The reservoir characterization of the Brazilian Santos Basin’s pre-salt carbonates is a major challenge due to the faciological and depositional complexity, providing high lateral and vertical heterogeneities, and consequently, the formation of static/dynamic intraformational seals. Regarding this context, there is a massive pre-salt accumulation known as the Iara Cluster. During the early development stage, this cluster was split into three distinct accumulations named Berbigão, Sururu, and Atapu. This study aims to characterize the geological and hydrodynamic factors that affect the Iara Cluster reservoir compartmentalization. To achieve this objective, we applied an integrated analysis based on 3D seismic interpretation, well logs, pressure formation and fluid geochemistry analysis. The spatial distribution of the reservoir range’s five main seismic patterns indicates potential stratigraphic-structural barrier zones. The well log analysis correlated with formation pressure data enabled the identification of several irregular oil-water contacts and free water levels. Small relative variations are associated with the perched-water phenomenon, while large variations are related to compartmentalization. The formation pressure analysis shows the hydraulic compartmentalization of the reservoirs in the Berbigão Field. Sururu and Atapu fields’ oil zones are possibly connected by a dynamic sealing zone or a common aquifer, which provides a pressure balance on a geological time scale, since their oil gradients are similar. Our analyzes identified stratigraphic components in reservoir trapping associated with reservoir quality lateral obliteration. Dissimilarities in the oil sample composition and properties indicate different petroleum charge histories along with the distinct CO2 contamination timing. The Berbigão oil-associated gas formed in earlier stages of maturation than the Sururu and Atapu samples. The results integration through a risk matrix revealed areas with a greater chance of compartmentalization and perched-water phenomenon. Our study highlights the importance of multidisciplinary analysis to comprehend complex carbonate reservoirs connectivity, and offers input to de-risk new ventures’ pre-salt reservoir quality.

This work aims to improve the understanding of how fracture zones affect carbonate reservoir properties based on observations of a pre-salt well located in the Santos Basin, Brazil. The identification of fracture zones allowed for the observation of a relationship between the occurrence of rock fractures and the silicification, as the latter plays an important role in determining porosity (higher silica content may increase brittleness of the rocks therefore increasing the likelihood of creating fractures zones and fractures may be filled up reducing the total porosity). To support the proposed observation, an integrated study was conducted using borehole imaging, spectroscopy logs, and sidewall core samples. The porosities were defined using nuclear magnetic resonance log analysis, alongside sidewall core samples, and thin sections. The integration of rock samples and well data with seismic analysis was performed to analyze the presence of a regional fault system that could explain high fracture densities as well as observed silica content characteristics. The results show how different types of cement filling up the formation pores affect fracture densities and total porosity. Furthermore, it was possible to infer that the amount of silica content observed in well logs and thin sections relates to hydrothermal fluids reaching out the reservoir through regional fault systems detected in the seismic section. Therefore, this paper supports the comprehension of how diagenetic processes can significantly affect the properties of pre-salt reservoirs.

Preconditioning is a practice adopted in the treatment of seismic data and, when properly applied, favours a resolution increase. However, retrieving all the frequency contents is still a challenge to overcome. Techniques to improve the seismic resolution should preserve the existing relations in the distribution of seismic events. Otherwise, it may cause undesirable situations, from the degradation of the signal-to-noise ratio to the creation of false events, leading to errors of interpretation. We developed a method called spectral stacking, which makes use of circular convolution in the frequency domain to extend frequency content, preserving the distribution of seismic events without adding artefacts. As an application of the spectral stacking method, we create a sharpening filter that resolves layers under Ricker’s criterion. In addition, the sharpening filter preserves the amplitude using a variable-window correction based on the local minima of the absolute values of amplitude. We validated our proposed method in synthetic and real tests. The results showed that the sharpening filter obtained a resolution increase, providing a sharper image of the seismic section.

Reservoir characterization is a valuable tool for the oil and gas industry. A better understanding of the reservoir demands the integration of petrophysical properties and elastic parameters. This integration is commonly performed with the aid of rock physics models. The elastic properties of solid-phase components are important parameters for rock physics models calibration. In this paper, we use an adaptation of mineralogical inversion to estimate the volumes of quartz, feldspar, and clay minerals that incorporate previously calculated clay volume and porosity. Clay volume estimation is performed from neutron and bulk density logs. We chose this method due to the presence of feldspar minerals in the reservoirs. Our workflow consists of petrophysics properties estimation, mineralogical inversion, rock physics model calibration in Well A, and compressional-wave velocity estimation in Well B. The mineralogical inversion in Well A provided average volumes of 64% quartz and 16% feldspar and previously estimated 20% clay minerals. When applied to Well B, the calibrated soft-sand model is a better approximation for high porosity data points than the constant-cement model, and the error between original and estimated logs is about 2.9%, suggesting that the approach can be extended to other wells in the study area.

The Parnaiba Basin, even being a new frontier basin, it’s already one of the most profitable for natural gas in Brazil. The shallow marine sandstones of the Poti Formation are the main gas reservoirs at Park of the Hawks. These reservoirs hold anomalously low resistivities which directly impacts water saturation calculations and leading to underestimations of their true potential as gas reservoirs. We propose a method for the characterization and mitigation of the problem and for the correction of the resistivity log based on the case study of well PGN-5, seeking to obtain more adjusted results for the reservoir evaluation. The methodology used is based on the integration data, where the main inputs were drill cuttings samples, well logs, gamma-spectral data and geochemical analyzes through X-rays fluorescence. We observed that the presence of pyrite and clay minerals are the causes of the low resistivities, still in the presence of gas-charged intervals, attested by crossover between density and neutron logs and through pressure gradients data. We propose a correction factor for the resistivity log in the anomalous low resistivity zone, allowing a new evaluation of the well, leading to a significant reduction in water saturation and a remarkable net pay gain.

“The authors propose an approach that uses machine learning to characterize car¬bonate facies in a wildcat (Gato do Mato) prospect in the Santos basin, offshore Brazil. We analyzed different seismic at¬tributes and selected those that best re¬sponded to the seismic patterns identified in the study area as input for an unsuper¬vised classification. The classification method used is the self-growing neural network (SGNN) tech¬nique that consists of the following steps: 1. Seismic pattern identification in seismic amplitude. The main patterns identified are build-up, debris, carbonate platform and bottom lake facies. 2. Generation and analysis of seismic attributes to characterize seismic patterns. We chose Eigen coherence, dip-steered enhancement, relief and relative acoustic impedance to help in seismic characterization. 3. We performed principal component analysis (PCA) of the attributes: amplitude filtered from dip-steered enhancement (seismic-driven structural filtering), Eigen coherence and relief. 4. Unsupervised seismic classification from the PCA of seismic attributes (item 3 above). Using this approach, we associated the classified seismic facies with the patterns identified in the amplitude data. The seis¬mic facies allowed us to differentiate the carbonate platforms from the build-up fa¬cies. However, the classification encoun¬tered difficulties in identifying the patterns associated with lake bottom facies and the chaotic seismic pattern of debris facies. ”

The identification of potassium (K) and magnesium (Mg) salts prior to the well drilling is a key factor to avoid washouts, closing pipes, fluid loss damage, and borehole collapse. The Bayesian classification combines the outcomes from statistical rock physics and seismic inversion, providing the spatial occurrence of the most-probable salt types. It serves as a facies identifier of Mg–K-rich salts (bittern salts) before drilling. Nevertheless, the most-probable classification is limited to the seismic resolution which may underestimate seismically thin-layer thicknesses. Along with the most-probable facies, the Bayesian classification renders the facies probability volume. We demonstrate that the facies probability and facies-specific total thickness highly correlate to each other even under the threshold of seismic resolution. Thus, we employ the bittern-salts probability volume to predict thin-bed bittern-salts thickness in undrilled locations. To capture the variability of the seismic estimation, we resort to Monte Carlo-assisted simulations of wells that emulate the layering patterns of a site-specific deposition environment. These simulations are crucial to assist the estimation of the joint probability density function between the facies volume and the total thickness. Therefore, given the facies probability, the joint probability density function enables us to derive the conditional expectation and percentiles of thin-bed thicknesses. Furthermore, this paper proposes a method to quantify the negative influence of seismic noise in the estimation of thin-bed thicknesses. The blind well confirms the consistency of this technique to unfold the uncertainty in the seismic predictability of thin layers. We argue that this procedure is extendable to other facies.

Brazilian presalt carbonate reservoirs are highly heterogeneous. This feature is mostly justified by the nature of the original depositional system and subsequently diagenetic processes. Consequently, reserve estimates and production forecasting are under large uncertainties. In this geologic context, it is of great relevance to develop techniques that helps to obtain a detailed description on the spatial distribution of these different rocks. In doing so, it contributes to the understanding of presalt carbonate sedimentary deposits, providing inputs for more predictive reservoir models. Traditionally, these carbonates are grouped into three classes, from which only one exhibits reservoir properties. Using a dataset from Buzios Field, this work proposes a characterization of presalt carbonate reservoir rocks by grouping them in terms of their mineral composition. Taking advantage of rock physics concepts, we aim to potentialize the use of elastic parameters for multiple rock type discrimination. We explored several attempts for rock classification by using a Bayesian approach. Among all the tested propositions, a two-step workflow for five lithotypes classification, emerges as the most appropriate for the Buzios Field. In this scheme, three lithotypes represent good-quality reservoirs and the other two are low-porosity and Mg-clay-rich carbonates. The average root-mean-square error of the most likely a posteriori rock proportions is around 8.4%, only approximately 1% higher than the conventional three lithotypes configuration. To support that, we compared different methodologies for Bayesian classification at well-log scale through acoustic impedance and compressional to shear velocity ratio. Potential applicability of the proposed methodology at field scale is reinforced by similar results achieved using well-logs filtered to the seismic bandwidth.

Brazilian presalt account for more than 70% of petroleum production in the country. More than ten years after the announcement of its discovery, presalt carbonates remain presenting many challenges regarding their reservoir’s characterization. Well log analysis and formation evaluation of carbonate rocks are difficult tasks due to the complex and heterogeneous nature of these rocks and its associated mineral phases such as magnesian clays (Mg-clays). This study proposes a new workflow for presalt reservoirs formation evaluation that incorporates nuclear magnetic resonance (NMR) logs in the estimation of petrophysical properties such as clay volume, porosity, water saturation and net pay. This workflow aims to be useful for initial assessments when a limited amount of data is available. We compare this approach with conventional methods widely applied in formation evaluation to verify the impact that use of different methodologies can have in the final assessments. These methods are applied in Barra Velha and Itapema formations of the Buzios Field, Santos Basin. Our results show that a hybrid method which combines NMR and conventional logs for clay content and water saturation is more robust for estimation of those properties in Barra Velha and Itapema formations. Clay content based on gamma-ray logs is more assertive to represent the shales observed in the Itapema Formation. However, clay content based on NMR logs is essential to properly identify Mg-clays in the Barra Velha Formation. Regarding the water saturation, the use of only Archie’s equation can result in net pay regions below the oil-water contact if their parameters were not properly determined. An accurate determination of these parameters requires a huge amount of data and measurements that are not always available. So, the hybrid approach for water saturation shows that the use of NMR logs above the transition zone is an optimistic alternative to overcome the limitations of the Archie’s equation in carbonate rocks. In general, effective porosity from NMR and neutron-density logs presented similar results. Nevertheless, NMR effective porosity was more accurate to regions with dolomitized and silicified carbonates and Mg-clays. In magnesian-clays interval, NMR effective porosity fitted two times better to the laboratory data than neutron-density effective porosity. So, in our analysis, the incorporation of NMR logs and its integration with conventional logs resulting in a hybrid approach provided a more assertive formation evaluation in the studied area, being essential its use in complex environments as presalt reservoirs.

An embedded model estimator (EMBER) petrophysical modeling algorithm has been applied to obtain effective porosity and permeability within the presalt carbonate reservoirs of the Barra Velha Formation in Buzios Field, Santos Basin. This advanced methodology was used due to the heterogeneity and complexity of the reservoirs, which makes modeling by conventional geostatistical methodologies difficult. For effective porosity modeling, we chose one facies model, one stratigraphic seismic attribute (acoustic impedance), and one structural seismic attribute (local flatness) as secondary variables. Permeability was modeled by using the best effective porosity simulation result as a secondary variable. Our results demonstrate that average effective porosity and permeability were 0.10 v/v and 440 md, respectively, indicating good reservoir quality throughout the studied area. A vertical trend of high effective porosities and permeabilities for the basal and uppermost reservoir sections was identified in our results, as well as a trend with lower values for these reservoir properties for the intermediate reservoir section. The lower section of the formation presented more continuity, and we infer it to be the best reservoir interval. We observed two horizontal trends for these reservoir properties at the formation top: one of higher values aligned to the north–south direction at the structural highs and another of lower reservoir properties related to isolated structural lows within structural highs. Correlation between modeled results and the blind test ANP-1 well upscaled properties was high, and upscaled well-log property distributions were preserved in the EMBER simulations, proving the predictive capacity of the algorithm. Finally, conditional distributions analysis indicated that the basal section of the Barra Velha Formation presents higher uncertainty for the estimation of effective porosity. Even though this interval is considered to have the best reservoir characteristics, decision making should be done with caution for this section.

Rock typing into flow units (FU) is a well-known technique for characterizing flow heterogeneities in reservoirs and producing reliable estimations of petrophysical properties. Despite the large availability of methods that correlate a specific pore-throat size to petrophysical attributes, extrapolating FU rock typing from the core and well log scales into the whole reservoir is a major challenge due to the scale differences between data and the lack of correlation with the common-used sedimentological facies. Most 3D generations of flow units and petrophysical property studies available in the literature are merely a geostatistical procedure, without any spatial data constraints in the 3D seismic data. We propose a new approach to discretize flow units in the core and well logs considering the decametric scale characteristics of the seismic data, generating a 3D model of FU facies and calculating porosities and permeabilities that are more accurate than the usual estimation based on sedimentary facies. Despite the complexity of the geological setting and the reduced number of FU, we produced volumes of permeability and porosity that are still capable of obtaining complex reservoir flow characteristics and could be directly considered as variables in lateral interpolation of reservoir parameters, seismic 4D interpretations and seismic-assisted history matching.

The Brazilian pre-salt carbonate reservoirs, in deep water, are examples of interesting places for oil and gas industry exploration due to their high production capacity. Oil and gas companies are often collecting information about the geology and the reservoir’s characteristics to improve its understanding and consequently optimize the production results. Seismic interpretation is mandatory for the understanding of geology, always pondering reducing the risks during exploration. Seismic and well data are commonly used together as a useful approach to comprehend the geological history and provide a good reservoir characterization. In this paper, we performed the seismic interpretation of the pre-salt carbonate reservoirs of the Buzios Field, Santos Basin, and used seismic attributes to obtain a better comprehension, as the TecVA attribute. Also, we generated isopach maps for a better understanding of reservoir intervals. As a result, we achieved a better definition of fault distribution and tectonic behavior, as well as determined the main interval thickness and the possibility of build-up and coquina bank occurrence.

The presalt reservoirs of the Barra Velha Formation are complex and heterogeneous. Their deposition was controlled by a mixture of physical and chemical processes, which consequently affected the distributions of facies and variations in porosity and permeability. In this paper we present a presalt facies reconstruction of reservoirs within the Barra Velha Formation of the Búzios Field. This was achieved through the use of an innovative workflow that integrates geological process modeling with a truncated Gaussian simulation geostatistical algorithm with trends. Our results show that the structural highs are dominated by carbonate build-ups/mounds architecture seismic patterns which are dominated by spherulites and its intercalation with shrub sediments culminating in spherulitites and shrubby carbonate lithologies. Reworked sediments and facies are concentrated in regions dominated by debris seismic patterns and lake bottom seismic facies corresponding to laminites also occur within the study area. In chronostratigraphic terms the Barra Velha is muddier at the base transitioning to in-situ carbonates in the middle section, before becoming muddier again at the top. The western portion of the Búzios Field is mostly composed by shrubby carbonates and reworked facies whilst spherulitities are more abundant to the east intercalated with shrubby carbonates. Some uncertainties remain in relation to the parameters used in the proposed methodology. Nonetheless, the proposed workflow was effective for facies reconstruction of the presalt carbonates allowing not only a better understanding of sedimentological processes but also accurately distributing facies throughout the study area.

Rock typing into flow units (FU) is a well-known technique for characterizing flow heterogeneities in reservoirs and producing reliable estimations of petrophysical properties, as porosity and permeability. Several methods that correlate pore-throat size with permeability and porosity in the core and well-log domains are available in the literature, being the flow zone indicator (FZI) method the most common used in both clastic and carbonate reservoirs. Extrapolating the flow units rock typing from the core and well-log scales into the whole reservoir is a major challenge due to the lack of correlation with sedimentological facies and available data scale differences. Most 3D generations of flow units and petrophysical properties are merely a geostatistical procedure, without any spatial data constraints (like seismic attribute). We propose a new approach to create flow units occurrence probability volumes as well as seismic derived porosities and permeabilities that are more robust than the usual estimate of petrophysical properties considering sedimentological facies. Considering the seismic scale characteristics and using the concept of decametre flow units and quantitative seismic interpretation in a Brazilian presalt dataset, we indirectly quantified superimposed small-scale effects that obliterate/generate porosity on a larger scale and established a minimum number of correlatable FUs with elastic seismic attributes. We produced 3D volumes of permeability and porosity that are still capable of obtaining complex reservoir flow characteristics and could be directly considered as variables in lateral interpolation of reservoir parameters, seismic 4D interpretations and seismic-assisted history matching.

This paper presents the application of an unsupervised neural network to classification of seismic facies based on a unique combination of stratigraphic and structural seismic attributes. This classification was integrated with statistical analysis of the porosity and permeability of the seismic facies which permitted the advanced reservoir characterization of the presalt carbonate reservoirs of the Barra Velha Formation in the Buzios Field, Santos Basin. This advanced approach is required due to the high degree of heterogeneity and complexity these reservoirs, which directly impacts on their porosity and permeability. Preconditioning of the seismic data was essential for filtering random and structurally oriented noise prior to the generation of seismic attributes. Four seismic attributes; acoustic impedance, rms amplitude, local flatness and principal dip component, were selected as the inputs for the unsupervised classification based on their capacity for differentiating between the observed seismic patterns within the Barra Velha Formation. Principal component analysis was then performed to decrease redundancy of the input seismic attribute data prior to classification. The analysis of amplitude seismic features as well as of the classification results allowed the identification of three different seismic patterns within the study area: build-ups, debris and aggradational/progradational carbonate platforms. The seismic attribute of principal dip component proved to be crucial for distinguishing between carbonate build-ups and debris seismic facies. Our results demonstrated that the build-up and debris seismic facies are commonly occur aligned with faults, display higher porosity and permeability and as such they are inferred to be the best reservoirs.

The Santos Basin, located in the southeastern Brazilian margin, presents a high diversification of reservoirs in both pre- and post-salt, with many fields still under study and which present great production potential. The Oligocene reservoirs of the Bauna and Piracaba offshore oil fields, the target of this study, are formed by turbidite sandstones. We propose an approach using the integration of seismic attributes and evaluation of well logs for building a 3D model of reservoir properties. From the analysis of seismic attributes, we built a geobody containing the turbidite bodies. Then, the porosity and saturation calculated from well logs were extrapolated, thus generating a static model with these petrophysical properties. The results showed two unconnected turbidite lobes, thus creating two independent productive zones, which have excellent porous properties and considerable oil volume in place.

This work proposed an additional approach to investigate gas hydrate occurrences in the Foz do Amazonas Basin, in the Brazilian Equatorial Margin. The automatic comparison of seafloor seismic amplitudes with those from the Bottom Simulating Reflectors (BSR) was used to exhibit the reversal of signal polarities among the seafloor (positive) and the BSR (negative), reinforcing the identification of BSR in areas where its visualization was unclear. Additionally, we used the envelope attribute to highlight the BSR in the seismic section. Subsequently, we decomposed the seismic data into different frequency bands, applied a -90 degrees phase rotation to the data and recalculated the envelope attribute for each section decomposed in frequency bands. This technique improved visualization, allowing the identification of intervals where BSR were laterally discontinuous, revealing to be valuable for mapping the gas hydrate distribution in Foz do Amazonas Basin.

On the account of the absence of modern analogues, the interpretation of evaporite-bearing basins relies extensively on seismic and well data. Recent studies describe the intrasalt kinematic, geometries and compositions, relating the change of reflection patterns in seismic data to variations in evaporite sequences. However, these interpretations are only qualitative. This study describes a step further in proceeding from qualitative to quantitative interpretation of an evaporite-dominated interval. It integrates geophysical and geological foundations by combining rock physics, seismic inversion and statistical techniques to deliver seismic-driven facies volume of the evaporite sequence in the Santos Basin, offshore Brazil. Synthetic seismogram demonstrate the ambiguities and uncertainties in relating the seismic amplitude to salt types. Rock-physics analysis indicates that acoustic impedance is an effective differentiator of salt types in comparison to seismic amplitude. Therefore, we perform seismic inversion to transform interface property into layer property. The acoustic impedance volume mitigated significantly the risk of seismic interpretation in the salt sequence. The Bayesian classification integrates acoustic impedance and rock-physics analysis to deliver the seismic-driven facies volume, which categorizes bittern salts, halite and anhydrite. This enables the refinement of the seismic-stratigraphic interpretation of intrasalt sequences of the Ariri Formation based on the sedimentary cycles of evaporites. Additionally, we calculate proportion maps to evaluate the spatial variability of salt deposition. We observe an increase in bittern salts and anhydrite proportions from the bottom to the top of the sequence. The comparison between well-based and seismic-based proportions testifies to the quantitative potential of seismic data. The approach provides quantitative analysis of the evaporite sequence and can be applied to other salt-bearing basins.

The main reservoirs in the Linguado Field are grainstone and packstone carbonates composed of oolites, oncolites, pelloids, and rare bioclasts, of the Quissamã Formation (Albian- age) and coquinas of the Coqueiros Formation (Aptian-age). Within Quissamã Formation, facies have high porosity variations and their 3D characterization is of utter importance to allow for a better location of the wells. The objective of this study was a volumetric characterization of Quissamã Formation by means of an adapted classical workflow composed of well-seismic tie, seismic preconditioning, seismic interpretation, seismic inversion, petrophysical properties estimation, and porosity geostatistical modeling. Seismic inversion results allowed the interpretation of a horizon to separate the carbonate platform in an upper zone, with low acoustic impedance, from a lower zone, with high acoustic impedance. Finally, behavioral knowledge of acoustic impedance and the porosity distribution within the Albian carbonate platform helped to better characterize the distribution of carbonaceous facies allowing the confirmation that commercial wells were drilled in low acoustic impedance and high porosity regions. It was also possible to confirm that a well, declared as noncommercial, was drilled in a poor reservoir region with high acoustic impedance and low porosity and identified other locations that were not yet drilled but could represent potential targets.

Rock typing into flow units (FUs) plays a pivotal role in constructing static and dynamic models of petroleum reservoirs. Decisions made by asset teams mostly depend on predictions of how fluids will percolate through the subsurface during the reservoir life cycle. In carbonate settings, dealing with rock typing is complex and can generate a large quantity of units because of diagenetic processes such as dissolution, cementation, and silicification. Most rock-typing methods in carbonates successfully classify small-scale flow heterogeneity in well resolution but fail when interpolating those facies further away from the 1D domain, because of the lack of correlation between FUs and spatial data. Seismic data can be used to detect large-scale FUs and assist the interpolation of small-scale FUs in 3D reservoir volume, thus producing more-realistic static and dynamic models. We propose a modification of the classical rock-typing methods that use permeability (k) vs. porosity (phi) plots and electrical properties, with a data set from the Mero Field, part of the giant Libra Field of presalt carbonate reservoirs in offshore Brazil. From the permeability cumulative S-curve analysis, we established major large-scale FUs that maintain part of the carbonate flow heterogeneity and correlate them with the elastic attributes: P-impedance (PI) and S-impedance (SI). In addition, we established a priori PI and SI correlations with the formation-factor (FF) (F) parameter to categorize large-scale FUs using the F vs. k methodology. With the large-scale FUs mapped in seismic data sets, core-plug-scale FUs can be populated into the 3D static and dynamic models using geostatistics tools, thus creating more-realistic reservoir models and assisting asset teams in the decision-making process.

Petroleum companies have invested heavily in the exploration of frontier offshore basins in Brazil. Uncertainties associated with geologic complexity, lithostratigraphy, fluid content, and seismic resolution in these basins are the most common challenges. Many methods have been used to circumvent these issues, such as assessing seismic attributes, seismic inversion, spectral decomposition, and the integration of these methodologies to accomplish an optimal approach. Because of the complex geology of these areas, it is very difficult to identify potential reservoirs within one specific geologic formation. Hence, applying spectral decomposition to frontier basins of high geologic complexity can help overcome the challenges because in the frequency domain, it is possible to better define variability and lateral discontinuities. The correct choice of the spectral decomposition optimization approach is critical for accurate target zone representation as well as selection of the appropriate transform. Prestack inversion, spectral decomposition, and attribute seismic facies classification were applied to evaluate the extent of a reservoir and analyze whether an appraisal well has been sited at a good location. The results showed that the new appraisal well was planned at a good location but that its facies were not as good as those of the first discovery well, as confirmed after drilling.

The integration of rock and well logs data is fundamental for the interpretation of depositional systems and sequences, a fundamental support for E&P activities. This approach was applied on the low permeability turbidite sandstones and slurries of the Maracangalha Formation, in the Massapê Oil/Gas Field, Recôncavo Basin. Well-log interpretation allowed the recognition of 23 turbidite stages, each of which records a specific period of growth of a fan system. These stages are composed of four main facies, all observed in each one of these stages: (a) fine to medium sandstones, with porosities greater than 9%, being the best reservoirs; (b) silty to very fine sandstone slurry facies, that corresponds to very muddy reservoirs with porosities less than 9%, forming important permeability barriers; (c) siltstones and (d) shales. Turbidite stages appear in the Gamma Rays logs (GR) with funnel, block and serrated log motif patterns, corresponding to dominantly thinning and fining upward signatures, recognized in several wells in the Massapê Field. The detailed correlation of these well-logs showed that these stages are present in the whole field. The mapping of high resolution turbiditic stages, considering the correlation of their four facies, will allow a better location of wells, resulting in a more efficient exploration and production development, capable of increasing the recovery of important oil reserves that still exist in the area, optimizing costs and giving greater robustness to E&P processes.

The oil industry utilizes seismic techniques to image the Earth’s subsurface. The number of reflected rays generated at a single point that return to the receivers impacts directly the quality of seismic data and, in turn, seismic interpretation. Seismic illumination is used as a quality control measure to find poor coverage zones, which are commonly found in pre-salt reservoirs of eastern Brazilian marginal basins. The Santos Basin has a wide evaporite section featuring some complex structures such as overhangs, mini-basins, salt domes, salt tongues and walls more than 3 km thick. Those structures change the paths of the seismic rays and reduce the coverage of seismic imaging below the evaporite layer in some regions. In this study, a quantitative and qualitative illumination analysis of a pre-salt horizon was performed comparing four different velocity model scenarios and the behavior of the seismic ray path was analyzed. The results show that both stratification and the geometric structures existing in the salt layer have a direct impact on the imaging of the pre-salt reservoirs. Each factor influences imaging in a different way and, when associated, can generate regions of low illumination quality. Consequently, it is of extreme importance to obtain a suitable understanding of the upper salt layer as it will govern the ray paths towards the layers below the evaporites. Furthermore, the mapping of the anomalies generated by the stratification should also be considered in the creation of the velocity model.

Historically, marine research has been using single-channel seismic (SCS) devices for scientific projects. Despite SCS’s abundant data availability and the contribution it has brought for subsurface comprehension, few efforts have been dedicated to improve the SCS processing flow to extract more information carried by seismic signals and for better imaging. Diffractions present the necessary means to estimate sediment acoustic properties useful for imaging, stability studies, and geohazard prevention. The root-mean-square (rms) velocity is estimated from diffractions using a diffraction velocity analysis workflow composed of the following main steps: separation of diffractions from specular events using stationary phase properties and planewave destruction filtering, determination of diffractor locations in time, velocity scanning using constant rms velocity time migration, automatic picking of rms velocity at the diffractor location in the scan volume, and quality control to avoid spurious rms velocity. The method circumvents the sparsity and nonuniform distribution of diffractions for smooth lateral velocity change conditions. Application in a SCS line acquired in the Joetsu Basin, Japan Sea, indicates improvement in the focusing of deeper events compared to the previous processing flow, and it adds consistent information about the acoustic properties of the subsurface.

Most subsurface rock models consider salt bodies as homogenous masses and set to evaporite minerals constant values of elastic properties such as density, compressional and shear velocities, Young’s modulus and Poisson’s ratio. Lithological analyzes of outcrops and wells indicate that evaporites present large vertical and lateral heterogeneities. Recent studies have demonstrated that the knowledge of the elastic properties of rock salt can substantially benefit velocity modeling, seismic imaging, reservoir geomechanical analysis, prediction of wellbore stability and calculation of optimum fluid weight. However, few papers document the spatial estimation of elastic properties for salt formations. We propose an approach to characterize the internal structures of the salt bodies in the Santos Basin, offshore Brazil, using well and 3D seismic data. It starts with a rock-physics analysis at well-log scale, which reveals that the elastic properties of rock salt are highly correlated. Once the relationships of the elastic properties are established, we explore the functionality of the empirical equations as property predictors. We demonstrate that the elastic properties can be empirically estimated from compressional velocity. The comparison between the estimated and the measured well logs validates the estimation. Then, we perform the seismic inversion to generate the spatial distribution of the acoustic impedance. We derive compressional and shear velocities, density, Young’s modulus and Poisson’s ratio volumes by applying the empirical equations to the acoustic impedance volume. The blind well points out that, through this workflow, the seismic data can successfully predict the elastic properties of the salt formation in undrilled portions.

Characterization of presalt coquinas reservoirs is a know challenging task due to its facies and, consequently, petrophysical properties heterogeneity and anisotropy. This fact makes the traditional seismic interpretation and well log analysis workflow not enough for the interpreter to address reasonably the reservoir complexity. In this study, a methodology integrating different geological and geophysical interpretation techniques based on data pre-conditioning, model-based seismic acoustic inversion, effective porosity geostatistical modeling using sequential gaussian simulation with collocated co-kriging and geobody interpretation is proposed to obtain maximum information from the available data which consists on post-stack seismic and well logs from the lacustrine coquinas carbonate reservoirs from the Coqueiros Formation located in the Linguado Field on Campos Basin. Acoustic seismic inversion results allowed the interpretation of four new seismic horizons that could individualize two coquinas intervals and effective porosity modeling results allowed the geobody extraction of the coquinas banks that represent the best reservoir facies within the study area with effective porosities between 13 and 30% making it even possible to identify new exploratory areas. Therefore, the proposed workflow is very reliable for coquinas reservoirs characterization and can be applied in other areas.

Foz do Amazonas basin is located at the northern portion of the Brazilian Equatorial Margin, along the coastal zone of Amapá and Pará states. This basin has been subjected to several studies, and the presence of gas hydrates has been demonstrated locally through sampling, and over broader areas using seismic reflection data. Seismic reflection is one method to identify the occurrence of gas hydrates, as they give rise to well-marked reflectors that simulate the seafloor, known as Bottom Simulating Reflectors (BSR). This study aims to investigate BSRs associated with the presence of methane hydrates in the Foz do Amazonas Basin through the application of seismic attributes. It was compared seismic amplitudes from the seafloor and the BSR to validate the inferred seismic feature. Then, Envelope and Second Derivative were chosen for highlighting the BSR in seismic section. The results showed an inversion of polarities in the signal between the seafloor (positive polarity) and the BSR (negative polarity). The integrated use of these approaches allowed validating the level of the BSR in line 0239-0035 and inferring the presence of gas hydrates, revealing to be a useful tool for interpreting the distribution of the gas hydrates in the Foz do Amazonas Basin.

Studies on evaporitic rocks are of great importance for the oil and gas industry as they can create traps and seals for the hydrocarbon accumulations. Also, salt high ductility allows the formation of complex structures associated with halokinesis posing thus major challenges for imaging the rocks at their flanks and below the structures. This paper discusses the effects of salt tectonics on post-salt layers and the difficulties in interpreting the top salt surface in a particularly complex area of the Santos Basin. The available seismic and migration velocity model data are from an area located in the distal portion of the Santos Basin where the existing salt structures had a profound effect on the post-salt layers. Complex salt structures were formed in this area due to the intrinsic characteristics of salt rocks as it flew away from the terrigenous depocenters, pushed in the Atlantic Ocean realms. Structures such as overhangs are common and sometimes difficult to be mapped. Their geometry generates multiple points with the same latitude and longitude, but at different depths as they are interpreted and thus represent a challenge for current surface interpolation algorithms. A workflow is proposed to optimize multi-z surfaces generation from the top of the salt layer from the interpretation this surface in conjunction with the analysis of the migration velocity model. Finally, a zonation map of the salt walls, mini-basins, salt domes, overhang and salt window in the region is presented.

Presalt reservoirs of the Santos Basin accounted for more than 50% of Brazilian hydrocarbon production in the first two months of 2019. Its most important reservoirs are found in the Barra Velha Formation, thus the understanding of its genesis and geological history is essential. This formation is composed of carbonates deposited in an alkaline lacustrine environment with a multiplicity of facies from boundstones and grainstones to mudstones. We performed a sedimentary analysis based on integration of sidewall core samples and well logs from two wells coupled with seismic patterns discrimination to characterize the tectonic and depositional evolution of the Barra Velha Formation in a sector of the Outer High of the Santos Basin in this study. Our method consisted initially on the evaluation of well logs, aiming to identify shallowing and flooding upward cycles of second and third orders for the paleoenvironmental conceptualization upper rift and sag phases. Then we defined electrofacies through the integration of sidewall cores, gamma ray and acoustic impedance logs using crossplot approach. Lastly, we described seismic patterns throughout the study area and correlated with results from well data analysis. The Barra Velha Formation was, therefore, subdivided in three zones Lower, Intermediate and Upper Zones. Well 1 has a facies association characteristic of a proximal and stable environment during deposition, while Well 2 initially presents in a distal environment sedimentation that evolves to a more proximal setting. This fact evidenced differences with respect to base level variations indicating compartimentalization within the lacustrine environment of upper rift and sag phase that corroborated with the detailed seismic pattern interpretation of the study area.

Exploratory work for hydrocarbons along the southeastern Brazilian Margin discovered high concentrations of CO2 in several fields, setting scientific challenges to understand these accumulations. Despite significant progress in understanding the consequences of high CO2 in these reservoirs, the role of several variables that may control such accumulations of CO2 is still unclear. For example, significant differences in the percentages of CO2 have been found in reservoirs of otherwise similar prospects lying close to each other. In this paper, we present a hypothesis on how the rifting geodynamics are related to these CO2-rich accumulations. CO2-rich mantle material may be intruded into the upper crustal levels through hyper-stretched continental crust during rifting. Gravimetric and magnetic potential methods were used to identify major intrusive bodies, crustal thinning and other geotectonic elements of the southeastern Brazilian Margin. Modeling based on magnetic, gravity, and seismic data suggests a major intrusive magmatic body just below the reservoir where a high CO2 accumulation was found. Small faults connecting this magmatic body with the sedimentary section could be the fairway for the magmatic sourced gas rise to reservoirs. Mapping and understanding the crustal structure of sedimentary basins are shown to be important steps for “de-risking” the exploration process.

Carbonate mounds, as described herein, often present seismic characteristics such as low amplitude and a high density of faults and fractures, which can easily be oversampled and blur other rock features in simple geobody extraction processes. We propose a workflow for combining geometric attributes and hybrid spectral decomposition (HSD) to efficiently identify good quality reservoirs in carbonate mounds within the complex environment of the Brazilian pre-salt zone. To better identify these reservoirs within the seismic volume of carbonate mounds, we divide our methodology into four stages: seismic data acquisition and processing overview; preconditioning of seismic data using structural-oriented filtering and imaging enhancement; calculation of seismic attributes; and classification of seismic facies. Although coherence and curvature attributes are often used to identify high density fault and fracture zones, representing one of the most important features of carbonate mounds, HSD is necessary to discriminate low amplitude carbonate mounds (good reservoir quality) from low amplitude clay zones (non-reservoir). Finally, we use a multi-attribute facies classification to generate a geologically significant outcome and to guide a final geobody extraction that is calibrated by well data and that can be used as a spatial indicator of the distribution of good reservoir quality for static modeling.

Mapping of seismic and lithological facies is a very complex process, especially in regions with low seismic resolution due to extensive salt layers, even when only an exploratory view of the distribution of the reservoir facies is required. The aim of this study was to apply multi-attribute analysis using an unsupervised classification algorithm to map the carbonate facies of an exploratory pre-salt area located in the Outer high region of the Santos Basin. The interval of interest is the Barra Velha Formation, deposited during the Aptian, which represents an intercalation of travertines, stromatolites, grainstones and spherulitic packstones, mudstones and authigenic shales, which were deposited under hypersaline lacustrine conditions during the sag phase. A set of seismic attributes, calculated from a post-stack seismic amplitude volume, was used to characterize geological and structural features of the study area. We applied k-means clustering in an approach for unsupervised seismic facies classification. Our results show that at least three seismic facies can be differentiated, representing associations of build-up lithologies, aggradational or progradational carbonate platforms, and debris facies. We quantitatively evaluated the seismic facies against petrophysical properties (porosity and permeability) from available well logs. Seismic patterns associated with the lithologies helped identify new exploration targets.

Foz do Amazonas basin is located at the northern portion of the Brazilian Equatorial Margin, along the coastal zone of Amapá and Pará states. This basin has been subjected to several studies, and the presence of gas hydrates has been demonstrated locally through sampling, and over broader areas using seismic reflection data. Seismic reflection is one method to identify the occurrence of gas hydrates, as they give rise to well-marked reflectors that simulate the seafloor, known as Bottom Simulating Reflectors (BSR). This study aims to investigate BSRs associated with the presence of methane hydrates in the Foz do Amazonas Basin through the application of seismic attributes. It was compared seismic amplitudes from the seafloor and the BSR to validate the inferred seismic feature. Then, Envelope and Second Derivative were chosen for highlighting the BSR in seismic section. The results showed an inversion of polarities in the signal between the seafloor (positive polarity) and the BSR (negative polarity). The integrated use of these approaches allowed validating the level of the BSR in line 0239-0035 and inferring the presence of gas hydrates, revealing to be a useful tool for interpreting the distribution of the gas hydrates in the Foz do Amazonas Basin.

Volcanic rock facies characterization in subsurface log data have always being challenging. Even though considerable types of well logs are acquired, the results achieved on facies characterization with the conventional log suits are very limited. Conversely, high-resolution borehole image logs calibrated with side wall core samples can provide the necessary structural and textural information for facies definitions. In this case study, an integration of good quality acoustic image log data, side wall core petrography and geochemical analyses provided a good understanding of volcanic facies and stratigraphic relationships. Additionally, outcrop data from the analogous Serra Geral Formation and other Large Igneous Provinces were used for comparison. In the studied well, from Santos basin, Brazil, it was possible to identify several kinds of subaerial basaltic lava flow units, such as compound pahoehoe, sheet pahoehoe and rubbly pahoehoe lava flows. Vesicles, amygdales, vesicle cylinders, sub-horizontal vesicle sheets, autobreccias and entablature are some of the structures described in this study. As a result, 2 image catalogues of subaerial volcanic rocks were produced characterizing facies and flow units along with a stratigraphic model of the history of this volcanism. This is the first time that pahoehoe lava flow units could be characterized at an offshore Brazilian basin. The results achieved are important for the understanding of the Cretaceous volcanism events in the pre-salt layer and also provide support for the evaluation and geological modelling of the volcanic rocks in Santos Basin oil fields.

Volcanic rock facies characterization in subsurface log data have always being challenging. Even though considerable types of well logs are acquired, the results achieved on facies characterization with the conventional log suits are very limited. Conversely, high-resolution borehole image logs calibrated with side wall core samples can provide the necessary structural and textural information for facies definitions. In this case study, an integration of good quality acoustic image log data, side wall core petrography and geochemical analyses provided a good understanding of volcanic facies and stratigraphic relationships. Additionally, outcrop data from the analogous Serra Geral Formation and other Large Igneous Provinces were used for comparison. In the studied well, from Santos basin, Brazil, it was possible to identify several kinds of subaerial basaltic lava flow units, such as compound pahoehoe, sheet pahoehoe and rubbly pahoehoe lava flows. Vesicles, amygdales, vesicle cylinders, sub-horizontal vesicle sheets, autobreccias and entablature are some of the structures described in this study. As a result, 2 image catalogues of subaerial volcanic rocks were produced characterizing facies and flow units along with a stratigraphic model of the history of this volcanism. This is the first time that pahoehoe lava flow units could be characterized at an offshore Brazilian basin. The results achieved are important for the understanding of the Cretaceous volcanism events in the pre-salt layer and also provide support for the evaluation and geological modelling of the volcanic rocks in Santos Basin oil fields.

The Espírito Santo onshore basin is an important hydrocarbon province on the eastern Brazilian continental margin that accounts for almost 9% of Brazil’s onshore oil production. This study aims to understand the stratigraphy and geologic evolution of the eastern Inhambú onshore oil field from the post-rift section (Cricaré Formation, Mucuri Member) to the drift section (Rio Doce Formation). We interpret the main stratigraphic surfaces and seismic facies from the basement to the upper pre-Eocene unconformity to build a chronostratigraphic chart and identify the main transgressive and regressive events. Lithological and geophysical logs from new wells allowed the identification of six 3rd -order cycles, including four regressive and two transgressive events. Based on these results, a new conceptual geological model for the eastern Inhambú Oil Field is proposed.

In carbonate rock reservoirs, spatial distribution models and elastic properties are complex because of diagenetic processes and mineralogical composition, which together directly interfere with variations in pore shape and interconnectivity. The main objective of this paper is to propose a workflow to aid in three-dimensional quantitative carbonate reservoir characterization of the Quissamã Formation (Macaé Group) in the Pampo field of the Campos Basin, offshore Brazil. Model-based seismic inversion, sequential Gaussian simulation with cokriging for porosity modeling, and truncated Gaussian simulation with trend for facies modeling were used to characterize the carbonate reservoirs. Our results show that the carbonate platform is located between the upper Aptian and lower Albian seismic surfaces. Interpretation of a new surface, called the intra-Albian, was possible via acoustic-impedance (AI) analysis. Our workflow facilitated identification of low AI, high porosity, and best facies areas in structural highs where the most productive wells have been drilled. Facies modeling suggests that intercalation of facies with high and low porosities is connected to shallowing-upward cycles. Finally, several debris facies with low AI and high porosities were identified in an area that could be targeted for new exploration.

An international research cruise named Iatá-Piuna took place on the São Paulo Plateau on May 2013 in the Campos and Espírito Santo basins, off Brazil. The cruise was carried ou on board the research vessel (R/V) Yokosuka that hosts the human operated vehicle (HOV) SHINKAI 6500. It aimed at finding chemosynthetic communities, composed of organisms capable of generating their own vital energy by metabolizing organic and inorganic compounds related to seeps. Identification of these organisms could provide information for understanding the origin of life, since they may resemble primitive organisms that existed in the initial stages of life on Earth. During Leg 2 (May 10–24, 2013), however, dives on the northern part of the São Paulo Plateau at the Espírito Santo Basin led to the discovery of a giant oil seep. The seep, ca. 3 nautical miles (ca. 5.6km) in length is located along an outcrop of Eocene rocks on a salt-induced escarpment of the plateau and at a water depth of ca. 2700m. The 200m relief of the seafloor suggests that the seep takes place along an active fault system driven by salt diapirism. The oil was analyzed and identified as a severely biodegraded marine oil, generated by carbonate rocks within a minibasin located to the east of the escarpment. This represents valuable exploratory information because it proves that an active petroleum system is present in the context of minibasins associated with salt diapirism in the area.

Much research has been published regarding the relation between major gas hydrate accumulations and the global carbon cycle. In this context, the determination of the sulfate/methane interface (SMI) depth is of primary importance in order to understand the dynamics of methane flux in the shallow section. This paper identifies the depth of the SMI in sediments based on sulfate and methane concentration profiles in cores recovered in the Rio Grande Cone Gas Hydrate Province, Pelotas Basin, southern Brazil. The shape of methane and sulfate concentration profiles in the sediments can be linked to the local methane flux rate as follows: (i) near linear, high upward-diffusing methane flux coupled with high sulfate diffusion from seawater; (ii) irregular, variable methane flux rates; and (iii) kink-type profile, which is indicative of variable rather than strictly high upward methane flux. The areas in which a high methane flux was identified are spatially associated with gas chimneys in sediments within pockmarks, whereas profiles with low methane flux are present in adjacent areas. These chimneys appear as acoustic blankings in seismic records and can therefore be mapped in subsurface. The wavy-like seismic reflection following the SMI coincides with the occurrence of authigenic carbonate nodules and concretions. In addition, high methane fluxes and the occurrence of concretions and nodules carbonates were correlated by stratigraphic position of the concretions bearing intervals and sulfate profiles.

An international research cruise named Iatá-Piuna took place on the São Paulo Plateau on May 2013 in the Campos and Espírito Santo basins, off Brazil. The cruise was carried ou on board the research vessel (R/V) Yokosuka that hosts the human operated vehicle (HOV) SHINKAI 6500. It aimed at finding chemosynthetic communities, composed of organisms capable of generating their own vital energy by metabolizing organic and inorganic compounds related to seeps. Identification of these organisms could provide information for understanding the origin of life, since they may resemble primitive organisms that existed in the initial stages of life on Earth. During Leg 2 (May 10–24, 2013), however, dives on the northern part of the São Paulo Plateau at the Espírito Santo Basin led to the discovery of a giant oil seep. The seep, ca. 3 nautical miles (ca. 5.6 km) in length is located along an outcrop of Eocene rocks on a salt induced escarpment of the plateau and at a water depth of ca. 2700 m. The 200 m relief of the seafloor suggests that the seep takes place along an active fault system driven by salt diapirism. The oil was analyzed and identified as a severely biodegraded marine oil, generated by carbonate rocks within a minibasin located to the east of the escarpment. This represents valuable exploratory information because it proves that an active petroleum system is present in the context of minibasins associated with salt diapirism in the area.

Time-frequency transforms are widely used in seismic exploration. These transforms enable analysis of the energy density of a non-stationary signal as functions of amplitude, time and frequency. The representation of energy density is not unique, and each transform has its advantages and disadvantages. The choice of which transform should be used depends on the application. In this paper, we propose a new way to analyze time-lapse anomalies using iso-frequency panels obtained by time-frequency transforms. We compared the iso-frequency panels of the Morlet Wavelet Transform and Choi-Williams Distribution. These panels revealed different characteristics and can provide additional information for the interpretation of time-lapse anomalies. We used seismic data from the Marimbá field of the Campos Basin, Brazil, for which base and monitor acquisitions were held in 1984 and 1999, respectively. We also used a special filtering approach to enhance seismic resolution and remove noise, whereby we applied the curvelet transform to remove noise, and employed a tool to correct the residual moveout and inverse Q filtering for attenuation correction. Then we analysed the time-lapse anomalies using iso-frequency panels. The main time-lapse anomalies appeared in the form of clouds in the iso-frequency panels obtained by the Morlet Wavelet Transform approach. Iso-frequency panels obtained by Choi-Williams Distribution showed a higher sensitivity and resolution for analyzing the anomalies. Our results show the great potential of these transforms for visualization of time-lapse anomalies. Keywords: time-lapse anomalies, spectrogram, Morlet Wavelet Transform, Choi-Williams Distribution. RESUMO. Transformadas tempo-frequência são amplamente utilizadas na exploração sísmica. Estas transformadas permitem a análise da densidade de energia de um sinal não-estacionário como funções de amplitude, tempo e frequência. A representação da densidade de energia de um sinal não é única, e cada transformada tem suas vantagens e desvantagens. A escolha da transformada que deve ser usada depende da aplicação. Neste artigo, propomos uma nova abordagem para analisar anomalias de dados time-lapse usando painéis iso-frequência obtidos através de transformadas tempo-frequência. Comparamos os painéis iso-frequência obtidos com a Transformada Wavelet de Morlet e a Distribuição de Choi-Williams. Estes painéis revelaram diferentes características que podem fornecer informações adicionais para a interpretação de anomalias time-lapse. Os dados sísmicos utilizados foram do Campo de Marimbá da Bacia de Campos, Brasil, os quais as aquisições base e monitor foram realizadas em 1984 e 1999, respectivamente. Antes da análise dos painéis iso-frequência, usamos um workflow para melhorar a resolução sísmica e a razão sinal-ruído. Neste workflow, aplicamos a Transformada Curvelet para remover ruídos aleatórios e coerentes, uma ferramenta para corrigir o moveout residual e um Q-filter para correção dos efeitos da atenuação. Após este workflow, as principais anomalias time-lapse apareceram na forma de nuvens nos painéis iso-frequência da Transformada Wavelet de Morlet. Já os painéis iso-frequência da Distribuição de Choi-Williams apresentaram uma maior sensibilidade e resolução para análise dessas anomalias. Os resultados mostraram o grande potencial dessas transformadas para a visualização e interpretação de anomalias time-lapse. Palavras-chave: anomalias time-lapse, espectrograma, Transformada Wavelet de Morlet, Distribuição Choi-Williams.

Empty elliptical vesicles are observed in outcrops of Barremian very fine clayey sandstone to siltstone lacustrine slurry deposits of the Pitanga Member (Maracangalha Formation), exposed in the Maré Island, Southern Recôncavo Basin, Brazil. These sedimentary features have been traditionally interpreted as water escape structures triggered by the diapirism of the underlying shales of the Candeias Formation. This work proposes that vesicles were generated during massive gas hydrate dissociation as a result of tectonic activity in a paleolake system. Tectonic uplift would have triggered both the reduction of the confining pressure as well as an increase in lake bottom temperature, resulting in the instability of gas hydrate and causing intense release of both methane — or carbon dioxide (CO2) — and water. On one hand, this proposal has a strong impact on paleoenvironmental interpretations, giving support to the current hypothesis that rocks related to the Pitanga Member would have been deposited under water columns deep enough for gas hydrate formation and subsequent dissociation. On the other hand, it provides new insights on the genesis of fluid escape structures in sedimentary rocks, both lacustrine and marine, providing a paleobathymetric indicator.

Attenuation is one of the main factors responsible for limiting resolution of the seismic method. It selectively damps the higher frequency components of the signal more strongly, causing the earth to work as a low-pass filter. This loss of high-frequency energy may be partially compensated by application of inverse Q filtering routines. However, such routines often increase the noise level of the data, thereby restricting their use. These filters also require a quality factor profile as an input parameter, which is rarely available. In recent years, alternative methods for stable inverse Q filtering have been presented in the literature, which makes it possible to correct the attenuation without introducing so much noise. In addition, new methods have been proposed to estimate the quality factor from seismic reflection data. We have developed a three-stage workflow oriented for attenuation correction in stacked sections. In the first stage, a trace-by-trace estimate of the quality factor is performed along the section. The second stage consists of preparing the data for attenuation compensation, which is performed via a special filtering strategy for efficient noise removal to avoid high-frequency noise bursts. The last stage is the application of a stable inverse Q filtering. As an example, we applied the proposed flow in a seismic section to compensate for the attenuation caused by shallow gas accumulation. Careful data preparation proved to be a key factor in achieving successful attenuation compensation.

Empty elliptical vesicles are observed in outcrops of Barremian very fine clayey sandstone to siltstone lacustrine slurry deposits of the Pitanga Member (Maracangalha Formation), exposed in the Maré Island, Southern Recôncavo Basin, Brazil. These sedimentary features have been traditionally interpreted as water escape structures triggered by the diapirism of the underlying shales of the Candeias Formation. This work proposes that vesicles were generated during massive gas hydrate dissociation as a result of tectonic activity in a paleolake system. Tectonic uplift would have triggered both the reduction of the confining pressure as well as an increase in lake bottom temperature, resulting in the instability of gas hydrate and causing intense release of both methane – or carbon dioxide (CO2) – and water. On one hand, this proposal has a strong impact on paleoenvironmental interpretations, giving support to the current hypothesis that rocks related to the Pitanga Member would have been deposited under water columns deep enough for gas hydrate formation and subsequent dissociation. On the other hand, it provides new insights on the genesis of fluid escape structures in sedimentary rocks, both lacustrine and marine, providing a paleobathymetric indicator.

Chemosynthetic communities have been described from a variety of deep-sea environments across the world’s oceans. They constitute very interesting biological systems in terms of their ecology, evolution and biogeography, and also given their potential as indicators of the presence and abundance of consistent hydrocarbon-based nutritional sources. Up to now such peculiar biotic assemblages have not been reported for the western South Atlantic Ocean, leaving this large region undocumented with respect to the presence, composition and history of such communities. Here we report on the presence of a chemosynthetic community off the coast of southern Brazil, in an area where high-levels of methane and the presence of gas hydrates have been detected. We performed metagenomic analyses of the microbial community present at this site, and also employed molecular approaches to identify components of its benthic fauna. We conducted phylogenetic analyses comparing the components of this assemblage to those found elsewhere in the world, which allowed a historical assessment of the structure and dynamics of these systems. Our results revealed that the microbial community at this site is quite diverse, and contains many components that are very closely related to lineages previously sampled in ecologically similar environments across the globe. Anaerobic methanotrophic (ANME) archaeal groups were found to be very abundant at this site, suggesting that methane is indeed an important source of nutrition for this community. In addition, we document the presence at this site of a vestimentiferan siboglinid polychaete and the bivalve Acharax sp., both of which are typical components of deep-sea chemosynthetic communities. The remarkable similarity in biotic composition between this area and other deep-sea communities across the world supports the interpretation that these assemblages are historically connected across the global oceans, undergoing colonization from distant sites and influenced by local ecological features that select a stereotyped suite of specifically adapted organisms.

The Rio Grande Cone is a large-scale fanlike feature in the continental slope of the Pelotas Basin, Southern Brazil, where ubiquitous world-class bottom simulating reflectors (BSRs) are readily observed in seismic records. With the purpose of searching for natural gas hydrate deposits in the Cone area, four oceanographic cruises were carried out between May 2011 and July 2013, leading to the discovery of two pockmark fields, active faults and gas hydrates in shallow sediments. Multichannel seismic, multibeam echo sounder, side scan sonar and sub-bottom profiler records were used to map the shallow section and select sites for piston core sampling. Gas hydrates were recovered in several piston cores within muddy sediments collected inside pockmarks displaying high backscatter in the multibeam and side scan sonar data. We present two representative piston cores where numerous levels of gas hydrates occur, along with degassing features, authigenic carbonate and soupy sediments. Gas dissociated from gas hydrate samples is dominantly methane (>99.78%) with minor quantities of ethane. The chemical and isotopic compositions of the gas strongly suggest a biogenic origin for the analyzed samples. These new findings are regarded as strong enough evidence to consider the Rio Grande Cone as a new gas hydrate province.

Attenuation is one factor that degrades the quality of reflection seismic subsurface imaging. It causes a progressive decrease in the seismic pulse energy and is also responsible for limiting seismic resolution. Currently, many methods exist for inverse Q filtering, which can be used to correct these effects to some extent; however, but all of these methods require the value of the Q factor to be known, and this information is rarely available. In this paper we present and evaluate three different strategies to derive the Q factor from the time–frequency amplitude spectrum of the seismic trace. They are based in the analyses of the amplitude decay trend curves that can be measured along time, along frequency or along a compound variable obtained from the time–frequency product. Some difficulties are highlighted, such as the impossibility to use short time window intervals that prevents the method from providing a precise map of the Q factor value of the subsurface layers. However, the Q factor estimation made in this way can be used to guide the parameterization of attenuation correction by means of inverse Q filtering applied to a stacked seismic section; this is demonstrated in a real data example.

This work shows the results obtained from seismic physical modeling experiments that image the non-homogeneous, two-phase distribution of immiscible fluids inside a cavity in a pinch-out model. The main goal of this study was to verify how the seismic sections can be used to observe the fluid distribution in this type of reservoir. A high-resolution deconvolution method was applied to improve the image resolution and depth migration correctly positioned the events. Instantaneous attributes were used to assist data interpretation. The results provided an image of the oil–water interface and revealed a complex fluid compartmentalization pattern that was confirmed by numerical modeling simulations. The results of this study should improve the understanding of mapping fluid distributions from seismic sections in pinch-out reservoirs.

The continental shelf off the coast of central Brazil, extending from 10 to 16°S, is unusually narrow (~20km) and rests on the São Francisco craton. The shelf break is located between the 45 and 50m isobaths and coincides with major hinge-lines of the marginal basins. The shelf was exposed for most of the Quaternary period, particularly during the last 1my, when the average sea level was −62m. Submarine geomorphology is strongly influenced by this extended sub-aerial exposure and reduced subsidence, resulting in widespread incisions on the shelf. During the limited episodes of shelf inundation, as is the case today, a few meters of non-framework grain assemblages dominated by coralline algae accumulated on the outer shelf, while quartz sands were restricted to water depths of less than 10–15m. Mud accumulation on this unusually shallow shelf is aided by additional accommodation space provided by incisions and canyon heads indenting the shelf. Artisanal fisheries, targeting high-value commercial species associated with hard bottoms located on the outer shelf and shelf break, are the most important human use of this shelf. Data used in this study have been compiled from theses and previously conducted surveys and consist of four piston cores, 509km of chirp subbottom profiles and side scan recordings, and 711 bottom grab samples that have been analyzed for various textural and compositional aspects.

In order to perform a good pulse compression, the conventional spike deconvolution method requires that the wavelet is stationary. However, this requirement is never reached since the seismic wave always suffers high‐frequency attenuation and dispersion as it propagates in real materials. Due to this issue, the data need to pass through some kind of inverse‐Q filter. Most methods attempt to correct the attenuation effect by applying greater gains for high‐frequency components of the signal. The problem with this procedure is that it generally boosts high‐frequency noise. In order to deal with this problem, we present a new inversion method designed to estimate the reflectivity function in attenuating media. The key feature of the proposed method is the use of the least absolute error (L1 norm) to define both the data and model error in the objective functional. The L1 norm is more immune to noise when compared to the usual L2 one, especially when the data are contaminated by discrepant sample values. It also favours sparse reflectivity when used to define the model error in regularization of the inverse problem and also increases the resolution, since an efficient pulse compression is attained. Tests on synthetic and real data demonstrate the efficacy of the method in raising the resolution of the seismic signal without boosting its noise component.

The ratio of total organic carbon to total nitrogen (TOC:TN) and the stable carbon isotope ratio of organic matter (δ13Corg) are widely applied for inferring the origin of organic matter (OM) in Quaternary marine sediments. A plot of TOC:TN vs. δ13Corg is useful for such studies but is strongly based on qualitative constraints. This study is based on the qualitative characterization of the source of Quaternary OM via analysis of TOC:TN and δ13Corg signatures, but also proposes a probability parameter, which combines both signatures, to infer the amount of Terrestrial OM Input (TOMI). This index provides a method for quantifying the proportion of terrestrial OM vs. marine OMin a more comprehensive manner. The TOMI index concept was applied to a study area in theJoetsuBasin, eastern margin of theJapanSea, where previous studies have characterized theOMfrom the Last Glacial Maximum (LGM) to the present. The upwards increase in TOC indicates thatOMproduction during the Holocene was higher than during the LGM. The enriched δ13Corg signature upwards and decrease in TOC:TN suggest predominantly marine phytoplankton OM during the Holocene. Throughout the LGM, low OM production with depleted δ13Corg values and high TOC:TN values in the sediments suggest a predominantly C3 terrestrial plant source for the OM. Using these data, it was possible to calculate a proxy for a sea level variation curve during that period and to investigate the influence of the proximity of the coastal line to the continental slope on the input of terrestrial material to the basin. The proposal provides information for the application of sequence stratigraphic concepts. The TOMI index could confirm that the proximity to the shoreline and shelf break has a strong influence on the input of terrestrial material during lowstand periods.

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