This week, we share our rankings of the ultradeep-water blocks in the Campos Basin on offer in ANP’s 17th Bidding Round in October. The basin is located along the coast of São Paulo, Rio de Janeiro and Espírito Santo states in the Southeastern region of Brazil and covers an area of about 300,000 km2 up to 3,000 m isobath.
To get situated, Figure 1 is a map of the Campos Basin showing sectors SC-AP1, SC-AP3 and SC-AUP2 with their respective ultra-deepwater exploration blocks selected for ANP’s upcoming auction.
Oil and gas exploration started in the Campos Basin during the 1970s. After almost 50 years and the drilling of more than 3,480 wells, with discoveries of supergiant oil fields such as Marlim and Albacora in marine Tertiary and upper Cretaceous sandstone turbidites of the post-salt sequences, the exploration campaigns came to a near halt in 2013-2015. Over the last three years, only four (4) exploration wells (e.g. 1-BRSA-1377-RJS, 1-BRSA-1376D, 1-BRS_1375-RJS and 4-BRSA-1372-RJ) were drilled in the basin (Figs. 1–2).
For almost 50 years, the Campos Basin was considered the “Crown Jewel” of petroleum exploration in the South Atlantic realm. With almost 13 billion bbl of oil produced to date, reminiscent oil reserves of about 6.1 Billion bbl (e.g., 3P; source ANP/BDEP), bbl and current production of around 922,809 boe/day, Campos still ranks as the second most productive basin in Brazil, only behind Santos (Figs. 1 and 3–4). It is very important to mention that almost 95% of the oil and gas produced thus far has come from the Tertiary and upper Cretaceous turbidite sandstone reservoirs in the drift sequences. This is due to the presence of huge turbidite reservoirs in these sequences, along with excellent quality seismic visualization of the shallow turbidity reservoirs in these horizons and the advancements in drilling technology. Despite the abundance of extensive oil accumulations in the marine turbidites of the post-salt sequences, it is critical to understand that almost 99% of the oil and gas discovered in the Campos Basin to date was generated in and migrated from the deeper Rift pre-salt lacustrine source-rock systems of the Barremian Lagoa Feia Group (composed of upper Barremian Coqueiros and lower Barremian Atafona formations).
The main reason for shutting down exploration in the Campos Basin was the discovery of the super-giant pre-salt Tupi field in the mid to late Aptian microbiolite carbonates of the Barra Nova and upper Barremian coquinas of the Itapema formation in the neighboring Santos Basin in 2006. This discovery in the lacustrine carbonates of the pre-salt sequence shifted all exploration efforts to Santos. Over the years that followed, several supergiant oil fields were discovered using the same play concept, including Sapinhoá, Guara, Lapa, Iara, Sepia, Atapu, Sururu, Berbigao, Carcara, Jupiter, Búzios and Mero, among others. These fields showed similar reservoir performance to the Tupi field, producing an average of more than 20,000 bbl/day per well, with some of them producing as much as 48,000 bbl/day (e.g., 9-ATP-1-RJS – February 2021, ANP Bulletin). To give you an idea of how prolific the pre-salt play in the Santos Basin is, it produced more than 70% of Brazilian daily oil and gas output in February 2021 (Source ANP/BDEP).
The lessons learned in the Santos Basin suggested that the search for new Tertiary and upper Cretaceous accumulations in the Campos Basin, following the post-salt marine sandstone turbidite concept, would not be as successful as the “hunt for the sleeping giant” pre-salt mid to late Aptian microbiolite hydrocarbon accumulations in the deep horizons below production areas, near-field exploration around production areas and, most importantly, the frontier acreage in the ultra-deep waters to the east of the currently producing oil fields (e.g., Picanha cluster). Furthermore, because of the success in Santos, the turbidite reservoir paradigm hindered the adoption of new and more productive paradigms, in particular the call to “Go Deeper” to hunt for the pre-salt sequences (Mello et al., 2020).
In the years that followed, Petrobras started hunting pre-salt targets in several areas of Campos, making significant discoveries in the northern portion of the basin such as Jubarte, Baleia Ana, Deep Marlin South and Roncador, etc., where the pre-salt production from the mid to late microbiolite oil fields today is around 174,576 boe/day (e.g., Fig. 4).
Over the last five years, ANP started auctioning off exploration blocks in the Campos Basin again during its 14th and 15th bidding rounds, aiming to leverage the pre-salt petroleum system concept (Figs 1 and 5). The blocks located in the eastern area of currently producing oil fields (e.g., Picanha cluster) cover an area of approximately 11,193,748 km2 and are considered one of the most prolific areas of the basin for pre-salt reservoirs (Figs. 1 and 4). The auctions attracted most of the world’s oil majors and were very competitive, with 17 exploration blocks being scooped up and the signing bonuses surpassing a total of approximately US$3.5 billion, making the auctions a huge success. (Figs. 1 and 4).
As a result, oil majors including Petrobras, Shell, ExxonMobil, Total, Chevron, BP and Repsol, among others, acquired 17 blocks in the 14th and 15th concession rounds (Fig. 1). In the years that followed, only four wells were drilled (e.g., 1-BRSA-1377-RJS, 1-BRSA-1376D, 1-BRS_1375-RJS and 4-BRSA-1372-RJ), with most of them showing very promising results, proving the occurrence of a working petroleum system in the upper Barremian source-mid to late Aptian reservoirs. However, most of the recently acquired blocks have not yet been tested, making their hydrocarbon potential very uncertain. The most significant factor will be to confirm the widespread presence of the lacustrine pre-salt mid to late Aptian reservoirs (Barra Nova Formation) and the upper Barremian lacustrine source-rock system of the Itapema Formation across the entire area. It is important to mention that the ultra-deep waters of Campos are still relatively unexplored in terms of source-rock thickness, quality, thermal evolution and charge volumes, major factors to lower the exploration risk in this huge frontier.
And now for our rankings…
The exploration rankings of the blocks on offer in the 17th Bidding round were based on a solid foundation of data and knowledge from the BPS Geodatabase (turning data into information to build knowledge !) of the entire nearshore and deep-water mature area of the Campos Basin, including 2D and 3D PSM covering the main production area and, most importantly, the eastern frontier acreage in the ultra-deep waters.
It is important to mention that only three (3) wells have been drilled in close proximity to some of the blocks on offer in the 17th Bidding Round, so the exploration risk analysis performed here was calibrated using the elements and processes from the resulting pre-salt petroleum system data of these wells together with the results of other oil wells in the mature areas, like the central and northern portion of Campos (Fig. 1 and 5-9).
Figure 5 shows an oil vs. oil correlation using advanced geochemical technology (AGT) of an oil recovered at 5,006 m in the mid-late Aptian microbiolite carbonate reservoir by well 3-BRSA-944A-RJS (Buzios Field), oils from the Tupi and Mero fields (not identified here) in the Santos Basin and an oil recovered at 4,356m in the mid-late Aptian microbiolite carbonate reservoir by well 3-BRSA-1054D-RJS (Marlim Leste field) in the Campos Basin. As you can see, despite being from two different basins and more than 500 km apart, they present absolutely identical biomarkers (e.g., Gammacerane index) and compound specific isotope values of d13C-C29 hopane (CSIA-Bh).
This confirms that the upper Barremian overcharged source-rock system with identical euxinic organic facies is widespread across the entire Campos and Santos basins. Moreover, Biomarker Technologies/BPS have proven that the very light isotope ratios of biomarkers (e.g., d13C-C29 hopane <-36‰), especially hopanes, are uniquely sensitive to reveal the details of an almost epi-continental lacustrine body containing stratified euxinic water columns giving rise to anoxic depositional environments that cross all the depocenters of the pre-salt sequences of the Santos, Campos and Espirito Santo basins (Moldowan and Dahl, 2019; Moldowan et al., 2019 and Mello et al., 2020). The CSIA-Bh technology is an incredible method to distinguish among very similar organic-facies and biomarker patterns and assign the proper oil to source-rock relationships. Therefore, we consider the occurrence of the overcharged upper Barremian source-rock system in the eastern ultra-deepwater area in and around the blocks on offer in the 17thBidding Round to be very promising (Fig. 1 and 5).
Figures 6 and 7 show gas data from the Marlim and Albacora oil fields. As you can see, the gas samples recovered from both fields show origins from the primary cracking of kerogen and NSO compounds mixed with secondary oil cracking and, in some samples from Marlim, secondary cracking of gas (Fig. 6). This suggests that most of the samples are wet gases, but some of the Marlin field gases migrated from very deep source rocks or deeper gas accumulations. According to a PCA study (Fig. 7; e.g., see Prinzhofer et al., 2000), when the gas values are presented for two synthetic V1 (maturity) and V2 (migration) parameters, the plot suggests short-distance deep vertical migration for the Albacora field wet gases and lateral long-distance migration for the Marlim East dry gas samples (see Mello et al., 2000). These results concerning gas maturity, gas migration pathways, gas segregation and gas migration distance and direction provide a unique method for evaluating the charge component in the petroleum system concept (Fig. 7). Indeed, when integrated with advanced geochemistry technology such as diamondoids, CSIA-B and CSIA-D and QUEDA (see Moldowan et al., 2020), 2D and 3D PSM and geological and seismic data, it suggests a short vertical migration charge pathway for the Albacora complex and a long-distance horizontal migration charge pathway for the dry overmature gases from the very deep Barremian depo-pods located to the east of the Marlin East complex.
Indeed, the basement map (Fig. 9), which acts as a proxy for the presence of mature to overmature source rock in the structural lows and potential pre-salt reservoirs and traps in the structural highs, suggests the presence of several active source rock depo-pods associated with the eastern regional external lows bordering most of the blocks on offer in the 17th Bidding Round. When integrated with the oil slick and 2D Petroleum system basin modeling performed by BPS, it allowed for the estimation of hydrocarbon risk along with our resulting rankings, which range from 1 to 3 (higher to lower priority).
Two exploration blocks from sector SC-AP1 (C-M-107 and C-M-109), were ranked as Priority 2 due to their association with structural highs (e.g., presence of reservoirs and trap/seal features, oil slicks detected by Radarsat satellite imaging and proximity to a major depo-pod suggesting the presence of a Barremian oil prone source-rock system). These blocks are in the salt-ramp and salt-diapir domains where the active oil prone upper-lower Barremian source rock kitchen is present, ranging from 5,200m to 8,000m in depth (see Figs. 9 and 11). In the salt-ramp and salt-diapir domains, the first pulse of oil generation/expulsion from the Barremian source-rock systems started very early, between 105–100 Ma and extending until 90 Ma. In general, the upper and lower Barremian source units were completely transformed into hydrocarbons. It happened in a single pulse in the deepest depocenters, but other pulses are predicted to have occurred in the salt-ramp domain at around 70-58 Ma and 20 to 0 Ma.
Two blocks from sector SC-AP3 (C-M-279 and C-M-348) and one block from SC-AUP2 (C-M-481) were ranked as Priority 3 due to their association with structural highs, their proximity to oil slicks detected by Radarsat satellite imaging and the presence of a working pre-salt petroleum system confirmed by the results of recently drilled well 1-BRSA-1377-RJ in block C-M-411. The C-M-279 and C-M-348 blocks are in the salt-diapir domain where the active oil prone upper–lower Barremian source rock kitchen is predicted to occur at depths ranging from 5,000m to 7,500m (see Figs. 9–11). These Priority 3 blocks are associated with a salt-diapir domain where salt-diapirism was intense during most of the Tertiary times. The presence of a continuous salt layer probably sealed all the fluids within the rift sequences. With this in mind, it is important to note that one of the major challenges of the analysis of areas in the salt-diapir domain is the lack of high-quality seismic data to visualize the pre-salt sequences. The acquisition of high-quality 3D PSDM that can image below the salt layer will be key to better analyzing these blocks. Therefore, reservoir quality appears to be a key exploratory risk in these areas.
Hydraulic fracturing of salt sequences might have broken the salt layer in order to dissipate excess pressure. In the salt-diapir domains of these blocks, the first pulse of oil generation/expulsion from the Barremian source-rock systems appears to have started very early, between 117–100 Ma, extending until 90-80 Ma. In general, the Barremian source rock was completely transformed into gas and condensate hydrocarbons. This, in turn, suggests that the hydrocarbons were expelled from a post-mature source-rock pod to the extent of being in the dry gas window. With this level of advanced maturity, one can conclude that the charge to the pre-salt reservoirs in this deep domain of the basin would consist mainly of dry gas.
All the other blocks were not ranked due to their very high exploration risk regarding fluid type (e.g., mainly dry gas prone), reservoir quality, excess reservoir pressure, location in the ultra-deep waters and relation to ramp-salt-diapir domains (Fig. 9).
Figure 10 shows a 2D Kirchhoff Pre-SDM Dip seismic deep focus line from TGS that crosses several blocks of sectors SC-AP3 and SC-AUP2, suggesting the presence of structural closures at the base of the salt and seismic facies analogs similar to the ones related to the pre-salt microbial carbonate reservoirs present in the pre-salt sequence in the Santos Basin. The presence of marked parallel planar reflectors right beneath the salt is suggestive of deposition in a carbonate-ramp environment (see Zalán and Newman, 2020).
Figure 11 shows a map depicting all the state-of-the-art 2D and 3D seismic surveys performed by TGS in the Campos Basin (for seismic data, contact TGS).
Figure 12 shows an example of the migration direction and oil saturation analysis at present day using BPS 2D petroleum system modeling (for location see Fig. 9). The line is located in the Northern Campos Basin and stretches from the nearshore to the ultra-deep waters up to the limit of the Aptian Salt sequence.
Integration and interpretation using the BPS Geodatabase with the 2D PSM line modeled in the northern Campos Basin crossing sector SC-AP1 (see figs. 9 and 12) suggest the presence of an active Barremian lacustrine oil-prone petroleum system (e.g., upper Barremian Coqueiros and possibly lower Barremian Atafona formations) ranging from depths of approximately 5,200–8,000 meters in the salt-ramp and Salt-diapir domains (Fig. 12). In fact, if present, both the upper and lower Barremian source-rock systems actually overlap each other, which could enhance the efficiency of hydrocarbon generation pods and migration charges in the area.
The evidence of working pre-salt oil and gas systems points to significant opportunities for O&G exploration in this remote and unexplored province. Moreover, the results indicate that integrated multiparameter surveys can improve the understanding of petroleum systems in frontier areas, potentially opening up huge exploration frontiers, as is the case with the pre-salt sequences in the ultra-deep salt-diapir domains of the Campos Basin.
Well, we hope that gives an idea of the major exploratory risks related to the blocks on offer in the Campos Basin in ANP’s upcoming 17th Bidding Round next October. For those looking to dip a toe in, the BPS Geodatabase has most of the data and analysis your team needs to assess these blocks before taking the plunge. And for those looking for extra expertise, get in touch to learn more about the possibility of performing state-of-the-art 3D PSM studies of this area of the Campos Basin. Please note that BPS is also organizing a detailed oil slick, piston core, heat flow and oil/gas chimney project to be launched around June covering all the selected Priority 1 and 2 blocks on offer in October. The results will be ready for delivery by August 2021.
Nobody knows the pre-salt like BPS!