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The shale from the Cretaceous Taizhou Formation is an important source rock in the Gaoyou Sag, Northern Jiangsu Basin. Fifty-three shale core samples analyzed for total organic carbon (TOC) and Rock-Eval pyrolysis analyses were used to evaluate the geochemistry of this shale. Twenty-one samples of them were analyzed using solvent extraction, extract fractionation, Gas Chromatography-Mass Spectrometer (GC-MS) of the saturated fraction, and organic petrology analyses. Based on the test results, the shale of the Taizhou Formation contains mainly Type II-III organic matter and is chiefly oil-prone and oil-gas-prone, as a fair to good oil-source rock with a small quantity of gas-source rock. Vitrinite reflectance, Rock-Eval pyrolysis, and biomarker suggest that in this sag, the shale of the Taizhou Formation is mainly in the early mature stage and within the oil window, so the shale generates chiefly liquid oil. The Gaoyou Sag is an oil-generating sag. The saturated fraction and biomarker composition of the shale provide evidence that the Taizhou Formation shale was formed mainly in a reductive sedimentary environment with anoxic fresh to low salinity water. The organic matter came chiefly from plankton and partly from land plants and bacterial organisms. [ABSTRACT FROM AUTHOR]

Shale oil exploration and development have been conducted in the Permian Lucaogou Formation in the Jimusaer Sag, Junggar Basin. The upper (P 2 l 2) and lower (P 2 l 1) members of the Lucaogou Formation developed with sand layers, which are the shale oil development sections in the Lucaogou Formation. In order to clarify the enrichment law of shale oil for these members, the geological conditions of the P 2 l 2 and P 2 l 1 members were analyzed. The focus of this study were oil-bearing sandstone and mudstone samples from the Lucaogou Formation. These samples were studied by casting thin section observation, total organic carbon, pyrolysis, and gas chromatography–mass spectrometry. The results showed that the upper and lower members of the Lucaogou Formation are mainly characterized as interbedded source rock and reservoir. An oil-source correlation showed that the crude oil in the upper member mainly originated from its adjacent source rock from a deeper position through secondary migration. However, no evidence of secondary migration was observed in the crude oil in the lower member which mainly originated from the adjacent source rock. For the sandbodies in the upper member, when burial is shallower than peak oil generation, the physical properties of the middle part of the sandbody are better than the top and bottom. When burial is deeper than peak oil generation, relatively good physical properties developed in the sandstone in the vicinity the source rock. The lower member has less reservoir thickness, poorer lateral continuity and horizontal permeability than the upper member. The high-quality reservoirs are represented in a single sandbody in the lower member that is mainly developed in the middle part. After the crude oil was discharged from the source rock enters the sandbody, and long-distance lateral migration was restricted. Thus, crude oil in the lower member is enriched and accumulated in situ. • The characteristics of the source rocks and reservoir of the upper and lower members of the Lucaogou Formation are described. • The oil-source correlation in the upper and lower reservoirs of the Lucaogou Formation have been discussed. • The oil accumulation model of the upper and lower member of the Lucaogou Formation is established. [ABSTRACT FROM AUTHOR]

Shale oil generated by the lower member of the Lucaogou Formation, which was deposited under saline lacustrine conditions within the Jimusaer Sag of the Junggar Basin (NW China), is generally characterized by high density and viscosity. However, a strong spatial heterogeneity of physical properties is observed as well. In this paper, these spatial variations and their controlling mechanisms are evaluated from the perspective of the primary depositional environment, source rock thermal evolution and fractionation effects of primary migration. Based on a detailed organic petrological and geochemical characterization of the target interval within the key well JHBE, hydrous pyrolysis experiments conducted on representative source rock samples from well JHBE, as well as established methods of oil-source correlation subjected to oil samples from several regionally distributed producing shale oil wells, a predictive model of density and viscosity changes of crude oil was established. According to the findings of this study, the thermal evolution and sedimentary environment of source rocks are the main factors affecting the quality of crude oil, and the fractionation effect of primary migration has little effect. Crude oil density and viscosity at first increase up to peak oil maturity, followed by a decrease with further increasing thermal evolution of the source rock. Furthermore, if the source rocks experienced similar thermal histories, it was discovered that relatively low density and corresponding viscosity values are characteristic for crudes from source rocks which were formed in a relatively high salinity environment. In contrast, hydrocarbon generation of source rocks formed under relatively low salinity environments is slightly retarded in direct comparison, and the density and viscosity of the generated crude oil are both relatively high. This highlights that a detailed organic petrographical and geochemical evaluation of the target formation is crucial for the assessment of shale oil potential and production sweet spots in alginite-dominated lacustrine sedimentary environments. • Oil-source correlation of the lower member in the Lucaogou Formation are conducted. • Crude oil density and viscosity control by thermal evolution are discussed from a new sight. • The higher salinity is, the lower density of crude oil is. [ABSTRACT FROM AUTHOR]

This research reveals the depositional environment can affect the organic matter enrichment. The major elements and trace elements are important indexes to reconstruct the depositional environment of Ordovician subsalt marine formations in the central-east Ordos Basin, combining organic parameters with inorganic parameters. Based on the microfacies, the study area is divided into gypsum-bearing dolomite flat, dolomite flat, gypsum-salt depression and limy dolomite flat. The higher Ti/Al ratios and the characteristics of trace elements show that there were detrital inputs in the sedimentation process. When the amounts of detrital inputs are large enough, they can obviously adsorb the elements and dilute the organic matter. Therefore, gypsum-bearing dolomite flat and dolomite flat have lower organic matter accumulation with higher detrital input. Lower P/Ti and Ba excess indicate the deficiency of paleoproductivity. Sr/Ba is higher than 0.6, indicating marine-continental transitional and marine environment. Even the paleosalinity is higher, previous researches have demonstrated the descending sea levels and strong hydrodynamic conditions are unfavorable for organic matter preservation. Lower paleoclimate index "C" and higher Sr/Cu illustrate arid and hot conditions. The value of V/(V + Ni) suggests that the limy dolomite flat is under the oxidizing conditions, and the three other environments are reductive to a certain extent. The Mo-U covariation shows that the water body is under strongly restricted conditions. These conditions are not conducive to biological growth and the accumulation of organic matter, causing low ancient productivity. The partial correlation analysis shows: the organic matter enrichment is affected by multiple factors; paleoproductivity, paleosalinity and paleoclimate have greater influence on the results of organic matter enrichment, and detrital input and oxidation conditions can decrease the paleoproductivity, indicating multiple factors are interrelated and interact with each other. • Major and trace elements are used to reconstructs the depositional environment of four types microfacies. • Paleoproductivity, paleosalinity and paleoclimate have greater influence on the organic matter enrichment. • Depositional environment has direction relationship with low paleoproductivity, causing low organic matter enrichment. [ABSTRACT FROM AUTHOR]

The origin of crude oils and their varied geochemical features along the western and northern slope of the Mahu depression in the Junggar Basin has been controversial. Based on the molecular and isotopic geochemistry of hydrocarbons from 46 drill-stem test crude oil samples and 36 core samples, three oil groups (I, II, III) and five subgroups (I 1 , I 2 , II, III 1 and III 2 ) have been recognized and oil-source correlations have been established. The subgroup I 1 oils originated mainly from lower Permian Fengcheng (P 1 f) carbonate source rocks, subgroup I 2 from P 1 f mudstone source rock and group II oils from Middle Permian Wuerhe (P 2 w) mudstone source rock whose potential was underestimated in the past. Group III consists of mixed oils, i.e., subgroup III 1 received contributions from P 1 f carbonates and P 2 w mudstones and subgroup III 2 is a mixture of oils from P 1 f mudstones and P 2 w-generated oils. In order to determine the main source rocks, the laboratory oil mixing experiments were carried out. Tricyclic terpane biomarker parameters (TTs) were used to quantify the source contributions. Whole oil carbon isotope ratios were also used to verify the proportions of different oils in each mixture. The results show that subgroup III 1 oils have diverse mixing ratios in different reservoir, subgroup III 2 oils are mainly from P 1 f mudstones and P 2 w source rock contributes little. Finally, the accumulation process of oil fields along the northern slope of the Mahu depression was analyzed and the contributions from different sources were revealed. This study provides an effective quantitative method to identify contributions from different lacustrine source rocks to mixed oils in the Mahu depression, which could be helpful in predicting location and composition of undiscovered oils. [ABSTRACT FROM AUTHOR]

The origin and potential source of the presalt natural gas in the Lower Paleozoic Ordovician carbonates within the Ordos Basin, China, is heavily debated, and the causes of carbon isotope reversal are currently unclear. This study analyzes the source and origin of the presalt natural gas and determines the reasons for carbon isotope reversal. The results show that the nonhydrocarbons contain CO 2 , H 2 S, and N 2 and some gas samples have high H 2 S contents of 9.02%–23.58%. The dryness coefficient (C 1 /C 1+) of 91.06%–99.99% (ave. 98.34%) suggests that the presalt gas is mainly a dry gas with some wet gas and that it originates from a high-to over-mature source. However, the results show that the presalt natural gas is primarily a wet-gas-cracking gas, rather than a kerogen-cracking gas, with a certain amount of coal-type gas mixing and it mainly originated from oil-prone marine carbonate source rocks rather than the Permian–Carboniferous coal measures. The gas has different types of carbon isotope reversal patterns, and the δ13C 2 values become negative at Ro equ > 1.5%. The mixing between the oil-cracking and wet-gas-cracking gas at Ro equ > 1.5% results in carbon isotope reversal (δ13C 1 > δ13C 2), rather than Rayleigh and migration fractionation. The occurrence of thermochemical sulfate reduction (TSR) is supported by the high abundance of H 2 S in the presalt gas, reservoir bitumen in dissolved pores, secondary calcite with negative δ13C carbonate of −21.1‰ to −9.7‰, and diagenetic cubic pyrite. It is evident that the heavy δ13C 2 values (greater than −28‰) and the carbon isotope reversal of δ13C 2 > δ13C 3 of the presalt natural gas at Ro equ < 1.5% are related to TSR. This study also establishes a new model of the carbon isotope reversal of the natural gas, which is primarily controlled by its thermal maturity and TSR. Six carbon isotope patterns can be well explained and are supported by real gas samples from the presalt strata, and two types of carbon isotope reversal are predicted. • The presalt gas is mainly oil-derived gas and dry gas with some wet gas. • Heavy δ13C 2 values (>−28‰) and carbon isotope reversal of δ13C 2 > δ13C 3 of are caused by TSR at low maturity. • The δ13C 2 values become greatly more negative at Ro equ > 1.5%. • A new model of carbon isotope reversal is established firstly, controlled by maturity and TSR. [ABSTRACT FROM AUTHOR]

Approximate 500 m deltaic-lacustrine successions were formed within 2 Ma in the Liangjialou area of the Dongying Depression in the Bohai Bay Basin (eastern China). However, few studies on sequence stratigraphy were previously conducted in the east of Liangjialou. In the present study, we integrate high-resolution three-dimensional (3D) seismic data with well-logging data to study the sequence stratigraphy and the depositional system.Our study shows that: (1) Four systems tracts have been identified in the study interval, they are HST, FSST, LST and TST. The HST has an ascending shelf-edge trajectory and aggradation to progradation stacking pattern. FSST has a descending shelf-edge trajectory and progradation to degradation stacking pattern. LST has a low-angle ascending shelf-edge trajectory and progradation to aggradation stacking pattern. TST has a backstepping shelf-edge trajectory and retrogradation stacking pattern. (2) Five high-resolution sequences (equal to 4th-order sequence), HRS1∼HRS5, were further subdivided within the 3rd-order LST. In addition, the depositional systems of HRS1∼HRS5 are significantly variable in 3D space. The delta and deep-water deposits in the north are larger than those in the south. (3) The formation of the sequence is controlled by both tectonics and dry-wet climatic cycles. The tectonic subsidence and high sediment supply in overall wet climate play a major role in the formation of the 3rd-order sequence. The higher frequency dry-wet climatic cycles dominate the formation of internal systems tracts. We further divide the climate of study interval into three stages that are excellent correlated to the specific systems tracts: Stage 1 (evaporation < precipitation) corresponds to HST; Stage 2 (evaporation > precipitation) corresponds to FSST; Stage 3 (evaporation < precipitation) corresponds to LST. (4) The basin morphology and source location mainly control the lateral variability of the depositional system of LST. Low paleotopography, narrow shelf width and steep slope dip in the north cause a large accommodation, and promote the development of the deltaic and deep-water deposits. In contrast, a high relief, wide shelf width and gentle slope cause only minor accommodation in the south, and limit the development of the deltaic and deep-water deposits. • A fine sequence stratigraphic framework was established. • Lateral variability of depositional system of LST was documented. • Reginal structure and dry-wet climatic cycles influence the lacustrine sequence in different time scale. • A new three-dimensional distribution model of LST depositional system was proposed. [ABSTRACT FROM AUTHOR]