The Xihu sag in the East China Sea shelf basin is one of the offshore sags with abundant resources and great exploration potential in China^[1]. The tight sandstone gas in the sag is huge in resource amount, accounting for about 80% of the total resources of the sag^[2]. With the deepening of exploration and development, exploration breakthroughs have been made successively in the Paleogene Huagang Formation and Pinghu Formation in the Xihu sag, and the proven gas reserves there have increased rapidly. Currently tight sandstone gas has become the major target of exploration and development in the Xihu sag^[3]. However, the low permeability tight sandstone reservoirs are strong in heterogeneity, and the factors controlling the development of high quality reservoirs remain unclear, restricting effective exploration and economic development of medium deep tight sandstone gas reservoirs (3500 m) in the sag. Therefore, study on factors controlling the tight sandstone reservoir in the Huagang Formation is of great significance for understanding the distribution and origins of high quality reservoirs. The central inversion structural belt where great exploration breakthroughs have been made recently in tight sandstone reservoirs of the Huagang Formation was taken as the study object in this work. Controlling factors and distribution rules of favorable tight sandstone reservoirs of the Huagang Formation were investigated from sediment sources, sedimentation facies, formation pressure and diagenetic environment, based upon analysis of reservoir physical properties, lithology and pore structures by means of thin section analysis, zircon U-Pb dating, SEM, electron probe, laser microprobe emis-sion spectral analysis (MESA) of carbon and oxygen isotope.

The Xihu sag in NNE strike is located at northeast of East China Sea shelf basin, covering an area of 5.18×10⁴ km², and is about 400 km long from south to north and 100 km wide from west to east (Fig. 1). The Xihu sag was formed at the Late Cretaceous, was a post-arc rifted sag, and experienced three stages of tectonic evolution, Eocene rifting period, Oligocene-Miocene depressing period, and Pliocene-Quaternary regional subsiding period. According to structural pattern, sedimentation, fault development, and oil and gas accumulation of Cenozoic, the Xihu sag from west to east is divided into three secondary structural units, the west slope (gentle), central inversion structural belt, and east fault zone. From the Paleocene to the Miocene, marine sediments of gulf-lacustrine facies and gulf-tidal flat facies and terrestrial sediments of lacustrine facies and river facies deposited successively. Sediment of the Huagang Formation 1 000 to 1 800 thick mainly includes alluvial plain facies, fluvial facies, swamp flood plain facies, delta facies and shallow lake facies. According to drilling data, strata of Cenozoic are complete without discontinuity, including, from bottom to top, the Paleozoic (E1), Pinghu Formation (E₂p) of Lower Eocene (E₂1), Huagang Formation (E₃h) of Oligocene, Longjing Formation (N₁¹l), Yuquan Formation (N₁²y) and Liulang Formation (N₁³l) of Miocene, Santa Formation (N₂s) of Pliocene and Donghai Group (Qd) of Quaternary (Fig. 1)^[4]. The Oligocene Huagang Formation of our interest is vertically divided into upper and lower members. The upper member contains five sublayers from H1 to H5 and the lower member contains seven sublayers from H6 to H12.

Reservoirs of Huagang Formation are largely fluvial sediments, which are hundreds of meters thick in single sand body and strongly heterogeneous in physical properties. Compared with other structural zones of the Xihu sag, the sandstone of the Huagang Formation in the study area is characterized by higher quartz content, coarser clastic particles, and lower contents of matrix, kaolinite, and cement. Observation of 1 522 rock slices shows that the sandstone in the Huagang Formation has a quartz content of 62%-80%, feldspar content of 15% to 20%, and lithic content of 16% to 25% in general (Fig. 2). The sandstone of the Huagang Formation is classified into several types according to the traditional sandstone classification criterion and naming principles^[5]. Of them, the feldspathic lithic quartz sandstone takes a majority of 86.99%, the feldspathic sandstone and feldspathic quartz sandstone account for 4.62% and 2.07% respectively. The rest rare rocks such as feldspar debris sandstone, debris sandstone, and lithic quartz sandstone account for a very small proportion of less than 1% each. In addition, gas reservoir rock of the Huagang Formation is generally coarser, and mainly fine-medium sandstone, followed by coarse-medium sand, and a small amount of the sandstone reaches the size of boulder and gravel. Compared with other structural areas of Xihu sag, the sandstone of the Huagang Formation is characterized by low contents of matrix, cement, and kaolinite of 2.92% to 5.09%, 1.0% to 3.1%, and 0.004% to 1.270 % respectively. If 15% matrix content is taken as the dividing point, the sandstone with matrix of less than 15% is classified as clean sandstone and that with matrix of more than 15% as apogrite^[6], all the reservoirs of the Huagang Formation in the study area are nearly clean sandstone.

According to core porosity and permeability, the reservoirs of the Huagang Formation are poor in physical properties and represent tight sandstone reservoirs on the whole. They have a porosity mainly from 6% to 12%, the permeability in a wide range, but mainly between 0.1×10^-3 μm² and 1.0×10^-3 μm², and over 1×10^-3 μm² individually. According to geological evaluation criterion of tight sandstone gas reservoir^[7], the reservoirs of the Huagang Formation in the study area are mostly tight reservoirs, and some are of moderate to low permeability one. The H3 sublayer, a gas pay, of the Huagang Formation has better physical properties, followed by sublayer H4 and H5, and sublayer H6 and H7 are the poorest.

Observation of cast thin sections of sandstone from the Huagang Formation in the study area shows that the sandstone has three types of storage space, primary pore, secondary pore, and microfracture. Among them, primary pore and secondary pore are the major reservoir space, while microfracture is rare.

(1) Primary pores. They are mainly intergranular pores between detrital particles. The primary pores in the sandstone of the Huagang Formation are generally incomplete in morphology. Some of the primary pores have been reduced to narrow triangles, strips or even fractures due to compaction, and some other primary pores are filled with authigenic minerals and deform (Fig. 3a, 3b).

(2) Secondary pores. The secondary pores in the reservoir of the Huagang Formation consist of intergranular dissolved pores, intergranular dissolved pores and moldic pore (Fig. 3c, 3d). Among them, the intergranular dissolved pores from dissolution enlargement of primary intergranular pores are the most developed secondary pores in the Huagang Formation reservoirs. The dissolved intragranular pores are mainly resulted from dissolution of feldspar and debris particles along the cleavage plane of the mineral, which appear in pane or honeycomb shape at low degree of dissolution, and in the form of moldic pore at high dissolution degree (Fig. 3d). In addition, there are other forms of secondary pore combinations in the reservoir, such as the combination of intercrystalline pore and dissolved intergranular pore.

(3) Microfracture. Microfractures in the Huagang Formation reservoir are small in number and are mainly composed of diagenetic microfractures and structural microfractures. It is found through core observation and microfracture identification with microscope and imaging log that the fractures are 0-0.5 mm wide, and structural fractures are 10 to 20 cm long. The upper and lower members of Huagang Formation have an average fracture density of 0.65line/m and 0.88 line/m from core observation respectively, and 0.047-0.443 line/m from single-well imaging log. Due to the small number, microfractures add little to storage space. Their contribution to reservoir physical properties is mainly manifested in improving reservoir permeability.

According to statistics and classification of reservoir space in 1715 thin sections, the reservoir space in the Huagang Formation is mainly pores, including primary pores and secondary pores. The secondary pores account for the highest proportion of 75.61% of the total reservoir space; and correspond to surface porosity of 4.23%. The primary pores account for 23.79% of the total reservoir space, and corresponds to surface porosity of 1.33%. Micro fractures, rarely seen in the Huagang Formation, account for 0.60% of its total reservoir space, and correspond to surface porosity of only 0.03%.

The characteristics of the mercury capillary pressure curves of all sublayers in Well N-6 are presented in Fig. 4. The samples with a permeability of over 10×10^-3 μm² and expulsion pressure of less than 0.1 MPa (0.05-0.08 MPa) have the maximum mercury saturation of over 90%, an average throat radius of 3-7 μm, a median pressure of less than 0.3 MPa and sorting coefficient of 2-3, indicating large throat diameter and good sorting. Samples with a permeability of (1-10)×10^-3 μm² and expulsion pressure of less than 0.2 MPa have a maximum mercury saturation of 78%-94%, an average throat radius of 0.8-3.0 μm, a median pressure of 0.8-1.4 MPa and sorting coefficient of 2-3, indicating moderate large pore throat and good sorting. Samples with a permeability of (0.1-1.0)×10^-3 μm² and expulsion pressure of 0.2-1.5 MPa have a maximum mercury saturation of 73%-85%, an average throat radius of 0.1-0.7 μm, a median pressure of 1.8 to 8.0 MPa, sorting coefficient of 2 to 4, porosity of 7% to 13%, and the curves show a medium platform, indicating moderate pore throat radius and sorting. Samples with a permeability of less than 0.1×10^-3 μm² have a displacement pressure of greater than 1.0 MPa, maximum mercury saturation of less than 80%, an average throat radius of less than 0.2 μm, and a porosity of less than 8%, indicating small pore throat and poor sorting.

In general, Huagang Formation has little difference in rock type and reservoir physical properties laterally, and physical properties and microstructure turning worse with the increase of depth vertically, and sublayer H3 has the best physical properties.

The provenance is one of the main factors affecting the physical properties of the reservoir. The distance from the provenance directly affects the compositional maturity and textural maturity of the sandstone, thus affecting the physical properties of the reservoir^[8].

3.1.1. Compositional maturity

Under the control of sediment provenance, the sandstone of the Huagang Formation in the area is medium-high in compositional maturity. Taking the north central part of the study area as an example, the compositional maturity (Q₁/(F₁ + R₁)) of sublayers ranges from 1.7 to 1.9 in (Table 1), and is lowest in sublayer H3 and highest in sublayer H7, suggesting the difference in compositional maturity is dependent on distance from provenance. The restoration of the sediment supply process in the north central part shows that sublayers H7-H3 were located at water transgression-highstand systems tract, when the sediment was transported from provenance of Diaoyudao, Hupijiao and Haijiao to the convergence region at north central part, as the transportation distance of sediment decreased, the sublayers H7 to H13 reduce in quartz content and compositional maturity. The statistics on clastic composi- tion and physical properties of the reservoir show the quartz content is positively correlated with physical properties of Huagang Formation. High content of rigid quartz can resist the compaction of overlying formation, and is conducive to the preservation of pores. The statistics also show there is a strong negative correlation between feldspar content and physical properties. This is because feldspar is susceptible to dissolution by formation fluid under burial condition, and most reduction of feldspar due to dissolution is contributed to the development of dissolved secondary pores.

3.1.2. Textural maturity

The criteria to identify maturity include roundness and sorting coefficient, which are respectively the direct reflection of transportation distance of sediment and hydrodynamic condition. Analysis of over 1,200 samples from the north central part of the study area shows that sorting becomes poorer from H7 to H3 (Table 2). The H7 has the best sorting, with 74.7% of samples reaching good sorting level, which is related to the longest transportation distance of sediment of this sublayer. Most samples from H6 to H3 are "good" and "moderate" in sorting. Less distinctive in trend as sorting, the roundness is mainly sub-angular or sub-rounded, but still shows the reservoir is fairly high in roundness. Generally, low matrix content is conducive to the preservation of primary storage space. The statistics on sandstone matrix content and physical properties of the reservoir of the Huagang Formation (Fig. 5) show that the matrix content has a clear negative correlation with porosity and permeability, indicating that low matrix content is an important indicator of moderate high-quality reservoir in the tight sandstone of the Huagang Formation. Another feature of sandstone of the Huagang Formation is coarser clastic particles. The clastic particles are mainly fine-medium, followed by coarse-medium, with grain sizes ranging between 0.15 mm and 0.48 mm. The coarser clastic particles also indicate better physical properties of sandstone. Statistics on median particle size and reservoir physical properties shows that the median particle size of the sandstone of the Huagang Formation is positively correlated with physical properties of the reservoir (Fig. 5). When the median particle size is less than 0.2 mm, the porosity and median particle size show the closest correlation. When the median particle size is over 0.2 mm, the porosity becomes less significant in increment, and is mainly concentrated at 5% to 10%. The median particle size and permeability are always positively correlated. The permeability increases with median particle size. When the median particle size is over 0.2 mm, the permeability still shows obvious increase.

3.1.3. Provenance direction and provenance areas

The provenance system of the Huagang Formation in the Xihu sag are characterized by multiple sources, multiple catchments, and multiple terraces formed by filling of broad and gentle river valley. The provenances were tracked by 1405 zircon U-Pb isotope chronology data points of 15 clastic rock samples covering the whole area of Xihu sag (Fig. 6)^[9,10,11]. The study shows that the sag had 3 provenances in three directions, the northern Hupijiao uplift provenance, the western Haijiao uplift provenance and the eastern Diaoyudao fold belt provenance during the depositional stage of the Huagang Formation (Fig. 7). The reservoirs formed by different provenances are also different in their sedimentary parent materials and epigenetic diagenesis, leading to differential physical properties of the reservoirs of the Huagang Formation in the Xihu sag.

The distribution of zircon U-Pb age shows that the material source of the Huagang Formation in the north central part of the study area comes mainly from Proterozoic. Specifically, the long transported Proterozoic clastic zircons account for the largest proportion of detrital zircons in the Huagang Forma-tion, indicating Hupijiao uplift in the north had been subjected to denudation during the depositional stage of the Oligocene Huagang Formation. The sediment from the Proterozoic metamorphic parent rock area of Hupijiao uplift has strong control on the formation of the Huagang Formation sandstone in the West Xihu sag, which results in gradual increasing trend of metamorphic rock content from south to north in the Huagang Formation. Meanwhile, the Mesozoic and Paleozoic clastic zircons transported for short distance mainly indicate sediments from Paleozoic Diaoyudaofold belt provenance on the east side, the Mesozoic Haijiao uplift and Yushan low uplifts provenance on the west side after weathering and erosion, which are characterized by short distance transportation and deposition from the provenance. The Hupijiao uplift was far from the central inversion tectonic belt of the Xihu sag, so the sediment from this uplift was transported for a long distance from the north to the south along the narrow water channel, resulting in high compositional maturity and textural maturity, therefore high original porosity and permeability of the sandstone of the Huagang Formation. At the same time, the good original physical properties of the Huagang Formation further made it easier for the acidic diagenetic fluid to get into the formation to dissolve soluble minerals and form a large number of secondary dissolution pores, thereby improving the storage capacity of tight sandstone. Mercury intrusion experiments show that feldspar clastic quartz sandstone with higher compositional maturity and textural maturity has larger pore throat and better sorting degree than arkoses clastic sandstone when they are at the same permeability level. Therefore, the provenance not only determines the high primary porosity of the sandstone of the Huagang Formation, but also is a prerequisite for forming high quality reservoir in later stage of diagenetic compaction. Exploration practice has proved that the well sorted medium-coarse feldspar clastic quartz sandstone in the Huagang Formation tight sandstone has the best exploration result.

The sediments transported far from the main provenance Hupijiao uplift makes the sandstone of the Huagang Formation high in compositional maturity and textural maturity, which is conducive to the development and preservation of the primary pores, and thus to the formation of high quality reservoir in the deep part of the Huagang Formation now.

Sedimentary facies has significant control over the original physical properties of the sandstone reservoir of the Huagang Formation. The braided river and delta front subfacies are the main sedimentary facies in the Huagang Formation, which consist of four microfacies, underwater distributary channel, channel bar-river bed, mouth bar and underwater inter-distributary. Among them, the underwater distributary and channel bar-river bed are dominant microfacies of the Huagang Formation reservoir. Comparison of the calculated original porosity of sandstone samples from these two microfacies (Table 3) shows that the average original porosity of the braided river channel bar-river sandstone is 38.35%, which is significantly higher than 32.55% of the delta underwater distributary sandstone. This is because channel bar-river bed microfacies of braided river has stronger hydrodynamic condition than that of delta underwater distributary, which makes the deposited sand bodies more completely panned and sorted. Therefore, channel bar-river bed of braided river facies is more conducive to development of original pores in the Huagang Formation sandstone than underwater distributary of delta facies.

3.3.1. Acidity-basicity evolution of diagenetic environment

Previous studies have found that organic acidic fluids can effectively dissolve feldspar aluminosilicate and carbonate minerals in the reservoir to generate dissolved pores^{[12,13,14,15,16]}. In order to find out the forming mechanism of the acidic diagenetic environment, laser microprobe emission spectral analysis (MESA) was carried out to test carbon and oxygen isotope composition of calcite cement in the Huagang Formation reservoir by University of Saskatoon, Canada. The test results show that δ¹³C ranges from -6.1‰ to -1.0‰, -3.5‰ on average, doesn’t change significantly with depth, and is generally low negative value below zero; δ¹⁸O ranges from -24.1‰ to -16.0‰, on average -21.6‰, which is far below zero and shows a negative trend with the increase of depth, indicating temperature increase in old strata. The analysis of calcite cement genesis shows that all data points fall into zone III of the plate (Fig. 8), indicating that the formation of calcite cement is related to the decarboxylation of organic acid. Therefore, the large amount of organic acid generated by kerogen and carbonic acid generated by the dissolution of CO₂ from decarboxylation of organic acid in formation water are the root causes of acidic diagenetic environment.

Keith and Weber^[17-18] proposed an empirical formula to calculate the paleo-salinity Z value during the formation of carbonate by carbon and oxygen isotope composition:

Z=2.048(1000δ¹³C+50)+0.498(1000δ¹⁸O+50)

This empirical formula was used to calculate the paleo-salinity Z during the formation of calcite cement in the sandstone of the Huagang Formation in this work. The results show that the Z values are concentrated, ranging from 103.03 to 117.20, and 109.31 on average, indicating formation fluid when calcite cement was formed had high paleo-salinity.

In addition, it is found from electronic probe analysis that quartz secondary overgrowth in the sandstone of the Huagang Formation contains a small amount of titanium dioxide (TiO₂) which is an indicator of surface weathering intensity (Table 4). Quartz overgrowth formed earlier contains titanium dioxide^[19], suggesting that there was other source of acidic material other than organic acid in the diagenetic environment of the Huagang Formation, that was carbonic acid left in the formation after early atmospheric freshwater leaching. But, this acidic substance in lower in content and only affects the top of the Huagang Formation, so it has less contribution to the development of secondary dissolution pores in the Huagang Formation than organic acid.

When the organic matter evolution reaches the level of generating large amount of condensate and wet gas, decarboxylation would weaken, CO₂ sources would then reduce. Moreover, various diagenetic alteration reactions would also consume acidic substances. All these would inevitably lead to gradual transition of diagenetic fluid from acidity to alkalinity^[20]. Previous coal sample heating experiment^[21] has confirmed the transition of the diagenetic fluid from acidity to alkalinity when organic matter reaches the R_o of 1.0% to 1.3%. The transition of diagenetic environment from acidity to alkalinity means increase of burial depth and enhanced compaction, which together with weakened dissolution of basic feldspar minerals would hinder the development of secondary dissolved pores and existing pores would lose significantly under compaction. In addition, the commonly developed authigenic illite and chlorite in alkaline diagenetic environment also severely reduce the seepage capacity of reservoir^[22]. Therefore, the alkaline diagenetic environment is detrimental to the development of high-quality reservoir in the Huagang Formation.

3.3.2. Control of acidic diagenetic environment over high quality reservoir

Diagenetic environment is the most direct factor affecting diagenesis, and has an important controlling effect on pore development and distribution in clastic rock reservoir^[23]. Due to variations in burial depth and structural location, diagenetic environment of the Huagang Formation in the central inversion tectonic belt evolved differently in both horizontal and vertical direction, resulting in strong vertical and lateral heterogeneity.

Diagenetic environment difference controls over the vertical distribution of high quality reservoirs. The diagenetic facies associations, pore types, acidity and alkalinity of diagenetic environment of each diagenetic stage of the Huagang Formation in the central inversion structural belt were identified based on vitrinite reflectance, clay mineral combination, pyrolysis temperature, homogenization temperature of inclusions, and particle contact relation, and diagenetic environment evolution process was recovered (Fig. 9). The vertical evolution pattern of diagenetic environment of the Huagang Formation shows the environment at early diagenesis A stage was weakly alkali, and the pores in the reservoir were mostly residual primary intergranular pores left after compaction; the environment of early diagenesis stage B transformed from weakly alkaline to weakly acidic one as the organic matter became mature and discharged organic acids, during this period acidity of diagenetic environment gradually increased with the increase of burial depth, and the major reservoir space was still primary intergranular pores with a small amount of dissolution pores of feldspar and debris. During middle diagenetic stage, the Huagang Formation entered a most complicated period of diagenesis evolution: as organic acids consumed by dissolution, the diagenetic environment changed from acidic to acid-base transition to alkaline and finally to weak alkali ones. In the middle diagenetic stage, the pores in the Huagang Formation reservoir were largely feldspar mineral dissolution pores, but some section had a small amount of primary intergranular pores.

3.3.3. Diagenesis and pore evolution

During the evolution of the diagenetic environment, the Huagang Formation in the central inversion tectonic belt of the Xihu sag has experienced various diagenetic processes. Compaction which has run through the entire environment evolution is an important reason leading to the poor physical properties of tight sandstone reservoir^[24]. Cementation is an important diagenesis transforming loose sediment into sedimentary rock, and one of the main reasons causing porosity and permeability reduction of clastic rock. The sandstone cement content -negative cement porosity plot (the porosity after removing all cement) of the Huagang Formation in the study area was analyzed with Monte Carlo method, the smaller the vertical axis value, the stronger the compaction is, and the larger the horizontal axis value, the stronger the cementation is. The results show that most of the sample points are concentrated in the compaction zone in the lower left of the plate, and only a small number of sample points fall in the cementation zone in the upper right corner of the plate (Fig. 10), indicating that cementation is the most important factor causing sandstone porosity reduction in the Huagang Formation, meanwhile the destructive effect of cementation on pores is also significant. Dissolution plays a constructive role in improving the physical properties of clastic reservoir^[25]. The dissolution pores in the sandstone of the Huagang Formation are formed mainly by acid dissolution and secondly by alkaline dissolution. In an acidic diagenetic environment, feldspar minerals, debris, and a small amount of cement in sandstone all can be dissolved, resulting in improvement of the porosity and permeability of the reservoir.

The difference in diagenetic environment has significant control over the lateral distribution of high-quality reservoir. In this study, the environmental evolution mode and porosity evolution mode of the north-central and south-central part of the Huagang Formation in the study area were established (Figs. 11 and 12), based on restoration of stratigraphic burial history and thermal evolution history, diagenesis analysis of each stage and quantitative calculation of pore evolution, to examine the control of difference in diagenetic environment over lateral distribution of the higher-quality reservoirs in the Huagang Formation^[26,27].

During early diagenesis stage A, the burial depth of the Huagang Formation in the north central part of the study area was less than 1700 m, and the diagenetic environment was weak alkaline, mechanical compaction at this stage made the porosity of the reservoir reduce to 20% to 30%. At this stage, in the south central region, the burial depth of the Huagang Formation was nearly 1300m, and the diagenetic environment was weak alkaline too, the cementation caused the porosity to reduce by 5%-10%.

During early diagenesis stage B, in the north central part, the Huagang Formation was at a depth of 1700-2500 m, with the entry of organic acidic fluid, the diagenetic environment started acid-base transition, the mechanical compaction, siliceous cementation, calcareous cementation, and authigenic clay mineral cementation led to a reservoir porosity reduction of approximately 27%, whereas acidic dissolution made the reservoir porosity increase by approximately 15%, and the reservoir porosity decreased to 13.57%. In comparison, in the south central region, the Huagang Formation was at the burial depth of 1300-1900 m, and in the diagenetic environment of acid-base transition, the secondary pores produced by dissolution of the acidic fluid discharged at early organic matter maturity stage and atmospheric fresh water made the reservoir porosity increase by 4%-8%.

During the middle diagenetic stage A, in the north-central part, the Huagang Formation was in completely acidic diagenetic environment, strong acidic dissolution made the reservoir porosity increase by about 5%, whereas mechanical compaction, calcareous cementation, siliceous cementation, and authigenic clay mineral cementation made the reservoir porosity reduce by 8.16%, and the total porosity of the reservoir reduced to 9.84%. At age 10.9 to 12.0 Ma, the top of the Huagang Formation suffered denudation due to tectonic uplift, meanwhile, a small amount of meteoric water seeping down made the upper part of the Huagang Formation maintain in acidic diagenetic environment, while the lower part of the Huagang Formation had changed to alkaline diagenetic environment as it wasn’t reached by meteoric freshwater seeping down and most organic acid was consumed. Meanwhile, in the southern central part, the Huagang Formation was in acidic diagenetic environment due to the continuous charge of organic acid, mechanical compaction and cementation caused the reservoir porosity to reduce somewhat, while the stronger organic acid dissolution made the secondary porosity of the reservoir increase by 6% to 10%. At age 5.5 to 10.9 Ma, the strata were uplifted and denuded, the upper part of the Huagang Formation was denuded by 1175-1342 m, and its diagenetic environment changed to acid-base transition. Whereas the lower part of the Huagang Formation was kept in acidic diagenetic environment due to continuous influence of organic acid.

During the diagenetic stage B, in the north central part, most of the Huagang Formation was close to 3500 m in buried depth, and as the small amount of organic acid brought by hydrocarbon charging reacted with existed alkali diagenetic fluid, the diagenetic environment turned into a weakly alkaline one containing authigenic minerals such as ferrous calcite, illite, chlorite etc. Under this circumstance, cementation and weakened mechanical compaction caused the reservoir porosity to reduce by only about 1.5%, while the weak alkaline dissolution (silica dissolution) made the reservoir porosity increase by about 0.3%, and eventually the total porosity of the reservoir reduced to about 8.5% nowadays. In south-central part, most of the Huagang Formation is presently at middle diagenesis stage A Although the reservoir porosity were further reduced by mechanical compaction and later cementation of ferrous calcite, ferrous dolomite, its acidic diagenetic environment rich in authigenic kaolinite provided necessary conditions for continuous acidic dissolution, making secondary porosity increase by 2%-6%, eventually the total porosity of the reservoir reduced to about 12% nowadays.

In consideration of different influences of various diagenetic environments on physical properties of the reservoir, it is concluded that shallow burial state with weak mechanical compaction is conducive to pore preservation. Meanwhile, in acidic diagenetic environment, the reservoir is subject to strong dissolution, which is conducive to development of secondary pores. Therefore, the higher quality reservoirs of the Huagang Formation in the study area today are mainly distributed in shallower sublayers H3 to H5 of the upper Huagang Formation in middle diagenetic stage A and acidic diagenetic environment.

Previous studies have confirmed that abnormal high pressure can offset the compaction of overlying strata, inhibit formation of cements such as quartz, and also is good for the carry-out of dissolved substances to enhance dissolution of soluble minerals such as feldspar^[12,13,14]. The abnormal high pressure in the Huagang Formation of the Xihu sag is small and mainly concentrated in the lower Huagang Formation in the north central part of central inversion structural belt. Abnormal high pressure influences the physical properties of the Huagang Formation reservoir mainly in the following three aspects: (1) to relieve the compaction on rock particles; (2) to further strengthen dissolution of soluble minerals such as carbonate minerals and silicate minerals by deep organic acidic fluids, thereby promoting the formation and development of secondary pores; (3) to produce micro-fractures, thereby increase the reservoir storage space and significantly improve the permeability of the reservoir when abnormal high pressure exceeds cracking pressure of the rock.

It can be seen from cross plot of pressure coefficient, reservoir physical property vs. depth that typical well C-5 has abnormally high pressure in the lower Huagang section in north central part of central inversion structural belt, with a pressure coefficient of 1.54 (Fig. 13). The physical properties of the Huagang Formation reservoir generally decrease with the increase of depth, but when abnormal high pressure occurs, the porosity of the reservoir increases with depth instead, the inflection point of physical properties is consistent to the increase of pressure coefficient. In comparison, Well E-4, a typical well drilled in the south central part of central inversion structural belt, has no abnormally high pressure in the lower Huagang Formation, and the physical properties of the reservoir constantly decreases with depth all the time (Fig. 13b). In addition, the evolution trend of secondary porosity of the reservoir (according to the quantitative statistics of cast thin sections) is close to the evolution trend of the total porosity in the depth interval of abnormal high pressure, but the secondary porosity increment is lower than that of total porosity. Obviously, abnormal high pressure improves the physical properties of the Huagang Formation reservoir mainly by preserving primary pores, but also promoting the development of secondary pores to some extent.

(1) Rocks of the Huagang Formation in the central inversion structural belt of the Xihu sag mainly include feldspar debris quartz sandstone, which is characterized by high quartz content, coarse clastic particles, low matrix content, low kaolinite content and low cementation content. (2) The Huagang Formation reservoirs in this area are poor in physical properties, and generally fall into the category of tight sandstone, but there are some higher quality reservoirs. The gas layers differ widely, H3 of which is medium porosity- permeability or low porosity-low permeability reservoir, H4 and H5 of which are low porosity-low permeability and ultralow porosity -ultra low permeability reservoirs, H6 and H7 of which are ultralow porosity-ultralow permeability reservoirs. (3) The development of higher quality reservoirs in the tight sandstone of the Huagang Formation are controlled by development of high original porosity, pore preservation by abnormal high pressure and differential diagenesis jointly. Sedimentary provenance and sedimentary facies control the development of original high porosity of the Huagang Formation sandstone which is the prerequisite for forming higher quality reservoir. Abnormal pressure is not only conducive to the preservation of primary pores but also promote the formation of secondary pores, therefore it plays a vital role in improving and protecting the physical property of the reservoirs. (4) Considering all control factors of reservoir development comprehensively, especially the diagenetic environment difference and abnormal high pressure, the higher-quality reservoirs in the tight sandstone of the Huagang Formation in the study area are vertically distributed in the shallowly buried upper Huagang Formation in acidic diagenetic environment, laterally distributed in the south central part of the central inversion tectonic belt with shallow depth, high abnormal pressure and acidic diagenetic environment.

F₁—debris content, %;

K—permeability, 10^-3 μm²;

N—number of samples;

R₁—feldspar content, %;

Q₁—quartz content, %;

Z—paleo-salinity, dimensionless;

ϕ—porosity, %.