As the exploration and development degree of oil and gas goes higher, shale oil and gas takes an increasingly important position in the energy structure of the world^[1,2,3,4]. Mesozoic - Cenozoic terrestrial lacustrine basin deposits, widely developed in northern China, have huge potential of shale oil and gas resources^[5,6]. The exploration of shale oil and gas is in full swing in Songliao Basin and Bohai Bay Basin. In Bohai Bay Basin, the shale in the third member of Paleogene Shahejie Formation (shortened as Sha 3 hereafter) in Dongpu sag has high organic matter abundance, good organic matter types, moderate thermal evolution degree, larger thickness and higher oil yield. According to preliminary estimation, it has a total oil and gas resources of 10.67×108 t, and great resource potential^[7]. However, reservoirs feature small particle sizes, complex mineral composition, small pore size, narrow pore throat, and poor physical properties, making the effective development and utilization of shale oil a world class problem.

Previous studies show that the Sha 3 Member in Dongpu sag has wide spread salt gypsum rock^[8]; most inter-salt shale strata have overpressure and abundant microfractures^[9,10]. Microfracture can serve as both effective reservoir space and seepage pathway of oil and gas, and thus is very important for the occurrence and migration of shale oil and gas^[11,12,13]. As early as 1976, high level oil and gas shows such as oil spots and oil immersion were obtained in the fractures of the inter-salt shale during the drilling of Well Wen-6. In 2000, fractured shale oil reservoir with overpressure was discovered during the drilling of inter-salt shale of the Sha 3 at the depth of 3110.49-3115.35 in Well Wengu 2, which produced 60 m³ of oil cumulatively. In 2009, high-quality oil and gas shows were found in the inter-salt shale section of Well Pushen 18 located in the central uplift zone. Meanwhile, a blowout happened at the depth of 3252 m in the adjacent Well Pushen 18-1, and it was confirmed by drilling core and imaging logging that the layer was overpressure oil and gas reservoir in inter-salt fractured shale^[9,10]. By re-examining old wells drilled in Dongpu sag, it was found that 74 wells detected oil and gas shows in the overpressure Sha 3 fractured shale. Clearly, the inter-salt fractured shale with overpressure in the Sha 3 Member of Dongpu sag has great exploration value and is a new domain of oil exploration.

In recent years, researchers have made a lot of achievements in researches on the types, origin, and quantitative prediction of fractures^{[14,15,16,17,18,19]}. However, most of the achievements are about structural fractures and non-structural fractures^[20,21], and few researches have been made on the inter-salt overpressure fractures. There is no theoretical support for the exploration and development of the oil and gas reservoir in inter-salt fractured shale with overpressure. In this study, taking the inter-salt shale reservoir of the Sha 3 Member in Dongpu sag as an example, the origin of overpressure, and development characteristics, formation mechanism, and geological significance of the inter-salt overpressure fractures were studied by rock core observation, rock slice identification, analysis with scanning electron microscopy, logging data analysis, fluid inclusion analysis, and formation pressure inversion, to provide theoretical basis for the assessment and effective development of oil and gas reservoir in inter-salt fractured shale with overpressure.

Located in in the south Bohai Bay Basin in east China, Dongpu sag is a typical salt-lake basin rich in oil and gas in Paleogene, with an exploration area of about 5300 km². It is adjacent to Luxi Uplift in the west, Neihuang Uplift in the east, and Linqing Depression in the north (Fig. 1). Controlled by faults, Dongpu sag consists of two subsags, one uplift, and one slope. In the northern part of the structural belt are two major hydrocarbon-generation subsags, the west (Liutun -Huzhuangji town area) and the east (Pucheng - Qianliyuan area). The Paleogene Shahejie Formation is the main target stratum for exploration in Dongpu sag, with a total thickness of about 5000 m. It is divided into four members, namely the Sha 1 Member (Es₁), the Sha 2 Member (Es₂), the Sha 3 Member (Es₃), and the Sha 4 Member (Es₄) from top to bottom^[22]. Among them, the Sha 3 Member (Es₃) is the most widely distributed and thickest in the study area. It is sediment of semi-deep - deep lacustrine sedimentary facies made up of different-thickness interbeds of gray and dark-gray shale and gray siltstone, fine sandstone, and salt gypsum rock. As both the main hydrocarbon-generation stratum system and the main reservoir, the Sha 3 Member (Es₃) has great exploration potential.

The most distinctive feature of the Sha 3 Member in Dongpu sag is that it contains three thick and widely distributed salt gypsum beds, namely Es₃⁴, Es₃³, and Es₃² from bottom to top. Except Es₃³ with smaller distribution range, the other salt gypsum beds are widely distributed, thick, and overlapped with each other, forming a regional caprock with multiple shielding beds^[23]. Es₃⁴ salt bed is mainly distributed in Wenliu - Qianliyuan area, covering an area of about 450 km². The deposition center of Es₃⁴ is located near Well Pushen 7, with a thickness of about 600 m (Fig. 1). Es₃² salt bed is mainly distributed in wester Liutun - Hubuzhai, Huzhuangji town, Wenliu, and west side of Qianliyuan Sag, with an area of about 400 km². The deposition center of Es₃² salt bed is in the southern part of Liutun Sag, with a thickness of about 500 m (Fig. 1). The widely distributed salt gypsum beds in the Sha 3 Member of Dongpu sag provide favorable geological conditions for the formation of overpressure and overpressure fractures in the inter-salt shale.

According to the pressure classification scheme for basins with overpressure in eastern China^[24] as well as the distribution characteristics of the pressure in the Sha 3 Member of Dongpu sag, the pressure system in Dongpu sag is classified into: normal pressure with pressure coefficient of 0.8-1.0; weak overpressure (pressure transition zone) with pressure coefficient of 1.0-1.2; overpressure with pressure coefficient of 1.2-1.5; strong overpressure with pressure coefficient greater than 1.5.

Statistics on formation pressure show that the Sha 3 Member in Dongpu sag has very obvious overpressure, with an average pressure coefficient of greater than 1.2 (Fig. 2). Longitudinally, the formation pressure gradually increases stepwise with the increase of depth, featuring marked pressure belts. The transition interfaces in the pressure system are at the depth of 3000 m and 4100 m respectively, corresponding to the middle submembers and lower submembers of the Sha 3 Member. The distribution of overpressure varies in different regions (Table 1). The Wenliu area has the highest formation pressure, with an average pressure coefficient of 1.39, and pressure transition interfaces at the depth of 3100 m and 4200 m respectively. Puwei area is the second, with an average pressure coefficient of 1.23, and has pressure transition interfaces at the depths of 3000 m and 4100 m respectively. Huqing area has the smallest pressure coefficient of 1.18 on average, and the pressure transition interface at the depth of 2900 m. Horizontally, the formation pressure gradually increases from west to east, and so does the depth of the transition interfaces of the pressure system, featuring obvious planar pressure zones. There are mainly three overpressure centers: the first one is located in Wenliu area, with a pressure coefficient greater than 1.3 in general and up to 1.9. It is the area with the highest pressure coefficient in the Dongpu sag; the second one is located in Hubuzhai area with a pressure coefficient of 1.2-1.7; the third one is located in Huzhuang town and Qingzu town, with a pressure coefficient of 1.1-1.5 (Figs. 3 and 4).

2.2.1. Undercompaction caused by the shielding of salt gypsum bed

It is found from comparison that the longitudinal and horizontal distribution of overpressure in Dongpu sag well correspond to the spatial distribution of salt gypsum rock (Figs. 2 and 3). The overpressure in the Sha 3 Member is mainly distributed under the salt gypsum beds. The top interface of the overpressure belt corresponds to Es₃² salt bed, under which the pressure coefficient abruptly increases to 1.5. The top interface of the strong overpressure belt corresponds to Es₃⁴ salt bed, under which the greatest pressure coefficient is up to 2.0. It is concluded from analysis that the salt gypsum bed is crucial for the formation and preservation of overpressure: (1) The salt gypsum bed has high lithological density, undeveloped pore throats, good sealing capacity, and high displacement pressure, blocking the fluid in shale from discharging upward. Hence, the shale has been kept under-compacted and has overpressure. (2) The minerals in the salt gypsum beds would undergo transformation and dehydration at a certain burial depth. 0.486 m³ of water is released during the transformation of 1 m² of gypsum to anhydrite^[25]. The water would enter into adjacent strata, leading to pressure increase, and further enhancing the under-compaction and overpressure of the shale^[26]. (3) The salt gypsum bed has strong plasticity and high fluidity at a high temperature and pressure, making it difficult for fractures to be formed. The newly formed fractures, if any, would be filled and unable to penetrate the gypsum beds. Therefore, the overpressure can be preserved.

2.2.2. Pressurization caused by hydrocarbon generation

The inter-salt shale in the Sha 3 Member of Dongpu sag has a large thickness of up to 500 m, TOC of 0.14-6.19%, type II₁, II₂, and some I kerogens which mainly generate oil. The thermal evolution of most of the organic matter has entered the stage of condensate gas - wet gas or even the stage of dry gas. The inter-salt shale in Sha 3 Member is the main hydrocarbon generation stratum system in Dongpu sag. Comparison between pressure coefficients and evolution characteristics of organic matter in Dongpu sag (Fig. 2) shows the overpressure belt is at basically the same depth as the depth at which the organic matter reaches the stage of thermal maturity, ranging from 3000 m to 4100 m; and the depth of strong overpressure belt is consistent with the depth at which the organic matter reaches the stage of high thermal maturity. All these indicate that the overpressure distribution is the same with thermal evolution of source rock in space and time in the sag. It is inferred through analysis that a large amount of oil and gas were generated after the organic matter in the source rock reached the oil generation threshold; the density would reduce when kerogen is transformed into oil and gas; and meanwhile, the volume of fluid generated would expand under high geothermal temperature^[27] (the expansion coefficient of crude oil is 0.955×10^-3, while the expansion coefficient of rock matrix is only 0.009×10^-3). As the upper and lower salt gypsum beds have good sealing capacity, the hydrocarbon generated can’t migrate out of the shale in time, and thus accumulate in the shale, leading to the increase of the formation pressure (overpressure).

2.2.3. Transformation and dehydration of clay minerals

According to testing and analysis, the clay minerals in the shale of Sha 3 Member in Dongpu sag mainly include illite, followed by the mixed layer of illite and montmorillonite (Fig. 2). The depth of overpressure layer corresponds to the depth of clay mineral transformation and dehydration. The illite content increases significantly while the content of mixed layer of illite and montmorillonite decreases gradually in the overpressure belt, indicating that the transformation and dehydration of clay minerals make some contribution to the formation of overpressure. It is inferred through analysis that the temperature of strata increased constantly with the increase of burial depth, since salt-bearing strata are rich in potassium ions and the salt gypsum beds have good thermal conductivity. When the temperature reached the dehydration threshold of montmorillonite, montmorillonite would transform into illite, and meanwhile release a large amount of water in lattice and adsorbed water, thus increasing the pore water content by 6.6% theoretically^[28]. The water generated from dehydration of clay minerals can’t be discharged in the closed system confined by salt gypsum beds, resulting in the increase of pore pressure and the formation of overpressure.

2.2.4. Fault sealing

Good structure configuration and strong fault sealing are important for the generation and preservation of abnormal high pressure. For example, Wendong structural belt is a quite complete rollover anticline, where the Xulou fault and Wendong fault intersect with each other, forming a combination of inverse ridge type, leaving the salt gypsum rock on both sides in juxtaposition with sandstone and shale, so a closed system is formed. In addition, according to the research on fault activity rate, Wendong fault was active during the initial sedimentary period of Shahejie Formation - Dongying Formation and was inactive after the sedimentary period of Dongying Formation, and thus it doesn’t cut through Dongying Formation^[21]. Therefore, Wendong fault was active before and inactive during the first reservoir-forming stage, and thus it provided good sealing in this stage. To sum up, Wendong fault belt features good sealing and can effectively block the migration of fluid in the reservoir. As a result, the fluid in the reservoir can’t discharge out of the shale in time, and giving rise to under-compaction and overpressure in the fault-controlled inter-salt shale.

In conclusion, under-compaction caused by the sealing of salt gypsum beds, hydrocarbon-generation pressurization, transformation and dehydration of clay minerals, and fault sealing are the four main factors leading to the formation of overpressure in Sha 3 Member of Dongpu sag. Among them, under-compaction caused by the sealing of salt gypsum beds and the fault sealing are static factors, while hydrocarbon- generation pressurization and the transformation and dehydration of clay minerals are the primary and secondary dynamic factor respectively. The matching of the factors in time and space brings about the development of overpressure in Dongpu sag.

Microfractures are commonly developed in the inter-salt shale strata of Sha 3 Member in Dongpu sag. According to analysis and observation of cores, cast thin sections of inter-salt shale samples taken from the area with overpressure by scanning electron microscopy, the microfractures are mostly distributed in the inter-salt and sub-salt strata; the strata near the microfractures have significant cementation of gypsum and anhydrite; meanwhile, the greater the pressure coefficient, the higher the development degree of the microfractures (Fig. 5). Therefore, the microfractures in shale related to overpressure in inter-salt strata are defined as inter-salt overpressure fractures.

The inter-salt overpressure fractures mainly come up in the inter-salt shale strata with overpressure, with irregular occurrence. Their distribution is not controlled by tectonic stress field and local structure. They feature small scale individually, short extension length, different widths, high density, and large opening. They are generally fiber-like and vein-like. Judging from the geometric shape, they are tensile fractures formed under tensile stress. Most of them have signs of oil and gas filling and migration (Fig. 6).

The distribution of the inter-salt overpressure fractures was examined from the quantitative characterization results of development parameters of the overpressure fractures in the inter-salt shale of Sha 3 Member in Dongpu sag (Table 2). It is found that the development degree of the inter-salt overpressure fracture increases in a stepwise pattern with the increase of depth, these fractures increase in density abruptly at the depth of 3000 m and increase in density again at the depth of 4100 m, with the maximum surface density of up to 3.12 cm/cm². The two depths are consistent with the depths of top interfaces of the overpressure belt and strong overpressure belt stated above. By overlapping the surface density and opening of the overpressure fractures in the inter-salt shale with the planar distribution of pressure coefficients in Sha 3 Member of Dongpu sag, it is found that the development degree of the inter-salt overpressure fractures well corresponds to the distribution of overpressure, and the development scale of inter-salt overpressure fractures gradually increases with the increase of pressure coefficient. The inter-salt overpressure fractures appear mainly in areas with the pressure coefficient of more than 1.2 and are distributed closely around the three overpressure centers in Dongpu sag. They are most developed in Wendong area, followed by Hubuzhai area, and are less developed in Huzhuangji town area (Fig. 4).

Statistics on pressure coefficient and characterization parameters of the inter-salt overpressure fractures such as length, opening, and density show that there is a positive correlation between the development degree of the fracture and the pressure coefficient (Fig. 7), indicating that the formation overpressure controls the formation of the inter-salt overpressure fractures.

3.3.1. Mechanical mechanism

The total stress (δ) acting on rock consists of the effective stress (S) borne by the rock matrix and the pore fluid pressure (P), of which the effective stress (the difference between S and P) is the main reason for rock deformation and fracture^[29]-. The pore fluid pressure changes the stress state of the rock by interacting with the rock matrix. It can offset the compressive stress borne by the rock and make the Mohr's circle shift towards left. When the pore fluid pressure increases to a certain extent, the Mohr's circle will intersect with fracture envelope and the stress acting on the rock will change from compressive stress to tensile stress; when the tensile stress reaches the fracturing limit of the rock matrix, the rock will fracture and overpressure fractures will then be formed, so the overpressure fractures are mostly tensile fractures.

3.3.2. Formation and stages of the inter-salt overpressure fractures

The main dynamic factor and two static factors contributing to the formation of overpressure in the inter-salt shale of Sha 3 Member in Dongpu sag are hydrocarbon-generation pressurization, and sealing of salt gypsum beds and fault. Therefore, the formation time of the inter-salt overpressure fractures there should be consistent with the time of large-scale hydrocarbon filling. The formation time of the fractures can be inferred by comprehensively analyzing the reservoir-forming history of oil and gas and evolution history of formation pressure. It can also be inferred by measuring the homogenization temperature of hydrocarbon inclusions filled in the fractures.

Jiang Youlu et al.^[30] carried out simulation experiments on the thermal evolution history and hydrocarbon generation and expulsion history of Sha 3 Member source rock in Dongpu sag. The results show that large-scale hydrocarbon generation and expulsion happened in two periods in Dongpu sag: from middle and late stage of deposition to early uplift period of Dongying Formation (about 23-31 Ma); from the late depositional stage of Minghuazhen Formation till now (about 0-7 Ma), as shown in Fig. 8. The expulsion quantity of hydrocarbon in the first period accounts for about 80% of the total quantity and, therefore, the first period is the main period of hydrocarbon generation and expulsion. The restoration results of the formation pressure in Sha 3 Member of Dongpu sag show the period before deposition of Dongying Formation was the initial accumulation stage of overpressure (27 Ma). In this period, the formation pressure built up continuously owing to hydrocarbon filling and the reversion and compression of the structure. Consequently, the formation entered overpressure stage (with a pressure coefficient of greater than 1.2) 25-30 Ma ago, and the formation pressure reached its maximum in the late depositional stage of Dongying Formation. After that, the formation rocks fractured on a large scale and the fluid in the formation was discharged with the enhancement of tectonism. As a result, the overpressure was released. The pressure started to accumulate again since the sedimentary period of Guantao Formation, and Sha 3 Member in Dongpu sag entered overpressure stage again in 5 Ma. The measurement of the temperature of the hydrocarbon fluid inclusions filled in the inter-salt overpressure fractures shows there are two stages of hydrocarbon inclusions in the inter-salt overpressure fractures. The hydrocarbon inclusions of the first stage feature a homogenization temperature of 90-140ºC and were formed about 25-30 Ma ago. The hydrocarbon inclusions of the second stage feature a homogenization temperature of 120-150 °C and were formed about 0-5 Ma ago (Table 3). Comprehensive analysis shows the results obtained from the analysis of hydrocarbon generation and expulsion period, the restoration of paleo-pressure, and the temperature measurement of hydrocarbon inclusions filled in the overpressure fractures are consistent with each other. Therefore, it can be inferred that the inter-salt overpressure fractures were created in two stages, 25-30 Ma and 0-5 Ma, respectively.

The overpressure fractures in the shale of Sha 3 Member were formed basically at the same time with large-scale filling of oil and gas. Owing to this favorable space-time corresponding relationship, the overpressure fractures can serve not only as effective reservoir space of oil and gas when they are generated but also as the pathways for the initial migration of oil and gas in the shale. Clearly, these fractures play a vital role in the accumulation and micro-distance migration of oil in the inter-salt shale of Sha 3 Member.

3.3.3. Evolution model

Hydrocarbon generation and expulsion of kerogen in organic-rich shale and sealing of salt gypsum beds are the main factors contributing to the formation of inter-salt overpressure fractures^[31]. The formation of the fractures in the inter-salt shale can be divided into four stages: (1) The formation temperature increases with the increase of burial depth. When it reaches 90-140 °C (the threshold for hydrocarbon generation), kerogen starts to generate hydrocarbons massively and salt gypsum rock and clay minerals start to transform and dehydrate, and the large amount of hydrocarbons and water generated cannot be discharged under good sealing conditions, resulting in the rapid increase of formation fluid pressure, and the formation of abnormal high pressure. Then the abnormal high pressure would induce the formation of inter-salt overpressure fractures (Fig. 9a). (2) Hydrocarbons generated from decomposition of kerogen cannot be discharged timely owing to the small pore throats and poor permeability of shale reservoirs, resulting in a constant increase of fluid pressure in kerogen, and pressure difference between kerogen and surrounding rock. The fluid pressure builds up constantly at the edges and tips of kerogen until the tensile stress borne by the rock exceeds the fracture strength of the rock. The rock then breaks, the fracture initiates from the tip of fibrous kerogen and grows along the path with the lowest resistance along lamina (Fig. 9b). (3) A single fracture extends along the long axis with isolated kerogen as the center, and extends horizontally to both ends along the path with low fracture strength such as kerogen edges, edges of debris particles, or intercrystalline micropores of clay minerals. One fracture can connect multiple kerogens while extending, and bends and becomes thinner at the ends. Parallel fractures run close to each other and the pore fluid pressure fields then overlap and gradually converge into knots in the shape of rhombus rings, and this will make the growth direction of the fractures change (Fig. 9c). (4) The fractures generated by hydrocarbon generation and expulsion of a large amount of kerogen converge, intersect, and connect with each other under the joint constraint of maximum pressure gradient and minimum fracture path, and finally, a complex fracture network is formed (Fig. 9d).

Organic-rich shale serves not only as traditional source rock but also as reservoir of shale oil and gas^[32]. Shale features extremely low porosity and permeability. According to the data measured on the whole core, the shale of Sha 3 Member in Dongpu sag has a porosity of less than 5% (2.6% on average) and permeability of less than 0.1×10^-3 μm² (0.037×10^-3 μm² on average) in general. Oil and gas are difficult to migrate and accumulate in shale with such poor physical properties. For the source-reservoir-in-one oil and gas reservoir in inter-salt shale with overpressure, the high-permeability network formed by inter-salt overpressure fractures generated from hydrocarbon generation and expulsion of kerogen plays a vital role in the storage and flow of shale oil and gas.

According to the calculation with the Monte Carlo approximation method, the inter-salt overpressure fractures in Sha 3 Member have a porosity of 0.02-0.97% (0.58% on average), contributing about 22.3% to shale porosity; and a permeability of (0.001-0.860)×10^-3 μm² (0.019×10^-3 μm² on average), contributing about 51.4% to shale permeability. Apparently, the inter-salt overpressure fractures can not only greatly improve the porosity of shale reservoirs as reservoir space, but also serve as major percolation pathways for shale oil and gas.

The hydrocarbon-generation pressurization of kerogen is the major drive for oil and gas migration^[33], and the resulting overpressure fractures serve as important pathways for the initial migration of shale oil and gas^[34]. The overpressure fractures resulting from hydrocarbon generation and pressurization extend along the bedding with kerogen as the center and are connected with each other at their ends. Driven by fluid pressure, the shale oil and gas newly generated flow along the direction with the least resistance in shale and gradually converge into structural fractures and diagenetic fractures in larger sizes, realizing the initial short-distance migration. A large amount of organic matter and residual oil and gas remain in the fracture network after the initial migration, forming an interconnected organic matter network. The network eventually evolves into an organic-rich zone and becomes the main reservoir space for shale oil and gas. Therefore, the fracture network formed by the interconnection of various types and sizes of fractures in the shale with overpressure serves not only as the primary pathway for the initial migration of shale oil and gas but also as the important storage space of shale reservoir, controlling the accumulation and enrichment of shale oil and gas.

According to the data of formation testing and oil production test after fracturing, the well sections with high oil and gas production in Dongpu sag all have inter-salt overpressure fractures, and there is a positive correlation between the shale oil and gas production and the development degree of inter-salt overpressure fracture (Fig. 10). Formation testing results of Well Hu 83 and Well Qing 65 which are in the same structural location and the same shale system, share similar lithologic association characteristics, but feature different development degrees of inter-salt overpressure fractures were compared. Well Qing 65 with more developed inter-salt overpressure fractures had an initial oil yield of up to 10t/d. Although the production of the well declined slightly as the test went on, the general production has kept at above 6t/d. Well Hu 83 with less developed inter-salt overpressure fractures had a production of only about 2t/d (Fig. 11). It can be seen that the development degree of inter-salt overpressure fracture determines the enrichment degree and productivity of shale oil and gas.

The analysis of shale fracture mechanics and triaxial hydraulic fracturing simulation experiments^[35,36] show that the development of natural fracture is the precondition for large- scale reservoir volume fracturing of shale through horizontal well. The hydraulic fractures would extend in the natural fracture face with low resistance and diverge, change direction, and intersect at their tips while connecting natural fractures, thus changing their continuous extension and morphology^[37]. The inter-salt overpressure fractures mainly extend along bedding horizontally and appear in dense groups. Therefore, during the large-scale hydraulic fracturing of shale through horizontal well, hydraulic fractures tend to connect the zones rich in inter-salt overpressure fractures along bedding, forming complex palisade-shaped or reticular fractures^[38,39]. This will significantly increase the width and length of hydraulic fracturing zone, greatly increase the range of shale connected by the volume fracture network, and thus greatly improving the production of reservoir stimulated by large-scale volume fracturing.

Overpressure is commonly seen in inter-salt shale strata of Sha 3 Member in Dongpu sag. The formation pressure increases stepwise with the increase of depth longitudinally and has obvious different pressure zones laterally, which is closely related to the distribution of salt gypsum beds. The undercompaction caused by the sealing of salt gypsum beds, hydrocarbon-generation pressurization, transformation and dehydration of clay minerals, and fault sealing are the four primary factors contributing to the formation of overpressure in Sha 3 Member of Dongpu sag. The matching of these factors in time and space leads to the formation of overpressure in Sha 3 Member there.

Overpressure fractures can be formed in inter-salt shale driven by the overpressure in the shale. They are small in scale but are highly effective since they are densely tensile fractures formed along with oil and gas filling. Hydrocarbon generation and expulsion of kerogen in organic-rich shale and the sealing of the salt gypsum beds are the main reasons for the formation of inter-salt overpressure fractures. They were formed basically at the same time as the two stages of large- scale filling of oil and gas, i.e., 25-30 Ma and 0-5 Ma respectively. This favorable space-time configuration makes it possible for the inter-salt overpressure fractures to play their roles in oil and gas storage and migration fully.

Inter-salt overpressure fractures serve not only as effective reservoir space but also as the most important percolation pathways for shale oil and gas. They can greatly increase the porosity and permeability of the reservoir. There is a positive correlation between the development degree of the fracture and the productivity of single well of shale oil and gas. The fractures of different origins and different sizes such as inter-salt overpressure fractures, structural fractures, and diagenetic fractures converge step by step to form an interconnected fracture network, jointly controlling the migration and enrichment of shale oil and gas. During the development of shale oil and gas, the inter-salt overpressure fractures will affect the extension and morphology of hydraulic fractures, inducing the formation of a complex high-permeability fracture network. This will greatly increase the influence range of the fracture network and improve the effect of the hydraulic fracturing.