Figure
1.
The schematic geological map of the Baiyun Sag (a) and sampling sites (b) (modified after Ping et al., 2019).
| Citation: | Cong Chen, Xiangtao Zhang, Guangrong Peng, Zulie Long, Baojun Liu, Xudong Wang, Puqiang Zhai, Bo Zhang. Controlling factors on the charging process of oil and gas in the eastern main sub-sag of the Baiyun Sag, Zhujiang River (Pearl River) Mouth Basin[J]. Acta Oceanologica Sinica, 2023, 42(3): 189-200. doi: 10.1007/s13131-022-2140-z
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As a hot spot of global oil and gas exploration, the South China Sea is rich in oil and gas resources, of which 70% are found in deep-water areas with a water depth of greater than 300 m (Wang et al., 2010; Zhu et al., 2012). The Baiyun Sag in the Zhujiang River (Pearl River) Mouth Basin (ZRMB) is the largest sag for hydrocarbon (HC) generation in the deep-water area of the northern South China Sea, with a total area of more than 25 000 km2 and a maximum sedimentary thickness of greater than 12 km (Pang et al., 2018; Ping et al., 2019). In recent years, a series of large-scale commercial oil and gas reservoirs have been found in the Baiyun Sag (Zhang et al., 2014; Mi et al., 2016), but the reservoir-forming strata are single and about 90% of the oil and gas are accumulated in the lower member of the Miocene Zhujiang Formation, while the oil and gas exploration in the middle and deep Zhuhai-Wenchang Formation is poor with scarce commercial petroleum discovery (Mi et al., 2018). One reason for this is that the exploration degree of the middle to deep strata is relatively low and the understanding of oil and gas accumulation is unclear. Another is that the basic geological conditions of the study area are very complex: the hydrocarbons can be supplied from multiple sets of source rocks of Wenchang and Enping formations, the basin has been in a high heat flow, the types of discovered oil and gas reservoirs are diverse, and the charging process of oil and gas is complex.
Because the Baiyun Sag was developed on the ocean-land transitional crust and affected by the expansion of the South China Sea (Li, 1993; Mi et al., 2018), the sag has the characteristics of high heat flow with the gradual increase in the geothermal gradient from 3.5℃/(100 m) in the north to 5.0℃/(100 m) in the south (Nissen et al., 1995; Shi et al., 2003; Mi et al., 2009; Tang et al., 2014). The Eocene Wenchang and Enping Formations are source rocks developed in the Baiyun Sag. These source rocks are deeply buried with a large thickness, and they have reached the thermal stage of high to over maturation at present (Mi et al., 2018; Zhu et al., 2019). The organic matter of source rocks drilled in the Enping and Wenchang formations are mainly prone to humic type with some sapropelic type (Zhu et al., 2008; Long et al., 2020; Chen et al., 2021), which can generate light oil, volatile oil and condensate in different thermal stages under a high geothermal gradient (Tissot and Welte, 1984; Zhao et al., 2013). In the Baiyun Sag, light oil, volatile oil, and condensate have all been discovered in the reservoirs from the Yuehai to Zhujiang Formation: condensate gas reservoir was founded in the Panyu Low Uplift (PLU) of the main sub-sag, light oil accumulated in the eastern sub-sag (ESS), and oil and gas coexisted in the eastern main sub-sag (E-MSS), showing the characteristics of multiple hydrocarbon supplies, multiple hydrocarbon charging stage, high accumulation efficiency, and complex fluid phases (Mi et al., 2018). These characteristics exhibit apparent specificity in hydrocarbon formation with foreign successful exploration areas in deep-water areas (Zhou et al., 2007; Zhu et al., 2012; Mi et al., 2018). In addition, because the hydrocarbon accumulation in the middle to deep depth of the Zhuhai to Wenchang Formation is ambiguous, currently the hydrocarbon exploration in the middle to deep depth only attempts in the uplift area of E-MSS. However, these attempts have discovered the W3-2 and H34B volatile oil reservoirs, which breaks through the exploration understanding of the main goal of searching gas in this area and confirms the exploration strategy of exploiting the Paleogene oil in the deep-water area of the Baiyun Sag. Also, these discoveries reveal the complex distribution pattern of oil and gas reservoirs, i.e., the coexistence of light oil reservoirs, volatile oil reservoirs, condensate oil and gas reservoirs, and pure gas reservoirs. More importantly, the distribution pattern of oil and gas, “upper gas and lower oil” (Gasupper-Oillower), is becoming much clear in this area. That is, condensate reservoirs are accumulated in the upper structural zone, such as the condensate reservoirs in the Layer ZJ210 of Wells H29A/H29B/H29C/H28/H34A/W9 and condensate gas reservoirs in Layers ZJ210–ZH110 of Well W3-1; the light oil and volatile oil reservoirs are accumulated in the lower structural zone, such as the volatile oil reservoirs in the Layer ZJ220 of Wells H28/H34A and the Layer EP310 of Well H34B, and the light oil reservoirs are discovered in the Layer ZJ220 of Well H29C and the Layer ZH110 of Well W9. Nevertheless, because this area lacks systematic research on the oil and gas genetic relationship, oil and gas charging sequence, adjustment and alteration of oil and gas reservoirs, hydrocarbon generation- migration-accumulation models of source rocks in the condensate gas reservoirs, volatile oil reservoirs and light oil reservoirs, the main controlling factors of the distribution of oil and gas are not clear. This also causes great disagreement among different geologists on the oil and gas exploration potential of the middle to deep depth of this area and raises the question of searching oil or gas, all of which directly restrict the oil and gas exploration at the middle to deep depth of the deep-water area of the (eastern) ZRMB. Furthermore, in domestic and global deep-water oil and gas exploration, it is rare for the complex oil and gas distribution and the basins that simultaneously possess the high heat-flow background, multiple hydrocarbon supplies, multiple oil and gas charging stages, and multiple fluid phases. The main controlling factors of hydrocarbon accumulation and the methodologies of migration and accumulation process in such basins are less studied than the traditional “cold basins” and urgently need to be deepened.
To examine the controlling factors of hydrocarbon accumulation under the abovementioned complex distribution of oil and gas pools in the Baiyun Sag, this paper analyzed the organic matter type and hydrocarbon potential of its main source rocks, identified the alteration extent of condensate gas reservoirs and volatile oil reservoirs, and investigate the possible phases of hydrocarbon migration. Meanwhile, the hydrocarbon transport and accumulation model and the fractionation evolution model of light oil, volatile oil and condensate oil in this area were also discussed. This work can provide valuable support for petroleum exploration in the Baiyun Sag, the Qiongdongnan Basin (Zhang et al., 2007, 2021), or the Zengmu Basin (Zhang et al., 2007, 2021), etc., that have experienced high heat flow and mainly sourced hydrocarbons from humic organic matter in continental margin basins in the South China Sea.
The Baiyun Sag is the largest Cenozoic sag deposited in the deep-water areas in the ZRMB. The sag covers an area of approximately 25 000 km2, and its water depth ranges from 200 m to 3 000 m (Pang et al., 2018; Ping et al., 2019). Based on the variations in subsidence and deposition in different areas, the sag can be divided into four sub-sags: the main sub-sag (MSS), the western sub-sag (WSS), the eastern sub-sag (ESS), and the southern sub-sag (SSS). The strata in the sag developed from bottom to top are the Eocene Wenchang and Enping Formation, Oligocene Zhuhai Formation, Miocene Zhujiang-Yuehai Formation, and Pliocene−Quaternary Formation (Fig. 1).
The Wenchang and Enping formations are mainly lacustrine deposits, which are the main source rocks in this area with a maximum thickness of over 7 000 m and a maximum depth of over 12 000 m (Mi et al., 2018). In addition, the crust of the Baiyun Sag has been dramatically thinned due to the strong dissociation, thus showing the characteristics of hot basin with a maximum geothermal gradient of 5.2℃/(100 m) in the borehole. Under the background of high heat flow, the source rocks in this area could generate hydrocarbons at an earlier stage, maturate quickly, and form overpressure induced by hydrocarbon generation, suggesting favorable conditions for hydrocarbon accumulation (Pang et al., 2018; Tian et al., 2020).
Currently, oil and gas in the Baiyun Sag are mainly found in the ESS and MSS, of which ESS are rich in light oil reservoirs (e.g., H16, H20 oil fields), and the Panyu Low Uplift in the northern MSS and the E-MSS are mainly rich in condensate gas reservoirs (e.g., W3, H29 gas fields). The strata of reservoir formation are concentrated in the lower member of the Zhujiang Formation and the Zhuhai Formation, while other strata are scarce of oil and gas accumulation.
From the perspective of oil and gas distribution, the E-MSS is the most complex, showing the characteristic of Gasupper-Oillower and the coexistence of condensate gas reservoirs and volatile oil reservoirs (Fig. 2). Specifically, the Layer ZJ210 of Well W3-2 in the graben area and the Layer EP310 in Well H36B are volatile oil reservoirs, with gas-oil ratios of 550 cm3/cm3 and 610 cm3/cm3, respectively. The Layers ZJ210 to ZH110 in the W3 step-fault zone near the sag in the uplift area are all condensate gas reservoirs, but vertically, the content of oil components decreases and the gas-oil ratio increases from bottom to top. For example, the gas-oil ratio of the gas reservoir in the Layer ZJ210 to ZH110 is 13 270 cm3/cm3 and 2 766 cm3/cm3, respectively.
The oil and gas distribution shows an obvious characteristic of Gasupper-Oillower in the nose-shaped structural belt H29 in the uplift area, in which the condensate gas is distributed in the Layer ZJ210 of Wells H29A/H29B/H29C/H28/H34A, and the oil is distributed in the lower Layers ZJ220 and ZH110 of Wells H34A/H28/H29C/W9.
It is noteworthy that in the condensate gas reservoirs in the Layer ZJ210, the gas-oil ratio of the gas reservoirs at different structural locations shows a trend of increase in gas-oil ratio with increasing the migration distance: the gas-oil ratio increases from 4 021 cm3/cm3 in Well H34A near the source rocks to 23 836 cm3/cm3 in Well H29A far away the source rocks. Similarly, the gas-oil ratio in the lower part of the condensate gas reservoirs is also relatively high, and the reservoir properties are quite different. For example, the Layer ZJ210 of Well H34A to Well H28 near the source rocks is a volatile oil reservoir, with a gas-oil ratio of 228–334 cm3/cm3 and a crude oil density of 0.50 g/cm3 under formation conditions; and the Layer ZJ220 of Well H29C is an ordinary black oil reservoir with a gas-oil ratio of 180 cm3/cm3 and a crude oil density of 0.63 g/cm3 under formation conditions, and the Layer ZJ210 in the structural belt W9 is a light oil reservoir with a gas-oil ratio of only 52 cm3/cm3.
In the Baiyun sag, only a few exploratory wells have been drilled through the Enping Formation or Wenchang Formation. Previous reports have revealed that the characteristic of source rocks in the Baiyun Sag is principally equivalent to that in the Zhu I and Zhu III depressions. We determined the hydrocarbon potential of source rock samples in the Enping and Wenchang formations from six wells (including one well that recently drilled) in the Baiyun Sag. The Rock-Eval parameters show that the lacustrine Wenchang Formation contains immature to marginally-mature Type-II1 kerogen with HI values (HC/TOC) greater than 300 mg/g (Fig. 3). Samples in the Well W4-1 belong to the fair to medium source rocks with the greatest organic matter abundance (1.36%–1.72% TOC).
The kerogen type of source rocks in the upper Enping Formation, which was deposited in a swamp, is difficult to be determined, because most of the samples have reached a higher level of thermal maturity as indicated by Tmax values. These source rocks contain TOC of <1.75% and have HI values (HC/TOC) of ≤150 mg/g, suggesting that they are probably poor to fair source rocks and contain gas-prone kerogen derived from land plants. Several samples contain TOC of 5.72%–11.56%, but their low HI values (HC/TOC) ranged from 87–128 mg/g suggest that they are carbonaceous mudstones and contain gas-prone kerogen. By contrast, underlying lacustrine samples buried at depths of over 4925 m in the Well P33 may be better source rocks. These samples contain TOC of 1.44%–3.90% with low HI values (HC/TOC) of <120 mg/g, but they have reached the late oil to early wet gas window as indicated by their Tmax values. The lacustrine source rocks in the lower Enping Formation in Wells P27 and H29B are graded as good to excellent source rocks that originally contained Type II kerogen and are characterized by oil- and gas-prone types. Our results indicate that lacustrine source rocks with oil- and gas-prone in the lower Enping Formation and Wenchang Formation probably generated the volatile oil that has been discovered in the E-MSS of the Baiyun Sag.
The gas samples in the E-MSS are classified as non-associated gas from sapropelic-liptinitic organic matter (mainly Type-II kerogen). The gas maturity equivalent oil-immersed vitrinite reflectance (Ro) exceed 2%. Thus, we conclude that the natural gas in the E-MSS was generated by oil- and gas-prone kerogen in the source rocks developed in the shallow lakes, which differs from the coal-related gas in the PLU of the Baiyun Sag (Wang et al., 2018). As mentioned above, the maturity of condensates in the E-MSS is similar to the volatile oils but lower than the natural gas. These suggest that the condensate gas reservoirs are a mixed product of mature condensate and highly mature dry gas.
In addition, according to the results of the identification chart of the origin of natural gas discovered in the Baiyun Sag (Dai, 1992), the natural gas in the ESS is mainly mixed gas between coal-based gas and oil-based gas (Long et al., 2020; Chen et al., 2021). Its ethane δ13C2 is about –28‰, reflecting a mixed origin of parent material (Liu, 2009). The discovered oil and condensate have the characteristics of high terrigenous input T compounds (Fig. 4), which are widely present in the Tertiary sediments (Van Aareee et al., 1990; Zhang et al., 2004; Lu et al., 2019). Also, the carbon isotope of the whole oil is –29‰ to –27‰, showing the dominant input of terrigenous higher plants (Summons et al., 2006), which speculated that the parent material of hydrocarbon formation is also Type II to III organic matter, and in terms of biogenic composition, this type of source rock is mainly rich in T compounds. The hydrocarbon-forming parent material is the resin compound from higher plants and mainly generate raw light oil (Rangel et al., 2002; Huang et al., 2003).
On the whole, from the evaluation results of the mudstones in the Wenchang and Enping formations and the characteristics of discovered oil and gas, the types of hydrocarbon-generating materials of the effective source rocks in this area are the mixed organic matters, which can generate oil in the mature stage and generate gas in the late high-mature stage. These factors are also the material foundation of the Gasupper-Oillower distribution pattern in the E-MSS.
In addition, under the background of high heat flow, source rocks in the Wenchang and Enping formations have reached the high to overmature thermal stage, and the organic matter that concurrently generates oil and gas directly leads to the fact that such source rocks have conventional oil generation in the early mature stage, volatile oil formation in the later stage of the oil generation peak, and condensate oil and gas generation in the high mature stage (Tissot and Welte, 1984; Zhao et al., 2013). Moreover, this kind of hydrocarbon generation and evolution sequence are intuitively reflected in the distribution pattern of Gasupper-Oillower that has presented in E-MSS.
Furthermore, previous studies on the characteristics of source rocks in the Wenchang and Enping formations in the MSS suggest that the main peak of oil generation of the source rocks is 33–23 Ma (Zhu et al., 2019). The main peak of gas generation is 23–16 Ma, which is characterized by the concentrated, rapid and massive gas generation, and the main gas generation period corresponds to the period of intense subsidence since 23.8 Ma in the Baiyun Sag (Pang et al., 2007).
Two kinds of liquid HCs, volatile oil and gas-condensate, are produced in the E-MSS. They have low densities (<0.75 g/cm3) under reservoir conditions with high wax content (1.28%–5.63%), indicating a terrestrial origin. The PVT data are widely used to identify the petroleum fluid phases (Zhou, 2004). As compared to black oils in the ESS, the volatile oils in the E-MSS have lower densities (0.50–0.65 g/cm3) with higher gas-oil ratios (GORs) (228–610 m3/m3) under reservoir conditions (Fig. 5a). In contrast, the condensate gas discovered in the sag has much lower densities (0.18–0.24 g/cm3) under reservoir conditions with remarkable high GORs that range from 2 800 m3/m3 to 24 000 m3/m3. The reservoir fluid ternary diagram also indicates that the fluid compositions of the E-MSS volatile oils are different from both the ESS black oil and ESB condensate gas. The contents of light components (C1+N2) of the ESB volatile oils are between those of black oils and condensate gas samples in the sag (Fig. 5b).
For a typical black oil reservoir, the reservoir pressure is significantly higher than the saturation pressure of the oil. Although the formation pressures among the E-MSS volatile oil reservoirs are different, they are close to the saturation pressures of its corresponding volatile oil. In one case, the crude oil is in a saturated or supersaturated state before entering the reservoir, and then the saturation pressure of the oil is adjusted to the reservoir pressure through some phase fractionation during migration. The other case is that the unsaturated oil first entered the reservoir, then the oil reservoir was charged by natural gas in the late period, which makes the unsaturated oil to be saturated or even supersaturated state. According to the fluid inclusion, a large amount of oil-gas miscible fluid inclusions, in which the oil occurred as oil ring surrounding the gas phase, were observed in sandstone samples from the reservoirs of Wells H28 (Fig. 6a) and W3-1 (Figs 6b and c). Such miscible phase inclusions with high gas-liquid ratios suggest that the fluid property of the hydrocarbon is in an oil-gas miscible or a critical (volatile oil) state when they were captured. When the temperature drops below the capture temperature, natural gas precipitates from the liquid oil in the inclusion system. It implies that a large amount of natural gas had been dissolved in the oil phase when the oil entered the reservoir. The H34B volatile oil was found in the Enping Formation, where the source rocks are located. Generally, oil in the Enping Formation will experience a short migration distance than in the upper Zhujiang Formation, and it is the first to be affected by late gas charging. If the late gas charging occurs, high reservoir pressure will make the excess gas dissolve in the oil which will show a high GOR. However, the saturation pressure of the H34B volatile oil is 36.7 MPa which is 5.8 MPa lower than the reservoir pressure, and the GOR of the H34B volatile oil is only 610 m3/m3 which is dramatically lower than the typical condensate gas reservoir. Thus, we suggest that the volatile oil was not formed from the late gas charge, but formed before entering the reservoir.
Oil-oil correlations were performed on volatile oils and condensates in the E-MSS. Gas chromatography results demonstrate that n-alkanes have not significantly depleted and the abundance of the unresolved complex mixture (UCM) is low (Fig. 7), indicating that neither type of fluid is biodegraded. Pristane/phytane (Pr/Ph) ratios of volatile oils range from 3.3 to 4.6, overlapping the range of Pr/Ph ratios of the condensates (3.1–4.5). These results show that the source rocks for the ESB volatile oils and condensates were formed under relative oxic conditions (Peters and Moldowan, 1993). The representative mass chromatograms of tricyclic terpanes (TTs), hopanes (m/z 191), and bicadinanes (m/z 412) are shown in Fig. 7. TTs are commonly used to recognize terrigenous organic matter input (Ekweozor and Strausz, 1983; Tao et al., 2015). The volatile oils and condensates exhibit a similar stairstep distribution of the TTs with a predominance of C19TT and C20TT (Fig. 7). It means that both the volatile oil and condensates were derived from organic matters that contain land plant input. Fu et al. (2019) concluded that oils in the E-MSS of the Baiyun Sag were produced in kitchens that contain fluvial/deltaic sediments. In addition, these oils present high abundances of oleanane and bicadinane (Fig. 7), which are derived from the higher land plants and have independent precursors (Grantham et al., 1983; Peters and Moldowan, 1993; Rangel et al., 2002), showing the origin of terrigenous organic matter. The range of oleanane/C30 hopane (Ol/C30H) ratios in both volatile oils and condensates varies between 0.57–2.43, whereas T-bicadinane/C30 hopane (T/C30H) ratios in these samples range from 1.79 to 5.08. Moreover, Ol/C30H and T/C30H ratios in the E-MSS volatile oils and condensates are different as compared to the PLU oils, which are characterized by the low Ol/C30H ratios (<0.92) and higher T/C30H ratios (4.00–7.67) (He et al., 2018). The asymmetric “V” pattern of C27–C29 regular steranes with approximately equal abundance of C27 and C29 sterane occurs in the volatile oils and condensates (Fig. 7), implying a mixed contribution of terrestrial land plants and aquatic organic matter to their source rocks (Volkman, 1988). In summary, the volatile oils and condensates exhibit similar organic geochemical characteristics, which is evidence that they were generated from similar source rocks.
Molecular parameters are widely used to evaluate oil maturity, but different molecular maturity parameters generally have different working ranges. For instance, the C29 sterane isomerization parameters 20S/(20S+20R) and ββ/(αα+ββ) reach equilibrium in the early to the middle oil maturity stage (Peters and Moldowan, 1993). The Methyl-Phenanthrene Index (MPI) shows a segmented correlation with increasing maturity (Radke et al., 1986). In this study, we used multiple parameters to determine the maturities of the E-MSS oils. The C31 homohopane maturity parameter 22S/(22S+22R) in the volatile oils and condensates ranges from 0.54 to 0.59, indicating that these samples reached or surpassed the peak oil generation stage, i.e., Ro>0.7% (Peters and Moldowan, 1993). The C29 sterane maturity parameter 20S/(20S+20R), which ranges from 0.50 to 0.53, has also reached equilibrium, i.e., the maturity of the ESB volatile oils and condensates exceeds 0.7%Ro. The Ts/(Ts+Tm) maturity parameter, which is based on the relative stability of C27 hopanes, is applicable over a wide maturity range but it also has a source dependence (Seifert and Moldowan, 1986). Ts/(Ts+Tm) ratios of the ESB volatiles oils and condensates are between 0.45–0.60, equivalent to Ro ranging from 0.7% to 1.0%. In addition, the estimated maturities of the ESB oils using the MPI parameter (Radke et al., 1982) are mainly between 0.81 and 0.86. Thus, these maturity parameters indicate that the volatile oils and condensates were generated at similar levels of thermal maturity, which are lower than that required for the crack of oil to gas. However, a diamondoid maturity parameter (MDI=4-MD/(4-MD+3-MD+1-MD), where MD refers to methyl diadamantane) indicates that these samples were generated at a much higher maturity, equivalent to Ro ranging from 1.36% to 1.53%. He et al. (2018) estimated the maturity of the E-MSS oils using a polycyclic aromatic hydrocarbon (PAH) parameter based on trimethylnaphthalenes, which also indicates that they formed at a high maturity. It is apparent that the maturity of the E-MSS oils shows significant differences applying different kinds of maturity parameters. Nevertheless, these parameters indicate that the E-MSS volatile oils and condensates were generated at the same level of thermal maturity. According to the study of Fang et al. (2013), the total adamantane content of crude oil is positively correlated to the oil maturity. The total adamantane contents of the E-MSS volatile oils and condensates as well as the ESS black oils are less than 4 000×10−6, while the condensates associated with the PLU natural gas have a content of total adamantane between 6 600×10−6 to 11 000×10−6 (Fig. 8). Therefore, the maturities of condensates in the E-MSS are similar to the volatile oil and black oil, but are lower than the typical condensate associated with natural gas in the PLU. This in turn suggests that the presence of volatile oil and condensate gas charges requires a more complex explanations than those attributed to differences in source rock maturities.
In general, the oil and condensate generated by the same source rock exhibit similar source characteristics, but vary in their maturities. Black oil and volatile oil are generated at a relatively lower level of maturity than condensate associated with natural gas (Li, 1998). However, light HC compounds can be partitioned from oil into natural gas under certain conditions. In that case, biomarker characteristics of condensates that precipitate from the gas may be similar to the original oil, and the maturity of the condensate and oil will be similar to a certain degree (Dzou and Hughes, 1993). The degree of similarity depends on the extent of component of the original oil taken away by the light HC compounds, which may be controlled by the temperature and pressure. We have shown that volatile oils and condensates from the E-MSS of the Baiyun Sag exhibits similar geochemical characteristics and maturities, and the condensates are not associated with the E-MSS natural gas. Therefore, the condensate in the E-MSS are probably formed during the fractionation of the volatile oil.
Secondary alteration can influence the oil composition and HC charging. Thompson (1988) first proposed the evaporative fractionation mechanism to describe the phenomenon of natural gas removing light compounds from crude oil when it exsolved and then forms a condensate gas accumulation. Meulbroek et al. (1998) further analyzed the situation when gas flows through an oil pool and strips compounds from it, and they designated this process as “Gas Washing”. Kissin (1987) and Losh et al. (2002) described how to estimate the loss of n-alkanes from a gas-washed oil. Generally, for the n-alkanes, the relationship between the logarithm of molar abundance and carbon numbers is linear in the unaltered oil and exhibits a segmented distribution in the gas-washed oils (Losh et al., 2002).
We estimated the depletion of n-alkanes (Q) in the E-MSS volatile oils using the relationship between the logarithm of molar abundance and the carbon numbers of the n-alkanes (Fig. 9). We found that the volatile oils in the lower Zhujiang Formation show differences between the unfractionated n-alkane profile and the measured n-alkane profile. More interestingly, the depletion of n-alkanes in volatile oils from the W3-1 (Q=2.9%) to the H29C structural belt (Q=74.8%) increased toward the margin of the sag. In contrast, the logarithm of n-alkane mass molarity and the carbon number of the E-MSS condensates show an approximately linear relationship, revealing no evident secondary alteration occurred in those samples.
Secondary alteration modifies the composition and physical properties of the oil (Carpentier et al., 1996; Larter and Mills, 2008; Thompson, 1988). Su et al. (2000) demonstrated that gas washing has a much greater effect on the secondary alteration than phase-controlled fractionation through a series of experiments: gas washing generally causes significant changes in the wax content, density and viscosity of crude oil, while phase-controlled fractionation results in a slight increase in viscosity and density of crude oil with little effect on freezing point and wax content. In the E-MSS, condensate gas accumulations and deeper volatile oil pools are present in the Zhujiang Formation. This implies that if the gas washing would have played an important role in the formation of ESB oil and gas pools, oil reservoirs near the MSS would have been subjected to more intense gas washing. In that case, oil pools near the MSS should exhibit a greater loss of n-alkanes than oil pools located farther from the center of the sag. In fact, our observation was opposite: the depletion of n-alkanes in volatile oils increased with the increasing distance from the MSS (Fig. 2). It was also observed that the wax contents of volatile oils in this area have not changed significantly. Dzou and Hughes (1993) studied the correlativity between migration fractionation and molecular biomarkers and suggested that most of the biomarkers and maturity parameters do not show an obvious correlation except for a slight increase in the Pr/Ph ratio. This phenomenon was also found by Curiale and Bromley (1996). In the E-MSS, an increase of Pr/Ph ratio also exists between volatile oil and condensate, such as the relatively higher Pr/Ph ratios among Wells W3-2, H34A, H28 and H29C. Therefore, the loss of n-alkanes of volatile oils was probably caused by phase-controlled fractionation. In this process, with the migration of volatile oils to the shallower strata, the formation pressure decreased, the loss of HC compounds from crude oils increased with the increasing distance from the MSS, and the exsolved gas carrying a substantial amount of dissolved oil continued to migrate and form shallower condensate gas accumulations. This mechanism is different from previous finding that the ESB oils have experienced intense gas washing (Chen et al., 2015).
Volatile oils and condensates in the E-MSS were generated by the same source rocks, however, their formations were influenced by several geological factors. First, the source-rock beds of the Wenchang and Enping formations in the MSS generated both the oil and gas in the study area. Second, the generation of oil and gas coincided with the formation of migration pathways. Li et al. (2017) concluded that the Eocene source rocks in the E-MSS principally generated oil from 33 Ma until 15 Ma, whereas, the main gas generation stage was between 20–10 Ma. Thus, the main gas generation period of the Eocene source rocks overlapped with the final stage of oil generation due to the rapid burial of source rocks in the MSS (Xie et al., 2014). This process is also promoted by the rapid increase in the basal heat flow from –60 mW/m2 to –90 mW/m2 in the MSS during this period (Li et al., 2017). This reduced the hydrocarbon generation window and led to the expulsion of two kinds of petroleum, i.e., oil and gas.
Two types of faults can be considered as the migration conduits for the eastern petroleum accumulations. The first episode of fault activity, which primarily occurred from 18.5 Ma to16.0 Ma (Sun et al., 2014), created faults between source rocks and the structural belt W3-1 (Fig. 2). The second episode occurred during the Dongsha Event (13.8–10.0 Ma), causing extensive faulting from the MSS to the structural belts W3-2 and H34 (Sun et al., 2008) (Fig. 2). The relative late charging time of the ESB petroleum (14–6.5 Ma) corresponds with the second episode of fault activity (Kong et al., 2018), and indicates that the oil generated earlier by the Eocene source rocks could not migrate into the traps due to the absence of effective migration pathways. In that case, the oil produced by the source rock during the maturity stage will first accumulate around the source rocks due to the lack of migration pathways. Then the oil was influenced by a late charge of natural gas to form a mixed-phase fluid with a high gas-oil ratio, i.e., volatile oil. At the same time, overpressure occurred in both the Wenchang and Enping formations, and the pressure coefficient reached 1.27–1.8 in the MSS (Kong et al., 2018). Thus, the solubility of natural gas in oil increases at high pressure, and some of the free gas dissolved in the oil and increase its GOR. In the subsequent lateral migration and accumulation processes, the migrated volatile oil reached its bubble point at a lower pressure, which led to the formation of exsolved gas that separated from the oil phase. It is worth noting that lateral migration through the sand bodies mainly occurred among the H34, H28 and H29C structures, which may be verified by the variations of geochemical migration parameters. The 4,6-/(1,4-+1,6-)-DMDBT and TMNr parameters based on the isomer ratio of dibenzothiophene and trimethylnaphthalene can be used to indicate the migration direction of crude oil. With the increase of migration distance, the fractionation effect of dibenzothiophene and trimethylnaphthalene isomers increased, resulting in the ratios gradually decreased (Li et al., 2013; Xiao et al., 2016). Both 4,6-/(1,4-+1,6-)-DMDBT and TMNr decreased from Well H34 to H28 to H29C, suggesting that the general migration direction of oil is from the MSS to the eastern margin of the depression along the sand bodies between the structures. By contrast, the later fault adjustment during the Dongsha Event (Zhao et al., 2012) promoted the phase-controlled fractionation process and provided a channel for the vertical migration of exsolved condensate gas.
The distribution of the ESB oil and gas pools have two characteristics: (1) The distribution of oil and gas presents Gasupper-Oillower; and (2) the GOR of condensate gas and the n-alkane mass depletions (Q) in volatile oils increase with increasing lateral distance from the MSS (Fig. 2). Based on the oil geochemistry, hydrocarbon generation history, and tectonic activity, we propose a Sequential Charge Model (SCM) to explain the accumulation processes in the E-MSS (Fig. 10). In the MSS of the Baiyun Sag, oils generated by the mature Eocene source rocks migrated a short distance due to the absence of large-scale fractures or faults, i.e., the oils accumulated near the source rocks. Next, free gas generated by the source rocks during the rapid subsidence period of the MSS dissolved in the oil, forming a mixed-phase fluid (volatile oil) with a high GOR. These volatile oils accumulated in suitable traps in the following manner. Initially, the mixed-phase fluids with high GORs migrated via sandstone beds and accumulated in lower Zhujiang reservoirs with slow fractionation. Then, because of the fault movement during the Dongsha Event, it caused trap failures and resulted in a series of phase-controlled fractionation events in the volatile reservoirs when formation pressure dropped below oil bubble-point pressures, which allows gas to be exsolved from the oil. The amount of loss of light to medium HC compounds in oils increases with increasing distance from the MSS. Exsolved natural gas carrying a substantial amount of dissolved oil continue to laterally migrate and form condensate gas accumulations in the upper Zhujiang reservoirs (Fig. 10). The above processes mainly occur in the structural belts W3-2 to H29C.
It is worth noting that the charging mechanism around the structures W3-1 and W9-1 is different from that of the structural belts W3-2 to H29C. In the structures W3-1 and W9-1, oil and gas principally vertically migrate along the deep faults adjacent to those structures. Volatile oil phase fluids were subjected to rapid phase fractionation and caused light and medium HC compounds to partition into natural gas. Figure 5 shows that the black bitumen filled in the intergranular pores and impregnated the edges of detrital particles of the sandstone from the reservoirs in Well 3-1B. Li et al. (2019) demonstrated that the bitumen in the structure W3-1 was not a cracking product of the ancient oil reservoir. Thus the bitumen in the reservoirs implied a rapid and strong fractionation may occur in the oil accumulation (Chen et al., 2017). This kind of fractionation became weaker at a shallower depth during vertical migration. Consequently, the amount of light HC compounds dissolved in the gas decreased, and the corresponding GOR increased (Fig. 10). Residual oil reservoirs occur deeper than gas reservoirs. As a result, commercial oil accumulations may be present at deeper depths near deep faults.
By applying the SCM of oil and gas in the E-MSS, it has been concluded that volatile oil accumulations in the MSS are more likely to occur near pods of mature source-rock beds where faults are absent. In contrast, oil fractionated when it laterally migrated from the MSS and formed Gasupper-Oillower pools. Therefore, two exploration targets are available in this area. The upper interval of the Zhujiang Formation contains condensate gas accumulations, and the volatile oil occurs in the lower Zhujiang Formation as well as in the deeper Eocene reservoirs.
The SCM also controls the distribution of petroleum pools in deep faults present with diapirs, i.e., oil reservoirs are deeper than gas reservoirs. For example, in the structure W3-1, where deep faults reach mature source-rock beds in a large trap, natural gas reservoirs with nearly 30×109 m3 of reserves have been discovered in the upper Zhuhai Formation and Zhujiang Formation. For the deeper Wenchang and Enping intervals, although they have not yet been drilled, we speculate that a large-oil pool may exist in the Eocene reservoirs at the structure W3-2. Moreover, deeper oil exploration in Wenchang and Enping reservoirs can be performed at the structure W3-1 and the adjacent structure W9-1. Sun (1996) proposed an empirical parameter φ1=C2/C3+(C1+C2+C3+C4)/(C5+C6+C7+C8+C9+C10+C11) based on PVT data of reservoir fluids to identify different types of reservoir fluids, concluding that the φ1 values between 15 and 60 indicate wet gas reservoirs with large oil rims. For the E-MSS condensate gas samples, the φ1 values ranged from 16 to 55, implying the presence of commercial oil pools under the condensate gas reservoirs. In addition, Process II of the SCM can lead to the formation of condensate gas accumulations with oil rims when volatile oil fractionates.
Two oil and gas systems exist in the E-MSS of the Baiyun Sag. One is condensate gas accumulations in the upper Zhujiang Formation, and the other is volatile oil accumulations in the lower Zhujiang Formation and deeper Eocene reservoirs. Volatile oils have experienced secondary alteration of phase-controlled fractionation that occurred during their lateral and vertical migration.
A Sequential Charge Model (SCM) is proposed to describe and explain the distribution of Gasupper-Oillower reservoirs in the E-MSS. The first stage is the formation of mixed-phase fluids (volatile oil) with a high gas-oil ratio during the rapid subsidence of the MSS without migration conduits. Then, these fluids were transported to the traps through two migration mechanisms. From the structural belts W3-2 to H34 and the H28 to H29, volatile oil migrated into lower traps via sandstone carrier beds and formed the volatile oil pools. During the charging process, the reduction of formation pressure led to the phase-controlled fractionation of these oil accumulations, which is different from the previous view of gas washing. Lastly, the fault adjustment made the exsolved condensate gas accumulate in the shallower reservoirs. In contrast, the vertical oil and condensate gas charge in the structures W3-1 and W9 is mainly controlled by the deep faults, which allowed rapid fractionation.
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Cong Chen, Xiangtao Zhang, Guangrong Peng, Zulie Long, Baojun Liu, Xudong Wang, Puqiang Zhai, Bo Zhang. Controlling factors on the charging process of oil and gas in the eastern main sub-sag of the Baiyun Sag, Zhujiang River (Pearl River) Mouth Basin[J]. Acta Oceanologica Sinica, 2023, 42(3): 189-200. doi: 10.1007/s13131-022-2140-z
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