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The successful development of unconventional hydrocarbons has significantly increased global hydrocarbon resources, promoted the growth of global hydrocarbon production and made a great breakthrough in classical oil and gas geology. The core mechanism of conventional hydrocarbon accumulation is the preservation of hydrocarbons by trap enrichment and buoyancy, while unconventional hydrocarbons are characterized by continuous accumulation and non-buoyancy accumulation. It is revealed that the key of formation mechanism of the unconventional reservoirs is the self-sealing of hydrocarbons driven by intermolecular forces. Based on the behavior of intermolecular forces and the corresponding self-sealing, the formation mechanisms of unconventional oil and gas can be classified into three categories: (1) thick oil and bitumen, which are dominated by large molecular viscous force and condensation force; (2) tight oil and gas, shale oil and gas and coal-bed methane, which are dominated by capillary forces and molecular adsorption; and (3) gas hydrate, which is dominated by intermolecular clathration. This study discusses in detail the characteristics, boundary conditions and geological examples of self-sealing of the five types of unconventional resources, and the basic principles and mathematical characterization of intermolecular forces. This research will deepen the understanding of formation mechanisms of unconventional hydrocarbons, improve the ability to predict and evaluate unconventional oil and gas resources, and promote the development and production techniques and potential production capacity of unconventional oil and gas.

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.

The India-Eurasia convergence since early Cenozoic has established the Tibetan Plateau and the Circum-Tibetan Plateau Basin and Orogen System (CTPBOS). When and how the convergence-driving strain has propagated into the CTPBOS is of significant importance in deciphering the growth process of the Tibetan Plateau. In this study, we conduct a structural analysis of the West Kunlun-southern Junggar transect along the NW margin of the Tibetan Plateau to establish the deformation propagation and through this to determine the plateau growth processes. The results suggest a two-phase deformation mode. The first stage features deformation confined in pre-existing weak zones like the West Kunlun orogen, Buchu Uplift and Tian Shan orogen during Paleogene, in which the intracontinental strain was speculated to be mainly consumed by shortening of these weak zones. The second stage is characterized by deformation propagating into foreland regions since early Miocene, in which shorting along foreland fold-and-thrust belts of a scale of tens of kilometers and decreasing basinwardly plays a key role in absorbing intracontinental strain. We suggest that this two-phase deformation mode possibly reflects a shift of governing mechanism of the expansion of the Tibetan Plateau from a rigid-block manner to a critical wedge taper style. Thematic collection: This article is part of the Fold-and-thrust belts collection available at: https://www.lyellcollection.org/cc/fold-and-thrust-belts

The discovery of unconventional hydrocarbon resources since the late 20th century changed geologists’ understanding of hydrocarbon migration and accumulations and provides a solution to energy shortage. In 2016, unconventional oil production in the USA accounted for 41% of the total oil production; and unconventional natural gas production in China accounted for 35% of total gas production, showing strong growth momentum of unconventional hydrocarbons explorations. Unconventional hydrocarbons generally coexist with conventional petroleum resources; they sometimes distribute in a separate system, not coexisting with a conventional system. Identification and prediction of unconventional resources and their potentials are prominent challenges for geologists. This study analyzed the results of 12,237 drilling wells in six representative petroliferous basins in China and studied the correlations and differences between conventional and unconventional hydrocarbons by comparing their geological features. Migration and accumulation of conventional hydrocarbon are caused dominantly by buoyance. We propose a concept of buoyance-driven hydrocarbon accumulation depth to describe the deepest hydrocarbon accumulation depth driven dominantly by buoyance; beyond this depth the buoyance becomes unimportant for hydrocarbon accumulation. We found that the buoyance-driven hydrocarbon accumulation depth in petroliferous basins controls the different oil/gas reservoirs distribution and resource potentials. Hydrocarbon migration and accumulations above this depth is dominated by buoyancy, forming conventional reservoirs in traps with high porosity and permeability, while hydrocarbon migration and accumulation below this depth is dominated by non-buoyancy forces (mainly refers to capillary force, hydrocarbon volume expansion force, etc.), forming unconventional reservoirs in tight layers. The buoyance-driven hydrocarbon accumulation depths in six basins in China range from 1200 m to 4200 m, which become shallower with increasing geothermal gradient, decreasing particle size of sandstone reservoir layers, or an uplift in the whole petroliferous basin. The predicted unconventional resource potential below the buoyance-driven hydrocarbon accumulation depth in six basins in China is more than 15.71 × 109 t oil equivalent, among them 4.71× 109 t reserves have been proved. Worldwide, 94% of 52,926 oil and gas reservoirs in 1186 basins are conventional reservoirs and only 6% of them are unconventional reservoirs. These 94% conventional reservoirs show promising exploration prospects in the deep area below buoyance-driven hydrocarbon accumulation depth.

There are successes and failures in the exploration of marine shale gas in South China. In some shale gas plays with great basis for hydrocarbon generation, a phenomenon exists that gas loggings reflect low gas bearing in some of the wells and the gas is dominated by nitrogen rather than hydrocarbon gas. The study of nitrogen concentration in shale gas contributes to solve the question that how shale gas diffuses in complex tectonic areas, which helps to figure out the preservation requirements and accumulation mechanisms of shale gas and avoid exploration crisis. This study focused on the lower Cambrian shale in Xiuwu Basin, Lower Yangtze Region, with emphasis on the well Jiangye-1, using gas component analysis, stable nitrogen isotope analysis, overburden permeability tests in parallel and perpendicular directions, and FIB-HIM experiments, also combining with core description, outcrop observation, and seismic interpretation to explore the causes of the high-content nitrogen and low-content hydrocarbon in the lower Cambrian shale gas. The results show that the nitrogen of the lower Cambrian shale in Xiuwu Basin is derived from the atmosphere and the deep crust-upper mantle. The bedding planes and the detachment layer at the bottom of the lower Cambrian compose the lateral pathways, and the widespread deep faults are the vertical pathways for shale gas migration and diffusion. Combining these two, an effective pathway network was built, favorable to gas exchange between the shale gas interval and the atmosphere, partly leading to the concentration of nitrogen and the diffusion of hydrocarbon gas. In the Jurassic, the magmatic activities occurred frequently in the surrounding areas, which not only brought nitrogen from the deep crust-upper mantle but also increased the value of paleo-heat flow even though the basin began to uplift, which promoted the graphitization of organic matter and the collapse of organic pores and accelerated the loss of shale gas. Based on the study above, an explanation model was summarized to expound the causes of high-content nitrogen and low-content hydrocarbon in shale gas plays near the plate-active region in Xiuwu Basin, Lower Yangtze Region.

It is a common method to use sequence stratigraphic theory to identify favourable intervals in hydrocarbon exploration. The Lower Cambrian shale of Well Jiangye-1 in Yangtze Region in Xiuwu Basin was chosen as the research object. The content of excess silicon of siliceous minerals in shale was calculated quantitatively, and the concentration distribution of Al, Fe, Mn showed that the excess silicon is of hydrothermally origin and the shale deposited in an environment with hydrothermal activity. Using U/Th values in the study, combined with lithology and logging data, in order to divide sequences of the Lower Cambrian shale in Yangtze Region in Xiuwu Basin. The result shows that the shale of the Lower Cambrian shale is recognized as 1 2nd sequence (TST-RST, TST = Transgressive systems tract; RST = Regressive systems tract) and then further subdivided into 5 3rd sequences (SQ1-SQ5). During the deposition of SQ2 and SQ3, hydrothermal activity was active, and their excess silicon content was generally above 20%-30%. Rising sea level and active hydrothermal activity were beneficial for the enrichment of siliceous minerals and organic matter. Based on the comparison of the reservoir parameters, it tells that SQ2 and SQ3 have relatively higher content of TOC, higher content of brittle minerals (such as siliceous minerals, carbonate minerals and so on), larger effective porosity and higher content of gas, which make it as the most favourable intervals of the Lower Cambrian in Xiuwu Basin.

The micropore-throat structure of a tight oil reservoir is complex, and its movable fluid distribution differs from that of a conventional reservoir. By using nuclear magnetic resonance (NMR) and centrifugation, the movable fluid distribution in the Chang 7 tight reservoir in the Xin'anbian Block of the Ordos Basin was quantitatively evaluated. Combined with the results of the physical property and high-pressure mercury intrusion experiments, the effects of the porosity, permeability, pore size distribution and micropore-throat structure on the movable fluid distribution in the Chang 7 tight reservoir were analyzed. The NMR results show that the T2 spectral morphology of the Chang 7 tight oil reservoir in the Xin'anbian Block can be characterized by three main patterns with different amplitudes of front and post peaks. The front peak corresponds to the scale of small pores and the post peak corresponds to the scale of large pores. Based on the three T2 spectrum patterns, the Chang 7 tight reservoir can be divided into three types: type 1 reservoir with more small pores and fewer large pores, type 2 reservoir with similar amounts of small and large pores, and type 3 reservoir with fewer small pores and more large pores. Thus, the characteristics of these three types of reservoirs can be determined. The movable fluid parameters were calculated by NMR and centrifugation. The movable fluid saturation of the type 1 reservoir is low, with an average of 20.38%, and the average movable fluid porosity is 1.47%. The type 2 and type 3 reservoirs have higher movable fluid contents of 40.79% and 47.04%, respectively. The average movable fluid porosities of the type 2 and type 3 reservoirs are 3.37% and 3.48%, respectively. The greater number of small pores and smaller number of large pores in the type 1 reservoir result in weak correlations of the movable fluid with the physical properties and pore-throat structure parameters. The movable fluid saturation is negatively correlated with the maximum pore radius, mainstream throat radius and maximum mercury saturation and is strongly positively correlated only with the porosity of the large pores. As the number of large pores increases, the movable fluid saturation strongly correlates with the property parameters, pore size distribution, and pore-throat structure parameters in the type 2 and type 3 reservoirs. The movable fluid saturations are positively affected by the maximum pore radius, median radius, mainstream throat radius, and effective porosity but are strongly negatively correlated only with the radius mean value. These results indicate that the fluid mobility of these two types of reservoirs can be promoted by the pore-throat system to obtain favorable seepage characteristics.

Shale and its roof and floor are very important for shale gas preservation. How to clarify the mechanism of its vertical sealing and its effect on shale gas enrichment is a significant problem to be solved. In this paper, the objective layers are the Upper Ordovician Wufeng Formation, the first member of the Lower Silurian Longmaxi Formation and the Lower Cambrian Qiongzhusi Formation, which are all in the representative shale gas blocks in the Sichuan basin of the Yangtze region. Studied by statistical drilling data, the focus is on the detailed analyses of the JiaoYe-1, Ning-201 and Wei-201 well, and experiments were carried out such as the porosity test, the TOC content analysis and the experiment of overburden permeability, permeability experiments before and after adsorption of methane under different osmotic pressure, and isothermal adsorption experiments. The experiments results are applied on studying the effect of shale and its roof and floor on shale gas enrichment, combined with formula deduction. The results show that the roof and floor have a vertical sealing effect on the organic-rich shale by the difference of physical properties. In eastern Sichuan, the roof of the organic-rich shale of the Wufeng Formation and the first member of Longmaxi Formation is assemblage of argillaceous siltstone and siliceous shale, while in southern Sichuan it is assemblage of gray shale and siliceous shale. The floor is nodular limestone and limestone in both areas. The combination of roof and floor, with low porosity, can form a quality roof and floor sealing ability in the absence of fracture development. Its sealing ability is stronger than that in the upper part of the Qiongzhusi Formation, considering its roof and floor composed of argillaceous siltstone and siliceous shale. The floor of the organic-rich shale at the bottom of the Qiongzhusi Formation is a dolomite reservoir with good storage capacity, between which there is an unconformable contact causing the worst sealing ability among the three intervals. With the increase of burial depth, the overlying pressure of shale increases. With the increase of TOC content and thickness, the amount of adsorption gas of shale increases. These two aspects of factors can lead to the permeability decline and self-sealing enhancement of the organic-rich shale. In this study, focusing on the Upper Ordovician-Lower Silurian and the Lower Cambrian in the Sichuan basin, four patterns of organic-rich shale and its roof and floor were summed up, and the rapid evaluation method of sealing of shale and its roof and floor under the limited geological data was established.

The determination of favorable areas for shale gas enrichment under a syncline background is an important problem that needs to be addressed. The research objects in this study are typical shale gas blocks of the southern Sichuan Basin and the Xiuwu Basin in the Yangtze region with Lower Cambrian and Upper Ordovician–Lower Silurian shales. We carried out permeability tests parallel and perpendicular to the bedding surface, permeability tests with different overburden pressures, and permeability tests and isothermal adsorption experiments under different osmotic pressures before and after the adsorption of methane parallel to the bedding surface. In addition, along with the analysis of drilling data statistics, the enrichment of marine shale gas under a syncline background was studied with respect to dip angle and burial depth. The results show that the preservation conditions of shale gas are better when the dip angle is below 10°, while they are relatively poorer at angle more than 20°. This is due to the migration of natural gas, mainly in parallel direction to the bedding surface, leading to favorable shale gas preservation with decreasing angle. Based on double effects of the overburden pressure and gas adsorption (both increase) parallel to the bedding surface on the permeability of shale, the permeability decreases. When the overburden pressure increases to 10–15 MPa, the permeability parallel to the shale layer changes suddenly and decreases to a low value, which means that under the syncline background, the drilling depth with good shale gas production capacity should be at least 1019–1529 m.

Uranium deposits are crucial resources for the development of the nuclear energy. Among known sources of uranium, the uranium-rich shales have recently obtained significance. In this paper, the Lower Cambrian Wangyinpu Formation shale in the Xiuwu Basin, southern China, has been studied using a combination of techniques including element analysis (Al, Fe, and Mn), δ30Si silicon isotopic analysis, δ18O oxygen isotopic analysis, study of core samples. It has been observed that significant hydrothermal activity occurred in the Xiuwu Basin during the Early Cambrian period. The results show that 20%–40% of the silicon in most of the sections of the Lower Cambrian Wangyinpu Formation were inherited from the hydrothermal fluids, with temperatures ranging between 75∘C and 102∘C. It is concluded that more than 90% of the uranium in most of the sections of the Lower Cambrian Wangyinpu shale was derived from submarine hydrothermal fluids, while less than 10% from the terrigenous detritus. The enrichment of uranium in the basin was observed in the Middle-Upper part of the Wangyinpu Formation and the geological resources estimated to a tune of ~4.9×103 t. In this paper, we proposed a model for silicon and uranium enrichment in the Lower Cambrian shale controlled by hydrothermal activity in the Xiuwu Basin. This model also provides a scientific rationale for uranium further exploration and exploitation of the uranium resource.

In order to meet the demand of shale oil and gas exploration, it is more and more important to study the controlling effect of sedimentary environment on the enrichment of organic matter. In this paper, the Lower Cambrian and Upper Ordovician-Lower Silurian shales in the Yangtze region are studied. Firstly, according to the content of Mo and TOC, the water closure property of the shale depositional period is judged. Then this study selected typical wells, and calculated quantitatively whether there was excess siliceous minerals in shale and the content of it. The origin of excess siliceous minerals is determined by Al, Fe and Mn element. The results show that the Lower Cambrian shale is deposited in a weak to moderate restricted water environment, and the Upper Ordovician and Lower Silurian shales are deposited in a strong restricted water environment in the Yangtze region. Excess siliceous minerals in the Lower Cambrian shale is of hydrothermal origin. On the one hand, hydrothermal activity can enhance the reductivity of the water bottom. On the other hand, it can improve the biological productivity, so that the sedimentary organic matter can be enriched. Excess siliceous minerals in Upper Ordovician and Lower Silurian shale is biogenic. The strong restriction of the water leads to stratification. The oxygen content in the upper layer makes the biological productivity higher and the lower layer more reductive, which is beneficial to the preservation of sedimentary organic matter.

Finding favorable sites for the exploration of shale gas, is still one of the important areas of research that needs immediate attention. The content of organic matter in shale plays a crucial role in the hydrocarbon generation potential, reservoir space and gas-bearing capacity of shales. Therefore, studying the sedimentary environment of organic shale can provide a scientific basis for locating favorable exploration areas for shale gas. The article takes the Lower Cambrian and the Upper Ordovician-Lower Silurian shales in the Yangtze region as the research object and selects representative wells to quantitatively calculate the existence of excess silicon in shale siliceous minerals and the content of excess silicon. Then, the origin of excess silicon can be clarified by the Al, Fe and Mn elemental analysis. Finally, the sedimentary organic matter enrichment mechanism is analyzed from water oxidation-reduction environments and biological productivity. The results of the study show that the excess silicon in the Lower Cambrian and Upper Ordovician-Lower Silurian shales in the Lower Yangtze region is of hydrothermal origin. The hydrothermal activity improves biological fertility on the one hand; whereas on the other hand, it can enhance the reducing capacity of the bottom water conducive for the preservation of organic matter thereby enriching the sedimentary organic matter. The place near the junction of Yangtze plate and Cathaysian plate, where hydrothermal activities were more intense, provided favorable loci for shale gas exploration in the Lower Yangtze region. It was observed that, since the hydrothermal activity was stronger in the Early Cambrian than in the Late Ordovician-Early Silurian times, the total organic carbon (TOC) content of the Lower Cambrian shale was higher than that of the Upper Ordovician-Lower Silurian shales.

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 (Ql), the volume of primary hydrocarbon accumulation (Q0), the ratio of destroyed hydrocarbon (Kl), 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.

Although significant progress has been made in the tight gas exploration and development, there is still a limited understanding of the fluid charging and hydrocarbon accumulation in the sweet spot. In this study, a novel method is proposed to generate the stochastically constructed porous media which represents the transition region between tight surrounding sandstone and sweet spot. Based on the constructed porous media, the fluid charging and hydrocarbon accumulation processes of the tight reservoir are simulated by the lattice Boltzmann method (LBM). The numerical simulation results show that, although a piston-like pattern can be observed in field-scale simulation or laboratory experiments, at the micro-scale, due to the inherent heterogeneity of the porous media, the fluid charging pattern tends to be fingering-like. The existence of the transition region between tight surrounding sandstone and sweet spot becomes a water-bearing gas layer or even gas-bearing water layer at the top/bottom of the gas layers (sweet spot). The existence of fractures is favorable for hydrocarbon charging into the reservoir rocks, but not for the hydrocarbon accumulation due to the gas escaping through the fractures. Combined with well logging interpretation results, three typical water bodies (isolated water body, water body at the top, or bottom of the gas layer) are identified from the view of fluid charging and hydrocarbon accumulation.

The southern Junggar Basin has enormous hydrocarbon mainly from the Jurassic and Permian source rocks, which indicated the importance of exploration of the deeply buried Jurassic reservoirs, therefore, the study of the deeply buried Upper Jurassic Qigu Formation (J3q) reservoirs in Well DS-1 in the Dushanzi anticline was carried out through microscopic observation and measurement, nuclear magnetic resonance (NMR), scanning electron microscopy (SEM) and high pressure mercury injection. Results showed that the main reservoir storage spaces in the deeply buried Upper Jurassic Qigu Formation reservoirs were fractures and dissolved pores. The J3q reservoirs with low porosity and permeability values of 0–12% and (0–5) × 10−3μm2 respectively, were generally tight. According to the mercury injection data, heterogeneity existed in the deeply buried Qigu Formation reservoirs with inhomogeneous pores and changeable sizes of pores throats. Pores and pore throats in the silt-fine sandstones of the lower Qigu Formation (J3q1) were more big and wide respectively than that in the argillaceous siltstones of the upper Qigu Formation (J3q3). Reservoirs in J3q1 had more mobile fluid and better conductivities than reservoirs in J3q3. The strong compaction and multistage diagenesis resulted in the tight J3q reservoirs. Anhydrite and quartz cementation, and various authigenetic minerals (e.g. hematite, kaolinite, illite/smectite formation, illite, chlorite and zeolite) filled in the pores. The homogenization temperature of brine inclusions (63.1–161.7 °C) in quartz overgrowth indicated the quartz had grown since the late Eocene. Due to the Tian Shan reactivity in the Late Cenozoic, the structure fractures were developed and promoted dissolution by oil and formation water in the reservoirs of J3q1. Keywords: Tight reservoirs evolution, Heterogeneity, Fluid inclusion, Structure fractures, Qigu Formation, The Dushanzi anticline, Southern Junggar Basin

Lower Cambrian is the main target intervals of marine shale gas exploration and exploitation in China. Shale gas bearing varies greatly among different intervals and how to determine favorable targets is an important problem to be solved. In this article, taking Jiangye-1 well in Xiuwu Basin as an example, according to core description, logging data analysis, section authentication, mineral and elemental composition analysis, bulk and effective porosity tests, total organic carbon (TOC) and gas content tests, lower Cambrian Wangyinpu and Guanyintang formations have been studied. Results show that TOC content is the dominating factors for effective porosity and gas bearing content, redox conditions and bioproductivity control the enrichment of sedimentary organic matter. The water reducibility of SQ1 varies greatly, of SQ2 and SQ3 is generally strong, reducibility of all the three sequences is stronger than those of SQ4 and SQ5; the bioproductivity of SQ3 is the highest and little difference in the bioproductivity has been found between SQ1 and SQ2, both of which show higher values than SQ4 and SQ5. Except for terrigenous siliceous minerals, large amounts of hydrothermal origin siliceous minerals exist in lower Cambrian Wangyinpu and Guanyintang formations. Specifically, siliceous origin of SQ1 varies greatly, part of intervals are terrigeneous origin and part of intervals are hydrothermal origin; most siliceous minerals of SQ2 and SQ3 are hydrothermal origin, whose content takes up 10%–30%; compared with SQ2 and SQ3, content of hydrothermal origin siliceous minerals drops in SQ4 and terrigeneous siliceous content increases; siliceous minerals of SQ5 originate from normal terrigeneous clastic deposition. Hydrothermal activities are helpful for the increase of reducibility of seawater and enhancing bioproductivity, the sedimentary organic matter abundance is thus controlled and the enrichment of shale gas is further affected. Hydrothermal activities are generally developed in the early Cambrian in South China. The intervals deposited when frequent hydrothermal activities occurred are exactly favorable targets of shale gas in lower Cambrian.

Great changes of the global energy industry have been caused by the rapid development of unconventional oil and gas. It is necessary to deeply consider the profound influence of the unconventional oil and gas revolution on the classical petroleum geology theory and to review geological conception of oil and gas accumulation elements and theoretic framework of petroleum system, giving the petroleum geology a new academic connotation. The author summarizes the significant progresses of global unconventional oil and gas exploration and development, and points out that the unconventional oil and gas revolution not only has a significant economic significance of oil and gas resource increment, but also brings great innovation to the theory of petroleum geology, thus having important scientific significances. This paper summarizes the core contents of four aspects of hydrocarbon generation, reservoir, distribution and development in classical petroleum geology, and comprehensively reviews the five important nodes in the developmental history of petroleum geology, which include anticline and trap theory, hydrocarbon generation from organic matter and petroleum system theory, continental petroleum geology, marine deepwater petroleum geology, continuous hydrocarbon accumulation and unconventional petroleum geology theory. Unconventional oil and gas has made a great breakthrough to classical petroleum geology on the basic theoretical concepts such as trap, reservoir, caprock, resource distribution, and enrichment, thereby promoting the basic research on petroleum geology to transform into the whole process of hydrocarbon generation, whole type of reservoir, and whole genetic mechanism, deepening unconventional petroleum geology theory, promoting the development and reconstruction of petroleum geology system, representing great significances to the strategic development from conventional to unconventional oil and gas in China or even in the world. Key words: petroleum geology, unconventional petroleum geology theory, continuous hydrocarbon accumulation, tight oil and tight gas, shale oil and shale gas, oil and gas production

A series of fault-related folds developed in the Dabei Gas Field of the Kuqa Depression, western China form major traps for hydrocarbon accumulation. The Bashijiqike (K 1 bs) sandstone reservoirs in the different fault-related folds of the Dabei Gas Field display similar excess fluid pressure, formation water type and salinity, and as well as light oil and gas properties. The light oil and gas in the K 1 bs sandstone reservoir of the traps share the same source and were generated at a thermal maturity level of 1.4–1.6% R o and 1.7–2.3% R o , respectively. To investigate the fluid evolution in the fault-related fold traps, an integrated fluid inclusion analysis was performed including petrography, fluorescence spectroscopy, microthermometry, Laser Raman spectroscopy and thermodynamic modeling. The fluid evolution recorded by the fluid inclusions in the different fault-related folds indicates that the formation fluid was characterized by low salinity at normal hydrostatic pressure from approximately >9–5 Ma. From 5 to 3 Ma the formation water salinity and fluid pressure increased rapidly. The formation water attained the highest salinity at approximately 3 Ma to present while the pore fluid overpressure decreased with time in the reservoir. Two episodes of oil and one episode of gas charge were identified in the K 1 bs sandstone reservoir with the second episode of oil charge occurring around 5–4 Ma, while the gas charge occurred around 3–2 Ma. The injection of new fluids associated with oil and gas charge caused changes of the formation water salinity in the different fault-related fold traps within the gas field. The fluid evolution in the Dabei Gas Field can be used to indicate fault-related fluid flow as the thrust faults are suggested to be the primly pathways for fluid migration and the fluid flow was controlled by the reactivation of these thrust faults. The similarity of the oil and gas charge histories, formation water salinity and fluid pressure evolution in the K 1 bs sandstone reservoirs among the different fault-related traps in the Dabei Gas Field implies that the fault-related fluid flow process and activation of the thrust faults were concomitant since approximately 9 Ma.

Oil and gas currently still hold a leading role in the global energy mix. The recent drastic increase in unconventional oil and gas production contributes significantly to strike a balance between the global demand and supply of oil and gas. However, a range of important fundamental questions about the unconventional oil and gas resources have not been adequately answered. Little is known about the distribution and accumulation patterns, as well as the exploration and development characteristics of unconventional oil and gas. The current status of global oil and gas exploration was reviewed and four key theoretical issues regarding the unconventional oil and gas geology were identified: (1) the traditional concept and definition of “petroleum system” needs to be revisited. The concept of a “holistic-process accumulation” model of a “total petroleum system” in petroliferous basins was proposed to analyze the unconventional hydrocarbon accumulation mechanisms from four key aspects of quantitative studies on hydrocarbon generation–expulsion–migration–accumulation processes. (2) The second issue is related to fine-grained sedimentary system and sedimentary facies of tight reservoirs. Through analyzing the relationship between fine-grained sediments and unconventional hydrocarbon accumulation, three research integration areas were put forward. (3) The third issue is on the micro-nano pore system and fluid phase behavior in shales and tight reservoirs. Five aspects of micro-nano pore system were identified to focus on unconventional hydrocarbon research, and the characteristics of micro-nano pore development and fluid phase behavior in micro-nanopores were elucidated. (4) The fourth issue is related to unconventional hydrocarbon accumulation patterns and resource evaluation. Based on the characteristics of unconventional hydrocarbon accumulation, an evaluation system for unconventional hydrocarbon resources was established and optimized. Key words: energy consumption, unconventional hydrocarbons, exploration status, petroleum system, tight reservoirs, micro-nano pore system

The Kelasu Thrust Belt is a favorable hydrocarbon accumulation zone in the Kuqa Sub-basin with several known giant gas fields including the Dabei and Kela-2 gas fields as well as the Dawanqi oil field. The origin and accumulation process of the hydrocarbons were investigated through an integrated petroleum geochemistry and fluid inclusion analysis, and basin modeling. Geochemical parameters indicate that the light oils from the Dawanqi oil field and Dabei gas field were generated from different sources as compared with light oils from the Kela-2 gas field. Light oils from the Dawanqi oil field and Dabei gas field are primarily derived from the terrestrial mudstones in the Jurassic Qiakemake (J2q) Formation with a maturity level of 1.4–1.6 %Ro, whereas light oils from the Kela-2 gas field are mainly derived from the terrestrial mudstones in the Triassic Huangshanjie (T3h) with a maturity level of 1.6–1.8 %Ro. Gases in the Kelasu Thrust Belt are dominated by coal-type gas and are primarily generated from the Jurassic coal measures. Carbon isotope ratios suggest that gases in the Dawanqi oil field and Dabei gas field were generated at a thermal maturity level of 1.6–2.3 %Ro, while gas in the Kela-2 gas field was generated at a thermal maturity level of 2.1–2.5 %Ro. Two episodes of oil and one episode of gas charge were delineated in the Dabei gas field. The second episode of oil charge occurred around 5–4 Ma, while gas charge occurred around 3–2 Ma. Three episodes of oil and one episode of gas charge were identified in the Kela-2 gas field. The latter two episodes of oil charge occurred around 5.5–4.5 Ma and the gas charge occurred around 3–2 Ma. The timing of the petroleum charge was also confirmed by the correlation between the maturity of the source rocks during the times of charge and the maturity levels of the light oil and gas in the reservoirs. The later oil and gas charge occurred at the same period in both the Dabei and Kela-2 gas fields, possibly relating to structural reactivation caused by regional tectonic compression, because intense tectonic compression and rapid uplift of the Tianshan Mountains occurred during the same period, which may have caused thrust fault activation and opening. Hydrocarbon expulsion from the source rocks during the period was possibly also related to the regional tectonic movement, providing hydrocarbon sources for the reservoirs.

The Dabei Gas Field is a recently discovered giant tight-gas field in the Kuqa Subbasin, western China. The reservoir porosity and permeability mainly range from 1% to 8% and from 0.01 to 1 md, respectively. The hydrocarbon (both gas and light oil) accumulation processes in the tight-sandstone reservoirs were studied based on detailed reservoir characterization, thermal maturity of both gas and light oil, hydrocarbon charge history, regional tectonic compression, and thrusting. Two episodes of oil and one episode of natural-gas charge were delineated in the tight-sandstone reservoir, as evidenced by (1) similar sources but different maturities for the gas and light oil, (2) the presence of abundant bitumen in the tight-sandstone reservoir, (3) the presence of both hydrocarbon gas inclusions and oil inclusions with two distinct fluorescence colors, and (4) the presence of two groups of aqueous inclusions (coeval with the petroleum inclusions) with contrasting homogenization temperatures and salinities. The oil inclusions with the blue-white fluorescence color were determined to have been trapped at 5–4 Ma, whereas the gas charge may have occurred at circa 3–2 Ma, corresponding to a salinity change recorded in the aqueous inclusions. The hydrocarbon accumulation processes appeared to be controlled by the tectonic compression of the South Tianshan Mountains. Intense tectonic compression caused thrust fault reactivation, which provided pathways for hydrocarbon migration. Overpressure evolution of the reservoir indicates that an intense tectonic compression began at circa 5 Ma, which caused thrust activation and concomitant oil charge into the relatively porous part of the reservoir. Subsequent tectonic compression caused uplift and erosion associated with thrusting at the end of the Kuqa Formation deposition (ca. 3 Ma), with thrust faults and fractures acting as major migration pathways for the gas accumulation in the already-tight sandstone reservoir resulting from both compaction and tectonic compression.

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 study of tectonics is one of the important aspects of shale gas preservation. It is vital for understanding how to determine the enrichment regularity of marine shale gas in anticlines. This paper focuses on typical shale blocks in the southern Sichuan Basin and shale in the Upper Ordovician and the Lower Silurian. In this study, triaxial unloading tests, permeability tests perpendicular and parallel to the stratification plane, FIB-HIM tests, and inclusion analyses are carried out with real drilling data. The enrichment regularity of marine shale gas in anticlines is studied by considering 2 aspects: the angle of the limbs and the burial depth. For anticlines with adjacent synclines, the migration regularity of shale gas is considered by 3 aspects: the dynamics, channels, and processes of migration. This study reveals that a limb angle greater than 120° reflects relatively good conditions for shale gas preservation, while limb angles lesser than 70° indicate relatively poor conditions. This study also suggests that during the process of uplift, large-scale concentrated fractures will form at a certain depth range and horizontal stress field, resulting in the large loss of shale gas. The regression equation of the fractured depth (H) and the horizontal stress (S) is presented as H=15.404S−754.41 (with a correlation coefficient R2=0.6834). The stratification plane and the organic pores form the migration channel of natural gas that is horizontal to the stratification plane in shale. Under the condition of both anticlines and contiguous synclines, shale gas escapes through fractures resulting from extrusion along the anticline and the uplift effect. In addition, driven by differences in the formation pressure coefficients, shale gas is capable of migrating in a short-distance stair-type style from synclines to the adjacent anticlines. Thus, if the drilling costs allow, the well locations should be placed in the more deeply buried synclines.

Tight oil refers to a petroleum play that occurs in a free or adsorbed state in source rocks or tight reservoir rocks (e.g., sandstone and carbonate rock) interbedded with or close to source rocks. Tight oil has generally not experienced large-scale, long-distance migration. According to such a definition and its characteristics, 10 key indices are proposed for tight oil resource evaluation in China. Tight oil reservoirs are divided into three groups in terms of porosity and permeability. Tight oil can be classified into three types according to the contact relationship between the tight oil reservoirs and source rocks, i.e., tight lacustrine carbonate oil, tight deep-lake gravity flow sandstones oil, and tight deep-lake deltaic sandstones oil. In China, tight oil resources are widely distributed and significant exploration discoveries have been achieved in the sixth member and seventh member of the Triassic Yanchang Formation in the Ordos Basin, the Permian Lucaogou Formation in the Junggar Basin, the Middle-Lower Jurassic strata of the Sichuan Basin, and the Cretaceous Qingshankou and Quantou Formations in the Songliao Basin. The total geological resources of tight oil in China assessed by using the “analog” method are estimated to be (10.67−11.15) ×109 tones. Taking into account of the future prospects of petroleum development, tight oil may become a realistic alternative to the conventional oil resources in China. Key words: tight oil, evaluation criteria, classification, reservoir characteristics, resource potential

In order to understand redox variations and organic matter accumulation on the Yangtze carbonate platform during the Late Ediacaran–Early Cambrian, petrological and geochemical studies of several wells were carried out in this work. Our data suggest that depositional environments were dominated by oxidizing bottom water conditions during the late Ediacaran, and evolved to anoxic conditions, triggered by blooms of microbial organisms in surface waters during the earliest Cambrian. Subsequently, massive release of H 2 S derived from both anaerobic recycling of organic matter and, probably, hydrothermal venting promoted a sulfidic ocean. The discovery of a Ni-Mo sulfide ore layer in the basal Cambrian implies that such a sulfidic condition spread onto the Yangtze carbonate platform interior during the late Cambrian Stage 2. Further, transgressive flooding led to widespread black shale deposition and persistently anoxic conditions, as indicated by geochemical proxies. During the late Ediacaran to earliest Cambrian, local and widespread phosphogenesis indicates that organic matter accumulation was intimately associated with microbial (especially cyanobacterial) blooms driven by phosphorus cycling. The organic matter accumulations in early Cambrian black shales, however, were in connection with anoxic bottom water conditions and intermittent replenishment of recycled organic phosphorus to surface waters.

The Kuqa Foreland Basin (KFB) immediately south of the South Tianshan Mountains is a major hydrocarbon producing basin in west China. The Kelasu Thrust Belt in the basin is the most favorable zone for hydrocarbon accumulations. Widespread overpressures are present in both the Cretaceous and Paleogene reservoirs with pressure coefficients up to 2.1. The tectonic compression process in KFB resulted from the South Tianshan Mountains uplift is examined from the viewpoint of the overpressure generation and evolution in the Kelasu Thrust Belt. The overpressure evolution in the reservoir sandstones were reconstructed through fluid inclusion analysis combined with PVT and basin modeling. Overpressures at present day in the mudstone units in the Kelasu Thrust Belt and reservoir sandstones of the Dabei Gas Field and the Keshen zone are believed to have been generated by horizontal tectonic compression. Both disequilibrium compaction and horizontal tectonic compression are thought to contribute to the overpressure development at present day in the reservoir of the Kela-2 Gas Field with the reservoir sandstones showing anomalously high primary porosities and low densities from wireline log and core data. The overpressure evolution for the Cretaceous reservoir sandstone in the Kelasu Thrust Belt evolved through four stages: a normal hydrostatic pressure (>12–5 Ma), a rapidly increasing overpressure (∼5–3 Ma), an overpressure release (∼3–1.64 Ma) and overpressure preservation (∼1.64–0 Ma). Overpressure developed in the second stage (∼5–3 Ma) was generated by disequilibrium compaction as tectonic compression due to the uplift of the Tianshan Mountains acted at the northern monocline of KFB from 5 Ma to 3 Ma, which provided abundant sediments for the KFB and caused the anomalously high sedimentation rate during the N2k deposition. From 3 Ma to 1.64 Ma, the action of tectonic compression extended from the northern monocline to the Kelasu Thrust Belt and returned to the northern monocline of KFB from 1.64 Ma to present day. Therefore, the horizontal tectonic compression was the dominant overpressure mechanism for the overpressure generation in the third stage (∼3–1.64 Ma) and overpressure caused by disequilibrium compaction from 5 Ma to 3 Ma was only preserved in the Kela-2 Gas Field until present day.

Kela-2 is a giant gas field with a proven reserve of 597 tcf in the Kuqa depression, northern Tarim Basin. Widespread overpressures have been encountered in the Eocene and Cretaceous sandstone reservoirs of the field, with pressure coefficients up to 2.1 from drill-stem tests and well-log data analysis. Disequilibrium compaction associated with horizontal tectonic compression may be the dominant overpressure mechanism in the sandstone reservoirs, because the overpressured sandstone with a maximum burial depth over 6000 m (19,685 ft) displays anomalously high porosity and low density. The causes for sandstone reservoirs with anomalously high porosity in the Kela-2 gas field were studied based on an integrated investigation of sandstone reservoir characteristics, paleo oil–water contact, petroleum charge history, and overpressure evolution. Collective evidence indicates that early oil charge had retarded the porosity reduction of the reservoir sandstone and resulted in disequilibrium compaction from overburden rocks, and overpressure from disequilibrium compaction and horizontal tectonic compression at the beginning of the rapid subsidence and deposition in the Kela-2 gas field again contributed to the preservation of the reservoir porosity: (1) overpressured mudstones in the Kela-2 gas field are characteristic of normal compaction, and overpressure was generated by horizontal tectonic compression instead of disequilibrium compaction; (2) the reservoir sandstones with high porosity and permeability are associated with high paleo oil saturation, as indicated by quantitative grain fluorescence (QGF) responses and anomalous QGF on extract intensity; (3) sandstone units below the paleo oil–water contact have very low porosity and permeability; and (4) three episodes of oil and one episode of gas charge are identified in the sandstone reservoirs of the Kela-2 gas field, and the later two episodes of oil charge occurred circa 5.5–4.5 Ma, which corresponds to the beginning of the rapid tectonic subsidence and deposition in the Kuqa depression. The initially charged oil in the sandstone reservoirs was subsequently displaced by gas at circa 3–2 Ma through fault activation at the edge of the anticline trap. The overpressure evolution for the K1bs reservoir sandstone in the Kela-2 gas field indicates that the apparent overpressure development in the sandstone reservoir began at 5 Ma following the major oil charge and has been maintained to the present. Overpressure development from 5 Ma in the sandstone reservoirs of the Kela-2 gas field is believed to be the dominant cause of the porosity preservation.

In order to evaluate rare earth elements (REEs) as a potential proxy for solid bitumen classification, we employed traditional correlation approaches, such as carbon isotopes and V/(V + Ni) ratios, to infer the source rocks of Sinian–Cambrian reservoir solid bitumens in the Sichuan Basin and analyse solid bitumens for their REE compositions by inductively coupled plasma–mass spectrometry. Our data suggested that Sinian–Cambrian reservoir solid bitumens were primarily sourced from the lower Cambrian shales deposited under anoxic–euxinic conditions. REE and their associated parameters seemed to be more sensitive to classify solid bitumens than traditional correlation approaches. REE concentrations played a dominant role and fractionation degree between light and heavy REE and played a secondary role in solid bitumen classification. REE concentration and pattern in solid bitumens might be controlled by two processes, including inheritance from source rocks and water–rock interaction. The major factor controlling REE concentrations in solid bitumens was the type of organic matter of source rocks. Authigenic minerals in solid bitumens formed by water–rock interaction appeared to have little influence on REE compositions of solid bitumens because of their trace contents. Overall, REE could be used as a novel complementary approach to solid bitumen classification in complicated petroleum systems. Copyright © 2015 John Wiley & Sons, Ltd.

The use of rare earth elements (REE) for oil–source correlation has not yet been established. In order to evaluate the potential of REE as proxies for oil–source correlation, we used traditional correlation approaches, including biomarkers and trace elemental ratios (V/Ni and Ni/Co), to identify the source rock of oil sands using isolated organic extracts of mudstones and oil sands, and by analyzing the organic extracts and their corresponding whole rock material for REE compositions by inductively coupled plasma-mass spectrometry (ICP-MS). Oil–source correlations using REE were not consistent with conclusions based on biomarker data and trace element ratios. Only one pair of oil–source rock relationship was successfully established using REE. REE concentrations of crude oils could possibly be controlled by the quantities of metal complexes and functional groups that provide complexing sites for V and REE as well as secondary alteration processes (e.g., thermal alteration and biodegradation). REE patterns might be linked to the organic matter types of source rocks. Although an accurate oil–source relationship failed to be established using REE in this study, REE could potentially be a novel complementary proxy for oil–oil and/or oil–source correlations when supplemented by traditional correlation approaches, including biomarkers.

Although the exploration and development of tight gas have made great progress, the quantified study on gas migration and accumulation in sweet spots of tight gas reservoir is still limited. In this work, a computer program is developed to conveniently describe the different shape of sweet spots and the fractures in tight reservoir. Then, gas migration and accumulation processes are simulated, and the numerical simulation results are visualized and quantified. Based on the simulation results, the mechanism of gas migration and accumulation in sweet spots is revealed. The results indicate that the migration and accumulation of gas are two relatively independent processes. The gas migration process is determined by the permeability of rocks. The critical condition of gas accumulation in sweet spots is mostly determined by the capillary pressure difference between sweet spots and surrounding rock. The two migration patterns are clearly observed during the numerical simulations. When surrounding rock has seepage capacity for gas, the migration pattern tends to be piston-like displacement; when surrounding rock is impermeable for gas, the gas can only migrate into sweet spots through connected fractures. As a result, the migration pattern for this situation tends to be fingering displacement.

Marine shale gas exploration in southern China has successes and failures. Under the condition of great hydrocarbon generation material basis, shale gas wells drilled from some shale gas blocks are rich in methane, while the wells in other shale gas blocks with high nitrogen and low hydrocarbon gas, which indicates that they have different accumulation mechanisms. Therefore, the study of gas composition in shale will help us to figure out the mechanism of shale gas accumulation and loss. In this paper, the Lower Cambrian shale from Wei-201 well in Upper Yangtze Weiyuan Block and Jiangye-1 well from Lower Yangtze Xiuwu Basin are selected as research object, and shale samples are used for tests and experiments including analysis of gas composition and nitrogen isotope, test of porosity and TOC content, overburden permeability test, permeability test before and after methane adsorption under different osmotic pressure, permeability test parallel and vertical to the bedding surface, FIB-SEM (Focus Ion Beam Scanning Electron Microscope) and FIB-HIM (Focused Ion Beam Helium Ion Microscope). Finally, the reasons for the difference in the gas components of the Lower Cambrian shale gas in Weiyuan Block and Xiuwu Basin are studied by means of seismic interpretation, core description and outcrop observation besides the tests and experiments. The results show that the gas components of the Lower Cambrian shale in Weiyuan Block, the Upper Yangtze, mainly consist of methane, derived from liquid hydrocarbon cracking. The sealing capacity of roof and floor, the great self-sealing of shale and the flat anticline structure contribute to the high methane content in shale gas. The Lower Cambrian shale gas in Xiuwu Basin, the Lower Yangtze, is mostly nitrogen, which is derived both from atmosphere and deep crust-upper mantle. The detachment layer at the bottom of the Lower Cambrian, the widely developed deep faults and the Jurassic volcanic activity are the reasons for the high nitrogen and low hydrocarbon of shale gas. Based on the above analysis, the patterns are summarized for shale gas accumulation in the simple anticline background and reservoir destruction in the complex syncline background.

As a result of complex tectonic background, shale gas in China exhibits differential enrichment. Choosing a favorable exploration target accurately is a crucial problem to be solved. In this study, the tests show that there is a superior transportation pathway within shale layer. Gas in the shale layer percolates much more in the direction parallel to the plane. Therefore, the accumulation pattern of shale gas indicates a complex tectonic background. Gas in the lower part of the structure diffuses and percolates in the vertical direction into the surrounding rock. Most gas percolates towards the high part of the structure in the direction parallel to the plane. When the shale was exposed, gas percolated along the parallel direction into the air. In the case of fracture development, if there is a reverse fault, gas would be enriched in the footwall. However, if there is an unsealed fault, it would become a pathway for gas migration. The above accumulation pattern was proved in several Areas. Also, this research presented a basis of evaluation units division. According to the buried depth, fractures, and structural position, Xiuwu Basin was divided into five evaluation units and Unit A3 is the most favorable exploration target.

As petroleum exploration advances and as most of the oil–gas reservoirs in shallow layers have been explored, petroleum exploration starts to move toward deep basins, which has become an inevitable choice. In this paper, the petroleum geology features and research progress on oil–gas reservoirs in deep petroliferous basins across the world are characterized by using the latest results of worldwide deep petroleum exploration. Research has demonstrated that the deep petroleum shows ten major geological features. (1) While oil–gas reservoirs have been discovered in many different types of deep petroliferous basins, most have been discovered in low heat flux deep basins. (2) Many types of petroliferous traps are developed in deep basins, and tight oil–gas reservoirs in deep basin traps are arousing increasing attention. (3) Deep petroleum normally has more natural gas than liquid oil, and the natural gas ratio increases with the burial depth. (4) The residual organic matter in deep source rocks reduces but the hydrocarbon expulsion rate and efficiency increase with the burial depth. (5) There are many types of rocks in deep hydrocarbon reservoirs, and most are clastic rocks and carbonates. (6) The age of deep hydrocarbon reservoirs is widely different, but those recently discovered are predominantly Paleogene and Upper Paleozoic. (7) The porosity and permeability of deep hydrocarbon reservoirs differ widely, but they vary in a regular way with lithology and burial depth. (8) The temperatures of deep oil–gas reservoirs are widely different, but they typically vary with the burial depth and basin geothermal gradient. (9) The pressures of deep oil–gas reservoirs differ significantly, but they typically vary with burial depth, genesis, and evolution period. (10) Deep oil–gas reservoirs may exist with or without a cap, and those without a cap are typically of unconventional genesis. Over the past decade, six major steps have been made in the understanding of deep hydrocarbon reservoir formation. (1) Deep petroleum in petroliferous basins has multiple sources and many different genetic mechanisms. (2) There are high-porosity, high-permeability reservoirs in deep basins, the formation of which is associated with tectonic events and subsurface fluid movement. (3) Capillary pressure differences inside and outside the target reservoir are the principal driving force of hydrocarbon enrichment in deep basins. (4) There are three dynamic boundaries for deep oil–gas reservoirs; a buoyancy-controlled threshold, hydrocarbon accumulation limits, and the upper limit of hydrocarbon generation. (5) The formation and distribution of deep hydrocarbon reservoirs are controlled by free, limited, and bound fluid dynamic fields. And (6) tight conventional, tight deep, tight superimposed, and related reconstructed hydrocarbon reservoirs formed in deep-limited fluid dynamic fields have great resource potential and vast scope for exploration. Compared with middle–shallow strata, the petroleum geology and accumulation in deep basins are more complex, which overlap the feature of basin evolution in different stages. We recommend that further study should pay more attention to four aspects: (1) identification of deep petroleum sources and evaluation of their relative contributions; (2) preservation conditions and genetic mechanisms of deep high-quality reservoirs with high permeability and high porosity; (3) facies feature and transformation of deep petroleum and their potential distribution; and (4) economic feasibility evaluation of deep tight petroleum exploration and development.