Over the last 20 years, oil companies started to proclaim gas geochemistry technology in petroleum exploration as miraculous indicators of the presence of large hydrocarbon accumulations in deeper reservoir horizons in unexplored sedimentary basins. A lot had happened, and technology was improved during that time, but still, gas geochemistry is very complex to sample and analyze. False positives and negatives, sampling reliability and, most importantly, preservation of sampling until laboratory measurement are critical factors.
BPS has performed gas studies in almost all onshore and offshore basins in Brazil. The results suggested that hydrocarbon compositional and gas geochemistry, when applied together with advanced geochemistry tools based on quantitative diamondoid analysis (QDA), were critical to determine gas origin, cracking, mixing, migration pathways and distance as well as characterize conventional and unconventional thermal maturity regimes in petroliferous basins. These gas technologies are the only ones capable of solving such puzzles.
For the study, all the methane to pentane gases were analyzed using high resolution gas chromatography (HR-GC) to measure gas composition and gas chromatography combustion isotope ratio mass spectrometry-GC/C/IRMS) for measuring carbon isotopic ratios (δ13C ‰; Prinzhofer et al., 2000; Prinzhofer et al., 2002). Using these technologies, it is possible to identify and differentiate gas origin (e.g., bacterial & thermogenic), type, mixing, conventional & unconventional thermal maturity, gas segregation, primary to secondary cracking and migration pathways and distance.
Today, as an example for the BPS newsletter, we are showing the application of gas geochemistry in Brazil’s Paleozoic onshore Paraná Basin.
Figure 1 shows a location map of the wells in the Parana Basin (e.g., 1- BB-1-PR (Barra Bonita), 1-MR-1-PR (Mato Rico; 2700m and 2550 m) and 1-RCA-1-PR) from which gases have been recovered and reported. It is important to mention that after almost 70 years of exploration and a total of 124 wells drilled, the only commercial hydrocarbon accumulation found in the Paraná Basin is the Barra Bonita gas discovered by well 1-BB-1-PR discovered by Petrobras (e.g., Barra Bonita gas Field). Gases from wells 1-CB-1-SP, 1-RO-1- PR, 1-CS-2-PR, 1-RP-1-PR, 1-RCH-1-SC, 1-MC-1-SC, and 1-LV-1-RS have also been recovered, but their analyses have not been reported.
It is well reported that there are two main potential source-rock systems in the Paraná Basin: the middle to Upper Devonian black shales from the São Domingos Member of the Ponta Grossa Formation; and the middle Permian black bituminous shales and marls from the Irati Formation (Fig. 2; Araujo et al., 2000 and 2005; Milani et al., 2007).
The upper Devonian Ponta Grossa Formation (São Domingos Member) is the same geologic age as the most important Paleozoic petroleum producing source rocks elsewhere in Brazil, South America, North America, and Russia (Fig. 2). Normally, the potential source rock presents a thickness ranging from 75 to 150 meters in the depocenters. Although the upper Devonian Ponta Grossa organic-rich sediments correspond to a world class source rock time interval, it is not as rich as observed elsewhere. In the northern area of Paraná Basin, where it is thermally immature, the original Total Organic Carbon (TOC) content ranges from 1.0 to 3.5%, the organic matter is type III/II, with predominantly moderate generation potential (S2 values between 2.0 and 6.0 mgHC/g Rock) and a hydrogen index (HI) of up to 350 mgHC/gTOC (G). Due to the thermal effect of diabase intrusions observed in most areas of the Paraná Basin, the TOC and pyrolysis data represent residual values, and therefore the original (restored) values were certainly higher.
Regarding the original organic matter, maceral geochemistry indicates that most of the upper Devonian Ponta Grossa organic-rich sediments contain a marine algal amorphous material. Compared to lower Devonian sediments, this interval is thicker and presents better organic matter preservation in the depocenter of the basin. However, at this location, the Ponta Grossa sediments are expected to be in the overmature gas window kitchen because of igneous intrusions associated with thermal subsidence, as shown by the high transformation ratio values in these areas depicted by basin modeling (Araujo et al., 2000 and 2005; Milani et al., 2007).
The other main potential source rock in the Paraná Basin is the middle Permian black bituminous shales and marls of the Irati Formation (see Fig. 2; Araujo et al., 2000 and 2005; Milani et al., 2007). The Irati Formation black bituminous shales and marls were deposited during the lower Permian in a shallow, anoxic marine/lacustrine hypersaline depositional environment intercalated with beds of limestone and dark gray shales deposited in oxic environments. The Irati organic-rich section is composed of two very thin layers of black, organic-rich, marine shales with a total thickness up to 30 meters at most (Fig. 2). The sediments have TOC values varying between 5 and 15%, with peaks reaching up to 25% (Fig. 26). The potential yield values (S2 from rock Eval) reach up to 100 mgHC/g Rock. The Irati source rock, in normal burial conditions, has a low degree of thermal maturity, as indicated by the pyrolysis and biomarker data, or an overmature stage when thermally altered under local influence of igneous sills. The effect was such that all the hydrocarbons related to the Irati source rock system are linked to unconventional cracking processes caused by igneous intrusions, therefore the gas window kitchen is expected in areas where the igneous intrusions occur inside the Irati Formation, as also shown by the high transformation ratio values in these areas. Oil window kitchens are predicted in the eastern part of the basin, and they are consistent with the occurrence of oil shows in wells and tar sands (Kern et al., 2005; Milani et al., 2007).
Figure 3 illustrates a geochemical plot using the results of gas chromatography (GC) and carbon isotope (δ13C ‰) analyses of the studied gases (see Fig. 1 for location). As can be observed, all the gases presented dominance of methane (> 91%) over the C2+ gases, and values of δ13C of methane heavier than -31.50 ‰. Such data suggests an overmature thermogenic origin for all gases.
The plot of Carbon Isotopes (δ13C ‰) of methane vs. ethane+ illustrated in Figure 4 shows the correlations of the gases recovered in the Barra Bonita, Mato Rico (e.g., depths at 2,550 m and 2,700 m) and 1-RCA-1-PR wells (Figs. 1 and 4). As can be observed, almost all gases analyzed present values of carbon isotopes (δ13C ‰) of methane heavier than the ethane, showing an inverse trend of maturity compared with generation by thermal subsidence (e.g., the higher the carbon number, the heavier the carbon isotopes values (δ13C ‰). This kind of data is diagnostic of gas generation through contact by igneous intrusions. As can be observed, the carbon isotopic data of Methane vs. Ethane show an inversion trend of carbon isotopes (*methane δ13C heavier values when compared with the ethane+ values, indicating gas generation through contact by igneous intrusions, like most of the gases recovered and analyzed in the Parana Basin). These δ13C data indicate the presence of overmature gases with atypical thermal maturity origin where the gas generation occurred by contact of the source rocks (SR) with igneous intrusions, and not through conventional thermal subsidence (Figs. 3 and 4; gas cracking to gas; Mello et al., 2000; Prinzhofer et al., 2000; Kern et al., 2005).
The presence of overmature gases with atypical thermal maturity origin where the gas generation occurred by contact of the source rocks (SR) with igneous intrusions is widespread for all gases recovered in the entire Parana Basin.
Figure 5 shows an ideal working petroleum system for the Ponta Grossa and Irati source rock systems in the Parana Basin. The schematic figure shows the upper Devonian Ponta Grossa source rock system deposited in an anoxic marine siliciclastic epicontinental depositional environment. The generation occurred mainly because of igneous intrusions inside and around the potential source rock. The result is the pyrolysis of the organic matter generating an overmature atypical dry gas. The migration and accumulation processes are very ineffective since the igneous intrusions allowed the leaking throughout the igneous intrusion’s fractures and rift faults that percolated from the basement normal faults through the Serra Geral Formation.
Such atypical generation/migration/accumulation processes are very complex and ineffective to form gas accumulations, because the older the time of residence of gas in the reservoirs, the higher the leaking processes from the gas accumulations is. Also, in the absence of salt/perfect seal, the leaking factor is critical for preservation of commercial gas accumulations. The only commercial accumulation system in the basin occurred in the Barra Bonita Field, where a gentle sill anticline acts as a trap caused by the igneous intrusions, although there is a contribution of a stratigraphic sandy channel in the lowermost portion of the package. It is also important to mention the role of the diabase sill sealing the structures in the basin. Although there are several stratigraphic and structural types of traps/seals in the basin, it appears that the Barra Bonita model is and will be the most important (Araujo et al., 2000 and 2005; Kern et al., 2005; Milani et al., 2007).
The presence of overmature gases with unconventional thermal maturity origin where the gas generation occurred by contact of the source rocks (SR) with igneous intrusions is widespread for all gases recovered in the entire Parana Basin up to now.
Figure 6 shows a diagram of ethane/propane versus ethane/Iso-butane compositional ratios obtained from GC analyses showing the correlations of the gases recovered in the Barra Bonita and Mato Rico wells. Such a plot is commonly used to show the effects of biodegradation in the heavier hydrocarbon gases, mainly in the propane and iso-butane if present. Also, thermal maturity breaks the higher gas molecules, increasing the lower carbon number molecules. Observe the absence of gas biodegradation in all the gases and a clear increased maturity trend from the Barra Bonita gases towards the Mato Rico gases at 2,700m, and to the shallowest Mato Rico accumulation (e.g., gas at 2,550m). The presence of the most mature dry gas at the shallowest part of the Mato Rico reservoirs (e.g., sample from 2,550 m) suggest a complex migration and gas fractionation process in the area (Mello et al., 2000; Prinzhofer et al., 2000).
Figures 7 and 8 show an example of the critical importance of using of gas composition and carbon isotope data to identify and characterize oil origin, thermal evolution, cracking stage, and migration pathways from gases taken from the Campo Mourão and Rio Bonito reservoirs in the Barra Bonita, RCA, and Mato Rico wells. As can be noted in Figure 7, the gases from all fields show a maturity trend going from the primary cracking of the kerogen (e.g., gases from Barra Bonita Field) to an extremely overmature generation stage where secondary cracking of oil, NSO components and gas occur (e.g., gases of Mato Rico Field). This data suggests the presence of a very complex petroleum system in the area, where source rock systems have been subjected to a very extreme thermal evolution stress. In the Parana Basin, the unconventional thermal maturity is caused by the influence of Igneous intrusions (e.g., see above Fig. 5). This gas system is generally composed of gas mixtures that have been generated by igneous bodies with different size, type, and distance from the source rocks (Mello et al., 2022).
By correlating the gas data of the Barra Bonita and Mato Rico wells with geological data, these gases were sourced from the upper Devonian, Ponta Grossa marine siliciclastic source rock system. On the other hand, the principal component analysis (PCA) representation of the gas data of the Barra Bonita and Mato Rico wells in Figure 8 suggests that the gases from Barra Bonita are much less mature than those from Mato Rico, having migrated a short vertical distance from a deep local source rock pod. The presence of a broad range of thermal evolution is directly correlated with the thickness and distance of the igneous bogies to the source rocks (see Figs. 6–8; Mello et al., 2000; Prinzhofer et al., 2000). In summary, the gases from the Mato Rico shaliest reservoirs (e.g., at 2,550m) are much more mature than all the other gases, suggesting a fractionation process, compared with the gases of the deepest Mato Rico reservoir (e.g., at 2,700m). This indicates origin from a deep source pod, probably located close to the area. This interpretation indicates how important gas geochemistry is in supporting a better understanding of the petroleum system in the basin, and therefore in streamlining exploration strategy and lowering exploration risk.
In summary, the Parana Basin presents at least two atypical gas prone petroleum systems: upper Devonian Marine Epicontinental (Ponta Grossa Formation) and Middle Permian, Marine Hypersaline (Irati Formation). The gas systems present an origin caused by an atypical generation process in which thermal maturity is caused by igneous intrusions affecting the potential source rock layers and not by thermal subsidence.