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The third member of the Upper Triassic Xujiahe Formation (T 3 x3) is a typical source-reservoir-cap unit for natural gas exploration in the Sichuan Basin. However, most previous studies mainly focused on the T 3 x3 as a source rock, ignoring its role as a reservoir. As a result, the evaluation of hydrocarbon resource potential was not accurate. This study established a hydrocarbon generation and expulsion model through analyzing the geological and geochemical characteristics of the T 3 x3 source rocks, and calculated the resource potential of conventional gas, tight gas and shale gas systematically with combining the lower boundary of buoyancy-dominated accumulation (LBBA). The results indicated that the thickness of the source rocks dominated by mudstone was distributed widely, with an average value of more than 45 m. The sedimentary environment was salty lacustrine deposits. They have a high content of total organic carbon (TOC) with an average value of 4.80 wt%, the kerogen is mainly type III with minor type II, and the thermal evolution has entered the high to over mature stage. The hydrocarbon generation threshold was determined to be 0.5%Ro, while the hydrocarbon expulsion threshold and the LBBA were determined to be 0.83%Ro and 1.12%Ro, respectively. The efficiency of hydrocarbon expulsion was relatively high, with an average of about 56%. Also, the maximum hydrocarbon generation and expulsion intensity reached to 110 × 108 m3/km2 and 53 × 108 m3/km2. The amounts of hydrocarbon generation, expulsion and residual associated with the T 3 x3 source rocks were 125.68 × 1012m3, 70.38 × 1012m3, and 55.30 × 1012m3, respectively. Under the criterion condition of the LBBA, the conventional gas resource was 7.21 × 1010m3, the tight gas resource was 294.34 × 1010m3, and the shale gas resource was 2488.50 × 1010m3. It indicated good prospects for exploration. • The geological and geochemical characteristics of source rocks were described. • The hydrocarbon generation and expulsion characteristics were studied by hydrocarbon generation potential method. • The resource potential of conventional and unconventional gas was calculated systemically. [ABSTRACT FROM AUTHOR]

Superimposed basins are commonly characterized by a complex distribution of oil and gas accumulations. Because they have generally experienced multistage hydrocarbon accumulation and tectonic movement, it is challenging to predict favorable exploration zones in these basins. The exploration of the deep strata of the Sichuan Basin (i.e., a typical superimposed basin), West China, has been unsatisfactory for petroleum prospectors. Therefore, we chose the Cambrian Longwangmiao Formation in the Sichuan Basin as an example to demonstrate the method, i.e., combination of petroleum system elements to quantitatively predict the petroleum favorable exploration zones. Based on the detailed analysis of the hydrocarbon accumulation process, the source rock (S), migration (M), reservoir depositional facies (D), and regional cap rock (C) are the most important elements controlling the formation and distribution of oil and gas accumulations in the studied basin. By studying the functional relationships among these four elements and the distribution of the petroleum accumulations, we determined the accumulation probability related to each element and quantitatively predicted the probability of a favorable hydrocarbon accumulation zone. We built a quantitative model of the reservoir preservation probability based on the statistical relationship between the intensity of the tectonic movement and subsequent destruction of existing oil and gas accumulations. Favorable exploration zones can be determined by overlaying favorable accumulation zones with disturbances associated with the tectonic evolution. The results suggest that the most favorable exploration zones of the Longwangmiao Formation in the Sichuan Basin are distributed in the regions west of Weiyuan and east of Gaoshiti–Moxi, Pengxi–Yilong, and Dazhou–Kaijiang. The production data for existing fields in the Sichuan Basin show that 87% of the successful wells are in the predicted favorable exploration zones and that the success rate with respect to the prediction of failure wells is 67%. This approach highlights the most prospective exploration areas in superimposed basins, which, in general, is challenging and complex for traditional basin modeling tools. • Favorable hydrocarbon accumulation zones are quantitatively predicted. • Impact of tectonic movement on the petroleum accumulations is studied. • Petroleum favorable exploration zones in complex superimposed basin are predicted. • The coincidence rate of the application of the model is 87%. [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]

Abstract The Ordos Basin is a significant gas-producing region in China. Previous studies have shown that a large amount of the gas discovered in the upper Paleozoic strata originated from Carboniferous–lower Permian coal and its interbedded coal measure mudstone. To compare the hydrocarbon generation characteristics and process, two coal and coal measure mudstone samples from the Shanxi Formation in the Shenfu area were used in confined gold tube pyrolysis experiments. The analytical results revealed that both samples had poor oil generation potential, with maximum C 6+ yields of 171.65–175.67 mg/g TOC for the coal and 50.12–51.86 mg/g TOC for the coal measure mudstone at the heating rate of 2 °C/h and 20 °C/h. However, their gas generation potentials are good, and the coal exhibited higher values than the mudstone, with final laboratory C 1 –C 5 yields of 154.71–173.32 mg/g TOC for the coal and 82.52–98.96 mg/g TOC for the coal measure mudstone. Based on a comprehensive analysis of the indicators lnC 2 /C 3 , lnC 1 /C 2 and δ 13C 1 – δ 13C 2 , the hydrocarbon generation process can be divided into three stages. The results of extrapolation to geological conditions revealed that the main gas generation stages of both source rocks in the Shanxi Formation began in the Early Cretaceous. Because of the regional tectonic uplift and the decrease in the geothermal gradient in the Late Cretaceous, the C 1 –C 5 volume yields of the coal and the coal measure mudstone reached plateaus of 78.4 ml/g TOC and 32.7 ml/g TOC, respectively, in the Late Cretaceous, and the current transformation ratios of C 1 –C 5 for the coal and the coal measure mudstone are only 32.1% and 22.8%, respectively. Highlights • Geochemical characteristics of the lower Permian Shanxi Formation coal and coal measure mudstone were analysed. • Confined pyrolysis experiments were performed on the two selected sample types. • Hydrocarbon generation process were determined based on the indicators of yields and carbon isotopes. • Kinetic parameters were used to simulate the hydrocarbon generation history of the coal and coal measure mudstone. [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]

[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]

Large shale oil resources were recently been found in lacustrine organic-rich shale with strong heterogeneity, however, few studies have been conducted to examine their oil contents, resulting in considerable risks in lacustrine shale oil exploration. The Middle Permian Lucaogou Formation (P 2 l) shale in Jimusaer Sag is a typical lacustrine deposit with strong heterogeneity, and its shale oil resource shows great potential. Integrated geochemical characterization of 265 core samples were conducted and results show that the P 2 l shale developed in an anoxic lacustrine with stratified salty water and the organic matter in the upper sub-member shale of the P 2 l is more oil-prone than that in the lower sub-member shale of the P 2 l. The hydrocarbon generation potential of the P 2 l shale decreases with the kerogen types changing from Type I to Type III, however, the residual hydrocarbon contents of the P 2 l shale increases from Type I to II 1 kerogen, and then decreases from Type II 1 to III kerogen, this is mainly due to differentiated hydrocarbon expulsion efficiencies among different kerogen types. Based on S 1 and TOC values and the S 1 /TOC ratios, considering the oil enrichment degree, this study classified the shale oil resources in the P 2 l shale into four categories: enriched, moderately enriched, less efficient, and invalid resources. The enriched and moderately enriched resources are mainly shales with Type II 1 kerogen, followed by Type II 2 kerogen, and the middle interval of the Lower P 2 l shale is the most favourable target for further shale oil exploration. The improved evaluation criteria are applicable for evaluating shale oil plays with strong heterogeneity qualitatively and quantitatively in terrestrial lacustrine basins in other parts of the world. [ABSTRACT FROM AUTHOR]

Evaluation of carbonate heterogeneity, closely related to pore geometry and connectivity, is important in oil and gas field production and reservoir prediction. To profoundly understand the heterogeneity of Lower Carboniferous carbonate reservoirs in the Marsel area, including Visean (C 1 v) and Serpukhovian (C 1 sr), the pore structure and fractal characteristics are investigated using routine petrophysical measurements, X-ray diffraction (XRD), cast thin section analysis, scanning electron microscopy (SEM), and mercury injection capillary pressure (MICP) tests. The origin of potentially prolific reservoir, the relationships between fractal dimension and reservoir physical properties, mineral composition and pore structure are also discussed. XRD results reveal that the mineral compositions are highly heterogeneous in C 1 v and C 1 sr. Routine petrophysical experiments indicate that C 1 v and C 1 sr are generally tight. However, some high porosity-permeability zones exist in C 1 sr, which is described as a potentially prolific reservoir. The cast thin section and SEM analyses identify three main pore types in the potentially prolific reservoir: interparticle dissolution pores, intercrystalline dissolution pores, and moldic pores. The MICP data reflect that the pore-throat radii in the prolific reservoir range from 0.29 to 4.6 μm, whereas those in tight section are typically <0.14 μm. The fractal dimensions are computed based on MICP data, and the fractal characteristics of the potentially prolific reservoir in C 1 sr are divided into two segments. In the tight section, relatively larger fractal dimensions are observed, indicating highly heterogeneous pore structure. The potentially prolific reservoir in C 1 sr is formed mainly because of penecontemporaneous dolomitization and leaching due to meteoric freshwater ingress. Different mineral compositions have differing effects on the fractal characteristics of the pore structure. Relatively good correlations of fractal dimension with porosity, permeability, sorting coefficient, and skewness indicate that fractal dimensions are helpful in reservoir quality evaluation and quantitative characterization of pore networks. [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]

The Tarim Basin in China is a complicated superimposed basin with four periods of hydrocarbon accumulations and three periods of modifications due to tectonic movements, forming complicated hydrocarbon reservoirs, many of which have gone through reservoir migration, reservoir scale reformation, reservoir damage and phase alterations a result of the tectonic events. Due to the complexity, the hydrocarbon exploration in this region has low success drilling rate. It is of great importance to study the destruction to the early hydrocarbon accumulations by the tectonic movements and quantitatively evaluate the remaining resource for understanding the current hydrocarbon distribution and guiding the exploration. This study analyzed six periods of large tectonic events in the Tarim Basin, and found the destroyed hydrocarbon volume was mainly controlled by four geological factors, including the ratio of the destroyed to the original hydrocarbon amount, tectonic event number and sequence, and the cap seal capacity. Larger ratio of destroyed hydrocarbon, less tectonic event number, later sequence and stronger cap seal capacity lead to more hydrocarbons preserved through the tectonic events. Based on the geological analysis, we established quantitative relationships among the destroyed hydrocarbon volume by the tectonic events (Q l ), the volume of primary hydrocarbon accumulation (Q 0 ), the ratio of destroyed hydrocarbon (K l ), the tectonic event number (n) and sequence (i), and cap seal capacity (fc). Using these relationships and the calibrated geological parameters, we delineated the hydrocarbon accumulation and destruction history and quantified the hydrocarbon loss due to the tectonic events for both the Tazhong area and the whole Tarim Basin. In the Tazhong area, four major accumulation events occurred at 510 Ma, 298 Ma, 227 Ma and 38 Ma with each accumulation underwent 68%, 59%, 28% and 0% of hydrocarbon loss due to later tectonic events. In total, over 60% of the original hydrocarbon reserves have been destroyed in the Tarim Basin, with an estimate of ca. 1.9 billion tons remaining hydrocarbons in the Tazhong area. At present, more than 95% oil and gas reservoirs and over 93% high quality exploration wells are located in the areas with high remaining resource potential predicted in this study, whereas 70% non-commercial production wells are located outside. Overall, this work shows that a careful evaluation of the damage to reservoirs from tectonic events can considerably enhance the success rate of hydrocarbon exploration. [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]

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]

In total, 2.37 million tons of marine crude oil originating from mixed source rocks has been discovered in the Tarim basin. Geological and geochemical analyses have confirmed that these mixed hydrocarbons are mainly from two sets of source rocks, including the Cambrian – Lower Ordovician and Middle-Upper Ordovician hydrocarbon source rocks. In this study, we determined the set of source rocks primarily responsible for the mixed hydrocarbons and the next location to be explored. Differences in n-alkane carbon isotopes in end-member oils from Cambrian–Lower Ordovician and Middle-Upper Ordovician source rocks were examined. A material balance model and simulation methods were used to evaluate the relative amounts contributed by each source. The results from known reserves in the Tazhong area show that the mixing ratio or contribution is up to 65% from Cambrian–Lower Ordovician source rocks and is generally higher than that from Middle-Upper Ordovician source rocks. The discovery of deep hydrocarbons has caused the total oil contribution from the Cambrian–Lower Ordovician to increase. The mixing ratio of Cambrian–Lower Ordovician oil varies depending on the well, formation, and block. It increases from west to east horizontally and from top to bottom vertically. Hydrocarbons from Cambrian–Lower Ordovician source rocks migrate upward along faults, and the mixing ratio decreases as the distance from the oil source fault increases. Favorable areas for Cambrian–Lower Ordovician hydrocarbon exploration are deep layers and areas near the fault zone that are connected to deep layers. The material balance model for carbon isotopes and evaluation methods for relative contributions considered differences in relative concentration and carbon isotope structure of n-alkanes. Herein, new methods for the identification and evaluation of hydrocarbons in the petroleum system of this superimposed basin are presented. [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]