To kick things off, we need to get situated. Figure 1 is a map of the Pelotas Basin showing sectors SP-AR1, SP-AP1 and SP-AUP1 with their respective nearshore to ultradeep-water exploration blocks that will be offered up by ANP during its upcoming 17th Bidding Round in October. The map also shows the location of seabed piston cores, wells drilled to date and our ongoing oil slick Radarsat-1 satellite survey. As you can see, most of the blocks on offer are situated close to the Florianopolis High, just across the divide with the Santos Basin. It is important to mention that only four wells have been drilled to date in the sectors being offered, with just one in the deep waters (1-BPS-3-BP in SP-AP1).
Among the Brazilian offshore basins, Pelotas is considered by many to be the last frontier in hydrocarbon exploration of the South Atlantic Realm. Although the basin lacks the prolific pre-salt lower Cretaceous Sag and Rift lacustrine sedimentary sections present in the Santos Basin, it has a very similar structural and stratigraphic correlation with the post-salt of southern Santos and its South Atlantic counterpart, the Walvis Basin, in Namibia (Fig. 2 and 3).
The basin is located in the extreme south of the Brazilian Continental Margin, covering an area around 330,000 square kilometers. It borders with the Santos Basin to the north, through the Florianópolis High, and the Punta Del Este Basin (Uruguay) to the south, through the Polonio High (Fig. 1). Only nine wells have been drilled in the basin’s offshore area, with only two in the deep-water areas (2-BPS-6A-BP and 1-BPS-3-BP – Fig. 1). All the wells drilled in its offshore area came up dry and did not report the presence of recoverable oil shows in the sedimentary sections, so there are no oil extracts for geochemical analysis.
The geological reconstruction of the southern South Atlantic conjugate margins at the rift stage (Barremian time) in the Pelotas Basin points to significant differences from the rift pre-salt section of the Santos Basin (e.g., Fig. 2). That said, the structural and stratigraphic framework and geochemical and geological data show major similarities to the drift sequences of the Santos and Walvis (Namibia) basins. In fact, the Aptian to Valanginian syn-rift strata in both Pelotas and Walvis are covered by volcanic wedges of seaward-dipping reflectors towards the oceanic crust. In contrast, the sag and rift sections in Santos are covered by prolific sedimentary sections composed of lacustrine source rocks and carbonate reservoir systems (e.g., Figs. 2–3; Mello et al., 2013; Mello et al., 2015; Mello et al., 2020).
As illustrated by the tectonic-stratigraphic columns of the southern South Atlantic conjugate margins (Fig. 3; Pelotas, Namibe, Walvis, Luderitz and Orange basins), organic-rich intervals have been identified and characterized in both basins as marine anoxic late Aptian-Albian, Cenomanian-Turonian and Paleocene sequences (see below Figs. 4 and 5; Mello et al., 2013; Mello et al., 2015). The reservoir rocks, on the other hand, have been identified in the Albian deltaic to marine sandstone sequences and late Cretaceous to Miocene marine sandstone turbidite sequences. However, when comparing Pelotas with Santos or the Orange Basin, significant differences between their structural and stratigraphic frameworks are noted, such as the presence of overcharged lacustrine Aptian source rock sequences in the Orange Basin (e.g., Mello, 2013; Mello et al., 2015). In this discussion only the northern portion of the Pelotas Basin will be considered (e.g., Figs. 1–3).
The geochemical data of well 2-BPS-6A-BP drilled in the deep waters of the northern Pelotas Basin showed the presence of at least two potential source-rock systems:
- Marine suboxic Paleocene sequence from the Imbe Formation (e.g., Figs 3–4).
- Marine anoxic Cenomanian–Turonian sequence from the Atlántida Formation (e.g., Figs. 3–4).
Although the marine suboxic Paleocene sequence from the Imbe Formation presents a thick organic-rich interval (e.g., around 200 m with average TOC content of up to 3.5%), it is predominantly composed of hydrogen poor Type III kerogen (average HI of around 220 mg HC/g. TOC) with low hydrocarbon source potential (S2 averaging 8 mg HC/g of rock). Moreover, in the northern portion of the basin, it presents an immature stage of thermal evolution (e.g., Tmax < 430 o and vitrinite reflectance > 0.5%Ro; Fig. 4). As such, this section cannot be considered a source-rock system in this portion of the basin and will not be discussed further.
In contrast, the marine anoxic Cenomanian-Turonian Atlántida Formation source-rock system presents a section that is around 40 meters thick on average, with high TOC content of up to 4% and good hydrocarbon source potential (cf., S2 up to 12 mg HC/g of rock), composed of marine algal Type II organic matter (HI up to 460 mg HC/g. TOC; Fig. 4). The integration of the Tmax and vitrinite reflectance data obtained from well 2-BPS-6A-BP (e.g., Tmax and Vitrinite reflectance ranging from 440-448 degrees and 0.6-0.75%, respectively; Fig. 4) with BPS’s 2D PSM of the studied area indicates oil peak maturity between 4,300-4,800 meters (e.g., %Ro values ranging from 0.7% to 0.8%) and gas peak maturity starting below 5,800 meters (%Ro values ranging from 1.0 to 1.2; Fig. 4). In addition, Figure 5 shows a geochemical log of deep-water well 1-BRSA-617-SCS, drilled in the southern Santos Basin, showing the organic-rich sections of the Paleocene (Jureia Formation) and Cenomanian-Turonian (Itajaí-Açu Formation). Note the similarities of the two source-rock intervals with those from well 2-BPS-6A-BP (see Fig. 1 for location).
It is important to mention that in the deep-water Walvis Basin the marine anoxic Cenomanian-Turonian source-rock system (e.g., well 1911-15 well) presents TOC content of up to 10% and excellent hydrocarbon source potential (cf., S2 up to 60 mg HC/ g of rock), composed of marine algal Type II organic matter (HI up to 600 mg HC/g. TOC; Mello et al., 2015).
The marine anoxic late Aptian/Albian Kudu Formation source-rock system recovered in wells from the Walvis and Orange basins (e.g., deep-water wells 1-Wingat-1-HRT and 1-Muronbe-1-HRT; Mello et al., 2015) has never been drilled in the Pelotas Basin. The Kudu Formation source-rock interval was found to consist of a thick (around 100–200 m) marine black shale containing TOC of up to 4%. The Type II kerogen (hydrogen index up to 500mg/g HC) is characterized a medium hydrocarbon source potential (S2 up to 20 mg HC/g of rock), while the vitrinite reflectance data of ~0.75-0.80%Ro indicates the entire section was within the peak oil generation window, therefore suggesting that most of the original organic-rich sediments were converted into hydrocarbons (e.g., Mello et al., 2015). As such, the presence of this sequence in the eastern depocenters located close to the Florianopolis High cannot be ruled out (e.g., see the ranking map below).
The marine anoxic Cenomanian-Turonian source-rock system is well documented in deep-water sequences in the southern Santos Basin (e.g., 1-BRSA-617-SCS; Fig. 5) and the Walvis Basin (e.g., wells 1911-15 and 1-Wingat-1-HRT; Mello et al., 2015). Moreover, they present correlations with the world-class overcharged marine anoxic source-rock systems present in the post-salt of Brazil’s Santos, Campos and Espírito Santo basins, the South American Equatorial Margin (e.g., Venezuela, Guyana and Para-Maranhão, etc.) and the deep waters off Angola, Congo and Gabon in West Africa (Fig. 4; Katz and Mello, 2000; Mello et al., 2013; Mello et al., 2015).
Due to the absence of the lower Cretaceous Sag and pre-salt lacustrine overcharged petroleum system in Pelotas, the most significant uncertainty for most explorers of northern Pelotas will be to predict how thick, organic-rich and mature the marine anoxic Cenomanian-Turonian source-rock system in the deep-water realm of the northern area near the Florianopolis High is. That said, it is critical to mitigate exploration risk regarding the presence of any working petroleum system in and around the deep to ultradeep-water blocks on offer in ANP’s 17th Bidding Round.
Figure 6 shows a regional dip-oriented PSDM seismic line from the north of the Pelotas Basin depicting the platform towards the deep-water region. As you can see, the main stratigraphic sequences, including the Paleocene (Imbe Formation) and Cenomanian-Turonian (Atlántida Formation) source rocks and the SDR wedges in the deep and ultradeep waters, are difficult to interpret because the quality of the line is not very good (modified from Mohriak, 2003). Therefore, the lack of coverage and good quality 2D PSDM seismic data of the entire area on offer in the 17th Bidding Round turns out to be the main challenge to mitigate exploration risk.
To overcome this challenge, TGS is starting a state-of-the-art 2D PSDM seismic acquisition covering not only the entire area on offer in the Pelotas Basin, but also a large portion of the ultradeep waters of the Pelotas and Santos basins east of the Florianopolis High (e.g., Phase 3 Subset (~8,217 km) and Phase 3 (~17,884 km; Fig.7)). Our idea at BPS is to perform a 2D PSM study for some of the acquired lines, aiming to confirm the presence of oil slicks and oil seeps detected in some of the offered blocks.
It is important to mention that no oil has ever been found in the Pelotas Basin. However, exploration performed by HRT Petroleum (today PetroRio) in the Walvis Basin in offshore northern Namibia found good quality, very mature light marine anoxic oil in Albian marine sand-rich turbidity reservoirs in well 1-Wingat-1-HRT drilled in the deep-water Walvis Basin (e.g., Fig. 8; see Mello et al., 2015). Detailed biomarker analyses of the oil showed a light oil (e.g., around 41o API) composed of almost 85% saturate compounds with very few aromatic and NSO compounds. Due to its high thermal evolution stage, the hopanes and steranes were recovered in very low concentrations, but enough to indicate a marine siliciclastic origin (e.g., Fig. 8; Mello et al., 2015).
Regarding the presence of good to excellent reservoirs in the deep-water Pelotas Basin, we consider it be a very low risk assumption. Together with the seismic data, the drilled wells show enough Cretaceous to Tertiary turbidity sandstones that can range from Albian to Miocene age with excellent poro-perm conditions. Most can be considered prime exploration targets. As a positive factor, the fast sedimentation generated disequilibrium of under compaction associated with overpressure due to rapid burial. Moreover, top-seal effectiveness appears to have been enhanced by reducing mud rock permeability through deep burial and widespread mud rock sedimentation.
Regarding traps/seals, the northern Pelotas Basin has relatively few large structures due to the lack of evaporites and a dominance of a passive-type tectonic realm with a history dominated by thermal subsidence, causing general ramp-type sedimentation. However, giant stratigraphic traps are predicted in the transgressive sequences, associated with onlapping within erosional, cut and fill features, but with a risk of effective charge. On the other hand, there is pervasive sealing potential in all the mud rock sequences spanning from Cretaceous to Miocene, although no “regional top seal” is recognized.
The Top-Cretaceous, lower Oligocene and Miocene levels present top-seal effectiveness even for gas with relatively low risk. In general, top-seal effectiveness decreases and relative risk increases towards the shelf and over the Florianopolis High.
Regarding generation, migration, accumulation and preservation, peak generation occurred very recently and hydrocarbons are still charging the basin’s reservoirs. The main migration mechanism is through the listric faults associated with the load- induced gravity sliding.
In summary, the analysis of geological, geophysical, geochemical, seabed piston core and oil slick data integrated in 2D and 3D petroleum system modeling and an exploration risk assessment approach provided a unique platform to deepen the understanding of the presence of active petroleum systems in the deep-water region of the northern Pelotas Basin.
And now for our rankings…
The exploration rankings of the Pelotas Basin deep-water blocks of the 17th Bidding Round were based on the petroleum system concept, taking into consideration analogies with the active post-rift petroleum systems observed in Southern Santos and the Walvis Basin (Namibia).
It is important to mention that only wells 1-BPS-6A-BP and 1-BPS-3-BP have tested targets in the deep-water northern area of the Pelotas Basin, so our risk analysis was calibrated using the elements and processes observed in these wells. Another limitation was the insufficient and limited 2D seismic data, which covers only part of the two offered deep and ultradeep-water sectors (Fig. 1).
Figure 9 shows a basement map of the Pelotas Basin that acts as a proxy for the presence of hydrocarbon kitchens containing mature source rocks in the structural lows and potential reservoirs and traps in the highs. When integrated with the oil slick, oil seep and source rock data, as well as 2D PSM performed by BPS, it allowed us to estimate hydrocarbon risk and generate a ranking of the exploration blocks to be offered in ANP’s 17th Bidding Round. The blocks were ranked as Priority 2 and Priority 3 (from higher to lower priority). Based on the currently available data, BPS does not recommend any of the other blocks on offer, so no priority levels were assigned.
Although the exploration risk is quite high, the eight blocks located in the ultradeep-water domain of SP-AUP1 were ranked as Priority 2 due to their proximity to the Florianopolis High and their association with a pronounced and important external structural low that we predict to be a critical hydrocarbon kitchen for the marine anoxic Albian-Cenomanian to Turonian source-rock system in the basin. Moreover, oil slicks and oil seeps representing black oil, cracked oil, condensate and gas were identified in and around the blocks.
The 2D PSM performed along a DIP seismic line that crosses the sector in the basin’s deep domain, together with an ongoing 3D PSM being conducted by BPS (www.brazilgeodatabase.com.br), suggests the presence of at least two active petroleum systems in the area: i) a marine anoxic Cenomanian to Turonian system and ii) a marine/lacustrine Aptian-Albian system. Both systems were observed in the deep-water wells drilled in the Pelotas (e.g., marine anoxic Cenomanian to Turonian; 1-BPS-6A-BP), Walvis and Orange basins (e.g., 1-Wingat-1-HRT and 1-Murombe 1-HRT; Figs. 3-6; Mello et al., 2013; Mello et al., 2015).
The 2D PSM of a seismic line (see location of line A in Fig. 9) calibrated with the geochemical data from 1-BPS-6A-BP suggests a transformation rate of 70% below 5,000-5,500 meters in depth for the Albian-Cenomanian to Turonian source-rock systems. In fact, if present, the source rock systems actually overlap each other, which could enhance the efficiency of hydrocarbon generation pods and migration charges in the area. Moreover, the 2D PSM data indicates that migration is occurring at “present day” in the ultradeep-water areas of Sector SP-AUP1. The 2D basin model demonstrates that the geometry of the mixed traps caused by gravitational tectonism in the blocks are prone to receiving hydrocarbons migrating from the deeper eastern external source-rock system depocenter (see fig. 9).
Another two exploration blocks from SP-AP1 were ranked as Priority 3, as there are several potential turbidity plays associated mixed traps caused by gravitational tectonism and the occurrence of gas and condensate seeps detected by diamondoids. As you can see, most of the blocks are located close to a main depocenter identified in the eastern area of these ultradeep-water blocks.
In summary, the integration of satellite oil slick, oil seep and advanced Geochemistry Technology (AGT) data and 2D PSM allows us to unequivocally suggest the presence of a working petroleum system in the area. Although the exploration risk is significant, the evidence points to significant opportunities for O&G exploration in this remote and unexplored province. Moreover, the results indicate that integrated multi-parameter surveys can improve the understanding of petroleum systems in frontier areas, potentially opening up a new exploration frontier.
The exploration blocks from sectors SP-AR1 and SP-AP1 that were not selected as Priority 2 or 3 were not ranked at all because we speculate the absence of working petroleum systems in their areas with the currently available data (Fig. 9).
At this point, it is very important to mention that HRT Petroleum (today PetroRio) found not only a Cenomanian to Turonian source-rock system, but also late/Aptian to Albian very thick and prolific source-rock systems in the Walvis and Orange basins. To our surprise, the oil recovered from well 1-Wingat-1-HRT presented biomarkers and extended diamondoid compounds that suggest contributions from lacustrine source rocks (see Mello et al., 2013; Mello et al., 2015). Therefore, we do not rule out the presence of a Sag marine/lacustrine overcharged source-rock system in the ultradeep waters of the northern Pelotas Basin. Although this assumption carries huge exploration risk, we believe the massive depocenter observed along the eastern limits of the basins could hold great surprises regarding an external source-rock hydrocarbon kitchen, but only a good drill bit will be able to confirm it.
Well, the ranking above should give you an idea of the speculative hydrocarbon potential of the deep and ultradeep waters of the Pelotas Basin on offer in October 2021. For those looking to dip a toe in, the BPS Geodatabase has all the data, analysis and knowledge your team needs to assess all these blocks in more detail before taking the plunge. And for those looking for extra knowledge and expertise for the rest of the Brazilian offshore basins, get in touch with BPS to learn more about our ongoing state-of-the-art 2D and 3D PSM studies of the Santos, Campos, Espírito Santo, Camamu-Almada, Potiguar and Ceará basins and the northern Equatorial Margin of Brazil.
Because nobody knows the pre-salt like BPS!