As a unique phenomenon in the stratigraphic pressure system, strata with abnormally high pressure have become a research focus in petroliferous basins for more than 70 years since they were discovered in the Gulf of Mexico in 1951^[1]. Abnormally high pressure has an important influence on reservoir compaction strength^[2], clay mineral transformation and cementation^[2,3,4], hydrocarbon generation window and hydrocarbon generation time of source rocks, dissolution strength^[5,6], fracture development and reservoir flow capacity^[7], and thus directly affects the quality of the reservoir. Generally, reservoirs under abnormally high pressure should have better physical properties, and high-quality reservoirs are relatively developed. However, in practical exploration, reservoirs with low porosity and low permeability, or extremely low porosity and extremely low permeability similar to those at normal pressure still exist at abnormally high pressure, and these reservoirs show strong heterogeneity. To understand the development mechanism of high-quality reservoirs and predict their distribution at middle to deep depth at abnormally high pressure, it is necessary to study the heterogeneity characteristics and influencing factors of these reservoirs.

Reservoirs at abnormally high pressure are mostly distributed in marine multi-cycle superposed basins in China. As a typical representative of abnormally high pressure basins in China, and with increasing exploration and development, a series of giant gas fields have been found in DF, LD and other blocks in the Yinggehai Basin. Especially in recent years, Zhanjiang Branch of CNOOC Ltd. has made a breakthrough in the exploration of marine gravity flow tight sandstone of the Miocene Huangliu Formation in LD block and found a giant gas field in the LD10 block. Previous studies on the Huangliu Formation in the Yinggehai Basin have mainly focused on reservoir sedimentary characteristics and sandbody development mechanisms^[8,9], the effect of abnormally high pressure on reservoir diagenesis^[10], reservoir characteristics and high-quality reservoir development mechanisms^[11], the relationship between formation water and oil and gas^[12], pore throat structure characteristics under abnormally high pressure^[13], abnormally high porosity zones and favorable oil and gas accumulation areas etc.^[14,15]. However, research on reservoir heterogeneity under abnormally high pressure is still weak. In this paper, the Miocene Huangliu Formation in the LD10 block of the Yinggehai Basin is taken as the research object. The heterogeneity characteristics and the evolutionary process of reservoir heterogeneity are analyzed, and the factors influencing heterogeneity are clarified, based on the study of reservoir micro characteristics, which provides a reference and ideas for the development mechanism of high-quality reservoirs and favorable reservoir distribution prediction of the Huangliu Formation in the LD10 block.

The Yinggehai Basin is a NW-SE-trending Cenozoic conversion-extension basin at high temperature (the geothermal gradient is approximately 4.6 °C/100 m) and abnormally high pressure (the maximum pressure coefficient is 2.3) with a total area of 11.3×10⁴ km^2[16,17]. It is one of the main areas for offshore natural gas exploration in China. From west to east, the basin is composed of three first-order structural units: the Yingxi slope, the Central depression and the Yingdong slope. The study area (LD10) is located in the depression slope zone between the diapir zone of the Central depression and the Yingdong slope (Fig. 1a). Its tectonic evolution has experienced two stages: syn-rift and post-rift. The syn-rift stage includes a faulting period (28.5 to 66.0 Ma) and a fault-depression period (23.0 to 28.5 Ma); the post-rift stage includes a thermal subsidence period (5.5 to 28.5 Ma) and an accelerated thermal subsidence period (0 to 5.5 Ma)^[18]. The basin is characterized by strong subsidence, rapid filling, high temperature and overpressure, diapir development. From bottom to top, there are Paleogene Eocene Lingtou Formation (E₂l), Oligocene Yacheng Formation (E₃y), Lingshui Formation (E₃l), Neogene Miocene Sanya Formation (N₁s), Meishan Formation (N₁m), Huangliu Formation (N₁h), Pliocene Yinggehai Formation (N₂y) and Quaternary Ledong Formation (Ql) (Fig. 1b), which are approximately 17 km thick^[16]. Two kinds of depositional facies developed in the Huangliu Formation, including shallow marine canyon channel and submarine fan. The second member of the Huangliu Formation (N₁h₂) in LD10 block is deposits of canyon channels, which is generally distributed in the NW direction along the long axis of the basin. Submarine fans are developed both in the first member of the Huangliu Formation (N₁h₁) and the second member of the Huangliu Formation (N₁h₂)^[19], in which the developed deep-water gravity flow sandbody is the main target of natural gas exploration in the study area.

Previous studies have shown that rapid subsidence in the late stage is an essential condition for the formation with abnormally high pressure in the Yinggehai Basin^[20]. Mudstone under compaction contributed primarily, while tectonic compression, fluid thermal pressurization and hydrocarbon charging contributed less for the formation of abnormally high pressure^[20]. According to the pressure classification standard in the Technical Guide for Formation Pressure Prediction and Detection (Q/HS 1023-2007) in the enterprise standard of CNOOC Ltd., the formation pressure system is divided into a normal pressure zone (pressure coefficient of less than 1.20) and an abnormally high pressure zone (pressure coefficient of greater than 1.20). The abnormally high pressure zone is further subdivided into a pressure transition zone (the pressure coefficient ranges from 1.20 to 1.70), an overpressure zone (the pressure coefficient ranges from 1.70 to 1.95) and a strong overpressure zone (pressure coefficient of greater than 1.95)^[21]. The results of modular stratigraphic dynamic tests (MDT) in 8 wells in the LD10 block show that the pressure coefficient is 1.20 at approximately 2250 m (middle and lower parts of the Yinggehai Formation), and the pressure begins to enter a transition zone. The present pressure coefficient of the Huangliu Formation ranges from 1.37 to 2.30, and averaged 1.85. The overpressure zone is mainly located in the middle and upper parts of the Huangliu Formation (N₁h₁). The strong overpressure zone is mainly located in the middle and lower parts of the Huangliu Formation (N₁h₂). The pressure transition zone has been detected only in wells LD-C1 and LD-A5.

This study collected 167 sandstone samples (41 samples from the overpressure zone and 126 samples from the strong overpressure zone) of the Huangliu Formation at different depths (3710 to 4412 m) from 8 key wells in the LD10 block of the Yinggehai Basin and 30 sandstone samples from the normal pressure zone with similar depths (3462 to 4200 m) from 4 key wells in the BD19 block of the Qiongdongnan Basin to study the differences of reservoir heterogeneity and diagenesis-porosity evolution between normal pressure zone and abnormally high pressure zone. These samples were mainly used for thin sections, X-ray diffraction (XRD) of whole-core and clay minerals, pore throats, high-pressure mercury injection and other tests. The BD19 area in the Qiongdongnan Basin is adjacent to the LD10 area. In addition, data from 20 modular stratigraphic dynamic tests, cuttings logs and buried thermal history data from 13 wells, 80 SEM photos, 65 images of granularity analysis and physical property data from 197 cores were collected from Zhanjiang Branch of CNOOC Ltd.

(1) Thin section analysis: A 25 mm diameter drill string was vacuumized and injected with blue epoxy resin, and then rock thin sections of 0.03 mm thick each were grounded and dyed with alizarin red and potassium ferricyanide mixture. All the prepared thin sections were observed by a multifunctional polarizing microscopy, and at least 300 points were observed on each section for quantitatively counting the content of components in the thin sections. (2) X-ray diffraction (XRD): First, the samples were crushed, and grounded with ethanol. Then, the samples were dried at 60 °C and separated by centrifugation, powder samples with particle size less than 2 μm were extracted and analyzed by X-ray diffraction at 104300 Pa and 18 °C to determine the content of clay minerals. (3) Pore throat image analysis: On the basis of thin section observation, the pores and throats in the field of view of each thin section were characterized by the digital instrument with a color image analysis system, and each field of view was characterized by at least 250 points to obtain the main micro-pore throat parameters.

(4) High pressure mercury injection analysis: The mercury was injected into the cylindrical sandstone sample with an intact appearance and no cracks, approximately 2.5 cm in diameter at 104 300 Pa and 18 °C until the pressure reduced when the mercury saturation was to the maximum. The injected volume and pressure were recorded as mercury entered and exited. The mercury injection curve was drawn according to the data recorded. All experiments were carried out in the State Key Laboratory of Continental Dynamics, Department of Geology, Northwest University.

The heterogeneity of tight sandstone reservoir refers to the differences in the framework mineral composition, textural maturity, content and type of fillings, pore throat structures and physical properties^[22,23]. By comparing the heterogeneity of framework mineral composition, textural maturity, fillings, pore throat structures and physical properties at abnormally high pressure and those at normal pressure, the heterogenous reservoir characteristics at abnormally high pressure are systematically studied.

According to the sandstone classification standard provided by Folk^[24], the sandstones of the Huangliu Formation in the overpressure zone and the strong overpressure zone are mainly feldspathic litharenite (Fig. 2a). They have similar framework mineral compositions and contents. The sandstones in the overpressure zone and strong overpressure zone have the average contents of quartz of 51.9% and 52.9%, the average contents of feldspar of 11.2% and 11.3%, and the average contents of debris of 15.0% and 14.2%, respectively. The feldspar includes mainly alkaline feldspar (average of 9.9%) and a small amount of plagioclase (average of 1.4%). The debris includes mainly metamorphic rock, followed by igneous rock and sedimentary rock (Fig. 2b). The textural characteristics of the sandstone in the overpressure zone and the strong overpressure zone are basically the same. The particles are mainly subangular to subrounded (accounting for 73.4%). The average grain sizes mainly range from 0.25 to 0.50 mm (accounting for 51.3%). The grains in the overpressure zone have better sorting than that in the strong overpressure zone. The former is poorly to moderately sortable (41.5% and 34.1%, respectively), and the latter is moderately to poorly sortable (45.2% and 37.3%, respectively). The reservoir rocks in the BD19 block in the normal pressure zone include mainly feldspathic litharenite (Fig. 2a) where the average content of quartz is 53.0%, the average content of feldspar is 8.5% (mainly alkaline feldspar, average of 8.3%), and the average content of debris is 20.5% (mainly metamorphic rock,average of 18.9%) (Fig. 2b). The roundness is mainly subangular to subrounded (accounting for 82.5%). The grain sizes are generally lower than 0.25 mm (accounting for 42.9%) with moderate grain sorting (accounting for 57.1%).

The Huangliu Formation reservoirs in the overpressure zone and the strong overpressure zone and the normal pressure zone at the similar depth in the two study area have basically the same lithology, mineral composition and content, rock textural maturity and degree of heterogeneity (Fig. 3a-3f). It implies that they came from the same source and parent rock during the depositional period of the Huangliu Formation. The heterogeneity of framework minerals and textural maturity in the two areas is relatively weak.

The observation and identification results of thin sections and analysis of XRD show that in the abnormally high-pressure zone of the Huangliu Formation in LD10 block and the normal pressure zone of BD19 block, fillings in sandstone pores include argillaceous matrix, carbonate minerals (calcite, ferrocalcite, dolomite, ferrodolomite, and siderite), authigenic clay minerals (illite, illite/smectite mixture, chlorite, and kaolinite), pyrite and silica cements. There is less synsedimentary argillaceous matrix in the sandstone, only 0 to 14.5%, and averaged 2.7%, 1.1% and 0.5% in the normal pressure zone, the overpressure zone and the strong overpressure zone respectively, therefore it has a very limited impact on the reservoir heterogeneity. The heterogeneity of fillings is mainly reflected in the types and contents of cements formed in the process of diagenesis.

There are some differences in the diagenetic cements of the reservoirs in the normal pressure zone, the overpressure zone and the strong overpressure zone, which are mainly carbonate minerals (average of 14.4%, 9.3% and 8.2%, respectively) (Fig. 3g). The primary carbonate component is ferrocalcite which has a wide range of content in reservoir at the normal pressure with the highest proportion of the carbonate cement (average of 87.5%). The cement heterogeneity is the strongest. The content of ferrocalcite cement gradually decreases from the normal pressure zone (0.1%-37.0%, average of 12.6%) to the overpressure zone (0-27.5%, average of 8.0%) to the strong overpressure zone (0-25.0%, average of 5.4%). In the normal pressure zone, overpressure zone and strong overpressure zone, the primary component of authigenic clay minerals (average contents of 5.1%, 4.4% and 3.7%, respectively) is illite, which is slightly higher in the normal pressure zone (average of 2.8%) than that in the overpressure zone (average of 2.1%) and strong overpressure zone (average of 2.6%). The siliceous cement also shows the same trend (average contents of 1.0%, 0.5% and 0.2%, respectively) (Fig. 3g). It is suggested that the abnormally high pressure has certain inhibition on the formation of ferrocalcite, clay minerals and siliceous cements in the reservoir, and this inhibition gradually increases with the increase of formation pressure, resulting in the gradual weakening of the reservoir heterogeneity caused by the primary cements. Authigenic pyrite shows a slightly increasing trend from the normal pressure zone (average of 0.1%) to the overpressure zone (average of 0.2%) and the strong overpressure zone (average of 0.3%) (Fig. 3g). This is because pyrite is developed under strong reduction conditions. The reservoir in the strong overpressure zone is deeper and tends to be a strongly reduced diagenetic environment, resulting in the formation of more authigenic pyrite in deeper layers.

Other cements such as calcite, dolomite, ferrodolomite, siderite, pyrite, siliceous mineral, clay mineral and argillaceous matrix are locally high, but the overall content is low. They have little influence on the reservoir heterogeneity (Fig. 3g). Thus, ferrocalcite is the primary cement that affects the difference in fillings contents and causes strong heterogeneity of fillings under different pressures.

The observation results of thin sections and analysis of pore throats image show that pores in the normal pressure zone, overpressure zone and strong overpressure zone are dominated by secondary dissolved pores (averaged 88%, 63% and 80%, respectively), including intergranular dissolved pores, dissolved feldspar pores, dissolved debris pores and dissolved carbonate pores, followed by intergranular pores and a small amount of microfractures. The surface porosity, percent of various pore types, pore radius, throat width and average pore/throat ratio in the normal pressure zone are less than those in the overpressure zone, especially less than those in the strong overpressure zone (Table 1).

The analysis results of high-pressure mercury injection show that under different formation pressures, the pore throat structure of the reservoir is different. From the normal pressure zone to the overpressure zone to the strong overpressure zone, the displacement pressure and the median pressure gradually decrease, the median radius gradually increases, the pore throat sorting coefficient and variation coefficient gradually decrease, and the mercury injection rate gradually increases (Table 2). The mercury withdrawal efficiency is the highest in the strong overpressure zone, followed by the normal pressure zone, and the lowest in the overpressure zone (Table 2). Overall, from the normal pressure zone to the strong overpressure zone, with the increase in the pressure coefficient, the percent of pores and the surface porosity increase, the pore diameter and throat width become larger, the throat sorting and connectivity improves, the throat structure and reservoir properties become better, and the throat heterogeneity becomes weaker.

According to the mercury injection parameters and curve shape, the pore throat structures of the reservoir in the abnormally high pressure zone can be divided into three types. Type I has the lowest displacement pressure, the highest mercury injection saturation and mercury withdrawal efficiency, and the pore throat structures and physical properties are the best, the heterogeneity is the weakest (Table 3). Type I samples are the majority in the strong overpressure zone which account for 74% of all type I samples. The displacement pressure of type II increases, the mercury injection saturation and mercury withdrawal efficiency decrease, the pore throat structure is better, and the physical properties and heterogeneity of this type of samples are medium (Table 3). Type II samples distribute in both overpressure and strong overpressure zones (accounting for 43% and 57% of all type II samples, respectively). Type III samples show the highest displacement pressure, and the lowest mercury injection saturation and mercury withdrawal efficiency. Their corresponding pore throat structures and physical properties are the worst, and their heterogeneity is the strongest (Table 3). Type III samples are mainly from the overpressure zone (accounting for 68% of all type III samples). In summary, with the increase of formation pressure, the heterogeneity of pore structures becomes weaker and the pore structures become better.

Statistics of physical properties show that, in the normal pressure zone, the porosity ranges from 3.20% to 12.00%, and the permeability ranges from 0.05×10^-3 μm² to 9.50×10^-3 μm²; in the overpressure zone, the porosity ranges from 1.00% to 14.00%, and the permeability ranges from 0.05×10^-3 μm² to 5.51×10^-3 μm²; in the strong overpressure zone, the porosity ranges from 1.00% to 16.00%, and the permeability ranges from 0.05×10^-3 μm² to 33.7×10^-3 μm². From the normal pressure zone to the overpressure zone to the strong overpressure zone, the average porosity (7.27%, 7.83% and 8.60%, respectively) and average permeability (0.57×10^-3, 0.69×10^-3 and 1.75×10^-3 μm², respectively) increase gradually (Fig. 4a, 4b). At normal pressure, as the burial depth increases, the reservoir physical property gradually weakens (Fig. 4a, 4b), when the burial depth is more than 3400 m, the reservoirs are dominated by extremely low porosity and extremely low permeability, and tight reservoirs (Fig. 4c, 4d). At abnormally high pressure, at the similar depth, the reservoirs are mainly extremely low porosity and extremely low permeability ones, followed by low porosity, low permeability and tight ones (Fig. 4c, 4d). But in the deeper zone, the porosity and permeability of the reservoir abnormally increases (Fig. 4c, 4d). Porosity and permeability are positively correlated in the three pressure zones, which indicate that the flow capacity is mainly affected by matrix pores (Fig. 4e). Abnormally high pressure mainly affects the porosity and then controls the permeability of the reservoir.

In summary, because the heterogeneity of framework mineral composition and textural maturity is weak, the heterogeneity in the overpressure and the strong overpressure zones of the Huangliu Formation reservoir is mainly determined by the heterogeneity of cements and pore throat structures, and consequently the reservoir heterogeneity. The cement heterogeneity is mainly controlled by the cementation strength of ferrocalcite. The heterogeneity of pore throat structures is mainly controlled by the difference of the pore throat structures. Compared with the reservoir in the normal pressure zone, with the increase of the pressure coefficient, the heterogeneity of cements and pore throat structures in the overpressure zone and the strong overpressure zone gradually weaken, resulting in weaker reservoir heterogeneity and better physical properties in the strong overpressure zone (middle and lower parts of the Huangliu Formation) than those in the high overpressure zone (middle and upper parts of the Huangliu Formation).

Compaction is an important diagenetic process that affects the heterogeneity of reservoir. In general, in the reservoir in the normal pressure zone, compaction becomes stronger with the increase of burial depth, and the contact among grains gradually transits from point to point and point to line in shallower layers to line to line and line to concave-convex in deep layers, and sutures are visible locally^[25].

According to Beard et al.^[26], before the diagenesis, initial reservoir porosity was affected by grain sorting. He proposed a Trask sorting coefficient to quantitatively calculate initial porosity (Eqs. (1)-(2)). From the calculation, the initial porosity in the overpressure zone is from 34.52% to 37.72% (average of 36.05%); the initial porosity in the strong overpressure zone is from 32.98% to 38.72% (average of 36.12%); and in the normal pressure zone of BD19 block, the initial porosity reservoir ranges from 33.69% to 39.99% (average of 36.89%). The initial porosity in the normal pressure, the overpressure and the strong overpressure zones is basically the same, indicating that the initial heterogeneity of the reservoir is very weak.

The results of thin section analysis show that under different formation pressures, the compaction strength reflected by the contact among grains is different (Fig. 5). In the samples from the overpressure zone of the Huangliu Formation, the contact among grains is mainly line to line and point to line (accounting for 44% and 32%, respectively), followed by line to concave-convex and point to point (accounting for 20% and 4%, respectively) (Fig. 5b). In the strong overpressure zone, the contact among grains is mainly line to line (accounting for 59%), followed by point to line and line to concave-convex (accounting for 19% and 14%, respectively), and locally point to point (accounting for 8%) (Fig. 5c). However, the percent of point-to-line contact (accounting for 4%) and line-to-line contact (accounting for 8%) decreases significantly in the normal pressure zone at the similar depth in the BD19 block. The percent of line-to-concave- convex contact in the normal pressure zone increases significantly (accounting for 33%), and more concave-convex contact appears (accounting for 25%), but point- to-point contact is hardly seen (Fig. 5a). Under normal pressure, when the burial depth is more than 3400 m, the reservoir is strongly compacted, and the contact among grains becomes tightly. It is explained that overpressure resists static rock compaction to a certain extent at the similar depth under abnormally high pressure, thus the compaction degree of the reservoir reduces, and the intergranular contact is relatively loose.

According to Ren et al.^[27], residual porosity after compaction can be calculated from the total cement content, surface porosity of residual intergranular pores, surface porosity of micropores, total surface porosity and measured porosity (Eq. (3)). According to Shan et al.^[28], it is difficult to measure the surface porosity of micropores under a microscope, and it is calculated by subtracting the total surface porosity from the measured porosity. It is calculated that the residual porosity after compaction ranges from 5.37% to 27.10% (average of 15.72%), and the porosity reduced by compaction ranges from 8.07% to 33.63% (average of 21.18%) in the normal-pressure reservoir; the residual porosity after compaction ranges from 5.90% to 28.19% (average of 16.06%), and the porosity decreased by compaction ranges from 7.66% to 30.62% (average of 19.99%) in the overpressure reservoir; the residual porosity after compaction ranges from 5.55% to 27.64% (average of 15.32%), and the porosity lost by compaction ranges from 7.21% to 30.30% (average of 20.80%) in the strong overpressure reservoir. Compared with the normal pressure zone, the Huangliu Formation reservoir in the abnormally high pressure zone has a fewer pores lost by compaction and more pores preserved after compaction (Fig. 5d). However, under abnormally high pressure, the residual porosity after compaction is mainly concentrated from 8.00% to 27.00%, but still enhances the reservoir heterogeneity.

According to Luo et al.^[29], after compaction and cementation, the residual porosity is calculated from the surface porosity of residual intergranular pores, total surface porosity and measured porosity :

It is calculated that the residual porosity after cementation of the normal-pressure reservoir ranges from 0 to 1.68% (average of 0.47%), and the porosity reduced by cementation ranges from 5.37% to 27.10% (average of 15.25%). The residual porosity after cementation of the overpressure-reservoir ranges from 0 to 3.03% (average of 1.66%), and the porosity reduced by cementation ranges from 3.60% to 27.39% (average of 14.40%). The residual porosity after cementation of the strong-overpressure reservoir ranges from 0 to 7.19% (average of 1.49%), and the porosity lost by cementation ranges from 3.54% to 27.28% (average of 13.83%). Abnormally high pressure inhibits the cementation strength to a certain extent.

The Huangliu Formation reservoir is mainly cemented by carbonate, especially by ferrocalcite, and from the normal pressure zone to the strong overpressure zone, the content of ferrocalcite decreases (Fig. 6a). It is believed that the dissolution and precipitation of carbonate minerals are controlled by formation temperature and pressure. Taking calcite as an example, the reaction equation of precipitation-dissolution is as follows^[30]:

CaCO₃(calcite)+CO₂+H₂O$\rightleftharpoons $Ca²⁺+2HCO^3-

The Yinggehai Basin has undergone three strike-slip extensional activities since the Eocene, accompanied by three stages of hot CO₂ fluid activities. The peak of the basement heat flow (70 mW/m²) is the highest, and the hot CO₂ fluid charging scale is the largest during the third stage of strike-slip extensional activity (0.4 to 1.9 Ma)^[31,32,33]. The author suggests that early, middle and late stages of calcite cementation taking place in the Huangliu Formation of the Yinggehai Basin. Among them, the ferrocalcite cement appearing in the late stage is the most developed, and its δ¹³C ranges from -6.32‰ to -4.02‰. The δ¹⁸O ranges from -17.0‰ to -11.9‰, which is the product of deep-seated hot CO₂ fluid activity in stage A of mesodiagenesis. The deep faults formed by strike-slip extensional activities in LD10 block provide channels for releasing deep-seated hot CO₂ fluid^[16]. In the process of episodic emission of hot CO₂ fluid along fractures and pore channels driven by abnormally high pressure, calcite is dissolved under the influence of high pressure and CO₂ partial pressure in deep conditions, and with the decrease in CO₂ partial pressure and pore fluid salinity in shallow conditions, calcite precipitates and fills pores. In the vertical direction, with the decrease in the pressure coefficient, the content of carbonate cement dominated by ferrocalcite is lower in the middle and lower parts of the Huangliu Formation reservoir (the strong overpressure zone), pores lost after cementation are slightly less, and there are more residual pores. However, the content of carbonate cement in the middle and upper parts of the Huangliu Formation reservoir (the overpressure zone) is relatively high; pores lost after cementation are slightly more, and residual pores are slightly less (Fig. 6b). The cementation strength also weakens with the increasing pressure coefficient, and its influence on the heterogeneity of the reservoir in the middle and upper parts of the Huangliu Formation is stronger than that in the middle and lower parts of the Huangliu Formation.

According to Luo et al.^[29], the porosity increased by dissolution is calculated from the surface porosity of dissolved pores, total surface porosity and measured porosity. The present porosity is the sum of the residual porosity after cementation and the porosity increased by dissolution:

It is calculated that the increased porosity after dissolution in the normal-pressure reservoir ranges from 2.48% to 8.80% (average of 5.41%), and the present porosity ranges from 3.10% to 8.80% (average of 5.88%). The increased porosity after dissolution in the overpressure-reservoir ranges from 2.80% to 7.54% (average of 5.57%), and the present porosity ranges from 2.80% to 9.60% (average of 7.23%). The increased porosity after dissolution in the strong-overpressure reservoir ranges from 0.41% to 13.49% (average of 7.32%), and the present porosity ranges from 4.50% to 14.53% (average of 8.81%). The error between the present porosity calculated and the porosity measured is less than 0.1%.

Previous studies show that abnormally high pressure can inhibit the evolution of organic matter, broaden the scope of the oil generation window, extend the time of organic acid and CO₂ generation, and increase the contact time and strength of acidic fluid with silicate and carbonate minerals^[34]. Heat fluid such as a large amount of organic acid formed during hydrocarbon charging, inorganic acid formed by hydrolysis of CO₂, and acidic water that precipitated in the process of clay mineral transformation dissolved the soluble substances in the reservoir and formed a secondary pore development zone^[35,36]. There were three stages of hydrocarbon charging in the Huangliu Formation in LD10 block. The early stage that occurred at the end of stage B of eodiagenesis is limited. The large-scale hydrocarbon charging that occurred in stage A of mesodiagenesis made the middle and lower parts of the Huangliu Formation strongly affected by organic acid due to the reservoirs buried deeper and with larger pressure coefficient (strong overpressure zone). In addition, large-scale activities of hot CO₂ fluid deep seated occurred after 1.9 Ma, and influenced the strong overpressure zone in the middle and lower parts of the Huangliu Formation below 3900 m. As organic acid dissolution was occurring, hot CO₂ fluid migrated upward and affected the reservoir under the strong overpressure at the same time, resulting in a more developed secondary pore zone. The statistical results show that the dissolved pores in the normal pressure zone, the overpressure zone and the strong overpressure zone range from 0.1% to 5.4% (average of 2.2%), 0.2% to 9.5% (average of 3.9%) and 0.5% to 15.3% (average of 6.6%), respectively. From the normal pressure zone to the overpressure zone to the strong overpressure zone, both dissolved pores and the porosity increased by dissolution increase. The present porosity in the strong overpressure zone is the highest, followed by the overpressure zone and the normal pressure zone (Fig. 7). Dissolution weakens the reservoir heterogeneity, and its influence on the reservoir in the middle and lower parts of the Huangliu Formation is stronger than that in the middle and upper parts of the Huangliu Formation.

On the basis of the research above and the burial and thermal history in the study area, the evolution sequence and process of heterogeneity in the Huangliu Formation reservoir in LD10 block was analyzed. The diagenetic process has entered substage A₂ of mesodiagenesis^[37]. The reservoir heterogeneity is mainly controlled by diagenesis and pores evolution process under abnormally high pressure.

Before 10.5 Ma (the early Miocene), the basin was in the early stage of thermal subsidence (10.5-23.0 Ma). Affected by the northeast source, the difference in the mineral maturity and textural maturity of the reservoir sedimentary sand body was small. The initial porosity in the overpressure zone and the strong overpressure zone were approximately equal (average of 36.05% and 36.54% respectively), and the initial reservoir heterogeneity was weak (Fig. 8).

From syndiagenesis to stage A of eodiagenesis (4.5 to 10.5 Ma, i.e., from the early Miocene to the early Pliocene), the basin was in a transitional stage from late thermal subsidence to early acceleration of thermal subsidence. During that period, the formation overlying the Huangliu Formation subsided rapidly, and abnormally high pressure began to appear at approximately 9 Ma^[38]. In the process of rapid subsidence, the Huangliu Formation went deeper and deeper, and the pressure coefficient increased to the maximum of 2.30. And the reservoir in the middle and upper parts of the Huangliu Formation were under overpressure (the present pressure coefficient of 1.70 to 1.95), the middle and lower parts were under strong overpressure (the present pressure coefficient of 1.95 to 2.30). In the late stage of thermal subsidence from 5.5 to 10.5 Ma, the burial depth of the Huangliu Formation increased to 1150 m with the burial rate of 192 m/Ma, and the compaction strength increased gradually. In the early stage of acceleration of thermal subsidence from 4.5 to 5.5 Ma, the maximum burial depth of the Huangliu Formation was 1600 m with the burial rate increased to 450 m/Ma. As the depth increased, the temperature raised to 60 °C, but the vitrinite reflectance R_o was less than 0.35%, and the thermal evolution degree had not reached the hydrocarbon generation threshold. During that period, mechanical compaction was the main diagenesis causing lost pores. Under the influence of abnormally high pressure, the residual reservoir porosity in the overpressure zone in the middle and upper parts of the Huangliu Formation and that in the strong overpressure zone in the middle and lower parts of the Huangliu Formation ranged from 5.90% to 28.19% (average of 16.06%) and 5.55% to 27.64% (average of 15.32%), respectively. After compaction, the overall pore structures of the Huangliu Formation reservoir were very different, and the heterogeneity was enhanced (Fig. 8).

During stage B of eodiagenesis from 3.1 to 4.5 Ma (the early to the middle Pliocene), the basin went through early to middle acceleration of thermal subsidence, the maximum depth of the Huangliu Formation reached to 2500 m, and the burial rate increased to 642 m/Ma. With the increasing burial depth, close contact among grains gradually decreased the compaction strength, the formation temperature increased to 90 °C and the vitrinite reflectance R_o was 0.5%. With the increasing temperature, early montmorillonite began to transform into mixed layers of illite/smectite and then into illite, and early micritic calcite and siliceous cements began to develop^[37]. Compaction was replaced by cementation and became the major diagenesis influencing the reservoir heterogeneity. Although the degree of thermal evolution of organic matter reached the hydrocarbon generation threshold at that time, only small-scale hydrocarbon charging occurred in a relatively limited time, and the resulting early dissolution had little influence on the reservoir.

During substage A₁ of mesodiagenesis from 1.9 to 3.1 Ma (from the middle Pliocene to the late Pliocene), the basin was in middle to late acceleration of thermal subsidence, with the maximum depth of 3 500 m and burial rate of the maximum (833 m/Ma) of the Huangliu Formation. At that time, under the influence of abnormally high pressure, the transforming rate of clay minerals was inhibited, and the content of clay minerals was low. However, carbonate cement, represented by late ferrocalcite, developed and began to fill a large number of pores to the maximum strength. The porosity in the overpressure zone and the strong overpressure zone was reduced by 3.60%-27.39% (average of 14.40%) and 3.54%-27.28% (average of 13.83%), respectively, and the residual porosity after cementation ranged from 0 to 3.03% (average of 1.66%) and 0 to 7.19% (average of 1.49%). Cementation worsened the connectivity among pores and throats in the reservoir, resulting in the most complex pore throat structures and the strongest heterogeneity. Cementation influenced the reservoir in the middle and upper parts of the Huangliu Formation more strongly than that in the middle and lower parts of the Huangliu Formation. With the increasing burial rate, the temperature increased to 130 ℃, and the vitrinite reflectance R_o increased to 0.70% (Fig. 8). The thermal evolution degree of organic matter exceeded the hydrocarbon generation threshold, resulting in the second stage of hydrocarbon charging, and finally large-scale dissolution.

During substage A₂ of mesodiagenesis after 1.9 Ma (the Quaternary), the basin was in late acceleration of thermal subsidence, the maximum depth of the Huangliu Formation was 4500 m with the burial rate decreased to 526 m/Ma. At that time, the formation reached its middle to deep depth, with the highest temperature of 170 °C and the vitrinite reflectance R_o of 1.00%, the thermal evolution degree of organic matter reached its peak. A large amount of organic acid accompanied by the second and the third stages of hydrocarbon charging dissolved a large amount of easily soluble components, such as feldspar and debris. In addition, deep-seated hydrothermal and hot CO₂ fluid activities after 1.9 Ma resulted in more dissolved pores in the strong overpressure zone (porosity of 0.41%-13.49%, average of 7.32%), but less in the overpressure zone (porosity of 2.80%-7.54%, average of 5.85%). After dissolution, the present porosities in the overpressure zone and the strong overpressure zone range from 2.80% to 9.60% (average of 7.23%) and 4.50% to 14.53% (average of 8.81%), respectively (Fig. 8). Although the dissolution weakened the heterogeneity to a certain degree, the difference in the pore throat structures made some dissolved products unable to be discharged with acidic fluid in local zones, and the difference in the secondary pores was obvious, resulting in strong reservoir heterogeneity.

In summary, the reservoir has been successively affected by compaction, cementation and dissolution since 10.5 Ma after syndiagenesis to stage A of eodiagenesis. The heterogeneity of the reservoir increased first and then decreased. In contrast, the reservoir in the overpressure zone in the middle and upper parts of the Huangliu Formation were more affected by cementation and less affected by dissolution, and with the heterogeneity stronger than that in the strong overpressure zone in the middle and lower parts of the Huangliu Formation. The heterogeneity of the Huangliu Formation reservoir, on the whole, is "stronger at the upper part and weaker at the lower part, and globally strong and locally weak". Favorable reservoirs are located in the strong overpressure zone in the middle and lower parts of the Huangliu Formation.

The heterogeneity of the Miocene Huangliu Formation tight sandstone reservoir is controlled by the heterogeneity of cements, pores and throats, physical properties. The heterogeneity of cements is influenced by the development of ferrocalcite. The heterogeneity of pores is controlled by different throat structures. The heterogeneity of physical properties is affected by heterogenous cements and throat structures.

Abnormally high pressure affects reservoir heterogeneity by controlling compaction, cementation and dissolution. Since 10.5 Ma, the heterogeneity of the Huangliu Formation reservoir has been affected by abnormally high pressure gradually: compaction increased the heterogeneity, cementation enhanced the heterogeneity, and dissolution weakened the heterogeneity. The reservoir heterogeneity in the middle and upper parts of the Huangliu Formation (the overpressure zone) is stronger than that in the middle and lower parts of the Huangliu Formation (the strong overpressure zone). Favorable reservoirs are mainly located in the strong overpressure zone in the middle and lower parts of the Huangliu Formation.

n—number of samples;

P₁—surface porosity of residual intergranular pores, %;

P₂—surface porosity of micropores, %;

P₃—surface porosity of dissolved pores, %;

P₂₅, P₇₅—grain diameters corresponding to the cumulative frequency of 25% and 75% on sandstone grain size distribution curve, mm;

P_t—total surface porosity, %;

R—relation coefficient, dimensionless;

S₀—trask sorting coefficient, dimensionless;

W—total cement content, %;

ϕ₁—initial porosity, %;

ϕ₂—residual porosity after compaction, %;

ϕ₃—residual porosity after compaction and cementation, %;

ϕ₄—increased porosity after dissolution, %;

ϕ₅—current porosity, %;

ϕ_m—measured porosity, %.