Oil and gas is the most important primary fossil energy in the world. Human society strongly relies on oil and gas to survive and develop. The survival and development of petroleum industry is determined by four factors: resources, market, technology, and social-political-economic environment. Among them, oil and gas resources are the foundation, while technological progress is the most active and critical factor. The development of petroleum industry is closely related to the progress of petroleum science and technology.

In recent years, significant changes have taken place in the field of upstream resources as well as theoretical and technological research in the petroleum industry. Major breakthroughs and rapid development have been made in unconventional, deep-water and deep/ultra-deep hydrocarbon exploration and development, which enhanced the upstream business of the petroleum industry to enter new fields and resulted in great progress in the geological theory and technical equipment. In particular, due to the successful development of unconventional hydrocarbon, the global oil and gas resources have increased significantly, the R & D of horizontal wells and volume fracturing technology and equipment for unconventional hydrocarbon exploitation has made rapid progress, and the production has increased rapidly; At the same time, a large number of new data revealed in unconventional hydrocarbon exploration have helped to make a major breakthrough in classical petroleum geology and been promoting revolutionary progress of this theory.

According to the definition of unconventional hydrocarbon officially issued by SPE, AAPG, SPEE and WPC in 2007, it refers to the continuous oil and gas resources, including heavy oil and oil sand, tight oil and gas, shale oil and gas, coalbed methane, shale oil and gas, natural gas hydrate and oil shale, etc. which are distributed continuously in a large area and cannot obtain natural industrial production capacity by traditional technology and can only be economically exploited by improving reservoir permeability or fluidity with the help of new technology^[1]. In the past decade, the role and position of unconventional hydrocarbon have become more important in global oil and gas production. Following the effective scale development of oil sands, tight gas and coalbed methane, the "unconventional hydrocarbon revolution" in the United States has witnessed rapid growth in tight reservoir production in recent years, which has propelled the unconventional hydrocarbon development into a brand new stage^{[2⇓⇓⇓-6]}.

Exploration and development and new global hydrocarbon resource assessment confirm that there are rich unconventional hydrocarbon resources all over the world. According to the estimation of International Energy Agency (IEA), the recoverable oil resources in the world are 9560×10⁸ t, including 4210×10⁸ t of unconventional oil; The recoverable resources of natural gas in the world are 783.8×10¹² m³, including 195×10¹² m³unconventional natural gas^[7]. According to the estimation of IEA, the global unconventional gas production will increase to 2.5×10¹² m³ in 2040, accounting for 42% of the total natural gas production; Among them, 1.7×10¹² m³ is shale gas, 0.46×10¹² m³ is tight gas^[7], and the global unconventional oil production will increase to over 10×10⁸ t, accounting for about 20% of the total crude oil production; The output of tight oil and shale oil is 5.1×10⁸ t, oil sand production 3.4×10⁸ t^[7]. Abundant resources and advanced technology will support the long-term and stable production of oil and gas industry and make great contributions to mankind.

The rapid development of unconventional hydrocarbon exploration and development reveals a large number of new data and information of petroleum geology, which also promotes a large number of scientific research activities for unconventional petroleum geology. These new discoveries reflect that unconventional reservoirs are different from conventional reservoirs in the characteristics, enrichment rules, accumulation mode and mechanism, and development mechanism of hydrocarbons. A major breakthrough has been made in the classical petroleum geology, resulting in a new field of unconventional petroleum geology research, and pushing the development of petroleum geology into a new stage.

Geology of petroleum is an applied basic discipline to study the origin, accumulation principle and distribution law of oil and gas, and is the theoretical basis of oil and gas exploration and development^{[8⇓⇓⇓⇓-13]}. The core content of classical petroleum geology can be summarized into the following four aspects, among which the most important are the petroleum system theory and trap theory.

(1) Theory of basin analysis, organic generation mechanisms and petroleum system. Sedimentary basin, sedimentation temperature increasing and pressure increasing is the geodynamic background of hydrocarbon generation and accumulation. Organic matter (kerogen) is the main source of oil and gas. Petroleum system includes oil and gas generation, migration, accumulation, adjustment, accumulation and accumulation. The whole dynamic process of transformation and destruction is related to the temperature and pressure environment of fluid and the interaction.

(2) Theory of oil and gas reservoirs composed of rock skeleton, effective pore and movable fluid. Oil and gas reservoir is composed of rock skeleton, effective pore and filled movable fluid. Reservoir physical properties are described by porosity and permeability. Permeability is affected by pore structure, fluid phase and surface affinity. Formation pressure refers to the movable fluid pressure, which is the most important geological characteristic and productivity index of oil and gas reservoirs. The in-situ stress field is mainly borne by the rock skeleton.

(3) Theory of the distribution of petroliferous basin, play, trap and oil and gas reservoirs. Oil and gas and petroleum system exist in a petroliferous sedimentary basin. Play (or reservoir forming combination) refers to a group of traps and oil and gas reservoirs with similar reservoir characteristics and spatial correlation, which reveals the basic law of spatial distribution of oil and gas reservoirs. Trap is the place of oil and gas accumulation with reservoir and sealing conditions. Oil and gas reservoir (pool) is the basic unit of oil and gas distribution, with unified reservoir rock mass, unified pressure system and unified oil, gas and water boundary.

(4) The conservation law of energy and matter in reservoirs, and theory of reservoir reconstruction and oil and gas exploitation. Fluid volume and energy change of oil and gas reservoir follow the principle of conservation of energy and matter. The basic principle of oil and gas development is to form fluid pressure difference in different parts of oil and gas reservoir by manual intervention, so as to produce and control fluid flow. Reservoir permeability, fluid properties and artificial intervention effect are the main factors that affect the development efficiency.

In 1885, I. C. White published “The Geology of Natural Gas” in the “Science” magazine, which systematically expounded the anticline reservoir theory for the first time and successfully applied it to exploration well location deployment^[14]. McCollough formally put forward the “Trap Theory” in 1934. He believed three conditions must be present for a trap to form: reservoir, cap rock and shelter conditions, with unified oil, gas and water interface, and reserves should be calculated strictly according to trap area, closure and porosity^[9]. In 1956, A. I. Levorsen established a relatively perfect trap classification system in his book Geology of Petroleum, dividing traps into structural, stratigraphic and combination traps^[10]. Trap theory points out that reservoir, cap rock and shelter condition are the necessary conditions for the formation of oil and gas reservoir, anticline is the simplest special case, and oil and gas accumulation in trap is the theoretical core of conventional oil and gas accumulation.

Why can traps preserve oil and gas? What is the formation and preservation mechanism of conventional reservoirs? Because the fluid in the oil-gas trap presents the differentiation law of oil-water layer according to the density, and the caprock and shelter are the sealing conditions of the upward direction of oil-gas migration, it shows that buoyancy is the basic power of oil-gas migration and accumulation. The problem of how oil and gas are enriched in underground tight strata has been explored for a long time, until the theory of buoyancy accumulation was put forward in 1885. According to the classical petroleum geology, the multi-component and multi-phase hydrocarbon bearing mixed fluid produced by the deep source rock is discharged from the source rock (primary migration) under the effect of hydrocarbon generation pressure and capillary force difference, and then migrates from the deep part of the basin to the shallow part and from the center of the basin to the edge of the basin under the guidance of buoyancy. Finally, it accumulates in all kinds of traps in the middle and shallow layers (secondary migration), and when the scale exceeds a certain critical condition, it forms a commercial oil and gas resource.

The mechanism of buoyancy accumulation and the model of trap controlling gave the hydrocarbon exploration a clear direction and goal. Instead of relying on superstition and experience, the hydrocarbon exploration embarked on rapid development in a scientific way. The theory of buoyancy accumulation and trap reveal that the oil and gas accumulation dominated by buoyancy is controlled by six factors, namely source, reservoir, cap, transportation, trap and preservation. The theory of source controlling oil and gas and the theory of petroleum system were put forward one after another, which constituted the theoretical basis of petroleum geology and successfully guided the exploration and development of conventional oil and gas in the world in recent 100 years. Currently, all kinds of conventional oil and gas reserves discovered in the world amounts to 9016 × 10⁸ t, accounting for more than 95% of the total proven oil and gas reserves in the world^[15].

Since the 1980s, oil and gas reservoirs with completely different geological characteristics and distribution characteristics from conventional oil and gas reservoirs were gradually detected in the exploration forbidden areas in the center of the basin, which were once considered impossible to form oil and gas reservoirs. In recent years, with the successful development of unconventional hydrocarbons such as shale oil and gas and oil sand in North America, the production of unconventional hydrocarbons has increased rapidly. Unconventional hydrocarbons have become one of the main alternative resources of the petroleum industry in the future, and have been attached great importance by the petroleum geological circles. Many scholars and institutions focus on unconventional hydrocarbons geology and have made great progress. Schmoker^[16] and Gautier^[17] of USGS put forward the concept of “continuous hydrocarbon reservoirs”, which refers to the oil and gas reservoirs with large spatial distribution and lack of obvious oil and gas/ underwater dip contact interface. The unconventional natural gas resources such as tight sandstone gas and shale gas are evaluated. Law et al.^[18] put forward the concept of unconventional hydrocarbons system; Loucks and Reed^[19] characterized the micro pore-throat characteristics of organic matters in Barnett shale reservoirs by field emission scanning electron microscopy. In 2007, SPE, SPEE, AAPG and WPC defined the concepts related to unconventional hydrocarbons resources in oil and gas resource management system^[1]. A group of Chinese scholars introduced and absorbed foreign research advances on unconventional petroleum geology, and achieved a series of important research achievements at the frontier of international disciplines.

Exploration and geological research have summarized the basic geological characteristics of unconventional oil and gas reservoirs: unconventional oil and gas continuous accumulation, large area distribution, no obvious oil, gas and water closed boundary; The reservoir is compact (porosity is 4%-12%, permeability is less than 1×10^-3 μm²). The micro and nano pore-throat system is developed, which needs horizontal well and fracturing technology to produce, so it is an “artificial reservoir”. Various phases (solid, liquid, gas, free and adsorbed) coexist. Both “near source” and “within source” can form reservoirs, with integrated source and reservoir, oil and gas controlled by strata, stable distribution and large resource scale. The migration and accumulation mechanism and distribution pattern are completely different from that of conventional oil and gas (Fig. 1).

Unconventional hydrocarbons broke many cognitive limitations in traditional oil and gas geology, including significant impact on the traditional petroleum system theory, which is mainly reflected in five aspects: (1) Continuous oil and gas accumulation theory, layered reservoir can store oil and gas, large area continuous distribution, sweet spots enrichment, breaking the traditional concept of trap accumulation and play enrichment. (2) Nano-scale pore-throat system was found in tight reservoirs, which broke the traditional lower limit of reservoir physical properties and found new types of unconventional hydrocarbon reservoirs such as tight sandstone and shale. (3) Unconventional oil, gas and resources are integrated together without cap rock plugging, which overturned the traditional concept of combination of source reservoir and cap rock. (4) Unconventional hydrocarbon accumulation is not dominated by buoyancy, but under the influence of non-buoyancy^[20-21], which broke the theoretical model of generation, migration and accumulation of petroleum system^[5,12,22]. (5) Unconventional hydrocarbon distribution is mainly controlled by the source rock series of the prototype basin, most of which are in the slope and center of the basin, which broke the traditional experience of oil and gas enrichment in high parts of the basin^{[5,12,20 -21]}. Among them, the core theory of oil and gas geology, that is, the generation, migration, enrichment and preservation mechanism of oil and gas, has been greatly challenged. At present, the frontier of theoretical development is mainly the formation of theory of new unconventional hydrocarbon accumulation mechanisms and petroleum system.

Unconventional hydrocarbon theory research has a great strategic impact on the innovation of petroleum geology and the development of the world's oil industry, especially on the formation of a major breakthrough in the classical petroleum geology theory, which has great scientific significance. However, we are soberly aware that the research results of unconventional petroleum geology mainly focus on the description of oil and gas reservoirs, the summary of enrichment and high-yield laws, regional sedimentary structural background, etc., and the theory of unconventional hydrocarbon accumulation needs to be further deepened.

This paper conducts a systematic investigation on the accumulation mode and mechanisms of unconventional hydrocarbons, and explores the theory of forming a new petroleum system. Technically, this research is to study the formation mechanism and distribution pattern of unconventional hydrocarbon reservoirs based on the investigation of the differences in the characteristics of conventional and unconventional hydrocarbon reservoirs found in the world; Secondly, this paper analyzes the differences in the formation process of conventional and unconventional reservoirs in representative hydrocarbon bearing basins in China, classifies unconventional reservoirs, and expounds the dynamic characteristics, occurrence characteristics and genetic mechanism of different types of unconventional reservoirs; Finally, the formation conditions, main controlling factors and boundary thresholds of each type of unconventional oil and gas resources are defined, and the distribution model is established based on the analysis result of examples. The research focuses on three aspects:

(1) This paper studies the influence of oil and gas component characteristics on oil and gas migration dynamics, analyzes the difference between oil and gas migration forces and resistance under different density conditions, determines the boundary threshold of accumulation, focuses on the dynamic mechanism and distribution law of solid bitumen and heavy oil accumulation, and clarifies the correlation and difference between unconventional and conventional hydrocarbon reservoirs.

(2) This paper studies the influence of reservoir medium conditions on hydrocarbon migration dynamics, analyzes the different hydrocarbon migration forces and resistances under different porosity and permeability and different lithologic medium conditions, determines the boundary threshold of reservoir formation, focuses on the dynamic mechanism and distribution law of tight reservoir, shale reservoir and coalbed gas reservoir formation, and clarifies the correlation and difference between unconventional and conventional reservoirs.

(3) The effects of temperature, pressure and redox environment on the migration dynamics of oil and gas are studied, the differences of migration forces and resistance of oil and gas under different temperature and pressure conditions are analyzed, the boundary threshold of hydrocarbon accumulation is determined, the dynamic mechanism and distribution law of gas hydrate accumulation are mainly studied, and the correlation and difference between them and conventional reservoirs are clarified.

From the above three aspects, this paper studies the formation conditions of conventional and unconventional reservoirs, analyzes the differences of their dynamic mechanisms, summarizes the basic models, and then explores the basic mechanism of their formation, forming new concepts and theories. Based on the analysis, in the author's point of view, there are two main problems in the frontier of unconventional hydrocarbon accumulation theory, namely unconventional hydrocarbon accumulation mechanism and new whole oil and gas system theory: (1) Unconventional hydrocarbon accumulation mechanisms: conventional hydrocarbon reservoirs and unconventional hydrocarbon reservoirs are very different in nature and occurrence characteristics. It is generally agreed that the accumulation mechanism is different. Conventional hydrocarbon reservoirs are formed by buoyancy, unconventional hydrocarbon reservoirs are formed by non-buoyancy, so what is non-buoyancy? What is the essence of its physicochemical force? What is its micro dynamic mechanism? There are many kinds of unconventional hydrocarbon, and there are great differences between the geological conditions and the phase behavior of oil and gas. Do they share a common mechanism of accumulation? And what is this mechanism?

Many scholars have studied the unconventional hydrocarbon accumulation mechanisms from different perspectives, and have put forward different reservoir formation models, including: genetic model of relative permeability change of reservoir^[28], genetic model of diagenesis change^[29], genetic model of capillary force plugging^[30], genetic model of lateral sealing of fault to hydrocarbon^[31], the formation model of unconventional hydrocarbon reservoir in deep abnormal high pressure fluid^[32], and the genetic model of unconventional hydrocarbon reservoir in different stages^[33]. It is worth noting that the remarkable progress in the theoretical research of unconventional hydrocarbon accumulation is the proposal of the concept of lower limit of buoyancy accumulation by Pang Xiongqi et al.^[34], which has been tested in exploration practice. This concept clearly describes the difference and relationship between conventional hydrocarbon reservoirs and tight continuous hydrocarbon reservoirs. Conventional hydrocarbon reservoirs are formed in high porosity and permeability media above the lower limit of buoyancy accumulation, and it is characterized by “four highs” and “separation of source and reservoir”. Unconventional tight hydrocarbon reservoirs are formed and distributed in low porosity and low permeability media below the lower limit of buoyancy accumulation, with the characteristics of “four lows” and “adjacent source reservoir” (Fig. 2). The concept of lower limit of buoyancy accumulation and the establishment of reservoir control model are the important progress of unconventional hydrocarbon accumulation model research. Song Yan et al. discovered and summarized the accumulation and enrichment mechanism of tight oil in the central and Western China^[35].

In the exploration and development and scientific research, we found that unconventional hydrocarbon reservoirs are characterized with the “self-sealing effect”, which means that, they are enriched and preserved in the reservoir, and do not need to be sealed by the cap rock or the trap. The hydrocarbon reservoirs can be preserved for a long time only by themselves, and we found that the reason of hydrocarbon self-sealing effect is the intermolecular force of oil and gas. Oil and gas molecules are affected by many forces under geological conditions, including buoyancy (gravity), intermolecular force, geo-stress, electromagnetic force, etc. Buoyancy (gravity) is the determining force in conventional reservoirs and intermolecular force is the decisive force in unconventional reservoirs. Due to the different physical and chemical characteristics of oil and gas, special reservoir medium conditions and special temperature and pressure environment, intermolecular forces have various forms, and self-sealing effect also have various types. The mechanism of unconventional hydrocarbon accumulation is the self-sealing effect of intermolecular forces.

(2) The whole hydrocarbon system theory: hydrocarbon system theory is an important part of conventional hydrocarbon geology, which scientifically summarizes the laws of generation, migration and accumulation of conventional hydrocarbons in petroliferous basins. As is stated by Jia et al., after the large-scale discovery of unconventional hydrocarbons, petroleum exploration practice has proved that there are significant defects in the conventional hydrocarbon system theory, so it is necessary to develop a new whole petroleum system theory, which will comprehensively describe all the hydrocarbon resources in the petroliferous basin, including the generation, migration, migration of conventional and unconventional hydrocarbons, and the accumulation, preservation, enrichment and distribution laws that unify the conventional and emerging unconventional petroleum geology^[36-37]. He put forward the “The Accumulation Rule of Conventional and Unconventional oil and gas Sequence in the Whole Hydrocarbon System” for the Permian in Junggar Basin (Fig. 3). He also summarized the three sequence accumulation models of Permian oil and gas system in Junggar Basin, Yanchang Formation hydrocarbon system in Ordos Basin and Cretaceous oil and gas system in Songliao Basin of China. Pang Xiongqi et al. discovered not only the lower limit of buoyancy accumulation, but also the bottom limit of hydrocarbon accumulation and the bottom limit of hydrocarbon supply from source rocks^[38]. According to these three dynamic boundaries, the petroliferous basin is divided into three different dynamic fields, revealing the correlation between the three dynamic fields and three types of oil and gas resources. A unified genetic model of conventional and unconventional reservoirs has been established^[34].

The term “self-sealing” was first put forward by Facca and Tonani in 1967 in their paper “The Self-sealing Geothermal Field” published in periodical Bulletin Volcanologique^[39], referring to a type of geological effect as a result of better self-sealing of cap rock against heat dissipation due to the sedimentation of silicon and consequently protected the formation of hot dry rock reservoir in the process of heat dissipation on top of the hot dry rock reservoir. The concept of “self-sealing” was then compiled by China National Committee for Terms in Sciences and Technologies in the book Geology Terminologypublished in 1993 by Science Press. Now, the term “self-sealing” is generally used by experts and scholars in different fields to refer to the geological process of rock mass recrystallization and cementation under the joint action of formation temperature and pressure change and underground fluid, and finally sealing or plugging the fluid in the reservoir rock under the cap rock. It makes the underground fluid lose contact with the out-side of the cap rock and form a relatively independent fluid unit or reservoir forming unit. This concept is used by petroleum geology experts to refer to the phenomenon that, when oil and gas pass through the upper cap, secondary minerals are formed or clay minerals are transformed to block the micro leakage pores and improve the sealing ability of the cap rock^[40], and the sedimentation inside the cap rock helped to strengthen the efficiency of cap rock^[41]. Based on this concept, some scholars study the self-sealing effect of karst, and call the area with relatively good karst development and sealing as self-sealing reservoir forming area, while the area with poor karst development as karst self-sealing rock barrier area^[42]. Obviously, this “self-sealing” effect is due to the cap rock like blocking capacity formed by the relatively tight part in the outskirt of target rock compared to the high porosity part. In this paper, the concept “self-sealing” is used to characterize all unconventional hydrocarbon self-sealing accumulation, which is defined as unconventional hydrocarbon in the sedimentary basin due to its own special physical and chemical characteristics or under the joint action of special reservoir medium conditions and special temperature and pressure environment, depending on the intermolecular forces within the hydrocarbon itself or between the hydrocarbon and the reservoir medium interface, independent of the up-dip sealing conditions such as traps outside the reservoir, it is isolated from the outside world and independent of accumulation and preservation. This is a new concept of “self-sealing effect”. Self-sealing formation of unconventional hydrocarbon reservoir usually has three geological characteristics: (1) The self-sealing effect of unconventional hydrocarbon is caused by the intermolecular forces inside the hydrocarbon or between the hydrocarbon and the surrounding medium, and because the migration resistance of hydrocarbon is far greater than the buoyancy, the accumulation is mostly non-buoyancy dominated. (2) The self-sealing effect of unconventional hydrocarbon occurs inside the unconventional hydrocarbon reservoir, not in the exterior or margin. (3) The self-sealing accumulation of unconventional hydrocarbon is dynamic and relative, which occurs in the process of formation and preservation of unconventional hydrocarbon reservoirs, and is destroyed or gradually disappeared when significant changes of formation conditions happen.

The intermolecular interaction force, also known as Van der Waals force, is a weak alkaline electrical attraction existing between two neutral molecules or two atoms. Van der Waals force exists widely among molecules of oil, gas and water, and between fluid and reservoir medium. There are three sources of intermolecular Van der Waals forces: (1) the interaction between the permanent dipole moments of polar molecules; (2) one polar molecule polarizes the other to produce induced dipole moments and attract each other; (3) the motion of electrons in molecules produces instantaneous dipole moment, which makes neighboring molecules instantaneous polarization, and the latter in turn enhances the instantaneous dipole moment of the original molecules. This mutual coupling produces electrostatic attraction. The contribution of these three forces is different, and the third action usually makes the largest contribution^[43].

Intermolecular forces are secondary bonds. Hydrogen bond, weak Van der Waals force, hydrophobic force, aromatic ring stacking and halogen bond are all secondary bonds, which are also called “Weak Intermolecular Interaction”. In 1873, the Dutch scientist Johannes Didric Van der Waals first proposed the concept of Van der Waals force to explain the behavior of gases. The force is so weak that it makes sense only when the atoms or molecules are very close. French scientists made a direct measurement of the Van der Waals force between two atoms in 2013. All the experimental methods were later used to build quantum logic gates or to carry out quantum simulation of condensed matter systems. The Van der Waals forces between atoms, molecules and surfaces appear in nature in various ways. Spiders and geckos, for example, rely on Van der Waals force to climb up smooth walls, and our proteins fold into complex shapes because of Van der Waals force. In geological process, intermolecular force as a kind of weak interaction exists everywhere, but it is very weak, and has not attracted people's attention. In the process of unconventional hydrocarbon accumulation, this kind of weak interaction promotes the formation of unconventional hydrocarbon, which is a huge scale of economic mineral resources, is very shocking and worthy of in-depth study.

There are many types of unconventional hydrocarbons and intermolecular forces that lead to self-sealing reservoir formation. There are also many types of corresponding intermolecular forces and self-sealing reservoir formation mechanisms. Different dynamic mechanisms form different types of unconventional hydrocarbon reservoirs. The intermolecular forces of hydrocarbons include molecular viscosity force, molecular condensation force, molecular interface force (capillary force), molecular adsorption force and molecular cage force. The first type is the formation mechanism of heavy oil and bitumen, and the intermolecular force is mainly manifested as macromolecular (molecular group) viscosity and contraction force. In the special oxidation environment, heavy oil and dry bitumen are formed by biodegradation of crude oil in the strong oxidation environment. Macromolecular heavy oil and bitumen are formed by molecular condensation. Molecular viscosity makes them closely connected, forming a relatively independent system and realizing self-sealing reservoir formation. The second type is the formation mechanism of tight oil and gas, shale oil and gas and coalbed methane, whose intermolecular forces are capillary force and adsorption force. This kind of self-sealing reservoir formation is shown in the special tight reservoir medium conditions, the pore throat of ultra-low porosity and low permeability reservoir is very small, usually the porosity is less than or equal to 12%, and the air permeability is less than or equal to 1×10^-3 μm², average throat radius is less than or equal to 1 μm. The capillary force and adsorption force of the fluid are greater than the buoyancy force, thus blocking the free outflow of its own oil and gas fluid and the free entry of external fluid, forming the self-sealing accumulation of oil and gas. It also forms a limited or bound hydrodynamic field, which is in sharp contrast to the open hydrodynamic field of free flow driven by buoyancy in conventional high porosity and high permeability reservoirs. The third type is the formation mechanism of natural gas hydrate, whose intermolecular force is the cage of water and methane. Natural gas hydrate is formed in high pressure and low temperature environment. Water molecules form hydrate through cage methane gas and transform into solid state, so as to enable self-sealing reservoir formation. All of these are fundamentally different from the open system and environment of conventional oil and gas migration and accumulation under the guidance of buoyancy.

The formation of unconventional hydrocarbon reservoirs under the special intermolecular interaction mechanism requires certain boundary conditions or geological thresholds. Only when this condition is satisfied can unconventional reservoirs be formed and distributed. The formation and distribution of different types of unconventional hydrocarbon reservoirs have different geological conditions, and the boundary conditions are also different. Bitumen requires a strong oxidation environment to form: generally, the salinity of formation water is less than 1000 mg/L and the temperature is less than 20 °C. The buried depth is less than 500 m; The formation of heavy oil requires strong oxidation environment: formation water salinity is less than 2000 mg/L, temperature is less than 30 °C. The buried depth is less than 1500 m. The formation of tight reservoirs usually requires reservoir porosity less than 12% and reservoir permeability less than 1×10^-3 μm², throat radius less than 1 μm; The formation of ultra-tight shale reservoir requires porosity less than 12% and permeability less than 0.1×10^-3 μm², throat radius less than 0.1 μm; The formation of coalbed methane reservoir requires porosity less than or equal to 5% and permeability less than or equal to 0.01×10^-3 μm², throat radius less than or equal to 0.025 μm. The formation of natural gas hydrate requires the phase equilibrium conditions of high pressure and low temperature: it is distributed in the earth's poles, marine sediments, and under the plateau ice cover, and the burial depth is less than 1200 m. Generally, the boundary conditions of different unconventional reservoir distribution are listed in Table 1.

The origin of heavy oil reservoir can be divided into primary and secondary. Primary heavy oil reservoir is generally formed by immature or low mature crude oil accumulation; Secondary heavy oil reservoir is formed by the destruction of the formed reservoir, or multiple migration over a long distance, loss of light components, water washing oxidation and biodegradation^[44]. Its genetic mechanism is that the heavy oil is difficult to flow due to molecular viscosity, resulting in the formation of “self-sealing reservoir”, which promotes the large-scale accumulation and preservation of heavy oil/heavy oil.

The term “molecular viscosity” originated from Newton's experimental study of viscous flow^[45], which used viscous force to characterize the resistance encountered in the process of fluid migration. Viscous force is a kind of interaction shear force on the contact surface when there is relative motion between adjacent flow layers due to the different velocity of each layer of fluid, also known as internal friction. It is the macroscopic expression of molecular cohesion and molecular momentum exchange of two-layer fluid (Fig. 4). The liquid is dominated by cohesive force, which depends on the intermolecular gravity^[46-47].

In 1686, the British scientist Newton discovered the law of internal friction. He pointed out that the internal friction was directly proportional to the relative velocity of the flow layer movement and the contact area between the flow layers, and the internal friction changed with the physical properties of the fluid and had nothing to do with the positive pressure. The influencing factors of viscous crude oil viscosity can be summarized into two aspects: (1) Macro influence^[48-49], including pressure, temperature, solid particles and flow rate, in which temperature and pressure mainly affect the viscosity of fluid by influencing the molecular spacing; The influence of flow velocity is mainly manifested as an irreversible momentum transferred from the place with higher velocity to the place with lower velocity; The influence of solid particles is that there are small solid particles such as wax crystals in crude oil, which can be regarded as suspended fluid. The existence of solid particles will hinder the movement of fluid. (2) The first is the influence of heteroatoms^[50]. Heavy oil contains more S, N, O and other elements. Their existence can induce permanent dipole and increase molecular polarity^[51-52]. The charge transfer, dipole interaction, hydrogen bonding^[53-54]caused by them make molecules gather and produce viscosity. The second is the influence of metal elements. Metal elements exist in the form of inorganic salts, oil soluble organic salts and metalloporphyrins in crude oil. When these substances are complexed, heteroatoms enter the skeleton structure during the formation of asphaltene, while Ni and V complexed with heteroatoms and enter the condensed aromatic ring structure of asphaltene, participating in the association of resin and asphaltene molecules, then the macromolecules further aggregate to produce viscosity.

Characteristics and distribution pattern of thick oil/ heavy oil self-sealing reservoir. In this paper, the formation and distribution of Orinoco heavy oil belt in the southern slope belt of the East Venezuela basin is taken as an example to illustrate the self-sealing accumulation model of heavy oil reservoir. It covers an area of 5.5×10⁴km² from West to East across the south of Guarico, Ansoatje and Montagas, which is the largest heavy oil reservoir in the world^[55]. The buried depth of heavy oil zone reservoir is 350-1200 m. the reservoir is mainly Oligocene and Miocene unconsolidated sandstone, with average porosity of 33.4% and average permeability of 4760×10^-3 μm². The crude oil viscosity ranges from 1000 MPa·s to 6000 MPa·s, and the proved original geological reserves are 1570.8×10⁸ t, recoverable reserves 364×10⁸ t^[56-57]. The heavy oil belt is distributed in the highest edge of the southern slope belt of the basin. After a long-distance lateral migration of tens of kilometers, the oil and gas from the northern part of the basin are largely filled into the unconsolidated sandstone of Upper Cretaceous to Miocene fluvial delta facies at the edge of the basin. In the southern margin, bitumen plug is formed due to the loss of light components, biodegradation, water washing and oxidation, which is combined with the mudstone in the layer and the overlying regional mudstone cap rock to form a large-scale structural lithologic heavy oil reservoir, with an oil-bearing area of more than 5×10⁴km^2[58].

Bitumen is the main product of molecular condensation of underground crude oil. It is a hydrogen rich macromolecular hydrocarbon organic fluid in crude oil. Under geological conditions, after modification, the fractionation and extraction of crude oil components occur, resulting in the migration and loss of light components in crude oil. When the heavy components are not easy to volatilize, they are preserved and eventually remain as black solid organic matter. Molecular condensation refers to the condensation reaction in which two or more organic molecules interact to form a larger molecule and lose water or other simple inorganic or organic small molecules. The occurrence of molecular condensation is mainly controlled by formation water medium conditions, formation depth and temperature, and crude oil composition. (1) It is the medium condition of formation water: the degree of oxidation degradation of macromolecular hydrocarbons is related to the oxygen content, salinity and the concentration of certain ions in formation water. (2) Formation depth and temperature: the survival and reproduction of microorganisms need certain temperature conditions. The control of temperature on microbial development determines that depth is an important factor to control the biodegradation degree of crude oil. The composition of crude oil has an important influence on the formation of bitumen. Through simulation experiments, Nandi and other scholars have shown that the yields of solid pitch formed by pyrolysis condensation of different group components (saturated hydrocarbon, aromatic hydrocarbon, non-hydrocarbon + asphaltene) in crude oil are significantly different^[59⇓-61].

The distribution patterns of bitumen self-sealing accumulation. The largest bitumen deposit in the world is developed in the Albert basin, Canada (Fig. 5). The early stage of Alberta basin is a cratonic marginal basin, which evolved into a foreland basin after middle Jurassic, covering an area of 30×10⁴ km². The oil sand is mainly distributed on the unconformity surface of Lower Cretaceous in the shallow part of the east wing of the basin. The source rocks include marine shale of Upper Devonian Duvernay Formation and Lower Carboniferous Exshaw Formation, with a distribution area of 13×10⁴ km², thickness of 25-135 m, and TOC value of 2%-24%^[62]. The reservoir is dominated by sandstones of the Lower Cretaceous Manville Group. The Pacific plate subducted eastward under the North American plate. Affected by this, the Rocky Mountains were compressed nearly EW. The Manville group presented a huge monoclinic structure, with a porosity of 20%-35% and a thickness of 30-50 m. A large amount of oil and gas generated in the Devonian Carboniferous system migrated eastward, forming the largest oil sand deposit in the world.

Statistical analysis shows that tight hydrocarbons and shale hydrocarbon exist in tight reservoirs, with general porosity less than 12% and air permeability less than or equal to 1× 10^-3 μm², average pore throat radius less than or equal to 1 μm. The main capillary force of oil-gas self-sealing is formed by the fluid binding in the micro pore throat system. The essence of capillary force is molecular interface force, which means that when there are two-phase immiscible fluids in micro pores, there will be a pressure difference on the contact surface of two-phase fluid due to the different wettability of pore inner wall to two-phase fluid. The difference is equal to the pressure of non-wetting phase minus the pressure of wetting phase (Fig. 6), that is, p_c=p_nw-p_w; where p_c is the pressure difference, p_nw is the pressure of non-wetting phase and p_w is the pressure of wetting phase. p_c is mainly related to the interfacial tension, capillary radius and contact angle of two-phase fluid^[63].

The capillary pressure during oil and gas migration is shown in equation 1.

There are three factors with significant impact on capillary forces, including interfacial tension of two-phase fluid, capillary radius and reservoir rock wettability^[63]. Interfacial tension can exert important influence on capillary force: in underground petroleum system, the value of oil-water or gas-water interfacial tension is affected by underground temperature, pressure, salinity of formation water, oil-gas composition, pH, etc.^[64-65]. In general, the interfacial tension decreases as temperature increases (Fig. 7a), and decreases as water salinity increases (Fig. 7b). Wettability can exert important influence on capillary force: wettability is usually expressed by the contact angle of oil-water interface measured by water phase to rock or pore wall. It is generally believed that a rock with a contact angle between 0 and 90° is usually hydrophillic. Most of the rocks with a contact angle more than 90° are lipophilic. When the rock is wet with water, the capillary force received by the source rock to expel hydrocarbon from the reservoir is the driving force (Fig. 7c-7d). When the rock is wet with oil, the capillary force received by the source rock to expel hydrocarbon from the reservoir is the resistance^[66]. The pore throat radius has an important influence on the capillary force: there is a negative correlation between the capillary force and the capillary radius. That is say, the smaller the capillary radius, the greater the capillary force (Fig. 7e). When the capillary force is close to or greater than the buoyancy, the oil and gas in the pores stop flowing, and at the same time, the capillary force also blocks the entry of external fluid, forming the self-sealing effect of oil and gas, and promoting the accumulation and preservation of tight oil and gas. As the main migration resistance in reservoir, capillary force is of great significance for unconventional hydrocarbon accumulation.

Accumulation and distribution pattern of tight hydrocarbon reservoirs. Distribution pattern of tight hydrocarbon reservoirs: The main body of tight reservoir is developed with nanometer pore throat, with pores of micron millimeter locally developed. The pore size for tight limestone oil reservoir is 40-500 nm, 50-900 nm for tight sandstone oil reservoir, and 40-700 nm for tight sandstone gas reservoir. The micrometer to millimetre pore throat system makes the reservoir tight and poor in physical properties. The general porosity is less than 10% and the permeability is (1×10^-6-1)×10^-3 μm², the fracture zone is accompanied with micro fractures, and the physical properties of the reservoir become better. For example, the average porosity of Box-8 in Sulige area of Ordos Basin is 7.34% and the permeability is 0.63 × 10^-3 μm², average porosity of Hill-1 is 7.04%, permeability is 0.38×10^-3 μm^2[20]. The tight hydrocarbons usually have an inversion of gas water relationship on basin scale, and abnormal pressure is usually developed^[67⇓-69]. It is considered that the hydrocarbon discharged from the deep source rocks enter the reservoir and the displacement water moves to the upper part and the edge of the basin. Due to lack of displacement power, the gas is forced to gather and form a reservoir in the deep depression area of the basin. There are two types of gas reservoirs, conventional and unconventional, which are generally developed in Blanco gas field in the San Juan basin (Fig. 8). The shallow layer of them is at the top of anticline trap and the conventional gas reservoir with gas in the upper water and under is developed; there are dense gas reservoirs with water on the upper and lower in the deep part of the basin and slope area. The formation is tight and the sandstone pore permeability is poor. When the natural gas is filled in the upper part, it is necessary to overcome the huge capillary force and form a self-sealing effect^[70].

Accumulation characteristics and distribution pattern of shale hydrocarbon. Shale hydrocarbon reservoir is formed in fine-grained sedimentary rocks rich in organic matter, mainly high TOC shale and mudstone siltstone. The reservoir has low-ultra low porosity and permeability similar to dense sandstone and dense limestone, and micro-nano pore system, with throat radius less than or equal to 1 μm. Therefore, self-sealing accumulation occurs with capillary force as the main driving force. Shale oil and gas source reservoir is a stagnant hydrocarbon reservoir of hydrocarbon generating rock series, which is different from tight oil and gas. At the same time, organic pores in rich organic shale are developed, with stronger molecular adsorption than that of tight hydrocarbon. Therefore, shale hydrocarbon has two phases, including free phase and adsorption phase, and its accumulation is a comprehensive result of various actions including capillary force and oil-gas molecular adsorption. The exploration and production practice shows that the free phase gas in high yield and high abundance shale gas reservoir accounts for a larger proportion. For example, the shale gas of the Silurian Longmaxi formation in Sichuan, China, has a single well production of (20-30)×10⁴ m³/d, the final gas production of single well is (2-3)×10⁸ m³, with 60%-70% of free gas. Barnett shale is a set of mixed deposition of clastic rock and carbonate rock in Carboniferous system of Fort Worth basin in the United States. The kerogen type is I-II 1 type, with shallow burial depth and in mature stage. A large number of nano pores can be seen, and the fractures are filled with calcite, with high gas content (8.5-9.9 m³/t), in which the adsorbed gas content accounts for 40%-60%^[73]. By 2018, the global recoverable resources are expected to be 214.5 × 10¹² m^3[74], and the top five countries are the United States, China, Argentina, Mexico and South Africa. Among them, the United States has the fastest shale gas development, with shale gas production reaching 6000×10⁸ m³ in 2018.

The adsorbed gas in coalbed methane is generally over 85%, and there is a certain proportion of adsorbed gas in shale gas^[75]. The self-sealing accumulation is mainly caused by molecular adsorption. The concept of adsorption was first proposed by Kayser in 1881, which refers to the aggregation of gases on a free surface (Fig. 9). Physical adsorption is defined internationally as the enrichment (positive or simple adsorption) or loss (negative adsorption) of one or more components at the interface. The adsorption in this paper refers to the phenomenon of oil and gas adhering to the surface of rocks or minerals.

Developed from the Langmuir monolayer adsorption theory, BET theory is still the largest, most influential and most widely used solid surface adsorption theory. According to BET theory, the physical adsorption of gas by solid is the result of Van der Waals force. Due to the Van der Waals force between molecules, when molecules collide with adsorbed molecules, it is possible to be adsorbed, thus forming a multi-molecular adsorption layer^[75].

There are many factors affecting the adsorption capacity of rocks. Generally, the smaller the pore size of rock, the larger the specific surface area, the stronger the adsorption capacity. When the pore size is larger than a certain extent, the adsorption will not occur^[76]. Cai^[77]and Zhang^[78] defined adsorption pore as micro formation pore with pore size less than 100 nm, and An^[79] thought that 1.5 nm was the critical pore size for adsorption force. According to the experimental study of Ross et al., it was found that methane adsorption capacity increased with the increase of organic carbon content (Fig. 10a) and thermal evolution degree (Fig. 10c), and showed differences with different types of organic matter (Fig. 10b)^[80⇓-82]. For organic poor shale, Lu et al. believed that its adsorption was mainly related to illite, and the adsorption test results showed that illite contributed 10%-40% to the total gas adsorption (Fig. 10d)^[83]. Ross et al. believed that clay minerals had large specific surface area, so they could absorb a large amount of gas (Fig. 10e)^[84]. Ross and Bustin studied the D-M shale and Jurassic shale in the sedimentary basin of western Canada, and found a good positive correlation between TOC content and micro-pore volume and methane adsorption capacity (Fig. 10f)^[84-85]. They found that when the water content was low, the adsorption capacity of Gordon shale, poker chip shale and muskwa shale was high; when the water content increases to 3% or more, the adsorption capacity decreases exponentially (Fig. 10g); Methane adsorption capacity of kerogen decreases linearly with the increase of temperature, and pressure is positively correlated with shale adsorption capacity (Fig. 10h)^[85].

Coalbed methane accumulation characteristics and distribution pattern. Coalbed methane accumulation is a comprehensive result of various factors including molecular adsorption. The Surat basin in Australia is an inner craton basin. Walloon coal measures absorb a large amount of coalbed methane. Groundwater in the basin is recharged by the eastern recharge area and migrates downward along the slope. Combined with the burial depth and the percentage of N₂ content, the basin is divided into recharge area, runoff area and detention area, corresponding to strong biogas transformation zone, slight biogas transformation zone, low biogas transformation zone and low biogas transformation zone The mixed zone of thermogenic coalbed methane and secondary biogas. Global CBM resources exceed 270×10¹² m³, mainly distributed in Russia, Canada, China, the United States, Australia, Germany and Poland^[87]. The CBM resource in Russia is (17-113)×10¹² m³, ranking the first in the world.

Molecular adsorption of shale hydrocarbon reservoirs. Shale hydrocarbon has two phases including free phase and adsorbed phase. Due to the development of organic pores formed in the later stage of kerogen in shale hydrocarbon reservoir, adsorbed oil and gas is of great significance in shale hydrocarbon. According to statistics, the content of adsorbed gas in shale gas is 20%-80%. The dynamic mechanism of unconventional hydrocarbon reservoir formation in petroliferous basin is often associated with many kinds of factors. Although the formation of coalbed methane reservoir is mainly caused by adsorption, the sealing effect of capillary force is also very large. The tight sandstone reservoir is mainly bound by capillary force, but the adsorption in the microporous medium is also very important. In the early stage of the formation of shale hydrocarbon reservoirs, the binding effect of capillary force may be dominant, and the oil and gas are mainly concentrated in the inorganic pore center in a free state. After a high degree of thermal evolution, the pores in organic matter develop, and the adsorption of oil and gas becomes more important. In the stage of shale gas development and production, the early high-yield shale gas is mainly free gas. In the later stage, the adsorption gas was the main factor. All these indicate that the genetic classification of unconventional reservoir dynamic mechanism only highlights one main dynamic force, but does not exclude the role of other dynamic forces in the process of reservoir formation.

Natural gas hydrate is an unconventional natural gas resource that has attracted great attention in recent years. Its self-sealing effect is manifested as the molecular cage interaction between methane and water molecules, that is, under a certain temperature and pressure environment, the cage structure formed by hydrogen bonding between water molecules wraps the guest molecules in it^[88]. Hydrogen bonding between water molecules, Van der Waals force between guest molecules and Van der Waals force interaction between cage structure and guest molecules are the basic driving forces of gas hydrate formation. These forces lead to the formation of cage structure of water molecules, which further cage methane molecules, leading to the formation of hydrate. The formation process of gas hydrate consists of dissolution, nucleation and growth process (Fig. 11). The formation process of gas hydrate can be regarded as a crystallization process, including nucleation and crystal growth process^[89]. The reaction equation is:

There are three factors that affect the molecule clathration that determines hydrate formation. (1) In a certain range, the increase of crystal hole occupancy of CH₄ molecule will effectively reduce the lattice potential energy of hydrate and improve the efficiency of molecular clathration to form hydrate^[90]. (2) Temperature: the stability of hydrate is affected by temperature^[91]. (3) Pressure: with the decrease of system pressure, the cage pore structure formed by water molecules connected by hydrogen bonds deforms and gradually dissociates, methane molecules escape from the cage pore structure and gather, and the solid hydrate finally decomposes into two phases of gas and liquid^[92]. This indicates that higher pressure is favorable for hydrate formation and distribution.

Natural gas hydrate self-sealing accumulation and distribution model. Based on the case study, this paper expounds on the distribution characteristics and basic model of natural gas hydrate reservoirs: the gas hydrate reservoirs in the northern slope basin of Alaska are distributed in the north latitude 69°-72° in the Arctic Circle, the East-West length is 1100 km, the North-South width is 100-600 km, and the area is about 36.5× 10⁴ km². The gas hydrate metallogenic system on the northern slope of Alaska is derived from the underlying lower Cretaceous tertiary petroleum system in the shallow part. It is the result of many factors such as underlying gas source, fault, lithology, special Arctic environment (permafrost, temperature and pressure field) and so on. The gas hydrate in situ resource is about 6.0×10¹² m³ standard natural gas^[94], and the resources of unproved recoverable natural gas hydrate are about 2.42×10¹² m^3[95].

We have been making progress in the understanding of hydrocarbon accumulation. From anticline reservoir to lithostratigraphic reservoir, from conventional reservoir to unconventional reservoir, there are still many new hydrocarbon resources to be recognized and discovered. Revealing the mechanism of intermolecular forces and the self-sealing reservoir forming model can guide the exploration and development of potential hydrocarbon resources more efficiently, and may also predict new types of resources that have not yet been recognized.

In terms of the range of distribution and the diversity of accumulation, conventional hydrocarbon reservoirs are special cases in petroliferous basins, while various unconventional hydrocarbon resources are normal cases. After clarifying the diversity of various unconventional hydrocarbon accumulation dynamics and the complexity of accumulation mechanism, we can predict and evaluate the new hydrocarbon resources that may appear under different geological conditions in the evolution process of petroliferous basin according to this law. A variety of unconventional hydrocarbon resources accumulate with hydrocarbon generation and special geological conditions. Based on the same principle, the types and distribution characteristics of unconventional hydrocarbon resources that may accumulate under other different conditions can be predicted, and the possible physicochemical characteristics and resource potential of these hydrocarbon products can also be predicted.

Based on deep understanding of the self-sealing mechanism of unconventional hydrocarbon reservoirs, efficient exploration of unconventional hydrocarbon resources can be realized according to its laws. Based on the same rationality, after studying the genetic mechanism, occurrence characteristics and distribution law of unconventional hydrocarbon reservoirs under special geological conditions, it can inspire us to realize efficient exploitation of unconventional hydrocarbon resources (Fig. 12). Bitumen and heavy oil are self-sealing reservoirs accumulated through molecular condensation and molecular viscosity changing into viscous liquid and solid at low temperature. Therefore, they can be liquefied or gasified by heating, so as to reduce viscosity and promote large-scale production of fluidity; Shale oil and gas, coal-bed gas and tight oil and gas are self-sealing reservoirs formed by molecular adsorption and molecular binding in tight and ultra-tight media. To develop them, it is necessary to modify the media conditions by volume fracturing to depressurize and desorb the oil and gas and increase the permeability and mobility, so as to obtain large-scale exploitation. Natural gas hydrate is self-closed by the clathration of water molecules to methane and other gas molecules. Large-scale exploitation needs to destroy the high pressure and low temperature conditions when the clathration is formed, so as to realize degassing and large-scale exploitation.

The core of classical petroleum geology is to reveal that buoyancy is the main driving force for migration and accumulation of conventional hydrocarbons, and trap is the main place for enrichment and preservation of conventional reservoirs.

Unconventional reservoirs are characterized by continuous and non-buoyancy accumulation. The core of non-buoyancy accumulation mechanism is the self-sealing of hydrocarbons, which is driven by intermolecular forces.

According to intermolecular force and self-sealing mechanism, unconventional reservoirs can be classified into three categories: heavy oil and bitumen are mainly self-sealing by macromolecular viscous force; tight oil and gas, shale oil and gas, and coalbed methane are mainly self-sealing by capillary force and adsorption force; and natural gas hydrate is characterized by intermolecular clathration force.

Deep understanding of hydrocarbon self-sealing accumulation mode and molecular interaction mechanisms helps to predict and evaluate the accumulation and distribution of unconventional hydrocarbon resources, and enlighten reverse thinking, so as to realize large-scale and efficient exploitation of unconventional hydrocarbon resources by reforming medium conditions and destroying hydrocarbon self-sealing conditions.

F—fluid internal friction force, N;

F°—reaction force of the fluid internal friction force, N;

g—gravitational acceleration, m/s²;

h—height, m;

p_c—pressure difference or capillary pressure, MPa;

p_cR—capillary pressure on the side with the larger radius of the capillary, MPa;

p_cr—capillary pressure on the side with the smaller radius of the capillary, MPa;

p_e—gas filling pressure, MPa;

p_nw—non-wetting phase pressure, MPa;

p_w—wetting phase (water column) pressure, MPa;

r—capillary radius, μm;

T_max—pyrolysis peak temperature, °C;

u—fluid velocity, m/s;

v—constant velocity of the upper part, m/s;

y—longitudinal layer distance, m;

γ—interfacial tension of two-phase fluid, mN/m;

θ—wetting angle, (°);

ρ_nw—non-wetting phase density, g/cm³;

ρ_w—wetting phase density, g/cm³.