Barra Velha Formation Research Articles

The influence of major faults and fractures on the development of non-matrix porosity system in a pre-salt carbonate reservoir, Santos Basin – Brazil

Faults and fractures are central for characterizing the permeability distribution in carbonate reservoirs since they act as pathways for diagenetic fluids that often favor intense rock dissolution and permeability. Usually, high permeability zones and fractures are not easily recognized in seismic data due to limited resolution and they are often associated with higher concentrations of hydrocarbons or even significant fluid losses during drilling, thus creating a challenge for hydrocarbon exploration. In the Santos Basin, southeast Brazil, the pre-salt carbonate reservoirs from the Barra Velha Formation (BVE) are the main hydrocarbon producers in Brazilian Atlantic margin and well-known for being extremely heterogeneous, exhibiting complex dual-porosity systems. In this study, we built a conceptual model of these fracture zones and non-matrix porosity formation that helped narrowing the understanding of these complex systems. The characterization of faults and fractures was carried out using seismic, well-logs, and borehole image data to understand the influence of these structures in the porosity formation along the Barra Velha Formation. In the study area, three fault sets were defined (F1, F2, and F3) from seismic data. F1 represents to the larger faults, while the F3 fault set represents the smaller faults related to the reactivation of F1; both sets being oriented NE-SW. The F2 fault set is associated with the rift formation and is oriented to NNE-SSW. These three fault sets compartmentalized the studied area into different domains, each exhibiting distinct fracture sets. The natural open fractures were formed during the reactivation of rift faults and are oriented mainly NW, NNE-NNW, NE, and ENE and were identified across the entire study area, but with different intensity values. The fracture intensity closely relates to the distance from major faults where the wells with the highest fracture intensity occurs located 150–590 m from the larger F1 fault set. Scan-lines were conducted throughout the area to determine the fault width, and an average value of 1.2 km was established. Seven non-matrix porosity classes were characterized and classified into stratigraphically concordant and discordant non-matrix pore types at well scale through borehole image interpretation. The Barra Velha Formation exhibit higher occurrence of stratigraphically discordant non-matrix porosity related to fractured zones while stratigraphically concordant non-matrix porosity is mainly controlled by the paleotopography of the study area. Overall, non-matrix porosity formation tends to follow an orientation that suggests a preferential dissolution flow towards NE and ENE directions. Intervals with higher silica content shows a positive correlation with both fracture intensity and stratigraphically discordant non-matrix porosities. This work provides a conceptual model about the fractures and non-matrix porosity distribution in pre-salt carbonate rocks that can help address some of associated structural and stratigraphic uncertainties during field appraisal and development.

Enhancing permeability estimation methods in Brazilian pre-salt complex carbonate reservoirs

Carbonate pre-salt reservoirs pose formidable challenges for formation evaluation and estimation of petrophysical properties such as rock flow capacity. The high complexity of the pore system and its textural heterogeneity often lead to poor predictions when using conventional formation evaluation methods. This paper discusses and tests the applicability of two approaches to calculate the absolute permeability curves for the carbonate reservoirs of the Barra Velha Formation in the Santos Basin, proposing a fine-tuned workflow for these complex rocks. In developing our workflow, we used data from a case study well, comprising a complete well log suite and two formation tests, and routine core analysis results (RCAL) in core plugs and sidewall cores. Our workflow consists of: (1) reinterpreting the nuclear magnetic resonance (NMR) log in vugular intervals by decomposing the transversal relaxation time spectra; (2) calculating the absolute permeability by the Timur–Coates model and adjusting the coefficients with the RCAL results from representative samples; (3) applying the Flow Zone Indicator (FZI) method for rock typing to optimally define Hydraulic Flow Units (HFU); (4) checking the consistency of HFUs regarding pore geometry and lithological characteristics; (5) evaluating the performance of the models against core data and formation tests. The predicted permeability curves performed well for the NMR and FZI models when compared to the RCAL data from representative samples, with mean absolute errors for the logarithm of permeabilities equal to 0.78 and 0.87, respectively. This represents an improvement of 15% and 5% when compared to the simplistic approach that uses a power law to relate porosity to permeability from RCAL. These curves also reasonably reproduce the results from the formation tests for the top part of the reservoir, where matrix porosity dominates the flow. However, the NMR and FZI permeability curves underestimate the test results at the bottom part of the reservoir, where karstic and fracture features dominate, demonstrating limitations in these permeability estimation methods for this specific scenario. From our observations, we propose several improvements to enhance the current methods for estimating absolute permeability in pre-salt carbonate reservoirs. In the case of the NMR approach, it is essential to consider the effects of mud invasion in vugs for the correct estimation of the proportions of free and irreducible fluids. In the FZI approach, optimization in defining the quantity and limits of hydraulic flow units is important, which shows that four units are sufficient to represent the reservoir interval.

A study on the accumulation model of the Santos basin in Brazil utilizing the source–reservoir dynamic evaluation method

The exploration potential within deep-water petroliferous basins holds great promise for oil and gas resources. However, the dearth of geochemical and isotopic data poses a formidable challenge in comprehending the intricate hydrocarbon charging processes, thereby impeding the comprehensive understanding of hydrocarbon accumulation mechanisms and models. Consequently, the establishment of robust source–reservoir relationships in deep-water petroliferous basins represents a pivotal challenge that significantly influences the exploration strategies and the comprehension of hydrocarbon enrichment dynamics within such basins. In this study, we introduce a novel approach, termed the “source–reservoir dynamic evaluation method,” tailored to investigate reservoir accumulation models in deep-water petroliferous basins. This method uses basin simulation technology to recover the thermal evolution history and hydrocarbon generation and expulsion history of source rocks, and on this basis delimits the hydrocarbon kitchen range. At the same time, the maturity of source rocks corresponding to crude oil and natural gas in typical reservoirs is calculated. Then, when the thermal evolution degree of source rocks adjacent to the reservoir reaches this maturity, the corresponding geological period is the main charging period of hydrocarbon. As a typical deep-water petroliferous basin, the Santos Basin in Brazil has abundant oil and gas reservoirs under the thick salt rock, but there are still some fundamental problems such as unclear oil–gas accumulation process and model. Therefore, in this paper, the main charging periods of typical hydrocarbon reservoirs are determined based on the internal relationship between the thermal evolution history of the main source rocks and the maturity of crude oil and natural gas, and then the hydrocarbon accumulation process is analyzed and the dynamic accumulation model is established. Finally, the favorable prospecting direction is pointed out. The results show that the oil and gas in the Barra Velha Formation in the Santos basin are mainly derived from the Itapema Formation lacustrine shale source rock, and the source rock is mainly developed in the Eastern Sag of the Central Depression, and its main hydrocarbon generation period is from the deposition period of Florianopolis Formation to the deposition period of Santos Formation. The main hydrocarbon expulsion period was from the deposition period of the Santos Formation to the Early deposition of the Iguape Formation. The oil and gas in the Barra Velha Formation were mainly charged from the Late deposition period of the Santos Formation to the Early deposition period of the Iguape Formation. During this period, the hydrocarbon migrated vertically along the normal fault formed in the rift period to the trap of the adjacent inheritance structural highs and accumulated in the reservoir, which was dominated by the accumulation model of the “lower generation-upper reservoir-salt cap”. Since the Barra Velha Formation has the characteristics of near-source accumulation, based on the hydrocarbon expulsion center and hydrocarbon expulsion intensity of the source rock of the Itapema Formation, the distribution ranges of 85% and 50% Pre-salt accumulation probability in the Santos basin were calculated by using the quantitative analysis model of the hydrocarbon distribution threshold. It is suggested that the next oil and gas exploration should be carried out in the paleo-structural highs and slope of Class I favorable area (the hydrocarbon accumulation probability is more than 85%) and Class II favorable area (the hydrocarbon accumulation probability is 85–50%).

U-Pb dating of Barra Velha carbonates reveals the influence of Santos Basin sedimentary and tectonothermal history on pre-salt carbonate ages

The depositional age and diagenetic history of the Upper Barra Velha carbonates are poorly understood. To clarify the geochronology of these events and the behavior of the U-Pb isotopic system in carbonates, we conducted an integrated petrographic, QEMSCAN imaging, and in situ U-Pb dating study of calcites and dolomites from the Barra Velha Formation, in the central Santos Basin (SE Brazil). Our results span three geochronological intervals, which are ∼125 Ma, ∼116-114 Ma, and ∼105-100 Ma. The U-Pb isotopic system of calcite allochems was disturbed, yielding ages of ∼115 Ma and ∼105-100 Ma. These ages coincide with magmatic and hydrothermal events in the pre-salt. Dolomites showed that geochronological disturbance of carbonate components may not be pervasive but rather related to fluid-rock interactions and properties of rocks and their constituents such as mineralogy, porosity and permeability. This is evidenced by the U-Pb system of non-porous, non-permeable, and less reactive dolomitic aggregates remaining undisturbed. Eodiagenetic microcrystalline and fine dolomite rhombs provided evidence of Barremian ages, challenging the belief that the Upper Barra Velha deposits are Aptian. Other eodiagenetic dolomites occur as ∼117 Ma eodiagenetic lamellar dolomites, as pseudomorphic dolomites that underwent U-Pb alteration at ∼100 Ma, and as ∼112 Ma pervasive rhombohedral dolomites associated with Mg-rich fluids percolation in the Upper Barra Velha carbonates. Blocky dolomite and saddle dolomite cements have ages of ∼100 Ma, with saddle dolomite constraining the latest silicification event as > 100 Ma. This research elucidates significant geological events, processes, and factors (including magmatic activity, hydrothermal alteration, fluid-rock interactions, and petrographic and mineralogical controls) that influenced the ages of the Upper Barra Velha carbonates. Moreover, it aids in reconstructing the depositional and diagenetic history of the Barra Velha Formation and enhances the understanding of the Santos Basin tectonothermal evolution.

Bridging the gap: Integrating static and dynamic data for improved permeability modeling and super k zone detection in vuggy reservoirs

Permeability modeling in fractured and vuggy reservoirs presents significant challenges, especially in carbonate reservoirs like Brazil’s Barra Velha Formation. The interpretation of vug properties is often subject to misconceptions. It is common to mistakenly consider vugs as part of the matrix, attributing uniform porosity and permeability properties. Alternatively, they are sometimes regarded as fractures, attempting to replicate the influence on permeability enhancement. However, vugs exhibit distinct behavior compared to fractures. Their characteristics are contingent upon factors such as geometry, size, and their relationship with the matrix. Existing methods often overlook the substantial impact of vuggy porosity, leading to inadequate representation of permeability values obtained from core plug measurements or downhole static data, such as Nuclear Magnetic Resonance (NMR) logs. In contrast, dynamic data derived from drill-stem tests (DSTs) and inferred from the Productivity Index (J) provide a more holistic view of the reservoir’s permeability, yet typically yielding a single permeability value for each interpreted interval. This research introduces a novel methodology that addresses these challenges by integrating static and dynamic data, with a primary focus on vuggy porosity using a permeability indicator from a dynamic source. A key innovation lies in the development of a method for estimating total permeability in vuggy intervals, accounting for the effects of vugs and calibrating permeability with dynamic data such as J, DST and Production Logging Tests (PLT). We substantiated the impact of vugs on the augmentation of permeability and production through the application of a localized reservoir simulation model around a key well. Two sensitivity analyses were conducted, one employing a grid representing matrix permeability and another incorporating total permeability with adjustments accounting for the influence of vugs. Additionally, we present two approaches for estimating vuggy porosity: one based on acoustic WellBore Image (WBI) and the second through image segmentation, which can be applied universally across different wellbore image formats. Furthermore, this study explores the concept of superkzones, representing intervals with exceptionally high permeability. The partitioning coefficient (CP), quantifying the relationship between vuggy porosity and total porosity, is employed to generate a probability curve for the occurrence of superkzones in intervals lacking production data. This curve accounts for critical factors such as pressure drop and fluid viscosity, providing a more comprehensive understanding of reservoir behavior. Through a comprehensive case study, our research aims to shed light on the intricate permeability characteristics of the Barra Velha Formation, while identifying the presence of superkzones. The proposed methodologies offer a bridge between static and dynamic data, resulting in a continuous permeability curve that aligns more closely with production data. Ultimately, this work contributes valuable insights for reservoir management and the production strategies optimization in complex carbonate reservoirs within the Santos Basin.

Early diagenetic evolution based on petrography and stable isotope analysis in the Barra Velha Formation of the Brazilian Pre‐salt

AbstractMineralogy and texture of diagenetic phases in the Aptian Pre‐Salt Barra Velha Formation are described, quantified and compared by facies and structural setting to understand their spatial and temporal distribution, and to develop predictive concepts for their genesis. This study examined data from eight wells from one oil‐field in the Santos Basin. Calcite is the most abundant mineral and occurs with fibro‐radial texture as spherulites and shrubs and sparse microcrystalline mudstone. The δ18O values from calcite spherulites and shrubs suggest water of similar composition and temperature, but they have different δ13C values. Mudstones show lower δ18O, suggesting warmer lake water and/or lower evaporation, whereas δ13C values indicate a variable, but commonly strong influence of biogenic CO2. Dolomite with rhombohedral habit was the first to precipitate, followed by lamellar, saddle and anhedral varieties. Rhombohedral dolomites show a positive δ13C‐δ18O correlation and a similar range in values to spherulites and shrubs, suggesting similar lake water. The lamellar dolomite is related to biofilms, whereas anhedral dolomite is attributed to mixing of pore and meteoric waters. Lamellar and anhedral dolomites have similar isotopic values, precipitating after rhombohedral dolomite in slightly warmer and/or less evaporatively concentrated pore water. Saddle dolomite is related to hydrothermal fluids that percolated the formation during early diagenesis. Silica occurs as replacement of primary calcite and Mg‐clay, but also as a cement and more rarely as a depositional chert. Both dolomite and silica display a complex range of petrographic textures, many of which are facies dependent. This study focusses on the most important phases of the paragenetic sequence that took place pre‐burial and are (1) formation of Mg‐clay, calcite spherulites and shrubs, (2) partial dolomitisation of shrubs and spherulites and precipitation of rhombohedral and lamellar dolomites, (3) precipitation of saddle dolomite, matrix and carbonate dissolution and (4) anhedral dolomite and all textures of precipitated or substituted silica.

The importance of core for carbonate reservoir evaluation: a case study from the Barra Velha Formation, Santos Basin, Brazil

Abstract The lacustrine carbonates of the Barra Velha Formation are a prolific hydrocarbon reservoir in the Santos Basin, Brazil. In many fields, they comprise decimetre- to metre-scale cycles composed of laminated calcimudstones, spherulite and shrub-dominated facies. However, locally these cycles are replaced by decametre packages of re-worked shrub grainstone/rudstone/breccia and in situ shrub framestone with significant (>30°) depositional dips. The latter could be interpreted in several ways (e.g. fault-block highs, carbonate mounds), but the integration of seismic, borehole image log and whole-core datasets converge on a model of aggrading carbonate mounds which developed in or marginal to a lake setting. The core datasets in this study demonstrate a distinctive depositional fabric within the carbonate mounds. From a production geology standpoint, the crucial difference between mound- and cyclothem-dominated successions is their permeability architecture. Cyclothem-dominated intervals show prominent and laterally continuous, decimetre-scale vertical matrix permeability variations. Mound-dominated intervals lack fine-scale palaeo-horizontal layering and exhibit a greater prevalence of irregular, centimetre-scale conduits and higher vertical permeability. This difference can only be reliably characterized via the integration of whole-core samples with other datasets and has a significant quantified impact on sweep and production performance.

Correlation between geomechanical and sedimentary facies and their implications for flow unit definition in the pre-salt carbonate reservoir, Brazil

Carbonate reservoirs are of great economic importance due to their frequent association with high permeability and hydrocarbon storage capacity. One of the most significant discoveries of this type of reservoir in recent decades has been the Brazilian Pre-salt. This deep reservoir has unusual depositional features, consisting of a wide variety of textures with different compositions, influenced by diagenetic overprinting that modify most of its mechanical, elastic and petrophysical properties. Despite the marked heterogeneity, these carbonates are characterized by excellent reservoir quality. The objective of this study is to establish a correlation between geomechanical behavior and sedimentary facies and its implications for the definition of flow units in the Barra Velha Formation, the main reservoir of the Brazilian Pre-salt. Thus, using a database from the Buzios field composed of well logs (conventional and advanced), well tests, thin sections, and laboratory petrophysics, geomechanical facies (GMFs) were defined using dynamic geomechanical modeling and an unsupervised algorithm (K-mean clutering), followed by textural classification of sedimentary facies and definition of flow units (FUs) on the decametric scale. These classifications were compared using frequency histograms. The geomechanical model revealed that the in-situ stress state exhibits a dual regime, between normal and strike slip. In addition, it was found that the direction of the maximum horizontal stress is in the NE-SW azimuth. In this context, four geomechanical facies were defined, which showed a notorious variation in mechanical strength. The strongest GMFs consisted mainly of well-cemented Grainstones and Packstones with no apparent porosity or microcrystalline porosity and correlated with the FU with the worst production rates. On the other hand, the weaker GMFs were mainly composed of Grainstones and Spherulistones with high intergranular porosity generated by dissolution processes, with higher risk of pore collapse and correlated with the FUs with the best production rates. However, this classification also identified laminated mudstones with microporosities associated with FUs that act as flow barriers. Geomechanical facies have also been incorporated into reservoir development by evaluating wellbore stability, fault reactivation risk, and brittleness index for future CO2 injection projects.

Primary microfossiliferous chert in the Aptian Barra Velha Formation

ABSTRACTThe Barra Velha Formation and other Aptian pre‐salt deposits record the history of the proto‐Atlantic basin and the rifting of Gondwana. Studies have sought to characterize the depositional environment of the basin with a focus on carbonate fabrics and magnesium silicate clays. However, the water chemistry and fluid sources in the basin, the silica cycle, and how the basin evolved over time are not fully constrained. Additionally, current understanding of the microbiota that inhabited this basin is incomplete because microfossils have rarely been identified in pre‐salt deposits, especially on the Brazilian margin. This study describes authigenic chert in the Barra Velha Formation that preserves distinct, organic‐rich structures and textures. The petrographic relationships between the chert and carbonate suggest that both formed as authigenic phases, but their formation was temporally decoupled. These relationships and δ30Si and δ18O data suggest that chert post‐dates the formation and subsequent dissolution of the carbonates, and may have formed from a different fluid. By characterizing the chert–carbonate paragenesis and mechanism of chert formation, this study provides new insights into the fluid sources and complexity of the basin. Together, the results of this research suggest that the chert precipitated as primary, authigenic phases after karstification of the carbonate from a newly introduced, low temperature, freshwater fluid that was chemically distinct from the lake water. The chert preserves organic matter that is compositionally and texturally distinct from the void‐filling bitumen associated with the classically studied carbonate facies. Based on the composition and morphologies of organic structures, this is likely primary organic matter and a morphologically diverse microfossil assemblage preserved in place at the time of chert formation. Thus, this early chert provides new insights into the water chemistry, fluid sources and silica cycle in the basin, and represents a unique taphonomic window that helps us characterize the pre‐salt basin microbiota.

High-resolution stratigraphy and characterization of reservoir-critical heterogeneities in the giant Tupi Field, pre-salt Santos Basin, Brazil

Abstract The large oil discoveries that have occurred in recent decades in the pre-salt section of the South Atlantic sedimentary basins have promoted a significant volume of scientific research regarding the origin of these deposits. Most of the current studies of this stratigraphic interval focus on regional aspects or sedimentological and diagenetic processes. However, few studies encompass the geological characteristics of the pre-salt deposits from a reservoir-scale perspective. This work addresses the construction of a detailed reservoir-oriented stratigraphic framework for the giant Tupi Field. Discovered in 2006 following a successful exploratory campaign in the southeastern Brazilian deep-water, the Tupi Field's main reservoirs are sag-phase carbonates from the Aptian-aged Barra Velha Formation. These rocks accumulated in alkaline to highly alkaline lacustrine settings, which allowed the development of unusual syngenetic elements, such as magnesian clays, calcitic spherulites and calcitic shrubs. The reservoirs' depositional organization was essentially conditioned by climatic oscillations and tectonic activity, which controlled sedimentation rates and accommodation styles through space and time. The high-resolution stratigraphic framework established in this article supports a detailed understanding, at different scales, of the Tupi Field's sedimentological evolution and its main vertical and lateral facies distribution. These aspects have, in turn, provided essential inputs for reservoir characterization and constrained critical heterogeneities of the 3D geocellular model, even in reservoirs affected by diagenetic processes.

Dynamic re-sedimentation of lacustrine carbonates in the Búzios Field, pre-salt section of Santos Basin, Brazil

The huge oil accumulations in the South Atlantic Pre-Salt section have driven studies that seek a greater understanding of the origin and evolution of these important reservoirs. Lacustrine carbonate intraclastic deposits correspond to the main reservoirs in the Búzios Field, currently with the highest daily production wells in the world, and in other Santos Basin fields. However, few studies were dedicated to these deposits due to the great complexity of Pre-Salt deposits and the lack of analogs. These factors have generated intense controversies in the interpretation of their depositional models. A systematic petrographic characterization allowed detailed characterization of the textures and primary constituents in the rift and sag sections of a well in the Búzios Field. The bioclastic accumulations of the rift Itapema Formation, show features indicative of reworking, such as abrasion, fragmentation and disarticulation of the bivalve bioclasts. Moreover, the bioclasts occur mainly within intraclasts and as nuclei of ooids, characteristics of multicycle redeposition. The massive structure of these deposits, the lack of characteristic wave structures, their distribution in lows and conspicuous mixing with stevensitic grains indicate their gravitational redeposition, as result of the intense tectonic activity during the rift phase. The sag phase Barra Velha Formation deposits are composed of intraclasts eroded from the in situ spherulites and shrubs. These rocks are predominantly massive, lack subaerial exposure features, and display features that point to dynamic and multicyclic reworking. Furthermore, they occur intercalated with in situ deposits in high frequency, even at a thin section scale. These aspects, along with the consistency of isotope values, the widespread spatial distribution and preservation of stevensite across diverse Pre-Salt areas, suggest that gravitational, waves and currents redeposition models should be reevaluated. We propose that internal waves, generated by perturbations of the chemocline of a meromictic, stratified lacustrine system promoted recurrent reworking of the in situ deposits. This generated intraclastic levels with multicycle redeposition aspects, often interlayered with the characteristic in situ deposits. Understanding the processes that generated these deposits will contribute to reduce exploration risks and optimize hydrocarbon production from the intraclastic reservoirs.

Interactions between Clays and Carbonates in the Aptian Pre-Salt Reservoirs of Santos Basin, Eastern Brazilian Margin

The giant Pre-salt reservoirs represent most of the oil production in Brazil. The main Aptian sag reservoirs were deposited in a unique and highly complex hyper-alkaline lacustrine setting. These deposits are essentially constituted by fascicular and spherulitic calcite precipitated in a magnesian clay matrix (stevensite, kerolite, and saponite/hectorite). Although vital for understanding the origin and main reservoir quality control, the genesis and interactions of clays and carbonates are still poorly constrained. The detailed petrographic description was focused on 812 thin sections from five wells drilled in the Santos Basin Aptian Barra Velha Formation, combined with cathodoluminescence, UV epifluorescence, and X-ray diffraction analyses. The main syngenetic processes were the deposition of finely laminated peloidal and ooidal Mg-clays, the formation of fascicular calcite crusts on the sediment–water interface, and the redeposition of these materials as intraclasts. Abundant clay peloids engulfed in syngenetic shrubs indicate that calcite and clay precipitation was concomitant, though with highly variable rates. Eodiagenetic phases include matrix-replacive and -displacive spherulites and fascicular shrubs; matrix-replacive blocky calcite and dolomite; lamellar carbonates filling matrix shrinkage pores; and microcrystalline calcite, dolomite, and silica replacing the Mg-clay matrix. The preferential dolomitization and calcitization of peloidal layers were most likely due to their higher permeability and larger specific surface. Matrix-replacive saddle dolomite, macrocrystalline calcite, and dawsonite are interpreted as mesodiagenetic or hydrothermal phases after significant matrix dissolution. Unraveling the processes of the formation and alteration of the carbonates and clays and their interactions in the Pre-salt deposits is essential for constraining the depositional and diagenetic conditions in their unique environments and their diagenetic overprinting and for decreasing the exploration risks and increasing the production of those extraordinary reservoirs.

Petrographical and petrophysical characterization of pre-salt Aptian carbonate reservoirs from the Santos Basin, Brazil

Reservoir quality in carbonates is influenced by various factors such as the depositional environment, burial history and diagenesis processes. Understanding these geological heterogeneities is essential for successful petroleum exploration. This study characterizes Brazilian pre-salt reservoirs and aims to understand how their heterogeneity impacts reservoir quality. We analysed carbonate samples from the Barra Velha Formation (Santos Basin) through an integration of petrographical and core plug descriptions, petrographical facies characterization, porosity and permeability measurements, and image analysis to identify the principal controls on porosity and permeability, pore-size distribution, and groups with similar petrophysical properties using the hydraulic flow unit (HFU) concept. Five facies groups were recognized: Spherulitestone (F1); Shrubstone (F2); Intraclastic Grainstone (F3); Intraclastic Packstone, Spherulitestone with mud and Shrubstone with mud (F4); and Shrub–Spherulite Intercalations and Bioclastic Grainstone (F5). The analysis of porosity and permeability showed that their variations are associated with pore type and cementation rate. Greater contributions of inter-aggregate, interparticle and vugular porosity, combined with a reduced amount of cement, results in higher porosity and permeability but an increase in cement tends to reduce the porosity and permeability. Among the facies groups, F2 and F3 exhibited the best porosities and permeabilities, followed by F1, F4 and F5. From image analysis, small pores (1.5 × 10 −5 –0.01 mm 2 ) are the most common in all rocks. However, these small pores contributed significantly to total porosity only in F4 and some samples of F3. For F2 and F3, the large pores (from 0.01 mm 2 to a maximum of 19.62 mm 2 ) are the main contributors, while F5 has a homogeneous contribution. Finally, the data were grouped into five HFUs: HFU1 and HFU2 represent the zones with the best reservoir quality, primarily composed of F2 and F3.

Deformational structures in the lower Barra Velha formation, Aptian, Atapu field, Santos Basin

The Barra Velha Formation, an Aptian Pre-salt unit of the Santos Basin, southeastern Brazil, is well-known for containing an important hydrocarbon reservoir. In the Atapu field, the lower part of the formation consists of laminated lutite (carbonate, siliciclastic, and hybrid), microbialite, and tufa rocks. The succession records muddy and in situ carbonate deposition in a low energy and shallow alkaline lacustrine environment in an active rift basin. Millimeter to decimeter scale soft-sediment deformation structures, faults, and fractures are very frequent and recurrent along the lutite succession. Convolute folds, loop bedding, injectites, intraclastic breccia, diastasis cracks, and associated faults, record ductile-brittle deformation in semi-lithified sediments. Normal planar and listric faults and unconfined fractures register dominant brittle deformation in lithified sediment. Foliated cataclasite and rare reverse faults record downdip slip on the hanging wall of temporarily inactive listric faults. The set of structures, the geological model, and the absence of other evident trigger mechanisms indicate that both ductile and brittle deformation are related to seismic events. The soft-sediment deformation structures are interpreted as having evolved during seismic shaking, while foliated cataclasite probably registers inter-seismic creep deformation.

Unravelling the origin of reworked deposits in Aptian lacustrine carbonate reservoirs of the Santos Basin, SE Brazil

The Barra Velha Formation, representing the uppermost Aptian formation of the Santos Basin, predominantly comprises dolomudstones, intraclastic grainstones, and rudstones. Additionally, spherulitic and Mg-rich claystones suggest deposition in a shallow alkaline lacustrine environment. Despite the significance of reworked deposits within the Barra Velha Formation, limited attention has been given to understanding their origin, provenance, and their link to high well productivity. This study aims to characterize the reworked carbonate facies and establish their diverse genesis using a multi-scale approach. Through the analysis of core samples retrieved from the upper 19 m of the Upper Barra Velha Formation, we identified eight sedimentary facies, including microfacies grouped into two distinct associations: back-barrier deposits and foreshore-shoreface transition deposits. Back-barrier deposits consist of shrubstones, laminated shrubby spherulitestone, laminated mudstone, massive grainstone, and massive rudstone facies, composed of in situ facies and carbonates reworked by wave and distal hyper-concentrated flow. Foreshore-shoreface transition deposits comprise laminated grainstone, pebble grainstone, and massive rudstone. The facies analyses provide insights into swash-backwash effects, hyper-concentrated flow, and high wave reworking deposits. Detailed interpretation of seismic reflectors in the Uppermost interval of Barra Velha Formation revealed two distinct geometric patterns: high-amplitude onlapping seismic reflectors toward the basement and bidirectional high-amplitude reflectors on the platform edge. These patterns primarily consist of spherulitestones, shrubstones, and grainstones-packstones BHI facies. Gravity flow deposits of a fan-delta in the Lowermost interval of the Barra Velha Formation were interpreted as rudstones-grainstones and mixed reworked carbonates/volcanic rocks BHI facies, associated with low-amplitude sheet-like shape reflectors dipping toward the slope seismic reflectors. Based on the constructed onlap curve derived from the seismic lines in the study area and the described facies associations, it is evident that the lake margins are expanding, conducive to the formation of reworked facies mainly associated with wave action.

Depositional and diagenetic characteristics of the Lula's Fingers: Evidences of microbial activity and exposure during final pre-salt depositional in Santos Basin

Over the past decade, considerable progress has been made in the understanding of non-marine carbonate rocks following the discovery of substantial oil reserves in the pre-salt region off the eastern coast of Brazil. The Lula's Fingers interval, situated at the top of the Barra Velha Formation, has been identified in gamma-ray log patterns as a crucial stratigraphic marker for the pre-salt deposits in the Santos Basin. Despite its stratigraphic significance, comprehensive sedimentological and petrographic studies on this interval are lacking. This absence of detail studies may be associated with the recurrence of fine-grained non-marine carbonate rocks. This study employs a range of techniques, including classical sedimentology (macro- and microscopic description), Markov Chain analysis, and complementary methods such as quantitative analysis using XRD, SEM-EDS, cathodoluminescence, and epifluorescence. These techniques are used to evaluate the sedimentological and diagenetic characteristics of the fine-grained non-marine carbonate rocks in Lula's Fingers interval. In general terms, the interval consists of in situ rocks formed through abiotic chemical precipitation (such as parallel-laminated calcilutite, laminated spherulestone, and shrubstone), as well as reworked calcarenites and calcirudites formed under high-energy conditions, resembling those described for the Barra Velha Formation. However, it differs primarily from the main Barra Velha deposits in the presence of (i) calcilutite exhibiting crenulated lamination, peloidal/pseudo-peloidal to clotted texture, and microbial lumps, providing substantial evidence of microbial activity, and (ii) nodular calcilutites with a pseudo-particulate texture. The presence of nodular calcilutites suggests that the deposition of the Lula's Fingers interval occurred in shallow to very shallow settings, occasionally experiencing subaerial exposure, in contrast to the alkaline lake settings interpreted for most of the Barra Velha Formation. Dolomitization and silicification within the Lula's Fingers interval have significantly altered the rocks, hindering the identification of primary texture and composition. Silica and dolomite commonly fill pores and function as replacive minerals across various lithofacies and microfacies. Lamellar dolomite emerges as the dominant texture within the study succession, often filling interstices between spherules and shrubs. Its presence is likely associated with a precursor detrital or authigenic material, possibly a magnesium clay matrix, which still influences the final texture of the rock despite complete replacement.

Coquina depositional model, Buzios Field, Brazil

Increasingly relevant as petroleum reservoirs, the coquina deposits of the pre-salt section of the Santos and Campos Basin display a wide variety of sedimentary systems that reflect a complex storm-dominated depositional environment. This complexity resulted in the deposition of numerous sedimentary facies distributed among structural lows and highs, and their understanding is an essential aspect in order to reduce exploration risks. Therefore, the aims of this contribution are twofold: (a) to understand the depositional processes during the generation of the Itapema Formation coquina deposits in the offshore pre-salt Buzios Field, Santos Basin, and (b) to establish a depositional model and identify stacking patterns in the coquina section. The facies analysis was based on rock texture, structure, allochemical composition, taxonomic composition, and taphonomic characteristics of bivalve shells, such as fragmentation, abrasion, sorting, thickness, orientation, and articulation. We described 695 thin-sections and sidewall samples distributed among ten wells in the field area. The analysis resulted in sixteen facies grouped into eight facies associations: (1) bioclastic bars, (2) washover deposits, (3) backshore, (4) bioclastic beaches, (5) tempestites, (6) tempestites with articulated shells, (7) offshore and offshore transition deposits, and (8) offshore siliciclastic mudstones. These carbonate facies associations were deposited mainly under the influence of waves and currents in isolated ramp-shaped margined platforms with low continental input associated with active faults, characteristic of the rift phase of the basin evolution. The stacking of the facies associations indicates that the Itapema Formation coquinas were deposited in an environment that became progressively shallower towards the top contact with the overlying Barra Velha Formation. Siliciclastic mudstones mark the top of the Itapema Formation immediately below the Pre-Alagoas unconformity, indicating a significant lake deepening that drowned the coquina section. The depositional model is the first one about the Buzios Field and the first about the pre-salt fields coquinas based on field-scale information.

Synthetic seismic-stratigraphic interpretation from a sedimentological forward model in a pre-salt field in the Santos Basin

Forward modelling of sedimentary systems is a method that simulates sedimentation processes over geological time to generate a set of facies distributed in a depositional space. The objective of using forward modelling in this work was to build a 3D facies model from which a synthetic seismic simulation was generated, and then to analyse the relation of seismic-stratigraphic interpretations with the knowledge of the a priori generated sedimentological model. This modelling methodology was applied in a pre-salt field in the Santos Basin, Brazilian offshore, focused on the Barra Velha Formation. The modelling parameters used were: (i) the initial surface of bathymetric depth; (ii) the lake-level variation; (iii) the subsidence map; and (iv) the deposition rates of the facies. Average-constant of acoustic impedance values were assigned to each facies and a synthetic seismic was obtained. With the facies and synthetic models available, it was possible to analyse: (i) the distribution of thicknesses and proportion of facies by region; (ii) the vertical stacking pattern and lateral facies variation; (iii) the Wheeler distance × time diagram; and (iv) the seismic reflector patterns through the seismic facies classification. Through these analyses it was possible to better understand the possibilities and limitations of seismic stratigraphy as an interpretation auxiliary tool in pre-salt carbonate environments.

The lower Barra Velha formation (Aptian) in the Atapu field, Santos basin: Geological model for a pre-salt succession

The characterization of facies, microfacies and facies successions allowed to develop a conceptual geological model for the lower succession of the Barra Velha Formation in the Atapu field, Aptian of the Santos Basin. The obtained data and interpretations were based on the detailed description (scale 1:10) of ca. 90 m of two almost continuous well-cores and petrographic analysis. The facies were defined based on their primary depositional attributes, which are well recognized despite diagenetic modifications. Lutites, microbialites, tufa-rocks, calcirudites constitute the main recognized facies. The clastic lutites recorded transport and deposition of terrigenous and intraformational clasts by hydrodynamic and gravitational processes in low energy and shallow lacustrine environment. Microbialites and tufa-rocks record in situ carbonate deposition in alkaline saturated waters. Injectites, diastasis cracks, loop bedding, slump folds, many of the normal and listric faults and fractures are syn-depositional structures interpreted as primarily induced by tectonics. Facies changes allow to divide the succession in three stratigraphic intervals. Lutites predominates in intervals 1 and 3 whereas tufa-rocks constitute the interval 2. In the lower part of interval 1 labile fresh siliciclastic components and tractive and gravitational structures are abundant, indicating dry climate but with sporadic rainfall during a period of relative high water level of the lake. The upward decreasing of siliciclastic fragments, the appearance of coarse microbialite and a fish mortality level in the upper part of interval 1, mark the transition to the tufa-rocks of interval 2. These latter features denote a relative dryer climate and higher alkalinity waters, and a low water level of the lake. The interval 3 lutites cover abruptly the tufa-rocks recording the drowning of the succession. This may be related to renewed rifting or to the beginning of the basin thermal subsidence.

Utilizing integrated artificial intelligence for characterizing mineralogy and facies in a pre-salt carbonate reservoir, Santos Basin, Brazil, using cores, wireline logs, and multi-mineral petrophysical evaluation

In complex carbonate reservoirs, it is crucial to understand the connections between reservoir compositions (minerals, facies, and properties). Conventionally, core samples have been used to measure reservoir parameters and identify minerals and facies. However, core samples are limited to certain wells. Therefore, additional techniques are necessary to overcome this limitation comprehensively. This study aims to identify key mineralogical and facies components of the Barra Velha Formation (BVF) and their relation to reservoir parameters. Dolomite, calcite, quartz, and clay minerals were commonly found using X-ray Diffraction (XRD). By employing multi-mineral (MM) petrophysical evaluations, we accurately recreated mineral quantities from XRD and petrophysical properties from core analysis to ensure reliability. Replications of inputs well logs and the mineralogical volume from spectroscopic (ECS) were used as reliability techniques for validating the MM. A total of 47 wells were analyzed using those methods. In this study, the classification of facies was accomplished through the selection of three prominent supervised artificial intelligence techniques, among which SOM, a widely employed method for facies estimation, was included. Additionally, the ensemble methods of Random Forest and XGBoost were adopted due to their recognized efficacy in handling tabular data and their track record of success in machine learning and artificial intelligence competitions. Remarkably, the performance evaluation revealed that Random Forest and XGBoost algorithms outperformed SOM, yielding the most favorable outcomes in this context. An integrated analysis of mineralogical and facies results was conducted, incorporating production data and special profiles such as nuclear magnetic resonance (NMR) and Wellbore Image (WBI) to identify vug-containing areas. The dolomitic facies exhibited favorable reservoir qualities, influenced by diagenetic processes represented by vuggy porosity, which enhanced permeability. Shrubstones, spherulites, and reworked facies showed superior petrophysical qualities and were connected with productive regions, leading to elevated dolomite concentrations, and vuggy abundance. The study highlights two major innovations: the use of mineralogical volume from multi-mineral assessments as inputs for AI-based property estimation to improve facies estimates, and the discovery of relationships between facies, minerals, and reservoir properties, compared to production data. This understanding allows for more accurate static model creation, optimal production interval selection, improved hydrocarbon recovery, and better specification of stimulation processes.