1 Introduction
The Wenchang-A Sag, located in the Zhu III Depression of the Pearl River Mouth Basin (PRMB) (Fig.1(a)), is a Cenozoic extensional graben basin at the continental margin (
Jiang et al., 2009;
Jiang et al., 2021). Since hydrocarbon exploration began in the 1980s (
Wu, 1984;
Huang et al., 2003), a series of oil and gas fields have been discovered in the Wenchang-A Sag, which is grouped into five areas, namely Areas A, B, C, D, and E (Fig.1(b)). Area A lies in the western part of the sag and is mainly found with oil reservoirs, while Area E, located in the eastern sag, develops gas reservoirs. Moreover, Areas B, C, and D are dominated by gas reservoirs, yet have locally-developed reservoirs (Fig.1(b)). This research, based on actual production data, investigates the geochemical characteristics of the source rock and hydrocarbons and considers that the primary source rock for the study area in only the Oligocene Enping Formation source rock (
Jiang et al., 2009;
Quan et al., 2015).
Previous studies indicate that the source rock of the Wenchang-A Sag is humic and has reached the mature stage (
Fu et al., 2011;
Quan et al., 2015). There are differences in oil and gas distribution in the study area. Areas A and B are dominated by oil reservoirs, and areas C, D, and E are dominated by gas reservoirs (Fig.1(b)). Further analysis is needed to understand the reasons for the varied distribution of oil and gas throughout the region, as well as the geochemical properties and origins of these hydrocarbons. Hence, this study first investigates the characteristics of the source rock and then thoroughly reviews the source rocks of the Wenchang-A Sag using multiple geochemical approaches, such as Rock-Eval pyrolysis, kerogen maceral analysis, and vitrinite reflectance measurement. Furthermore, the geochemical characteristics and source of crude oil are identified by mass spectrometry-gas chromatography of total, light and saturated hydrocarbons. Meanwhile, the origin of natural gas is determined by gas composition, carbon isotope ratio, and light hydrocarbons. The results of this study are expected to clarify the geochemical characteristics and origin of oil and gas in the study area, and identify the main control factors contributing to the differentiated planar distribution of oil and gas reservoirs, and thus to provide the theoretical guidance for the deployment of hydrocarbon exploration in the Wenchang-A Sag.
2 Geological setting
PRMB is in the northern South China Sea, covering an area of about 175000 m
2 and mainly featuring Cenozoic deposits (
Wu, 1984;
Jiang et al., 2009;
Quan, 2018), and contains eight structural units. Namely Zhu I, II, and III Depressions, Shenhu Uplift, Panyu Low Uplift, Dongshan Uplift, Southern Depression, and Northern Fault Belt. The Wenchang-A Sag is located in the northern Zhu III Depression (Fig.1(a)). The Wenchang-A Sag is characterized by faulting in the south, overlapping in the north, and transition in the center. Due to the fault belt and local low relief, many sub-sags develop sequentially inside this sag, named A−E (Fig.1(b)).
Since the Cenozoic, PRMB has undergone three tectonic evolution stages, namely rift, fault depression, and depression stages (
Xu and Huang, 2000;
Xiao et al., 2009). From bottom to top, it mainly develops the Palaeogene Wenchang, Enping, and Zhuhai Formations, as well as the Neogene Zhujiang, Hanjiang, and Yuehai Formations (Fig.1(c)). The second member of the Enping Formation is encountered in the Wenchang-A Sag, and the Enping Formation is found with thick source rocks (Fig.2(a) and Fig.2(b)). During the fault depression stage of the late Oligocene (30−16.5 Ma), the Zhuhai and Zhujiang Formations are deposited, which serve as the main reservoir rocks for the Zhu III Depression (
Cheng et al., 2015;
Quan et al., 2015), and the second member of the Zhuhai Formation has the most considerable thickness (Fig.2(a) and Fig.2(b)). PRMB has entered the depression stage since 16.5 Ma, which is associated with weakening tectonic movement and sedimentation of finer mudstone and siltstone that evolve into the regional cap rock of the Zhu III Depression (
Chen et al., 2020). Due to tectonic movement, Area C of the central Wenchang-A Sag is seen with the highest development of faults; and the seismic profile from the sag center in Area C to the sag margin presents closely spaced faults (Fig.2(a)). As for Areas A and B in the sag margin, they show fewer faults in the seismic profile (Fig.2(b)).
3 Materials and methodology
3.1 Materials
A total of 109 mudstone samples were collected from 15 wells. Rock-Eval pyrolysis used 68 samples. A total of 17 vitrinite reflectances were measured. The data are shown in Tab.1. Saturated hydrocarbon gas chromatography-mass spectrometry (GC-MS) used 24 mudstone samples. Crude oil samples were collected from 19 wells. Data on the physical properties and components of crude oil are provided by CNOOC Zhanjiang Branch (Tab.2). GC-MS of 26 crude oils was determined. Specific sample information is shown in Tab.3. Natural gas samples come from 15 wells. The types and distribution of sampling wells are shown in Fig.1(b).
3.2 Methods
1) Rock pyrolysis
Samples are pre-treated by stepwise acid washing to remove unwanted substances, such as carbonate and silicate, and dried using filter paper. The source rock samples are crushed and ground into 0.07–0.15 mm, and the test instrument is the Rock-Eval 6 apparatus. The flow rate of high-purity nitrogen gas is 50 mL/min; that of hydrogen, 30 mL/min; and that of air, 300 mL/min. The initial temperature is 300°C and held for 3 min, and then the temperature is raised at a rate of 25°C/min to 650°C.
2) Determination of kerogen maceral
Kerogen needs to be extracted first. The mudstone samples with TOC ≥ 0.4% are selected (25/20-mesh; 50 g of each sample) and mixed with HCl, NaOH, and heavy liquid, successively. Then, they are separated by ultrasonically assisted centrifugal separation to extract the kerogen in the upper part. Afterwards, the kerogen is extracted and transformed into thin sections by utilizing the glycerol method of thin section preparation. Finally, thin sections of kerogen prepared were observed using the LEICA DM400B biological microscope, and maceral characteristics were summarized. These tests are carried out in the laboratory of CNOOC Zhanjiang Branch Co. Ltd.
3) Vitrinite reflectance
The vitrinite reflectance refers to the percentage of the reflection light intensity from the polished vitrinite surface to the normal incidence light with the wavelength of 546 nm ± 5 nm (green light) (
Hunt, 1979). The adopted instrument is the MPV-COMPACT microscope photometer, which is manufactured by Leitz (Germany). The tests of vitrinite reflectance of the source rock are performed with a temperature of 23°C ± 3°C and relative humidity below 70%.
4) Gas chromatography-mass spectrometry (GC-MS) of saturated hydrocarbons
Soxhlet extraction method, using chloroform as solvent, is used to extract soluble organic matter bitumen from the sample. After bitumen is removed by n-hexane, saturated hydrocarbons, aromatic hydrocarbons, and non-hydrocarbons are separated by silica gel-alumina (3:2) chromatography. The HP5890-5972 GC-MS analyzer is used to analyze the saturated hydrocarbon fractions, equipped with a 60.00 m × 0.32 mm × 0.25 µm capillary column. The starting temperature of heating is 100°C; the carrier gas is helium; the constant flow mode is adopted; the ion source temperature is 230°C; and the inlet temperature is set to 310°C.
5) Natural gas composition
After depressurization, drying, and filtration, the sample is tested using HP 5890 II 600501 GC system. The gas output pressure is set at 80 psi, and the test is performed. The carrier gas is helium. We start at temperature of 40°C and held for 10 min; then, it is heated at 5°C/min to 180°C and held for 10 min.
6) Natural gas carbon isotope ratios
The test is performed, using the IsoPrime 100 gas source stable isotope ratio spectrometer and Agilent 7890A gas chromatograph (Instrument No. D01JS016). The initial temperature of the GC system is 35°C. The temperature is subsequently elevated at a rate of 8°C/min to 80°C, and finally stimulated at a rate of 5°C/min to 260°C and held for 10 min (
Li et al., 2019;
Lu, 2021).
7) Light natural gas hydrocarbons
The analysis of light hydrocarbons of natural gas is performed using the HP Agilent 6890N GC system, equipped with the HP PONA, 50 m × 0.2 mm × 0.5 mm chromatographic column, and flame ionization detector (FID). The temperature is initially set below 30°C and held for about 15 min. Then, it is heated to 70°C at 15°C/min and kept for 2 min. Furthermore, it is raised to 150°C at 3°C/min and held for 10 min. At last, the temperature is elevated to 270°C at 5°C/min.
4 Results
4.1 Geochemical characteristics of source rocks
4.1.1 Organic matter types
Organic matter types determine kerogen’s ability to produce oil or gas. The organic matter that is more of the sapropel type tends to have oil in the mature stage, while the humic organic matter generates a massive volume of natural gas during the mature stage (
Huang et al., 1984;
Chen et al., 2021;
Li and Gong, 2022). Overall, humic organic matter is distributed on the edge of the sag, while sapropelic organic matter is distributed in the middle of the sag. The source rocks of the gas reservoir are mainly humic organic matter, and the reservoirs are distributed in the sapropelic organic matter area. Areas A and B also have local sapropelic source rocks (Fig.3).
The types of organic matter in the study area vary in different sub-sags (Fig.4). Organic matter types of formation intervals vary at different depths. For example, in wells B2 and D1, sapropelic and humic organic matter occur vertically alternately. Planar and vertical variations in organic matter types may contribute to the differentiated hydrocarbon distribution across the study area.
4.1.2 Hydrocarbon generation potential of source rocks
Total organic carbon (TOC) is the amount of organic carbon in a rock per unit mass (
Lu et al., 2021;
Tang et al., 2022). It also includes carbon in soluble organic matter, and is often used to represent organic matter abundance (
Dehyadegari, 2021;
Su et al., 2021;
Huang et al., 2022). S
2 illustrates the content of the pyrolysis hydrocarbon of kerogen at 300°C–500°C, and hence, it can be used as a measure of the hydrocarbon generation potential of source rocks (
Peters and Cassa, 1994). The quality in Areas A and B is poor and fair, and the quality of source rocks in Areas C and D is better. There is a diverse range of source rock quality across various wells in the E area. E2 is the best, followed by E1, and E3 is the worst (Fig.5). It shows that source rocks in Area E also have the potential to generate oil and gas.
Vitrinite reflectance (
Ro) is an essential measure of source rock maturity (
Wu and Gu, 1986).
Ro of the source rock in the study area is 0.70%–1.29% (Tab.1), averaging 1.01%. This indicates that the source rock throughout the sag has entered the mature stage. The maturity of source rocks gradually increased from the south-west to the north-east of the study area, i.e., from Areas B to E.
4.2 Physical and compositional characteristics of crude oil
Crude oil is divided into four types according to its characteristics of physical properties, components and saturated hydrocarbon biomarker parameters. The characteristics and sources of different oils are analyzed below.
The crude oil of the Wenchang-A Sag is light oil, with a density of 0.75–0.83 g/cm3 and averaging 0.78 g/cm3 (Tab.2). The wax content of crude oil varies greatly. Class I and II crude oils have a higher wax content, and Class III and IV crude oils have a lower wax content (Fig.6). Such differentiation may be related to the thermal maturation of source rocks. The sulfur content of crude oil in the study area is low. The content of saturated hydrocarbons is 65.00%–92.44%, and no notable content variation is seen among aromatic hydrocarbons, non-hydrocarbons, and asphaltenes (Tab.2).
4.3 Biomarkers of source rocks and crude oil
The compounds pristane (Pr) and phytane (Ph) found in sediments are generated from the phytol side chain of chlorophyll. Pristane is formed in an environment containing oxygen, while phytane is produced through hydrogenation reduction. Accordingly, they indicate organic matter᾽s sedimentary environment (
Wood and Hazra, 2017). Pr/Ph below 1 stands for a reducing environment; 1–3, an oxidizing-reducing environment; above 3, an oxidizing environment (
Hunt, 1979). The Pr/Ph values of the four types of crude oil in the study area and the source rocks of Enping Formation in different blocks are all greater than 1, indicating that they are all in a partial oxidizing environment. The
n-alkanes of Class I and II crude oils are forward-type, while the
n-alkanes of Class III and IV crude oils are completely peak-type (Fig.7) (Tab.3). The hopane characteristics of crude oil and source rocks in Wenchang A sag are similar, with C
30 hopane as the main peak, 18α(H)-C
29 trisnorhopane (C
29Ts) having a certain peak, and the content of gamma-cerane being low.
The difference between different types of crude oil is mainly reflected in the chromatogram of sterane and bicadinanes. C
27–C
29 regular steranes (RSt) are derived from the steroids of eucaryon and algae (
Tissot and Welte, 1984). 4-methyl steranes (MSt) is a frequent component in the Cenozoic lacustrine sediments in China (
Huang et al., 1994). Bicadinanes (W + T) originate from resin compounds from higher plants and are formed in a more oxidizing sedimentary environment (
Wood and Hazra, 2017;
Milkov, 2018).
Class I crude oil in the study area has a high C27 diasteranes content. The distribution of ααα20RC27-ααα20RC28-ααα20RC29 is V-shaped, and the content of biscadinanes T is high. The bicadinanes / C30hopane ((W + T) / C30H) value is between 1.00 and 6.03 (Tab.3), which is similar to the characteristics of source rocks in C area (Fig.7). This kind of crude oil is mainly distributed in Areas A and B.
Class II crude oil also has a high diasteranes content. The distribution of ααα20RC27-ααα20RC28-ααα20RC29 in regular steranes is ‘L’-shaped distribution, and the bicadinanes content is shallow. The (W + T)/C30H value is between 0.06 and 0.66 (Tab.3), which is similar to the characteristics of source rocks in Area E (Fig.7). This type of crude oil is mainly distributed in the Area C. Still, the crude oil of Wells D4 and E1 also have the same characteristics.
The diasteranes content in class III crude oil is low. The regular steranes of ααα20RC27-ααα20RC28-ααα20RC29 are distributed in the reverse ‘L’-shaped distribution. It has the high C29 regular steranes and bicadinanes content. The (W + T)/C30H value is between 1.59 and 2.11, similar to the source rocks in Area B. The class III crude oil is distributed in Areas B and C, which is the crude oil of Wells B1 and C9.
The diasteranes content in class IV crude oil is low, and the regular steranes of ααα20RC27-ααα20RC28-ααα20RC29 are distributed in ‘V’-shaped distribution, with high peak bicadinane, (W + T)/C30H value between 1.42 and 2.58, which is similar to the characteristics of source rocks in Area A. The crude oil of Wells A2 and C2 has these characteristics.
4.4 Geochemical characteristics of natural gas
4.4.1 Natural gas composition
Natural gas composition data are summarized in Tab.4.
The chemical composition of natural gas in the study area changes significantly. A predominance of methane is observed in hydrocarbon gases. However, the methane content varies from 2.75% to 85.87%, with an average of 42.49%. The dryness coefficient (C
1/C
1 + ) is 40.25%–90.19%, which indicates that natural gas is generally wet gas. Wells B5, D4, D5, and E1 are found with higher dryness coefficients (> 85%), while wells A2 and C4 are lower (< 60%). Variations in dryness coefficients may be related to organic matter types and maturity (
Quan et al., 2019;
Lu et al., 2021). In terms of non-hydrocarbon gases, besides the lower H
2 content (up to 0.01%), considerable variation is observed in O
2, N
2, and CO
2. Specifically, the O
2 is 0.00%–17.02%, averaging 2.91%; the N
2, 0.58%–75.72%, averaging 12.05%; the CO
2, 0.19%–90.82%, averaging 26.13%.
4.4.2 Stable carbon isotope ratios of natural gas
The carbon isotope ratio of natural gas is an important carrier of geological information in natural as (
James, 1983;
Tilley et al., 2011).
δ13C
1 in the study area ranges from −46.15‰ to −37.50‰;
δ13C
2, from −34.70‰ to −28.41‰;
δ13C
3, from −31.48‰ to −24.99‰;
δ13C
4, from −30.86‰ to −26.25‰ (Tab.4).
δ13CO
2 lies between −28.16‰ and −4.11‰ and averages −10.69‰ (Tab.4). The carbon isotope ratios of
n-alkanes in the natural gas grow with the increasing carbon number (
δ13C
1 <
δ13C
2 <
δ13C
3 <
δ13C
4), and yet the reversal distribution of the carbon isotopes of propane and butanes is observed in some formation intervals of wells C2, C7, D4, and D5 (
δ13C
1 <
δ13C
2 <
δ13C
3 >
δ13C
4) (Tab.4). This may be because the produced natural gas is a mixture of gases from the same source rock yet with varied maturity or genes (
Dai, 1990;
Zumberge et al., 2012).
4.4.3 Light natural gas hydrocarbons
Natural gas light hydrocarbons are usually used to characterize maturity and origin (
Huang et al., 2014;
Feng et al., 2016). The number of C
5-C
7 alkanes (
n-C
5-C
7) is 0.20%–0.69%, averaging 0.34; that of the iso-alkanes C
5-C
7 (iso-C
5-C
7), 0.21%–0.68%, with an average of 0.49%; that of cycloalkanes (cyc-C
5-C
7), 0.05%–0.42%, with an average of 0.18% (Tab.5). The content of
n-alkanes and iso-alkanes is relatively high, yet the cycloalkanes content is low. The content of heptanes and isoheptanes can be used as alkylating measurements of the alkylating of light hydrocarbons in sediments (
Feng et al., 2016;
Gong et al., 2018;
Liu et al., 2018). The heptane content of natural gas in the study area varies from 10.96 to 28.57 (averaging 18.00), while the isoheptane content is 1.00–4.25 (with an average of 2.28) (Tab.5). Extended variation ranges of the two parameters indicate differences in maturity and parent material sources.
5 Discussion
5.1 Sources of crude oil
Based on the vitrinite reflectance of kerogen (Tab.1) and maturity biomarker parameters (Fig.8(a) and Fig.8(b)), it is concluded that the source rocks in Wenchang-A Sag are mature and have good hydrocarbon-generating potential (
Xiao et al., 2020). Although the crude oil in the study area is all mature (Fig.8(c)), the oil maturity still varies among different areas and wells in the same area (Fig.8(d)). For example, the crude oil maturity of wells A2 and A3, C1 and C2 are differentiated. According to the theory of hydrocarbon generation evolution (
Hunt, 1979;
Huang et al., 1984), the wax content of oil increases with deepening maturation. Therefore, the discrepancy in the wax content for crude oil in Wenchang-A Sag is believed to be attributed to varying maturity.
The Enping Formation is the main source rock, but the source rocks of different wells of different blocks are wildly varied. Due to organic matter types, crude oil and natural gas characteristics also change. Cross plots of the parameters that can reveal the differences between crude oil and source rocks, such as ∑C27RSt/∑C29RSt, ∑C27DiaS/∑C27RSt, and (W + T)/C30H are drawn (Fig.9). Class I crude oil and Class IV crude oil have a single source. Class I is similar to the source rock distribution in Area C. The data distribution of Class IV crude oil is similar to that of source rock in Well A2, indicating that this type of crude oil comes from source rock in area A. Class II crude oil and Class III crude oil have mixed source characteristics. Class II crude oil is similar to source rocks in D and E areas. The type III crude oil is similar to the source rocks of wells A1 and B1, indicating that the crude oil comes from both the source rocks of Areas A and B.
5.2 Geneses and sources of natural gas
5.2.1 Thermal maturity
Natural gas heptane and isoheptane are important in determining maturity and organic matter types.
Thompson (1983) proposes two empirical curves for determining parent material types, and
Cheng et al. (1987) develop criteria for determining maturity. Group I natural gas is between aliphatic and aromatic, mature natural gas. Group II is close to the aromatic line, most of which are mature natural gas, and some of which are highly mature. Group III has the characteristics of the first two gas groups (Fig.10(a)).
Carbon isotope ratios among different components of natural gas change significantly with maturity, which is commonly used for maturity identification (
James, 1983). Our calculation shows (Fig.10(b)) the carbon isotope ratio is consistent with the theoretical line (
James, 1983;
Wang et al., 2022), yet with scattered distribution (mainly of 0.7%–1.2%). Accordingly, natural gas is attributed to the mature stage. Group III gas data are widely distributed and vary widely in maturity. The inverse distribution of carbon isotope ratios of propane and butanes in group III (Tab.4) can be attributed to the mixing of natural gas with varying maturity in these gasses.
5.2.2 Sources of natural gas
The origins of natural gas can be identified according to the measurements of natural gas composition and carbon isotope ratios (
Wood and Hazra, 2017;
Milkov, 2018). The organic and inorganic gases can be distinguished using the carbon isotope ratios of natural gas components. With the increasing carbon number, the carbon isotope ratios of biogenetic gas grow, while the case of inorganic gas is just the opposite (
Chung et al., 1988;
Dai, 1990;
Tilley et al., 2011). The natural gas features
δ13C
1 <
δ13C
2 <
δ13C
3 <
δ13C
4, with the distribution reversal found between propanes and butanes of some samples (Tab.4). For hydrocarbon gases, the methane carbon isotope ratio of the biogenetic gas is typically below −30‰ (
Whiticar, 1999). To sum up, the hydrocarbon gases of the Wenchang-A Sag are identified as biogenetic gas. And it’s all thermogenic gas (Fig.10(c)).
The light hydrocarbon content depends on the types of organic matter. Specifically, gas from sapropelic organic matter has a relatively higher content of
n-alkanes, while that originating from humic organic matter has a higher content of iso-alkanes and cycloalkanes (
Leythaeuser et al., 1979). Group I of natural gas comes from sapropelic parent material, Group II is humic parent material. Group III is distributed near the boundary, with mixed source characteristics (Fig.10(d)). Comparison with the planar distribution of organic matter types of the source rocks (Fig.3) shows that the parent material types of natural gas are consistent with the organic matter types of the source rocks. In other words, the differentiation of natural gas types across the study area is mainly caused by the variation of organic matter types.
According to hydrocarbon generation theory (
Hunt, 1979;
Huang et al., 1984), humus-like organic matter can generate natural gas through kerogen cracking during the mature stage, and crude oil can also produce natural gas via cracking. To identify cracking types of natural gas in the Wenchang-A Sag, the chart proposed by Prinzhofer and Huc (1995) is adopted (Fig.10(e)). Groups I and II have negative slope change characteristics, i.e., kerogen cracking gas. However, Grope III has horizontal variation characteristics but also longitudinal variation characteristics, mainly crude oil secondary cracking gas and also kerogen cracking gas characteristics.
5.3 Exploration significance
The distribution of oil and gas reservoirs in the Wenchang-A sag is complex due to multiple small sub-sags. Class I crude oil is sporadically distributed in Areas A, B, and C, and comes from source rocks in Area C (Fig.11(a)). Class II crude oil is widely distributed in Area D and less in E and C areas. Crude oil comes from source rocks in Areas D and E (Fig.11(a)). Class III crude oil is mainly distributed in Area B and there is a small amount in Area C. The oil source is the source rocks in Areas A and B. Class IV crude oil distribution area is small, only in Areas A and C, which comes from source rocks in Area A (Fig.11(a)). In summary, the crude oil in the study area is mainly derived from local source rocks. Source rocks in adjacent sub-sags also contribute. In the future, exploration can continue in Areas C and D to find reservoirs.
Natural gas in Groups I and II is derived from local source rocks, and the natural gas in Group III has mixed source characteristics (Fig.11(b)). The type of natural gas is closely related to the type of source rock organic matter. Future gas reservoirs are concentrated in Areas C, D, and E.
6 Conclusions
1) The Enping Formation source rocks of the Wenchang-A Sag have significant differences in different areas. The source rocks throughout the sag have entered the mature stage, with Ro of 0.70%−1.29%. The hydrocarbon generation potential of source rocks in the central sag is higher than that in the sag margin. In terms of organic matter types, the planar distribution shows that Areas A, B, and D have more sapphire-type source rocks, while Areas C and E are found with more humic-type rocks.
2) The reservoirs of Wenchang-A Sag are concentrated in the development zone of the more-sapropelic source rocks and have low-density light oil. The wax content of oil varies greatly due to products of different maturation stages. According to the physical properties and biomarker parameters, crude oil is divided into four classes. Classes I and IV crude oil come from local source rocks. Classes II and III have mixed source characteristics. Class II comes from source rocks in Areas D and E, and class III comes from Areas A and B.
3) The natural gas in the study area is mostly mature. Mixing natural gas with varying maturity results in the reversal distribution of carbon isotope ratios of hydrocarbon gases, which are mainly thermogenic. Group I is sapropelic gas, Group II is humic gas, and Group III has mixed source characteristics. Groups I and II gas are kerogen cracking gas, group III has both crude oil secondary cracking gas and kerogen cracking gas characteristics. The parent material types of natural gas are consistent with the planar distribution of organic matter types of source rocks.
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