recent rapid subsidence of the Bohai Bay Basin and the saline depositional environment of one of the potential source rocks favor oil generation at relatively low maturity levels, most of the economic oils discovered in the Bamianhe region appear to have derived from conventionally mature source rocks but contain lower maturity fluids admixed with them. [Copyright &y& Elsevier]

The chemical compositions of 20 crude oils and the extracts of potential source rocks from the Jinhu Depression of the North Jiangsu-South Yellow Sea Basin, eastern China were studied in detail by geochemical methods in order to understand their genetic relationship. The oil samples were collected from the major producing fields in the Western Slope (WS) and the Biandong-Yangjiaba-Minqiao uplift belt (BMY). The rock samples studied, selected after Rock-Eval pyrolysis screening of a large suite of samples, consist of 20 shale samples in the E2f2 member of the Paleocene Funing Formation from the oilfield areas (WS and BMY) and the Sanhe sag all within the Jinhu Depression. Geochemical characteristics indicate only one single family of oils. A number of biomarker features support deposition of the source rocks for these oils under conditions of enhanced salinity/stratified water columns. A wide thermal maturity range for the oils as indicated by sterane isomerization ratios was not substantiated by other maturity parameters. The genetic relationships between the oils and the E2f2 member of the Paleocene Funing Formation present in the deeper parts of the Sanhe and Longgang sags were suggested using a wide range of molecular parameters. Variation in the sterane concentrations in source rocks with different maturity suggests that migrational contamination and/or in-situ extractions of organic matter from caprocks or intra-reservoir shales by mature oils could potentially produce oils with apparent immaturity at the molecular level. Secondary alteration (e.g. biodegradation) of oils in the reservoir could also have a similar effect on the bulk oil compositions. Although we do not discount the possible presence of minor amounts of “immature oils”, exploration focus in the Jinhu Depression, as well as many other rift basins in eastern China, should be on mature oils derived from the deep source kitchens. [Copyright &y& Elsevier]

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]

Carbonate petroliferous basins usually develop fault-reservoir composite migration pathway systems. Accurate estimates of transport efficiency are important for locating oil and gas prospects, which is of considerable interest to oil explorers. The Cambrian Longwangmiao Formation in the Moxi–Gaoshiti area in the Sichuan Basin, the largest single monoblock gas accumulation in China with complicated migration pathway systems, was selected as an example to demonstrate the method. Using a combination of geologic, statistical, experimental data analyses, and quantitative characterization, a quantitative method for calculating the fault-reservoir composite transport efficiency is established for the first time. The results show that fault-reservoir composite migration pathway systems control the hydrocarbon accumulation. The analysis of data from 17 drilling wells using this method indicated a strong correlation between well productivity and composite transport efficiency, and the matching degree of actual and predicted results was as high as 83%. The best locations for oil and gas exploration are near areas with a high composite transport efficiency. Project planners can quickly find oil and gas prospects by matching calculated composite transport efficiencies to observed petroleum occurrences in a basin to avoid costly drilling mistakes. The method will have wide application in other carbonate basins around the world. • The fault-reservoir composite migration pathway controls hydrocarbon accumulation. • Quantitatively method for the composite transport efficiency is first established. • Composite transport efficiency is useful for location of oil and gas prospects. • Prospects for future drilling in the Moxi-Gaoshiti area of China are recommended. [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]

• Non-effective and effective sandstone reservoirs were identified. • Effective reservoirs' hydrocarbon enrichment potential was quantitatively evaluated. • Exploration was recommended to improve project performance by considering risks. Geological uncertainty is the greatest risk in oil exploration. Most of the evaluation and risk assessment of exploration projects are characterized by the hydrocarbon enrichment evaluation of the target reservoir to avoid non-effective reservoirs. Based on experiments and detailed analysis of the hydrocarbon accumulation process, we propose a new criterion, namely reservoir hydrocarbon enrichment potential index, expressed as PI , for improved evaluation and assessment. According to the index PI , sandstone reservoirs are classified into four categories: Level IV, PI ≤ 0; Level III, 0 < PI ≤ 0.01; Level II, 0.01 < PI ≤ 0.1; Level I, 0.1 < PI ≤ 1. Level IV reservoirs are non-effective, whereas Level III, Level II, and Level I reservoirs are effective and their hydrocarbon enrichment potentials increase progressively. The recommended strategy is to prioritize the exploration of sandstone reservoirs in the order of Level I > Level II > Level III and avoid Level IV reservoirs. This strategy was applied to the Mesozoic sandstone in western Sichuan Depression, China, to demonstrate the method and workflow. Drilling success rate is positively correlated with the PI of the sandstone reservoir. The results of 153 wells drilled in western Sichuan Depression show the accuracy of the method to be 84.5%. Therefore, this method is useful for quick and effective scientific decisions on oil exploration projects, thus mitigating the risks in oil exploration projects. [ABSTRACT FROM AUTHOR]

Due to the large resource potential of tight sandstone gas, the Upper Paleozoic strata of the Linxing area has become an important exploration target in the Ordos Basin. In this study, by analyzing the distribution characteristics of tight sandstone gas (TSG), the relations of source-reservoir assemblages were divided into three types containing interbedded with source rocks (Type I), adjacent to source rocks (Type II) and far from source rocks (Type III). Five factors were identified to control their genesis, migration, and accumulation. Firstly, the gas generation intensity of source rocks is larger than 10 × 108 m3/km2, which indicated that source rocks could provide gas to the reservoirs. The gas generation centers of source rocks control the distribution of TSG reservoirs, while the areas among the hydrocarbon generation centers were the enrichment zones for TSG. Secondly, under the condition of generally tight reservoirs, the sandstone reservoir which has good quality (high porosity, high permeability) provided the favorable accumulation condition for TSG. Thirdly, the study area experienced one stage of gas charging mainly from the late early Jurassic to late early Cretaceous, which was 178 to 100Ma. Continuous gas generation and expulsion led to the sustained accumulation of TSG. Fourthly, with the general development of overpressure in the Upper Paleozoic strata, gas expansion force as the main power drive natural gas to migrate into the reservoirs of type I and type II during the accumulation period. Finally, the development of faults and fractures provided a migration path for natural gas charging in the reservoir of type III vertically. The existence of microcracks can improve the petrophysical properties of tight reservoirs. Under the joint control of these factors, the reservoir of Type I is the most favorable exploration target. • The geological characteristics of tight sandstone gas reservoirs in the Linxing area were described. • The five controlling factors on tight sandstone gas reservoirs were discussed in detail. • The favorable exploration target was determined under the joint control of five factors. [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]

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]

Based on the definition and theoretical model of the LLHG (a), four methods including hydrocarbon generation potential (b 1), residual hydrocarbon amount (b 2), organic element variation (b 3) and expulsed hydrocarbon amount (b 4) are used to calculate the value of LLHG, the results are verified by the thermal simulation experiment (c). • The lower limit of hydrocarbon generation (LLHG) is redefined and modeled. • The LLHG is obtained based on methods of hydrocarbon generation potential and verified. • The LLHG values in the north of Dongpu Depression are generally larger than those in the south. • The main effect factors of LLHG are organic matter type and abundance, formation temperature and pressure. With the increasing demand for hydrocarbons, exploration tends to be deeper and unconventional resources. However, whether there are the lower limits for exploration depth or thermal maturity (R o) appears to be particularly essential. It is of considerable significance to determine the lower limit of hydrocarbon generation (LLHG) since this limit can provide guidelines for hydrocarbon potential estimation. According to the mechanisms of hydrocarbon generation and expulsion, five methods are combined to determine and verify the LLHG, whose values can be expressed by LLHG (Ro) and LLHG (H). Source rock samples from the Paleogene Shahejie Formation (Es) in the Dongpu Depression were taken as an example to determine the LLHG, and then controlling factors of the LLHG were discussed. LLHG (Ro) values for Es range from 3.23% to 3.97% (average 3.71%) and LLHG (H) values range from 5244 m to 5525 m (average 5433 m). Regionally, LLHG values display obvious differences between the northern and southern of depression. LLHG values in the north are roughly larger than those in the south. In the northern depression, the LLHG (Ro) values are ranging from 3.61% to 3.97% (average 3.81%) and LLHG (H) values are ranging from 5415 m to 5545 m (average 5488 m). However, in the southern part, the LLHG (Ro) values range from 3.20% to 3.74% (average 3.48%) and the LLHG (H) values range from 5265 m to 5375 m (average 5278 m). The main controlling factors for LLHG diversity between the north and the south of depression are organic matter (OM) type and abundance, formation temperature and pressure. [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]

Mineralogical, petrographical, geochemical analyses, and fluid inclusions petrography and microthermometry were combined to investigate the basic properties of the source rock (organic matter content, kerogen type, and thermal maturity) and sandstone reservoirs (composition, pore systems, porosity, and permeability), the hydrocarbon origin, and the formation mechanisms of the deep (>3.5 km) petroleum system in the Upper Paleogene Es1 (the uppermost member of the Shahejie Formation) in the No. 3 Structural Belt in the Nanpu Sag, Bohai Bay Basin. The results indicate that the Es1 source rock is primarily composed of dark gray mudstone and presents a set of high-quality source rocks (>500 m, average total organic carbon (TOC) 1.38%, in a mature stage (maximum pyrolysis yield of 430 °C–460 °C)). The Es1 sandstone is composed of lithic arkose formed in a braided river delta and has low porosity (average 13.4%) but moderate-high permeability (average 184.9 mD). The hydrocarbons originated from the Es1 source rocks in the Caofeidian subsag during two charging periods: 10 Ma and 3 Ma. The key factors controlling the formation of the deep petroleum system are as follows: (a) High-quality hydrocarbon supply, (b) Medium-high permeability reservoirs, (c) A favorable configuration of the source rock and reservoirs (self-generated and self-accumulated), and (d) Late hydrocarbon charging; the second factor is the most important. The medium-high permeability reservoirs are attributed to a high-energy depositional environment (distributary channels of braid delta front), a high content of rigid detrital grains (mainly quartz and metamorphic rock fragments) provided by the Archean granite provenance, and the secondary pores formed by feldspar dissolution. This study provides a new example for revealing the formation mechanisms of deep (>3.5 km) petroleum systems in the terrestrial rift basin across the Bohai Bay Basin. • Properties of sandstones and source rocks of a deep petroleum system are investigated. • The hydrocarbon origin of the deep petroleum system is revealed. • Controlling factors of high-quality sandstones are summarized. • Formation mechanisms of deep petroleum systems of the Bohai Bay Basin are detailed. [ABSTRACT FROM AUTHOR]

This study analyzes the bulk and molecular geochemical data of 56 core samples of the Eocene Qianjiang Formation, a confined source rock unit embedded with salt intervals formed in a hypersaline lacustrine setting in central China. These source rocks within a single evaporative cycle collected from a recent shale oil exploration well are highly laminated, consisting of both intra- and inter-salt shales. Both organic pores and matrix pores serve as storage for hydrocarbon generated from kerogen within the source rock. Because the contrast in density between kerogen and oil, conversion of kerogen to oil inevitably leads to the increase in pore pressure and oil expulsion from kerogen within the same source rock unit. Impregnation of source rocks by expelled oils from nearby mature source rocks or from the organic-rich laminae within the same source rock units leads to anomalous Rock-Eval pyrolysis data, characterized by an abnormally high S1 peak, a high Production Index (PI), a suppressed Tmax and other anomalies. It is contradictory that both Rock-Eval pyrolysis data and sterane isomerization ratios of the studied inter-salt shale samples indicate strong impact of allochthonous hydrocarbons in the source rocks, whereas most aliphatic biomarker parameters obtained from the solvent extracts of these shales still provide useful information on the vertical variation in organic source input and depositional environment of the host rocks. This study provides insights into the bulk and molecular geochemical data interpretation, particularly in the inter-salt shale oil system evaluation in inferring the prevailing directions and pathways of diagenetic fluid movement and hydrocarbon migration. • Impregnation of source rocks by expelled oils leads to anomalous Rock-Eval pyrolysis data • Evaporative edimentary records are biased, where the inter-salt sediments recorded mainly the salinity reducation process • Contradictory geochemical parameters in laminated inter-salt shales provide insight into the prevailing fluid directions and pathways [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 accumulation mechanism of hydrocarbons in the Yingmai 2 Oilfield of the Tabei Uplift in the Tarim Basin is not well understood. Here, the characteristics and formation of Paleozoic faults in the Yingmai 2 Oilfield are studied with new 3D seismic data and regional geologic data. Inclusion features and geochemical parameters are used to investigate the faults controlling the oil and gas compositions. The results indicate that three fault systems developed in the Yingmai 2 Oilfield: a NNW-trending strike-slip fault system that formed in the middle Caledonian, a NW-trending strike-slip fault system that formed in the Caledonian–late Hercynian and a NE-trending thrust fault system that formed in the late Hercynian–Indosinian, which was associated with volcanic activity. The two strike-slip fault systems were important early hydrocarbon migration pathways in the late Caledonian–early Hercynian, late Hercynian, and Himalayan accumulation periods. The NE-trending thrust faults were sealed by volcanics, and divided the originally uniform oilfield into two accumulation systems during the Himalayan. This finding is supported by the differences in the compositions of the oils and gases in the eastern (YM area) and the western (YG area) Yingmai 2 Oilfield. The oil density, iC 4 /nC 4 , Ph/nC 18 , and V/Ni ratios of the oils in the reservoirs in the YM area are lower than those in the YG area, whereas the TMNr, TeMNr, 4-1/DBT, Pr/Ph, C 29 -diasterane/C 29 -regular sterane ratios, H 2 S content, and the content of Himalayan hydrocarbon inclusions are higher. The hydrocarbon accumulation in the Yingmai 2 Oilfield is attributed to multiple episodes of hydrocarbon charging and suggests that the YM area has greater exploration potential than the YG area. [ABSTRACT FROM AUTHOR]

Deep sour gases are found in the Ordovician carbonate reservoir of the Tazhong Uplift in the Tarim Basin, northwest China. All sour gases in this field are dominated by gas hydrocarbons (C 1 –C 4 ) with varying amounts of H 2 S. Most of the gases in the eastern Tazhong are characterized by high gas dryness coefficients (>0.95), 13 C-enriched methane (δ 13 C 1 ranging from −44.6‰ to −35.8‰), and small difference between values of the δ 13 C 2 and δ 13 C 1 (δ 13 C 2 - 1 ). In contrast, the gases in the western Tazhong are characterized by relatively low gas dryness coefficients (mostly < 0.90), 13 C-depleted methane (δ 13 C 1 ranging from −54.9‰ to −35.7‰), and high values of δ 13 C 2 - 1 , indicating relatively lower maturity. Gas compositions, carbon isotope ratios, and diamantane data together with thermal pyrolysis experiments using sealed gold tubes suggest that the Ordovician gases in the Tazhong Uplift belong to oil cracking gases mixed with high-maturity 13 C-enriched dry gases, which originated from the deeper paleo-reservoirs cracking. The H 2 S (0.0008%–23.1000%) is attributed to thermochemical sulfate reduction (TSR); in contrast to typical TSR-altered gases, the natural gases in the western Tazhong are characterized by low dryness coefficients, relatively 13 C-depleted methane, and high δ 13 C 2 - 1 , suggesting a low degree of TSR alteration. Observations suggest that the H 2 S contents are generally high in the western Tazhong, with positive correlation to Mg 2+ concentrations and total dissolved solids (TDS) in the Ordovician formation water, indicating that TSR has entered early period of SO 4 2− contact ion pairs (CIPs) oxidation. Compared with the eastern Tazhong, the Mg 2+ concentrations and TDS in the western Tazhong are higher and form more CIPs that accelerate TSR and produce H 2 S. In addition, based on the analysis of the Cambrian formation water and the Cambrian gypsiferous salt, TSR might have also exist in the deeper Cambrian reservoirs, and the TSR-altered gases with high content of H 2 S migrated along faults to Ordovician reservoirs. [ABSTRACT FROM AUTHOR]

[Display omitted] • A new hydrocarbon generation and expulsion model was established. • Mudstones and Upper-Middle Eocene source rocks contributed most to petroleum system. • The new model provides an efficient method for identifying oil-gas sources. The widely developed Tertiary coal-bearing intervals in the Xihu Sag, East China Sea Shelf Basin in offshore eastern China, are hosted in the Middle-Upper Eocene Pinghu Formation (PHF) and Oligocene Huagang Formation (HGF). Based on field data and geochemical features, a new model for the hydrocarbon generation and expulsion is developed using Rock-Eval pyrolysis that was applied to quantify the potentials of coaly source rocks of the PHF and HGF throughout the Xihu Sag. The results suggest the coaly source rocks of the HGF and PHF are primarily composed of type II/III kerogen, and begin to expel hydrocarbon at 0.68 %R o and 0.71 %R o , respectively. Several hydrocarbon expulsion centers are located in the western slope zone for coals and the central anticline zone for mudstones, with the highest intensity of 3.5 × 106 and 24 × 106 t/km2 for coals and mudstones, respectively. Among all source rocks, the coals and mudstones contribute 2.5% and 97.5%, respectively, of the total expelled hydrocarbon, whereas the source rocks of the HGF and PHF provide 19% and 81%, respectively, of the total hydrocarbon. The study also shows that the natural gas discovered in the north of the central anticline zone and the north of the western subsag have mixed sources from the HGF and PHF while the light oil and condensate accumulated in other zones are primarily derived from the source rocks of the PHF. The model used in the Xihu Sag provides an efficient method for evaluating source rocks and identifying oil-gas sources. [ABSTRACT FROM AUTHOR]

Abstract: Unusually high dibenzothiophene (DBT) concentrations are present in the oils from the Tazhong-4 Oilfield in the Tazhong Uplift, Tarim Basin. Positive-ion electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) was used in combination with conventional geochemical approaches to unravel the enrichment mechanisms. Significant amounts of S1 species with relatively low DBE values (0–8), i.e., sulfur ethers, mercaptans, thiophenes and benzothiophenes, were detected in three Lower Ordovician oils with high thermal maturity, which were suggested to be the products of thermochemical sulfate reduction (TSR) in the reservoir. The occurrence of TSR was also supported by the coexistence of thiadiamondoids and abundant H2S in the gases associated with the oils. Obviously low concentrations of the DBE=9 S1 species (mainly equivalent to C0–C35 DBTs) compared to its homologues were observed for the three oils which were probably altered by TSR, indicating that no positive relationship existed between TSR and DBTs in this study. The sulfur compounds in the Tazhong-4 oils are quite similar to those in the majority of Lower Ordovician oils characterized by high concentrations of DBTs and dominant DBE=9 S1 species with only small amounts of sulfur compounds with low thermal stability (DBE=0–8), suggesting only a small proportion of sulfur compounds were derived from TSR. It is thermal maturity rather than TSR that has caused the unusually high DBT concentrations in most of the Lower Ordovician oils. We suggest that the unusually high DBT oils in the Tazhong-4 Oilfield are caused by oil mixing from the later charged Lower Ordovician (or perhaps even deeper), with high DBT abundances from the earlier less mature oils, which was supported by our oil mixing experiments and previous relevant investigations as well as abundant authigenic pyrite of hydrothermal origin. We believe that TSR should have occurred in the Tazhong Uplift based on our FT-ICR MS results. However, normal sulfur compounds were detected in most oils and no increase of δ13C2H6–δ13C4H10 was observed for the gas hydrocarbons, suggesting only a slight alteration of the oils by TSR currently and/or recently. We suspect that the abnormal sulfur compounds in the Lower Ordovician oils might also be a result of deep oil mixing, which might imply a deeper petroliferous horizon, i.e., Cambrian, with a high petroleum potential. This study is important to further deep petroleum exploration in the area. [Copyright &y& Elsevier]