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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]

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

Abundant shale oil resources were recently found in the organic‐rich Permian Lucaogou (P2l) Formation shale, Jimusar Sag, Junggar Basin. Although some scholars have conducted some researches on the basic geochemical characteristics of the Lucaogou Formation shale, it is not enough to effectively guide the shale oil exploration in the area. This is because during the exploration process of shale oil, besides the basic geochemical characteristics of shale, its mineral composition, physical properties, and oil‐bearing characteristics are all very important evaluation parameters. To systematically evaluate the favourable shale oil exploration sections in the Lucaogou Formation, 265 pieces of shale cores were sampled from well Ji174 in this study. Besides the basic geochemical characteristics of the 265 pieces of cores, the mineralogical, petrophysical, and oil‐bearing characteristics were also analysed. Results show that the shale has abundant organic matter (average total organic carbon 3.51%, average petroleum generation potential 15.67 mg/g), dominated by Type II1 and Type II2 kerogen, and has entered the early‐mature to mature stage. The Upper Member of the Lucaogou Formation has relatively higher organic matter and organic matter type is relatively more oil prone compared to the Lower Member; however, organic matter thermal maturity is lower. The P2l Formation shale is characterized by high carbonate minerals and low clay minerals, and when considering mineralogical brittleness, both the Upper and Lower members are ideally fracturable in shale oil development. The P2l Formation shale has a wide porosity range (1.1–13.9%), and the Lower Member's porosity is slightly greater. The inversion of shale porosity in the P2l Formation is controlled by the differentiated mineral composition. The oil saturation index values of the Lower Member shale are significantly greater than the Upper Member shale. From the above, the Lower Member of the P2l Formation shale is ideally suited and has greater shale oil potential in the Jimusar Sag, Junggar Basin, especially in the depth intervals of 3,255–3,272, 3,282–3,298, and 3,317–3,334 m in the well Ji174. [ABSTRACT FROM AUTHOR]

Recent exploration has revealed the great potential of gas resources, complicated gas distributions and geochemical characteristics of natural gases in tight sandstones of the West Sichuan Basin, China (WSBC). The chemical, stable carbon and light hydrocarbon compositions of natural gases from WSBC were investigated to assess the genesis, sources, and migration pattern leading to variations in the geochemical and stable carbon isotope compositions. The analysis shows that the natural gas in the Jurassic tight sandstones occurs as dry gas or wet gas in some places; however, most of the gas in the deep Triassic tight sandstones is apparently dry gas. Carbon isotope distributions increased in the order δ13C1 < δ13C2 < δ13C3 < δ13C4. The light hydrocarbon content increased in the order of chain (i.e. non-cyclic) alkanes, cycloalkanes, and aromatic hydrocarbons. Relatively high ethane carbon isotope values and methylcyclohexane contents indicated the presence of lacustrine coal-formed gases. The Jurassic natural gas is in a lower thermally mature stage and possibly originated from a mixture of T3X3 and T3X5 black mudstones. The deep Triassic natural gas was possibly originated in the deep source rocks because the gas has a relatively higher thermal maturity. Positive correlations between burial depth and methane content, dryness coefficient, δ13C1, and δ13C1-δ13C2 for the deep Triassic gas suggest that the migration distance was short and the source was nearby or the gas accumulated in situ. The chemical compositions and geological studies revealed that the fractionation of the Jurassic natural gases in a tight reservoir was predominantly caused by vertical migration rather than the maturity of the local source rocks. Copyright © 2016 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

There are two sets of carbonate source rocks in the Lower Carboniferous layers in Marsel: the Visean (C 1 v) and Serpukhovian (C 1 sr). However, their geochemical and geological characteristics have not been studied systematically. To assess the source rocks and reveal the hydrocarbon generation potential, the depositional paleoenvironment and distribution of C 1 v and C 1 sr source rocks were studied using total organic carbon (TOC) content, Rock-Eval pyrolysis and vitrinite reflectance (Ro) data, stable carbon isotope data, gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS) analysis data. The data were then compared with well logging data to understand the distribution of high-quality source rocks. The data were also incorporated into basin models to reveal the burial and thermal histories and timing of hydrocarbon generation. The results illustrated that the average residual TOC contents of C 1 v and C 1 sr were 0.79% and 0.5%, respectively, which were higher than the threshold of effective carbonate source rocks. Dominated by type-III kerogen, the C 1 v and C 1 sr source rocks tended to be gas-bearing. The two source rocks were generally mature to highly mature; the average Ro was 1.51% and 1.23% in C 1 v and C 1 sr, respectively. The source rocks were deposited in strongly reducing to weakly oxidizing marine–terrigenous environments, with most organic material originating from higher terrigenous plants and a few aquatic organisms. During the Permian, the deep burial depth and high heat flow caused a quick and high maturation of the source rocks, which were subsequently uplifted and eroded, stopping the generation and expulsion of hydrocarbons in the C 1 v and C 1 sr source rocks. The initial TOC fitted by the △logR method was recovered, and it suggests that high-quality source rocks (TOC ≥ 1%) are mainly distributed in the northern and central local structural belt. [ABSTRACT FROM AUTHOR]

The Pearl River Mouth Basin in the South China Sea has accumulated >2 km of Eocene sediments in its deep basin, and has become the exploration focus due to the recent discoveries of the HZ25-7 oil field in the Eocene Wenchang (E 2 w) Formation. In this study, the geochemical characteristics of potential source rocks and petroleum in the HZ25-7 oil field are investigated and the possible origins and accumulation models developed. The analytical results reveal two sets of potential source rocks, E 2 w and Enping (E 2 e) formations developed in the study area. The semi-deep-to-deep lacustrine E 2 w source rocks are characterized by relatively low C 29 steranes, low C 19 /C 23 tricyclic terpane (<0.6), low C 24 tetracyclic terpane/C 30 hopane (<0.1), low trans-trans-trans -bicadinane (T)/C 30 hopane (most <2.0), and high C 30 4-methyl sterane/ΣC 29 sterane (>0.2) ratios. In contrast, the shallow lacustrine and deltaic swamp-plain E 2 e source rocks are characterized by relatively high C 29 steranes, high C 19 /C 23 tricyclic terpane (>0.6), high C 24 tetracyclic terpane/C 30 hopane (>0.1), variable yet overall high T/C 30 hopane, and low C 30 4-methyl sterane/ΣC 29 sterane (<0.2) ratios. The relatively low C 19 /C 23 tricyclic terpane ratios (mean value: 0.39), low C 24 tetracyclic terpane/C 30 hopane ratios (mean value: 0.07), high C 30 4-methyl sterane/ΣC 29 sterane ratios (mean value: 1.14), and relatively high C 27 regular sterane content of petroleum in the HZ25-7 oil field indicate that the petroleum most likely originated from the E 2 w Formation mudstone in the Huizhou Depression. One stage of continuous charging is identified in the HZ25-7 oil field; oil injection is from 16 Ma to present and peak filling occurs after 12 Ma. Thin sandstone beds with relatively good connectivity and physical properties (porosity and permeability) in the E 2 w Formation are favorable conduits for the lateral migration of petroleum. This petroleum accumulation pattern implies that the E 2 w Formation on the western and southern margins of the Huizhou Depression are favorable for petroleum accumulation because they are located in a migration pathway. Thus exploration should focus in these areas in the future. [ABSTRACT FROM AUTHOR]

The process and mechanisms of secondary hydrocarbon migration in the Huixi half-graben, Pearl River Mouth Basin, were investigated on the basis of geological analysis of the strata and study of the porosity and permeability of the reservoir rocks, fluid potential, oil properties, and geochemistry of oil-source correlation. The results suggest that the hydrocarbons of the Zhujiang Formation in the Huixi half-graben were derived from source rocks of the Eocene Wenchang Formation and the Eocene-Oligocene Enping Formation in the Huizhou Sag. The hydrocarbons migrated laterally from northeast to southwest. The sandstone in the upper member of the Zhujiang Formation exhibited superior physical properties (porosity and permeability) and connectivity than the lower member. Thin sandstone beds with good physical properties and stable distribution in the upper member of the Zhujiang Formation were the main carrier beds for lateral hydrocarbon migration. [ABSTRACT FROM AUTHOR]

Seven hydrocarbon reservoirs have been discovered to date in the Upper Ordovician of the Tazhong Area, a region in which hydrocarbon phase distribution is complex. In the present study, the genesis and controlling factors of the hydrocarbons with complex phase in the Tazhong Area were investigated on the basis of the geological and geochemical conditions required for the formation and distribution of hydrocarbon reservoirs, integrated with the source rock geochemistry, natural gas and oil properties, and oil and gas reservoir fluid tests PVT (i.e., pressure, volume, and temperature tests). The results indicate that hydrocarbon reservoir types in the Upper Ordovician of the Tazhong Area transition from unsaturated to saturated condensate-gas reservoirs from west to east and from condensate-gas reservoirs to unsaturated-oil reservoirs from north to south. The crude oil in the region originated primarily from the mixing of Lower-Middle Cambrian and Middle-Upper Ordovician source rocks, while the natural gas was sourced primarily from the cracking gas of Lower-Middle Cambrian crude oil. This hydrocarbon-phase distribution was controlled primarily by temperature and pressure and has been affected by multiple periods of hydrocarbon accumulation and alteration. The high-quality Lower-Middle Cambrian reservoir-cap assemblage may be an important target for future exploration of natural gas in the Tazhong Area. [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]

Systematic analyses of the formation water and natural gas geochemistry in the Central Uplift of the Tarim Basin (CUTB) show that gas invasion at the late stage is accompanied by an increase of the contents of H2S and CO2 in natural gas, by the forming of the high total dissolved solids formation water, by an increase of the content of HCO−3, relative to Cl−, by an increase of the 2nd family ions (Ca2+, Mg2+, Sr2+ and Ba2+) and by a decrease of the content of SO2−4, relative to Cl−. The above phenomena can be explained only by way of thermochemical sulfate reduction (TSR). TSR often occurs in the transition zone of oil and water and is often described in the following reaction formula: σCH+CaSO4+H-2O→H2S+CO2+CaCO3. (1) Dissolved SO2−4 in the formation water is consumed in the above reaction, when H2S and CO2 are generated, resulting in a decrease of SO2−4 in the formation water and an increase of both H2S and CO2 in the natural gas. If formation water exists, the generated CO2 will go on reacting with the carbonate to form bicarbonate, which can be dissolved in the formation water, thus resulting in the enrichment of Ca2+ and HCO−3. The above reaction can be described by the following equation: CO2+H2O+CaCO3→Ca2++2HCO−3. The stratigraphic temperatures of the Cambrian and lower Ordovician in CUTB exceeded 120°C, which is the minimum for TSR to occur. At the same time, dolomitization, which might be a direct result of TSR, has been found in both the Cambrian and the lower Ordovician. The above evidence indicates that TSR is in an active reaction, providing a novel way to reevaluate the exploration potentials of natural gas in this district. [ABSTRACT FROM AUTHOR]

Abstract: Based on the distribution and geochemical characteristics of potential source rocks in the Niuzhuang and Guangbei sags and the Niuzhuang South Slope, Bohai Bay Basin, the quantities of hydrocarbons expelled from the Eocene-Oligocene Shahejie Formation were evaluated using a mass balance approach. The results confirm that most of the hydrocarbons in the study area were generated and expelled from the Shahejie Formation source rocks in the Niuzhuang Sag. The algae-rich, saline-brackish water lacustrine, Es4 oil shales of the Shahejie Formation from the Bamianhe to Wangjiagang region along the Niuzhuang South Slope exhibit excellent potential for early hydrocarbon generation, but they are not the major source for proven oil reserves in the Bamianhe region. The source rocks for most of the known oil reserves in the study area occur in the Es4 mudstones in the deep part of the Niuzhuang Sag. Thus, the commonly assumed origin of so-called “immature oils” from source rocks shallower than the conventional oil window in this area needs revision. [Copyright &y& Elsevier]

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]

A large amount of deep oil has been discovered in the Tazhong Uplift, Tarim Basin whereas the oil source is still controversial. An integrated geochemical approach was utilized to unravel the characteristics, origin and alteration of the deep oils. This study showed that the Lower Cambrian oil from well ZS1C ( 1x ) was featured by small or trace amounts of biomarkers, unusually high concentration of dibenzothiophenes (DBTs), high δ 34 S of DBTs and high δ 13 C value of n -alkanes. These suggest a close genetic relationship with the Cambrian source rocks and TSR alteration. On the contrary, the Middle Cambrian oils from well ZS1 ( 2a ) were characterized by low δ 13 C of n -alkanes and relatively high δ 34 S of individual sulfur compounds and a general “V” shape of steranes, indicating a good genetic affinity with the Middle–Upper Ordovician source rocks. The middle Cambrian salt rock separating the oils was suggested to be one of the factors responsible for the differentiation. It was suggested that most of the deep oils in the Tazhong Uplift were mixed source based on biomarkers and carbon isotope, which contain TSR altered oil in varied degree. The percentage of the oils contributed by the Cambrian–Lower Ordovician was in the range of 19–100% (average 57%) controlled by several geological and geochemical events. Significant variations in the δ 34 S values for individual compounds in the oils were observed suggesting a combination of different extent of TSR and thermal maturation alterations. The unusually high DBTs concentrations in the Tazhong-4 oilfield suggested as a result of mixing with the ZS1C oil ( 1x ) and Lower Ordovician oils based on δ 34 S values of DBT. This study will enhance our understanding of both deep and shallow oil sources in the Tazhong Uplift and clarify the formation mechanisms of the unusually high DBTs oils in the region. [ABSTRACT FROM AUTHOR]