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The horizontal distribution and periodic accumulation of hydrocarbon in reservoirs are well understood. However, our understanding on the vertical distribution of hydrocarbon accumulation in reservoirs is not clear and remains mysterious to some extent. We proposed a concept of hydrocarbon accumulation depth limit (HADL) to characterize the hydrocarbon’s vertical distribution in petroliferous basins, which is determined by statistical analyses of the variation trends of reservoir layers’ essential properties, including hydrocarbon saturations (So), movable hydrocarbon ratios (Mo) and dry layer ratio (Ko), when the depth is increased. A total of 80,762 drilling results from 12,237 exploration wells in six representative petroliferous basins in China were collected and analyzed. The reservoir layers’ essential properties So, Mo and Ko and their correlations with porosity, permeability, pore throat radius and thermal evolution degree were investigated. The critical values of So, Mo and Ko that define HADL were quantified to be So=0, Mo=0 and Ko=100. Our study indicates that the HADL in petroliferous basins varies from less than 3,000 m to more than 13,000 m deep, depending on the hydrocarbon composition, reservoir lithology, reservoir age, geothermal gradient, tectonic movement, etc. Two factors play an essential role in the formation and variation of HADL: 1) the depletion of hydrocarbon generation potential of source rocks which cuts off hydrocarbon contribution for reservoirs formation and 2) the termination of differential compaction which eliminates capillary pressure difference between the outer surrounding rocks and inner reservoir layers, ending the dominant driven force for hydrocarbon migration and accumulation in deep and tight reservoir layers. All proven oil reserves of 33.95 billion tons equivalent in China, as well as world’s discovered 52,926 oil and gas reservoirs and their unproved potential resources, are distributed above the HADL we defined.

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology. It has not only changed the balance of supply and demand in the global energy market, but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs. However, misconceptions widely exist in studies of different types of petroleum accumulations because of the lack of a unified genetic classification. Unconventional reservoir has been used in the literature as a general name for various oil/gas reservoirs that are formed under complex dynamic mechanisms as long as buoyancy is not the major controlling factor. On the other hand, different terms have been given to the reservoirs even with the same formation mechanism. This paper selected six representative basins in China as the major subject of the study, analyzed the drilling results of 80,762 reservoir layers from 12,237 exploration wells in these basins. By investigating the progress of unconventional oil/gas exploration in North America in the past 30 years and addressing the distribution characteristics of discovered 52,926 oil/gas reservoirs in 1,186 basins around the world, this study revealed the correlations and differences of formation and distribution characteristics between conventional and unconventional oil and gas reservoirs. It was found that there are five correlations between conventional and unconventional reservoirs, including sharing the same oil and gas source, occurring in strata with the same geological age, coexisting in the same sedimentary basins, being confined in the same petroleum systems, and being enriched in the same reservoir layers. It was also found that there are five differences between conventional and unconventional reservoirs, including differences in hydrocarbon compositions, spatial relations to source rocks, reservoir lithology and quality, distribution in geological settings, and reservoir formation mechanism. Then, the unified genetic classification scheme is put forward to clarify their differences and correlations. All kinds of conventional and unconventional oil and gas resource are classified into 3 categories and 6 subcategories according to their dynamic mechanisms of formation, reclassified into 15 types based on main controlling factors, and further divided into 49 styles considering their underground occurrences. The application results show that all different oil/gas reservoirs can find their corresponding positions in the classification scheme, and all the oil/gas reservoirs with the same genetic mechanism, major controlling factor and occurrence can find their particular position in this classification scheme.

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology; that has not only changed the balance of supply and demand in the global energy market, but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs. However, what is the difference of conventional and unconventional resources and why they always related to each other in petroliferous basins is not clear. As the differences and correlations between unconventional and conventional resources are complex challenging issues and very critical for resources assessment and hydrocarbon exploration, this paper focused on studying the relationship of formations and distributions among different oil/gas reservoirs. Drilling results of 12,237 exploratory wells in 6 representative petroliferous basins of China and distribution characteristics for 52,926 oil/gas accumulations over the world were applied to clarify the formation conditions and genetic relations of different oil/gas reservoirs in a petroliferous basin, and then to establish a unified model to address the differences and correlations of conventional and unconventional reservoirs. In this model, conventional reservoirs formed in free hydrocarbon dynamic field with high porosity and permeability located above the boundary of hydrocarbon buoyancy-driven accumulation depth limit. Unconventional tight reservoirs formed in confined hydrocarbon dynamic field with low porosity and permeability located between hydrocarbon buoyancy-driven accumulation depth limit and hydrocarbon accumulation depth limit. Shale oil/gas reservoirs formed in the bound hydrocarbon dynamic field with low porosity and ultra-low permeability within the source rock layers. More than 75% of proved reserves around the world are discovered in the free hydrocarbon dynamic field, which is estimated to contain only 10% of originally generated hydrocarbons. Most of undiscovered resources distributed in the confined hydrocarbon dynamic field and the bound hydrocarbon dynamic field, which contains 90% of original generated hydrocarbons, implying a reasonable and promising area for future hydrocarbon explorations. The buried depths of hydrocarbon dynamic fields become shallow with the increase of heat flow, and the remaining oil/gas resources mainly exist in the deep area of “cold basin” with low geothermal gradient. Lithology changing in the hydrocarbon dynamic field causes local anomalies in the oil/gas dynamic mechanism, leading to the local formation of unconventional hydrocarbon reservoirs in the free hydrocarbon dynamic field or the occurrence of oil/gas enrichment sweet points with high porosity and permeability in the confined hydrocarbon dynamic field. The tectonic movements destroy the medium conditions and oil/gas components, which leads to the transformation of conventional oil/gas reservoirs formed in free hydrocarbon dynamic field to unconventional ones or unconventional ones formed in confined and bound hydrocarbon dynamic fields to conventional ones.

Hydrocarbon expulsion occurs only when pore fluid pressure due to hydrocarbon generation in source rock exceeds the force against migration in the adjacent carrier beds. Taking the Middle–Upper Ordovician carbonate source rock of Tarim Basin in China as an example, this paper proposes a method that identifies effective carbonate source rock based on the principles of mass balance. Data from the Well YW2 indicate that the Middle Ordovician Yijianfang Formation contains effective carbonate source rocks with low present-day TOC. Geological and geochemical analysis suggests that the hydrocarbons in the carbonate interval are likely self-generated and retained. Regular steranes from GC–MS analysis of oil extracts in this interval display similar features to those of the crude oil samples in Tabei area, indicating that the crude oil probably was migrated from the effective source rocks. By applying to other wells in the basin, the identified effective carbonate source rocks and non-source rock carbonates can be effectively identified and consistent with the actual exploration results, validating the method. Considering the contribution from the identified effective source rocks with low present-day TOC (TOCpd) is considered, the long-standing puzzle between the proved 3P oil reserves and estimated resources in the basin can be reasonably explained.

The fine-grained rocks in the Paleogene Shahejie Formation in Nanpu Sag, Huanghua Depression, Bohai Bay Basin, are extremely important source rocks. These Paleogene rocks are mainly subdivided into organic-rich black shale and gray mudstone. The average total organic carbon contents of the shale and mudstone are 11.5 wt.% and 8.4 wt.%, respectively. The average hydrocarbon (HC)-generating potentials (which is equal to the sum of free hydrocarbons (S1) and potential hydrocarbons (S2)) of the shale and mudstone are 39.3 mg HC/g rock and 28.5 mg HC/g rock, respectively, with mean vitrinite reflectance values of 0.82% and 0.81%, respectively. The higher abundance of organic matter in the shale than in the mudstone is due mainly to paleoenvironmental differences. The chemical index of alteration values and Na/Al ratios reveal a warm and humid climate during shale deposition and a cold and dry climate during mudstone deposition. The biologically derived Ba and Ba/Al ratios indicate high productivity in both the shale and mudstone, with relatively low productivity in the shale. The shale formed in fresh to brackish water, whereas the mudstone was deposited in fresh water, with the former having a higher salinity. Compared with the shale, the mudstone underwent higher detrital input, exhibiting higher Si/Al and Ti/Al ratios. Shale deposition was more dysoxic than mudstone deposition. The organic matter enrichment of the shale sediments was controlled mainly by reducing conditions followed by moderate-to-high productivity, which was promoted by a warm and humid climate and salinity stratification. The organic matter enrichment of the mudstone was less than that of the shale and was controlled by relatively oxic conditions.

The third member of the Upper Triassic Xujiahe Formation (T3x3) is a typical source-reservoir-cap unit for natural gas exploration in the Sichuan Basin. However, most previous studies mainly focused on the T3x3 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 T3x3 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 T3x3 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.

Sediments with organic matter content (total organic carbon) TOC ≤ 0.5% which can act as effective source rocks are critical and challenging in the field of petroleum geology. A new method is proposed through a case study to identify and evaluate the effective source rocks, which is applied to study the changing characteristic of hydrocarbon-generation potential index with depth. The burial depth corresponding to the beginning of hydrocarbon-generation potential index reduction represents the hydrocarbon expulsion threshold in source rocks. Then, new identification standards are established for discrimination of effective source rocks of Middle–Upper Ordovician in Tarim Basin. The critical value of TOC for effective source rocks change with their burial depth: the TOC > 0.5% with source rock depth > 4000 m, TOC > 0.4% with depth >4500 m, TOC > 0.3% with depth > 5000 m, TOC > 0.2% with depth >5500 m. Based on the new criteria, effective source rocks in the Middle–Upper Ordovician are identified and their total potential hydrocarbon resources is evaluated, reaches 0.68 × 109 t in the Tazhong area, which is 65.4% higher than that of previous studies and consistent with the exploration result. Thus, this new method is of significance to resource evaluation and can be applied in the carbonate source rocks and mudstone source rocks with high degree of exploration.

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

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.

The genetic type and accumulation model of the Devonian reservoirs in the Marsel Block remain unclear, despite decades of exploration history. According to the well testing, logging interpretations and sample testing results, the Devonian natural gas reservoir in the Marsel Block has five typical characteristics: (1) It is obvious that the traps contain continuous gas accumulations. Not only the apexes of the structures are enriched in natural gas, but also the slopes and depressions contain gas accumulations. (2) The gas reservoirs are classified as tight reservoirs, but there are also reservoirs with high porosity and permeability in some areas. (3) The general negative or low-pressure in the gas reservoir is obvious, although the pressure in the target layers of some wells is close to normal. (4) The yields of single wells in the Devonian reservoir are quite different: some wells have low yields or are dry, whereas the gas production from high-yield wells has reached 700 000 m3/day. (5) The gas-water relationship is complicated: there is no obvious gas-water interface, but the water-producing layer is generally located at the apexes of structures. Research and analysis have shown that using the model of the conventional gas reservoirs genetic type can only explain the characteristics of parts of the gas reservoir, while the model of accumulation in a deep-basin gas reservoir cannot fully explain the distribution characteristics of the Devonian reservoir. However, the model of accumulation in a stacked complex continuous oil and gas reservoir can reasonably explain the geological and distribution characteristics of the Devonian reservoir. Moreover, the predicted gas distribution along a cross-section of the reservoir is also in agreement with the geological background and tectonic environment of the Marsel Block, therefore, the genetic type of the Devonian natural gas reservoir in the Marsel Block is a stacked complex continuous tight-gas reservoir. Finally, by comprehensively analyzing the source rock, reservoir and cap rocks, as well as the structural characteristics, it is verified that Devonian in the Marsel Block has favorable geological conditions for formation of a superimposed continuous tight gas reservoir.

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-II1 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-II1 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.

This study analyzes the bulk and molecular geochemical data of 56 core samples of the Eocene Qianjiang Formation, a confined source rock unit embedded with salt intervals formed in a hypersaline lacustrine setting in central China. These source rocks within a single evaporative cycle collected from a recent shale oil exploration well are highly laminated, consisting of both intra- and inter-salt shales. Both organic pores and matrix pores serve as storage for hydrocarbon generated from kerogen within the source rock. Because the contrast in density between kerogen and oil, conversion of kerogen to oil inevitably leads to the increase in pore pressure and oil expulsion from kerogen within the same source rock unit. Impregnation of source rocks by expelled oils from nearby mature source rocks or from the organic-rich laminae within the same source rock units leads to anomalous Rock-Eval pyrolysis data, characterized by an abnormally high S1 peak, a high Production Index (PI), a suppressed Tmax and other anomalies. It is contradictory that both Rock-Eval pyrolysis data and sterane isomerization ratios of the studied inter-salt shale samples indicate strong impact of allochthonous hydrocarbons in the source rocks, whereas most aliphatic biomarker parameters obtained from the solvent extracts of these shales still provide useful information on the vertical variation in organic source input and depositional environment of the host rocks. This study provides insights into the bulk and molecular geochemical data interpretation, particularly in the inter-salt shale oil system evaluation in inferring the prevailing directions and pathways of diagenetic fluid movement and hydrocarbon migration.

The Dibei gas field is a large tight gas field located in the Kuqa subbasin, Tarim Basin, northwestern China. The reservoir is within the Lower Jurassic Ahe Formation (J1a) and has porosity and permeability ranges of 2%–8% and 0.01–1 md, respectively. Two episodes of hydrocarbon charge are identified based on a detailed study of fluid-inclusion petrography and microthermometry, fluorescence spectroscopy characteristics, and the thermal maturity of both gas and light oil. Low-maturity oil as represented by hydrocarbon inclusions with yellow-green fluorescence entered the reservoir circa 23–12 Ma, whereas high-maturity hydrocarbons, as indicated by hydrocarbon inclusions with blue-white fluorescence, have charged the reservoir since 5 Ma. The hydrocarbon charge process combined with porosity evolution determined the present gas–water distribution characteristics in the Dibei gas field. Porosity in the J1a sandstone reservoir was relatively high during the first episode of hydrocarbon charge, which allowed oil to migrate upward and accumulate in structural highs under buoyancy. From 5 Ma to the present, the Dibei gas field experienced strong tectonic compression associated with intense thrust-fault reactivation, causing deformation and oil leakage from the reservoir. Continuous tight sand deposits along the slope areas, located far away from the active faults, became favorable accumulation sites for gas derived from the underlying Triassic source rocks. Hydrocarbon accumulation along the slope area in the Ahe Formation is dominantly controlled by equilibrium between hydrocarbon-generation pressure and capillary pressure.

In this study, we investigate the petrophysical parameter values above which oil can accumulate, using a tight oil reservoir in the Jimusaer Depression, Junggar Basin, as an example. Statistical analysis of well-drilling data and effective porosity measurements is integrated with numerical simulations of force balance to illuminate the mechanisms that place a lower limit on the petrophysical parameters of tight hydrocarbon reservoirs. Further, we discuss the factors that influence these limits. The results show that when porosity is observed to be less than 5%, corresponding to a pore-throat radius of more than 0.2 μm, exploratory wells reach reservoirs comprising only water layers. The lower limit for oil accumulation is reached when irreducible water saturation reaches 100% and porosity is approximately 5%. This fits well with the values arrived at by modeling the force balance. In the reservoirs under consideration, oil charging is driven by excess pressure resulting from hydrocarbon generation and is resisted by capillary force. When the pore-throat radius is larger than 0.2 μm, the capillary force will be greater than the driving force, and tight reservoirs cannot be charged with oil. This corresponds to a porosity of approximately 5%, matching the results derived from observations. The values of these lower limits depend on many factors, such as source rock quality, depth, temperature, hydrocarbon-generation kinetics, and interfacial tension, and hence vary under different geological conditions. Thus, in lacustrine basins in China with type I kerogen-dominated source rocks, the lower limits are smaller than in those where other types dominate. Differences in the geothermal gradient mean that, at similar hydrocarbon-generation temperatures, the lower limits for reservoirs in Western China are smaller than for those in the east. There is also a smaller lower limitation porosity in tight gas reservoirs than in tight oil reservoirs due to the difference in interfacial tension.

In a petroleum accumulation system, the source rock plays a significant geological role in controlling hydrocarbon distribution, because it provides the material basis for hydrocarbon accumulation. Thus, quantitative evaluations of source rock control on hydrocarbon distribution are useful for predicting future hydrocarbon discoveries. Using the Huizhou Depression in the Pearl River Mouth Basin, China, as a case study, geostatistical methods and probability calculation were employed to analyze the controlling effect of source rocks. The Huizhou Depression can be divided into five petroleum accumulation systems of which the Huixi contains the largest known amount of hydrocarbons. A probability model of hydrocarbon accumulations is established for quantitative evaluation of potentially favourable hydrocarbon distribution. In each petroleum accumulation system, the larger the hydrocarbon expulsion intensity, the larger the amount of hydrocarbons that accumulates; the longer the distance from the hydrocarbon expulsion centre, the lower the amount of hydrocarbon accumulates. The hydrocarbon distribution limit controlled by the source rock is 3.5 times the radius of the source kitchen in the Huizhou Depression. In the current state of exploration, oil fields in the Huizhou Depression are mainly observed in the areas 1.5 to 2 times the source kitchen radius. Based on the prediction model, structural highs around hydrocarbon source kitchens are potentially favourable zones for structural hydrocarbon reservoirs, and the interiors of source kitchens are potentially targets for subtle hydrocarbon reservoirs and unconventional resources.

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 (C1/C1–5) 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.

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 C6+ 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 C1–C5 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 lnC2/C3, lnC1/C2 and δ13C1–δ13C2, 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 C1–C5 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 C1–C5 for the coal and the coal measure mudstone are only 32.1% and 22.8%, respectively.

Upper Eocene Enping Formation mudstones in the Pearl River Mouth Basin, South China Sea, which formed during a lake-flooding event, are one of the most important sets of cap rocks in the basin. However, the generation potential (GP) of Enping Formation mudstones remains poorly understood and controversial. Despite a lack of documentation, these mudstones are presumed to have the potential to generate hydrocarbons. In this study, new organic geochemical data for these mudstones are provided based on several new wells drilled into Eocene strata in the Huilu area, northern Pearl River Mouth Basin, which illustrate their hydrocarbon GP. Total organic carbon content ranges from 0.55 to 3.3 wt. % (mean, 1.31 wt. %) with kerogens dominated by type III organic matter (OM) derived from terrigenous plant material. The Zhuqiong II movement, a rifting episode that occurred during the late Eocene (ca. 38 Ma), was associated with the introduction of a large quantity of terrigeneous higher plants by rivers that led to type III OM accumulation and preservation of Enping Formation mudstones. Rapid transverse facies changes led to the geochemical heterogeneity of the source rocks. The OM in these rocks reached an early–midmature stage in uplifted areas (vitrinite reflectance [Ro] e 0.5%–1.0%) and a late–mature stage in sags (Ro e 1.0%–1.3%), stages wherein hydrocarbons can be generated. Therefore, the Enping Formation mudstones may have had the potential to generate hydrocarbons, especially gas, and hence deserve attention in future exploration.

Luocaogou formation developed a set of good quality hydrocarbon source rock in the Jimusaer Depression. Plenty of hydrocarbon shows in shale have been discovered, indicating a good prospect for shale oil exploration. In this paper, the data including Rock-Eval pyrolysis, X-ray diffraction (XRD), lithology, and porosity were used to analyze the impact of oil retention in Lucaogou shale. The results showed that the TOC contents of lacustrine shale have a maximum of 15.51%, averaging 3.49%; the maturity is in the range 0.5%–1.1%; and the organic matters are of type I; the largest net thickness of source rock can reach 194 m, mainly distributed in the centre area rounding J35-J174 well block. Impacts of oil retention in lacustrine shale include TOC, Ro and reservoir physical property. S1 contents increase with growing TOC, and when TOC content is more than 3%, hydrocarbon show thickness ratios (thickness ratio of hydrocarbon show to strata) are over 90%. When Ro reaches 0.8%, OSI (S1/TOC✕100) become largest, and hydrocarbon show thickness ratios are over 80%. Good oil saturation relates to high porosity. Argillaceous limestone and argillaceous dolomite primarily develop matrix pores, while mudstone mainly develops organic pores. Since lower content of clay and higher content of brittle minerals in argillaceous limestone and argillaceous dolomite than in mudstone, both of the porosity and oil saturation of argillaceous limestone and argillaceous dolomite are better than that of mudstone. Generally, the areas deeper than hydrocarbon expulsion threshold (3200–4300 m of depth or 0.8%–1.3% of Ro) are most favourable for shale oil accumulation, which matches the actual oil production data. The depths of high production wells are no less than hydrocarbon expulsion threshold, since S1 contents are high enough to satisfy critical residual amount and pores are developed. Meanwhile, good quality of reservoir developed when organic pores and overpressure were formed during hydrocarbon generation and expulsion.

Hydrocarbon evaporative loss evaluation is important for shale oil resource assessment. We propose a mass balance model to evaluate the hydrocarbon evaporative loss (S1-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 S1-loss. The results indicate that the S1-loss can range from 0.12 to 7.25 mg/g Rock, corresponding to 11%–89% loss of the generated hydrocarbons (S1-loss/(S1+S1-loss)) due to evaporation before lab analysis. It appears that when Ro ≤ 1.3%, S1-loss and S1-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%, S1-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 S1-loss/TOC varies little among the samples but the absolute S1-loss amount increases with increasing TOC. Restricted by regional geological conditions in this study, we focused on the S1-loss for lacustrine type I kerogen only, and quantification of evaporative loss for other kerogen types remains a subject for further study.

Three rounds of exploration in Marsel, Kazakhstan show that the area has good petroleum geological conditions; however, the exploration degree is low and the resource potential is unclear. The total organic carbon ( TOC ) content is the criteria for effective source rocks and is also the key parameter to calculate the amount of resources; while previous evaluations of the effective source rocks and calculated amounts of resources were based on residual TOC , which gradually decreases with mass hydrocarbon expulsion; therefore, this will inevitably produce errors. For greater accuracy, the TOC recovery coefficient formula was used to recover the residual TOC in Marsel; then, the criteria of the effective source rocks were revised to calculate the Carboniferous and Devonian resources in Marsel. The results are as follows: for the source rocks in Marsel, the TOC recovery coefficient of the Carboniferous source rocks is approximately 1.6, while that for the Devonian is approximately 2.0; the revised lower limit of TOC for the effective source rocks is 0.3% and 0.25% for the Carboniferous and Devonian, respectively; after TOC recovery, the total amount of hydrocarbon expulsion is 26.7 × 10 12 m 3 , the total amount of recoverable resources is 2.62–5.10 × 10 12 m 3 , and the mean is 3.79 × 10 12 m 3 for the main source rocks. The effective source rocks evaluated based on the recovered TOC and the latter resources could reflect the quantity of source rocks and actual resource potential of Marsel more accurately. This has certain significance for the exploration of areas that have low levels of exploration with an unclear understanding of the resource potential as well as a high degree of thermal evolution and a low quantity of residual TOC .

In recent years, significant progress and breakthroughs have been made in the exploration of conventional and unconventional natural gas in the Lower Cambrian petroleum system in the Sichuan Basin in Central China, showing excellent exploration prospects. However, detailed evaluation of the Qiongzhusi shale, the main source rocks in the Lower Cambrian petroleum system, including their hydrocarbon generation and expulsion characteristics, is lacking, even though such evaluation is critical for understanding conventional and unconventional natural gas resource potential. To investigate the geological and geochemical characteristics of the Qiongzhusi shale, experiments including pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) were conducted. Based on modeling work and fluid inclusion analysis, the hydrocarbon generation and expulsion characteristics of the Qiongzhusi shale and their control on hydrocarbon accumulation was analyzed, and the conventional and unconventional natural gas resource potential of the Lower Cambrian petroleum system was systematically evaluated. The results indicate that the organic matter of the Qiongzhusi shale is mainly derived from bacteria and algae deposited in a saline, reducing marine environment. The shale is predominantly composed of type I kerogen with an average TOC value of 1.85 wt%, and is widely distributed in the basin with an average thickness of 212.7 m. The Qiongzhusi shale is primarily post-mature with an average vitrinite reflectance (Ro) of 2.53%. Modeling work suggests the Qiongzhusi shale reached the hydrocarbon expulsion threshold (HET) at Ro = 0.9%, and the main hydrocarbon expulsion stages are Triassic, Jurassic, and Cretaceous. The maximum hydrocarbon generation and expulsion intensities at present day are 32 × 106 t/km2 and 18 × 106 t/km2, respectively. The conventional natural gas resource potential of the Longwangmiao Formation derived from the Qiongzhusi shale is estimated to be between 9.51 × 1012 m3 and 19.03 × 1012 m3. The unconventional shale gas resource potential of the Qiongzhusi shale is predicted to be 1.4 × 1012 m3, showing significant prospects for natural gas exploration.

As the most important source rocks in the eastern Junggar Basin, the middle Permian Pingdiquan (P2p) source rocks have attracted increasing attention after the discovery of tight oil in the Shazhang uplift. The P2p source rocks are widely distributed (up to 7546 km2) and have an elevated thickness in the eastern Junggar Basin. To explore the P2p tight oil resource in the eastern Junggar Basin, 113 core samples from 34 exploration wells were analysed geochemically and re-examined for their organic matter abundance, type and thermal maturity, hydrocarbon potential and sedimentary environment. Geochemical analysis results indicate that the P2p source rocks are fair to good source rocks dominated by Type II kerogen, presently in a low mature–mature stage, and biomarkers and trace elements indicate deposition in a terrestrial to coastal environment under oxic to dysoxic, and fresh to brackish conditions, with possible intermittent seawater influence, implying proximity to the open sea. Based on hydrocarbon expulsion modelling, hydrocarbon expulsion began at 0.87% Ro, and the peak expulsion occurred at 1.1% Ro. Hydrocarbon generation intensities in the Shazhang uplift and the Wucaiwan sag are relatively large, with values centred at 4–6.5 million t/km2 and 4–6 million t/km2, respectively, with total hydrocarbon generation and expulsion from the P2p source rocks approximately 4.56 × 109 t and 1.44 × 109 t, respectively, indicating significant tight oil exploration potential in the eastern Junggar Basin. The Shazhang uplift and the Wucaiwan sag are two hydrocarbon expulsion centres in the study area with the largest hydrocarbon expulsion intensity centred around the Shazhang uplift, exceeding 3 × 106 t/km2. We suggest that the area with high hydrocarbon expulsion intensities is a favourable target for tight oil accumulation and 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.

Shale oil exploration of the Permian Lucaogou Formation (P2l) has greatly advanced in the Jimusar Sag in the Junggar Basin. However, despite the strong exploration prospects of shale oil resources, the potential of shale oil resources in the Junggar Basin has been insufficiently assessed. This study performs systematical evaluation of P2l source rocks in the Jimusar Sag and proposes an improved hydrocarbon generation potential method to assess the hydrocarbon generation and expulsion characteristics and evaluates the shale oil resource potential of the P2l source rocks in the Jimusar Sag. The results show that the P2l source rocks are thick (up to 200 m) and are distributed over a wide area (up to 1200 km2) in the study region. It contains high TOC (2%–5%), characterized by dominantly type I and type II kerogen. The source rocks are in the low mature–mature stage, and possess good conditions for generation of hydrocarbons. The P2l source rocks reached the hydrocarbon expulsion threshold at a thermal maturity of 0.8% vitrinite reflectance. The efficiency of hydrocarbon expulsion of the source rock is 34%. The amounts of hydrocarbons generated and expelled were 65 × 108 t. Based on the above information, the shale oil resources potential is calculated to be 43 × 108 t, indicating very good shale oil resource prospect in the P2l source rocks of the Jimusar Sag. Copyright © 2017 John Wiley & Sons, Ltd.

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 ( 24 tetracyclic terpane/C 30 hopane ( trans-trans-trans -bicadinane (T)/C 30 hopane (most 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 ( 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.

Fossil resources are valuable wealth given to human beings by nature. Many mysteries related to them have been revealed such as the origin time and distribution area, but their vertical distribution depth has not been confirmed for people’s different understanding of their origin and the big depth variations from basin to basin. Geological and geochemical data of 13,634 source rock samples from 1,286 exploration wells in six representative petroliferous basins are examined to study their Active Source Rock Depth Limits (ASDL), defined in this study as the maximum burial depth of active source rocks beyond which the source rocks no longer generate or expel hydrocarbons and become inactive, to identify the maximum depth for fossil fuel resources distribution. Theoretically, the maximum depth for the ASDLs of fossil fuel resources ranges from 3,000 m to 16,000 m, while their thermal maturities (Ro) are almost the same with Ro≈3.5±0.5 %. A higher heat flow and more oil-prone kerogen are associated with a shallower ASDL. Active source rocks and the discovered 21.6 billion tons of reserves in six representative basins in China and 52,926 oil and gas reservoirs in the 1,186 basins over the world are found to be distributed above the ASDL, illustrating the universality of such kind of depth limit. The data are deposited in the repository of the PANGAEA database: https://doi.org/10.1594/PANGAEA.900865 (Pang et al., 2019).

The Middle–Upper Ordovician carbonate source rocks in the Tabei Uplift, Tarim Basin, are at highly mature evolution stage with relatively low present-day TOC (TOCpd). It is significant to study the hydrocarbon expulsion characteristics for the marine hydrocarbon exploration in Ordovician carbonate reservoirs. Due to similar depositional environment and same kukersite kerogen, two groups of Ordovician source rocks (468 sets of data from the highly mature Middle–Upper Ordovician source rock (O2+3) in the Tarim Basin and 27 sets of data from the lowly–medium mature Upper Ordovician Yeoman Formation (O3y, Canadian Williston Basin)) are selected as analogue to research the hydrocarbon expulsion characteristics by the approach of mass balance. The result indicates that the two sets of source rocks (O2+3 and O3y) have similar hydrocarbon generation kinetics with the original hydrocarbon index of 900 mg HC/g TOC and a narrow Tmax window; the kerogen transformation ratio reaches 90% at calculated VRE of 1.10%. The hydrocarbon expulsion threshold of the O2+3 source rock is at calculated VRE of 0.9%, the maximum expulsion intensity can reach 20 × 104 t/km2, and the cumulative volume of expulsion is 9.3 ✕ 109 tons. The restored TOCo values of the O2+3 can reach approximately 2%, showing a good original potential. The distribution of high quality oil discovered in the Tabei Uplift is in accordance with that of high hydrocarbon expulsion intensity of the O2+3 carbonate source rocks, implying that the regions with high hydrocarbon expulsion intensity in the southern slope of Tabei Uplift would be favorable exploration areas for the marine hydrocarbons in the Ordovician carbonates in the Tarim Basin in the future.

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

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.

The Sufyan Depression is located in the northwest of Muglad Basin and is considered as a favorable exploration area by both previous studies and present oil shows. In this study, 16 wells are used or referred, the burial history model was built with new seismic, logging and well data, and the thermal maturity (Ro, %) of proved AG source rocks was predicted based on heat flow calculation and EASY %Ro modeling. The results show that the present heat flow range is 36 mW/m 2 ∼50 mW/m 2 (average 39 mW/m 2 ) in 13 wells and 15 mW/m 2 ∼55 mW/m 2 in the whole depression. Accordingly, the geothermal gradient is 20 °C/km∼26 °C/km and 12 °C/km∼30 °C/km, respectively. The paleo-heat flow has three peaks, namely AG-3 period, lower Bentiu period and Early Paleogene, with the value decreases from the first to the last, which is corresponding to the tectonic evolution history. Corresponding to the heat flow distribution feature, the AG source rocks become mature earlier and have higher present marurity in the south area. For AG-2_down and AG-3_up source rocks that are proved to be good-excellent, most of them are mature with Ro as 0.5%–1.1%. But they can only generate plentiful oil and gas to charge reservoirs in the middle and south areas where their Ro is within 0.7%–1.1%, which is consistent with the present oil shows. Besides, the oil shows from AG-2_down reservoir in the middle area of the Sufyan Depression are believed to be contributed by the underlying AG-3_up source rock or the source rocks in the south area.

The lower–middle Permian Lucaogou (P2l) Formation is a “sandwich-type’’ combination of source rocks and reservoirs that is considered to be a potential tight oil reservoir in the Jimusar Sag (JS). We investigated the P2l Formation using a designated workflow to assess its potential as a viable tight oil reservoir play using geological, petrographical, petrophysical, and geochemical characterisation of core samples. The results showed that the P2l source rocks have a widespread distribution (up to 1500 km2), a huge thickness (up to 160 m), a relatively high abundance of organic matter (averaging 3.12 wt%), a good sapropelic quality, and a moderate thermal maturity. The reservoir consists mainly of dolomites and siltstones, predominantly characterised by secondary dissolved pores, with medium–high porosity (averaging 9.1%) and relative low permeability (averaging 0.26 mD), high abundance of brittle minerals (averaging 87.1%), and low abundance of clay minerals (averaging 11.2%) with low water sensit...

Recently, great breakthroughs in natural gas exploration have been achieved in the Nanpu Sag, Bohai Bay Basin, eastern China; however, the genetic type and formation mechanisms of the gas are still unclear, impeding further exploration. Chemical and isotopic compositions were investigated to determine the origins for the gas. Three groupings of the natural gases are recognized: oil-type gas, coal-type gas, and mixed-source gas. The oil-type gases are relatively depleted in 13 C (δ 13 C 1 13 C 2 13 C (δ 13 C 1 > −40‰; δ 13 C 2 > −28‰) with higher wetness (0.80–0.95). The third grouping of gases exhibits intermediate molecular and isotopic values. Most of the gases in the shallow layers of the No. 1 and 4 structural belts have δ 13 C values similar to those of underlying gases and display evidence for microbial alteration. Primary cracking of kerogen is responsible for the generation of most of this gas. Pyrolysis of the source rocks combined with maturity estimations revealed that the relatively shallow oil-type gas was derived primarily from Oligocene and Eocene (Ed 3 –Es 1 ) source rocks bearing Type I–II 1 kerogen, whereas the coal-type gas was generated from the Eocene (Es 2+3 ) source rocks containing II 2 –III kerogen. We concluded that the kerogen type and maturity of the source rocks and the activity of source-connecting faults primarily controlled the distribution of the different gases. We suggest that there is significant deep gas potential in the Nanpu Sag, perhaps even over the whole Bohai Bay Basin, that would be prospective for further deep gas exploration in the area.

In recent years, new oil reservoirs have been discovered in the Eocene tight sandstone of the Huilu area, northern part of the Pearl River Mouth basin, South China Sea, indicating good prospects for tight oil exploration in the area. Exploration has shown that the Huilu area contains two main sets of source rocks: the Eocene Wenchang (E2w) and Enping (E2e) formations. To satisfy the requirements for further exploration in the Huilu area, particularly for tight oil in Eocene sand reservoirs, it is necessary to re-examine and analyze the hydrocarbon generation and expulsion characteristics. Based on mass balance, this study investigated the hydrocarbon generation and expulsion characteristics as well as the tight oil resource potential using geological and geochemical data and a modified conceptual model for generation and expulsion. The results show that the threshold and peak expulsion of the E2w source rocks are at 0.6% vitrinite reflectance and 0.9% vitrinite reflectance, respectively. There were five hydrocarbon expulsion centers, located in the western, eastern, and northern Huizhou Sag and the southern and northern Lufeng Sag. The hydrocarbon yields attributed to E2w source rocks are 2.4 × 1011 tons and 1.6 × 1011 tons, respectively, with an expulsion efficiency of 65%. The E2e source rock threshold and peak expulsion are at 0.65% vitrinite reflectance and 0.93% vitrinite reflectance, respectively, with hydrocarbon expulsion centers located in the centers of the Huizhou and Lufeng sags. The yields attributed to E2e source rocks are 1.1 × 1011 tons and 0.2 × 1011 tons, respectively, with an expulsion efficiency of 20%. Using an accumulation coefficient of 7%–13%, the Eocene tight reservoirs could contain approximately 1.3 × 1010 tons to 2.3 × 1010 tons, with an average of 1.8 × 1010 tons, of in-place tight oil resources (highest recoverable coefficient can reach 17–18%), indicating that there is significant tight oil potential in the Eocene strata of the Huilu area.

Source rocks generate and expel hydrocarbon with thermal evolution, which lead to a decrease of total organic carbon (TOC) content. A new quantitative model for original total organic carbon (TOCo) content evolution and recovery was proposed, and then was used to the carbonate source rocks with different TOCs (CSRDTOC) in the Tazhong area, Tarim Basin, China. Studies showed that the higher the TOC of source rocks, the bigger the range of TOC reduction and recovery coefficient. When vitrinite reflectance (VR) is equal to 2.5%, recovery coefficients of TOCo = 0.2%, 0.4%, and 1.0% are 1.43, 1.66, and 2.01, respectively. It must restore TOCo when we evaluate source rocks at the stage of high overmaturity and predict oil and gas resources.

Although tight oil has great resource potential, studies of oil charging mechanisms in tight reservoirs are relatively few. Researchers have found that a force balance exists during oil charging, but quantitative analyses of conditions critical for tight oil charging are sparse. This study developed a formula to identify effective source rocks using oil expulsion intensity as the discrimination parameter based on quantitative expression of hydrocarbon-generation overpressure and force-balance conditions. Using this formula, critical oil expulsion intensity under conditions at various burial depths can be obtained. This method was applied in the tight reservoirs of the Jimusar Sag, Junggar Basin, China. The calculated critical oil expulsion intensity range was between 122.61 × 104 t/km2 and 620.01 × 104 t/km2. The distribution range of effective oil source rocks and total expelled oil can be determined on the basis of critical oil expulsion intensity at different burial depths. This method provides...

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.

Determination of total organic carbon (TOC) is essential in unconventional shale resource play evaluation. Indirect method, such as petrophysical approach, can provide a fast, convenient and cost efffective means for TOC estimation from well logs. Among the publically available approaches, the ΔlogR method is a popular one in conventional source rock evaluation and has been applied to unconventional resource play evaluation by many practitioners. Careful examination of the method finds that improvements can be made for a better TOC estimation with relaxed limitations. This study proposes the following revisions on the original ΔlogR method: 1) allowing estimation of petrophysical parameters from the targeted source rock rather an assumed linear approximation, 2) using additional logs to improve TOC prediction, and 3) replacing LOM (level of organic metamorphism unit) with a more commonly used thermal indicator Tmax for convenience. Depending on data or preference, the choice of using different porosity logs (density versus sonic) and parameter estimation methods (cross-plot method versus data-driven approaches) makes the revised method flexible for application. We present the revisions along with application examples from the Devonian Duvernay Shale in the Western Canada Sedimentary Basin to demonstrate the application of the improved ΔlogR method in shale gas evaluation. Comparison of the results from the revised method and the original one reveals that the revised models provide better and unbiased estimates of TOC with a higher correlation coefficient and bell-shaped residues centered at zero.

In recent years, many oil and gas reservoirs have been discovered in the Jurassic Toutunhe Formation in the Fudong slope, Junggar Basin. The total reserve in the formation is nearly 100 million tonnes, indicating huge exploration potential in the area. However, the main factors controlling the hydrocarbon accumulation remain unclear, and the mechanisms of hydrocarbon accumulation and enrichment are controversial. In this work, by studying the mechanism and main factors controlling hydrocarbon accumulation in the Toutunhe Formation in the Fudong area, a quantitative model of the reservoir rock and caprocks that control hydrocarbon distribution was constructed, the critical conditions for hydrocarbon accumulation were determined and favourable exploration areas were predicted. The results indicated that the oil in the Toutunhe Formation was derived from both Permian and Jurassic source rocks, the oil migrated from west to east after generation and both reservoir rock and caprock controlled the formation and distribution of oil reservoirs. The oil-bearing capacity improved with increases in the storage coefficient and caprock thickness. Accumulation did not occur when the reservoir rock and caprock index ( RCI) was ≤ 0.5 but was favoured when the values were higher; this factor was the critical condition for hydrocarbon accumulation.

Although a large amount of petroleum has been discovered in the Tarim Basin, the origin of the oils is still disputed. Yingmaili Oilfield was selected as a case study to further examine hydrocarbon generation and accumulation in the basin. Detailed geochemical studies were conducted to unravel the formation mechanisms. The oils in the field correlate well with Middle–Upper Ordovician (O 2+3 ) rocks (or similar rocks). Oil–oil and oil–source rock correlation by maturity parameters of saturate and aromatic hydrocarbons suggest that the Yingmaili and adjacent oils are primarily comparable to source rocks deeper than 6000 m. The results also showed that carbonates might be important potential source rocks as indicated by a relatively high abundance of aromatic sulfur compounds and relatively high C 29 /C 30 -hopane and C 35 /C 34 -hopane ratios of the oils, which are typical features of carbonate source rocks. We suggest the oil from wells YG2 and YG2-1C are more suitable to be end members from the O 2+3 source rocks (or similar rocks) than the oil from well YM2 as previously suggested. We also suggest that the previous model of hydrocarbon migration along the Ordovician unconformity should be revised.

Reconstructing the hydrocarbon generation and expulsion history of source rocks is an essential part of evaluating the hydrocarbon resource potential by genetic method. The hydrocarbon generation potential method is an efficient tool for quantifying the hydrocarbon generation and expulsion characteristics of source rock and evaluating the hydrocarbon resource potential based on Rock-Eval data. Although various revised versions of the method are publicly available, the following problems remain to be resolved: (a) the method is subjective; (b) implicit limitations are observed; and (c) rock mass loss is not considered, which may result in unacceptable errors. In this study, we propose a revised hydrocarbon generation potential method. Expressions for calculating the original rock mass (Go), original total organic carbon (TOCo), transformation ratio (TR), hydrocarbon expulsion ratio (ER) and hydrocarbon expulsion efficiency (f) were developed and incorporated into the hydrocarbon generation and expulsion history reconstruction and hydrocarbon resource potential evaluation, and these expressions combined conventional and unconventional resource evaluations systematically with objective and accurate results. The first member of the Qingshankou Formation (K2qn1) in the Northern Songliao Basin, Northeast China, was used as an example to demonstrate the application of the proposed method. The results have been compared with the unrevised method using the same Rock-Eval data sets and verified with previous reports to demonstrate its reliability. The results also indicate that the hydrocarbon generation threshold (HGT) and hydrocarbon expulsion threshold (HET) of K2qn1 are Ro = 0.4% and Ro = 0.6%, respectively. Three hydrocarbon generation and expulsion peak stages were identified: K2n (81–74 Ma), K2m (74–66 Ma), and N2t (66–0 Ma). The hydrocarbon generation and expulsion centers of K2qn1 are mainly the Qijia-Gulong Sag and Sanzhao Sag. The resource potentials of conventional oil, unconventional tight oil, and shale oil associated with K2qn1 source rocks in the Northern Songliao Basin are 8.15 × 108 t, 22.97 × 108 t, and 62.1 × 108 t, respectively.

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

The Dongpu Depression has abundant oil and gas resources, but the distribution of hydrocarbon resources and enrichment degrees of organic matter (OM) in the northern and southern Dongpu Depression have significant differences due to the diverse sedimentary environment. To gain deep insight into the effects of sedimentary environment on OM accumulation and preservation, a series of experiments including element geochemistry, organic geochemistry and isotope geochemistry were performed on core samples collected from the fresh, brackish and saline regions of the third member of the Eocene Shahejie Formation (Es3). The lacustrine closure, paleo-salinity, redox conditions, hydrodynamic conditions, paleo-climate and paleo-productivity were quantitatively evaluated. Controlling factors and OM enrichment models were evaluated and established. The results show that the Es3 Formation was deposited as the lake experienced closed saline to transitional and then fresh lake stages. The lacustrine deposits were accompanied by climate changes from dry to humid and strongly rifting during Es3 deposition. The weak hydrodynamic conditions (Zr/Rb) and paleo climate indices (δ18O, climate index, Fe/Mn, Sr/Cu and Al/Mg) imply that moderate humid and dry climate can encourage OM development and preservation. The paleo productivity indices (δ13C, P/Al, P/Ti and P content) are positively related to TOC indicating that high productivity promotes OM accumulation. All the paleo salinity indices (Z value, Sr/Ba and B/Ga) have positive correlations with TOC content, suggesting that OM enrichment increases with salinity to some extent. The positive relationships between the redox indices (V/Cr, V/Sc, U/Th, and δU) and TOC indicate that redox conditions are the most important for OM preservation. This study not only advances the theory of OM enrichment mechanism in saline basins, but also provides guidance for predicting the distributions of high-quality source rocks in the Dongpu Depression.

To evaluate petroleum resources, it is important to quantify the hydrocarbon generation and expulsion characteristics of source rock. The hydrocarbon generation potential method is an efficient model for calculating the characteristics of source rocks and evaluating the resource potential. The previous hydrocarbon generation potential model was mainly established by measured Rock-Eval pyrolysis data, and due to inappropriate preservation measures, an important component (volatile hydrocarbon content) of source rock may be significantly reduced. Prior methods may, therefore, not objectively reflect the properties of a source rock and cause unacceptable errors in the resource assessment. This study proposes an improved hydrocarbon generation potential method. The new method considers the initial hydrogen index (HI0) and transformation ratio (Tr) during the evolution of source rocks, which can more realistically reflect the hydrocarbon generation and expulsion history of source rocks. Therefore, the hydrocarbon evaporative loss (Qloss) is calibrated and the hydrocarbon generation and expulsion features of source rocks are more accurately evaluated. The proposed method is used to examine the effectiveness of the third member of the Upper Paleogene Shahejie Formation (Es3) in Nanpu Sag. By utilizing the improved hydrocarbon generation potential model, the hydrocarbon expulsion threshold of the Es3 source rock is positioned at Ro = 0.875%. The maximum hydrocarbon generation and expulsion potential (Qg and Qe) are 593.78 and 323.78 mg HC/g TOC, respectively, and the maximum hydrocarbon expulsion efficiency is 54%. The maximum hydrocarbon generation and expulsion intensities are 500 × 104 t/km2 and 250 × 104 t/km2, respectively, which locate source rock at the Laoyemiao and Gaoshangpu Structural Belts. The amounts of generated and expelled hydrocarbon are 13.7 × 108 t and 6.9 × 108 t, respectively, and the resource potential of the tight oil of the Es3 in the Nanpu Sag is 0.69 × 104 t. Compared with the previous method, the improved hydrocarbon generation potential method limits the maximum Qg and calibrates the Qloss; therefore, the new method more objectively reflects the hydrocarbon generation and expulsion characteristics and resource prospect of the source rock.