The framework of the PSM project carried out by BPS was guided by seismic data and the source rocks and oils analyzed across the entire basin. The integration of all this data allowed the building of 2D PSM in Petromod, with the population of the lithofacies distribution maps based on the gross depositional environment (GDE) established by well correlations, sedimentologic attribute mapping and petrophysical quantification of reservoir properties. All the mapped leads (more than 20) were recognized by conventional practices and uploaded into the 2D PSM in their correct stratigraphic position to test the migration models and prospectivity of each. This multi-client 2D PSM and Exploration Risk Assessment allowed for the reconstruction and characterization of the active petroleum systems present in the deep-water domain of the basin. The integration of the elements and processes (relevant for thermal evolution of source rocks and oils, trap formation, oil and gas migration, oil and gas accumulation and preservation of the new frontier leads and prospect targets) are critical in reducing the drilling the exploratory risk in such an unexplored deep-waters area.
Twenty (20) dip-oriented (2,851 km) and six (6) strike-oriented (1,953 km) seismic lines covering an area of approximately 10,000 km2 using 4,804 km of 2D pre-stack depth migration (PSDM) seismic lines (ANP library) up to the 3,500 m isobaths were interpreted and mapped. The study area encompasses the shelf, slope and deep and ultra-deep-water domains, all calibrated with geological and geochemical data from 25 wells drilled in the Para-Maranhão Basin (Fig. 1).
The deliverables of the 2D PSM project include the mapped seismic surfaces in depth and time, digital models provided in Petromod format and gridded surfaces in depth used for modeling. The written report documents in detail the conceptual assumptions for the PSM model and simulation results, including spatial distribution of source rocks, reservoirs and seals, reservoir and source rock facies, source rock families and characteristics, quality and maturity of the source rock systems, kinetic reactions used, high resolution and advanced geochemical analyses of oil, gases and source rock organic extracts, oil & source rock correlation and identification and characterization of oil and source rock systems, 2D assessment of hydrocarbon migration over geological time, time of hydrocarbon charge, risk assessment for defined plays and leads (the potential of structural and stratigraphic traps has been quantified and evaluated), temperature maps of the main reservoir layers, diagrams of thermal and maturity calibration data, likely volumes and oil quality, including mass balances for the entire model, hydrocarbon generation, expulsion, oil and gas accumulation potential with AVO and DHI identification, as well as transformation ratio maps and 2D maturity and burial history plots and maps, among other products.
Figures 2–5 illustrate our take on the complex geological environment of the Para-Maranhão Basin. The mapped stratigraphic horizons were interpreted through the detailed seismic mapping of key horizons, including reservoirs, source rocks (e.g., Cajú Group and Codó Formation systems) and their associated fault systems: Transitional Crust, Basement, Top of Rift (lower Albian–Aptian), Top of Santonian-Turonian-Cenomanian, Top of Cretaceous, Top of Middle Eocene, Top of Middle Oligocene, Top of Middle Miocene and Seabed. Simulations of generation and migration processes were calibrated with geochemical data obtained from source rock and oil samples in order to correctly distribute their properties along the 2D PSM, aiming to address the complex oil mixing questions surrounding the oil accumulations discovered in the platform domain, as no well has ever been drilled in the deep-water domain of the basin.
As can be observed in the seismic sections shown in Figures 2 and 3, the Para-Maranhão Basin presents a complex structural and stratigraphic framework where Mesozoic and Cenozoic trap styles are controlled by transpressional, transtensional and gravitational tectonic processes. This tectonic regime gave rise to a restricted continental platform and deep depocenters with huge topographic variation limited by the transform, listric, thrust, strike-slip and oblique-slip dominated characteristics of the main faults.
The Upper Cretaceous Santonian to Upper Albian sedimentary record marks an important transgressive event that culminated in the drowning of the basin and the onset of deposition in the deep waters of the marine anoxic dominated Cajú Group, which is considered to be the most important source rock system in the basin. On the other hand, the Top of Cretaceous surface occurs as a detachment horizon noticeable in the dip-oriented seismic lines. This detachment surface is strongly controlled by the shelf break faults (such as the ones named “Slope 1” and “Slope 2” in Fig. 2) and controls the formation of large rollover anticlines (extensive domain) and snakeheads (compressive domain). It is important to note that the Eocene horizon acts as a décollement surface, preventing the transfer of the thrust belt compression (drape folds) of the Eocene sedimentary layers to the overlying Oligocene layers.
Figure 3 illustrates the seismostratigraphic pattern of the marine anoxic source rock system (Lower Albian to Santonian-Turonian age, Cajú Group) and lacustrine source-rock system (Aptian Codó Formation) in the ultra-deep waters. Both source rock systems are present in a huge depocenter in which they attained the ideal thermal stress to generate liquid and vapor hydrocarbons. Note that both source rock systems are deeply buried (below 7,000 m). Moreover, the seismic data shows the presence of a strong reflector located just below the basement, suggesting the thinning of the continental crust (i.e., the boundary between continental and oceanic crusts, potentially even marking the transition between them).
Figure 4 illustrates an example of the analysis of the transformation ratio simulated in a PSDM seismic dip line (102801) for both the marine anoxic Lower Albian to Santonian-Turonian (Cajú Group) and the lacustrine Aptian Codó Formation source rock systems. For location, see the red dip line in Figure 1. This simulation provides insight into the charge risk. Apart from temperature over time, the parameter is dependent upon source rock kinetics. Figure 4 displays the base case scenario of the present-day transformation ratios. As can be observed, both source rock systems present in the platform and the basin’s deep-water domain show transformation ratios ranging from 80-98%. In the base scenario, calculated by applying a heat flow of around 70 mW/m2 at rifting and 40 mW/m2 at present day, the Aptian Codó source rock has been significantly transformed or ‘cooked’, while the Cajú Group source rock retains the potential to generate and expel hydrocarbons today.
In the deep-water domain, the lacustrine Codó source rock generated all of its hydrocarbons at very early stages of the Cretaceous (before 100 Ma). There is little potential for entrapment of this charge for the Upper Cretaceous and Tertiary leads. On the other hand, the marine anoxic Lower Albian to Santonian-Turonian (Cajú Group) source rock shows generation and expulsion of liquid hydrocarbons around the K/T boundary, but the charge appears to be present in variable amounts throughout the entire Tertiary, also partly controlled by erosional events.
Figure 5 illustrates migration simulation results (base case scenario) of the same 2D PSM dip-line, in which the earliest active kitchen is located in the basin’s deep-water domain (outboard area). Charge is later present in the platform area, where a portion of the sources have reached the gas window (indicated by red, i.e., vapor, vectors). The accumulated hydrocarbons are roughly equally sourced from both source intervals (i.e., the Codó and the Cajú source rocks). Effective sealing within the overburden does not occur before the end of the Cretaceous. Before this, most hydrocarbons are lost at the surface. Apart from local migration focusing mainly to the slope area, the greatest part of the charge migrates to the Upper Cretaceous layers and not to the section further up (e.g., Tertiary layers). In the simulation, most accumulations occur in the lower part of the Upper Cretaceous sequence. The Tertiary play has not been charged due to effective sealing within the uppermost Cretaceous deposits.
In this simulation, a potential prospect located within Cretaceous turbidites is mainly charged from the upper (Cajú) source interval (85% of filling). The Codó source rock expels gas. A migration focus is present along a fault line (black arrows), although this fault is modeled to be of no significance at present day in this scenario. Hence, the migration pattern is due to geometric effects alone in this case. Analysis of the filling history of this trap shows that it was charged and filled over a long period of time, starting in the Early Tertiary and continuing to present day.
The mapping of leads in the Pará-Maranhão Basin was based on structural aspects, sequence stratigraphy, analysis of well data and seismic signal. In general, a “lead” is any indication or hint of the presence of a trap in the subsurface that may allow explorers to investigate it further. Figs. 6-8 show some of the exploration leads that were identified in the course of the 2D seismic volume interpretation and then integrated with the PSM, including the analysis of the geometry and integrity of their traps and seals, as well as their charge histories, including source rock tracking and assessment of trap integrity in relation to sealing. The reservoir quality and volumetric parameters were supported by log petrophysics data in combination with available MDT and DST data. MDT fluid data and pressure analysis were used for the identification of geopressure conditions, fluid type and formation factor values.
The data was used to derive stochastic volumes for all identified exploration leads, including risk analysis of individual opportunities and plays. Fluid expectations and amounts of oil and gas for each lead were crosschecked with the PSM and advanced geochemistry results, leading to a reasonable prediction of the potential oil and gas accumulations. The inventory includes more than twenty leads mapped in the rift and post-rift sections (Figs 6–8).
For the upper Albian-Cenomanian marine anoxic Cajú Group (Limoeiro Formation) system, the PSM results predict overcharged generation potential for liquid-prone hydrocarbons in both the basin’s platform and deep-water domains. In contrast, the lower Albian-Aptian lacustrine Codó Formation system represents an oil prone province on the platform and a gas-prone area in the deep-water domain.
According to the oil type distribution and the predicted source rock kitchens, the geographic limits of the late Aptian/mid-Albian – Upper Cretaceous (!) and late Albian/Cenomanian – Upper Cretaceous (!) petroleum systems appear to overlap each other. Both petroleum system kitchens and their extent of migration are widespread from the western to the eastern flanks of the Gurupi High. Oil mixtures from the two mentioned source rocks were identified and must originate from depocenters located at least partly in the deep-water domain. A marine anoxic light-oil prone province is expected for the entire Pará-Maranhão Basin. The oil quality is generally remarkable across the entire basin (API varying between 32° and 44°, with sulfur content always lower than 0.4). The biodegradation processes affected some oils, as suggested by the gas chromatography (GC) and biomarker data (GC-MS), but the evidence of multiple charge pulses having arrived in the reservoirs (as suggested by the coexistence of high n-alkanes and 25-norhopane) did not allow for significant deterioration of oil quality.
The 2D petroleum system modelling associated with seismic interpretation identified a large number of exploration leads potentially containing very high recoverable reserves. In contrast to the plays previously drilled in the basin that targeted Tertiary fractured carbonates, the biggest volumes of potentially recoverable hydrocarbons were related to plays within the Upper Cretaceous turbidites and syn-rift Albo-Aptian sandstones.
Although the seismic interpretation pointed to the existence of promising Oligocene leads, no commercial analogue was found in the South American or West African equatorial basins. While good quality turbidite reservoirs were identified in the shallow platform of the Brazilian Equatorial Margin, the best reservoir analogues were found and are concentrated in the deep-water domains of Guyana, Suriname and French Guyana, which present porosities above 30% and permeabilities up to 2 Darcy. In the Brazilian Equatorial Margin, no drilling campaign has ever been performed in the deep-water domain. Therefore, because of the remaining uncertainty related to distribution and quality, the reservoir constitutes the biggest exploratory risk for the deep-water domain of the Pará-Maranhão Basin.
The crucial play fairway mapping defined distinct areas with high exploration potential in the Pará-Maranhão Basin according to their particular risks. In some of these areas, different plays can overlap. For example, in the “Structured Tertiary and Cretaceous Play” area, the possibility of the existence of a rift lead cannot be excluded, although the charge risk is increased because of the high thermal evolution related to the Aptian source rock system. In a general way, the “non-structured Tertiary and Cretaceous plays” predominate in the basin’s deep-water domain, with the major risks being related to turbidite reservoir occurrence and quality as well as entrapment conditions (stratigraphic for all the drift leads). Deep rift-related targets do not present a high entrapment risk in the basin, but the likelihood of high gas/oil ratios increases the charge risk for liquid hydrocarbons. In the platform areas, two exploratory entities were defined: the “Eocene Carbonate Plays”, with the major risks being related to reservoir quality, which is conditioned by fracturing and hydrocarbon migration due to the very long distance to the generation pods located in the deep-water domain, and “Mixed Platform plays”, with the major risk being related to hydrocarbon migration and seal effectiveness. The slope region is dominated by the already mentioned “Structured Tertiary and Cretaceous Plays”, with risks related to several factors such as entrapment, charge, migration and seal being reduced in relation to all the other deep-water areas in the Pará-Maranhão Basin. Note that the reservoir risk appears to be high for the entire area, except in the “Mixed Platform Plays Area”, where promising well data exists.
In summary, all the giant deep-water discoveries in the Liza, Payara, Turbot, Ranger, Liza deep, Snoek, Pacora, Longtail, Hammerhead, Pluma, Tilapia and Haimara fields in Guyana, as well the Maka and Sapakara fields in Suriname, and the Zaedyus Field in French Guyana, have generated massive proven recoverable reserves of light oil. ExxonMobil alone has made 18 discoveries in the Stabroek Block since it began drilling in Guyana in 2015, now having more than eight billion boe in estimated recoverable resources in the block. This has turned a near-failure exploration frontier in the South American Equatorial Margin into a huge success. Also, those plays show tectono-stratigraphic evolution, source rock and reservoir systems as well as oil types similar to those present in the Brazilian Equatorial Margin and across the conjugate margin. By applying, in a paleogeographic context, a unified model, similar giant provinces to those observed in those basins must also occur in the underexplored Brazilian Equatorial Margin.
Finally, the PSM study performed by BPS in the Brazilian Equatorial Margin enabled the establishment of an unprecedented stock of leads and plays yet to be tested for this vast region. The recent discoveries in Guyana, Suriname and French Guyana, as well as in the conjugate margin analogous plays (Jubilee field in Ghana), enable interpretations to be performed with calibrated results. The new geochemical data analysis integrated with the 2D PSM for the deep-water areas of the Brazilian Equatorial Margin have also resulted in better evaluation of the risks and exploratory criteria for the selection of viable prospects even in areas from the deep-water frontier domain that lack well data.
There is no doubt that eventual drilling the deep-water domain of the Brazilian Equatorial Margin will reinforce the fate of the South Atlantic Equatorial Margin as a huge hydrocarbon exploration success story.