Geochemical characteristics and origins of natural gases in the eastern Cote d’Ivoire Basin, West Africa

1. Introduction

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

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.

Figure  1.  Simplified structural map of the Cote d’Ivoire Basin and distributions of the three sampled wells in the basin (a). Stratigraphic table of the major Cretaceous strata in the Cote d’Ivoire Basin (modified from Morrison et al., 2000) (b).

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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

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.

Table  1.  Total organic carbon (TOC, %wt.) content, Rock-Eval pyrolysis and vitrinite reflectance (Ro, %) from source rocks in the eastern Cote d’Ivoire Basin

Well	Formation	TOC/%				S1 + S2 (HC/Rock)				HI (HC/TOC)				Tmax /℃
		Min.	Max.	Average		Min.	Max.	Average		Min.	Max.	Average		Min.	Max.	Average
G-1	Turonian	1.38	2.48	1.92		3.8	21.36	9.01		207	888	453		405	437	433
	Cenomanian	1.63	1.99	1.88		5.72	7.32	6.83		334	369	356		435	438	436
	Albian	0.54	1.24	0.89		0.95	4.96	2.26		144	391	235		432	440	437
L-1	Turonian	1.43	3.08	2.04		6.69	19.1	10.78		441	614	518		426	434	430
	Cenomanian	0.54	2.97	1.42		1.54	18.47	6.91		275	676	444		431	436	434
	Albian	0.51	0.72	0.59		0.37	0.74	0.57		49	111	81		425	443	437
D-1	Turonian	2.29	3.22	2.62		12.14	21.04	15.49		498	674	586		412	422	418
	Cenomanian	1.67	4.06	2.91		7.83	28.94	18.55		442	712	606		417	424	420
	Albian	0.74	1.72	1.25		1.00	6.67	4.02		74	500	228		425	441	435
Note: Ro: vitrinite reflectance; TOC: total organic carbon concentration; S1 = free hydrocarbons yield; S2 = pyrolytic hydrocarbon yield; S1 + S2 = generation potential; HI: hydrogen index = S2 × 100/TOC; Tmax = temperature of maximum generation.

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Table  2.  Molecular component molar ratio (%) and stable carbon isotopic composition (‰, V_PDB) from natural gases in the eastern Cote d’Ivoire Basin

Well	Main molecular composition molar ratio/%					Carbon isotope/‰
	CH4	C2H6	C3H8	C4H10		$ \text{δ}^{13} $C-CH4	$ \text{δ}^{13} $C-C2H6	$ \text{δ}^{13} $C-C3H8
G-1	60.8	17.7	12.4	3.2		−33.5	−27.0	−26.9
	69.1	17.2	9.1	3.4		−33.6	−27.5	−27.8
	68.6	17.9	8.4	3.2		−32.3	−27.3	−27.4
L-1	71.4	15.4	9.7	2.9		−35.0	−29.4	−28.3
	68.8	15.0	10.9	4.0		−33.4	−26.2	−25.0
	76.5	13.2	7.0	2.5		−34.8	−29.8	−27.9
	71.7	17.2	8.0	2.4		−31.7	−29.5	−27.6
	70.7	17.6	8.2	2.5		−31.7	−29.6	−27.8
	71.6	17.5	7.9	2.3		−31.9	−29.7	−28.0
	71.4	17.7	7.9	2.2		−31.0	−29.2	−27.7
	71.7	18.0	7.6	2.0		−31.9	−28.3	−27.7
	75.8	15.5	6.2	1.8		−33.7	−28.7	−27.9
	75.4	15.4	6.7	1.9		−32.2	−26.9	−26.7
	70.7	19.4	7.6	1.8		−31.2	−28.2	−27.3
	76.8	16.6	5.3	1.1		−32.0	−28.4	−27.3
	69.4	21.1	7.5	1.7		−33.2	−29.7	−28.2
	69.7	20.8	7.5	1.6		−31.4	−29.1	−28.1
	70.1	17.0	9.1	3.0		−31.0	−26.3	−26.3
	76.8	15.9	5.8	1.3		−31.9	−28.4	−28.0
	70.6	19.2	8.0	1.8		−29.9	−27.7	−27.6
	75.8	15.6	6.4	1.7		−30.9	−27.2	−26.9
D-1	84.6	7.3	4.3	2.1		−41.8	−29.9	−28.5
	85.0	7.5	3.8	1.9		−41.6	−30.2	−28.5
	85.4	7.4	3.6	1.8		−40.8	−30.1	−28.7
	86.1	7.4	3.5	1.6		−41.5	−30.6	−28.7
	85.4	7.5	3.7	1.8		−41.7	−30.3	−28.9
	77.4	9.7	5.8	3.4		−41.7	−30.8	−29.2

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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 (V_PDB) standard.

4. Results

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 T_max (435–437℃) higher than the Cenomanian-Turonian source rocks (average T_max in 418–436℃). However, the cross-plot of T_max 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.

Figure  2.  Plot of total organic carbon (TOC) versus generated hydrocarbons (S₁ + S₂) showing source rock quality (a). Plot of hydrogen index (HI) versus maximum hydrocarbon generation (T_max) showing kerogen types (refer to Espitalié et al., 1984) (b). HI = S₂/total organic carbon × 100.

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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/ƩC_1-4) 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/ƩC_1-4 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.

Figure  3.  The stable carbon isotopes distribution of gaseous alkanes (methane CH₄, ethane C₂H₆, and propane C₃H₈) in the eastern Cote d’Ivoire Basin.

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5. Discussion

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.

Figure  4.  The origin of natural gas interpretative diagram based on δ¹³C-CH₄, δ¹³C-C₂H₆, and δ¹³C-C₃H₈ data in the eastern Cote d’Ivoire Basin (refer to Dai et al., 2014).

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Figure  5.  The plot of ethane/propane (C₂/C₃) molar ratio versus δ¹³C-C₂H₆−δ¹³C-C₃H₈ (refer to Prinzhofer and Battani, 2003) showing the natural gases of the eastern Cote d’Ivoire Basin are dominated by primary cracking gases.

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Figure  6.  Genetic diagram of δ¹³C-CH₄ versus C₁/(C₂+C₃) showing the genetic type of the natural gases in the eastern Cote d’Ivoire Basin. The boundary lines are from Milkov and Etiope (2018).

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Figure  7.  The plot of δ¹³C-CH₄ and C₁/(C₂+C₃) distinguishing the genetic types of the natural gases in the eastern Cote d’Ivoire Basin. (A: biogenic gas; B: biogenic gas and sub-biogenic gas; C: sub-biogenic gas; D: oil-type gas; E: oil-type cracked gas; F: oil-type cracked gas and coal-derived gas; G: condensate oil-associated gas and coal-derived gas; H: coal-derived gas; I: inorganic gas; J: inorganic gas and coal-derived gas [plot after Dai 1992)].

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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 (VR_eq, δ¹³C₁ = 25.55 × lg VR_eq − 40.76) (Gang et al., 1997) was used to evaluate the maturity of oil-type gases in this study. The caculated VR_eq 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).

Figure  8.  The types and thermal maturity of natural gas classification diagram based on δ¹³C-CH₄ and δ¹³C-C₂H₆ data in the eastern Cote d’Ivoire Basin. The boundary lines are based on Dai (1992), Dai et al. (2005), and Li et al. (2022).

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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.

Figure  9.  Down-hole variation of source rock quality [total organic carbon (TOC), generation potential (S₁ + S₂), and hydrogen index (HI)] from Turonian to Upper Albain in the eastern Cote d’Ivoire Basin (a). Present temperature and maturity fields of the eastern Cote d’Ivoire Basin (modified from Rüpke et al., 2010) (b).

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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.

Figure  10.  Mass chromatograms (m/z 191 and m/z 217) of the Upper Albian source rock and crude oil from Well D-1 (data from preliminary report of Geochemical Solutions International, Inc).

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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

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 (VR_eq) 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.