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Geochemical characteristics and origins of natural gases in the eastern Cote d’Ivoire Basin, West Africa
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Li Li1, 2, *, Quan Li1, Tao Cheng1, Songling Yang1, Yong Rao1, Xinyu Liu1, Wenjing Ding2, 3
Acta Oceanologica Sinica | 2024, 43(8) : 26 - 36
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Acta Oceanologica Sinica | 2024, 43(8): 26-36
• Marine Geology •
Geochemical characteristics and origins of natural gases in the eastern Cote d’Ivoire Basin, West Africa
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Li Li1, 2, *, Quan Li1, Tao Cheng1, Songling Yang1, Yong Rao1, Xinyu Liu1, Wenjing Ding2, 3
Affiliations
  • 1 CNOOC International Ltd., Beijing 100028, China
  • 2 School of Natural Sciences, Macquarie University, Sydney, NSW, 2109, Australia
  • 3 CNOOC Research Institute, Beijing 100028, China
Published: 2024-08-25 doi: 10.1007/s13131-024-2335-6
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The gas sources in the eastern Cote d’Ivoire Basin (Tano Basin) are seldom reported and remain controversial due to multiple sets of potential source rocks and poorly documented geochemical characteristics of natural gases. The marine source rock potential from the Upper Albian to Turonian as well as the molecular composition and the stable carbon isotope composition of natural gases in the eastern Cote d’Ivoire Basin were studied in detail to investigate the origins of natural gases. The total organic carbon (TOC), hydrogen index (HI), and generation potential (S1 + S2) of source rocks indicate that both sapropelic source rocks and humic source rocks developed during the late Albian, whereas sapropelic source rocks developed during the Cenomanian and the Turonian. The normal order of δ13CH4 < δ13C2H6 < δ13C3H8 (δ13C1 < δ13C2 < δ13C3), the relationship between C2/C3 molar ratio and δ13C2-δ13C3, and the plot of δ13C1 versus C1/(C2+C3) collectively show that the natural gases are thermogenic due to the primary cracking of kerogen, including the typical oil-associated gases from Well D-1, the mixed oil-associated gases and coal-derived gases from Well G-1 and Well L-1. Based on the plot of δ13C1 versus δ13C2 and the established relationship between δ13C1 and equivalent vitrinite reflectance (Ro), we proposed that the natural gases are in a mature stage (Ro generally varies from 1.0% to 1.3%). Combined with results of basin modelling and oil-to-source correlation, the transitional to marine source rocks during the late Albian were thought to have made a great contribution to the natural gases. Our study will make a better understanding on petroleum system in the eastern Cote d’Ivoire Basin.

marine source rocks potential  /  molecular composition  /  stable carbon isotopes  /  Upper Albian  /  Tano Basin
Li Li, Quan Li, Tao Cheng, Songling Yang, Yong Rao, Xinyu Liu, Wenjing Ding. Geochemical characteristics and origins of natural gases in the eastern Cote d’Ivoire Basin, West Africa[J]. Acta Oceanologica Sinica, 2024 , 43 (8) : 26 -36 . DOI: 10.1007/s13131-024-2335-6
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1 Introduction
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The hydrocarbon exploration in the Cote d’Ivoire Basin began in the late 19th century, and a total of 81 discoveries that range from non-commercial to large have been made in this basin (Lake et al., 2014; Bempong et al., 2019). In the early stages of exploration, the use of seismic data resulted in some non-commercial discoveries. After 2000, the exploration shifted to deep water. The major commercial oil discovery in the mahogany prospect of the West Cape Three Points License formed the Jubilee field with 916 MMboe of recoverable reserves, resulting in the first exploration boom in the Basin (Bempong et al., 2019). In the past five years, the commercial discoveries of the Afina field in 2019 (354 MMboe of recoverable reserves), the Eban field in 2021 (117 MMboe of recoverable reserves), and the Baleine field in 2021 (780 MMboe of recoverable reserves) have set off another oil and gas exploration boom.
As a whole, it still has great petroleum exploration potential in terms of highly prospective discovered reserves (Morrison et al., 2000; Bird et al., 2001; Rüpke et al., 2010; Dailly et al., 2013; Davison et al., 2016; Tetteh, 2016; Bempong et al., 2019). The eastern Cote d’Ivoire Basin, also known as the Tano Basin, is recognized as the eastern extension of Cote d’Ivoire and Ghana (Bempong et al., 2019). It covers an area of about 3 000 km2 and occupies largely offshore and less onshore segments in the southwestern part of Ghana. In recent years, several new-field wildcat wells, including Well D-1, Well L-1, and Well G-1, were drilled and encountered significant thickness of gas and condensate sands, confirming its rich natural gas resources. Source rocks of the Cote d’Ivoire Basin are restricted to Cretaceous age (Strand, 1998; Bird et al., 2001). However, the properties of lacustrine source rocks spanning through the Aptian to Lower Albian are largely unavailable and unknown due to their large burial depths. The marine source rocks from the Upper Albian to Turonian have been penetrated suggesting rich oil-prone source potential (Atta-Peters and Garrey, 2014; Atta-Peters et al., 2015; Garry et al., 2016; Bempong et al., 2019). As important source rock interval, the Albian series were deposited in environments grading from lacustrine to marine, allowing the preservation of both oil-prone source rocks and gas-prone source rocks (Chierici, 1996; Benkhelil et al., 1998; Lake et al., 2014). The gas source is seldomly reported and remains controversial due to multiple sets of potential source rocks and the poorly investigated geochemical characteristics of natural gases. This will hinder the understanding on formation and accumulation of natural gases in the eastern Cote d’Ivoire Basin.
In natural gas geochemistry, molecular and stable carbon isotope compositions of gaseous alkanes contain ample information on geologic backgrounds (organic source, sedimentary environment) and geochemical processes during hydrocarbon generation. In order to assessing natural gas resource potential and finding favorable areas for exploration, many researchers have established numerous parameters and classic diagrams to shed insights into deciphering the formation of natural gases (Berner et al., 1992; Dai, 1992; Prinzhofer and Battani, 2003; Dai et al., 2005, 2016; Milkov and Etiope, 2018; Milkov, 2018; Li et al., 2022). The correlation between chemical compositions and isotopes are regarded as important diagnostic tools for assessment of its sources and exploration potential.
In this study, cores and natural gases from three wells (Well D-1, Well L-1, and Well G-1) were sampled and analyzed to investigate their geochemical characteristics and gas-source correlation. The source rock potential was discussed based on the analyses of the total organic content and Rock-Eval pyrolysis. The genetic types and thermal maturity of natural gases were revealed by their characteristics of molecular components and stable carbon isotope compositions. This study will be beneficial for better understanding on the main source of natural gases and it will be a guide to the future natural gas exploration in the eastern Cote d’Ivoire Basin.
2 Geological setting
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The eastern Cote d’Ivoire Basin, also known as the Tano Basin, is an east-west orientated sedimentary basin. It is located on the south coast of Ghana and extends to the southeast coast of Cote d’Ivoire (Fig. 1). It is a typical transform margin basin that is bounded respectively by the Saint Paul Fracture Zone to the east and the Romanche Fracture Zone to the west. This basin has undergone a complex tectonic history and formed as a result of the break-up of Gondwanaland (Mascle and Blarez, 1987; Blarez and Mascle, 1988; Basile et al., 1993, 1998; Clift et al., 1997; Lake et al., 2014; Ye et al., 2019). This basin began rifting in the Aptian (or the Barremian), resulting in the deposition of lacustrine sediments. With the south Atlantic opened from south to north, the continental separation and the rift-to-drift transition probably occurred during the late Albian to Cenomanian, resulting in the development of the lacustrine sequence overlain by the restricted-marine and the subsequent open-marine sequences (Chierici, 1996; Lake et al., 2014; Ye et al., 2019). A series of the early Cretaceous pull-apart depocenters is bounded by extensional faults associated with the Saint Paul Transform Fault to the northwest. These depocenters are subdivided by large transpressional arches associated with the Romanche transform movement to the southeast.
The early source rocks are organic-rich lacustrine sediments that developed within the Aptian-early Albian. The distribution of the lacustrine source rocks was influenced strongly by rift tectonic activity (Antobreh et al., 2009). Then, the separation of Africa from South America that started from the Late Albian caused the development of the transitional-to-marine source rocks. It is proposed that the formation of organic-rich marine source rocks is greatly influenced by marine transgression and global oceanic anoxic events (Wagner, 2002; Lake et al., 2014). Based on oil geochemistry and source rocks maturity data, it is suggested that the Albian and Cenomanian-Turonian series contain the main source rocks in this basin (Morrison et al., 2000; Rüpke et al., 2010; Lake et al., 2014). Abundant hydrocarbons, discovered varying in age from the Albian to Campanian, have proved the resource potential both in the Lower and Upper Cretaceous clastic reservoirs (Bird et al., 2001; Brownfield and Charpentier, 2006; Dailly et al., 2013; Davison et al., 2016).
3 Samples and methods
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Emphasis is given to the Albian-Turonian source rock samples, because the younger shales are generally in immature thermal stage, even within basinal depocentres. Source rocks potential analyses [total organic carbon (TOC, %wt.), Rock-Eval pyrolysis], molecular composition analysis and stable carbon isotope composition analysis of natural gases were carried out. The locations of the three sampled wells (Well G-1, Well L-1, and Well D-1) in the eastern Cote d’Ivoire Basin are present in Figure 1. The results of the analyses are shown in Table 1 and Table 2.
Before analysis for TOC and Rock-Eval pyrolysis, a total of 230 isojar cuttings samples from the Upper Albian-Turonian of three wells were extracted sequentially with dichloromethane to remove contaminants from the drill cuttings. Then these cuttings were crushed to a size of $ \leqslant $0.075 mm. Around 70 mg of each powdered sample were pre-treated with concentrated HCl and rinsed with deionized water for more than 50 times, then analysed for TOC analysis using a Leco elemental analyser. About 50 mg of each powdered samples were analysed for Rock-Eval analysis using a Delsi Rock-Eval RE Ⅱ instrument (Espitalié et al., 1984). An external standard was used every ten samples to ensure the quality of the TOC analysis and Rock-Eval pyrolysis analysis.
A total of 27 headspace gas (isojar) samples from the Upper Albian reservoirs of three wells were collected for both gas component analysis and stable carbon isotope component analysis by standard methods in Hill et al. (2007). Gas component of C1–C5 was analyzed in triplicate using a Hewlett Packard 6890 series gas chromatogragh equipped with a flame ionization detector. Stable carbon isotopes of C1–C3 was measured by a Micromass Optima mass spectrometer interfaced with a Hewlett Packard 6890 series gas chromatogragh. The stable carbon isotopic values are within the precision of ±0.3‰ and subject to the Vienna PeeDee Belemnite (VPDB) standard.
4 Results
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4.1 Source rocks potential
There appears to be a decrease in source potential towards the Upper Albian in the locations of three sampled wells. The values of TOC and S1 + S2 of source rocks from the Cenomanian-Turonian is generally higher than that from the Albian (Table 1, Fig. 2a): (1) For the Upper Albian source rocks: Well G-1, TOC average 0.89%; S1 + S2 average 2.26 mg/g; Well L-1, TOC average 0.59%; S1 + S2 average 0.57 mg/g; Well D-1, TOC average 1.25%; S1 + S2 average 4.02 mg/g. (2) For the Cenomanian source rocks: Well G-1, TOC average 1.88%; S1 + S2 average 6.83 mg/g (HC/Rock); Well L-1, TOC average 1.42%; S1 + S2 average 6.91 mg/g (HC/Rock); Well D-1, TOC average 2.91%; S1 + S2 average 18.55 mg/g (HC/Rock). For the Turonian source rocks: Well G-1, TOC average 1.92%; S1 + S2 average 9.01 mg/g (HC/Rock); Well L-1, TOC average 2.04%; S1 + S2 average 10.78 mg/g (HC/Rock); Well D-1, TOC average 2.62%; S1 + S2 average 15.49 mg/g (HC/Rock). Therefore, the TOC together with the S1 + S2 reflect a higher hydrocarbon generation potential of the Cenomanian-Turonian source rocks (Fig. 2a) than the Upper Albian source rocks. The Upper Albian source rocks generally have lower hydrogen index (HI) values (average 235 mg/g (HC/TOC) from Well G-1, average 81 mg/g (HC/TOC) from Well L-1, and average 228 mg/g (HC/TOC) from Well D-1) than the Cenomanian-Turonian source rocks. This is likely influenced by the higher thermal maturity of the Upper Albian source rocks, with their average Tmax (435–437℃) higher than the Cenomanian-Turonian source rocks (average Tmax in 418–436℃). However, the cross-plot of Tmax versus HI indicates a dominant type Ⅲ–Ⅱ2 kerogens in the Upper Albian samples and a dominant type Ⅱ2–Ⅱ1 kerogens in the Cenomanian-Turonian samples (Fig. 2b). This implies a predominantly terrigenous contribution to the Upper Albian organic matter. Thus, the Upper Albian source rocks are characterised by more gas-prone compared to the Cenomanian-Turonian source rocks.
4.2 Molecular and stable carbon isotope compositions of natural gases
The main molecular composition and stable carbon isotope composition of the natural gases from the Upper Albian sandstone reservoirs in the eastern Cote d’Ivoire are presented in Table 2.
Among all the measured hydrocarbon gases, methane (C1) contents vary from 60.8% to 86.1% (average 74.3%), ethane (C2) contents vary from 7.3% to 21.1% (average 15.1%), and propane (C3) contents vary from 3.5% to 12.4% (average 7.1%), butane (C4) contents vary from 1.05% to 4.04% (average 2.3%). Natural gas dryness C1/(C2+C3) of the samples ranges from 2.02 to 7.92 with an average of 3.84%. The drying coefficient (C1/ƩC1-4) of the samples is between 0.65 and 0.87 (average 0.75). C1 contents of the samples of Well D-1 (77.4%–86.1%) are higher than that of the other two wells (0.61–0.77), resulting in their higher C1/(C2+C3) ratios and C1/ƩC1-4 ratios.
The stable carbon isotopes of the natural gases appear in a positive order (δ13C1 < δ13C2 < δ13C3) (Fig. 3). The δ13C1 values are the highest among the gas composition, ranging from −41.8‰ to −29.9‰, with an average value of −34.3‰. The δ13C1 values of the natural gases from Well D-1 are higher than that from the other two wells. The δ13C2 and δ13C3 values vary from −30.8‰ to −26.2‰ (average −28.7‰), and from −29.2‰ to −25.0‰ (average 27.7‰), respectively.
5 Discussion
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5.1 Genetic types of natural gases
Based on two distinct generation mechanisms, natural gases can be divided into inorganic gases and organic gases (Dai, 1992). The latter can further be divided into biogenic, mixed genetic, and thermogenic gases according to their different formation processes. The molecular composition characteristics and stable carbon isotope values of gaseous alkanes in natural gases can be used for genetic type classification of organic gases (Dai et al., 1987; Berner et al., 1992; Dai, 1992; Prinzhofer and Huc, 1995; Dai et al., 2016; Faramawy et al., 2016; Milkov and Etiope, 2018). Inorganic gases are generally characterised by negative carbon isotope series (i.e., δ13C1 > δ13C2 > δ13C3 > δ13C4), and δ13C1 values are high (generally between −30‰ and −10‰). By contrast, organic gases generally have positive carbon isotope series (i.e., δ13C1 < δ13C2 < δ13C3 < δ13C4), whereas reversed trends are caused by different mixing processes of different gentic types and thermal maturity of organic gases (Dai, 1992; Dai et al., 2008). The dryness [C1/(C2+C3) ratio] of biogenic gases is commonly higher than that of thermogenic gases, and they have lower δ13C1 values (generally < 55‰) (Bernard et al., 1976; Faber and Stahl, 1984; Whiticar and Suess, 1990; Milkov and Etiope, 2018). Thermogenic gases are classified into sapropelic-type (or oil-type) and humic-type (or coal-derived) gases. Since thermal maturity has limited impact on δ13C2 of parent gas source rocks, δ13C2 value of thermogenic gases has been widely used to distinguish oil-type and coal-derived gases (Dai, 1992; Berner and Faber, 1996; Dai et al., 2005; Li et al., 2022; Huang et al., 2015; Wang et al., 2015). The δ13C2 value of −27‰ and −29‰ can be used as the boundary of the coal-type and oil-derived gases (Dai et al., 2005; Li et al., 2022). Specially, oil-type gases generally have lower δ13C2 values (commonly δ13C2 < −29‰) than coal-derived (commonly δ13C2 > −27‰), and δ13C2 values between −29‰ and −27‰ often reflect a mixture of these two types of gases. However, some studies also proposed that the δ13C2 threshold may not be reliable when identifying genetic types of thermogenic gases if these gases originate from multiple sets of source rocks or are influenced by microbial oxidation and diffusive fractionation (Dai, 1992; Prinzhofer and Huc, 1995; Prinzhofer and Pernaton, 1997; Dai et al., 2016). Therefore, when using carbon isotope compositions to identify the genesis of natural gases, it is necessary to consider the existence of different mixing processes.
In this study, several cross-plots of molecular composition and stable carbon isotopes of natural gases were used to identify the genetic types of natural gases in the eastern Cote d’Ivoire Basin. The normal order of δ13C1 < δ13C2 < δ13C3 and the δ13C1 values of greater than −55‰ reflect that the natural gases are organic origin (Table 2; Fig. 3). Various gas origins including oil-type gases, coal-derived gases, and a mixture of oil- and coal-derived gases were observed in the discrimination graph of δ13C1-δ13C2-δ13C3 (Fig. 4) (Dai, 1992; Dai et al., 2014). The relationship between C2/C3 molar ratio and δ13C2-δ13C3 shows that the natural gases are derived from the primary cracking of kerogen, with limited variance of C2/C3 molar ratio (1.38–3.11, average 2.15) (Fig. 5) (Prinzhofer et al., 2000; Prinzhofer and Battani, 2003). In the revised “Bernard plot” [plot of δ13C1 versus C1/(C2+C3)] (Milkov, 2018) (Fig. 6), all gas samples are distributed in the area of thermogenic gas and in the junction areas of abiotic gas, far away from the primary microbial area. Different relationships of δ13C1 versus C1/(C2+C3) between thermogenic and biogenic gases were observed by Dai (1992). The gas samples fall in the thermogenic gas area, with the low C1/(C2+C3) ratios of less than 50 (Fig. 7). Therefore, the natural gases are all thermogenic and not subjected to microbial oxidation processes. Compared to the typical oil-associated gas samples from Well D-1, the mixed oil-associated gases and coal-derived gases of Well G-1 and Well L-1 were indicated by the higher δ13C1 values (Fig. 7). Some gas samples of Well L-1 plot in the coal-derived gas zone. To conclude, combined with the cross-plots mentioned above (Figs 4, 5, 6 and 7), these natural gases from the primary cracking of kerogen were classified into two groups: oil-type gases from Well D-1; a mixed oil-type gases and coal-derived gases from Well G-1 and Well L-1.
5.2 Thermal maturity of natural gases
Although stable carbon isotopes of natural gases are generally inherited from kerogens, they are also influenced by thermal maturity in various degrees and will become heavier with increasing thermal maturity (Berner et al., 1992; Rooney et al., 1995; Berner and Faber, 1996; Su et al., 2018). Compared to δ13C2, thermal evolution has a greater influence on δ13C1 (Dai, 1992). δ13C1 values of oil-type gases that are derived from sapropelic organic matter exhibit a greater control on thermal maturity than organic sources. Synthesizing genetic type and thermal evolution, the thermal maturity evaluation of natural gas using the plot of δ13C1 versus δ13C2 was established by Li et al. (2022). In Fig. 8, the typical oil-type gases of Well D-1 and some mixed-type gases of Well G-1 and Well L-1 are in a thermally mature stage, with Ro values of less than 1.3%. In addition, the relationship between natural gas δ13C1 and equivalent vitrinite reflectance (VReq, δ13C1 = 25.55 × lg VReq − 40.76) (Gang et al., 1997) was used to evaluate the maturity of oil-type gases in this study. The caculated VReq is between 0.96% and 1.0%. The other gas samples (δ13C2 values less than −29‰) of Well L-1 and Well G-1 fall in a range of highly mature stage of sapropelic-type gas. This is inconsistent with no gas samples falling into the area of secondary cracking of oil and gas samples as indicated by Fig. 5, as well as their low dryness (0.65–0.77). In view of that δ13C1 values of coal-derived gases are usually 7‰ to 8‰ higher than that of oil-type gases at the same thermal maturity stage (Dai et al., 1987; Dai et al., 2005), we propose that the gases of Well G-1 and Well L-1 falling in the high maturity zone is attributed to the notably higher δ13C1 values, which is caused by the mixing of coal-derived gases and oil-associated gases in a mature stage (Ro generally varies from 1.0% to 1.3%) (Wu et al., 2020).
5.3 Origins of natural gases
The natural gases of three wells in the eastern Cote d’Ivoire Basin are mainly distributed in the Upper Albian sandstone reservoirs of delta facies. According to our studies on natural gas components and stable carbon isotopes, these gases were generated from the primary cracking of gas-prone and oil-prone kerogen, with Ro less than 1.3%. Combined with the types and thermal maturity of organic matter, we suggest that the transitional-to-marine source rocks during the Late Albian are the most likely hydrocarbon sources of the gas reservoirs.
Firstly, both sapropelic source rocks and humic source rocks developed during the late Albian. In the earliest stage of the Cretaceous separation of African and South American plates, restricted connection to the ocean and continuous marine transgression resulted in the continuous expansion of the restricted marine environment as well as the fining-upward deltaic sequence in nearshore zone (Pletsch et al., 2001). This can be also substantiated by the quality variation of the Upper Albain source rocks from the studied three wells: humic source rocks in delta facies mainly developed in the deep strata of the Upper Albian making them favourable for coal-derived gas generation, then sapropelic source rocks in lagoon facies with higher hydrocarbon generation potential developed in a wider range in the shallower strata (Fig. 9a). Therefore, the natural gases generated from the Upper Albian source rocks have the origins of both coal-derived and oil-type sources.
Secondly, basin modelling of the eastern Cote d’Ivoire Basin has been performed in previous research (Rüpke et al., 2010), indicating that the Upper Albian source rocks with moderate maturity (Ro less than 1.3%) were deposited in majority of the study area (Fig. 9b). Therefore, the oil-prone source rocks in the shallow strata are capable of generating oils. Several crude oil samples from Upper Albian reservoirs have been analyzed for oil-to-source correlation in the study area (report “Geochemical Solutions International, Inc. 2010. petroleum geochemistry of Vanco D-1 oil offshore Ghana”; report “Geochemical Solutions International, Inc. 2014. geochemical characterization of mud and headspace gas, sidewall core, cuttings, drilling mud and crude oil samples from Well L-1, Cape Three Points Deep Water Block Ghana”). These reports proposed a dominant contribution from lacustrine source rocks, but the lacustrine hydrocarbon supply horizon is unclear due to lack of samples and the corresponding geochemical data. In this study, we suggest a contribution from marine source rocks of the Upper Albian according to the similar biomarker characteristics between oils and mudstones of the Upper Albain (Fig. 10). Evidence includes abundant C30 24-n-propyl steranes (marine precursors), the absence of oleanane, sterane/hopane ratio (oil: 0.31, mudstone: 0.34), gammacerane/hopane (oil: 0.15, mudstone: 0.14), C35/C34 hopane (oil: 0.64, mudstone: 0.69), and similar maturity parameter values (e.g. Ts/Tm, αββ/(ααα + αββ) C29 sterane, and 20S/(20S + 20R) C29 ααα-sterane). Combined with the down-hole variation of source rock quality (Fig. 9a), it is likely that the oil-type gases with moderate maturity of Well D-1 originates from the nearby oil-prone source rocks in the shallow layer of the Upper Albian.
For the mixed oil-type gases and coal-derived gases from Well G-1 and Well L-1, we propose that the in situ thick humic source rocks made a major contribution to the coal-derived gases. A small amount of oil-type gases might be derived from the nearby or downdip sapropelic source rocks of the Upper Albian. In addition, the oil-type gases likely escaped from a deeper oil pool and later mixed with the coal-derived gases in the Upper reservoirs.
6 Conclusions
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The source rocks potential as well as molecular composition and stable carbon isotope composition of natural gases have been comparatively studied. Based on the data from total organic content and Rock-Eval pyrolysis, both sapropelic source rocks and humic source rocks developed during the late Albian. The normal order of δ13C1 < δ13C2 < δ13C3 and several cross-plots based on molecular composition and stable carbon isotopes (i.e. the plot based on δ13C1, δ13C2, and δ13C3; the plot of (C2/C3) molar ratio versus δ13C6-δ13C3; the plot of δ13C1 versus C1/(C2+C3)) show that the natural gases in the eastern Cote d’Ivoire Basin originate from the primary cracking of kerogen. Natural gas samples were divided into two groups: oil-type gases from Well D-1; a mixed oil- type gases and coal-derived gases from Well G-1 and Well L-1. The plot of δ13C1 versus δ13C2 and the equivalent vitrinite reflectance (VReq) indicate that the gases are in a mature stage (Ro generally varies from 1.0% to 1.3%). Combined with the types and thermal maturity of organic matter, basin modelling, and oil-source correlation, we suggest that the transitional-to-marine source rocks during the late Albian made a great contribution to the coal-derived gases and oil-type gases.
Funding
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  • The Major Science and Technology Project of CNOOC under contract No. KJGG2022-0902; the National Natural Science Foundation of China under contract Nos 42202184 and 42272177.
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doi: 10.1007/s13131-024-2335-6
  • Receive Date：2023-07-23
  • Online Date：2025-11-19
  • Published：2024-08-25
Article Data
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  • Received：2023-07-23
  • Accepted：2023-12-05
Funding
The Major Science and Technology Project of CNOOC under contract No. KJGG2022-0902; the National Natural Science Foundation of China under contract Nos 42202184 and 42272177.
Affiliations
    1 CNOOC International Ltd., Beijing 100028, China
    2 School of Natural Sciences, Macquarie University, Sydney, NSW, 2109, Australia
    3 CNOOC Research Institute, Beijing 100028, China

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* Li Li, E-mail:
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表12种不同金属材料的力学参数
科
Family		 属数
Number of
genus		 种数
Number of
species		 占总种数比例
Percentage of
total species (%)		 属
Genus		 种数
Number of
species		 占总种数比例
Percentage of total
species (%)
鹅膏菌科Amanitaceae 2 11 5.26 鹅膏菌属 Amanita 10 4.78
小菇科 Mycenaceae 2 12 5.74 丝盖伞属 Inocybe 5 2.39
多孔菌科 Polyporaceae 8 14 6.70 蜡蘑属 Laccaria 5 2.39
红菇科 Russulaceae 3 23 11.00 小皮伞属 Marasmius 6 2.87
小菇属 Mycena 11 5.26
光柄菇属 Pluteus 5 2.39
红菇属 Russula 17 8.13
栓菌属 Trametes 5 2.39
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