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. 2022 Jul 8;7(28):24795–24811. doi: 10.1021/acsomega.2c02826

Geochemical Characteristics of Three Oil Families and Their Possible Source Rocks in the Sub-Sag A of Weixinan Depression, Beibuwan Basin, Offshore South China Sea

Xiaoxiao Ma †,‡,§, Lin Wei †,‡,§,*, Dujie Hou †,‡,§,*, Changgui Xu ∥, Yong Man ∥, Wenlong Li ∥, Piao Wu ⊥
PMCID: PMC9301645  PMID: 35874235

Abstract

graphic file with name ao2c02826_0014.jpg

Three oil families from the sub-sag A of the Weixinan Depression are identified by integrated analysis of physical properties, stable carbon isotopes, and gas chromatography–mass spectrometry (GC–MS). Their similarities and differences in relative thermal maturities, depositional environments, and biological sources of organic matter (OM) are investigated. A possible oil–source correlation of this area is established. Group A1 oils, defined as low-maturity oils, are characterized by high density and high viscosity. They contain more terrigenous OM deposited in a freshwater environment with unstratified water columns reflected by a relatively high terrestrial/aquatic ratio and Pr/Ph values, low abundance of C30 4-methlysteranes, and low δ13C values. They are derived from the upper hydrocarbon supply combination. Group A2 oils are characterized by moderate density and viscosity and medium stable carbon isotope values. This group of oils has lower terrestrial/aquatic ratios and Pr/Ph values and a medium concentration of C30 4-methlysteranes and δ13C values, suggesting that the oils are derived from the shales which have more contribution from the algal input and are formed in a weakly oxidizing environment. They are a mixture generated from the source rocks in the middle and lower hydrocarbon supply combination. Groups A3 oils, defined as light oils, have low density and viscosity. The geochemical data of the A3 oils, including a less-negative stable carbon isotope, high abundance of C30 4-methylsteranes, low Pr/Ph values, and highest Ts/(Ts + Tm) ratios (Ts represents C27 18α(H)-22,29,30-trisnorneohopane and Tm represents C27 17α(H)-22,29,30-trisnorhopane), suggest that they are generated from the source rocks deposited in a subanoxic environment with the large input of dinoflagellates. The A3 oils are generated from the shales from the lower hydrocarbon supply combination. The oil–source correlation results can be further supported by the distribution of faults and structural ridge as the migration channel of petroleum developed around the sub-sag A.

1. Introduction

The Beibuwan Basin is a fault-depression superimposed basin dominated by Cenozoic sedimentation in the northern continental shelf sea of the South China Sea. It has an area of 3.98 × 104 km2.1 The Weixinan Depression (Figure 1a), located in the north part of the Beibuwan (BBW) Basin, is one of the petroliferous depressions. Three faults controlled the development of the Weixinan Depression. The Weixinan fault controls the deposition of Changliu Formation. In Eocene, with the weakening of Weixinan fault activity, no. 1 fault became more active and controlled the sediments of the Liushagang Formation. In Oligocene, as the activity of no. 1 fault weakened, the activity of no. 2 fault gradually increased and developed into a main fault controlling the deposition of the Weizhou Formation.2 According to the distribution of depocenter of Paleogene Liushagang Formation, the depression was further divided into sub-sags A, B, and C.3 Due to the differences in later structural evolution and burial history, these three subsags are differentiated in hydrocarbon generation evolution.

Figure 1.

Figure 1

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Geological maps showing the tectonic distribution units of the Weixinan sag (a) and the distribution of the three major oil families in the sub-sag A (b).

Over the past 30 years, a group of commercial oil-bearing structures and oil fields have been discovered in the Weixinan Depression, especially in sub-sag B (Figure 1a). However, according to previous exploration results, sub-sag A has a certain area larger than sub-sag B, and the shales from sub-sag A have great hydrocarbon potential as well, but only a small amount of oil has been discovered. Therefore, the exploration and research on the sub-sag A become a focus. Previous studies on crude oils in the Weixinan Depression have focussed on oil classification, oil–source correlation, and hydrocarbon accumulation conditions on the scale of the whole basin or particular area (e.g., sub-sag C, the southeast slope and WZ12 oil field). For example, Huang et al.4 and Fan et al.1 recognized three different oil groups generated from the Liushagang Formation. In comparison, Fan et al.1 believed that the first type of oils was derived from the bottom of the first member of the Liushagang Formation (El1) and the top of the second member of the Liushagang Formation (El2), the last two types of oils were generated from the bottom of the El2 formation and the top of the third member of the Liushagang Formation (El3) in the Weixinan Depression. The studies on the WZ12 oil field by Jin5 and Wang et al.6 revealed that these oils were from the El2 and El3 source rocks. As outlined above, these previous organic geochemical studies on the crude oils from the Weixinan Depression were conducted on the samples mostly from sub-sag B, such as the WZ12 oil field.6 Nevertheless, the geochemical characteristics and possible source rocks of crude oils from the sub-sag A have not yet been studied in detail. Compared to the sub-sag B, the petroleum system of sub-sag A remains unclear.

The aims of this work are to investigate the basic geochemical characteristics of the oils, define oil families, and to make an oil–source correlation in order to achieve a better understanding of the petroleum system in sub-sag A.

2. Geological Background

The Beibuwan Basin, located in the northern continental shelf area of the South China Sea, is a Mesozoic–Cenozoic extensional basin with an area of 3.98 × 104 km2. The Weixinan Depression, which is located in the northern BBW Basin, has an area of about 3454 km2. It is adjacent to the Weixinan fault in the north and the no. 3 fault in the south.

The structural evolution of the Weixinan sag was characterized by two stages separated by unconformities (Figure 2): Eocene–Oligocene extensional phase marked by fault bounded and rifted strata and the Miocene-recent passive margin phase.4,7 The Eocene–Oligocene rifting stage began in the Chuangliu Formation (Ech) characterized by a coarse-grained conglomerate with interbedded sandstone and shale. The Liushagang Formation (El) is subdivided into upper (El1), middle (El2), and lower (El3) sections on the basis of their lithology and fossil assemblages. It widely consists of a combination of dark shale, which is the effective source rock in the Weixinan Depression. The Weizhou Formation (Ew) is dominated by sandstone and also contains dark mudstone. The postrift marine sediments of the Miocene to Pleistocene consist mainly of sandstone interbedded with mudstones (Figure 2).

Figure 2.

Figure 2

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Generalized stratigraphic column of the Weixinan sag.

In the Weixinan Depression, BBW Basin, hydrocarbon reservoirs have been discovered within the El3, El1, Ew, Ej, and Ex sand stones (Figure 2). Available geological data have suggested that the oil fields are sourced from El rocks, which include from bottom to top, El3, El2, and El1 formations.4,8,9 Among them, two layers of organic-rich shale (oil shale) were deposited at the top and bottom of the seconder member of Liushagang Formation (El2). Fu and Liu10 and Fu11 suggested that although it is considered that the main source rocks in the BBW Basin are lacustrine shales of the El2 formation, these shales vary in the quality.

3. Materials and Methods

A series of 19 crude oils from the sub-sag A in the Weixinan Depression, northern Beibuwan Basin were chosen in this work. The well locations are shown in Figure 1b, and the detailed information on these samples is shown in Table 1. A total of 136 source rocks were chosen for Rock-Eval pyrolysis and total organic carbon (TOC) analyses, and 20 source rocks were chosen for gas chromatography–mass spectrometric (GC–MS) analyses (Tables 1–5).

Table 1. Physical Properties of Three Oil Families in the Sub-Sag A of the Weixinan Saga.

oil field form. density (g/mL, 20 °C) viscosity (mPa s) wax (%) sulfur (%) oil family
WZ103 El3 0.83–0.81/0.85 4.60–9.71/5.88 28.20–38.50/25.15 0.01–0.20/0.08 A3
WZ103W El3 0.76–0.84/0.82 0.64–12.13/5.57 1.63–24.39/18.22 0.05–0.11/0.09 A3
WZ111 Ej 0.92 98 8.75 0.27 A2
WZ111 El3 0.81–0.89/0.85 2.64–84.46/27.62 12.24–31.1/22.60 0.06–0.31/0.16 A3
WZ111 Ech 0.83–0.84/0.83 4.46–6.53/5.29 11.01–17.33/14.56 0.08–0.09/0.09 A3
WZ111E Ej 0.92 236.39 1.19 0.31 A2
WZ111N El1 0.86–0.87/0.87 21.22–67.47/43.87 14.33–18.42/16.11 0.22–0.29/0.25 A2
WZ111W Ew 0.865–0.87/0.87 19.26–22.79/21.12 12.30–12.70/12.50 0.20–0.20/0.20 A2
WZ57 El1 0.90–0.92/0.91 70.77–119.4/95.09 17.25–17.43/17.34 0.40–0.50/0.45 A1
WZ61S El1 0.85–0.86/0.86 12.11–18.05/14.91 15.13–20.42/18.52 0.16–0.20/0.18 A2
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Note: each cell consists of two parts, above the horizontal line is the range (minimum to maximum) and below is the average.

Table 5. Summary of GC–MS Parameters of Saturated Fractions for Source Rocks from the SR1 and SR3 in the Sub-Sag A, Weixinan Sag, BBW Basina.

well depth (m) combination PP1 PP2 PP3 PP4 PP5 PP6 PP7 PP8 PP9 PP10 PP11 PP12 PP13 PP14 PP15 PP16 PP17 PP18 PP19 PP20 PP21 PP22
WZ592 3127 SR1 1.42 0.52 1.44 1.56 1.51 0.58 0.38 1.32 n.d. n.d n.d 0.01 0.35 0.27 0.04 0.05 1.50 0.87 0.13 0.67 0.04 n.d.
WZ592 3145 SR1 0.67 0.57 1.44 1.64 1.88 0.82 0.76 1.44 0.20 n.d n.d 0.01 0.54 0.31 0.02 0.05 1.43 0.91 0.11 0.68 0.06 n.d.
WZ592 3158 SR1 0.92 0.38 2.20 1.42 1.45 1.74 0.83 1.95 n.d. n.d n.d n.d. 0.36 0.25 0.03 0.05 1.57 0.79 0.16 0.64 0.03 n.d.
WZ592 3270 SR1 0.57 0.37 2.31 1.32 1.28 1.43 0.79 2.02 0.53 n.d n.d 0.01 0.46 0.30 0.04 0.07 1.70 0.82 0.12 0.76 0.05 n.d.
WZ592 3272 SR1 0.73 0.39 2.06 1.29 1.28 1.37 0.72 1.98 n.d 0.54 0.14 0.01 0.41 0.27 0.04 0.08 1.78 0.79 0.10 0.77 0.05 n.d.
WZ592 3310 SR1 0.74 0.55 1.30 1.33 1.34 1.81 0.85 2.47 n.d 0.00 0.14 0.00 0.34 0.16 0.61 0.08 1.60 0.74 0.12 0.70 0.08 n.d.
WZ592 3312.6 SR1 1.04 0.53 1.01 0.78 0.71 1.00 0.31 3.59 0.63 0.00 0.18 0.01 0.40 0.13 2.35 0.10 1.35 0.67 0.13 0.73 0.11 n.d.
WZ592 3320 SR1 0.86 0.54 1.36 1.49 1.46 2.48 0.82 3.37 n.d 0.00 n.d 0.01 0.40 0.25 0.28 0.05 1.38 0.94 0.14 0.66 0.06 n.d.
WZ592 3332 SR1 0.96 0.55 1.35 1.28 1.35 0.94 0.35 2.85 n.d 0.00 0.08 0.01 0.60 0.23 0.02 0.10 1.76 0.93 0.11 0.79 0.05 n.d.
WZ592 3394 SR1 1.24 0.57 1.18 1.31 1.18 1.07 0.54 1.97 n.d 0.00 0.10 0.01 0.47 0.14 0.01 0.07 1.64 0.74 0.22 0.65 0.04 n.d.
WZ112N1D 2828 SR1 0.91 1.34 0.56 1.35 1.39 2.41 1.43 1.19 n.d. n.d. n.d. 0.10 0.31 0.16 0.13 0.43 1.11 1.44 0.24 0.04 n.d. n.d.
WZ592 3460 SR1 1.24 0.63 1.04 1.32 1.22 0.82 0.40 2.01 n.d. 0.00 0.06 0.01 0.69 0.29 0.02 0.07 1.59 0.87 0.26 0.72 0.03 n.d.
WZ571 2884 SR1 1.25 0.66 1.15 1.65 1.81 1.30 0.83 1.64 0.39 0.00 0.00 n.d. 0.39 0.33 0.08 0.14 0.89 1.04 0.37 n.d. 0.11 0.36
WZ571 2964 SR1 1.47 0.77 0.92 1.62 1.66 1.12 0.53 2.44 0.44 0.00 0.00 n.d. 0.44 0.40 0.12 0.16 1.02 1.64 0.37 n.d. 0.10 0.48
WZ571 3210 SR1 1.70 0.83 0.79 1.50 1.50 1.69 0.62 3.08 0.44 0.00 0.00 n.d. 0.44 0.31 0.08 0.21 1.24 1.19 0.32 0.43 0.06 0.69
WZ1121 2984 SR1 1.98 0.92 0.62 1.26 1.16 1.51 0.53 3.14 0.16 0.06 0.06 n.d. 0.16 0.09 0.07 0.25 1.34 0.65 0.45 0.48 0.08 0.37
WZ1121 3242 SR3 1.65 0.81 0.71 1.15 1.12 0.71 0.42 1.72 0.87 0.08 0.08 n.d. 0.87 0.48 0.18 0.22 1.10 0.83 0.45 0.63 0.11 1.46
WZ1121 3326 SR3 1.87 1.21 0.42 1.08 1.05 0.36 0.26 1.56 0.93 0.18 0.18 n.d. 0.93 n.d n.d. 0.26 1.18 1.19 0.44 0.34 0.25 1.07
WZ1121 3344 SR3 1.23 0.53 1.20 1.09 1.07 0.62 0.48 1.23 0.90 0.27 0.27 n.d. 0.90 0.71 0.21 0.27 0.96 0.95 0.42 0.66 0.22 1.56
WZ1121 3402 SR3 0.94 0.36 2.10 1.07 1.05 1.12 0.79 1.21 0.96 1.14 1.14 n.d. 0.96 0.88 n.d. 0.15 0.79 0.57 0.50 0.54 0.73 2.52
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(Note: PP1 = (nC21 + nC22)/(nC28 + nC29); PP2 = nC21–/nC21+; PP3 = TAR = (nC27 + nC29 + nC31)/(nC15 + nC17 + nC19); PP4 = CPI22–32 = 2 × (nC23 + nC25 + nC27 + nC29 + nC31)/(nC22 + 2 × nC24 + 2 × nC26 + 2 × nC28 + 2 × nC30 + nC32); PP5 = OEP = [(nC25 + 6 × nC27 + nC29)/(4 × nC26 + 4 × nC28)]; PP6 = Pr/nC17; PP7 = Ph/nC18; PP8 = Pr/Ph; PP9 = C19TT/(C19TT + C23TT) = C19 tricyclic terpane/(C19 tricyclic terpane + C23 tricyclic terpane); PP10 = ETR = (C28TT + C29TT)/(C28TT + C29TT + Ts); PP11 = C24TeTT/C23TT; PP12 = GA/C30H = gammacerane/C30 αβ hopane; PP13 = Ts/(Ts + Tm); PP14 = C29Ts/(C29Ts + C29H); PP15 = oleanane/C30H; PP16 = C31 22R homohopane/C30 αβ hopane; PP17 = C31 22S/22R homohopanes; PP18 = C27/C29 = C27 (ααα 20S + αββ 20R + αββ 20S + ααα 20R) steranes/C29 (ααα 20S + αββ 20R + αββ 20S + ααα 20R) steranes; PP19 = ββ-C29/∑C29(%) = C29 αββ sterane/(C29 ααα sterane + C29 αββ sterane); PP20 = C29 ααα 20S/(20S + 20R) sterane; PP21 = St/H = steranes/hopanes = C27–C29 regular steranes/C29–C35 αβ hopanes; PP22 = 4-MSI = C30 4-methylsteranes/C29 regular steranes; and n.d. = not applicable.

3.1. Rock-Eval Pyrolysis and Total Organic Carbon Analyses

The TOC was measured based on the standard process (SY/T 5116-1997) using LECO CS-230. The pyrolysis analysis was conducted on the Rock-Eval instrument,12 and the parameters including the free hydrocarbon (S1), potential hydrocarbon (S2), and maximum temperature of hydrocarbon generation (Tmax) were obtained.

3.2. Gas Chromatography–Mass Spectrometry Analyses

About 20–30 mg of each crude oil was separated into saturated hydrocarbons and aromatic hydrocarbons on a short activated neutral alumina column using n-hexane and n-hexane/dichloromethane (1:2, v/v). The surficial contamination of the cutting samples was removed through rinsing with deionized water and alcohol before powdering into 200 mesh. Extractable organic matter was extracted from the ground samples in chloroform using a Soxhlet apparatus for 72 h. Then, the method of separation of saturated hydrocarbons is the same as that of oils. The saturated hydrocarbons were analyzed on an Agilent 7890 gas chromatograph interfaced to an Agilent 5975c mass spectrometer (70 eV ionization energy) as described by Ding et al.13 The oven temperature was initially held at 50 °C (held for 1 min), then heated up to 120 °C at a rate of 20 °C/min, programmed from 120 to 250 °C at 4 °C/min, and finally to 310 °C (held at 310 °C for 30 min) at 3° C/min. The selective ion mode and full scan were used for the data acquisition.

3.3. Stable Carbon Isotope Analyses of Fractions

The stable carbon isotope (δ13C) analysis of whole oils and source rock kerogens was carried out using a Finnigan MAT-251 mass spectrometer as describe by Cai et al.14 Stable carbon isotope measurements were made on the aliphatic and the aromatic hydrocarbon fractions of oil samples as well. The 13C/12C isotope ratio of the CO2 generated from a sample was compared with the corresponding ratio of a reference, calibrated against the PDB standard. The reproducibility of the total analytical procedure is in the range of 0.1–0.2‰.

4. Results and Discussion

4.1. Geochemical Characteristics of Oils

Based on the bulk composition, the saturated hydrocarbon biomarker distributions, and stable carbon isotopic data of the studied oils from the sub-sag A, they can be divided into three families: the A1 oil family, the A2 oil family, and the A3 oil family (Table 1). The distribution of three types of oils is shown in Figure 1b. The A1 oil family is mainly from the WZ57 oil field, and the A2 oil family is mainly from WZ111, WZ111E, WZ111N, WZ1111W, and WZ61S oil fields. The A3 oil family is distributed in the El3 formation of WZ103, WZ103W, WZ103S, and WZ61 oil fields. The basic geochemical characteristics of the oil families and comparison of their similarities and differences in biomarker were conducted in this study.

4.1.1. Physical Properties

The physical properties of crude oil show a huge difference among these three oil families (Figure 3a). Density of crude oils is widely used to classify the light crude oil (0.80–0.87 g/mL), medium crude oil (0.87–0.89 g/mL), and heavy crude oil (0.89–0.93 g/mL).15 Density of oils from the El2, El3 and Ech formations typically ranges from 0.76 to 0.89 g/mL (average = 0.85 g/mL; Table 1), classifying the oil as the light crude oil. The medium and heavy oils are observed in the Ew, Ej, and El1 formations in the WZ111W, WZ111E, and WZ57 reservoirs, respectively. The A1 oil family is characterized by a high density (0.90–0.92 g/mL; average = 0.91 g/mL; Table 1 and Figure 3a), a high viscosity (70.77–119.4 mPa s; average = 95.09 mPa s), a medium wax content (17.25–17.43%; average = 17.34%), and a high sulfur content (0.40–0.50%; average = 0.45%). Compared with the A1 oil family, the oils from the A2 oil family, except for oils from WZ111E1 and WZ1113, have a lighter density (0.85–0.87 g/mL; average = 0.86 g/mL), a lower viscosity (12.11–67.47 mPa s; average = 28.18 mPa s), a medium wax content (12.30–20.42%; average = 16.26%; Table1), and a lower sulfur content (0.16–0.29%; average = 0.22%; Table 1). The A3 oil family is characterized by a low density (0.82–0.87 g/mL; average = 0.84 g/mL; Table 1), a low viscosity (4.3–32.8 mPa s; average = 7.97 mPa s; Table 1), a slightly higher wax content (13.5–29.28%; average = 21.87%; Table1), and the lowest sulfur content (0.01–0.22%; average = 0.10%; Table 1). In general, the physical properties are affected by thermal maturity, biological sources of organic matter (OM), and secondary effects.15 Heavy oils can be divided into two types on the basis of their origin that are primary heavy oils (immature heavy oils) and heavy oils formed due to water washing and biodegradation.16 The role of biodegradation is supported by different GC–MS traces for oils from the Ej and Ew formations. The crude oils from the WZ57 oil field are considered to be immature heavy oils, which is suggested by lower C27 18α(H)-22,29,30-trisnorneohopane/(C27 18α(H)-22,29,30-trisnorneohopane + C27 17α(H)-22,29,30-trisnorhopane) [Ts/(Ts + Tm)] ratios (<0.45) (Figure 3c). Although there is no obvious correlation between the density of oils and burial depth (Figure 3b), the negative relationship between density and Ts/(Ts + Tm) indicates that the density of crude oils decreases with increasing thermal maturity (Figure 3c). As shown in Figure 3d, the density has a negative correlation with the stable carbon isotope ratios of oils, suggesting the differences in density are related to the source material of OM, and the oils are derived from different source rocks.

Figure 3.

Figure 3

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Scatter plots of (a) density vs viscosity, (b) density vs depth, (c) density vs Ts/(Ts + Tm), and (d) density vs stable carbon isotope values (δ13Coil) of crude oils in the sub-sag A of the Weixinan sag.

Collectively, the variation of physical properties implies that thermal maturity decreases from group A3 to group A1, except the biodegraded oils in the A2 oil family. Besides that, it suggests that they are probably derived from different source rocks.

4.1.2. Stable Carbon Isotopic Composition of Oils

The stable isotopic composition of crude oil has been used for many decades to provide information on relationships between oil families. The stable carbon isotope ratios (δ13C) of the whole oils, saturated and aromatic hydrocarbon, nitrogen-, sulfur- and oxygen-bearing compounds (NSO), and the asphaltene fraction from the three oil families are presented in Table 2. The δ13C values of the whole oils in different oil families have obvious differences. Group A1 has much more negative δ13Coil (whole oil) values (average = −29.55‰), δ13Csat (saturated hydrocarbon) values (average = −31.13‰), and δ13Caro (aromatic hydrocarbon) values (average = −28.7‰) than groups A2 (δ13Coil average of −26.98‰; δ13Csat average of −27.59‰; δ13Caro average of −25.95‰) and A3 (δ13Coil average of −25.33‰; δ13Csat average of −25.55‰; δ13Caro average of −23.89‰). A plot of the δ13Csat versus δ13Caro shows that groups A1, A2, and A3 fall into three clusters (Figure 4a). These values indicate that studied oil families are originated from multiple source rocks.

Table 2. Bulk Carbon Isotopic Composition of the A1, A2, and A3 Oil Families from the Sub-Sag A of the Weixinan Saga.
            δ13CPDB (‰)
no. field well depth (m) form. oil family whole Oil saturate aromatic NSO asphaltene
S01 WZ57 WZ571 2820.9 Ew A1 –29.40 –30.60 –28.70 n.d. n.d.
S02 WZ57 WZ571 2831.9 El1 A1 –29.70 –31.13 –27.43 –27.80 –28.43
S03 WZ111 WZ1113 995.5 Ej A2 –26.79 –27.15 –25.02 –26.19 –26.67
S04 WZ111E WZ111E1 986 Ej A2 –26.50 –27.40 –26.10 –25.96 –26.50
S05 WZ111E WZ111E1 991 Ej A2 –26.71 –27.13 –24.74 –26.14 –26.38
S06 WZ111E WZ111E1 995 Ej A2 –26.50 –27.10 –25.80 –25.90 –26.40
S07 WZ111N WZ111N3 2097.25 El1 A2 –27.24 –28.15 –25.72 –26.35 –26.62
S08 WZ111N WZ111N4 2088.25 El1 A2 –27.23 –27.69 –25.31 –26.39 –26.71
S09 WZ111W WZ111W2d 1582.04 Ew A2 –27.22 –28.16 –26.50 –26.64 –26.98
S10 WZ111W WZ111W2d 1551.01 Ew A2 –27.38 –28.12 –26.84 –27.06 –27.41
S11 WZ61S WZ61S1 1808 Ew A2 –27.20 –27.70 –26.40 n.d. n.d.
S12 WZ61S WZ61S1 1812.1 Ew A2 –27.10 –27.60 –26.50 n.d. n.d.
S13 WZ61S WZ61S1 1972.8 El1 A2 –26.90 –27.40 –26.30 n.d. n.d.
S14 WZ61S WZ61S1 1991.3 El1 A2 –27.00 –27.50 –26.20 n.d. n.d.
S15 WZ103 WZ1031 2033 El3 A3 –25.20 –25.40 –23.27 –24.32 –25.54
S16 WZ103S WZ103S1 2286.5 El3 A3 –25.07 –25.22 –23.80 –24.22 –24.94
S17 WZ103W WZ103W2 2104.5 El3 A3 –24.90 –25.20 –24.40 –24.20 –24.90
S18 WZ111 WZ1112 2856.1 Ech A3 –26.57 –26.91 –24.53 –24.93 –25.44
S19 WZ61 WZ611 1967 El3 A3 –24.91 –25.00 –23.42 –24.23 –25.01
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(Note: NSO = nitrogen-, sulfur-, and oxygen-bearing compounds).

Figure 4.

Figure 4

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Cross plots of (a) δ13CPDB saturates vs δ13CPDB aromatics, (b) δ13Coil vs Ts/(Ts + Tm), and (c) 4-MSI vs δ13Coil of three oil families in the sub-sag A, Weixinan Depression.

To our knowledge, the δ13C variation is dependent on some factors, such as biological OM, the depositional condition,17,18 thermal maturity, and biodegradation.19,20 Just to get a better understanding of its effectiveness for oil family classification, these controlling factors are discussed below.

Biodegradation does have a minor influence on δ13Csat and a small effect on the δ13Cwhole.21 Marcano et al.22 also suggested biodegradation on crude oil does not lead to significant carbon variations. The biodegraded oil samples are mainly from group A2, and their δ13C of the whole oil, saturate, and aromatic fractions ranges from −26.79 to −26.50‰ (average −26.62‰), −27.40 to −27.10‰ (average −27.19‰), and −26.10 to −24.74‰ (average −25.41‰), respectively. The difference between the biodegraded oils and other oils in the A2 group is less than 1‰ (Table 2), suggesting biodegradation has no significant effect on stable carbon isotope in this study area.

The influence of thermal maturity on the stable carbon isotope will make it much heavier (less negative) due to the preferential cleavage of 12C–12C bonds.19 As shown in Figure 4b, the inconspicuous positive relationship (R2 = 0.42) between the stable carbon isotopic composition of the whole oil and Ts/(Ts + Tm) suggested that it is likely less affected by thermal maturity. It seems to mean that the thermal maturity of the A1 oil family is lower than those of A2 and A3 families. However, because thermal maturity can only account for minor δ13C variations (usually <1‰), the huge difference (the deviation exceeds 3‰) between A1 and A3 is not entirely the result of thermal maturity in this study area.

Although numerous studies on the carbon isotope analysis have been done to identify the lacustrine and marine OM, the isotopic variations of the OM are still unclear. In general, oils generated from terrigenous OM are isotopically less negative than marine oils with δ13Coil > −26‰. On the contrary, a study reported by Sun et al.23 has concluded that marine oils are isotopically more negative than nonmarine oils, and the heavy carbon isotope composition is related to the development of specific algae. As shown in Figure 4c, the positive relationship (R2 = 0.74) between δ13Cwhole and the ratio of C30 4-methylsterane to C29 regular steranes (4-MSI) implies that the less-negative δ13Cwhole is closely related to algal bloom even though the samples are in various maturity stages. It is coincident with the results reported for the Pearl River Mouth, Bohaiwan, Sunda basins.23−26 The deposits in these basins are formed in a freshwater environment with abundant C30 4-methylsterane. Thus, in these studied oils, the δ13Cwhole values of the A1 and A2 oils are mostly less than −26‰, suggesting that algae have a contribution on the biological sources of their source rocks. However, the relatively heavy δ13Cwhole values (>−26‰) in the A3 oils may reveals the algal bloom, especially the dinoflagellate.

In summary, the differences in stable carbon isotopic compositions among the groups of oil are consistent with biological source and thermal maturity variations (Figure 4b,c). There is a clear trend in the bulk carbon isotope values, suggesting thermal maturity decreasing from group A3 to group A1 and the algal bloom increasing from group A3 to group A1 as well.

4.1.3. Aliphatic Hydrocarbon

4.1.3.1. n-Alkanes and Isoprenoids

The n-alkane distributions are widely used to distinguish sources of OM and evaluate the thermal maturity of crude oils and source rocks.27,28 GC–MS analyses performed on saturated hydrocarbons of the sub-sag A oils show that the carbon number of the n-alkanes ranges from C10 to C40 (Figure 5). Histograms representing the distributions are shown in Figure 5, but four samples (S03, S04, S05, and S06) from the A2 oil family showed slight biodegradation and has been excluded from Figure 5. n-alkanes in the crude oils fall into two patterns (Figure 5). Pattern 1 is a strong odd-over-even predominance, with maxima at nC27 (Figure 5a), for the A1 oil family. Pattern 2 is characterized by a slight odd-over-even predominance, with a maximum at nC17, nC23, or nC25, for the oils from the groups A2 and A3 (Figure 5b,c). The OEP [(nC25 + 6 × nC27 + nC29)/(4 × nC26 + 4 × nC28)] values (average 1.56; Table 3) and CPI [2 × (nC23 + nC25 + nC27 + nC29 + nC31)/(nC22 + 2 × nC24 + 2 × nC26 + 2 × nC28 + 2 × nC30 + nC32)] values (average = 1.73; Table 3) suggest a low thermal maturity of A1 oils. The OEP and CPI values of the oils from the A2 and A3 groups are around 1.0 (Table 3), indicating that they are in the mature–high mature stage. However, closer observation of the data suggests that the oils from the A3 group are slightly more mature than the oils from the A2 group.

Figure 5.

Figure 5

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Mass chromatograms (m/z 85) of saturated hydrocarbon fractions of representative crude oils and normalized n-alkane profiles from (a) A1 oil family, (b) A2 oil family, and (c) A3 oil family in the sub-sag A of the Weixinan sag. Relative abundance = Ci/∑Ci ×100% (i = 10–40).

Table 3. Summary of GC–MS Parameters of Saturated Fractions for Crude Oils in the Sub-Sag A, Weixinan Sag, BBW Basina.
no. well depth (m) P1 P2 P3 P4 P5 P6 P7 P8 P9 P10 P11 P12
S01 WZ571 2820.9 0.62 0.33 2.96 1.56 1.75 1.44 0.62 2.42 0.11 0.25 1.45 3.50
S02 WZ571 2831.9 1.15 0.75 1.09 1.56 1.71 1.13 0.64 2.02 0.14 0.29 1.28 3.35
S03 WZ1113 995.5 n.d n.d n.d n.d n.d 7.50 6.68 1.10 0.21 0.34 0.80 2.01
S04 WZ111E1 986 n.d. n.d. n.d. n.d. n.d. n.d. n.d. n.d. 0.18 0.34 0.78 1.89
S05 WZ111E1 991 n.d. n.d. n.d. n.d. n.d. n.d. n.d. n.d. 0.21 0.35 0.79 2.01
S06 WZ111E1 995 n.d. n.d. n.d. n.d. n.d. n.d. n.d. n.d. 0.20 0.36 0.76 1.92
S07 WZ111N3 2097.25 1.25 0.80 0.79 1.11 1.09 0.56 0.43 1.36 0.17 0.28 0.51 0.66
S08 WZ111N4 2088.25 1.56 0.98 0.59 1.11 1.08 0.41 0.30 1.40 0.22 0.27 0.55 0.72
S09 WZ111W2d 1582.04 0.95 0.73 0.90 1.07 1.08 0.46 0.30 1.73 0.22 0.24 0.73 2.20
S10 WZ111W2d 1551.01 0.96 0.78 0.82 1.09 1.05 0.48 0.31 1.74 0.20 0.29 0.71 2.21
S11 WZ61S1 1808 1.74 0.94 0.59 1.11 1.08 0.46 0.33 1.43 0.22 0.29 0.56 0.66
S12 WZ61S1 1812.1 1.35 0.91 0.72 1.11 1.09 0.46 0.34 1.44 0.22 0.29 0.62 0.78
S13 WZ61S1 1972.8 1.43 0.79 0.76 1.10 1.09 0.50 0.36 1.44 0.19 0.30 0.50 0.57
S14 WZ61S1 1991.3 1.55 0.81 0.71 1.11 1.09 0.48 0.34 1.45 0.19 0.30 0.48 0.55
S15 WZ1031 2033 1.31 0.81 0.76 1.08 1.05 0.45 0.28 1.65 0.26 0.41 0.38 0.59
S16 WZ103S1 2286.5 1.20 0.89 0.70 1.09 1.07 0.55 0.34 1.88 0.24 0.48 0.71 2.39
S17 WZ103W2 2104.5 1.03 0.67 0.93 1.07 1.09 0.44 0.23 2.09 0.22 0.45 0.37 0.56
S18 WZ1112 2856.1 1.05 0.71 0.94 1.08 1.05 0.41 0.25 1.68 0.32 0.34 0.42 0.59
S19 WZ611 1967 1.52 1.05 0.57 1.07 1.05 0.29 0.21 1.50 0.24 0.45 0.30 0.41
no. well P13 P14 P15 P16 P17 P18 P19 P20 P21 P22 P23 P24 P25
S01 WZ571 0.04 0.37 0.03 0.23 0.10 0.37 0.50 0.86 1.35 0.20 0.15 0.36 0.65
S02 WZ571 0.06 0.42 0.04 0.25 0.09 0.39 0.52 0.87 1.36 0.25 0.18 0.32 0.75
S03 WZ1113 0.06 0.56 0.07 0.26 0.05 0.44 0.55 0.89 1.00 0.38 0.37 0.08 2.15
S04 WZ111E1 0.05 0.57 0.06 0.27 0.05 0.44 0.55 0.88 1.02 0.34 0.32 0.08 2.11
S05 WZ111E1 0.06 0.57 0.07 0.26 0.06 0.44 0.55 0.89 1.00 0.37 0.37 0.08 2.22
S06 WZ111E1 0.05 0.56 0.07 0.27 0.04 0.45 0.56 0.87 1.01 0.35 0.31 0.08 2.06
S07 WZ111N3 0.05 0.52 0.05 0.26 0.03 0.40 0.59 0.89 0.98 0.36 0.33 0.09 2.21
S08 WZ111N4 0.06 0.55 0.07 0.28 0.04 0.41 0.57 0.89 1.03 0.36 0.28 0.10 1.88
S09 WZ111W2d 0.06 0.55 0.04 0.29 0.03 0.37 0.59 0.88 0.94 0.30 0.59 0.08 1.09
S10 WZ111W2d 0.07 0.53 0.04 0.28 0.04 0.39 0.58 0.89 0.80 0.32 0.59 0.09 1.01
S11 WZ61S1 0.07 0.57 0.05 0.27 0.06 0.44 0.58 0.88 1.10 0.38 0.35 0.10 1.29
S12 WZ61S1 0.07 0.57 0.05 0.27 0.05 0.45 0.59 0.88 1.06 0.36 0.35 0.10 1.27
S13 WZ61S1 0.06 0.59 0.06 0.28 0.05 0.43 0.58 0.89 1.00 0.39 0.39 0.09 1.61
S14 WZ61S1 0.06 0.57 0.05 0.26 0.05 0.40 0.58 0.89 1.01 0.37 0.37 0.10 1.66
S15 WZ1031 0.08 0.64 0.12 0.37 0.11 0.46 0.60 0.88 1.02 0.42 0.51 0.12 2.98
S16 WZ103S1 0.08 0.54 0.10 0.33 0.12 0.47 0.61 0.88 0.84 0.37 0.46 0.09 3.30
S17 WZ103W2 0.09 0.66 0.12 0.42 0.11 0.45 0.60 0.87 0.98 0.45 0.45 0.10 2.65
S18 WZ1112 0.13 0.85 0.31 0.61 0.27 0.51 0.59 0.86 0.41 0.49 0.51 0.19 2.51
S19 WZ611 0.08 0.67 0.13 0.40 0.10 0.49 0.62 0.89 0.66 0.42 0.49 0.11 2.57
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(Parameters: P1 = (nC21 + nC22)/(nC28 + nC29); P2 = nC21–/nC21+; P3 = TAR = (nC27 + nC29 + nC31)/(nC15 + nC17 + nC19); P4 = CPI22–32 = 2 × (nC23 + nC25 + nC27 + nC29 + nC31)/(nC22 + 2 × nC24 + 2 × nC26 + 2 × nC28 + 2 × nC30 + nC32); P5 = OEP = (nC25 + 6 × nC27 + nC29)/(4 × nC26 + 4 × nC28); P6 = Pr/nC17; P7 = Ph/nC18; P8 = Pr/Ph; P9 = C19TT/(C19TT + C23TT) = C19 tricyclic terpane/(C19 tricyclic terpane + C23 tricyclic terpane); P10 = ETR = (C28TT + C29TT)/(C28TT + C29TT + Ts); P11 = C24TeTT/C23TT; P12 = C24TeTT/C26TT; P13 = GA/C30H = gammacerane/C30 αβ hopane; P14 = Ts/(Ts + Tm); P15 = C30 diahopane/(C30 diahopane + C30H); P16 = C29Ts/(C29Ts + C29H); P17 = oleanane/C30H; P18 = C31 homohopane/C30 αβ hopane; P19 = C31 22S/(22S + 22R) homohopanes; P20 = C30 αβ/(αβ + βα) hopane; P21 = C27/C29 = C27 (ααα 20S + αββ 20R + αββ 20S + ααα 20R) steranes/C29 (ααα 20S + αββ 20R + αββ 20S + ααα 20R) steranes; P22 = ββ-C29/∑C29(%) = C29 αββ sterane/(C29 ααα sterane + C29 αββ sterane); P23 = C29 ααα 20S/(20S + 20R) sterane; P24 = St/H = steranes/hopanes = C27–C29 regular steranes/C29–C35 αβ hopanes; P25 = 4-MSI = C30 4-methylsteranes/C29 regular steranes; and n.d. = not applicable).

The terrestrial/aquatic ratio (TAR), which is defined as (nC27 + nC29 + nC31)/(nC15 + nC17 + nC19),27 is in the range of 1.09–2.96 (average = 2.03) in the A1 oil family compared to the A2 oil family (0.59–0.90; average 0.73) and the A3 oil family (0.57–0.94; average 0.78). Excluding the influence of thermal maturity on the TAR ratios (Figure 6a), it possibly indicates that the A1 was derived from a source rock with a larger input of terrigenous OM (e.g., higher plants) compared to the A2 and A3 oils. In comparison, the source rock of A2 and A3 oil groups was deposited with algal OM. The (n-C21–/n-C22+) ratios lie in the range of 0.33–0.75 (average = 0.54) in the oils from the A1 group, which are lower than those in the A2 oil family (0.73–0.98; average 0.84) and the A3 oil family (0.67–1.05; average 0.83).

Figure 6.

Figure 6

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Scatter plots of (a) TAR vs Ts/(Ts + Tm), (b) Pr/Ph vs Ts/(Ts + Tm), (c) C19TT/(C19TT + C23TT) vs Ts/(Ts + Tm), (d) oleanane/C30H vs Ts/(Ts + Tm), (e) St/H vs Ts/(Ts + Tm), and (f) 4-MSI vs Ts/(Ts + Tm), showing the influence of thermal maturity on the geochemical parameters. (Note: St/H represents steranes/hopanes = C27–C29 regular steranes/C29–C35 αβ hopanes; 4-MSI = the ratio of C30 4- methylsterane to C29 regular steranes.)

Pristane/phytane (Pr/Ph) is commonly used to evaluate redox conditions during deposition, although it is also affected by thermal maturation.29−31 As shown in Figure 6b, there is no positive and/or negative relationship between Pr/Ph and Ts/(Ts + Tm), suggesting the thermal maturity has no obvious influence on the Pr/Ph ratios. Generally, the low Pr/Ph (<0.6) indicates the hypersaline environment of the source rock, Pr/Ph < 0.8 represents anoxic conditions, and Pr/Ph > 3.0 is interpreted to be an indicator for an oxic environment with the input of terrestrial OM.32,33 The Pr/Ph ratios of most of the analyzed oils are >1 (1.10–2.42; average = 1.64; Table 3), suggesting these oils were derived from a source rock deposited in an oxidizing environment. Comparatively speaking, the sedimentary environment of the A3 and A2 oils is more reductive than that of the A1 oils (Figure 7b,c). The Pr/nC17 and Ph/nC18 ratios of the A1 oils are higher than those of the A2 and A3 oils, except for samples S03 in which Pr/nC17 and Pr/nC18 are highest due to biodegradation. The cross plot of Pr/nC17 and Pr/nC18 (Figure 7a) indicates that most of oils from these three families originated mixed OM, except for the A1 oils with a certain terrestrial OM. Besides that, the Pr/nC17 and Ph/nC18 ratios decrease with increasing thermal maturity, suggesting the A3 oils are more mature than A2 and A1(Figure 7a).

Figure 7.

Figure 7

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Cross plots of (a) Ph/nC18 vs Pr/nC17, (b) C27/C29 vs Pr/Ph, (c) TAR vs Pr/Ph, and (d) 4-MSI vs C24Te/C23TT. (Note: C27/C29 = (5α(H),14α(H),17β(H) C27 sterane 20S + 5α(H),14β(H),17β(H) C27 sterane 20S + 5α(H),14β(H),17β(H) C27 sterane 20R + 5α(H),14α(H),17α(H) C27 sterane 20R)/(24-ethyl-5α(H), 14α(H), 17α(H)–C29 sterane 20S + 24-ethyl-5α(H), 14β(H), 17β(H)–C29 sterane 20R + 24-ethyl-5α(H), 14β(H), 17β(H)–C29 sterane 20S + 24-ethyl-5α(H), 14α(H), 17α(H)–C29 sterane20R); TAR = (nC27 + nC29 + nC31)/(nC15 + nC17 + nC19); 4-MSI = the ratio of C30 4-methylsterane to C29 regular steranes; and C24Te/C23TT = C24 tetracyclic terpane/C23 tricyclic.)

4.1.3.2. Terpanes

In compared to the hopanes, tricyclic terpanes have a relatively low abundance (Figure 8). However, a relatively high abundance of tricyclic terpanes was detected in the A3 oil group compared to a moderate abundance in the A2 oils and a low concentration in the A1 oils. Tricyclic terpanes have a variety of origins, such as Tasmanites,34 bacteria,35,36 and higher plants.37 Generally, the C19TT/(C19TT + C23TT) was widely used as an effective indicator for the terrigenous OM input in low-mature sediments.38,39 However, as shown in Figure 6c, a strong positive relationship between C19TT/(C19TT + C23TT) and Ts/(Ts + Tm) (R2 = 0.80) suggests that it is strongly affected by thermal maturity. The C19TT/(C19TT + C23TT) ratios are in the range of 0.11–0.14 (average = 0.13), 0.17–0.22 (average = 0.20), and 0.22–0.32 (average = 0.26) in the A1, A2, and A3 oil families, respectively. It suggests that A3 oils have higher thermal maturity than A2 and A1 oils. The extended tricyclic ratio (ETR) has the ratio of 0.25–0.29 (average = 0.27), 0.26–0.34 (average = 0.31), and 0.34–0.48 (average = 0.43) in the A1, A2, and A3 oil families, respectively. It implies that their source rocks are derived from the freshwater environment because the ETR is widely used for an effective indicator of salinity.40,41 C24 tetracyclic terpane/C23 tricyclic (C24Te/C23TT) is also an index for terrestrial OM.42,43 The amount of C24Te is slightly higher with C24Te/C23TT varying in a range of 1.25–1.42 (average 1.36) in the A1 oil family compared to that in the A2 oil family (0.48–0.8; average = 0.65; Table 3) and A3 oil family (0.30–0.71; average = 0.44; Table 3). It is consistent with the results from the TAR, suggesting a larger input of terrigenous OM to the source rocks of the A1 oil family than those of A2 and A3 oil families.

Figure 8.

Figure 8

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Representative m/z 191 and 217 mass chromatograms of the aliphatic hydrocarbon fraction showing the distribution of terpanes and steranes in the A1 (a), A2 (b), and A3 (c) oil families.

A series of C27–C35 hopanes, except for C28 homologue, are present in the crude oils. The oils from the A1 and A2 oil families have a relatively low oleanane/C30 αβ hopane ratio (0.03–0.1; average = 0.05), while the oleanane/C30 αβ hopane ratio of the A3 oil group is >0.1 (0.10–0.27, average = 0.14). A high oleanane/C30 αβ hopane ratio may imply the contribution of gymnosperms to the OM. Nevertheless, good exponential correlation between oleanane/C30 αβ hopane and Ts/(Ts + Tm) (R2 = 0.83), except for the A1 oil family, shows that the oleanane/C30 αβ hopane ratio increases with increasing thermal maturity (Figure 6d). This is consistent with the studies of Ekweozor and Telnaes44 and Tyson45 who suggested the oleanane/C30 αβ hopane ratio increases from the low value in the immature sample to the maximum value at the top of the oil window and then remains relatively stable. The maturity-related parameters, including Ts/(Ts + Tm), C30 diahopane/(C30 diahopane + C30 αβ hopane), C29Ts/(C29Ts + C29H), C31 homohopane/C30H, and C30 αβ/(αβ + βα), indicate a trend in maturity from low to high variability in the A1, A2, and A3 oil families (Figure 9 and Table 3). Gammacerane is thought to be a good indicator of water column stratification and perhaps the salinity.46 The gammacerane/C30 αβ hopane ratio (Gam/C30H) of the three oil families is <0.15 (0.04–0.0.13; average 0.07; Table 3), suggesting that they were originated in a freshwater environment with unstable water column stratification.

Figure 9.

Figure 9

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Cross plot of C29Ts/(C29Ts + C29H) vs Ts/(Ts + Tm) for the oil families and source rocks in the sub-sag A of the Weixinan sag. SR1 = the upper hydrocarbon supply combination; SR3 = the lower hydrocarbon supply combination.

Overall, some source-indicative parameters about terpanes, such as C19/(C19TT + C23TT) and oleanane/C30 αβ hopane, are apparently influenced by thermal maturity in the high-mature stage (Figure 6). Thus, they cannot be used for the assessment of OM sources for the A2 and A3 oil families in the study area, but they could reflect the increased thermal maturity from the A1 oils to A3 oils. However, the algal OM contributes more to the A3 oils than the A2 and A1 oils, which is supported by C24Te/C23TT ratios.

4.1.3.3. Steranes

Regular steranes are commonly used for delineating the biological sources and thermal maturity of OM. The ratio of C27 steranes/C29 steranes in the A1 and A2 oils is mostly >1 (0.8–1.36, average = 1.05), which is higher than that in the A3 oil family (0.41–1.02, average = 0.78). The cross plot of Pr/Ph and C27/C29 ααα 20R steranes, in which most of the oils are indicated to be sourced from mixed OM in a subanoxic environment, expect for the A1 oils is shown in Figure 7b. The C29 ααα 20S/(20S + 20R) sterane ratio ranges from 0.12 to 0.56, and the C29 αββ/(αββ + ααα) sterane ratio ranges from 0.40 to 0.54 (Table3). The C30 4-methylsteranes are widely detected in the lacustrine deposits in eastern China.47 Its biological precursors are related to certain algae, especially dinoflagellates.48−50 Abundance C30 4-methylstrane was detected in the A1, A2, and A3 oil families. The ratio of C30 4-methylsteranes to C29 steranes (4-MSI) is in the range of 0.65–0.75 (average = 0.70), 1.01–2.22 (average = 1.71), and 2.51–3.30 (average = 2.80) in the A1, A2, and A3 oil families, respectively. It reveals a flourish of dinoflagellates in the lake during the deposition period of source rocks. Fu11 proposed that the 4-MSI could be used for evaluation of OM, that is, high-quality shales (4-MSI > 1.5), good source rocks (4-MSI > 0.5), and fair source rocks (4-MSI < 0.5). Thus, it is concluded that the A1 oils were generated from the good source rocks, and A2 and A3 oils were derived from the excellent shales.

4.2. Geochemical Characteristics of Source Rocks

According to previous studies, the shales from the Liushagang Formation are the main source rock in the Weixinan sag, especially the second member of Liushagang Formation (El2).51−55 However, according to the results of Fu et al.56 and Fu and Liu,10 the quality of El2 source rocks is quite different. Thus, there is a new definition, which is given for the division of source rocks from the Weixinan sag, based on the comprehensive investigation on geochemical analysis and regional sedimentary facies of source rocks. It is suggested that there were three sets of hydrocarbon supply assemblages of source rocks in the Weixinan sag: the first hydrocarbon supply assemblage includes the lower part of the El1 and the upper part of the El2 (the upper hydrocarbon supply assemblage; SR1); the second one, so-called the middle hydrocarbon supply assemblage (SR2), contains the middle part of the El2 formation, and the last one consists of the lower part of the El2 and the upper part of the El3 (the lower hydrocarbon supply assemblage; SR3).5,57 In our work, the discussion about the geochemical characteristics of source rocks is being carried out based on this new classification. After our preliminary analysis of the source rocks in the Weixinan sag, it is concluded that crude oils were generated from the source rocks located in the center of subsag and migrated into the reservoir for accumulation. Although the lack of drilling in the center of sub-sag A makes it an obstacle, it adjoins the sub-sag B which contains significant source rocks and they have similar sedimentary facies and history. Oil–source rock correlation was measured by studying the wells drilling the source strata in the edge of sub-sag A and sub-sag B.

4.2.1. Bulk Organic Geochemical Characteristics

The results of TOC and Rock-Eval pyrolysis of shales from the upper, middle, and lower hydrocarbon combinations are tabulated in Table 4 and plotted in Figure 10. It shows that the shales from the upper hydrocarbon combination (SR1) are fairly excellent source rocks, suggested by medium TOC values (0.84–9.03%; average = 2.92%) and medium PG (S1 + S2) values (2.43–44.11 mg/g, average = 13.9 mg/g). The source rocks from the middle hydrocarbon combination (SR2) have lower hydrocarbon potential with low TOC values (0.33–2.74%, average = 1.92%) and low PG values (0.55–12.23 mg/g, average = 6.96 mg/g). In comparison, the shales from the lower hydrocarbon combination (SR3) are mostly excellent source rocks, and their TOC values range from 0.58 to 10.03% (average = 3.77%).

Table 4. Rock-Eval Parameters and Carbon Isotopes of Kerogen of the Shale Samples from the Weixinan Saga.
hydrocarbon supply combination TOC (%) PG (mg/g) Tmax (°C) HI (mg/g) δ13CPDB (‰)
SR1 0.84–9.03/2.92 2.43–44.11/13.9 381–446/430 147–823/394 –29.13–26.10/–27.83
SR2 0.33–2.74/1.92 0.55–12.23/6.96 379–448/435 115–464/307 –30.14–26.10/–28.14
SR3 0.58–10.03/3.77 1.24–89.68/15.54 372–446/437 91–862/333 –27.52–21.22/–25.93
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(Note: TOC = total organic carbon; PG = S1 +S2 (mg/g); HI = S2/TOC (mg/g); Tmax = temperature of maximum hydrocarbon generation rate; and HI = S2/total organic carbon. Each cell consists of two parts: above the horizontal line is the range (minimum to maximum) and below is the average).

Figure 10.

Figure 10

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Cross plot of TOC vs PG from the shale samples of the SR1, SR2, and SR3 in the Weixinan sag. (Note: PG = S1 + S2, S1 = free hydrocarbons; S2 = potential hydrocarbons; and TOC = total organic carbon.)

The Tmax values of all source rocks range from 372 to 448 °C, showing a difference from low maturity to high maturity. However, because the wells are located in the margin of subsags, their thermal maturity is far less than the source rocks in the center of basin, where the oils were generated from. Based on these data, we assume that the source rocks generating oils are in the mature–high mature stage. Shales from these three hydrocarbon supply combinations mainly contain type III to type I kerogen. Overall, source rocks from the SR3 are greater than those from SR1 and SR2. The shales from the SR2 are in the poorer quality.

The stable carbon isotope of kerogen is widely used to identify the biological OM and the depositional condition of source rocks. The heavy carbon isotopic signature has been a characteristic of shales containing Botryococcus and Pediastrum algal.58 In the Weixinan sag, abundant Botryococcus, Pediastrum, and dinoflagellate cysts were observed in the organic-rich shales from the El2 formation.55 The lacustrine facies exhibit the largest isotopic variability. The δ13C of SR1 source rocks range from −29.13‰ to −26.10‰ with an average of −27.83‰. The δ13C values vary in the SR2 source rocks from −30.14‰ to −26.10‰ (average = −28.14‰), whereas they are the heaviest one in the SR3 source rocks (−27.52‰ – −21.22‰; average = −25.93‰; Table 4). The enrichment of 13C in the SR3 shales implies a flourish of dinoflagellates compared to the SR1 and SR2 source rocks.

4.2.2. Molecular Geochemistry

The distribution diversities in n-alkanes and isoprenoids of the SR1 and SR3 source rocks are shown in Figure 11. The n-alkane carbon numbers range from C10 to C40, with maxima at C23. The TAR ratios range from 0.42 to 2.31 with an average of 1.25. The OEP values in the SR1 are mostly >1 (1.16–1.88, average = 1.43), except for the sample from WZ592 (0.78), indicating a low maturity. However, the relatively low OEP (1.05–1.12, average = 1.08) and CPI (1.07–1.15, average = 1.10) values exhibit that the SR3 shales are more mature than the SR1. The Pr/Ph ratios of shales from the SR1 range from 1.19–3.59 with an average of 2.28, suggesting that the SR1 source rocks were deposited in a freshwater environment with a dominant higher plant input. In comparison, the ratios of Pr/Ph are in the range of 1.21–1.72 (average = 1.42), showing a weakly oxidized environment during the deposition of SR3 source rocks. It is consistent with gammacerane/C30H (0.004–0.11; average = 0.02; Table 5), which indicates a freshwater environment as well. The oleanane/C30H ratios of source rocks from the SR1 range from 0.01–2.35 (average = 0.25), which is higher than that in SR3 (0.18–0.21; average = 0.19). Ts/(Ts + Tm) ranges from 0.15–0.68 with an average of 0.42 in the SR1, while that of the SR3 is in the range of 0.87–0.96 (average 0.91). This indicates that the thermal maturity of the SR1 is much lower than that of the shales from the SR3, which have been in the high-mature stage. It has a good agreement with other thermal maturity-related parameters (e.g., C31 20R αβ hopane/C30 αβ hopane, C29 ββ/(αα + ββ)), indicating the highest maturity in the SR3 source rocks. The distribution of C27–C28–C29 ααα 20R sterane mostly exhibits a “L” shape in the SR1 and “V” shape in the SR3 (Figure 11). The 4-MSI in the SR1 ranges from 0 to 0.69 with an average of 0.38, which is much lower than that in the SR3 (1.07–2.52; average = 1.65, Table 5). The studies reported by Boreham et al.58 and Summons et al.59 suggested that 4-MSI is related to the bloom of algae, especially dinoflagellates. According to the OM evaluation criteria reported by Fu,11 the variation of 4-MSI implies that the best source rocks are from SR3, followed by SR1. It also has a good agreement with the results suggested by TOC and PG values.

Figure 11.

Figure 11

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Typical biomarker distributions of shale samples from SR1 and SR3 in the Weixinan sag, showing in the order of n-alkane (m/z 85), terpane (m/z 191), and sterane (m/z 217) distribution. (Note: SR1 = the upper hydrocarbon supply combination; SR3 = the lower hydrocarbon supply combination.)

4.3. Oil–Source Rock Correlation

As outlined above, several source-related parameters, such as oleanane/C30H, C19TT/(C19TT + C23TT), are affected by thermal maturity, so that they are inaccurate to be used as the basis for oil–source rock correlation. However, the δ13Coil, TAR, C24Te/C23TT, ETR, and 4-MSI are not/slightly affected by thermal maturity. Thus, on the basis of these indicators, together with physical properties and thermal maturity-related parameters (e.g., Ts/(Ts + Tm), C29Ts/(C29Ts + C29H), C30 diaphone/(C30diahopane + C30H)), three groups of oils were classified. The A1 oil family, occurring in the El1 reservoir located near the center of sub-sag A, was characterized by high density and low thermal maturity (Ts/(Ts + Tm) < 0.42). Their source rocks were deposited in the freshwater environment with mixed OM and a small input of dinoflagellates. It is supported by the high Pr/Ph values (average 2.22), low ETR (average 0.27) and Ga/C30H (average 0.05), high TAR (average 2.03), and low 4-MSI (average 0.70). The A2 oils, which are distributed in Ew and El1 reservoirs close to the no. 2 fault, have medium density and moderate thermal maturity. They were derived from the source rocks deposited in a freshwater environment with agal inputs. It is consistent with the medium Pr/Ph values (average 1.45), ETR (average 0.31) and Ga/C30H (average 0.06), low TAR (average 0.73), and medium 4-MSI (average 1.71). The A3 oils, discovered in El3 reservoirs far from the depression, were distinguished by light density and higher thermal maturity. They were generated from the best source rocks deposited in a subanoxic environment with a large input of algae, especially dinoflagellates.

According to the geochemical characteristics of source rocks, there are three hydrocarbon combinations (SR1, SR2, and SR3). The SR1 shales are good-great source rocks, which are deposited in a freshwater environment with mixed OM (Figure 7a,b). Although there is a lack of the molecular geochemical data of the SR2 source rocks, their carbon isotope of kerogen was compared with those of the SR1 and SR3 to predict the hydrocarbon potential of the source rocks (Table 4). It is suggested that the SR2 are fairly good source rocks with moderate thermal maturity, and their depositional environment is similar to that of the SR1. In comparison, the SR3 source rocks have the greatest hydrocarbon potential, which were formed in a weakly oxidizing environment with the dominated algal input suggested by high abundance of C30 4-methylsterane.

Based on the discussion about these oil families and hydrocarbon supply combinations, coupling with the cross plots (Figures 7a,b, 9 and 12), one supposition on oil–source relationship in the sub-sag A was that the A1 oils are generated from the SR1 source rocks in the center, the A2 oils are mixed oils from the SR2 and SR3 shales, whereas, the A3 oils were derived from the SR3 shales.

Figure 12.

Figure 12

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Correlation of three oil families with corresponding kerogens of three source rock combinations based on their δ13C variations. (Note: SR1 = the upper hydrocarbon supply combination; SR2 = the middle hydrocarbon supply combination; and SR3 = the lower hydrocarbon supply combination.)

To verify the correctness of the oil–source relationship, the research on the structure of sub-sag A was carried out. According to previous studies, it is found that there are no any faults except the no. 1 fault in the northern of sub-sag A, where the A1 oils are located in. Thus, we proposed that the A1 oils are derived from the SR1 source rocks near the reservoir. The A2 oil family is distributed in the northern of no. 2 fault, and there are many small faults. Therefore, the oils generated from SR2 and SR1 source rocks immigrated along small faults into WZ111 reservoirs. Although the faults in the sub-sag A are not developed, there are two major tectonic ridges: WZ103 and WZ61.60 Through basin simulations, it is found that oils migrated and accumulated along tectonic ridges. Thus, we proposed that the A3 oils were generated from the SR3 source rocks and migrated along the WZ103 and WZ61 and accumulated in the WZ103 and WZ61 reservoirs.

5. Conclusions

Three sets of source rocks were identified in the Weixinan sag, including the upper hydrocarbon supply combination (SR1), the middle hydrocarbon supply combination (SR2), and the lower hydrocarbon supply combination (SR3). The SR3 source rocks have the best hydrocarbon potential, which are in the high-maturity stage. They are characterized by heavy δ13C values, high 4-MSI, and lower Pr/Ph values, suggesting that they are formed in a freshwater environment with algal bloom. The SR2 source rocks feature middle δ13C values, which is similar to the SR1 source rocks. They are formed in a freshwater environment with mixed OM, whereas the thermal maturity of the SR2 shales is higher than that of the SR1.

Three oil families (A1, A2, and A3) were classified in the sub-sag A in the Weixinan Depression by a large amount of parameters related to the biological source, depositional environment, and thermal maturity, such as δ13Coil, δ13Csat, δ13Caro, Pr/Ph, 4-MSI, and Ts/(Ts + Tm). The A1 oils are in the low-mature stage, which is originated from the good source rocks deposited in the suboxic environment with terrigenous OM. The A2 oils are in the medium-mature stage, which is derived from the shales’ subanoxic environment with mixed OM and an input of dinoflagellates. The A3 oils are in the high-mature stage, which is generated from the great source rocks deposited in a subanoxic environment with the algal bloom.

The oil–source correlation results show that the possible source rocks of the A1 oils are from the SR1, those of the A2 oils are mixed from the SR2 and SR3, and those of the A3 oils are from the SR3.

Acknowledgments

The work was financially supported by Key S&T Special Projects of COONC (project no.: CNOOC-KJ 135 ZDXM 38 ZJ). We gratefully acknowledge the Zhanjiang Branch of the China National Offshore Oil Corporation for sample and data collection.

The authors declare no competing financial interest.

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