The hydrocarbon exploration history in the Namibian offshore Basins started in the late 1960s, culminating with the discovery, in 1973, of a dry gas by the Kudu 9A-1 well, in Barremian eolian sandstones (Kudu Field; Fig. 1).
Up to 2012, 16 shallow-water exploration wells have been drilled offshore Namibia, including eight in the Kudu gas field and seven outside the Kudu field area, all of them were reported to be dry oil wells (Fig. 1).
The seven outside the Kudu field area, representing Walvis, Luderitz, and Orange Basins wells, proved the presence of lower and upper Cretaceous turbidite reservoirs but did not recover any active source rocks. In summary, a gas-prone paradigm was established and predominated for almost 54 years, halting any exploration campaigns in the area, until the discovery, in 2012, of a 41o API, marine siliciclastic oil, source by the Aptian/ Barremian marine anoxic (e.g., Kudu source rock system), in the HRT Wingat-1 deep-water well oil, Walvis Bay ((Mello et al, 2013 and 2015).
The oil discovery killed forever the Namibian Gas Prone Paradigm in Namibia and opened a giant oil frontier for exploration.
With the discovery of the Wingat-1 oil, HRT Petroleum, performed proprietary oil extraction procedures in a total of more than 200 reservoir cutting, and core intervals were taken from, reservoir sections, from seven nearshore wells from Walvis, Luderitz and Orange basins. Also, around 30 oil extracts from Albian to Barremian sandstones side wall cores were taken from the Wingat-1 well (Fig. 1). The reservoir samples covered turbidite sandstones, ranging in age, from Turonian to Aptian/ no older than Barremian, that were selected, collected, picked, washed, and carefully extracted and submitted to SARA and examined by high-resolution gas chromatography (GC) and gas chromatography-mass spectrometry (GC-MS). After those screening analyses, the samples that were confirmed to be composed of indigenous oils were submitted to high-resolution metastable reaction monitoring gas chromatography-mass spectrometry (MRM-GC-MS-MS). From those, 50 extracted oil and the Wingat-1 oil samples were selected for advanced geochemical technologies (AGT) analyses (e.g., quantitative diamondoid analyses (QDA), compound-specific isotope analyses of n-alkanes (CSIA-Ac), biomarker (CSIA-Bh) and diamondoids (CSIA-D).
The aim of this newsletter is to discuss the results and interpretation, of GC, GC-MS, and MRM-GC-MS-MS data, of eight of the selected 51 samples, as examples, based on Brazilpetrostudies experience from the analysis of several hundred oils & oil extracts and source rock extracts, recovered from the pre and post-salt sections of the Santos Basins, Offshore Brazil. The idea is to assess their oil type, source rock origin, depositional environment, and degree of thermal maturity and biodegradation, using only some source, oil quality, and maturity biomarker related taken from the GC, GC-MS, and MRM-GC-MS-MS data (Mello et al., 1988, 1995, 2015 and 2021a)
Next week, we will show how proprietary technology based on quantitative diamondoid analyses (QDA), compound-specific isotope analyses of n-alkanes (CSIA-Ac), and biomarker (CSIA-Bh) and diamondoids (CSIA-D) data can, undoubtedly, like no other technologies, confirm the data obtained from GC-MS and MRM-GC-MS, but also, assess source rock age, oil cracking and oil mixing. (Mello et al. 2021a and b; Moldowan et al, 2021).
The results of the analyses performed in selected oil extracts from seven, nearshore wells drilled in Walvis (1911/10-1, 1911/15-1, 2012/13-1, 2213/6-1, and 2213/5-1), Luderitz (e.g., 2513/8-1), and Orange (2815/15-1) basins, and in deep-water side wall cores in the Wingat-1 well, Walvis Bay. All these samples taken as examples representative of the total sample set are reported in figures 1-4. For comparison end-members Albian marine siliciclastic and Barremian lacustrine saline oils from Santos Basin, Brazil was also included. The complete set of sample data is part of the BPS/ Brazil and Namibian Geodata.
Figure 2 illustrates GC and GC-MS data of 2-ANP-2A-RJS (end-member lacustrine saline system), 6-BRSA-661-SPS (end-member marine siliciclastic system), and Wingat-1 (end-member marine siliciclastic system) oils. The plot shows the high-resolution GC for whole oil and the C27 diasteranes (DIA) / tetracyclic polyprenoids (TPP) ratios taken from mass chromatograms of m/z 259. Both are used as oil types, oil quality, source rock systems, maturity, and biodegradation stages indicators (Mello et al, 1995; 2013, 2015 and 2021a and b).
The gas chromatogram profiles (e.g., Fig. 2) of the oils from the 6-BRSA-661-SPS (end-member marine siliciclastic system; Santos Basin), and Wingat-1 (end-member marine siliciclastic system; Walvis Basin) wells are diagnostic examples of the distribution of linear and branched hydrocarbons typical of a marine siliciclastic peak/ late peak thermally mature stage, not biodegraded oils (Mello et al, 1988). On the other hand, the oil from the 2-ANP-2-RJS well, is an example of a bimodal distribution of linear and branched hydrocarbons typical of a lacustrine saline peak/ late peak thermally mature stage, biodegraded oils (Mello et al, 2021a and b).
The presence of B-carotane in the GC’s traces of the oil (not showing in the GC, is a diagnostic compound of lacustrine algae that occur in the Southern South Atlantic Basins (Mello et al, 1988 and 1993 and 2021b). Important to mention is the bimodal aspect of the gas chromatogram of 2-ANP-2A-RJS oil, indicating the presence of low biodegradation in the oil today. The presence of bimodal GC fingerprint together with 17-norhopanes (e.g., m/z 177; not showing here) indicates a mixture of severe paleo biodegraded oils from first migration charges with fresher non-biodegraded oil charged from the most recent migration events to the mid to late Aptian microbiolites reservoirs. Today, the oil is not biodegraded. In summary, oil quality is directly controlled by the proportion of fresher oil (non-biodegraded) that was contributed by the most recent oil charge in the reservoir (Fig. 2; Mello et al., 2021).
Figure 3 illustrates the plot diagram of biomarker hopane/ sterane and C27 diasteranes (DIA) / tetracyclic polyprenoids (TPP) ratios taken from mass chromatograms of m/z-191 (hopanes), m/z 217 (steranes), and m/z 259 (diasteranes and TPP) have been used successfully for characterizing and differentiating lacustrine and marine oils and their putative source rock systems in the offshore Southern Brazilian Marginal basins (Mello et al., 1988, 1995 and 2021a). When compared with those samples, the oils extracted data indicate the presence of two active petroleum systems: an end-member Albian-Aptian-Barremian (?), marine siliciclastic oil type system present in the 6-BRSA-661-SPS oil from Santos Basin, Brazil, all the seven nearshore wells drilled in Walvis (1911/10-1, 1911/15-1, 2012/13-1, 2213/6-1, and 2213/5-1), Luderitz (e.g., 2513/8-1), and Orange (2815/15-1) basins, and two oils (DST and SWC) recovered from the deep-water Wingat-1 well, Walvis Bay, Namibia); and an end-member upper Barremian, lacustrine saline oil type system present in the 2-ANP-2A-RJS oil from Santos Basin, Brazil.
The oils classified in Figures 2–4, as marine type were sourced by Albo-Aptian, marine anoxic black shales source rock system, based on all GC-MS and MRM-GC-MS-MS biomarker feature, among others, show: low hopane/sterane (<4), C27/ C29 steranes (< 1.3) and gammacerane/ hopane ratios (< 0.13), associated with very high C27 diasterane over TPP (> 1), and positive of C30 regular/total of regular steranes ratios. The presence of C30 sterane compounds, considered to be a marine algal biomarker, confirms the marine siliciclastic depositional environment for its putative source rocks (e.g., Figs. 2–4; see petroleum systems of Santos Basin in Mello et al., 1988 and 1995). By contrast, the oils classified as lacustrine saline oil type (2-ANP-2a-RJS oil), were sourced by Aptian-Barremian, euxinic, lacustrine saline black shales source rock system (Mello et al, 2021a and b). The most important biomarker characteristics of the lacustrine saline systems are higher gammacerane/ hopane (> 0.13), hopanes/steranes (> 4), and C29/ C27-steranes ratios (> 1.5), very high diasterane over TPP compounds (<1), the relative abundance of dinosteranes, and absence of the marine biomarker C30 regular steranes. Such distribution suggested the absence of lacustrine oil types in all the oil samples analyzed from Namibia. By contrast, all the marine siliciclastic oils analyzed from Namibia, are like the Albian marine siliciclastic oil from the post-salt Maastrichtian turbidite sandstone reservoir from the 6-BRSA-661-SPS well, of Santos Basin (e.g., Figs. 2-4; see petroleum systems of Santos Basin in Mello et al., 1988, 1995 and 2021).
Regarding thermal maturity, based on the biomarker maturity parameters (GC profile, C29-steranes 20S/20S+R and TS/Ts + Tm ratios) both the marine siliciclastic oils recovered, in the wells Wingat-1, 6-BRSA-661-SPS and 2-ANP-2A-RJS are at peak/ late peak of maturity stage oil generation (e.g., data not showing here), whereas the seven extract oils from the nearshore wells drilled in Walvis (1911/10-1, 1911/15-1, 2012/13-1, 2213/6-1, and 2213/5-1), Luderitz (e.g., 2513/8-1), and Orange (2815/15-1) basins, and one extract oil (SWC) recovered from the deep-water Wingat-1 well, Walvis Bay, Namibia, are suggested to be at mature to peak mature stage oil generation (e.g., data not showing here). The Gas Chromatogram (GC) profiles of the oil extracts confirm such a conclusion (Mello et al, 1988, 1995); see figure 2).
To confirm such conclusions about the source type and age, depositional environment, oil quality, oil cracking and oil mixtures, proprietary technology based on quantitative diamondoid analyses (QDA), compound-specific isotope analyses of n-alkanes (CSIA-Ac) and biomarker (CSIA-Bh) and diamondoids (CSIA-D), performed in the oil extracts mentioned in this study will be discussed next week in the BPS Newsletter (Mello et al.,2021).
The GC, GC-MS and MRM-GC-MS data suggested that similar marine siliciclastic petroleum systems are found between the Namibian Walvis, Luderitz and Orange basins and Santos’s Basin across the Southern Atlantic Ocean. The only problem is the age constraint of those source rock systems, being Albian in Brazil and Aptian -Barremian, in Namibia. Also, the presence of the marine siliciclastic mature oils in all the eight wells studied here, suggests the possibility, of the presence of a prolific Aptian-Barremian, overcharged, marine siliciclastic source rock system (upper Kudu SR system), in the entire deep-water real of Walvis Bay, Luderitz and Orange basins. Such a possibility was confirmed by the latest discoveries of giant oil accumulations in the deep-offshore, Orange Basin (e.g., Venus, Graff, Rona and Jonker light oil accumulations.
Marcio Rocha Mello, PhD
A petroleum geologist with a Ph.D. in Petroleum Geochemistry from Bristol University, Marcio is president of Brazil Petrostudies (BPS), one of the most advanced E&P service and consultancy companies in Brazil. With over 45 years of experience, Marcio started his career at Petrobras, where he founded the First Center of Excellence, considered one of the world’s top petroleum geochemistry laboratories. In 2004, Marcio founded HRT Petroleum, today PRIO, eventually leading one of Brazil’s largest-ever IPOs. He has published more than 300 papers and led petroleum systems studies of most sedimentary basins of Brazil, West Africa, and Latin America.