Hydrocarbon distribution and enrichment patterns in fault basins, as the keys to reservoir prediction, have always been a major subject in petroleum geology^[1,2]. Since the 1960s, Chinese petroleum geologists have proposed a number of hydrocarbon accumulation theories, including source control theory^[3], composite hydrocarbon accumulation zone theory^[4,5], oil reservoir ring-like distribution theory^[6,7], subtle oil-gas reservoir theory^[8], rich oil-gas sag theory^[9], sag-wide oil-bearing theory^[10,11] etc, reflecting the continuous development process of petroleum geology research from phenomenon characterization to mechanism exploration. With the deepening of exploration practice and geological knowledge, petroleum geologists began to rethink the distribution patterns of reservoirs in fault basins. For example, what is the final macroscopic distribution pattern of reservoirs in an oil-rich sag? What are the factors controlling hydrocarbon accumulation? These problems are not only the research contents of petroleum geology in continental fault basins, but also are crucial in exploration practice. At present, most of the continental fault basins in eastern China have entered the medium-high exploration level stage^[12] where the exploration objects are increasingly complex. To realize continuous discovery of hydrocarbon reserves is the necessary for fine and profitable exploration in mature exploration areas. In addition, results of the new round hydrocarbon resources evaluation show that the mature exploration areas in the east still have substantial remaining resources and great exploration potential. Therefore, taking Dongying Sag as an example, following the evolution of key accumulation factors, based on fine geological modeling, the interactive evolution of pressure-fluid- reservoir elements and their coupling control effect on reservoir accumulation have been examined to reveal the inherent mechanism of order distribution and differential accumulation of hydrocarbon. The study results will effectively guide the exploration practice in mature exploration areas.

Exploration practice shows that the hydrocarbon in Dongying Sag is distributed in an orderly manner. From the spatial view, lithologic, structural and stratigraphic reservoirs are horizontally adjacent and vertically superposed. There are often transitional types between different reservoir types, however, there are differences in the distribution sequences of reservoirs in different areas and structural units. From the perspective of sag, secondary sequence and sedimentary system, the orderly distribution of hydrocarbon is universal.

The Dongying Sag includes four oil-generating subsags. In each subsag, lithologic reservoir, structural-lithologic reservoir, lithologic-structural reservoir, structural reservoir and stratigraphic reservoir develop from the center to the edge in turn. The reservoir types are distributed orderly on the plane and in ring pattern around the center of the subsag (Fig. 1).

At the level of secondary sequence, taking the upper fourth member of Shahejie Formation to the lower second member of Shahejie Formation (Es₄^s-Es₂^x) of oil-bearing series in Dongying Sag as an example, lithologic, structural and stratigraphic reservoirs are distributed orderly from the center of the subsag to the edge. Between different types of reservoirs, there are transitional reservoirs of structural-lithologic type and lithologic-structural type with relatively complete distribution sequence (Fig. 2). In other secondary sequences, the reservoir sequences are incomplete, and the distribution patterns of reservoir types are obviously different, which reflects the difference of spatial distribution relationship between different secondary sequences and source rocks.

At the level of sedimentary system, taking the example of Dongying Delta, the sedimentary system of the delta is mainly made up of prodelta subfacies (fluxoturbidite), delta front subfacies (mouth bar sandbody), delta plain facies (distributary channel sandbody). From the center of the subsag to the edge, lithologic, structural-lithologic and structural reservoirs (Fig. 3) show obvious orderly distribution. At the same time, the beach-bar sand and fan sandy conglomerate reservoirs also have the similar orderly distribution characteristics^[13,14] in Dongying Sag.

In summary, the reservoirs in the fault basin are distributed orderly, adjacent horizontally, and superposed vertically at the level of sag, secondary sequence and sedimentary system. The knowledge of the orderly distribution of reservoirs can help the scientific prediction and evaluation of the spatial distribution of reservoirs and guide the active shift of the main exploration objects between different zones (stratigraphic systems).

The orderliness of hydrocarbon distribution is the regularity of spatial distribution of reservoirs in the basin. However, the main factors controlling hydrocarbon accumulation in different structural and lithologic zones of the basin are different somewhat, so the modes of hydrocarbon accumulation in different zones have differences too. As far as Dongying Sag is concerned, different types of reservoirs have developed in Paleogene, such as sandy conglomerate in steep slope belts,turbidite in depression belts and beach-bar sand in gentle slope belts etc. The main controlling factors of the reservoirs are different, resulting in significant differences in the modes of hydrocarbon accumulation^{[14,15,16,17,18]}. Based on analysis of many reservoirs, a model of hydrocarbon accumulation and differential enrichment has been established.

Sandy conglomerate reservoirs in steep slope belts: The hydrocarbon accumulation model of this kind of reservoir features sealing by root fan and hydrocarbon enrichment controlled by favorable facies zone of middle fan (Fig. 4). Laterally, for the sandy conglomerate fans of the same period, the hydrocarbon accumulation is characterized by the conduction of outer-fan fracture, inner-fan lateral sealing and middle-fan hydrocarbon accumulation; vertically, for the sandy conglomerate fans with multiple stages of sands stacked over each other, it can be divided into high filling degree zone, transitional zone and low filling degree zone. The buried depth of 3280-4 100 m is a high fullness zone, where the inner-fan has strong sealing capacity, the reservoir is lithologic one blocked by inner-fan, either oil filled or dry, with high hydrocarbon filling degree, oil-bearing height of 80-190 m and reservoir width of 600-2 500 m. The buried depth of 2500-3280 m is the transitional zone, where the root fan has moderate sealing capacity, the reservoir type is structural-lithologic or lithologic with oil and water inter-connected; the reservoir is medium in hydrocarbon filling degree, with an oil-bearing height of 20-90 m and width of 300-1 500 m. The buried depth of 1 700-2 500 m is the low filling zone, where the root fan has poor sealing capacity, the reservoirs are mostly self-sealing structural reservoirs and stratigraphic reservoirs with low hydrocarbon filling degree, mainly composed of oil-bearing water layers, with oil-bearing height of 10-70 m and reservoir width of 200-1 000 m.

Turbidite reservoirs in depression belts: featuring the hydrocarbon accumulation pattern of pressure concealed conduction (Fig. 5). Statistical results show that when the inten-sity of hydrocarbon expulsion of source rock is greater than 350×10⁴ t/km², abnormal high pressure generally occurs in the source rock, which is favorable for oil and gas accumulation in turbidite lens within the oil source rock. Exploration practices show more than three quarters of lithologic reservoirs have a pressure coefficient of greater than 1.2 (belonging to overpressure). In overpressure areas, the hydrocarbon filling degree of lithologic reservoirs is high. Oil and gas accumulation in turbidite lens outside of source rock is up to the distance of the turbidite lens to the source rock, and the vertical hydrocarbon migration in fault zone and fissure zone. Up to now, it has been found that turbidite reservoirs are mainly distributed within the range of about 225 m above the source rock, and hydrocarbon filing degree of the turbidite reservoirs outside source rock gradually decreases with distance increasing from the source rock.

Beach-bar sand reservoirs in gentle slope belts: the hydrocarbon accumulation features pressure-suck filling model (Fig. 6), and the extensive overpressure of source rock controls the oil and gas enrichment. In the high-pressure zone of source rock close to the sag center, the reservoirs are mostly lithologic one highly filled by hydrocarbon. Often with no obvious bottom or edge water, they are either oil filled or dry. In the pressure transitional zone in the middle of the basin slope, the reservoirs are largely structural-lithologic ones with high hydrocarbon filling degree, and oil and water layers in local parts. In the normal pressure zone at the structural high at the edge of the basin, the reservoirs are mainly structural and stratigraphic ones with low hydrocarbon filling degree. Alternating oil layers and water layers is common, and obvious bottom or edge water layer is often seen in these reservoirs.

The orderliness of sedimentary filling and pressure structure in the basin controls the orderly distribution of hydrocarbon, whereas, the differential enrichment of hydrocarbon in different structural zones in the basin is controlled by the coupling of pressure, fluid and reservoir.

The Cenozoic development and evolution in the Bohai Bay Basin were controlled by the interaction of the Pacific plate subduction and the Indian plate extrusion collision^[19,20]. As the third-order structural unit in the Bohai Bay Basin, Dongying Sag experienced two evolutionary stages, rifting and post-rifting depression in the Cenozoic, therefore the overall basin structure appears as a half graben-like basin, faulting in the north and overlapping in the south. Controlled by the structural pattern of the sag, the sedimentary system consists of deep-water turbidite fan, prodelta, delta front, delta plain, river and alluvial fan from the sag center to the edge in orderly distribution. Vertically, within the typical secondary sequence of the basin or the entire fault-depression sequence stratigraphic framework, sedimentary systems change in an orderly manner too (Fig. 7).

The statistical results show that there are differences in the types of reservoirs developed in different sedimentary systems of Dongying Sag. The delta front and deep-water turbidite fans in the central sag are the main components of lithologic traps and also important components of fissure-sand body migration system in the sag, and mainly form developmental lithologic reservoirs. In the delta front, fault-lithologic traps are dominant, and so structural-lithologic reservoirs and structural reservoirs. The delta plain is not only the main reservoir stratum of large-scale structural reservoirs, but also the main component of transverse transport system of the basin, where structural reservoirs take majority. In the river channels are largely structural reservoirs and lithologic-structural reservoirs. In alluvial fans, stratigraphic reservoirs take the majority (Fig. 8). It can be seen that the orderliness of the sedimentary system from the center to the edge of the sag determines the basic conditions for the orderly distribution of static elements for the reservoir formation, that is, the orderliness of sedimentary filling controls the continuity characteristics of reservoir forming elements, such as trap type and transport system, and then determines the orderly distribution of hydrocarbon.

Stratum overpressure plays an important role in the process of hydrocarbon generation, migration accumulation. According to the pressure data of drilling DST and MDT test, the overpressure in the Dongying Sag is mainly in the third member and fourth member of Shahejie Formation, which is consistent with the development series of source rocks. Whereas, the overlying formations, including the second member and first member of Shehejie Formation, Dongying Formation, Guantao Formation, Minghua Town Formation and the underlying Kongdian Formation all have normal pressure, showing single overpressure characteristics on the whole^[21]. Most of the overpressure centers are in the sedimentary (subsidence) center of the sag. The overpressure is large in magnitude, with pressure coefficient reaching up to 2.0, and gradually transits to normal pressure towards the edge of the basin (Fig. 9).

The exploration practice of beach-bar sand in gentle slope belts shows that the orderliness of stratum pressure structure controls the orderly distribution of reservoir types. Lithologic reservoirs mainly occur in the overpressure zone (Fig. 10). From the perspective of geochemical characteristics, they have similar hydrocarbon maturity (Fig. 9), showing the characteristics of high pressure driven reservoir forming. Although the displacement pressure and the median saturation pressure representing the reservoir-forming resistance are the largest in lithologic reservoirs (Table 1), the overpressure environment provides enough power for hydrocarbon filling and favorable conditions for hydrocarbon accumulation in lithologic traps. Normal pressure area is dominated by structural reservoirs (Fig. 10), which have hydrocarbon maturity in orderly distribution, with high maturity in the lower part and low maturity in the upper part (Fig. 9). This indicates that the hydrocarbon accumulation in normal pressure area is driven by buoyancy. The resistance to oil charging in structural reservoir is low (Table 1), and the buoyancy generated by the difference in oil-water density can be enough to displace the water in the capillary pores, enabling hydrocarbons to accumulate in the structural trap. In the pressure transition zone, the fault is the main channel of vertical pressure relief, the reservoir stratum is the lateral hydrocarbon migration channel, and the geochemical parameters of hydrocarbon maturity show reversal (Fig. 9), indicating joint drive of overpressure and buoyancy. The reservoirs in this zone are diverse in types, but most of them are structural-lithologic reservoirs (Fig. 10).

Different tectonic-lithofacies belts have different structural subsidence, sedimentary filling patterns and diagenetic evolution processes, which determine the differences of pressure-fluid-reservoir mechanism and evolution process (Fig. 11), and in turn the different coupling modes during the hydrocarbon reservoir formation and final differential accumulation of hydrocarbon.

In steep slopes, near provenance, and formed by rapid accumulation, sandy conglomerate composed of mixed coarse and fine grains has weak anti-compaction ability and strong heterogeneity. High-quality reservoir is the key to control the formation of sandy conglomerate oil and gas accumulation^[22,23,24]. The study results show that the alternate actions of acid and alkali fluids controlled the development of secondary pores in the sandy conglomerate. At the end of the sedimentation of Dongying Formation, the alkaline fluid produced from dehydration of the gypsum salt layer in the underlying Kongdian Formation to the lower submember of fourth member of the Shagangjie Formation mainly migrated upward through the inner-fan subfacies lacking mudstone interlayer and the middle fan near the root fan. In addition to the strong compaction, the root fan subfacies also experienced strong cementation of anhydrite and carbonate which almost plugged all the original pores, so that the acidic fluids accompanied with hydrocarbon generation from source rocks couldn’t dissolve inner-fan reservoir on a large scale, and the physical properties of inner-fan reservoir gradually deteriorated (Fig. 12). In contrast, the middle-fan subfacies had better original sedimentary conditions, higher strong anti-compaction ability, mudstone interlayers, so the action range of the alkaline fluid was limited, carbonate cement was formed in local parts, while original pores were preserved in other parts, which could provide space for late acidic fluid inflow. When getting into these remaining pores, acidic fluid dissolved feldspar particles and carbonate cement formed early, increasing the reservoir space of middle-fan subfacies further (Fig. 12). Subsequently, with the physical properties of the reservoir in the middle fan becoming better, and those of the root fan reservoir becoming worse, the diagenetic trap with the fan root sealing came about. Since the end of the sedimentary period of the Guantao Formation, the source rocks experienced structural uplift at the end of the Dongying sedimentation and late subsidence. The organic acid discharged from the secon-dary hydrocarbon generation of the source rocks re-dissolved the reservoir in the middle fan, further improving the storage space in it. The root fan suffered continuous compaction, so the reservoir there gradually densified with hydrocarbon sealing capacity enhancing, and the diagenetic traps were gradually shaped. Comparison of hydrocarbon geochemical indicators shows that hydrocarbon sources are different in different sandy conglomerate reservoirs or in different positions of the same sandy conglomerate reservoir. The hydrocarbon in the sandy conglomerate reservoir mainly comes from the source rock of the fourth member of the Shahejie Formation, but there are significant differences of hydrocarbon sources in different layers of sandy conglomerate reservoirs or in different positions of the same reservoir. In the reservoirs adjacent to the sag (e.g. Well Yan 22-X1) in the upper fourth member of Shahejie Formation, the hydrocarbon is derived from the source rocks of the lower and upper fourth members of Shahejie Formation, with characteristics of mixed sources (Fig. 13a); in the reservoirs adjacent to the root fan (e.g. Yan Well 22) in the upper fourth member of Shahejie Formation and in the third member of Shahejie Formation (e.g. Yan Well 16), the hydrocarbon is derived from the source rock of the lower fourth member of Shahejie Formation (Fig. 13b and 13c). Although the two sets of oil-bearing systems are vertically superposed in space, the hydrocarbon migration along the vertical direction of the fan is controlled by the degree of diagenetic evolution of the root fan. In the early stage, during the hydrocarbon generation and expulsion of the lower fourth member of the Shahejie Formation, the sandy conglomerate in fan body and root fan had better physical properties, and could act as conductive layer to allow hydrocarbon migration to the shallow layer and accumulate in the structural traps of the third member of Shahejie Formation, like that in Well Yan 16. In the late stage, during the hydrocarbon generation and expulsion of the upper submember of the fourth member of Shahejie Formation, as the burial depth increased, the reservoir in the root fan gradually worsened in property and enhanced in sealing capacity, so the hydrocarbon generated by the upper submember of the fourth member of Shahejie Formation mainly migrated laterally and accumulated in the diagenetic traps nearby. Therefore, the hydrocarbon near the root fan and shallow reservoirs mainly came from the source rocks of the lower submember of the fourth member of Shahejie Formation. Whereas, the oil in the outer-fan reservoir has mixed sources of the upper and lower submembers of the fourth member of the Shahejie Formation, showing the transformation process of the root fan from open to close. Since the sandy conglomerate fan is adjacent to the source rock of the fourth member of the Shahejie Formation, the hydrocarbon generation of the source rock provides power for hydrocarbon charging. However, most of the sandy conglomerate reservoirs discovered have normal pressure, indicating that the hydrocarbon migration in the fan is mainly driven by buoyancy. Under the condi-tion of sufficient oil source, the breakthrough pressure difference between root fan and middle fan of sandy conglomerate determines the degree of reservoir enrichment.

The turbidite and beach-bar sands in the subsag are mostly enclosed in or adjacent to the source rocks, where the formation and evolution of reservoir is related to the acidic fluid discharged during the hydrocarbon generation of source rock. The acidic fluid caused the dissolution of unstable acidic minerals (feldspar and carbonate cement) and thus formation of a large number of secondary dissolution pores (Fig. 14), improving the reservoir properties of the deep reservoir. The hydrocarbon generation of source rock led to the formation of abnormal pressure compartment inside the source rock, the sand body enclosed in which was protected by overpressure, the overpressure caused the pore fluid to carry a part of the loaded pressure, inhibiting the compaction and benefiting preservation of reservoir properties^[25]. At the same time, feldspar alteration in acid environment consumed a large amount of formation water^[26,27], leading to the reduction of inner pressure with the water consumption in the deep closed system, thus improving the reservoir space. The huge pressure difference formed by pressure boost from hydrocarbon generation of source rock and pressure reduction of reservoir due to water consumption, provided power for hydrocarbon charging, giving rise to a “pressure-suck” filling hydrocarbon migration and accumulation mode with overpressure of hydrocarbon source rock controlling hydrocarbon charging fullness (Fig. 14).

As one of the typical representatives of the continental fault basin in eastern China, the Dongying Sag can provide reference for hydrocarbon exploration in similar basins with the similar characteristics of orderly distribution and differential accumulation of hydrocarbon. The orderliness of hydrocarbon distribution in the basin reveals the regularity of hydrocarbon distribution in the same reservoir-forming system and the exploration potential in the blank areas of different reservoir series, which can provide guidance for the selection of exploration area in mature areas. The diversity of hydrocarbon accumulation patterns between different zones means the key elements controlling hydrocarbon accumulation in different types of hydrocarbon reservoirs, and accordingly ideas and key technologies for their exploration must be different. Aiming at key factors controlling hydrocarbon accumulation, geological modeling and quantitative evaluation should be carried out to provide guarantee for efficient exploration. This understanding is applicable to different levels of exploration processes, supporting scientific deployment of exploration in petroliferous basin group, petroliferous basin and oil-gas accumulation zone, keeping the stable and sustainable development of mature exploration areas.

For the exploration of blank areas in high-exploration basin, firstly the orderly pattern of hydrocarbon distribution should be established based on comprehensive analysis of the basin structural evolution, sedimentary filling and key factors controlling reservoir accumulation, to predict the types of reservoirs that may exist in the reserve blank areas, so as to effectively guide the selection of macroscopic exploration areas. Based on selecting the key evaluation zones, through detailed analysis of discovered reservoirs, the main controlling factors of hydrocarbon reservoir formation need to be sorted out. The formation reasons of the reserves blank area need to be analyzed by combining with the analysis of the failed wells. Then the reserve areas and the reserve blank areas need to be compared to find out the key factors restricting the exploration and the differences in coupling effects of the blank zone. Starting from the key factors controlling reservoir formation, fine geological modeling, quantitative evaluation, target selection and exploration deployment should be carried out, so as to realize the superimposition and connection of proved reserves in major oil-bearing series.

Taking the exploration of beach-bar sand in gentle slope belts as an example, the shift of exploration ideas and exploration effect are introduced. In the past, the exploration of beach-bar sand reservoirs was mainly concentrated in the nose structures and their wings at structural highs. But without clear understanding of sand body distribution and hydrocarbon reservoir types, there were a large number of blank areas left (Fig. 15a) in the low slope area and deep sag zone. However, good oil and gas shows in several wells (e.g. Well Gao 89) of the blank reservoirs indicate that the beach-bar sands in the low slope area and deep sag zone have great exploration potential. From the perspective of sedimentary system, shore- shallow lacustrine beach-bar sand on gentle slope belts is widely distributed, with the characteristics of large-area distribution of reservoirs, which provides material basis for the orderly distribution of hydrocarbon. At the same time, beach- bar sand bodies are mostly in lateral connection with the overpressure center of source rocks, and the overpressure provides conditions for large-area oil and gas accumulation in beach- bar sand bodies. According to the orderly distribution pattern of hydrocarbon, it is speculated that structural, structural-lithologic and lithologic reservoirs develop successively from the edge to center of the sag. It was inferred that the deep subsag zone might have lithologic hydrocarbon reservoirs, and then some blank reserve zones in the deep subsag zone were selected to be key evaluation areas. In allusion to lithologic reservoirs in the anomalous high-pressure zone of the deep subsag, starting from the reservoir distribution and pressure characteristics, fine geological modeling and re-evaluation were carried out, and 68 wells were drilled successively. In Fandong Area and Lijin subsag, Fan 159, Fan 147, Liang 75, Liang 76 and other monolithic reserve blocks were found, with the newly added proven reserves of 1.94×10⁸ t, realizing the overall connection of oil-bearing beach-bar sandstone reservoirs in the same series of the original 12 oilfields in Dongying Sag (Fig. 15b).

The orderly development of sedimentary systems in fault basins is the basis for the orderly distribution of reservoirs. The continuity of pressure structure is the key to controlling the orderly distribution of reservoirs. From the sag center to edge, the reservoir types in the sag, secondary sequence and large- scale sedimentary system are characterized by orderly distribution of lithologic, structural and stratigraphic reservoirs. There are often transitional reservoirs between these types, such as structural-lithologic and lithologic-structural reservoirs, which shows that the orderly distribution of reservoir types is universal.

Controlled by coupling function of pressure-fluid-reservoir, hydrocarbon accumulation characteristics of different structural belts are different. Alternate acid-alkali actions controlled the development of high-quality reservoir in the middle fan of sandy conglomerate in steep slope belts, giving rise to the hydrocarbon accumulation model of fan root sealing and middle-fan enrichment. In this model, the breakthrough pressure difference between the fan root and middle-fan determines the accumulation degree of hydrocarbon; action of acid fluids controls the development of high-quality reservoir in beach- bar sand and turbidite. The pressure difference between the source rock overpressure caused by hydrocarbon generation and the reservoir low pressure caused by reservoir improvement provides the power for hydrocarbon filling, giving birth to the “pressure suck” filling mechanism with overpressure of hydrocarbon source rock controlling hydrocarbon filling degree.

The orderly distribution of reservoir types in fault basins reveals the regularity of hydrocarbon spatial distribution under the same reservoir system, which is the basis for hydrocarbon prediction in mature exploration areas. The differences in oil and gas accumulation between different zones reveal different types of reservoirs have different factors controlling their enrichment, which are the keys to fine and high efficient exploration.