A petrographic examination was conducted using an Olympus BX60 microscope (10×, 20×, 50×, and 100×). The homogenization temperature (T _h) and ice melting temperature (T _m) for aqueous fluid inclusions were measured using a Linkam (TH–600) heating–cooling stage. The precision (reproducibility) of the T _h and T _m values was ±1°C and ±0.1°C, respectively.

Oil inclusions can be illuminated with ultraviolet (UV) light to identify the degree of maturity (Burruss, 1991; Chang and Huang, 2008). A fluorescence spectrum device (Nikon 80I microscope connected to a high-pressure mercury lamp with a lamp excitation wavelength of 300–380 nm) was used for the spectral acquisition of oil-bearing inclusions. Fluorescence spectrum parameters usually include the selected λ_max value (wavelength relevant to maximum intensity) and QF ₅₃₅ values (ratio of the 535–750 nm integral area to the 430–535 nm integral area) for characterizing the emission spectra of oils and maturity (Munz, 2001; Ping et al., 2019). Typical petroleum inclusions were selected to reconstruct the composition and pressure‒temperature (P‒T) entrapment conditions by microthermometry and volumetric analysis using confocal laser scanning microscopy (for details, see Ping et al., 2013; Pironon and Bourdet, 2008). This reliable method requires T _h and the degree of bubble filling (F _v) as known parameters to determine the C₇₊ molar proportion of petroleum inclusions. The quantitative correlation among the C₇₊ mole fraction and T _hoil and F _v can be used to predict the minimum trapped pressure.

The Raman instrument used was a JY/Horiba LABRAM HR800 (532-nm green laser; 400–500 mW output power) at China University of Geosciences (Wuhan) equipped with 10×/20×/50× long-focus objectives. Peak calibration was used with ∼520.7 cm⁻¹ polished silicon during the experiments. Components of gaseous fluid inclusions were investigated by setting a 200-µm confocal hole and 300-gr·mm⁻¹ grating with a 2,650 cm⁻¹ grating center. The accumulative time varied from 0 to 500 s to acquire the optimal signal-to-noise ratio. Options of precise resolution (1,800 gr·mm⁻¹ grating and 50-μm aperture) are also necessary for acquiring accurate Raman shifts in terms of single gas phase inclusions. At the same time, neon lamp-corrected measurement should also be applied to acquire strict Raman wavenumbers (Kawakami et al., 2003; Wang et al., 2011; Dubessy et al., 2012; Huang et al., 2018). The density of pure CH₄ inclusions can be calculated by measuring the Raman shift of the C–H symmetric stretching band (v ₁) of CH₄ (Seitz et al., 1993, 1996; Lu et al., 2007) at room temperature (25°C, ensured homogenization). After Raman spectrographic collection, the density of pure CH₄ fluid inclusions can be determined by applying different equations (for more details, see Zhang et al., 2016). The density of pure CO₂ inclusions can be measured as the separation between Fermi diad peaks of CO₂ (Rosso and Bodnar, 1995). After the acquisition of the Raman spectrum in the homogenized state, the density of CO₂ inclusions is calculated by applying multiple regression formulas (see Huang et al., 2018; Wang et al., 2019).

NaCl aqueous inclusions bearing dissolved CH₄ are usually coeval with CH₄-rich fluid inclusions in microfractures or isolated within quartz overgrowths. The quantitative factor (PAR/mCH₄) of CH₄–H₂O–NaCl ternary fluids depends on salinity and temperature. To exactly calculate the CH₄ solubility in a NaCl aqueous inclusion at a known temperature, the salinity must be determined first. The salinity of the aqueous fluid inclusions can be determined using the Raman spectra of the v(OH) stretching vibration of water (e.g., Dubessy et al., 1989; Caumon et al., 2015).

I₃₄₂₅/I₃₂₆₀ was calculated using the integral Raman intensity ratio of wavenumber intensity at 3,425 cm⁻¹ to wavenumber intensity at 3,260 cm⁻¹ at 25°C (Guillaume et al., 2003; Becker et al., 2008; Caumon et al., 2014). The measured I₃₄₂₅/I₃₂₆₀ and temperature were substituted into Eq. 1 (R ² > 0.997; Ou et al., 2015): S = − 0.116   I R 2 + 5.805   I R − 6.933 (1)

The integration of the Raman peak area ratio (PAR) of the CH₄ v ₁ band (∼2,917 cm⁻¹) to the OH stretching band of water in homogenized aqueous inclusions can determine the CH₄ concentration of water-rich fluid inclusions (mol/kg; Ou et al., 2015): P A R / m C H 4 = a T + b (2) where T is the experimental temperature (K) in a homogeneous state. The slope (a) and intercept (b) are determined by the square root of mNaCl (see Ou et al., 2015). Based on these parameters and the model of Duan et al. (2003) and Duan and Mao (2006), the density and homogenization pressure (P _h) of water-rich fluid inclusions can be obtained.

The integration of the Raman peak intensity ratio (HR) of the upper band (at ∼1,380 cm⁻¹) of the CO₂ Fermi dyad to the OH stretching band of water placed into the formula mentioned previously permits calculation of the concentration of CO₂ in water (mol/kg; Guo et al., 2014): H R m C O 2 = a × T + b ,   a t T > 404.45   . a = − 2.39 × 10 − 4 ,   b = 0.202 . (3) With these parameters, the density of water-rich fluid inclusions can be obtained based on Duan and Sun (2003).

Thermal maturity can be estimated through multilinear regression analysis of Raman spectroscopic parameters of carbonaceous material (Wilkins et al., 2014, 2015, 2018). The peak separation distance, peak height ratio, and full width at half maximum (FWHM) of the G (1250–1450 cm⁻¹) and D (1500–1605 cm⁻¹) bands can be used to calculate the equivalent vitrinite reflectance (EqVR%). The application details of the equations are described by Liu et al. (2013).

BasinMod–1D (Version 7.06) software was adopted for the simulation of burial and thermal histories, which integrates the lithology, stratigraphic thickness, erosion thickness, absolute age, vitrinite reflectance, and measured borehole temperature data. Well completion reports (e.g., DST data) from the SINOPEC Zhongyuan Oilfield provide the measured R_o and borehole temperature values (Figure 3). Thermal history simulation was mainly corrected using the vitrinite reflectance and temperature. The simulation results of the burial history of well Q-12 in step II and well H-83 in step I are shown in Figure 4.

Analysis of oil testing pressure data shows that the reservoir pressure of different structural units in the study area has different development characteristics (Figure 3). The measured burial depth of the formation pressure point between 1,100 and 4,900 m ranges from 14.0 to 76.0 MPa, the pressure coefficient is 0.77–1.80, and the formation pressure increases with the burial depth. Es₁, Es_2, Es₃, and Es₄ were dominated by normal pressure. The shallow strata (<3,400 m) of Es₃ ¹ and Es₃ ² are mainly normal pressure, but the deep part is mostly in overpressure conditions. Overpressures are widespread in step I, but step II mainly occurs under normal pressure conditions, and faults in the distribution of the reservoir pressure have a significant control effect.

CH₄, H₂O, CO₂, and petroleum fluids can be trapped by quartz grains or overgrowths during diagenetic processes. Petrographic observations at room temperature and the identification of UV fluorescence and Raman characteristic peaks can be comprehensively used to precisely classify the fluid inclusion assemblages (FIAs) into five types (Figures 5, 6):

Aqueous fluid inclusions coeval with CH₄ and CO₂ inclusions in quartz were selected for salinity measurements by the method of height ratio (I₃₄₂₅/I₃₂₆₀) calculation of the water band. Secondary aqueous fluid inclusions coeval with petroleum inclusions were heated to a homogeneous state by the disappearance of the vapor bubble. The salinities (wt% NaCl equivalent) of these fluid inclusions were calculated based on their final ice-melting temperatures (T _{m, ice}; Bodnar, 1993). Figures 8A–D show the statistical distribution of salinity and homogenization temperature of different types of inclusions in each well located in step I and Step II, respectively. The homogenization temperature and salinity of reservoir inclusions in step I have the following characteristics. The homogenization temperatures of aqueous inclusions, which are coeval with CO₂ and CH₄ gas inclusions, range from 110 to 130°C (Figure 8A). The salinity interval of these water-rich inclusions varies between 2.7 and 4.9 wt% NaCleq (Figure 8B). The bimodal T _h distribution of aqueous inclusions coeval with yellow petroleum inclusions is 110–130°C, and that coeval with blue petroleum inclusions is 150–160°C. The T _{m, ice} of these water-rich inclusions varies between –2.6 and –5.2°C, with a salinity interval of 4.7–8.1 wt% NaCleq. In wells Q-6, Q-11, and Q-12, the homogenization temperatures of aqueous inclusions, which are coeval with CH₄ gas inclusions, range from 95 to 110°C (Figure 8C). The salinity interval of these water-rich inclusions varies between 3.5 and 5.3 wt% NaCleq. The homogenization temperatures of aqueous inclusions, which are coeval with CO₂ gas inclusions, range from 90 to 100°C and 105 to 110°C. The salinity interval is 3.4–7.3 wt% NaCleq. The bimodal T _h distribution of aqueous inclusions coeval with yellow petroleum inclusions is 115–130°C, and that coeval with blue petroleum inclusions is 100–110°C. The T _{m, ice} of these water-rich inclusions varies between –2.3 and –9.8°C, with salinity intervals of 3.9–13.7 wt% (Figure 8D).

The pressure and density of secondary CH₄ gas fluid inclusions in quartz can be measured using quantitative Raman analysis. Figures 6A,C exhibit the typical Raman spectrum of CH₄-system fluid inclusions, which were classified based on the petrographic characteristics and compositions in a homogeneous state. Table 1 lists the data for 15 pure CH₄ inclusions (in type I), including their densities, obtained from the C–H symmetric stretching band (v ₁) of methane (Figure 6A, A′ and A″). The density varies from 0.1772 to 0.1785 g/cm³ in the wells of step I (average value: 0.1779 g/cm³). The density varies from 0.1010 to 0.1339 g/cm³ in the wells of step II (average value: 0.1126 g/cm³). The homogenization pressure (P _h) is calculated using the thermodynamic model (Peng and Robinson, 1960) with consideration of the densities and T _h of coeval aqueous inclusions. P _h varies from 38.00 to 38.06 MPa (average value: 38.03 MPa) in step I and from 18.29 to 25.50 MPa (average value: 20.90 MPa) in step II. Meanwhile, with the discovery of CO₂-bearing inclusions (Figure 6B), 13 pure CO₂ inclusions (in type II) were quantified and are shown in Table 2. The density varies from 0.608 to 0.662 g/cm³ (average value: 0.555 g/cm³) in step I and from 0.450 to 0.612 g/cm³ (average value: 0.555 g/cm³) in step II. P _h varies from 32.82 to 39.56 MPa (average value: 36.19 MPa) in step I and from 19.34 to 28.68 MPa (average value: 24.94 MPa) in step II.

Tables 3, 4 show the data compilation of four dissolved CH₄ inclusions in NaCl aqueous inclusions (in type I) and three dissolved CO₂ inclusions in NaCl aqueous inclusions (in type I), which were analyzed by Raman spectroscopy in a homogeneous state (Figures 6C,D). The methane content (mCH₄) of the dissolved methane inclusions can be determined and ranges from 0.387 to 0.690 mol/kg. The CO₂ content (mCO₂) of the dissolved CO₂ inclusions can be mainly determined and ranges from 0.223 to 0.335 mol/kg.

The Raman maturity method can achieve targeted and convenient determination (e.g., organic matter in reservoir sandstone). A large amount of residual bitumen was found in the Paleocene reservoirs of the western slope belt in Dongpu Sag (Figures 5F,G). Residual bitumen is usually observed in the grain pores of quartz. The Raman peak parameters of bitumen were obtained by in situ Raman observation and software calculation, and equivalent vitrinite reflectance (EqVR%) was calculated (Table 5). In the Es₃ ² Formation of wells Q-12, Q-11, and Q-6, the separation of the G and D peaks can be used to calculate the maturity of bitumen (Figure 6F). The EqVR% of these residual bitumen ranges between 0.67% and 1.04%. They are characterized by low maturity.

According to parameters, such as homogenization temperature, petroleum inclusion composition, and bubble filling degree of oil inclusions and coexisting aqueous inclusions, the minimum trapped pressure (P _t) of inclusions can be obtained by PVTsim software simulation and fluorescence spectra (Figure 9).

The content of CH₄ (C₁) in petroleum inclusions of the Es₃ ² Formation in wells Q-6, Q-11, and Q-12 ranges from 14.92% to 30.82%, and the content of C₇₊ (hydrocarbons with carbon numbers over 7) varies from 43.33% to 61.08%. The oil content of petroleum inclusions varies from 80.5 to 95.7°C. The minimum trapped pressures of yellow and blue petroleum inclusions range from 19.08 to 27.87 MPa. The content of C₁ in the petroleum inclusions of the Es₃ ² Formation in the H-83 well ranges from 25.88% to 52.01%, and the content of C₇₊ varies from 19.98% to 48.60%. The oil content of petroleum inclusions varies from 80.5 to 88.7°C. The minimum trapped pressure of blue petroleum inclusions ranges from 42.91 to 54.46 MPa, and the minimum trapped pressure of yellow petroleum inclusions ranges from 32.76 to 34.45 MPa (Table 6).

From the microscopic observation of the Es₃ ² Formation in the sandstone reservoir sample, three kinds of fluid activities (petroleum, CH₄, and CO₂) are identified. Microthermometry was used to measure the homogenization temperature of aqueous inclusions, which was related to different types of fluid inclusions (petroleum, CH₄, and CO₂). The T _h throwing-dot method can be used to estimate the CH₄, CO₂ and oil accumulation times (Figure 4) (Haszeldine et al., 1984; Horsfield and McLimans, 1984). Burial histories show the reservoir in two different steps undergoing different fluid evolution processes. In well H-83 of step I, saffron yellow petroleum inclusions with maturation ranges of 0.64–0.75% R_o accumulated at ∼32–29 Ma (T _h interval: 110.0–130.0°C; yellow frame in Figure 4). CH₄ and CO₂ fluid accumulated at ∼24–21 Ma (T _h interval: 120–130.0°C; red frame in Figure 4). Late generated oil (pale blue petroleum inclusions) with high maturation in 0.97–1.26% R_o accumulated at ∼12–0 Ma (T _h interval: 150.0–160.0°C; blue frame in Figure 4). In wells Q-6, Q-11, and Q-12 of step II, saffron yellow petroleum inclusions accumulated at ∼33–30 Ma, and after the uplift and denudation of the Dongying movement, the source rocks were buried deep again. Secondary oil generation accumulated at 4–0 Ma (T _h interval: 115.0–125.0°C; yellow frame in Figure 4). Low-abundance pale blue petroleum inclusions and high-abundance CH₄ and CO₂ gas inclusions are observed, which accumulated at ∼28–20 Ma (T _h interval: 95.0–110.0°C; red and blue frame in Figure 4).

Currently, all development wells in step I and step II produce oil and no natural gas. In each well of step II, except for the discovery of multistage petroleum fluids, the greatest significance is that a large abundance of CH_4- and CO₂-gas-bearing inclusions is detected in situ by LRM spectroscopy. At the same time, a large amount of bitumen fills the grain pores of the sandstone reservoir. The EqVR% of bitumen ranges from 0.67% to 1.04%. According to the vitrinite reflectivity and occurrence, it belongs to the degraded and oxidized bitumen formed in situ. The coexistence of CH₄ and CO₂ gas in fluid inclusions indicates that the early oil in the reservoir underwent degradation and oxidation. Crude oil with a high carbon number will produce many light components (mainly methane) and CO₂ after degradation and leave low-maturity bitumen in situ (Revesz et al., 1995; Head et al., 2010). The CH₄ and CO₂ fluid trapping period occurred after the first stage of the oil charging event. At this time, step II of the western slope belt experienced a strong uplifting structure and erosion because of the Dongying movement. Strong tectonic movement over a short period of time causes the opening of the fault and the exposure of crude oil. The Dongying movement has different tectonic control functions for different fault blocks. Compared with step II, step I has a very weak tectonic uplift and denudation, and the differences in the abundance of CH₄ and CO₂ gas inclusions in the two regions are also indicative (Figure 7).

Aqueous inclusions are simultaneously observed alongside gas/petroleum inclusions, indicating that immiscible FIAs were trapped during mineral crystallization (Roedder, 1984; Goldstein, 1986; Diamond, 2001; Hurai, 2010). Isochore calculations of fluid trapped pressure follow the approach of a two-phase immiscible field (Pironon, 1990; Thiery et al., 2000; Gao et al., 2017). Based on the combination of the Raman spectra with the relevant thermodynamic model (Peng and Robinson, 1960; Duan and Mao, 2006), the component concentration and density of the water-rich and gas-rich phases can be obtained (Dubessy et al., 2001; Becker et al., 2008; Lecumberri-Sanchez et al., 2012; Mao et al., 2013).

In petroliferous sedimentary basins, reservoir pore fluids usually consist of oil, gas, and formation water. Pore fluid pressure is one of the key parameters for reservoir fluid evaluation. The parameters of the formation fluid pressure and pressure coefficient are usually used in pore pressure characterization. The formation fluid pressure coefficient (P _c) here refers to the ratio of the actual formation fluid pressure (P _f) to the hydrostatic pressure (P _hyd) at the same depth. It is a main parameter used to identify abnormal formation pressure (Law and Spencer, 1998). In this study, measured formation pressure and temperature data sets from drill stem tests (DSTs) were supplied by the SINOPEC Zhongyuan Oilfield (Figure 3). The current measured pressure coefficient of the Es₃ ² Formation ranges from 1.50 to 1.66 (high overpressure) in step I and from 0.95 to 1.02 (normal pressure) in step II (Table 6). The trapped pressure of fluid inclusions represents the pore fluid pressure in the initial conditions (Parry and Bruhn, 1990; Evans, 1995). Recovering the paleo-pressure of pure CH₄ and CO₂ gas inclusions by Raman spectroscopy quantitative analysis and the minimum trapped pressure of petroleum inclusions calculated by the predictive model, we obtained the pressure evolution of the two stages of the oil charging event and one gas charging event in different tectonic units (Figure 10). In the early Oligocene, step I and step II entered the basin rifting stage, and the source rock was in the middle stage of oil generation. Saffron yellow petroleum inclusions are largely trapped in reservoir sandstone. The reservoir maintains moderate overpressure with a pressure coefficient between 1.25 and 1.28. In the middle Oligocene, and the Dongying movement resulted in severe uplift and denudation of step II. The late Oligocene–Miocene oil reservoir degraded into CH₄ and CO₂ gas reservoirs, and the reservoir pore pressure decreased (average P _c: 1.20). The wells of step I have only minor uplift denudation. With the reburial of the Es₃ Formation, step I entered late oil generation in the late Miocene, and the maturity simulation was basically the same as the maturity of the pale blue petroleum inclusions. The pore pressure of the reservoir is approximately 1.67, which is at high overpressure conditions, and step II enters the middle stage of oil generation again (R_o%: 0.5–0.7). The maturity of late crude oil is consistent with that of trapped saffron yellow petroleum inclusions. Reservoirs maintain normal pressure conditions (average P _c: 0.90).