In recent years, with the breakthrough of oil-gas exploration in the Bongor Basin in Chad of Central West African rift system, the South America Basin, the Sumatra Basin in Indonesia, and the Qaidam Basin in China^[1,2,3], basement buried-hill oil and gas reservoirs have become one of the hot spots for exploration at home and abroad. Large-scale petroliferous basement reservoirs abroad are mostly carbonate and granite. Studies on the karstification of carbonate and evolution of deep reservoirs revealed the genetic mechanisms of carbonate buried-hill reservoirs^[4,5]. Affected by tectonic and volcanic activities, the basement lithology of the Qaidam Basin in western China and the Hailar Basin in eastern China is dominated by metamorphic rock, volcanic rock, and volcanic sedimentary rock^[6]. There are many studies on the macro-control factors such as tectonic activities and paleogeomorphy of such reservoirs^[7,8], but there is little discussion on the genetic mechanism and evolution of their fluid-rock reaction, which restricts the deepening of the theory on basement reservoir as well as the oil-gas exploration.

Landes defined basement oil-gas reservoir first^[9], and the definition was supplemented and modified by researchers at home and abroad later. In this paper, basement oil and gas reservoir follows the definition of Pan, et al., that is oil and gas reservoirs in the metamorphic rock, volcanic rock, sedimentary rock and carbonate (whether metamorphic or not) in the Paleozoic and older strata below the unconformity surface at the bottom of the young oil source rock series^[10]. Previous studies showed that the basement reservoirs in the Hailar Basin are mainly weathering crust type and structural fracture type^[11], and the exploration was concentrated in structural traps such as fault blocks, fault noses, and fault anticlines on the top surface of basement. It is found from drilling and reservoir analysis that besides the weathering crust in the upper part of basement, there are also fracture-dissolution pore/cave reservoirs developed in deep basement, but their genetic mechanisms of dissolution have not been thoroughly discussed. Based on elemental analysis, carbon and oxygen isotope composition of fracture-filling carbonate minerals, temperature and salinity measurement data of fluid inclusions, test data of formation water, etc., the fluid interaction mechanism and diagenesis reformation of basement fracture-pore reservoirs with epimetamorphic pyroclastic rock are studied in order to deepen the understanding of the formation of basement reservoirs and provide a theoretical basis for the exploration of basement buried-hill in the Hailar Basin from weathering crust to interior.

Hailar Basin is a typical continental rift basin in northeastern China, which, together with Erlian Basin and Yingen- Ejina Basin, belongs to the rift basin groups around the boundary of China and Mongolia. Since the Late Paleozoic Era, affected by temporal and spatial superimposed reformations of 3 tectonic domains of the Paleozoic Paleo-Asian Ocean Tectonic Domain, the Mongolia-Okhotsk Ocean Tectonic Domain before the Mesozoic Early Cretaceous and the Pacific Ocean Tectonic Domain after the Late Cretaceous, the Hailar Basin has formed a tectonic framework of "two uplifts and three depressions"^[12,13]. The Beier Sag located in the southern part of the Beier Lake Depression is one of the most important petroleum-rich sags in the basin, which has 3 hydrocarbon source sub-sags, the east, center and north and 3 positive tectonic units, i.e., western slope zone, central uplift zone, and eastern fault uplift zone (Fig. 1a). The age of basement Budate Group is currently recognized as the Early Carboniferous-Early Permian^[14], and its overlying strata have undergone three major tectonic evolution stages^[15], namely, the rifting stage (Lower Cretaceous Tongbomiao Formation- Nantun Formation), the rifting-depression transition stage (Damoguaihe Formation-Yimin Formation), and the depression stage (Qingyuangang Formation). During the rift stage, the strata have undergone 3 periods of construction and 2 periods of reformation, namely, the initial rifting period of Tongbomiao Formation and its uplift and denudation later (T₃), the strong rifting period during the deposition of Member Ⅰ of Nantun Formation, and the weak rifting period during the deposition of Member Ⅱ of Nantun Formation and the uplift and denudation at the end of Nantun deposition (T₂₂). The major hydrocarbon source rock is the dark mudstone in the lower middle part of the Member Ⅰ of Nantun Formation, and the main producing pays are the Nantun Formation and Tongbomiao Formation in the middle lower plays; some oil is located in the basement, and a small amount is the secondary oil reservoir of the upper play with Damoguaihe Formation (Fig. 1b).

The central uplift zone of Beier Sag, surrounded by two major hydrocarbon source sub-sags in the west and center of Beier Sag, is an important petroleum-rich structural belt in the sag (Fig. 1c). In the secondary structural belts of Huoduomoer and Sudeerte of the central uplift zone, large-scale oil discoveries have been made in main formations such as Nantun Formation, Basement and Tongbomiao Formation. The Sudeerte structural belt is the main petroleum bearing structure of the basement buried-hill, where the wells vary widely in daily oil production, from 0.15 t to 160.00 t with an average of 20 t. The highest daily oil production of a single well in the high-yield reservoir of basement buried-hill in the eastern part of the structural belt is 160 t; the average daily oil production of fault blocks near the sag-controlling fault in the west is 20 t; the average daily oil production per well in the center is 10 t. The main oil producing pay in basement buried-hill found by drilling is located in the weathering crust section (less than 100 m below the top surface of basement), contributing 90% of oil production. In addition, high-yield industrial oil flow has been found in the interior section of basement (135 m below the top surface of basement) of Well B30, with an oil production of over 30 t per day.

The Carboniferous-Permian basement rock in Hailar Basin is a set of terrigenous clastic rock, pyroclastic rock, volcanic rock and transitional rock that have undergone regional epimetamorphism and dynamometamorphism. The effective reservoirs mainly occur in terrigenous pyroclastic rock-normal sedimentary rocks such as andesitic tuff, tuff, tuffaceous sandstone, siltstone^[16], and are characterized by universal-bearing of pyroclastic materials. Therefore, this type of reservoir is collectively referred to as epimetamorphic pyroclastic rock in this paper. The epimetamorphism is characterized by palimpsest texture, particle fragmentation, recrystallization, argillaceous felsitic texture, and feldspar sericitization, etc. The mineral content analysis results of 70 samples show that they have a pyroclastic material content of 8%-95% (on average 54%), normal sedimentary clastic content of 10%-90% (on average 40%), and authigenic mineral content of 5%. Volcanic debris consists of rock debris, crystal pyroclast and a small amount of vitric pyroclast. The rock debris mainly includes andesite debris, tuff debris, and basalt debris, etc., and crystal pyroclast mainly consists of quartzose-crystal pyroclast and feldspar crystal pyroclast. The samples have an average contents of quartz of 31.9%, clay minerals of 25%, plagioclase of 20%, calcite of 15%, ankerite of 13%, dolomite of 9.2%, siderite of 5%, and potash feldspar of 3%. Most of the samples also contain pyrite, anhydrite, anatase and other minerals, and a few samples contain minerals such as augite, glauberite, hematite, analcite, barite, hornblende, pyrotechnite, and tridymite, etc.

The evolution of the basement pyroclastic rock reservoirs in Beier Sag is controlled by diagenetic environment, tectonic action and volcanic activity, and is characterized by compaction, pressolution, cementation, metasomatism, dissolution and supergene weathering leaching^[17], tectonic fracturing, composite superposition of low-temperature hydrothermal alteration and epimetamorphism. The reservoir is characterized by double-porosity, and has two types of reservoir space, namely, fracture and pore, including open fracture, incompletely filled fracture, dissolution pore, and matrix pore.

Fractures are mainly of tectonic origin, and come in high- angle, low-angle and horizontal. Open fractures mainly are medium-high-angle ones with an inclination of 30°-90° (Fig. 2a). The fractures developed in multiple stages are reticular and filled with multiple-stage cements, including quartz, calcite, dolomite, ankerite, kaolinite, chlorite, and pyrite, etc. The incompletely filled space in fractures and the re-dissolution of calcite, dolomite, ankerite and other filled minerals form effective reservoir spaces, including fracture-dissolution pores/caves (Fig. 2b, 2c). During diagenesis, partial dissolution of feldspar, dolomite, ankerite and other particles and dissolution of intermediate-basic tuff gave rise to intragranular and intergranular pores. A small number of residual primary intergranular pores are also an important part of pore space (Fig. 2d-2g). There are also intergranular micropores of authigenic clay minerals (Fig. 2h). Various dissolution pores are communicated by fractures and micro-fractures, greatly improving the physical properties of the reservoirs and forming an interconnected fracture-pore reservoir space network (Fig. 2i).

Superimposed development of pores, caves and fractures is the main characteristic of oil reservoirs with high and stable yield in basement buried-hills. The reservoirs are divided into 4 classes according to core porosity and permeability. Class I reservoir has a porosity of more than 3%, a permeability of more than 1×10^-3 μm², and a porosity of more than 10% and a permeability of more than 100×10^-3 μm² at a few sample points. This kind of reservoir is high-quality reservoir with developed fractures and pores, with an average daily oil output of more than 15 t and relatively stable output. Class II reservoir can be divided into two types: (1) One has a porosity of 2%-3%, a permeability of greater than 0.05×10^-3 μm², primarily fractures and secondarily pores as storage space, unstable output, and fast output reduction. (2) The other has a permeability of (0.05-1.00)×10^-3 μm², a porosity of more than 2%, mainly pores and secondarily fractures as storage space, and relatively stable output. After fracturing, this type of reservoir will have significant increase in output. Class III reservoir has a porosity of 1%-2% or a permeability of (0.02- 0.05)×10^-3 μm² and daily oil output of less than 1 t. Class IV is non-reservoir with a porosity of less than 1% or permeability of less than 0.02×10^-3 μm² (Fig. 3).

The vertical variations of porosity and permeability of basement reservoirs show that with the increase of distance (ΔD) from unconformity surface of basement, porosity and permeability decrease first and then increase locally. The basement can be divided into weathering section and interior section.

The ΔD value of weathering section is 0-80 m, consistent with the weathering crust thickness of 60-80 m revealed by drilling. The reservoirs vary greatly in physical properties, with a porosity of up to 13% and a permeability up to 500× 10^-3 μm². The upper reservoir has obviously better physical properties than the lower reservoir. The porosity and permeability decrease monotonically with the increase of ΔD value, which indicates that the development degree of reservoir is closely related to weathering-leaching of unconformity surface of basement.

The interior section has ΔD value of greater than 80 m, and physical properties decreasing on the whole but increasing locally with the increase of depth. The first reservoir zone with increased porosity and permeability appears when the ΔD value is between 80 m and 120 m, with a porosity of greater than 3% and permeability of greater than 1×10^-3 μm², reaching the threshold of class I reservoir. The second possible reservoir zone appears when the ΔD value is between 205 m and 220 m, with permeability obviously increasing while the porosity not increasing obviously due to the small number of samples. This indicates that there are one or more reservoir zones in the deep part of interior basement which are not fully revealed by drilling. These reservoir zones, developed within a certain depth range in the longitudinal direction, have little relation with the unconformity surface and are controlled by the action scope and degree of deep dissolution fluid (Fig. 4).

During the process of exposure and burial, the basement has undergone reformation by various fluids from shallow surface and deep underground, which control the development degree of reservoir. Faults and fracture zones are areas with active fluid migration and material exchange. Research on the geochemical characteristics of fracture fillings is one of the effective means to study fluid action. According to the test and analysis results of carbon and oxygen isotope composition, fluid inclusion and rock element content, the diagenetic fluids in the study area include atmospheric freshwater mainly acting on the shallow layer of basement and deep magmatic hydrothermal, organic acid and hydrocarbon-bearing fluids mainly acting on the deep layer of interior basement. The formation and reformation of reservoir by fluids are shown in two aspects: (1) Under the effect of alkaline fluid, the calcite, dolomite, ankerite and other veins fill in the fractures to block the fracture space; (2) Acid fluid flow along fractures and microfractures, dissolving easily soluble components such as carbonate and tuffaceous to form a large number of dissolution pores connecting with fractures, greatly improving the physical properties of reservoir.

Cathodoluminescence test and analysis shows that the fractures are mainly filled with siliceous and calcareous materials. Siliceous fillings representing acidic fluid are developed in at least two stages. The early fracture fillings are cryptocrystalline quartz with dark blue cathode light, and the late fracture fillings are cryptocrystalline-phanerocrystalline quartz with blue cathode light. Calcareous fillings representing alkaline fluid are mainly calcite, which developed in at least 2 stages. The early calcite emits dark yellow cathode light; and the late calcite emits orange cathode light, cutting through the early calcite or filling in the middle of the fracture in juxtaposition with the early calcite (Fig. 5).

The results of element content test by X-ray fluorescence show that the samples from the study area have average SiO₂, Al₂O₃, Fe₂O₃, CaO, CO₂, Na₂O, MgO, K₂O contents of 55.4%, 3.2%, 7%, 5.6%, 4.9%, 2.9%, 2.9%, and 2.1% respectively, and contain trace elements like P, S, Ti, Mn, Sr, and Ba, etc. In humid environment, the leaching loss of Sr is large, so Rb/Sr value will be high and Sr/Ba value will be low, while in arid environment, the situation is the opposite^[18]. Samples collected from the study area have low Rb/Sr values, ranging from 0.01 to 1.03, 0.15 on average; and high Sr/Ba values, ranging from 0.1 to 6.5, 1.6 on average, indicating that the study area was in an arid environment. In terms of weathering crust index K of clastic rock^[19], the samples have a index range from 14.5 to 39.7, with an average value of 22.9 (except two samples with small values), indicating that the study area was in semi-weathering zone (Fig. 6).

During the weathering-leaching of basement, acidic fluid formed through dissolving CO₂ in the atmospheric freshwater dissolved easily soluble components in reservoir, improving the physical properties of reservoir^[20]. Due to the different migration capabilities of different elements, the unconformity surfaces are characterized by enrichment of inactive elements such as Al₂O₃ and Fe₂O₃, relative enrichment of relatively stable elements such as SiO₂, and loss of easily migratable alkali and alkaline earth metal elements (CaO, Na₂O, K₂O, MgO)^[19]. The relationship between the major element content and ΔD shows that the inactive elements such as Al₂O₃ and Fe₂O₃ have little change on the whole, and the content of relatively stable element such as SiO₂ decreases slowly with the increase of ΔD (Fig. 6). When the ΔD value is 0-40 m, the contents of CaO, Na₂O, K₂O, and MgO etc. increase with the increase of ΔD value, indicating that the surface water leached basement from the top down, thus dissolving the calcite and feldspar etc., resulting in the downward migration of leachable elements. When the ΔD value is 40-60 m, the CaO content increases with the increase of ΔD value, while the contents of Na₂O, K₂O, MgO, and Fe₂O₃ etc. decrease with the increase of ΔD value, indicating that calcite may have precipitated. When the ΔD value is 60-80 m, the CaO content decreases with the increase of ΔD value, while the contents of Na₂O, K₂O, MgO, and Fe₂O₃ etc. increase with the increase of ΔD value, indicating that metasomatism of dolomite and ankerite may have occurred. The migration variations of elements show that the leaching by atmospheric fresh water causes the active elements to migrate downward from the top surface of basement and accumulate in the lower part, the upper part has higher degree of dissolution and reservoir development than the lower part, and the acting range is consistent with the thickness (60-80 m) of weathering-leaching zone in this area (Fig. 6).

3.2.1. Magmatic hydrothermal fluid

Test data of 44 fluid inclusions from 4 samples taken from Well B40 shows that the calcite filling in early fractures which emits dark yellow cathode light contains 3 stages of primary saline inclusions with average homogenization temperatures of 66.6, 167.4 and 192.8 °C respectively and a mean salinity of 7.4% (Figs. 7 and 8); the calcite filling late fractures which emits orange cathode light has 1 stage of primary saline inclusion with an average homogenization temperature of 91.2 °C. According to the analysis of burial history and thermal evolution (Fig. 9), the homogenization temperature of primary inclusions shows that the early low-temperature calcite was formed 132 Ma ago, corresponding to the period from late Member Ⅰ to early Member Ⅱ of Nantun Formation, and the fluid was brackish formation water in the compaction basin; and the high-temperature calcite originates from magmatic hydrothermal fluid, as the homogenization temperature of the inclusions is higher than the highest paleotemperature experienced by the stratum. The late calcite was formed 126 Ma ago, corresponding to the late Member Ⅰ and the early Member Ⅱ of Damoguaihe Formation.

3.2.2. Hydrocarbon-bearing fluid

In the calcite emitting dark yellow cathode light filling early fractures, there are four stages of secondary saline inclusions, with average homogenization temperatures of 114.2, 65.1, 85.4 and 106.5 °C (Figs. 7 and 8), respectively. Among them, the inclusions with an average homogenization temperature of 114.2 °C have a salinity range from -5.1% to -4.9%, the low salinity indicates that the fluid is hydrocarbon-bearing saline. The calcite emitting orange cathode light filling in the late fractures contains one stage of secondary saline inclusions with an average homogenization temperature of 116.8 °C (Figs. 7 and 8). According to the analysis of burial history and thermal evolution (Fig. 9), the capture time of the higher-temperature secondary hydrocarbon-bearing saline inclusions was 108-112 Ma ago, corresponding to the period from late Member Ⅰ to early Member Ⅱ of Yimin Formation. This period is the main hydrocarbon generation and expulsion period of hydrocarbon source rock in the Nantun Formation ^[21,22]. Calcite was reformed by hydrocarbon-bearing fluid in this period after deposition, which inhibited pore cementation of the reservoir to a certain extent.

3.2.3. Organic acid

Fluorescence test results show that calcite filling in fractures contains two stages of secondary oil inclusions, with one stage emitting blue-green fluorescence and the other of yellow-green fluorescence. The blue-green fluorescent oil inclusions have a homogenization temperature from 100.3 °C to 105.2 °C, and 102.8 °C on average (Figs. 7 and 8), and the secondary saline inclusions contemporaneous with the blue- green fluorescent oil inclusions have a homogenization temperature from 117.3 °C to 123.3 °C, 119.8 °C on average (Fig. 8), and mean salinity of 7.0%. According to the analysis of burial history and thermal evolution (Fig. 9), the timing of hydrocarbon charging started from the late depositional stage of Member Ⅰ to the depositional stage of Member Ⅱ and Member Ⅲ of Yimin Formation. The regional study of Hailar Basin shows that the hydrocarbon source rock of Nantun Formation began to generate hydrocarbons in the early depositional stage of Yimin Formation, and reached the peak of hydrocarbon generation in the late depositional stage of Yimin Formation^[21,22], which is consistent with the conclusion obtained from the secondary saline inclusions contemporaneous with the blue-green fluorescent oil inclusions. At this time, the hydrocarbon source rock released a large amount of organic acids which had strong dissolution effect on the reservoir.

3.2.4. Fluid source

Carbon and oxygen isotopic compositions of carbonate cements can effectively indicate the source of fluid. Different types of fluids differ in carbon isotopic composition. Therefore, carbonate cements precipitated after different fluids provided carbon sources have different carbon isotopic compositions^[23]. The test data of carbon and oxygen stable isotopic composition of carbonate cements filling in fractures in the study area show that (Table 1) the δ¹³C values mainly range from -6‰ to -2‰, but one calcite vein sample has a low value of -11.03‰ and one marble vein sample has a high value of -0.32‰. The δ¹⁸O values are mostly lower than -23‰, mainly in the range of -27‰ to -16‰, and the value of the marble vein sample is -8.32‰. In general, decarboxylation of organic acids provides a lighter carbon source, with δ¹³C values as low as -23‰--8‰, and δ¹³C value below -8‰ is considered the indication of organic carbon mixing. The carbon source provided by atmospheric freshwater is relatively heavy, with δ¹³C value generally ranging from -4‰ to -1‰, and δ¹³C values of carbon source provided by seawater range from 0 to 3‰^[24]. If the value of oxygen isotope composition of carbonate cements is negative, the fluid generally comes from atmospheric freshwater or magmatic hydrothermal fluid^[25]. Combined with temperature measurement data of fluid inclusions, it is concluded that the mixing of magmatic hydrothermal fluid has resulted in the negative value of oxygen isotope composition of carbonate cements. The distribution of carbon isotope composition values (Table 1) and the carbon-oxygen isotope composition chart (Fig. 10) jointly show that carbonate cements are affected by the mixing of inorganic carbon and organic carbon sources, and the fluids bringing carbon include atmospheric freshwater, organic acid and deep inorganic hydrothermal fluid.

3.2.5. Fluid pathway

The formation water in Hailar Basin is characterized by high salinity and high HCO₃^- content. The formation water has a total salinity of 1800-25 000 mg/L, on average 8600 mg/L, and the HCO₃^- content accounts for 45%-60% of the total salinity, followed by Na, K, CO₃^2-, SO₄^2- and so on^[26]. The majority of formation water samples from the study area are NaHCO₃ type, a small number of formation water samples are MgCl₂ type and Na₂SO₄ type, indicating there is shallow surface water and deep fluid mixing into the formation water. The dawsonite found in Tongbomiao Formation and Nantun Formation indicate that a large amount of deep inorganic CO₂ intrusion occurred in this area^[27]. Researches on CO₂ content and carbon isotope composition show that the high content of HCO₃^- is the result of deep inorganic CO₂ invasion originated from magma-volcanic rock having chemical reaction with formation water, and the high concentration of Na⁺ is related to the dissolution of albite^[26].

It can be seen from the plane distribution of formation water (Fig. 11), the salinity increases obviously near the dis-cordogenic fault connecting basement, and decreases inside the fault blocks far away from the discordogenic fault, which indicates that the deep fault was fluid ascending pathway and affected the salinity of formation water. The deep CO₂-rich hydrothermal fluid rose along the discordogenic fault, CO₂ dissolved in water and reacted with water to generate H⁺ and HCO₃^-, thus causing the HCO₃^- content in formation water to increase significantly, and the increase amount was significantly larger than that of CO₃^2-. The increase of H⁺ content would cause the environment to become acidic, then the Na⁺ and Ca²⁺ were released due to dissolution of albite and anorthite. At the same time, some Ca²⁺ would combine with CO₃^2- to produce carbonate cements, leading to the fall of Ca²⁺ concentration and rise of Na⁺ content in the formation water.

At Late Permian, the paleo-Asian Ocean was finally closed, and the Sino-Mongolia block underwent intracontinental orogeny. The Hailar Basin was located at active continental margin, where the formation of large-scale nappe structures led to lateral shortening and vertical thickening of the rock strata^[12], resulting in basic magma underplating and the exchange and circulation of crust and mantle materials, frequent volcanic and subvolcanic activities; so the basement rocks of Beier Sag include intermediate-basic volcanic rocks and shallow intrusive rock such as basalt, dacite and diorite porphyrite, pyroclastic rock such as tuff, as well as other transitional assemblage rock series with terrigenous clastic rock. This was the initial consolidation diagenesis stage of basement, when compaction and cementation happened (Fig. 12), but a small amount of primary pores were preserved locally (Fig. 2g).

In Jurassic, Hailar Basin experienced regional tectonic uplift in late orogenic period. Beier Sag suffered long-term depositional break and weathering denudation, forming unconformity surface on top of Carboniferous-Permian basement. During this period, weathering and top-down leaching of atmospheric freshwater happened, as a result, unstable components and fine-grained materials were carried away by leaching, and carbonate and feldspar were dissolved, forming dis-solution pores and caves in the reservoir section of weathered crust (Fig. 2b, 2d), which was the first major development period of dissolution reservoir (Fig. 12). The scope of action was 60-80 m below the unconformity surface.

In the early Cretaceous, Hailar Basin entered the stage of extensional collapse after orogeny. The basin was characterized by extensional shear deformation dominated by NE-direction tension^[15], and accepted sediments above the basement. The evolution of basement reservoir had different characteristics in different tectonic evolution stages. In the initial sedimentary rifting period of Tongbomiao Formation, extension faulting just begun, and the sedimentation was in the form of filling and leveling, with relatively weak volcanic intrusion. From the strong rifting period to the weak rifting period during the deposition of Member Ⅰ-Member Ⅱ of Nantun Formation, strong rifting induced the upwelling of mantle materials, and volcanic activities and sub-volcanic activities were intense, with Nantun Formation strongly arched at a high angle or even right angle on the seismic profile. Magma upwelled along the discordogenic faults and invaded the sedimentary strata, leading to the interruption of the original parallel continuous seismic events of the sedimentary strata or irregular contact with the intrusive body (Fig. 1c). At this time, a large amount of high temperature fluid rich in CO₂ released from the magmatism rose along the discordogenic faults and tectonic fissures, metasomatizing and altering wall rocks. Consequently, multi-stage quartz and carbonate mineral filling cements in network-like and vein-like, pyrite and chlorite cementation, and ankerite metasomatism developed in the tectonic fractures and fault zones (Fig. 5). As hydrothermal activity got stronger and temperature got higher, a large amount of CO₂ was brought into the reservoir from the deep, resulting in increase of its partial pressure and some dissolution to the carbonate minerals formed previously^[29], so in this stage, cementation and dissolution took place simultaneously, but cementation took dominance (Fig. 12).

During the rifting-depression transition stage when the Damoguaihe Formation-Yimin Formation deposited, except for the large sag control fault, many faults formed in the rifting period stopped activity. It can be seen from the seismic profile that these faults are below the T₂₂ interface (Fig. 1c). The hydrocarbon source rock in Nantun Formation began to mature during the sedimentary period of Yimin Formation, and reached the hydrocarbon generation peak in the late sedimentary period of Yimin Formation, so the hydrocarbon charging had certain inhibition on reservoir cementation. When maturing, the hydrocarbon source rock generated a large amount of organic acid, dissolving calcite, ankerite, dolomite, feldspar and intermediate-basic tuffaceous in the basement rock connecting with the hydrocarbon source rock through faults and fractures. This was the second major development period of dissolution reservoir (Figs. 2c, 2e, 2f, 5e and 12). Studies before have shown that the dissolution of organic acid to carbonate cements have two mechanisms: one is to directly dissociate H⁺ to dissolve carbonate cements, the other is to dissolve carbonate cements by carbonic acid generated by dissolving CO₂ (from decarboxylation) in water^[30].

Deep magmatic hydrothermal fluid rising from the fault promoted the dissolution on reservoir. The comparison of dissolution rate of organic acid to calcite and dolomite shows that the dissolution rate of dolomite is lower than that of calcite at lower temperature and pressure (about 60-90 °C), while the dissolution rate of dolomite becomes gradually higher than that of calcite when the temperature and pressure increase gradually (higher than 90 °C)^[31]. Thus, a large amount of dissolution pores of dolomite and ankerite can be seen in the samples from the study area under microscope, which is related to the heating effect of magmatic hydrothermal fluid. Besides, from the changes of formation lithology in Beier Sag, the volcanic lava and pyroclastic rocks from basement to Damoguaihe Formation transition from basalt, andesite, dacite and other intermediate-basic rocks to acidic rocks such as rhyolite. At this period, the nature of magmatic hydrothermal fluid changed from alkalescence in rifting period to acidity rich in H₂S, SO₂, HF and HCl in rifting-depression transition stage, thus further dissolving feldspar, carbonate minerals, and tuff etc. to produce secondary pores. Therefore, in the second development period of dissolution reservoir, the organic acid and deep magmatic hydrothermal fluid worked jointly, and the acting scope was the deep layer below the weathered zone of unconformity surface, i.e. 80 m below the top surface of basement and deeper. After the deposition of Qingyuangang Formation, the basin entered depression period, when all fault and volcanic activities basically stopped, the organic acid produced by the hydrocarbon source rock gradually reduced, and the dissolution and reformation of basement reservoir basically completed.

Therefore, the development of high-quality reservoir in the basement of Beier Sag depended on two major factors, namely the supergene weathering leaching in Jurassic Period, and the combined dissolution of organic acids from hydrocarbon source rock and deep hydrothermal fluid in late Early Cretaceous. Hence, there are two reservoir zones vertically, the weathering crust near the unconformity surface of basement, and the interior basement. Horizontally, the distribution of reservoir on weathering crust is controlled by paleotectonic conditions in exposure period. In the areas with high palaeostructure and heavy weathering-leaching, the reservoir of weathering crust is well developed. In contrast, the distribution of interior reservoir is controlled by discordogenic faults, and the contact of basement with the hydrocarbon source rock. The interior reservoir is well developed in the areas where faults and fractures communicated with deep fluid or the basement is in direct contact with or connected with the hydrocarbon source rock through fractures.

There are two types of reservoirs developed in the basement of epimetamorphic pyroclastic rocks in Beier Sag, namely fracture reservoir and pore-cave reservoir. Origins of the pore-cave reservoir include the dissolution of calcite, dolomite, ankerite and other carbonate minerals, or the dissolution of feldspar particles or tuff. There are a small amount of residual primary pores and authigenic mineral intergranular micropores in this kind of reservoir. There are two sets of reservoirs in the basement, the weathering section and interior section. The interior section has high-quality reservoir zone, with a porosity of greater than 3% and permeability of greater than 1×10^-3 μm², reaching the threshold of Class I reservoir.

The basement reservoir was formed through complicated interactions between fluid and rocks, including the leaching of atmospheric freshwater, and the dissolution of deep magmatic hydrothermal fluid rising along discordogenic faults, organic acid and hydrocarbon-bearing fluid released during hydrocarbon generation and expulsion from hydrocarbon source rock.

The diagenetic reformation of basement reservoir can be divided into 4 stages, namely initial consolidation diagenesis stage, early supergene weathering-leaching stage, middle structural fracture-cementation-dissolution coexistence stage and late combined dissolution stage of organic acid and magmatic hydrothermal fluid. Among them, early supergene weathering-leaching stage and late combined dissolution stage of organic acid and magmatic hydrothermal fluid are the two major dissolution stages, as well as the main genesis and formation stages for the two sets of pore-cave reservoirs in the shallow weathering crust and interior of basement buried-hill.

Oil reservoirs in the weathering crust near the unconformity surface of basement buried-hill have been discovered in Hailar Basin. Systematic drilling of the interior basement hasn’t been carried out. Given the formation mechanism of the reservoir by deep fluid dissolution, more attention should be paid to the exploration of oil and gas reservoirs inside the basement, to expand the exploration scope to deep basement formations actively.