The Namibian and Brazilian southern South Atlantic ... · The Namibian and Brazilian southern South Atlantic petroleum systems: ... Congo and Gabon in Africa) are characterized by

The Namibian and Brazilian southern South Atlantic petroleum

systems: are they comparable analogues?

MARCIO ROCHA MELLO1*, NILO C. DE AZAMBUJA FILHO1, ANDRE A. BENDER1,

SILVANA MARIA BARBANTI2, WEBSTER MOHRIAK1, PRISCILA SCHMITT1 &

CARLOS LUCIANO C. DE JESUS1

1HRT Oil & Gas, Avenida Atlantica 1130, 7th Floor, Copacabana, Rio de Janeiro, Brazil2Integrated Petroleum Expertise Company (IPEX), Rua Dezenove de Fevereiro,

69/71 Botafogo, Rio de Janeiro, Brazil

*Corresponding author (e-mail: [email protected])

Abstract: Tectonic reconstructions made across the southern South Atlantic Ocean indicate adiversity of rift and drift basin characteristics on the conjugate margins that define them as differentstratigraphic and structural entities., In terms of petroleum systems, the basins are not as unlike assome characteristics suggest. Given the lack of significant hydrocarbon discoveries to date south ofthe Walvis Ridge, doubts have been cast on the presence in this area of the prolific Lower Cretac-eous lacustrine and marine source rock systems, which are well known in the Greater CamposBasin and offshore Angola. Oils and condensates from the basins south and north of the WalvisRidge exhibit geochemical similarities suggesting that comparable source rock systems arepresent in both areas. The condensate geochemical analysis results from the Kudu Field inNamibia are compared with oils from marine and lacustrine sources in Brazil, indicating thatthe Kudu condensates are derived from at least two different source rocks. These results suggestthat the underexplored basins offshore Namibia contain thermally mature Lower Cretaceous lacus-trine and marine source rocks, offering a new frontier for petroleum exploration in Africa’ssouthern South Atlantic.

The geological similarities of the sedimentarybasins in the South Atlantic go back to the Mesozoicwhen Africa and South America were connectedand started to undergo extension to form a seriesof Late Jurassic–Early Cretaceous rift basins(Tankard et al. 1995). Several workers havesuggested that the West African margin riftingresulted in three discrete lacustrine phases, eachphase having its own particular deformation styleranging from Neocomian to Early Aptian (Briceet al. 1982; Mello et al. 1990b, 1991; Katz & Mello2000). There is evidence that lacustrine sourcerocks, responsible for 90% of the oil produced inBrazil and Angola (Mello et al. 1991; Schiefelbeinet al. 1999; Katz & Mello 2000) were depositedbetween approximately 130 and 115 Ma, when theSouth Atlantic palaeodepositional conditions werealmost the same in the conjugate margin basins(Coward et al. 1999; Seranne & Anka 2005).

The rift phases are represented by prolific sourcerock systems, ranging from lacustrine freshwaterto saline sag basin and culminating with deposi-tion in a shallow transitional marine environment(Cainelli & Mohriak 1999). Most of these rift andsag basins record maximum transgression eventswith an onlap surface followed by an overall

regressive package representing the subsequentinfilling of the basin (Contreras et al. 2010).

The basins from Argentina to southern Brazil(Fig. 1) are characterized by rift troughs overlainby marine sediments with no evidence for evapor-ites, and this is also the case for the conjugatemargin basins (Orange, Luderitz and Walvis)located south of the Walvis Ridge (Fig. 1). Thebasins north of the Rio Grande Rise–Walvis Ridge(Santos, Campos and Espırito Santo in Brazil;Benguela, Kwanza, Congo and Gabon in Africa)are characterized by extensive salt deposition inthe Late Aptian (Karner 2000; Mohriak 2001;Davison et al. 2007). A maximum transgressionevent, developed during the Albian–Cenomaniantimes, established a marine restricted environmentwith a prolific source rock system, constituting animportant source rock system in the Congo Basin,in West Africa (Cole et al. 2000), but also develop-ing local source rock pods in other segments of theSouth Atlantic margins.

One of the main topics of this paper is the geo-chemical correlation between oil and oil-extractedsamples recovered from the rift and drift reservoirsfrom southern Brazilian and West African offshorebasins based on molecular and isotopic tools.

From: Mohriak, W. U., Danforth, A., Post, P. J., Brown, D. E., Tari, G. C., Nemcok, M. & Sinha, S. T. (eds) 2012.Conjugate Divergent Margins. Geological Society, London, Special Publications, 369,http://dx.doi.org/10.1144/SP369.18 # The Geological Society of London 2012. Publishing disclaimer:www.geolsoc.org.uk/pub_ethics

10.1144/SP369.18 Geological Society, London, Special Publications published online August 22, 2012 as doi:

Geochemical analyses from the Neocomian–Aptianand Albian–Cenomanian source rock systems fromthe Greater Campos Basin (which includes the mainsalt basins in SE Brazil, from Espırito Santo toSantos) show a strong correlation with oils and oilextracts recovered from wells drilled in the Walvisand Orange basins, offshore Namibia. Such data sug-gest the occurrence of similar petroleum systemsin both Brazilian and West Africa margins, andallow the differentiation between two importantsource rock systems: (i) Neocomian–Aptian shallowbrackish–saline water systems; and (ii) Albian–Cenomanian deep marine restricted system.

The successive intermittent marine incursions,within the Neocomian–Aptian shallow brackish–saline water systems, caused expansions and con-tractions of the water bodies, variations in thewater column salinity, and, hence, the transitionfrom a lacustrine fresh to a lacustrine saline and,finally, to a marine hypersaline water depositionalenvironment, whose desiccation resulted in thedeposition of the extensive evaporites by the LateAptian, particularly in the Santos Basin, wheremassive stratified evaporites occur in the deep-waterregion (Karner & Gamboa 2007).

The variations of water level in the lacustrine andrestricted marine water bodies, owing to climaticfluctuations, played an important role in the sourceand reservoir facies deposition and diagenetic pro-cesses. The compartmentalization of the basin intointra-basinal highs and lows also favoured the

development of anoxic conditions in the lacustrineand marine restricted systems, therefore affectingthe thickness, distribution and quality of thesource rock. Our results indicate that source andreservoir facies deposition from the Neocomian tothe Early Aptian in the Namibian basins show simi-larities to those of the Santos Basin (Fig. 2), wherepre-salt Aptian–Neocomian sedimentary succes-sions are recognized below the massive stratifiedevaporites. In the past there were questions aboutthe quality of the source rocks and reservoir faciesin the southern Santos Basin because of concernsover the influence of Early Cretaceous magmatismin the Santos and Pelotas basins, with lava flowsand related igneous intrusions and volcaniclasticrocks having formed during the rift phase(Mohriak 2003). Several authors even suggestedthat volcanic layers might constitute most of thepre-salt sequence in the deep-water region of theSantos Basin, with no syn-rift continental lacustrinedeposits in the Sao Paulo Plateau (e.g. Kumar &Gamboa 1979).

The evaluation of temperature and maturationdata of exploratory wells by means of petroleumsystem modelling technology on both sides of theAtlantic indicate that heat flow history is differ-ent across the Santos and the Namibian basins(Gallagher & Brown 1999). The different heatflow histories have impacted timing, volumes andcomposition of the oil- and gas-prone areas onboth sides of the South Atlantic (Lentini et al. 2010).

Fig. 1. Regional map of the southern South Atlantic sedimentary basins, with bathymetry and main tectonic elements.The location of the Serra Geral volcanics from the Palaeozoic Parana Basin (onshore Brazil) and the Etendeka volcanics(onshore Namibia), as well as the volcanic wedges offshore the conjugate margins (SE Brazil–Namibia), are indicatedin black. The main bathymetric contours (in km) are also shown. SPP, Sao Paulo Plateau; ES, Espırito Santo; FZ,fracture zone. Modified from Gladczenko et al. (1998).

M. R. MELLO ET AL.10.1144/SP369.18

Geological Society, London, Special Publications published online August 22, 2012 as doi:

Geochemical and geological data evaluated inthis study allowed a petroleum system analysis forthe pre-salt or equivalent successions, in terms oftheir source and reservoir depositional sequences,using petroleum fingerprinting. Rifting and the tec-tonic processes that culminated with the break-upof the Gondwana were responsible for the keyelements of a mega-petroleum system in the SouthAtlantic Brazilian and West African basins. Thesegeochemical analyses of oil samples recoveredfrom Brazilian and Namibian offshore wells wereundertaken to assess to what extent the two pet-roleum systems might be similar. The ultimate aimwas to assess the possibility that a new frontier forpetroleum exploration might exist offshore Nami-bia, containing giant oil and gas reserves chargedfrom lacustrine and marine source rock systems.

Geological and geophysical correlation

of the conjugate margins

The tectonosedimentary evolution of the southernBrazilian (Fig. 3) and Namibian margins (Fig. 2)

include a pre-rift phase with Palaeozoic sedimentsthat are related to the Palaeozoic–Karoo sedimen-tary basins (Tankard et al. 1995), a syn-rift phasethat includes siliciclastic and carbonate rocksdated as Neocomian–Aptian (Light et al. 1992), atransition phase with Late Aptian evaporites northof the Florianopolis (Rio Grande) Fracture Zone–Walvis Ridge, and a transgressive–regressivemarine phase that developed from Albian to Recentin the conjugate margins (Jungslager 1999).

A regional geoseismic profile in the SantosBasin, from the platform towards the deep-waterregion (Fig. 4), illustrates some of the main charac-teristics of the Greater Campos Basin, with hydro-carbon accumulations located both in post-saltturbidite reservoirs (e.g. Mexilhao Field, in theregion of the Cabo Frio Fault Zone) and in pre-saltreservoirs (e.g. the Tupi discovery, located in theoutermost high of the basin, underlain by massivestratified evaporites: Carminatti et al. 2008).

The Pelotas Basin, south of the Floriano-polis Fracture Zone, is characterized by a thickpost-break-up sedimentary succession with noevaporites in the transition from the continental

Fig. 2. Regional map of the southern South Atlantic (geographical co-ordinates), with the location of the mainstructures in the SE Brazilian region. The well 1-ESS-130-ES (Catua Field) is located in the Espırito Santo Basin, nearthe Vitoria–Colatina lineament, which extends from onshore to offshore. The location of the seismic sectionsMexilhao–Tupi (SS, near borehole RJS-628) and Pelotas Basin (PS, near boreholes SCS-2 and BPS-07) are indicated asyellow lines. AR, Abimael Ridge; BA, Buenos Aires; CFFZ, Cabo Frio Fault Zone; FFZ, Florianopolis Fracture Zone;PAFZ, Porto Alegre Fracture Zone; RJ, Rio de Janeiro; RJFZ, Rio de Janeiro Fracture Zone; SCL, Southern CrossLineament; SEH, Santos External High; VCL, Vitoria–Colatina Lineament; VTR, Vitoria–Trindade Ridge. Purpleline, volcanic basement limit (Mohriak 2001); white continuous line, Leplac crustal limit; blue dashed line, crustal limit(Karner 2000).

PETROLEUM SYSTEM CORRELATION10.1144/SP369.18


M. R. MELLO ET AL.10.1144/SP369.18


environment to the marine environment (Dias et al.1994; Mohriak 2003; Bueno et al. 2007; Contreraset al. 2010). The sedimentary succession in the basinincludes volcanic rocks penetrated in a few bore-holes in the platform, and Cretaceous–Quaternarysequences that extend towards the oceanic crust(Fig. 5). Regional seismic profiles indicate the pres-ence of seaward-dipping reflector (SDR) wedgesforming a volcanic substratum in the deep-waterextension of the basin (Fig. 6). Although no bore-holes have penetrated these features beyond theshelf break, exploratory wells in the platform sug-gest that the southern Brazilian margin is highly vol-canic and was characterized by the presence ofa thermal anomaly in the mantle during the earlystages of oceanic crust formation, which resultedin the formation of thick wedges of volcanic rocks(Gladczenko et al. 1997, 1998; Abreu 1998; Talwani& Abreu 2000). A thick Cretaceous–Tertiary sedi-mentary overburden, which may exceed 6 km inbasin depocentres, suggests that postulated sourcerocks might be mature in the deep-water region.The few boreholes in the basin are mostly locatedin the platform and did not penetrate Early Cretac-eous source rocks, but a few boreholes in deepwaters indicated the presence of Tertiary sandstoneturbidite reservoirs.

The region from southern Angola to Namibia isalso a frontier region for petroleum exploration,with fewer than 20 boreholes drilled in an areathat is larger than the Greater Campos Basin. TheKunene-1 borehole, drilled in the Namibe Basinin southern Angola, penetrated siliciclastic sedi-ments overlying a structural high located close tovolcanic intrusions and seamounts associated withthe Walvis Ridge (Fig. 2). There are a few ODP(Ocean Drilling Program) and exploratory bore-holes on the Walvis Ridge and in the WalvisBasin, but with no commercial discovery up to thepresent.

The Luderitz Basin in southern Namibia hasalso been tested by few exploration wells, and theKudu gas and condensate accumulation, locatedon the border between the Luderitz and the Orangebasins, constitutes the most important discovery inNamibia and South Africa, with proved reservesof around 1.3 Tcf (trillion cubic feet) and potentialreserves estimated to reach up to 3 Tcf of gas inBarremian sandstones that are intercalated withvolcanic layers.

A regional seismic profile in the region north ofthe Kudu discovery (Fig. 7) illustrates the tectonicstyle of the Luderitz Basin, which is clearly markedin the platform by syn-rift structures developed

Fig. 3. Regional satellite image (top) and topobathymetric map (bottom) of southern Africa. The Kunene-1 borehole islocated in the Namibe Basin, north of the Walvis Ridge. The seismic profile SS-1 and the boreholes in the Kudu area ofthe Luderitz Basin are located near the border between Namibia and South Africa.

Fig. 4. Regional geological section (A–B on inset map, SS in Fig. 3) extending from the platform towards the outerhigh in the deep-water region of the Santos Basin, where the Tupi giant discovery found pre-salt reservoirs sourced bylacustrine shales.



Fig. 5. Regional geoseismic profile from the platform towards the deep-water region of the Pelotas Basin (PS in Fig. 3),showing the main stratigraphic sequences and the SDR wedges in the ultra-deep-water region (modified from Abreu 1998).

Fig. 6. Regional seismic profile from the platform towards the deep-water region of the Pelotas Basin (basinwardsextension of PS in Fig. 3) (modified from Mohriak 2003).

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during the Neocomian–Barremian and a sag basindeveloped in the Barremian–Aptian (Light et al.1992). Borehole 2814/07-2ST-1 was drilled in theplatform and penetrated a thick Late Cretaceoussiliciclastic succession and also Early Cretaceousrocks (Barremian–Neocomian) without reachingigneous rocks, interpreted as volcanic basement.Basinwards of the shelf break, the classical wedgesof SDRs are imaged in the seismic profiles, but athick Aptian–Barremian sag to rift trough isobserved near the outer high in the basin.

A regional geoseismic transect near the Kududiscovery (Fig. 8) also indicates the presence of athick syn-rift trough landwards of the field. Seis-mic data suggest that the syn-rift sequence is over-lain by Barremian–Aptian strata, which are lessaffected by extensional faults and correspond to asag basin, where source rocks have been penetratedby a number of boreholes (Schmidt 2004). Theregion basinwards of the Kudu discovery showsthe rift–sag basin, in which source rocks and reser-voirs are predicted, and the deep-water region ischaracterized by SDR wedges (Fig. 9), which areprobably related to volcanic sequences formedduring the early stages of the oceanic crust develop-ment (Gladczenko et al. 1998).

The sag basin offshore Namibia shows manycharacteristics that resemble the sag basin in the Bra-zilian margin, with subhorizontal strata overlying

volcanic highs in deep water, and a marked uncon-formity between the dipping horizons and thesedimentary succession, as observed in the Tupidiscovery, which penetrated carbonate rocks in theAptian sag basin and sediments with volcanic rocksin the Barremian–Neocomian syn-rift sequence(Henry et al. 2009).

The main difference is that the Aptian succes-sion offshore Namibia is not covered by an evap-orite sequence that is characteristic of the GreaterCampos Basin. We discuss here the similaritiesthat may occur in the sedimentary environmentsbelow the Aptian unconformity, suggesting thatboth basins, although marked by different tectonicelements during their development, shared a com-mon environmental and depositional source rocksystem during the extensional phase that predatedthe inception of oceanic crust.

Geochemical characterization of the

hydrocarbons from the Kudu Field using

biomarker, carbon isotope, diamondoid,

CSIA-D and CSIA-B technologies

In the absence of wells that have penetrated theLower Cretaceous source rocks in the offshoreNamibian basins, detailed molecular geochemistry

Fig. 7. Regional seismic profile (SS-1 in Fig. 2) from the platform towards the deep-water region of the Luderitz Basin,north of the Kudu gas field. The borehole 2814/07-2ST-1 penetrated Barremian and probably Neocomian sediments atthe total depth of 5290 m, without reaching volcanics.



technologies using biomarker and diamondoidhigh-resolution geochemistry techniques (HRGT)were applied to the condensate samples taken fromthe Kudu 4, 4B and Kudu 5 wells (Fig. 10). Theseanalyses were critical to determining the identityof the source rock systems in offshore Namibia.

The results of the HRGT analyses enabled thecharacterization of lacustrine and marine oil types inNamibia, and their correlation with their counterpartsfrom across the southern South Atlantic basins, inBrazil. The geochemical approach applied in theKudu hydrocarbon samples was mainly based onthe distribution and concentration of biologicalmarkers and diamondoids, and their carbon isotopecomposition, in order to assess the age, palaeoenvir-onment of deposition and the extent of thermal crack-ing (Moldowan et al. 1985, 1990, 2001; Mello et al.1988a, b; 1995, 2000, 2011; Mello & Maxwell1991; Holba et al. 1998, 2003; Peters & Moldowan1993; Dahl et al. 1999; Mello & Katz 2000; Stolhofenet al. 2000; Wei et al. 2007; Sassen & Post 2008;Rodriguez Monreal et al. 2009).

Age and palaeoenvironment of deposition-relatedbiomarkers are characterized by compounds, whoseoccurrence in oils and source rock extracts are re-stricted to certain depositional environments, andsome also are specific to certain geological time peri-ods. The identification of the age-related biomarkersis achieved by using gas chromatography–mass

spectrometry–mass spectrometry (GC–MS–MS)techniques.

The application of the specific biomarkers, dia-mondoids and specific carbon isotope analysis ofdiamondoids (CSIA-D) and biomarkers (CSIA-B)has allowed the identification of different oiltypes, their origin to be characterized, and also anestimate to be made of the age and depositionalenvironment of their source rock systems (Peters& Moldowan 1993; Dahl et al. 1999; Mello et al.2000, 2011; Mello & Katz 2000; Wei et al. 2007;Sassen & Post 2008). Also, the application ofthese geochemical tools is extremely important fordetermining the presence of active petroleum sys-tems in sedimentary basins. Furthermore, it has aprofound impact on exploration strategies in frontierregions where source rocks have not been sampled,as in offshore Namibia (Peters & Moldowan 1993;Dahl et al. 1999; Mello et al. 2000, 2011; Mello &Katz 2000).

Quantitative analyses of sterane biomarkers anddiamondoids of Kudu samples presented low con-centration of C29 steranes (e.g. up to 3.5 ppm ofC29 total steranes in the Kudu 5 sample) and extre-mely high concentrations of diamondoids (up to360 ppm of 3- and 4-methyldiamantanes in theKudu 4 and 4B samples: Fig. 11). According todiamondoid data obtained for many oil samplesfrom the eastern Brazilian marginal basins, the

Fig. 8. Composite geoseismic section in the Orange Basin, where the Kudu gas and condensate field was discovered inAptian–Barremian siliciclastic reservoirs.

M. R. MELLO ET AL.10.1144/SP369.18


diamondoid baseline is 5 ppm (HRT geochemicaldatabase). Therefore, based on a baseline of 5 ppm,the high values of 3- and 4-methyldiamantanes ofthe Kudu samples analysed in this study are indica-tive of highly cracked condensates (i.e. 95–98.5%:Fig. 11) (Dahl et al. 1999; Wei et al. 2007; Sassen& Post 2008; Rodriguez Monreal et al. 2009).

However, the presence of up to 4 ppm of C29steranes, in the Kudu 5 sample, with around 95%cracked stage, imply that this samples is a mixtureof two different fluids: a highly cracked condensate(i.e. up to 95% cracked) mixed with a less-maturenon-cracked condensate (i.e. up to 4 ppm of bio-marker: Fig. 11) (Dahl et al. 1999; Mello et al. 2000).

Fig. 9. Regional seismic profile in the Luderitz Basin (C–D in Fig. 8), with the location of the Kudu discovery well.(Top) Uninterpreted profile; (bottom) with an interpretation showing the SDRs interpreted as volcanic wedges thatpost-date the rift sequence.



95–99% diamondoid cracking results, if con-verted to vitrinite reflectance (% Ro) give valuesgreater than 2% Ro for the source of these crackedsamples, implying a very deeply buried sourcerock system in the Orange Basin (Dahl et al. 1999;Mello et al. 2000; Wei et al. 2007).

In order to identify the origin of the highlycracked condensates that represent more than 95%of the Kudu samples, compound specific isotopeanalysis of the diamondoids (CSIA-D) was per-formed (Dahl et al. 1999; Mello et al. 2000, 2011;Mello & Katz 2000; Wei et al. 2007; Sassen &Post 2008). The diamondoid isotope compositionof the condensates from the Kudu Field illustratedin Figure 12 shows a good correlation with the oilrecovered in the 1-ESS-130-ES well, drilled in theEspırito Santo, Basin, and considered to be mixedoil with lacustrine and marine contribution (HRTdatabase). In contrast, the Kudu samples show apoor correlation with the marine derived oils from

the Santos Basin (e.g. 3CRV-1-BSS and 1-PRS-4:HRT database).

Figure 13 shows CSIA-D data for the Kudusamples compared with lacustrine oils derivedfrom Aptian–Barremian source rocks from theSantos and Campos basins (HRT database). Thesimilarity of the data suggests that diamondoids ofthe Kudu condensate have been generated in asimilar Aptian–Neocomian lacustrine saline sourcerock system to that which must also occur on theNamibian margin. The per-mil range offsets of theisotope curves of these lacustrine oils (Fig. 13),and in fact, the offset between the curves for Kudu4 and Kudu 5, could be in response to faciesdifferences among the lacustrine source rocks forthese oils.

The oil sample from the well 1-ESS-130-ES iscracked and represents a typical mixed oil. Wherea highly cracked fluid is mixed with less maturefluids of a different source, most of the diamondoid

Fig. 10. Location map of the Namibe, Walvis and Luderitz basins, with exploratory blocks and ODP boreholes. TheKunene-1 borehole is located north of the Walvis Ridge, in the Namibe Basin. Exploratory block 1911 is located southof the Walvis Ridge, west of the Etenka volcanics, which outcrop onshore, near the coastline. The exploratory boreholes2815/15-01 and Sidetrack, Kudu 4, 4B and 5, which are discussed in this work, are located near the Kudu gas andcondensate field.

M. R. MELLO ET AL.10.1144/SP369.18


isomers come from a highly cracked source and theCSIA-D isotopic profile reflects the highly crackedsource rather than the less mature fluid. Some ofthese samples have mixed contributions of dia-mondoids from both the marine and lacustrinesources, but with a predominance of lacustrinefluids. These would have intermediate CSIA-D pro-files between pure lacustrine and marine oils.Among all the oils with marine biomarkers, themixed lacustrine–marine oil from the 1-ESS-130well shows a better correlation with the condensatesamples from the Kudu 4 and 5 wells in the CSIA-Dprofile data (Fig. 12).

In summary, the integration of quantitativediamondoid analysis and the CSIA-D (diamond-oids) data suggest that the Kudu condensates aremixed oils that possibly were derived from atleast two different source rocks: Albian–Cenoma-nian marine source rock in the oil window; anda volumetrically dominant contribution from ahighly mature source rock associated with thelacustrine rift petroleum system present in theOrange Basin. In addition, CSIA-D results fromthe condensate samples recovered from KuduField in Namibia are compared with oil samplessourced by Lower Cretaceous marine and lacustrinesources in Brazil.

Geochemical characterization of extracted

oils recovered from the wells 2815/15-01

and Sidetrack-2815/15-01 (east of the

Kudu Field) using biomarkers

compounds

A number of reservoir core and cutting sampleswere selected from six wells from the Luderitz,Walvis Bay and Orange basins, in offshore Namibia(Fig. 10). The samples were analysed using gaschromatography (GC) and gas chromatography–mass spectrometer (GC–MS) to identify biologicalmarkers of the migrated oils extracted from thesamples. The biomarkers were critical for assessingoil types present in the basins, and also to predicttheir source rock depositional environment andthermal evolution (Figs 10 & 14–16).

Figure 14 shows a number of selected extractedoil samples that presented high concentrations ofmigrated oils in the 2815/15-01 and the 2815/15-01 Sidetrack wells, close to the Kudu Field(see Fig. 10). The figure also shows gammacer-ane/C30 hopane and hopane/sterane ratios v. depthfor most of the well samples recovered, and the fin-gerprints of the ‘whole oil’ gas chromatogram andmass fragmentograms (GC–MS) of the hopanes

Fig. 11. Biomarker and diamondoid data showing the extent of oil cracking and the presence of mixed hydrocarbons inthe Kudu samples. As can be observed, the samples suggest a highly cracked stage (oil cracking .95%), mixed with lessmature non-cracked oil (e.g. Kudu 5 sample).



Fig. 12. Carbon isotope values of diamondoid components present in the condensate samples of Kudu 4 and Kudu 5wells, compared with marine anoxic and mixed oil recovered from wells in the Santos and Espırito Santo basins,offshore Brazil.

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(m/z 191) and diasteranes (m/z 259) biomarkersfrom four selected sample intervals.

The hopane/steranes and gammacerane/C30hopane data v. depth (Fig. 14) suggest the pres-ence of two distinct oil types among all of thesamples analysed (i.e. compare samples around2500 m with the samples deeper than 3000 m).This is clearly demonstrated when biomarkerdata such as normal paraffins and b-carotane (GCfingerprint), terpanes (m/z 191 mass chromatograms)and diasteranes (m/z 259 mass chromatograms)are compared (Fig. 14) (Mello 1988; Mello et al.1988a, b, 1991, 2000; Schiefelbein et al. 1999).

The migrated oils analysed at 1400 and 2470 mfrom the 2815/15-01 well present low hopane/ster-anes and gammacerane/ C30 hopane ratios associ-ated with high C27 diasteranes/TPP (tetracyclicpolyprenoids) ratios. The TPP were identified byHolba et al. (2003), who also observed thatlacustrine-derived oil, in the South Atlantic Realm,contains a very high abundance of TPP relative toC27 diasteranes (Schiefelbein et al. 1999).

The biomarker ratios present in the samples shal-lower than 2500 m (i.e. samples from 1400 and

2470 m: Fig. 14) are comparable to the Albian–Cenomanian marine oil type present in the Camposand Santos basins, offshore Brazil (Mello 1988;Mello et al. 1988a, b, 1991, 2000; Schiefelbeinet al. 2000). By contrast, the migrated oils thatoccur deeper than 3000 m, in the 2815/15-01 Side-track well, such as at 3140 and 4110 m, are exam-ples of lacustrine saline oils, commonly found inthe Campos and Santos basins, as suggested by theoccurrence of high hopanes/steranes and gam-macerane/C30 hopanes ratios associated with lowdiasteranes/TPP ratios (Fig. 14) (Mello 1988;Mello et al. 1988a, b, 1993, 2000; Peters & Moldo-wan 1993; Schiefelbein et al. 1999; Holba et al.2003).

b-carotane is present in the GC traces of themigrated oil analysed at 4110 m (Fig. 14). Thiscompound has been reported from oils and oilextracts from lacustrine saline Neocomian sourcerocks from the Campos Basin (Mello 1988; Melloet al. 1988a, b, 1993). Another compound thatsuggests the lacustrine character for the deepersamples is the high abundance of gammaceranerelative to C30 hopane. High abundances of

Fig. 13. Carbon isotope values of diamondoid compounds present in condensate samples from Kudu Field and CamposBasin lacustrine oils. As can be observed, the condensate samples from the Kudu 4 and Kudu 5 wells show a goodcorrelation with Brazilian oils derived from Aptian–Barremian lacustrine saline source rocks.



Fig. 14. Gammacerane/C30 hopane and hopane/sterane ratios v. depth in the wells 2815/15-01 and 2815/15-01Sidetrack, together with GC, m/z 191 and m/z 217 mass chromatograms of selected extracted samples.

Fig. 15. Cross-plot of C29 steranes 20S/20S+R ratio against depth (m) and the m/z 217 mass chromatograms (GC–MS) of some samples taken at several depths from the well Kudu-4.

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gammacerane are a key lacustrine diagnostic par-ameter in the characterization of lacustrine-derivedoils in the Santos and Campos basins, as well as inthe conjugate margins (sample 4110 m from Fig. 14)(Mello 1988; Mello et al. 1988a, b, 1993, 2000).

Regarding thermal evolution assessment of theoil extracts, the GC traces from the migrated oils ana-lysed at 1400 and 2470 m (Fig. 14) suggest a highthermal evolution stage of generation (Mello 1988;Peters & Moldowan 1993). With increased maturity,high molecular weight n-alkanes and biomarkers arethermally degraded, thus increasing the proportionof lighter n-alkanes and decreasing the biomarkerconcentrations (Mello 1988; Peters & Moldowan1993). The GC traces from the 1400 and 2470 msamples present a profile with a predominance oflight n-alkanes, indicating therefore a high maturity

stage. However, the migrated oils analysed at 3140and 4110 m from the Sidetrack well (Fig. 14) showa bimodal whole oil profile that is typical of a mix-ture of two different oil types; such as a mixture ofa marine crude oil with a predominance of lightern-alkanes (i.e. high thermal evolution) with a lacus-trine saline, less mature oil, with a predominance ofhigh molecular weight n-alkanes and biomarkers(Mello 1988; Peters & Moldowan 1993).

Figure 15 illustrates the GC–MS distribution ofC29 steranes detected in the less mature non-cracked condensate portion of the Kudu 4 sample.The C29 steranes’ maturity parameter 20S/20S +20R, with values up to 38%, indicate a close to peakstage of thermal evolution for the less mature con-densate fluid present in the Kudu 4 mixture (Mello1988; Peters & Moldowan 1993; Wei et al. 2007;

Fig. 16. Cross-plot of hopane/sterane index v. diasteranes/TPP index from the saturate fractions of extracts of the2815/15-01 and 2815/15-01 Sidetrack wells compared with lacustrine and marine oil data from Santos, Campos andEspırito Santo basins. Note the presence of two oil systems in the plot. The lacustrine oils are characterized by lowdiasteranes/TPP ratios together with high hopane/sterane ratios, and the marine oils are characterized by a low hopane/sterane index and higher diasteranes/TPP ratios.



Sassen & Post 2008). Also, their relative isomerdistribution suggests a good correlation with oilsderived from Albian–Cenomanian marine sourcerocks from the Greater Campos Basin in Brazil(Mello 1988; Mello et al. 1988a, b).

Figure 16 shows a cross-plot of biomarker ratios,diagnostic of assessment of the depositional envi-ronment (Mello 1988; Katz & Mello 2000; Melloet al. 2011) that has been used successfully for char-acterizing and differentiating lacustrine and marineoil and source rock types in several basins aroundthe world. The plot presented in Figure 16 comparesthe migrated oils samples taken from the 2815/15-01 and 2815/15-01 Sidetrack wells with anumber of marine Albian–Cenomanian and LowerCretaceous lacustrine saline oils from Campos,Santos and Espırito Santo basins, including the oilfrom the supergiant Tupi Field, in Offshore Brazil.As can be noted, there is a good correlation amongthe migrated oils from the 2815/15-01 and 2815/15-01 Sidetrack wells with the Brazilian marineanoxic and lacustrine oils, suggesting that they sharea similar origin (Fig. 16).

In summary, the integration of biological markerdata from extracted oils recovered from the reser-voir rocks from the 2815/15-01 and 2815/15-01Sidetrack wells offshore Namibia, when comparedwith marine and lacustrine saline oils from offshoreBrazil, suggested that two oil systems might bepresent in the southern South Atlantic:

† Albian–Cenomanian marine (!) petroleumsystem – this system is present in the Campos,Santos and Espırito Santo basins offshoreBrazil, and in their African conjugate Kwanzaand Congo basins offshore Angola;

† Aptian–Barremian lacustrine saline (!) pet-roleum system – this system is also present inthe Campos, Espırito Santo and Santos basinsin Brazil, and in the conjugate Congo andKwanza basins in Angola. In Brazil andAngola such a system is overcharged and rep-resents more than 40 billion barrels (bbl) ofhydrocarbon reserves (Mello et al. 2011).

Conclusions

A multidisciplinary approach, focusing on thenature and distribution of hydrocarbon fluids,places the discovered hydrocarbons of the KuduField, offshore Namibia, in an interpretative frame-work that provides a potential ‘road map’ for futurehydrocarbon exploration, focusing on the Albian–Cenomanian and Aptian–Barremian source rocksystems in offshore Namibia.

The geological and geochemical data from theGreater Campos and Namibian basins reveal ageneral similarity between the Brazilian and West

African southern marginal basins (Mello et al.1991, 2011; Katz & Mello 2000). This similarityreflects a comparable source rock depositionalenvironment and, consequently, oil systems. Asym-metric rifting has, however, resulted in differentsedimentary and subsidence histories that have, inturn, resulted in major differences in the distributionof light oil v. gas and condensates, and also in differ-ent reservoir depths along the margins. The syn-riftsuccessions are, for example, deeper in the Brazilianmarginal basins when compared with the WestAfrican margin (Mello et al. 1991). However,Albian–Cenomanian mature marine source rocksystems are widely recognized in several basins inWest Africa, particularly in Gabon, Congo andAngola (Mello & Katz 2000).

The SE Brazilian margin is characterized byoils derived from lacustrine source rocks, withonly a minor contribution from Albian–Cenoma-nian marine sources rocks (Mello et al. 1988a, b,1993). Although marine organic-rich sedimentsare present in the Campos Basin, their overburdenis insufficient for large-scale generation. In contrast,adequate overburden is, at least locally, presentalong the Namibian margin, resulting in light oiland gas generation from marine source rocks, asobserved in part of the Kudu Field.

Consequently, when comparing the petroleumsystems present around the South Atlantic Realmas possible exploration analogues for underexploredregions, account must be taken of source rockpresence and source rock maturity. The resultspresented here provide strong evidence for the pres-ence of at least two active petroleum systems inNamibia, with their respective pods of hydrocarbongeneration located deep offshore. The biomarkerfingerprints of the migrated oils present in the sedi-mentary sections of the 2815/15-01 and the 2815/15-01 Sidetrack wells and the geochemical data ofthe Kudu 4 and Kudu 5 wells are similar to thosethat have sourced more than 90% of the oil pro-duced in the Brazilian and Angolan marginal basins.

In summary, the petroleum system concept,applied in this study using state-of-the-art geochemicalanalysis technology, suggests that the Namibian off-shore basins can be considered a new frontier forexploration. On the basis of the analogies drawn herewith basins north of the Walvis Ridge–Rio GrandeFracture Zone, the Namibian source rock systemsare similar to those that have sourced more than 90%of the oil discovered in the Brazilian and Angolanmarginal basins and might be large enough to chargegiant to supergiant oil and gas accumulations.

We thank several geoscientists from IPEX and HRT whocollaborated in the analyses and interpretations of the oilsamples from the Brazilian and West African margins.We are grateful to many colleagues from HRT and other

M. R. MELLO ET AL.10.1144/SP369.18


petroleum companies who participated in several technicalmeetings and workshops discussing the similarities anddifferences between conjugate margins in the South Atlan-tic. We are also indebted to reviewers R. Crossley andB. Katz for many constructive comments and criticismsthat improved this work.

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