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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.

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.

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.

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.

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.

The Kela-2 gas field is located in the center of Kelasu structural belt in Kuqa Depression. This trap is one of a series of traps in the folded belts which are distributed in a string of pearls in the dual structure. The primary gas-bearing layers are sandstone of Lower Cretaceous K1bs while the secondary layers are dolomite member and glutenite member of Lower Tertiary E1–2km and sandstone of Lower Cretaceous K1b. The main component of natural gas is methane whose content is higher than 97%. It is characterized by dry gas whose source rock is Jurassic coal measure. The Kela-2 structural trap was formed during the Xiyu period and then became a reservoir in the late time. The reservoir formed late and the thick seal rock of Lower Tertiary gipsmantle are the avail reason why the giant Kela-2 gas field has been well kept. The abnormal high pressure of the Kela-2 gas field results from the strong structural compression in the northern part during the Xiyu period.

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).

In western-central China, oil and gas exploration in the foreland fold and thrust belts experienced five exploration episodes. Before 1949, the preliminary surface investigation was the first episode of Chinese petroleum exploration. From the 1950s – 1960s, the exploration stepped forward to the initial reorganization episode and the basic advances in techniques episode. From the middle of the 1960s to the middle of the 1980s, the exploration was in recess. Since the middle of the 1980s, the exploration has progressed into a fully operational mode. Because of the complexity of mountains and ranges, seismic data were hard to obtain and seismic images were poor. Also, the complication of structural deformation inserted additional difficulties to seismic data processing and data interpretation. Furthermore, abnormally high pressure underground brought a higher drilling risk. Therefore, the high risk of exploration, the complexity of the topography and the complication of the geological conditions determined that, in the foreland fold and thrust belts, oil and gas exploration is an intricate process. Recent exploration results reveal that foreland basins contain large scale oil and gas reservoirs that have sufficient reserves and a higher production rate per single well. For example, the Kela 2 gas field in the Kuche depression contains an explored natural gas field of 48.1 km2, an explored natural gas reserve of 2,840.29×108 m3, and a reserve abundance of 59×108 m3/km2.