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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.

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.

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

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.

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.

As proved by the analysis of growth strata and regional study, the intense tectonism of the Cenozoic in the northern margin of Tianshan Orogenic Belt initiated at about 10–7 Ma BP and associated with intense tectonic deformation, led to the formation of three thrust belts at the northern margin of Tianshan Orogenic Belt. The time of intense deformation is much younger than that of the southern Tianshan, which suggests that the tectonic deformation propagated from the southern Tianshan to the northern Tianshan due to the India-Asia collision. The intense deformation of the Late Cenozoic resulted in relatively gentle deformation in the western Uromuqi-Qigu anticline and widespread tectonic deformation transporting and retrogressing from the south to the north. The differential tectonic deformation indicates that the front of thrust belt is beneficial to hydrocarbon accumulating. Moreover, for the intense denudation and uplifting along the structure belt of foreland, structures with gentle deformation are advantageous to the preservation of oil and gas accumulating during the early phase.

Since the 1950’s, along with the discoveries of the Daqing oil field and exploration in the Bohai bay area, terrestrial petroleum geology exploration has been gradually developed. The theory of oil generation in a terrestrial basin and multiple oil-gas accumulation zones is the core of terrestrial petroleum geology. This new hypothesis not only improved the theory of petroleum geology, but it also effectively directed oil and gas exploration in the Chinese terrigenous basin. In addition, numerous structural types of oil and gas reservoirs were discovered, more than a dozen oil and gas production bases were developed, which include Daqing, Bohai bay, Changqing and Xinjiang, and which effectively supported the construction and development of the Chinese national economy.

The development of a petroleum accumulative zone required the collaboration of a series of geological conditions, which included the source of the oil and gas, the migrating passage, conditions of the trap, conditions of the reservoir and conditions of the cap rock. According to the relationship between a lithostratigraphic petroleum system, geo-zone and traps, this chapter proposes a geo-zone concept of the structure sequences of the petroleum play and the principles of classification. The development of a lithostratigraphic reservoir was controlled by the following four factors that were the type of basin, growth structure, sequence and facies, and source rock and injection mechanism.

In petroleum basins around the world, strong volcanism not only controlled geo-dynamic and tectonic evolution at a deep level, but it also influenced deposition and accumulation in the basin during the late period. Using research works and statistical study of volcanic rocks in rifted basins that are related to the continental margin around the world, Plank (2003) believed that all of the rift basins experienced strong volcanism if they are related to the continental margin. Among these rifted basins, many of them have become important targets for petroleum exploration. At present, the study results and exploration practices indicate that volcanic rocks could function as excellent reservoir sequences. Large size volcanic petroleum reservoirs have been discovered in many countries around world, for example the Jatibarang basaltic oil and gas field in Indonesia (which has oil reserves of 1.65×108t and natural gas reserves of 764×108m3); the Scott Reef basaltic oil and gas field in Australia (which has oil reserves of 1,795×104t and natural gas reserves of 3,877×108m3); the Kudu basaltic natural gas field in Namibia (which has natural gas reserves of 849×108m3); the Cenozoic volcanic oil and gas reservoir in Japan; the Muradkhanli oil and gas reservoir in trachybasalt and andesite in Azerbaijan. Because these volcanic oil and gas fields have thick production layers, a high production rate and huge petroleum reserves, they have become important exploration targets (Petford and McCaffrey, 2003; Zhao, 2008; Zhou, 2008).

The Chinese petroleum industry is famous for producing oil and gas from terrigenous sedimentary basins. As a result, geological studies of the terrigenous petroleum basin and the use of related technologies for petroleum exploration and development are at an advanced stage in the world. If the idea that terrigenous stratigraphy can generate oil is the central idea behind the geological theory, then the characteristics of reservoir sequences in the terrigenous basins are the significant foundation of this geological theory. This chapter will discuss the distribution of the stratigraphy, the major types of depositional facies and the characteristics of the petroleum system in the Chinese petroleum basins. In addition, the nature of the depositional evolution in the major petroleum basins will be briefly introduced.

When comparing four prototype basins, they not only have different tectonic and depositional backgrounds, but they also have different petroleum accumulative (elements) conditions. Therefore, these prototype basins contain noticeable distinctions in their correlations of accumulative elements and in their accumulative processes; in addition, they also display their own accumulative features and patterns. In the rifted basin, because the petroleum rich depression contains high quality hydrocarbon source rock of large thickness and broad distribution, it thus has the characteristics of a “petroliferous rich depression”. In the depressed basin, the lithostratigraphic traps were not only favorably developed on the delta front, but they also perfectly correlated with the hydrocarbon source rock that was located in the central area of the lake, which displays the characteristics of accumulating oil on the delta front. In the foreland basin, the development of a lithostratigraphic reservoir in the foreland thrust belt was controlled by faults and fans; this characteristic is represented by the northwestern margin in the Zhungeer basin. In the marine craton basin, oil and gas accumulations were controlled by the reef flat on the platform margin and other high energy facies. Understanding these characteristics and patterns will benefit oil and gas exploration in the future.

Petroleum reservoirs and traps were carriers and storage for oil and gas migration and accumulation. However, it depended on the passage that linked the source rock and the trap as to whether hydrocarbons would accumulate. Different combinations of “source rock and trap” not only influenced the difficulty and the probability of petroleum accumulation, but also revealed clear distinctions in the petroleum injective mechanism, accumulative features and major controlling factors. Considering that the hydrocarbon source rock was the material foundation for petroleum accumulation, the traps (which were located either above source rock or beneath source rock) exhibited various dynamic features distinctively. Thus, according to the vertical relationship between source rocks and traps, this section will classify different types of petroleum play and will further discuss their mechanism and major controlling factors.

In the 21st century, PetroChina has advanced the geological theory behind the lithostratigraphic petroleum reservoir and has improved exploration technology, which motivated exploration practice for lithostratigraphic petroleum reservoirs in China with positive results (Jia, 2003; Jia et al., 2005). Recently, a series of important exploration breakthroughs have been achieved in the Erlian basin, Songliao basin, Eerduosi basin, Bohai bay, Zhungeer basin and Tarim basin. Many large size lithostratigraphic petroleum reservoirs with a hundred million tons of reserves and several medium size lithostratigraphic petroleum reservoirs with 5,000×104 t of reserves were discovered in successive order. In the following we will discuss four exploration examples.

The term deeply buried oil and gas reservoir was designated for particular oil and gas reservoirs that have a buried depth deeper than 4,000 m. From a geological point of view, this depth is equivalent to the special depth where liquid hydrocarbon was transformed into gaseous hydrocarbon. In general, geologists consider that, in a basin, the deeply buried oil and gas reservoirs identify a petroleum reservoir in the new strata that is positioned beneath the existing productive oil and gas layers. More than 30 years of worldwide in-depth exploration practices confirm that there are plentiful of oil and gas reservoirs in the deep positions of basins. In-depth petroleum exploration not only is an important method for increasing the production rate for an old oil field, but it is also a valuable exploration domain for increasing the production rate in a new oil field (Gan et al., 1988; Guo et al., 1996). Preliminary estimations show that the reserves of deeply buried oil and gas are equal to 28% of the total oil and gas reserves in China. In China, large scale petroleum basins have the preconditions in a deep position to form oil and gas reservoirs. Several deeply buried oil and gas reservoirs have been discovered. Emphasizing oil and gas exploration in deeply buried strata has extraordinary significance for Chinese petroleum exploration.