Fluid Properties, Charging Stages, and Hydrocarbon Accumulation Process in the Pinghu Oil and Gas Field, Xihu Sag, East China Sea Shelf Basin

Abstract

The Pinghu Oil and Gas Field in the East China Sea Shelf Basin represents a significant offshore hydrocarbon-producing region in East Asia. However, the Paleogene hydrocarbon system in the Pinghu Oil and Gas Field is complex, and the fluid properties, charging stages, and hydrocarbon accumulation process are still unclear. A comprehensive integrated analysis of the hydrocarbon accumulation characteristics, fluid properties, temperature pressure regimes, primary hydrocarbon sources and origins (genesis), charging stages, preservation conditions, and evolutionary history of hydrocarbon accumulation have been studied by utilizing a series of well data, oil and gas geochemical parameters, carbon isotope, and fluid inclusion analyses. Hydrocarbon charging in the Huagang Formation experienced one stage, and the crude oil is characterized as light and conventional, exhibiting low density and viscosity, a low pour point, and low contents of wax, resin, and sulfur. In contrast, the reservoir of the overpressured Pinghu Formation experienced a two-stage hydrocarbon charging process (oil filling and gas filling), exhibiting higher density, viscosity, and wax content compared to the Huagang Formation. The hydrocarbon charging and evolution process of the Pinghu Formation and Huagang Formation in the Pinghu Oil and Gas Field can be summarized in three different stages, including the oil filling period (10–5 Ma), gas filling period (5–2 Ma), and oil and gas adjustment period. The Pinghu Oil and Gas Field, especially in the lower Pinghu Slope Belt (Fangheting Structure), has good potential for further exploration.

1. Introduction

The Pinghu Oil and Gas Field, situated within the western slope of Xihu Sag in the East China Sea Shelf Basin, represents a significant offshore hydrocarbon-producing region in China [1,2,3,4,5]. Its primary producing intervals are the Eocene Pinghu Formation and Oligocene Huagang Formation [6,7,8]. The hydrocarbon accumulation process in this field is complex, having undergone multiple episodes of tectonic activity and fluid charging [2,6]. Elucidating the fluid properties, oil and gas charge history, and overall hydrocarbon accumulation process is crucial for enhancing geological understanding and guiding future exploration and development activities. Over the past decade, advancements in deep-water exploration technology and fundamental research have enabled significant progress in this field by global petroleum geologists. The main research efforts have focused on the following three aspects: (1) fine-scale characterization of fluid properties and genetic identification [9], (2) precise determination of multi-phase charging episodes [6], and (3) dynamic simulation of the hydrocarbon accumulation process and establishment of accumulation models [10].

Previous studies have revealed the fluid properties, accumulation history, and aggregation mechanisms of the Pinghu Oil and Gas Field through various technical methods, such as biomarker compounds, isotopes, fluid inclusions, and basin modeling [11,12,13,14,15,16]. The major findings include the following: the coal-measure strata of the Pinghu Formation are the main hydrocarbon source rocks, the natural gas is mainly coal gas, and two stages of hydrocarbon accumulation events have been identified, namely the late Miocene and the Pliocene–Quaternary [14]. The latter is closely related to the late rapid subsidence and the peak of hydrocarbon generation in the East China Sea Basin. The late tectonic activities provided migration pathways for the large-scale hydrocarbon accumulation in the second stage [15].

Thus, during the exploration and development of the Pinghu Oil and Gas Field, researchers have recognized favorable conditions for the development of lithological reservoirs or structural–lithological composite reservoirs within its deep-buried strata, especially in the Pinghu and Huagang Formations. This understanding is supported by two key observations: (1) Many structural traps initially identified during the early development phase were subsequently been shown to exhibit lithological constraints as exploration progressed [2,4,6,17,18,19,20]; and (2) recent exploration targeting lithological reservoirs within the Pinghu Oil and Gas Field has yielded significant discoveries, encompassing both lithological traps and composite traps, in both the western structural highs and eastern structural lows [4,5,7,21,22,23,24,25,26,27]. These successes highlight the field’s substantial remaining exploration potential in lithological reservoir plays.

However, despite the superior fundamental geological conditions of the Pinghu Oil and Gas Field within the Xihu Sag, over twenty years of exploration and development have led to its entry into a production decline phase. The production outlook is becoming increasingly challenging, necessitating a comprehensive integrated analysis of the following critical aspects for the Paleogene system [28,29,30]: hydrocarbon accumulation characteristics, fluid properties, temperature–pressure regimes, primary hydrocarbon sources and origins (genesis), charging episodes, hydrocarbon migration pathways, preservation conditions, and evolutionary history of hydrocarbon accumulation.

This study aims to conduct an in-depth synthesis and analysis by utilizing representative well data and associated analytical test results from the Pinghu Oil and Gas Field. The primary research objectives are as follows: (1) to delineate the principal hydrocarbon accumulation intervals within the Pinghu Field and elucidate their spatial distribution patterns; (2) to characterize the dominant oil reservoir types, dominant gas reservoir types, fluid properties, and temperature–pressure regimes; and (3) to elucidate the primary hydrocarbon sources, charging stages, and preservation conditions, thereby clarifying the hydrocarbon accumulation processes and constructing evolutionary models for the accumulation history. This integrated research holds significant implications not only for guiding future exploration strategies within the Pinghu Oil and Gas Field in Xihu Sag, but also for providing valuable insights applicable to hydrocarbon exploration in other geologically analogous regions.

2. Geological Setting

The Xihu Sag is situated on the eastern continental shelf margin within the East China Sea Shelf Basin [1,2,3,4,5,8,11], exhibiting a predominant north–northeast (NNE) strike (Figure 1a). The formation dip direction of the western slope is about 100° to 130° (SE direction) and the dip angle is between 3° and 6° (Figure 2b). It covers an area of approximately 5.2 × 10⁴ km², with dimensions of roughly 400 km north–south and 100 km east–west. Its eastern boundary is defined by the Diaoyu Uplift, while its western margin transitions southward from the Haijiao Uplift to the Yushandong Uplift; the Diaobei Sag lies to the south. In addition, the Xihu Sag can be subdivided west-to-east into five distinct zones: the Western Slope Zone, Western Subsag Zone, Central Anticline Belt, Eastern Subsag Zone, and Eastern Fault Belt Zone (Figure 1a). The Central Anticline Belt is characterized by the development of multiple inverted anticlinal structures [10], exhibiting a north–northeast (NNE, 25° to 40°) strike and northwest–southeast (NW-SE) dip direction. The Western Slope Zone is characterized by three different slopes from north to south (Hangzhou Slope Belt, Pinghu Slope Belt, and Tiantai Slope Belt). The tectonic evolution of the Xihu Depression comprises three main phases (Figure 2): (1) the syn-rift phase (Late Cretaceous to Eocene, T100 to T40), (2) the post-rift inversion phase (Oligocene to Miocene, T40 to T20), and (3) the regional subsidence phase (Pliocene to Quaternary, T20 to T0) [31,32].

The Pinghu Oil and Gas Field is situated in the central segment of the Western Slope Zone (the middle and southern Pinghu Slope Belt) within the Xihu Sag (Figure 1b). It is bounded to the west by the Pinghu Main Fault and to the east by the Santan Subsag (Figure 2b). During the Paleocene to Eocene period, under regional transtensional stress [4], faults in this region developed various scales, predominantly oriented NNE (north–northeast) with subordinate NNW (north–northwest) trends. These faults compartmentalized the Pinghu Oil and Gas Field into multiple structural traps, including the northern Tuanjieting Structure, the central Bajiaoting and Fangheting Structures, and the southwestern Zhongshanting Structure (Figure 1b). In this study, the Bajiaoting and Fangheting Structures are the significant regions for the fluid properties, charging episodes, and hydrocarbon accumulation process analyses.

The stratigraphic sequence encountered in drilling within the Pinghu Oil and Gas Field, from top to bottom, comprises (Figure 2) the Quaternary Donghai Formation, Pliocene Santan Formation, Miocene Liulang Formation, Yuquan Formation, Longjing Formation, Oligocene Huagang Formation, and Eocene Pinghu Formation, and the underlying Baoshi and Bajiaoting Formations. The primary hydrocarbon-bearing intervals in the Pinghu Field are the Huagang and Pinghu Formations. The field exhibits a characteristic hydrocarbon distribution pattern of oil reservoirs overlying gas layers [2,7], representing a dual hydrocarbon system.

In the Xihu Sag, the Pinghu Formation (estuarine, tidal flat, and deltaic deposits) is the main source rock [3]. The spatial distribution (both vertical and lateral) of coal-measure source rocks of the Pinghu Formation exhibits significant heterogeneity across the western slope, with considerable variations in geochemical characteristics and hydrocarbon generation potential among different areas [33,34]. These variations give rise to distinct oil and gas distribution patterns regionally. In contrast, the Huagang Formation (lacustrine and shallow-water fluvial–deltaic deposits) hosts the primary sandstone reservoirs. Development of an axial, basin-scale fluvial system within the Huagang Formation occurred during the Oligocene post-rift phase [4,10]. This system was predominantly fed by a northern provenance axis, with relatively minor sediment contributions from lateral sources. Fluvial channel morphologies within this system exhibit a downstream transition from straight and low-sinuosity braided, through high-sinuosity braided, to meandering patterns [5,7].

The main types of source rocks in the Pinghu Formation of the Xihu Sag include coal, carbonaceous mudstone, and dark mudstone [10], which have a good material basis for hydrocarbon generation and high TOC contents. Specifically, the average TOC content of coal is 51.3%, and the hydrocarbon generation potential (S1 + S2) is >90 mg/g; the average TOC content of carbonaceous mudstone is 12.6%, and the hydrocarbon generation potential (S1 + S2) is >35.4 mg/g; the TOC content of dark mudstone is greater than 1.0%, with an average of 1.23%, and the hydrocarbon generation potential (S1 + S2) is >2 mg/g. The thermal evolution degree of organic matter in the Pinghu Formation is mainly in the mature oil-generating window stage (Ro is mainly between 0.5–1.3%), but in some local deep sags or subsags, it has entered the highly mature gas-generating stage (Ro can reach 1.3–1.87% or even higher). This endows the Pinghu Formation with the resource characteristics of generating both oil and gas, with gas being the dominant product.

On the whole, this study focuses on the sandstone and mudstone intervals of different drilled wells within the Pinghu and Huagang Formations of the Bajiaoting and Fangheting Structures (Figure 1 and Figure 2). The target interval is interpreted as part of a tidal flat and fluvial–deltaic depositional system [11].

3. Dataset and Methods

This study integrates drilled-well data from 30 wells of the Pinghu Oil and Gas Field, especially from Bajiaoting and Fangheting Structures (Figure 1b), as well as the analysis and testing data of 258 core samples related to these wells. The main series of test analyses used in this research includes analyses of oil and gas geochemical parameters (such as gas–oil ratio, density, wax content, pressure coefficient, hydrocarbon source rock types, and vitrinite reflectance), carbon isotopes (δ¹³C₁, δ¹³C₂, δ¹³C₃), and fluid inclusion.

The crude oil (20 samples) and natural gas (18 samples) used in this study were mainly collected from the Pinghu Formation and Huagang Formation in 13 wells (W1, W2, W3, W4, W5, W6, W9, W11, W15, Wb1, Wb2, Wb6, and Wg4) in the Pinghu Oil and Gas Field. Among them, the crude oil samples were mainly obtained by downhole samplers, capturing crude oil fluids at the target production layer depth or specific positions in the wellbore, with relatively high-quality samples. The natural gas samples were mainly collected at the wellhead. At the oil–gas separator after the wellhead production pipeline, both the separator oil samples and separator gas samples were collected simultaneously. The source rocks in the study area are mainly mudstones of the Pinghu Formation. In this study, 22 mudstone samples were collected, and the relevant samples were mainly from five wells: W2, W5, W6, W11, and W15.

In this study, the hydrocarbon saturations of different strata in the Pinghu Formation and Huagang Formation were mainly obtained through the analysis of rock samples (cores or sidewall cores) taken from underground. Hydrocarbon saturation refers to the percentage of the volume occupied by oil or gas in the pore space of reservoir rocks. For the data in this study area, cores from different reservoirs in the Pinghu Oil and Gas Field were subjected to pressure-maintaining treatment and then quickly sent to the laboratory. Through a series of experiments for separation, the volumes of oil, gas, and water in the pores of different reservoir samples were measured mainly by the combined analysis of distillation method and chromatographic technology, and finally the corresponding saturation values were obtained.

The analyses above were carried out at the State Key Laboratory of Geological Processes and Mineral Resources, China University of Geosciences (Wuhan). In addition, the Pinghu Oil and Gas Field area is covered by high-resolution 3D seismic data with an area of approximately 1000 km². The seismic data, acquired in 2018 using dual-vessel, ten-streamer 3D acquisition, feature 54-fold coverage, 75 m cable spacing, and bin sizes of 25 m (X-line) and 12.5 m (inline). In addition, the locations of different drilled wells used in this study are shown in Figure 1b.

This study summarizes the fluid properties, charging episodes, and hydrocarbon accumulation process in the Pinghu Oil and Gas Field with different structures (especially the Bajiaoting and Fangheting Structures) in the western slope belt of the Xihu Sag through a comprehensive research method of oil and gas geochemical analysis and fluid inclusion analysis. Based on the depositional evolution characteristics from the Eocene Pinghu Formation to Oligocene Huagang Formation, integrated with the hydrocarbon sources, accumulation phases, migration pathways, and preservation conditions, we try to reconstruct the hydrocarbon accumulation processes of multiple filling stages in the Pinghu Oil and Gas Field, and establish corresponding hydrocarbon charging–accumulation evolution models.

4. Results and Interpretation

4.1. Types of Oil and Gas Reservoirs and Main Layers

Within the Pinghu Oil and Gas Field, hydrocarbons are primarily distributed within the Huagang Formation and the Pinghu Formation (Figure 3, Figure 4 and Figure 5). The hydrocarbon phases include light oil and condensate gas. Light oil is predominantly found in the Huagang Formation (Figure 3), while condensate gas is mainly concentrated in the Pinghu Formation (Figure 3). Due to the development of abnormal high pressure starting from the lower member of Pinghu Formation (P12 to P9), a distinct vertical distribution pattern emerges: overpressured condensate gas developed in the lower member of Pinghu Formation, normally pressured condensate gas developed in the middle–upper member of Pinghu Formation (P8 to P5, and P4 to P1), and light oil developed in the Huagang Formation.

The hydrocarbon distribution pattern in the Pinghu Oil and Gas Field exhibits general similarity to the overall characteristics of the Pinghu Slope Belt of the Xihu Sag [10]. However, it differs significantly from the Central Anticlinal Belt. High-maturity dry gas reservoirs are commonly encountered within the Central Anticlinal Belt, whereas the Pinghu Slope Belt, including the Pinghu Oil and Gas Field, is dominated by condensate gas reservoirs. This contrast reflects the variation in hydrocarbon generation maturity across different structural belts.

Significant variations in hydrocarbon distribution are also observed among different structural belts within the Pinghu Oil and Gas Field (Figure 3). The Upper Pinghu Slope Belt is predominantly characterized by light oil. For instance, Well Wg4 encountered crude oil in the P11 reservoir unit of the lower member of the Pinghu Formation. Hydrocarbons are primarily distributed within the Huagang Formation and the middle–lower members of the Pinghu Formation in the Middle Pinghu Slope Belt (e.g., Zhongshanting and Bajiaoting Structures) (Figure 3 and Figure 4). The oil layer is predominantly concentrated in the H4 reservoir unit, with minor occurrences in the H5 and H6 units. Condensate gas is mainly concentrated in the P5–P8 and P11–P12 reservoir units (Figure 3 and Figure 4). In contrast, hydrocarbon accumulation occurs across a broader range of stratigraphic intervals in the Lower Pinghu Slope Belt (Fangheting Structure) (Figure 3 and Figure 5). The oil layer is distributed from the H1 to H7 reservoir units. Condensate gas is present throughout the Pinghu Formation, although the primary productive intervals (e.g., P1, P3, P6, P8, and P10) vary significantly among different wells (Figure 3 and Figure 5). Thus, in plain view, the hydrocarbon distribution pattern across the Pinghu Oil and Gas Field indicates that the hydrocarbon enrichment level in the Middle and Lower Pinghu Slope Belts is generally higher than that observed in the Middle–Upper Pinghu Slope Belt areas.

The discovered hydrocarbon accumulations in the Pinghu Oil and Gas Field can also be classified as structural reservoirs, specifically structural–stratigraphic (or structural–lithologic) composite reservoirs, with a significant number of stratigraphic (or lithologic) reservoirs also present (Figure 6). Although the Huagang Formation exhibits well-developed sandstone bodies, its hydrocarbon reservoirs are predominantly structural and lithologic reservoirs with bottom water or thin-bedded reservoirs (Figure 6a). In contrast, the Pinghu Formation, characterized by moderately developed sandstone bodies, hosts a greater diversity of reservoir types, including well-developed structural, structural–lithologic composite, and lithologic reservoirs (Figure 6a).

In summary, the Fangheting structural area contains the greatest number of gas reservoirs and exhibits the richest variety of reservoir types (Figure 6b). The Zhongshanting structural area is dominated by structural–lithologic composite reservoirs (Figure 6b). The Bajiaoting structural area primarily features structural reservoirs (Figure 6b).

4.2. Oil and Gas Filling Degree of Different Structures in the Pinghu Oil and Gas Field

Statistical analysis of the hydrocarbon filling degree within the Fangheting and Bajiaoting structural areas of the Pinghu Oil and Gas Field reveals distinct vertical variations (Figure 7). The number of hydrocarbon-bearing intervals and the hydrocarbon filling degree within the Pinghu Formation are significantly higher than those observed in the Huagang Formation. The Huagang Formation exhibits relatively small oil column heights (typically less than 30 m) and filling degrees mostly at or below 50%. In contrast, the Pinghu Formation displays gas column heights approaching 100 m, particularly within the overpressure-developed intervals (P8–P11 reservoir units), where the hydrocarbon filling degree approaches 100% (near-full filling). The Fangheting structural area, situated within the Lower Pinghu Slope Belt, demonstrates superior characteristics in terms of the number of oil-bearing intervals, oil column height, and overall filling degree (Figure 7a), followed by the Bajiaoting structural area (Figure 7b).

4.3. Hydrocarbon Fluid Properties, and Temperature and Pressure Characteristics

4.3.1. Hydrocarbon Fluid Properties of the Pinghu Oil and Gas Field

The crude oil of the Huagang Formation in the Pinghu Oil and Gas Field is characterized as light, conventional oil (Figure 8), exhibiting low density (0.7543 g/cm³–0.7903 g/cm³) and viscosity (0.88 mPa·s–1.24 mPa·s), a low pour point (−26–−12 °C), as well as low contents of wax (0.14–2.70%), resin (0.25–0.92%), and sulfur (0–0.23%). The condensate oil and gas of the Pinghu Formation generally exhibits higher density, viscosity, and wax content compared to Huagang crude oil (Figure 8). The wax content increases downward from the middle–upper to the lower member of Pinghu Formation, reaching a maximum of 18.85%.

The relative density of natural gas in Pinghu Oil and Gas Field is 0.6810~0.7480 g/cm³ (Figure 8), the average critical temperature is 223.15 °C, and the average critical pressure is 4.5992 MPa. The overall performance of the condensate gas reservoir does not contain hydrogen sulfide. In addition, the Pinghu Oil and Gas Field has abundant formation water analysis data from Huagang Formation to upper Pinghu Formation. The strata water of Huagang Formation in Pinghu Oil and Gas Field is CaCl₂ type, with chloride values of 9501.7 mg/L–15,033.9 mg/L and total salinity of 17,551 mg/L–21,242 mg/L. The formation water of Pinghu Formation is of the NaHCO₃ type, the chloride content is 477 mg/L–4342 mg/L, and the salinity is 7040 mg/L–41,050 mg/L.

The pressure coefficient data also indicate that there are significant differences in the physical properties of oil and gas in atmospheric pressure systems and overpressure systems (Figure 8d). The light oil and condensate gas in the atmospheric pressure system of the Huagang Formation have a low gas oil ratio and low density. However, the overpressure system of the Pinghu Formation has a high gas–oil ratio, high density, and high wax content in the condensate gas. From the Pinghu Formation to the Huagang Formation, the gas–oil ratio, density, viscosity, and wax content decrease with depth (Figure 8).

4.3.2. Temperature and Pressure Characteristics of the Pinghu Oil and Gas Field

The Huagang Formation and Pinghu Formation in the Pinghu Oil and Gas Field have a normal temperature gradient of about 3.5 °C/100 m (Figure 9). The reservoir temperature of the Huagang Formation ranges from 100 °C to 115 °C, and the temperature of the main producing layers in the Pinghu Formation ranges from 110 °C to 135 °C. The strata above P10 (at an altitude depth of 3500 m) in both the Huagang Formation and Pinghu Formation belong to the normal pressure system, with a pressure coefficient of 1.03 (Figure 8d). Specifically, the formation pressure of the H2–H8 strata in the Huagang Formation is between 23 MPa and 27 MPa, and the formation pressure of the P0–P10 layers in the Pinghu Formation is between 28 MPa and 37 MPa. The P11–P12 layers in the Pinghu Formation belong to abnormal overpressure strata, with a formation pressure gradient reaching 1.3–1.75 MPa/100 m.

4.4. Source Rock Types and Genesis of Oil and Gas

The crude oils in the Pinghu Oil and Gas Field mainly fall into two types: light oil and condensate oil. The biomarker characteristics of different types of crude oils are basically similar, showing the characteristics of mature crude oils mainly sourced from higher plants in a weakly oxidizing environment. The main difference among these lies in the composition and distribution of n-alkanes. Among them, crude oils with high wax content mainly exhibit the typical characteristics of the high-carbon-number post-peak type [3,6].

In this study, the cross-plot of Pr/nC₁₇ and Ph/nC₁₈ was used to conduct a comparative analysis of different types of crude oils and source rocks (Figure 10a). The plot shows that the crude oils are clearly genetically related to the type III source rocks of the Pinghu Formation, both being sourced from terrestrial higher plants in an oxidizing environment. Therefore, it is considered that the crude oils in the Pinghu Oil and Gas Field are mainly derived from the coal-measure source rocks of the Pinghu Formation, and the contribution from the Huagang Formation may be relatively low.

In addition, since the maturity of the crude oils is not significantly different from that of the local source rocks (Figure 10a), it is speculated that the crude oils are mainly derived from the deeper Pinghu Formation sediments of the Santan Subsags. The sterane maturity parameters and methylphenanthrene parameters of the condensate oil from Well W15 both indicate that the oil sample has reached maturity (Figure 10b). Based on the methyl-phenanthrene parameters, the calculated maturity Ro is 0.65%. The calculated maturity of the crude oil sample from Well W15 (sampled at the wellhead) is lower than that of other wells in the Pinghu Oil and Gas Field (Figure 10b). It may be that the condensate oil formed when the source rocks were in the low-maturity to mature stage (Ro = 0.50–1.35%), which is the result of the early charging of low-maturity oil and gas.

The natural gas in the Pinghu Oil and Gas Field is mainly wet gas, with a dry coefficient generally less than 0.9 (Figure 11a), which is the product of the natural gas maturity stage. From the cross-plot of C₁/(C₂ + C₃) and C₂ of natural gas components (Figure 11b), it can be seen that the natural gas in the Pinghu Oil and Gas Field is mainly distributed in the mature oil–gas area, and a small amount is distributed in the highly mature condensate gas area. The maturity of the natural gas is lower than that in the Pingbei area [10].

In terms of the genetic types of oil and gas, the natural gas in the study area is mainly of mixed origin, showing a mixture of oil-type and coal-type gas zone characteristics (Figure 11d). Therefore, it is speculated that it receives contributions not only from coal but also from dark mudstone. The carbon isotopes of natural gas components indicate that the natural gases have similar properties and similar source rock types (Figure 11c,d).

The thermal maturity of the source rock samples from relevant wells in the study area is equivalent to that of Ro (vitrinite reflectance), about 1.0% to 1.3% (Figure 12), while the Ro in the Santan Subsag and the Central Anticline Belt is approximately 1.5% to 2.0% [3,10]. Since the thermal maturity of the hydrocarbon source rock samples on the Pinghu Slope Belt is relatively low, it is believed that the Paleogene natural gas in the Pinghu Oil and Gas Field was mainly charged from nearby source rock that developed in the Santan Subsag.

4.5. Characteristics of Fluid Inclusions and Charging Stages of Oil and Gas Accumulation

4.5.1. Characteristics of Fluid Inclusions

In the sandstone samples from Well W5, the secondary overgrowth of quartz minerals and the characteristics of late diagenetic quartz cementation are very typical (Figure 13). The intergranular pores of the rocks generally contain oil, all showing strong pale yellow and pale blue–green fluorescence. Two stages of hydrocarbon inclusions can be observed and identified in the sandstone:

The first stage developed in the middle stage of the secondary overgrowth of quartz minerals, with a high development abundance (GOI is about 5%±). The inclusions are distributed in groups or bands in the middle–inner part of the quartz overgrowth rims, or in bands along the micro-fractures that can cut through the overgrowth rims (Figure 13a,b). The liquid hydrocarbons in the inclusions are dark brown and light grayish–yellow, and the gas is gray. Specifically, liquid hydrocarbon inclusions account for about 85%±, and gas–liquid hydrocarbon inclusions account for about 15%±.

The second stage developed after the secondary overgrowth of quartz minerals and the late-diagenetic quartz cementation period, with a medium development abundance (GOI is about 2%±). The inclusions are distributed along the mineral micro-fractures (Figure 13c,d) that cut through quartz grains and their overgrowth rims, or in lines/bands in the quartz cement. The liquid hydrocarbons in the inclusions are pale yellow or transparent and colorless, showing pale blue–green, pale green (white), and pale yellow–white fluorescence; the gaseous hydrocarbons are gray. Specifically, liquid hydrocarbon inclusions account for about 15%±, gas–liquid hydrocarbon inclusions account for about 80%±, and gas inclusions account for about 5%±.

4.5.2. Charging Stages of Oil and Gas Accumulation

The fluid inclusion technique is widely used for the division of hydrocarbon accumulation stages [2]. Based on the analysis results of fluid inclusions and combined with the thermal evolution–burial history analysis of different wells (W5 and W4), a comprehensive determination of the hydrocarbon charging and accumulation stages in different well areas of the Pinghu Oil and Gas Field can be made (Figure 14).

The results of the recovered micro-thermometry of the fluid inclusions show that the central values of the homogenization temperatures of reservoir fluid inclusions in the Pinghu Formation and the lower member of the Huagang Formation in the Pinghu Oil and Gas Field range from 125 to 140 °C (Figure 14). The distribution of homogenization temperatures in the reservoir of the lower member of the Huagang Formation shows a single-peak pattern (Figure 14b), while that in the reservoir of the Pinghu Formation shows a double-peak pattern (Figure 14a). This indicates that the hydrocarbon charging in the reservoir of the lower member of the Huagang Formation is mainly in one stage, while the reservoir of the Pinghu Formation has experienced a two-stage hydrocarbon charging process.

Combined with the results of the restoration of the stratigraphic burial history and thermal history, it is speculated that the hydrocarbon charging periods in the Pinghu Oil and Gas Field are the late Miocene and the Quaternary, with the period since 5 Ma being the most important, representing a late-stage rapid hydrocarbon accumulation.

4.6. Reservoir Properties, Fault Sealing Capacity, and Oil and Gas Preservation Condition

The reservoirs of the Huagang Formation in the study area are mainly massive medium-grained sandstones and fine-grained sandstones. Sandstone thickness accounts for 70% of the total stratum thickness. The sandstones have high textural and mineralogical maturities. Intergranular pores are the main pore type, and the reservoirs have good physical properties. The porosity ranges from 12.0% to 28.0%, with an average porosity of 21.0% (Figure 15). The permeability interpreted from well logging ranges from 5.0 mD to 900.0 mD, with an average permeability of 181.0 mD (Figure 15). These values belong to medium-porosity and medium-permeability reservoirs. In contrast, the Pinghu Formation in the study area features an obvious interbedded distribution pattern of sandstone and mudstone. Its porosity ranges from 5.0% to 17.0%, with an average of 13.0% (Figure 15), and the permeability ranges from 0.5 mD to 100.0 mD, with an average permeability of 10.6 mD. The sandstone of the Pinghu Formation belongs to a low-porosity and medium-to-low-permeability reservoir. From the Huagang Formation to the Pinghu Formation, as the burial depth increases, both the porosity and permeability of the reservoirs decrease. Specifically, the porosity decreases from 23% to 11%, and the permeability drops from 86 mD to 3.6 mD (Figure 15).

The faults in the Pinghu Oil and Gas Field area were formed during the rifting period and basically stopped activity during the depression period [2]. The lateral sealing ability of the fault system during the hydrocarbon accumulation period determines whether hydrocarbons can effectively accumulate and be preserved.

In this study, based on the analysis of the relationship between fault throw and cumulative sandstone thickness, the sealing effect of the fault on hydrocarbons can be identified (Figure 16). The distribution of oil and gas layers in the Pinghu Formation is mainly concentrated in the areas where the fault throw is much greater than the total sandstone thickness (within the range of the fault throw), indicating that when the fault throw is much greater than the total sandstone thickness, the fault has good lateral sealing ability, which requires the fault throw to be more than 2.5 times the total sandstone thickness (Figure 16a). By contrast, when the fault throw is much less than the total sandstone thickness, the fault has good hydrocarbon conductivity. On the relationship diagram between the fault throw and ratio of the sand and stratum, the oil and gas layers are mainly distributed in the range where the fault throw is >75 m and the sand-to-stratum ratio is <45% (Figure 16b), indicating that the faults within this range have good lateral sealing, which is conducive to hydrocarbon accumulation and preservation.

5. Discussion

5.1. The Process and Mode of Oil and Gas Accumulation

Based on the comprehensive analysis of the hydrocarbon reservoir types, fluid properties, source rock types, charging stages, and hydrocarbon preservation conditions presented above, the hydrocarbon charging and evolution process of the Pinghu Formation and Huagang Formation in the Pinghu Oil and Gas Field can be summarized into three different stages (Figure 17).

The first hydrocarbon charging stage is the oil filling stage, which occurred from 10 Ma to 5 Ma (Figure 17a). At this time, a large amount of crude oil was charged into the sandstone of the lower member of the Pinghu Formation. Due to the strong sealing ability of the regional transgressive mudstone caprock in the lower member of the Pinghu Formation, the charging efficiency of crude oil in the middle–upper members of the Huagang Formation and Pinghu Formation was relatively low.

The second hydrocarbon charging stage is the stage of massive natural gas charging, which took place from 5 Ma to 2 Ma (Figure 17b). The early-formed oil reservoirs were affected by the invasion of highly mature natural gas. During the gas-invasion process, the light components of the original crude oil were continuously lost, and the wax content of the crude oil increased continuously. However, with the continuous charging of natural gas, the oil with high wax content was gradually dissolved into the natural gas, and a condensate gas reservoir was gradually formed. Nevertheless, the condensate oil always retained the typical characteristic of low wax content. Meanwhile, some light components of the crude oil and natural gas migrated upward through faults and accumulated in the sandstone of the Huagang Formation. As the pressure decreased, the crude oil was precipitated, forming a light condensate oil–gas mixed reservoir in the Huagang Formation.

The third hydrocarbon charging stage is the adjustment stage of the hydrocarbon reservoir, which has been ongoing since 2 Ma (Figure 17c). Due to the natural gas invasion, the vertical sealing ability of the shallow caprock deteriorated, resulting in the continuous loss of natural gas and the formation of reservoir bitumen in the Huagang Formation. Eventually, the current distribution pattern of “gas in the deeper part and oil in the shallower part” observed in the exploration of the Pinghu Formation–Huagang Formation in the Pinghu Oil and Gas Field was formed.

5.2. Hydrocarbon Exploration Prospects of the Pinghu Oil and Gas Field

Previous exploration and research have confirmed that the Pinghu Oil and Gas Field has superior hydrocarbon source conditions [1,2,3,4,5,6,7,8,9,10,11,12,13,14,15]. Currently, high-quality source rocks such as dark mudstone, coal seams, and carbonaceous mudstone of the Pinghu Formation have all reached the mature–highly mature stage [3,6]. Therefore, the hydrocarbon sources in the study area are abundant. Meanwhile, research has verified that the closer to the lower part of the Pinghu Slope Belt, such as the hydrocarbon filling degree of the Fangheting area, is significantly higher than that of the Bajiaoting Structure. Thus, abundant hydrocarbon sources and favorable charging conditions are important prerequisites for the formation of large-scale hydrocarbon accumulations.

Previous studies on the sedimentary systems of the Pinghu Formation have shown that from the north to the south of the Pinghu Oil and Gas Field, the fluvial control gradually weakens, while the tidal control gradually strengthens [1,5]. The reservoir in the lower member of the Pinghu Formation in the Pinghu Oil and Gas Field has been fully reworked by tides, and the sand bodies are well-sorted [5]. Considering that high pressure commonly develops in the lower member of the Pinghu Formation and the reservoir physical properties are relatively good, the quartz sandstone encountered in the P11 layer of well Wb6 reveals good reservoir physical properties. Research indicates that for reservoirs located in the over-pressured zone, the overall trend of the decrease in reservoir physical properties with increasing depth will slow down, and secondary pore development zones can be locally formed and benefit from further hydrocarbon exploration.

Thus, the Pinghu Oil and Gas Field has superior conditions for trap development and hydrocarbon accumulation. It mainly develops multiple types of hydrocarbon reservoirs, such as structural traps, structural–lithologic composite traps, and lithologic traps. Structural traps are well-developed in the Pinghu Oil and Gas Field. However, up to the present, the large-scale structural traps in this oil and gas field have been explored at a basic level. It is considered in this study that the lower member of the Pinghu Formation has good development conditions for structural–lithologic composite traps and lithologic traps, with great exploration potential.

6. Conclusions

The main conclusions of this study are as follows:

(1) Hydrocarbons of the Pinghu Oil and Gas Field are primarily distributed within the Huagang Formation and the Pinghu Formation. Light oil is predominantly found in the Huagang Formation, and predominantly concentrated in the H4 reservoir unit, with minor occurrences in the H5 and H6 units. Condensate gas is concentrated in the Pinghu Formation, and it is mainly concentrated in the P5–P8 and P11–P12 reservoir units.

(2) The Huagang Formation and Pinghu Formation in the Pinghu Oil and Gas Field have a normal temperature gradient of about 3.5 °C/100 m. Crude oil from the Huagang Formation (Pinghu Oil and Gas Field) is characterized as light and conventional, exhibiting low density and viscosity, a low pour point, as well as low contents of wax, resin, and sulfur. The condensate oil and gas of the overpressured Pinghu Formation exhibits higher density, viscosity, and wax content compared to the crude oil of the Huagang Formation.

(3) Hydrocarbon charging in the reservoir of the lower member of the Huagang Formation is mainly in one stage of gas filling, while the reservoir of the Pinghu Formation has experienced two stages of the hydrocarbon charging process: oil filling (10–5 Ma) and gas filling (5–2 Ma).

(4) The hydrocarbon charging and evolution process of the Pinghu Formation and Huagang Formation in the Pinghu Oil and Gas Field can be summarized into three different periods. The first hydrocarbon charging stage is the oil filling stage, which occurred from 10 Ma to 5 Ma. The second hydrocarbon charging stage is the stage of massive natural gas charging, which took place from 5 Ma to 2 Ma. The third hydrocarbon charging stage is the adjustment stage of the hydrocarbon reservoir, which has been ongoing since 2 Ma.

(5) The Pinghu Oil and Gas Field has good conditions for trap development and hydrocarbon accumulation. It is considered that the lower member of the Pinghu Formation, especially in the lower Pinghu Slope Belt (Fangheting Structure), has good development conditions for structural–lithologic composite traps and lithologic traps, with great potential for next-stage exploration.