Relationship Between Paleogene Reservoir Densification and Hydrocarbon Accumulation in the Xihu Depression

HU Senqing, XU Guosheng, ZHAO Linhai, WANG Xu, CUI Hengyuan,ZHANG Wu, and MIAO Qing

1) Shanghai Branch of China National Offshore Oil Corporation, Shanghai 200050, China

2) State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation (Chengdu University of Technology),Chengdu 610059, China

Abstract Fluid inclusion analysis and testing were conducted to clarify the relationship between reservoir densification and hydrocarbon accumulation in the Paleogene Pinghu and Huagang formations in the Xihu Depression. The hydrocarbon accumulation stages of the reservoirs were studied in combination with the reconstruction results of burial and thermal evolution histories. Furthermore, the relationship between reservoir densification and accumulation charging was clarified in combination with the pore evolutionary history. In accordance with the time relation between reservoir densification and hydrocarbon charging, the reservoirs were classified into three types: pre-charging, syn-charging, and after-charging densification. Results indicated that large-scale hydrocarbon charging occurred in 11 - 0 Myr. Reservoir densification was mainly caused by strong mechanical compaction and pore filling by well-developed siliceous and carbonate cements. Entering the middle diagenetic stage A1, the reservoir was under an acidic-diagenetic environment, resulting in the development of secondary dissolution pores. If large-scale hydrocarbon charging occurred during this period, then an after-charging densification reservoir, which is the most suitable type for hydrocarbon accumulation, might have developed. Entering the middle diagenetic stage A2, the reservoir was under an acidic-alkaline transitional diagenetic environment.During this stage, dissolution became weak, and compaction and cementation were enhanced, resulting in the continuous loss of pore space and reservoir densification. Entering the middle diagenetic period B, the reservoir was under an alkaline-diagenetic environment, and the reservoir had been largely densified. If large-scale hydrocarbon charging occurred during this period, a pre-charging densified reservoir, which is the worst reservoir type for hydrocarbon accumulation, might have developed.

Key words Xihu Depression; accumulation phase; hydrocarbon charging; reservoir densification; diagenetic environment

1 Introduction

Oil and gas consumption is continuously increasing in China; however, achieving breakthroughs in conventional oil and gas exploration is difficult. Thus, with the development of unconventional hydrocarbon geological theories,global oil and gas exploration and development are transforming from the conventional to unconventional sources.As an important replacement for the sustainable development of the oil and gas industry, unconventional oil and gas sources are worth exploring (Songet al., 2015; Sobhaniaraghet al., 2016; Tian, 2019; Tianet al., 2019; Qiu and Zou, 2020). Tight oil and gas reservoirs, which are important oil and gas sources (Schmoker, 2002; Mu, 2017;Zhuet al., 2018), are the focus of unconventional oil and gas exploration at present and are considered as a major body for increasing the reserves and the production of oil and gas in China (Charpentieret al., 1995; Aïfaet al., 2014;Gonget al., 2017). At present, no strict boundary exists between tight and conventional sandstone reservoirs (Law,2002; Jianget al., 2006). In China, sandstone reservoirs with the porosity below 10% and the permeability below 0.1×10-3μm2are usually defined as tight sandstone reservoirs (Holditch, 2006; Jiaet al., 2012; Zouet al., 2013;Ciet al., 2019).

The Xihu Depression is rich in oil and gas resources and has great potential for hydrocarbon exploration and development. With the continuous exploration of low-porosity and low-permeability tight sandstone reservoirs in the Xihu Depression, the number of proven natural gas reserves has gradually increased (Heet al., 2008; Liu and Tang, 2013). Newly released statistics shows that approximately 60% of the total natural gas resources in the depression are in the low-permeability dense sandstone gas areas, which will become the main body of oil and gas exploration and development in the Xihu Depression. However, the tight sandstone reservoirs in the study area generally have strong heterogeneity (Zhaoet al., 2018). In addition, studies on reservoir densification, degree of densification, and relationship between reservoir densification and hydrocarbon filling remain limited and the exploration and development of tight sandstone gas reservoirs in the Xihu Depression are constrained. Therefore, a study on the relationship between Paleogene sandstone reservoir densification and hydrocarbon accumulation is of great theoretical value and practical importance for the subsequent hydrocarbon exploration and development.

2 Regional Geological Setting

The Xihu Depression is located in the northeast of the continental shelf of the East China Sea, trending in NESW direction (Fig.1). The depression is approximately 100 km wide in the E-W direction and 400 km long in the N-S direction, with an area of 5.18×104km2. On the basis of the tectonic and sedimentary framework, the depression can be divided into five structural units from W to E, namely,the western depression group, the western sub sag, the central uplift group, the eastern sub sag, and the eastern depression group. The depression is characterized by two sags and a central uplift, with zoning in the E-W direction,and blocking in the N-S direction (Zhanget al., 2012; Liet al., 2014; Guo, 2015; Chenget al., 2019).

The East China Sea Basin has experienced seven important regional tectonic movements since the Cretaceous(Fig.1); these movements include the Jilong, Yandang, Oujiang, Yuquan, Huagang, Longjing, and Okinawa Trough movements (Tao and Zou, 2005; Zhanget al., 2014).

Fig.1 Regional and tectonic maps of the Xihu Depression. The location maps of the East China Sea Basin is modified from Wang et al. (2020). The tectonic map of sub-structure units in Xihu Depression is after Zhang et al. (2017) and Feng et al.(2020).

The drilling results show that the Cenozoic strata are complete in the Xihu Depression (Fig.2). From the bottom to the top, the Cenozoic strata consist of the Paleocene (E1), lower Eocene (E2l), and middle - upper Eocene Pinghu formation (E2p), the Oligocene Huagang formation(E3h), the Miocene Longjing formation (N11l), the Miocene Yuquan formation (N12y), the Miocene Liulang formation (N13l), the Pliocene Santan formation (N2s), and the Quaternary Donghai Group (Qd) (Yanget al., 2013).This study focuses on the Eocene Pinghu formation and the Oligocene Huagang formation, which are the major source rocks and reservoirs in the Xihu Depression.

3 Petrological and Petrophysical Characteristics of Reservoirs

The reservoir sandstones of the Huagang and Pinghu formations in each structural belt of the Xihu Depression are mainly composed of feldspathic litharenite and lithic arkose. The quartz content is relatively high at approximately 60% to 75%. The feldspar and lithic content are approximately 20% to 40%. The sandstone is clean with a low matrix content (4% - 12%). The Huagang formation is relatively fine, that is, mainly fine to medium in grain size. Grain sorting is excellent in the western sub sag and the central uplift group, and moderate in the western depression group. Roundness is commonly subangular to subrounded.

Fig.2 General structure and stratigraphic column of the Xihu Depression. The sedimentary environment is modified from Zhao et al. (2019) and source reservoir cap rock assemblages are after Qian et al. (2020) and Su et al. (2019).

Based on the observation from thin sections, the rock of the Huagang formation in each structural unit of the Xihu Depression is mainly feldspathic and lithic quartzarenite,which accounts for more than 78% of the total reservoir sandstone. In the southern part of the central uplift group,the lithic and feldspar contents are lower than those of other areas; therefore, compositional maturity is the highest The rock of the Pinghu formation in each structural belt of the Xihu Depression is dominated by feldspathic and lithic quartz sandstone, which accounts for more than 79%of the total reservoir sandstone. The compositional maturity of the sandstone in the Pinghu formation is high (Q1 /(F1 + R1) index ＞ 2.1), although varying slightly in each structural unit. In the southern part of the central uplift group, the quartz content and compositional maturity are the highest.

Previous studies have shown that the reservoirs in different parts of the Xihu Depression vary in terms of petrophysical properties (Chen, 2016) and have strong reservoir heterogeneity. The low-porosity and low-permeability reservoir is one of the major reservoir types.

According to the porosity and permeability test results,the Huagang formation samples in the cores from the Xihu Depression have poor petrophysical properties, with the porosity ranging from 6% to 12% and the permeability ranging from 0.016×10-3μm2to 850×10-3μm2. More than 40% of the reservoir has the permeability below 1.0×10-3μm2, and the proportion of reservoirs with the permeability ranging from 1.0×10-3m2to 10×10-3m2is approximately 35%. The reservoir tends to become poor in petrophysical properties with the increase in burial depth. In the middle to the bottom of the upper member of the Huagang formation, the reservoirs have medium to low porosity and permeability, then change gradually into ultralow porosity and permeability sandstone at the lower member of the Huagang formation.

For the overall petrophysical properties, the reservoirs in the Pinghu formation are characterized by low to medium porosity and permeability. The porosity ranges from 7% to 13%, and the overall permeability ranges from 10×10-3μm2to 30×10-3μm2. The petrophysical properties of the reservoirs in the western sub sag and the central uplift group are relatively poor, with the porosity ranging from 4.6%to 8.9% and 6.0% to 7.0% and permeability ranging from 0.3×10-3μm2to 0.6×10-3μm2, respectively. These values make the western sub sag and the central uplift group ultralow-porosity and ultralow-permeability reservoirs. The petrophysical properties of the reservoirs in the southern part of the central uplift group and the western depression group are relatively good. The porosity ranges from 7% to 14% and 5% to 17%, and the permeability ranges from 8×10-3μm2to 22×10-3μm2and 14×10-3μm2to 30×10-3μm2, respectively. These values make the southern part of the central uplift group and the western depression group low to ultralow porosity and low to medium permeability reservoirs.

4 Diagenetic Types and Evolutionary Patterns

4.1 Reservoir Diagenesis

4.1.1 Compaction

The Huagang and Pinghu formations in the Xihu Depression have experienced strong compaction, which is shown in three aspects. First, plastic particles, such as mica, were plastically deformed and preferentially oriented (Figs.3a and 3b). Second, soft lithics, such as phyllite, schist, and shale clast, underwent plastic deformation, and some even became pseudomatrix (Fig.3c). Third, clastic particles were in line or in concave-convex contact, and stylolite contact occurred among some quartz grains due to pressure dissolution (Fig.3d). In the upper member of Huagang formation and the Pinghu formation, the original pores are preserved better than the ones in the lower member. The proportion of original pores decreases with the increase in burial depth. Compaction is a destructive diagenetic process for the reservoir sandstone, reducing the reservoir porosity remarkably.

4.1.2 Cementation

In the study area, the cementation of reservoirs is generally limited. The total cement content is approximately 4.8%. In addition, the composition of the cements in the Huagang and Pinghu formations in the Xihu Depression is relatively monotonous, that is, dominated by carbonate minerals (calcite, ferrocalcite, dolomite, ankerite, and siderite), kaolinite, and siliceous cement (Fig.4). The proportion of other authigenic minerals is low. Carbonate cements have dispersed, blocky, or poikilotopic textures. Authigenic kaolinite minerals mainly fill in the intergranular or intragranular pores formed by the dissolution of aluminosilicates, such as feldspar. The pseudomatrix cements formed by the compaction of mud clasts and the plastic deformation of mica are also common. Partial authigenic quartz minerals result from the dissolution and precipitation of detrital quartz grains.

4.1.3 Dissolution

In the sandstone reservoirs of the Huagang and Pinghu formations in the study area, the dissolution, mainly of aluminosilicate minerals, commonly occurred. Feldspar skeleton particles often suffered from dissolution along the grain edges, cleavage planes, and/or joint fractures, resulting in the formation of intragranular dissolved pores or molds (Figs.5a and 5b). Feldspar-bearing volcanic debris often suffered from selective dissolution by organic acid(Fig.5b). With the increase in burial depth, more feldspar grains were dissolved to form secondary pores under an acidic-diagenetic environment, leading to the formation of secondary pore-developed zones due to organic acid dissolution in the Xihu Depression (Zhanget al., 2019).

Fig.3 Micrographs to illustrate the tight compaction characteristics of the Huagang and Pinghu formations in the Xihu Depression. (a), mica plastically deforms and develops fractures, (+), well AA3, 3426.5 m, Huagang formation; (b), line contact is dominant. Plastic clasts, such as mica, are compacted and deformed, only retaining a small amount of primary intergranular pores, (-), well AW6,3963.3 m (TVD), Pinghu formation; (c), grains show line to concave-convex contact, and a few show suture contact.Plastic clasts are severely compacted and develop pseudomatrix, (+), well AA7, 3725.52 m, Huagang formation; (d),clasts are mainly in line contact. A small amount of kaolinite is observed in pore space, (-), well UE1, 3609.44 m,Pinghu formation.

4.2 Reservoir Diagenetic Evolutionary Stage and Pore Evolutionary Process

Fig.4 Authigenic mineral compositions of the Huagang and Pinghu formations in the Xihu Depression (according to thin section analysis).

Fig.5 Micrographs to illustrate the dissolution of sandstone reservoirs in the Huagang and Pinghu formations in the Xihu Depression. (a), intergranular and intragranular pores, molds, dissolved fractures, well LN2, Pinghu formation, 3503.14 m, 10×10 (-); (b), volcanic debris were dissolved to form intragranular pores, well LM1, Huagang formation, 3858.6 m, 10×10 (+).

Diagenetic stages affect the formation and evolution of pores in oil and gas reservoirs by controlling the preservation of primary pores, the distribution of secondary pores,and the connectivity of pores. The diagenetic stages of the Huagang and Pinghu formations in the Xihu Depression are qualitatively and semiquantitatively divided on the basis of many types of data, including observation of the diagenetic features in each structural unit; results of the Eocene - Oligocene Ro (vitrinite reflectance), Tmax(pyrolytic peak temperature), Th (homogenization temperature of inclusions), X-ray diffraction, and scanning electron microscopy; evolutionary characteristics of authigenic minerals under microscopic observation; petrophysical properties and pore structure.

An example is the middle-northern part of the central uplift group, where the reservoir burial depth is large, and the diagenetic environment evolution process is relatively complete. Four diagenetic stages and five diagenetic periods are determined for the sandstones in the Huagang and Pinghu formations; these stages and periods are the syndiagenetic stage, the early diagenetic stage (stages A and B), the middle diagenetic stage (stages A and B), and the late diagenetic stage.

4.2.1 Syndiagenetic stage

The sedimentary facies of the Huagang and Pinghu formations in the study area is delta front to prodelta. According to the statistical analysis to 1324 samples from the Huagang and Pinghu formations, most of the sandstones are relatively fine in grain size, that is, mainly medium to fine sandstones. The lack of fine-grained sediments and interstitial materials in sandstones increases the possibility of porosity reduction due to mechanical compaction.

4.2.2 Early diagenetic stage

Stage A: The smectite content in the I/S mixed layer reached 70%. With the increase in overburden load, the porosity of the reservoir decreased rapidly by mechanical compaction. A small amount of chlorite coating (pore lining) pores and associated siderite minerals were observed in a few wells in the middle-northern part of the central uplift group due to the alkaline-diagenetic fluid. Authigenic quartz was difficult to grow within the chloritecoating pores. Consequently, some of the original intergranular pores were preserved. In early stage A, the porosity was maintained at 20% - 25%.

Stage B: The smectite content in the I/S mixed layer reached 50% - 70%. Affected by atmospheric fresh water and acidic fluids, the acidic pore fluid in the sandstone reservoirs could dissolve aluminosilicate minerals, resulting in the enlargement of feldspar dissolution pores. Dissolution induced the enlargement of secondary intergranular pores, and the average porosity increased slowly.

By the end of this period, the porosity of the sandstone reservoirs in the Huagang and Pinghu formations was maintained at approximately 20% - 28% due to the alteration by atmospheric water and early diagenetic acidic fluids.

4.2.3 Middle diagenetic stage

Stage A: The smectite content in the I/S mixed layer accounted for 35% - 50%. The original intergranular pores reduced continuously due to mechanical compaction. The organic matter within the source rocks entered the lowmature to mature stage. Aluminosilicates, such as feldspar,were dissolved due to the formation of organic acids under burial diagenetic conditions. The reservoirs near the source rocks, especially the lower member of the Huagang and Pinghu formations, were strongly affected by the diagenetic fluid. During this stage, the K+concentration in the pore fluid increased due to the dissolution of feldspar and other aluminosilicates; as a result, the conversion of smectite into I/S mixed minerals under relatively high diagenetic temperature accelerated. High PCO2within the diagenetic fluid had a buffering effect on pH when aluminosilicates, such as feldspar, were dissolved. Carbonate minerals were difficult to dissolve. When the concentration of Ca2+, Fe3+, and Mg2+ions converted from clay minerals increased, the Ca2+concentration producedviafeldspar dissolution would increase, and carbonate cementation would occur, resulting in the alteration of feldspar dissolution and calcite precipitation. In the middle diagenetic stage A, the porosity was maintained at 10% - 16%.

Stage B: During this stage, the diagenetic fluid became alkaline. The Ca2+, Mg2+, and Fe2+ions in the pore fluid combined with CO32-to form ferrocalcite, ankerite, and other iron carbonates within the reservoirs. Due to severe mechanical compaction and late-stage carbonate cementation, partial intergranular pores in the sandstone reservoir were blocked, resulting in the decrease in porosity.Lastly, the reservoirs became tight, and the porosity was maintained at approximately 6% - 10%.

4.2.4 Late diagenetic stage

During the late diagenetic stage, Ro ＞ 2%, Tmax＞ 490℃,fluid temperature ＞ 150℃, smectite in I/S mixed layer ＜15%, and late diagenetic minerals appeared. Organic matters were highly mature to over mature. The transition of clay minerals continued to supply Na+, Ca2+, Fe3+, Mg2+,and Si4+ions for the diagenetic fluid. The alkaline water was rich in calcium, magnesium, and iron ions, and ferrocalcite and siderite began to precipitate. The cementation of iron-bearing calcite and the mechanical compaction in the deep formations were the major reasons for the deterioration of the petrophysical properties for the reservoirs at this stage.

5 Relationship Between Reservoir Densification and Hydrocarbon Charging

5.1 Reasons for reservoir densification

The sandstone reservoir in the study area has undergone varying degrees of alteration during diagenesis. Reservoir densification occurred because of two reasons. First, strong mechanical compaction caused a great loss of porosity.Second, pore filling occurred due to the widespread development of carbonate and siliceous cementation. The sandstone cement content-negative cement porosity plot (the porosity afterremoving all cement) of the Huagang and Pinghu formations 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. On the basis of the analysis results of each structural unit in the study area, data points are concentrated in the lower left corner of compaction zone (Fig.6). Therefore, compaction is the major controlling factor for porosity reduction and reservoir densification, whereas cementation is the secondary controlling factor for reservoir densification.

5.2 Reservoir Densification Time

According to the petrophysical data and comprehensive analysis of the diagenesis and pore evolution of the Huagang and Pinghu formations in each structural unit in the study area, the diagenetic environment at middle diagenetic stage A2began to change from acidic to alkaline, resulting in the weak dissolution process. Accompanied by carbonate and siliceous cementation and continuous mechanical compaction, the porosity of sandstone reservoirs decreased gradually to approximately 10%. Therefore, the initiation of middle diagenetic stage A2corresponds to the beginning of reservoir densification.

Based on the analysis of the burial history and diagenetic pore evolutionary pattern of the reservoirs in the study area (Figs.7 - 12), the start time of middle diagenetic stage A2was different for the reservoirs in the different structural belts. In the western sub sag and north and central parts of the central uplift group, the reservoirs entered the middle diagenetic stage A2relatively early and tended to be compacted relatively early due to the fast burial rate and great burial depth. In the western depression group and south of the central uplift group, the reservoir densification time was relatively late; moreover, part reservoirs have not entered the middle diagenetic stage A2.

The densification time of the lower member of the Huagang formation in the middle-northern part of the central uplift group was 18 Myr to 15 Myr. The densification time of the upper member of the Huagang formation was 2.75 -0 Myr (the first initiation time was 16 - 14 Myr; Fig.7).

The densification time of the upper member of the Pinghu Formation in the middle-southern part of the central uplift group was 10 - 5 Myr (the start time of densification was 16 - 14 Myr; Fig.6). The densification time of the lower member of the Pinghu formation was 4 - 0 Myr. Partial reservoirs in the upper member of the Pinghu formation have not entered the middle diagenetic stage A2(Fig.8).

The densification time, determined by the time of entering the middle diagenetic stage A2, of the lower member of the Pinghu formation in the southern part of the central uplift group was 29 - 11 Myr. The densification time of the middle and upper members of the Pinghu formation was 15 - 0 and 3 - 0 Myr, respectively. The densification time of the lower member of the Huagang formation was 2 - 0 Myr, and that of the upper member of the Huagang formation has not entered the middle diagenetic stage A2;furthermore, the porosity and permeability of the reservoirs there are generally good (Fig.9).

Fig.6 Cross plots of the cement content and minus-cement porosity of the Paleogene Huagang and Pinghu formations in the Xihu Depression.

Fig.7 Relationship between diagenesis-porosity evolution in reservoirs and hydrocarbon charging phases in the middlenorthern part of the central uplift group (based on well QP1).

Fig.8 Relationship between diagenesis-porosity evolution in reservoirs and hydrocarbon charging phases in the middlesouthern part of the central uplift group (based on well AA4).

Fig.9 Relationship between diagenesis-porosity evolution in reservoirs and hydrocarbon charging phases in the southern part of the central uplift group (based on well MT2).

The densification time of the lower and upper members of the Huagang Formation in western sub sag was 15.75 -3 and 11.5 - 0 Myr, respectively (Fig.10). The densification time of the Pinghu formation should be earlier than that of the lower member of the Huagang formation due to its great burial depth (undrilled). Therefore, most of the reservoirs of the Pinghu formation in the western sub sag are tight reservoirs.

In the Pinghu structural belt (belonging to the western depression group), the densification time was late. The reservoirs had relatively good petrophysical properties, making them favorable exploration targets. Currently, only the reservoirs in the lower member of the Pinghu formation have entered the middle diagenetic stage A2, and the overlying reservoirs have not entered the middle diagenetic stage A2(Fig.11). The densification time of the lower and middle members of the Pinghu formation in the north of the Pinghu structural belt was 4 - 0 and 3.5 - 0 Myr, respectively (Fig.11). The other overlying reservoirs have not entered the middle diagenetic stage A2.

Fig.10 Relationship between diagenesis-porosity evolution in reservoirs and hydrocarbon charging phase in the western sub sag (based on well WS2).

Fig.11 Relationship between diagenesis-porosity evolution in reservoirs and hydrocarbon charging phases in the Pinghu structural belt (based on well B1).

5.3 Hydrocarbon Charging Phase

The burial and thermal histories were simulated by combining the stratified data, amount of strata denudation, Ro value, hydrogen index, pyrolysis peak temperature (Tmax),and formation temperature from well TK1, with Easy%Ro chemical kinetic model of basins (Fig.12). The simulation results indicated that the organic matters in the Pinghu and Huagang formations began to mature and reached the hydrocarbon generation peak in the Miocene.

The fluid inclusion analysis revealed that hydrocarbonbearing inclusions commonly occur within the quartz overgrowths, calcite cements, and fractures cutting through quartz grains (Table 1). Based on the fluid homogenization temperature and thermal and burial histories, three hydrocarbon charging phases are inferred (Table 1).

Fig.12 Schematic map on thermal evolution and burial history of well TK1.

Table 1 Relation between hydrocarbon charging phase and characters of hydrocarbon-bearing inclusions in the Xihu Depression

The first hydrocarbon charging phase was approximately 19 - 17 Myr (Table 1), and the corresponding homo-genization temperature was 96 - 107℃. The scale of hydrocarbon charging at this phase was small, and hydrocarbons released during the early mature stage of organic matters were the main source (Liuet al., 2018). These hydrocarbons were captured by early-stage calcite cements.Although the total hydrocarbon charging during this period was small and contributed little to the hydrocarbon accumulation, the dissolution by organic acidic fluids improved the petrophysical properties of the reservoir to some extent.

The second hydrocarbon charging phase was approximately 17 - 11 Myr (Table 1), and the corresponding homogenization temperature was 118 - 150℃. The amount of oil charging at this phase was still relatively small, and hydrocarbons were captured in reservoirs as inclusions within the quartz overgrowth. Moreover, the reservoirs were in good oil-bearing conditions. The abundance (GOI)of hydrocarbon-bearing brine inclusions was average.

The third hydrocarbon charging phase was relatively late at approximately 11 - 0 Myr (Table 1), being the most important oil and gas charging stage in the study area.Inclusions were mainly in the second-stage calcite cement,and corresponding homogenization temperature was 135 -155℃. The abundance of hydrocarbon-bearing brine inclusions was high (4% - 5%), and the abundance in some calcite cements was high (up to 30% - 40%). The contents of brown hydrocarbon fluid inclusions and dark gray gas inclusions were 70% and 30%, respectively.

5.4 Reservoir Classification Evaluation

The sandstone reservoirs greatly differed horizontally and vertically between various structural belts in the study area due to the differences in the sedimentary facies, rock types, diagenesis, and petrophysical properties of the Paleogene sandstone reservoirs in the Xihu Depression.Through an integrated analysis of mercury injection data,core testing results, and thin section observation, the parameters for the classification of the reservoirs according to the petrophysical properties were determined, and the criteria for reservoir classification and evaluation that is suitable for the actual exploration and development of the Xihu Depression were established (Table 2). Types I, II1,and II2reservoirs with natural productivity are classified as high-quality reservoirs.

5.5 Relation Between Reservoir Densification and Hydrocarbon Accumulation

In accordance with the diagenesis stage and pore evolutionary pattern, combined with the relationship between reservoir densification time and hydrocarbon main charging phase (11 - 0 Myr) in different structural belts (Figs.7 -11), the reservoirs can be classified into three types: precharging, syn-charging, and after-charging densification.

After-charging densification reservoir: This type is commonly shallow in burial depth, and the compaction strength it suffered is relatively small. The reservoir has not entered the middle diagenetic stage A2and underwent strong dissolution under acidic diagenetic condition, resulting in good petrophysical properties. During the third-phase large-scale hydrocarbon charging (11 - 0 Myr), sand-stone reservoirs(excluded siltstone) maintained an uncompacted state with good porosity and permeability (Φ ＞ 10%, K ＞ 1×10-3μm2).This type of reservoir belongs to types I - II2. Before hydrocarbon accumulation, the reservoir is not yet dense,and the reservoir petrophysical property is ready for largescale hydrocarbon charging, resulting in excellent accumulation efficiency. Consequently, this type of reservoir is the most prospective reservoir in the study area; it is mainly located in the Pinghu structural belt, the upper member of the Huagang formation in the middle-northern part of the central uplift group, the Huagang and Pinghu formations in the southern part of the central uplift group,and the upper member of Huagang formation in the Yuquan structural belt of the middle-northern part of the central uplift group (Figs.13 and 14).

Syn-charging densification reservoir: This type has entered the middle diagenetic stage A2. The alteration by acidic fluid has weakened due to the transition from acidic to alkaline-diagenetic conditions. Reservoirs gradually became dense during the third-phase hydrocarbon charging in 11 - 0 Myr due to relatively strong compaction and carbonate and siliceous cementation. Porosity and permeability reduced gradually to 6% and 1.0×10-3μm2, respectively. Majority of the reservoirs belong to type II2,and a few belongs to types I - II2.

Reservoir densification is synchronized with the third large-scale hydrocarbon charging phase (11 - 0 Myr). Thus,continuous hydrocarbon charging not only reduces the strength of cementation effectively but is also favorable for maintaining the good petrophysical properties of the reservoir due to overpressure. Therefore, this type of reservoir is good for hydrocarbon accumulation and has good potential for exploration. The potential of syn-charging densification reservoirs is only less than that of aftercharging densification reservoirs. On the basis of drilling data in various structural belts, this type of reservoir is mainly distributed in the upper member of the Huagang formation in the western sub sag, the upper member of the Huagang formation in the middle-northern part of the central uplift group (Fig.13a), and the lower member of the Huagang formation and upper member of the Pinghu formation in the middle-southern part of the central uplift group (Figs.13b and 14c).

Pre-charging densification reservoir: This type has entered the middle diagenetic stage B recently. These reservoirs underwent severe compaction and late-stage carbonate cementation due to alkaline-diagenetic conditions. Almost all reservoirs, including well-sorted medium-coarse sandstones and poorly sorted conglomeratic sandstones,have very low porosity and permeability (Φ ＜ 10%, K ＜ 1×10-3μm2). This type of reservoir belongs to types III and IV, without natural production capacity. Moreover, the reservoir had fully entered the middle diagenetic stage A2and became dense before the third large-scale hydrocarbon charging in 11 - 0 Myr due to great burial depth and an enhanced pore evolutionary process. The hydrocarbon accumulation and exploration potential of this type of reservoir are limited. The pre-charging densification reservoir is mainly distributed in the lower member of the Huagang formation in the western sub sag and the middlenorthern part of the central uplift group, and the middle and lower members of the Pinghu formation in the southern part of the central uplift group.

Table 2 Classification criteria for evaluating the Paleogene sandstone reservoirs in the Xihu Depression

Fig.13 Distribution of high-quality reservoirs in the upper (a) and lower (b) members of the Huagang formation in the Xihu Depression.

Fig.14 Distribution of high-quality reservoirs in the upper (a), middle (b), and lower (c) members of the Pinghu formation in the Xihu Depression.

6 Conclusions

1) Reservoir densification is caused by strong mechanical compaction and wide development of siliceous and carbonate cement, and the former is the major reason for the loss of porosity and densification of the Huagang and Pinghu formations.

2) The sandstone reservoirs in the Huagang and Pinghu formations of the Xihu Depression have mainly experienced three types of diagenesis and a total of 4 stages (6 periods) of diagenetic evolutionary process. The three types of diagenesis are compaction, cementation, and dissolution. The six periods of the diagenetic evolutionary process include the syngenetic stage, the early diagenetic stages A and B, and the middle diagenetic stages A and B, and the late diagenetic stage. Severe compaction in the syngenetic stage established the fundamental characteristics of the reservoir densification. In the early diagenetic stage A, mechanical compaction is the major diagenetic process. Later,the degree of compaction increased continuously, and the original intergranular porosity decreased gradually. In the middle diagenetic B period, reservoirs finally became dense under the strong mechanical compaction and late-stage carbonate cementation.

3) During the middle diagenetic stage A2, the diagenetic environment changed from acidic to alkaline, leading to weakened dissolution accompanied by late-stage carbonate and siliceous cementation and enhanced compaction. This process marks the initiation of reservoir densification. In consideration of the relationship between hydrocarbon charging and densification, reservoirs in the Huagang formation in the study area can be divided into three types: pre-charging, syn-charging, and after-charging densification. The reservoirs of the Huagang and Pinghu formations in the western depression group are aftercharging densification reservoirs. The reservoirs of the Huagang formation and the upper member of the Pinghu formation in the western sub sag are mainly syn-charging densification reservoirs. Reservoirs in the central uplift group gradually become poorer from north to south and from shallow to deep.

Acknowledgements

This study was supported by the National Science and Technology Major Projects (No. 2016ZX05027-002-006)and the Research on the Key Technologies of Exploration and Development in the West of Xihu Depression (No.CNOOC-KJ135ZDXM39SH01).