Abundant hydrocarbons have been produced from the pre‐salt lacustrine carbonates of the Cretaceous Barra Velha Formation in the Santos Basin of offshore Brazil. The highly heterogeneous lithology and pore systems make it difficult to predict the reservoir quality via petrophysical well logs. Core description, computed tomography (CT) scanning, thin sections and wireline well logs are utilized to characterize the lithology, pore spaces are reservoir quality of the Cretaceous Barra Velha Formation pre‐salt lacustrine carbonates in the Santos Basin. The results show that the lithology mainly includes shrubstone, grainstone, laminated micrite and massive micrite. The pore systems are dominated by secondary pores, such as intergranular pores, dissolution pores and intercrystalline pores as well as modified primary pores. Geological well logs (conventional well logs, electrical and sonic image logs and nuclear magnetic resonance [NMR] logs) are integrated to build the predictable models of the carbonate reservoirs. The shrubstone, which is dominated by intergranular pores, has the highest reservoir quality, which can be derived from NMR logs. Grainstone contains both primary intergranular pores and abundant secondary dissolution pores. The laminated and massive micrite contain only micropores and therefore have the lowest reservoir quality. Lastly, conventional well logs integrated with electrical and sonic image logs are utilized to predict the distribution of lithology and reservoir quality in single wells, and the results are testified by the NMR log data. The shrubstone and grainstone are future exploration targets of the Cretaceous Barra Velha Formation in the Santos Basin. The results are hoped to give insights into the petrophysical behaviours of various lithologies, and provide theoretical and technical guidance for reservoir evaluation and prediction.
The Santos Basin in Brazil is a hot area of oil and gas exploration in recent years, and its subsalt lacustrine mudstones are the main source rock of the basin. However, there is a lack of studies on the source rocks of the subsalt Picarras and Itapema formations, which is not conducive to the accurate evaluation of the source rock characteristics. Based on logging data of 51 wells and geochemical data of 16 wells, this paper makes detailed evaluations of the organic matter abundance, type, maturity, and distribution characteristics of source rocks of the subsalt Picarras Formation and Itapema Formation in the Santos Basin. The results show that the characteristics of source rocks of the Itapema and Picarras formations are similar, both of which have a high abundance of organic matter. The types of organic matter are mainly type I and II 1 , and the maturities are in the low-maturity to the high-maturity stage, which meets the standard of good source rocks. The total organic carbon content of the source rocks of the Picarras Formation ranges from 0.4 to 4.0%, much lower than that of the source rocks of the Itapema Formation, 0.8–5.6%. In addition, the hydrogen index average value of the source rocks of the Itapema Formation is 712.8 mg/g TOC, higher than that of the Picarras Formation, 697.5 mg/g TOC, both revealing a great hydrocarbon potential. The quality of source rocks of the Itapema Formation is better than that of the Picarras Formation. The two sets of source rocks have great hydrocarbon generation potential and are mainly developed in the eastern and western sags of the central depression. Therefore, the surrounding uplift areas will be the target for further oil and gas exploration.
The Santos Basin, located in the southeastern waters of Brazil, is a passive continental margin basin with the most abundant deepwater petroleum resources in the world discovered to date. However, few studies have been conducted on the present geothermal fields of the Santos Basin, which severely restricts the oil and gas resource evaluation of the basin. This study first utilizes 35 temperature data from 16 post-salt drilling wells and 370 temperature data from 31 pre-salt drilling wells to calculate the post-salt and pre-salt geothermal gradients and terrestrial heat flows in the Santos Basin. Then, the basin simulation software BasinMod 1D is used to quantitatively evaluate the impacts of salt rock sedimentation on the present geothermal fields and the maturity of pre-salt hydrocarbon source rocks. The results demonstrate that the present post-salt geothermal gradient in the Santos Basin is 2.20–3.97 ℃/100m, with an average value of 2.99 ℃/100m, and the post-salt terrestrial heat flow is 54.00-97.32 mW/m2, with an average value of 73.36 mW/m2, while the present pre-salt geothermal gradient is 2.21–2.95 ℃/100m, with an average value of 2.53 ℃/100m, and the pre-salt terrestrial heat flow is 61.85–82.59 mW/m2, with an average value of 70.69 mW/m2. These values are characteristic of a low-temperature geothermal fields in a zone with a stable structure. The sedimentation of the salt rock causes a decrease in the temperature of the pre-salt strata, which inhibits pre-salt hydrocarbon source rock maturity, with an inhibition rate of up to 1.32%. The inhibition degree decreases with increasing salt rock thickness. At the same time, the salt rock thickness is positively correlated with the present surface heat flow. The unique distribution of the salt rock and related salt structures lead to present terrestrial heat flow differences among different structural units in the basin. This study is of great significance for evaluating and exploring the pre-salt oil and gas resources in the Santos Basin.
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