•The organic matter-rich Lucaogou formation has fair to good hydrocarbon-generative potential.•Hydrocarbon expulsion began at 0.73% Ro and the peak expulsion occurred at 0.9% Ro.•The total expelled hydrocarbon quantities are 18.7×108 t.•The hydrocarbon expulsion intensity controls the distribution of tight oil.The petroliferous Permian system of the Junggar Basin in northwest China is predominantly a conventional oil exploration region. To assist in the unconventional tight oil reservoir exploration, the hydrocarbon expulsion potential of source rocks and its influence on the tight oil distribution of the Middle Permian Lucaogou Formation (P2l) in the Jimsar Sag are discussed. The researches are based on geological and geochemical characteristics such as the distribution, abundance, type, thermal maturity of source rocks, and “sweet spots”. Meanwhile, hydrocarbon expulsion intensity and quantity were evaluated with hydrocarbon generation potential method. The Middle Permian Lucaogou source rocks have wide distribution and high thickness (mostly thicker than 100 m). The source rocks exhibit low to high TOC (mainly ranges from 1.0 wt% to 5.0 wt%) and primarily contain type-II kerogen, resulting in significant hydrocarbon expulsion potential under moderate mature thermal evolution (Ro mainly ranges from 0.55% to 1.05%). According to the hydrocarbon expulsion modelling, the source rocks reached the hydrocarbon expulsion threshold at 0.73% Ro and the hydrocarbon expulsion rate became greatest at 0.9% Ro. The comprehensive hydrocarbon expulsion efficiency was approximately 48%. About 18.7×108 t of hydrocarbons were expulsed from the Lucaogou source rocks in the Jimsar Sag. The hydrocarbon expulsion intensities are relatively large and rang from 150×104 t/km2 to 400×104 t/km2 in the center and west area of the Sag, where is the superimposed area of source rock thicker than 200 m, TOC greater than 3.5% and Ro higher than 0.85% in the sag. There are 17 exploratory wells obtaining commercial oil flow in the Sag. 16 of the 17 exploratory wells are located in the area with hydrocarbon expulsion intensity greater than 50×104 t/km2. By contrast, other exploratory wells outside the hydrocarbon expulsion coverage area have slight show of oil, even dry. In addition, there is positive correlation between the hydrocarbon expulsion intensity and the daily output of well testing. It is concluded that the tight oil exploration should focus on the area with hydrocarbon expulsion intensity greater than 100×104 t/km2, which is a favorable area for commercial hydrocarbon accumulation and exploration.

•New geochemical data of the Paleozoic natural gas from southern Jingbian gas field were analyzed for the first time.•The main gas source in the Ordovician weathering crust was discussed by comparing with the Upper Paleozoic.•Different carbon isotopic reversal phenomena of Upper Paleozoic and Lower Paleozoic natural gas were analyzed separately.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 (C1/C1-4) 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.

•Combining FE-ESEM observation and N2 sorption experiment to characterize shale pores.•Two fractal dimensions of shales are calculated and discussed.•Pore development and genesis of high-maturity shales are investigated.•Controlling factors of shale pore structure are investigated.•Relationships between pore structure parameters and two fractal dimensions are studied.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 N2 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 D1 and D2 respectively. D1 ranged from 2.60 to 2.71 and D2 ranged from 2.71 to 2.82. D1 was typically smaller than D2, 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 D1 and D2. Fractal dimensions are useful for the characterization of the pore structures complexity of the Longmaxi Formation shales because D1 and D2 correlate well with pore structure parameters as they both increase with the increase of surface area and the decrease of average pore diameter.

•The petroleum in the HZ25-7 oil field mainly originates from the Eocene Wenchang Formation.•Oil injection was from 16 Ma to the present in HZ 25-7 oil field, with peak filling occurred after 12 Ma.•The western and southern margins of the Huizhou Depression are expected to be a favorable exploration target.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 (E2w) 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, E2w and Enping (E2e) formations developed in the study area. The semi-deep-to-deep lacustrine E2w source rocks are characterized by relatively low C29 steranes, low C19/C23 tricyclic terpane (<0.6), low C24 tetracyclic terpane/C30 hopane (<0.1), low trans-trans-trans-bicadinane (T)/C30 hopane (most <2.0), and high C30 4-methyl sterane/ΣC29 sterane (>0.2) ratios. In contrast, the shallow lacustrine and deltaic swamp-plain E2e source rocks are characterized by relatively high C29 steranes, high C19/C23 tricyclic terpane (>0.6), high C24 tetracyclic terpane/C30 hopane (>0.1), variable yet overall high T/C30 hopane, and low C30 4-methyl sterane/ΣC29 sterane (<0.2) ratios. The relatively low C19/C23 tricyclic terpane ratios (mean value: 0.39), low C24 tetracyclic terpane/C30 hopane ratios (mean value: 0.07), high C30 4-methyl sterane/ΣC29 sterane ratios (mean value: 1.14), and relatively high C27 regular sterane content of petroleum in the HZ25-7 oil field indicate that the petroleum most likely originated from the E2w 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 E2w Formation are favorable conduits for the lateral migration of petroleum. This petroleum accumulation pattern implies that the E2w 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.

•Cambrian () oil from ZS1, ZS1C wells was sourced from O2+3 and rocks respectively.•The proportion for the deep oil from the and O2+3 rocks is about 57:43.•The compound specific sulfur isotope could indicate TSR extent of the deep oil.•Lower Cambrian oil was suggested to be responsible for the unusually high DBTs.•Maturity impact on correlative index cannot cause reversed oil–source result.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 δ34S of DBTs and high δ13C 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 δ13C of n-alkanes and relatively high δ34S 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 δ34S 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 δ34S 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.

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.Highlights► FT-ICR MS was proved to be powerful in identifying HMW sulfur compounds. ► The relationship between TSR and aromatic sulfur compounds was discussed. ► The high DBT concentrations in Tarim Basin is mainly a result of oil mixing. ► TSR occurred in a deeper interval rather than the present petroliferous horizon.

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.

Taking more than 1000 clastic hydrocarbon reservoirs of Bohai Bay Basin, Tarim Basin and Junggar Basin, China as examples, the paper has studied the main controlling factors of hydrocarbon reservoirs and their critical conditions to reveal the hydrocarbon distribution and to optimize the search for favorable targets. The results indicated that the various sedimentary facies and lithologic characters control the critical conditions of hydrocarbon accumulations, which shows that hydrocarbon is distributed mainly in sedimentary facies formed under conditions of a long-lived and relatively strong hydrodynamic environment; 95% of the hydrocarbon reservoirs and reserves in the three basins is distributed in siltstones, fine sandstones, lithified gravels and pebble-bearing sandstones; moreover, the probability of discovering conventional hydrocarbon reservoirs decreases with the grain size of the clastic rock. The main reason is that the low relative porosity and permeability of fine-grained reservoirs lead to small differences in capillary force compared with surrounding rocks small and insufficiency of dynamic force for hydrocarbon accumulation; the critical condition for hydrocarbon entering reservoir is that the interfacial potential in the surrounding rock (Φn) must be more than twice of that in the reservoir (Φs); the probability of hydrocarbon reservoirs distribution decreases in cases where the hydrodynamic force is too high or too low and when the rocks have too coarse or too fine grains.

•The mechanism of hydrocarbon accumulation in the carbonate rocks of the Tazhong area in the Tarim basin is revealed.•The study provides quantitative analysis of the controlling factors of hydrocarbon accumulation in this carbonate reservoir.•The study provides a predictive method for favorable exploration in carbonate rocks in the Tazhong area of the Tarim basin.The Tazhong area, at the center of the Tarim basin, western China, contains abundant hydrocarbon resources, principally in Ordovician carbonate reservoirs. The geological conditions for hydrocarbon accumulation in the area are quite complicated and are characterized by multiple stages of hydrocarbon generation, accumulation, adjustment and alteration. Despite decades of exploration and production in the region, the mechanisms of hydrocarbon accumulation and their controlling factors are still not well established. The geological setting and the distribution characteristics of the reservoir, have been used to investigate the mechanisms of accumulation, to quantitatively describe the main controlling factors, and to predict potential favorable hydrocarbon accumulation zones in Ordovician carbonate rocks of Tazhong. Our results show that the hydrocarbons in the Ordovician reservoirs came from mixed sources including middle-lower Cambrian and middle-upper Ordovician source rocks within the Majiaer Sag. Four stages of accumulation are recognized and hydrocarbons migrated into the Tazhong area along six intersections of NE and NW fault sets, principally from the northeast to the southwest but then, locally, from the northwest to the southeast. The Ordovician carbonate reservoirs are typically lithologically defined and the dynamic force of hydrocarbon accumulation is primarily reflects differential capillary forces. The accumulation and distribution of hydrocarbons was controlled by the petrophysical properties of the reservoir and by hydrocarbon supply/charge energy. The petrophysical properties of the reservoir controlled the hydrocarbon accumulation threshold with the maximum differential capillary pressure force, on average, approximately 13 MPa. The supply or charge energy of the hydrocarbons controls the accumulation distribution range. The daily production of individual wells decreases with increasing distance from the fault intersections and the maximum hydrocarbon migration distance is about 35 km. Reservoir properties and the hydrocarbon supply/charge Energy coupling Index (REI) appear to control hydrocarbon accumulation and distribution. Accumulation does not occur when the value of REI is ≤ 0.6, but is favored when values are higher.

•Abundant geological and geochemical data of Lower Carboniferous source rocks were analyzed for the first time.•Organic matter abundance, types and thermal maturity of source rocks were evaluated based on multiple parameters.•Organic matter source, depositional environment and thermal evolution history in Marsel area were analyzed.•The distribution of high-quality source rocks was ascertain and provided ideas for tight gas exploration.There are two sets of carbonate source rocks in the Lower Carboniferous layers in Marsel: the Visean (C1v) and Serpukhovian (C1sr). 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 C1v and C1sr 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 C1v and C1sr were 0.79% and 0.5%, respectively, which were higher than the threshold of effective carbonate source rocks. Dominated by type-III kerogen, the C1v and C1sr 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 C1v and C1sr, 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 C1v and C1sr 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.

The Tazhong area, located in the central part of the Tarim Basin, is the major commercial oil and gas province in the Tarim Basin. Hydrocarbons have been discovered in the Ordovician, Silurian and Carboniferous reservoirs. Most of the hydrocarbon reservoirs in the Tazhong area have experienced post-charge and accumulation readjustment or loss associated with multiple post-charge tectonic movements. The relationship between the destroyed hydrocarbon proportion (DHP) caused by tectonic events and tectonic movement intensity (TMI) in 15 well blocks has been established for the entire Tazhong area using TMI analysis. TMI can be quantitatively characterized by the denudation thickness and effective caprock thickness ratio, whereas the DHP can be quantitatively determined by the variations of the palaeo and current oil-water contacts. There appears to be a good relationship between DHP and TMI with a correlation coefficient of 0.9. Most of the original Ordovician hydrocarbon accumulations formed in the late Ordovician had been lost, with an average DHP of up to 70%. The tectonic movement is much weaker in the late Silurian and late Permian period, with the DHPs for the Silurian reservoirs and Carboniferous reservoirs in the eastern Tazhong area averaging 50%. All the DHPs show a gradual increase from west to the east (Figs.17–19). The preservation condition of the reservoirs is generally better in west than in the east.Highlights► Analyzed the relationship between the past tectonic events and the hydrocarbon loss amount. ► Built the prediction method of destroyed hydrocarbon proportion by tectonic movements. ► Predicted the DHP in the Tazhong area, Tarim basin, west China.

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.