Pre-salt Carbonate Research Articles

3D modelling of flow units and petrophysical properties in brazilian presalt carbonate

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.

Geological process modeling and geostatistics for facies reconstruction of presalt carbonates

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.

Geochronology of volcanically associated hydrocarbon charge in the pre-salt carbonates of the Namibe Basin, Angola

Abstract In volcanic rifted margins, the timing of hydrocarbon charge is difficult to predict, but is important in understanding fluid genesis. We investigated whether igneous activity was linked to hydrocarbon charge in the prolific South Atlantic pre-salt petroleum system. To do this, we applied in situ carbonate U-Pb geochronology, a relatively novel tool for dating hydrocarbon migration, to bituminous veins in pre-salt travertines from the rifted onshore Namibe Basin (Angola). To test if fluid flow was synchronous with known volcanic pulses, we also obtained new 40Ar/39Ar geochronology from a nearby volcanic complex. Bitumen is associated with calcite in a first generation of veins and vugs, and with dolomite in younger veins. The dated calcite veins yielded a pooled U-Pb age of 86.2 ± 2.4 Ma, which overlaps the volcanism 40Ar/39Ar age of 89.9 ± 1.8 Ma. The overlapping dates and the localized bitumen occurrence around the dated volcanic center show a clear genetic relationship between Late Cretaceous igneous activity and hydrocarbon charge. The dolomite was dated at 56.8 ± 4.8 Ma, revealing a previously unknown Paleocene/Eocene fluid-flow phase in the basin.

E&P Notes (October 2020)

E&P Notes (October 2020)

4D petroelastic modeling based on a presalt well

After their initial discovery in 2006, followed by an accumulated production of over 2 billion barrels of oil equivalent, the presalt carbonate reservoirs of offshore Brazil are now candidates for time-lapse seismic analysis. Therefore, we have conducted a 4D feasibility study in a Brazilian presalt reservoir well, which is composed of two types of carbonate rocks: microbialite and coquina. We evaluated two petroelastic models to obtain the acoustic impedance (AI) and shear impedance (SI) needed to estimate potential time-lapse differences ([Formula: see text], [Formula: see text], and [Formula: see text]). For this, we used the Gassmann and Xu-Payne models, in which the latter considers the pore geometry of the rock in its equations. Our analysis of both models shows that changes in pressure and saturation are very similar, and we can conclude that, despite being a carbonate, the application of Gassmann’s model is sufficient for the 4D feasibility studies conducted in the deemed reservoir because it does not require pore space geometry parameters, as does the Xu-Payne model. The analysis of the time-lapse attributes provided us with a greater comprehension of the 4D scenarios modeled, some of which presented detectability of changes in the microbialite and coquina.

Decameter-Scale Flow-Unit Classification in Brazilian Presalt Carbonates

Summary 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 (ϕ) 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.

Role of Brazil’s Continental Slopes in Being Provided with Hydrocarbon Resources

Abstract—Analysis more of 80 hydrocarbon fields, mainly oil-producing, in the deepwater part of the Santos, Campos and Espirito Santo basins reveal the tendency of these large fields to lie in a productive oil-pay belt extending in the sea depth from range from 400 to 2500 m (possibly 3000 m or more) in a system of external depressions stretching along the lower part of the continental slope. This belt may continued to the north. All the fields in this belt in reserves category are estimated as large and giant. In the last 10–15 years, exploration works have been conducted in this belt already in the presalt formation: in the Santos Basin, 29 fields; in the Campos Basin, 21; and in the Espirito Santo Basin 7. It is noteworthy that 48% of the total hydrocarbon production of the country formed in presalt carbonate deposits of the Aptian Formation on the continental slope, 44% postsalt rocks on the continental slope and shelf, and only 8% is attributed to the mainland. In the world, Brazil’s deepwater presalt Aptian Formation (Barremian–Aptian in the Santos Basin) is essentially unique. In recent decades, giant hydrocarbon accumulations have been discovered, thereby doubling the country’s oil and gas reserves to total reserves of more than 3 billion t and 4.7 trillion m3, respectively. The geology of the presalt formation is narrowly related to tectonic movements that took place during the breakup of the Gondwana supercontinent into the South American and African continents. This took place 150 Ma ago in the Early Cretaceous. The salt of the Aptian Formation is an excellent caprock, the presalt reservoirs are superior in their characteristics, the oil is light and sweet, and the source rocks are enriched in organic matter. The thickness of the Aptian salt is limited, varying from basin to basin; the main width of the salt is in the Santos Basin 400 km and the thickness is 2000 m; in the north, the thickness and width decrease; in the Sergipi Alagoas Basin, it already reaches 100 m.

Deep-burial hydrothermal alteration of the Pre-Salt carbonate reservoirs from northern Campos Basin, offshore Brazil: Evidence from petrography, fluid inclusions, Sr, C and O isotopes

Petrographic, mineralogical, elemental, isotopic and fluid inclusion analyses were integrated to unravel the diagenetic evolution of Brazilian Pre-Salt lacustrine carbonate reservoirs of northern Campos Basin, southeast Brazilian margin. Detailed thin section and cathodoluminescence petrography, scanning electron microscopy and electron microprobe analyses established a paragenetic evolution of diagenetic processes and products, comprising extensive dolomitization, silicification, and dissolution. A paragenesis including saddle dolomite, macrocrystalline calcite, mega-quartz, Sr-barite, celestine, fluorite, dickite, sphalerite, galena, and other metallic sulfides filling fractures and dissolution porosity, and aqueous fluid inclusions with homogenization temperatures of 92–152 °C and salinities between 13 and 26 wt % eq. NaCl characterized a hydrothermal system with some analogy to carbonate-hosted Pb–Zn Mississippi Valley (MVT) and Irish-type deposits. Petroleum inclusions and solid bitumen testify atypical oil generation and migration, associated with the hydrothermal flow. The host Pre-Salt spherulitic and fascicular carbonates present highly radiogenic 87 Sr/ 86 Sr ratios, indicating strong interaction with continental crust materials. Hydrothermal phases show δ 18 O values more negative than syngenetic and diagenetic carbonates. The δ 13 C values are interpreted as result of interaction between the hydrothermal fluids and the host rocks. The combined data set provides clear evidence of intense hydrothermal alteration of northern Campos Basin Pre-Salt reservoirs at deep-burial conditions (>2 km), possibly related to Late Cretaceous or more probably Paleogene magmatic activity. Mixed-sourced fluids bearing a basinal signature fed the hydrothermal system and promoted dissolution of the host rocks. The hydrothermal alterations had strong impact on the porosity, permeability, and heterogeneity, contributing, together with the associated fracturing, to the excellent production performance of the Pre-Salt reservoirs. • A deep-burial hydrothermal system is recognized in the Campos Basin Pre-Salt carbonates. • Hydrothermal phases show low δ 18 O values, and high Th and salinity fluid inclusions. • The geochemical and fluid inclusion signatures are similar to MVT deposits. • Hydrothermal fluids are the result of mixing between different sources. • Atypical oil generation and migration occurred associated with the hydrothermal action.

Impact of basin architecture on diagenesis and dolomitization in a fault-bounded carbonate platform: outcrop analogue of a pre-salt carbonate reservoir, Red Sea rift, NW Saudi Arabia

The early Miocene Wadi Waqb carbonate in the Midyan Peninsula, NE Red Sea is of great interest not only because of its importance as an archive of one of the few pre-salt synrift carbonate platforms in the world, but also as a major hydrocarbon reservoir. Despite this importance, little is known about the diagenesis and heterogeneity of this succession. This study uses petrographical, elemental chemistry, stable isotope (δ 13 C and δ 18 O) and clumped isotope (Δ 47 ) analyses to decipher the controlling processes behind the formation of various diagenetic products, especially dolomite, from two locations (Wadi Waqb and Ad-Dubaybah) that have experienced different diagenetic histories. Petrographically, the dolomites in both locations are similar, and characterized by euhedral to subhedral crystals (50–200 µm) and fabric-preserving dolomite textures. Clumped isotope analysis suggests that slightly elevated temperatures were recorded in the Ad-Dubaybah location (up to 49°C), whereas the Wadi Waqb location shows a sea-surface temperature of c. 30°C. These temperature differences, coupled with distinct δ 18 O VPDB values, can be used to infer the chemistry of the fluids involved in the dolomitization processes, with fluids at the Wadi Waqb location displaying much higher δ 18 O SMOW values (up to +4‰) compared to those at the Ad Dubaybah location (up to −3‰). Two different dolomitization models are proposed for the two sites: a seepage reflux, evaporative seawater mechanism at the Wadi Waqb location; and a fault-controlled, modified seawater mechanism at the Ad-Dubaybah location. At Ad-Dubaybah, seawater was modified through interaction with the immature basal sandstone aquifer, the Al-Wajh Formation. The spatial distribution of the dolostone bodies formed at these two locations also supports the models proposed here: with the Wadi Waqb location exhibiting massive dolostone bodies, while the dolostone bodies in the Ad-Dubaybah location are mostly clustered along the slope and platform margin. Porosity is highest in the slope sediments due to the interplay between higher precursor porosity, the grain size of the original limestone and dolomitization. Ultimately, this study provides insights into the prediction of carbonate diagenesis in an active tectonic basin and the resultant porosity distribution of a pre-salt carbonate reservoir system.

From Atoms to Pre-salt Reservoirs: Multiscale Simulations of the Low-Salinity Enhanced Oil Recovery Mechanisms

The goal of this review paper is two-fold: bringing an updated survey on the literature of the proposed mechanisms behind the low-salinity enhanced oil recovery (EOR) and propose ways to model them based on simulations coupling atomic to reservoir scales. The low salinity water injection (LSWI) presents some advantages over other EOR techniques since it is a cost-effective method, has no inherent environmental damage and does not affect the subsequent stages of crude oil treatment and refinement. The LSWI is particularly interesting for exploration and production on pre-salt carbonate reservoirs. We couple the LSWI mechanisms with molecular modeling methodologies, addressing their use to describe the EOR via LSWI. From the molecular modeling, one can obtain parameters for the large-scale reservoir simulators, thus, improving their accuracy. Therefore, the molecular modeling approaches are complementary tools to optimize the EOR via LSWI. Among all the involved mechanisms on the LSWI, the wettability alteration is pointed out by several authors as the fundamental one, to explain the EOR. However, there are controversies related to its cause: salting-in effect, multi-component ionic exchange, pH alteration, electric double layer expansion, fines migration, limited release of particles and osmotic pressure are among the main proposals. In this sense, several molecular modeling techniques have been explored to foster theories that explain the possible mechanisms and optimize the oil production combining the molecular dynamics simulations and Ab initio calculations with reservoir simulators.

Ultra-deepwater seismic plays offshore Brazil — Future drilling off Santos and Campos Basins

Contemporaneous seismic data acquisition in the Santos and Campos Basins offshore Brazil have focused on image characterization of deepwater and ultra-deepwater reservoirs and their relationship with hydrocarbons originating from synrift source rocks. Our interpretation has mapped the stratigraphy of postsalt turbidite reservoirs, and, on the presalt lithology, it has uncovered the underlying synrift sequences that embrace oil-bearing source rocks and the prolific, recently discovered, microbialite carbonate reservoirs. The new phase in geophysical data acquisition and offshore drilling that started in 1999 bolstered the Brazilian offshore petroleum production to record levels. The new, massive, nonexclusive, speculative 2D and 3D data acquisition surveys conducted offshore the Brazilian coast far exceed the amount of all existing cumulative vintage data. Deepwater drilling programs probed the interpreted new prospects. As whole, the modern geophysics data libraries offshore Brazil brought in the technology era to seismic interpretation, reservoir characterization, and geosteering operations in deepwater development drilling. Still, regional interpretation mapping of the outer shelf, slope, deepwater and ultra-deepwater provinces of the Santos and Campos Basins indicates plenty of prospective future drilling in the salt locked minibasins of the ultra-deepwater provinces. Salt tectonics shapes the architecture of these basins; hence, postsalt deepwater turbidite plays were readily interpreted from seismic amplitudes of the modern data that also allow for resolution images of the synrift source rocks, salt architecture, migration paths through faulting and salt windows, reservoir characterization, and regional seal mapping. The new techniques of prestack depth migration have enabled uncovering the imaging structure of the synrift that led to characterization of the presalt carbonate reservoirs and discovery of giant accumulations. Future offshore exploration will continue aiming at postsalt deepwater and ultra-deepwater minibasins plus presalt plays under the massive salt walls, still an underexplored frontier.

Experimental efforts to access 4D feasibility and interpretation issues of Brazilian presalt carbonate reservoirs

Brazilian presalt reservoirs comprise carbonate rocks saturated with light oil with different amounts of [Formula: see text] and excellent productivity. The occurrence of giant-size accumulations with such productivity generates the interest in production monitoring tools, such as time-lapse seismic. However, time-lapse seismic may present several challenges, such as imaging difficulties, repeatability, and detectability of small variations of reservoir properties. In addition, when assessing time-lapse seismic feasibility, the validity of Gassmann’s modeling for complex, heterogeneous carbonate rocks is arguable. Other questions include the pressure variation effects on the seismic properties of competent rocks. The effective stress is a linear combination of confining stress and pore pressure that governs the behavior of physical properties of rocks. Many applications assume that the effective stress for elastic-wave velocity is given by the difference between confining stress and pore pressure, whereas another common approach uses the Biot-Willis coefficient as a weight applied to the pore pressure to estimate the effective stress. Through a series of experiments involving ultrasonic pulse transmission on saturated core plugs in the laboratory, we verified the applicability of Gassmann’s fluid substitution and estimated the empirical effective stress coefficients related to the P- and S-wave velocities for rock samples from two offshore carbonate reservoirs from the presalt section, Santos Basin. We observed that Gassmann’s equation predicts quite well the effects of fluid replacement, and we found that the effective stress coefficient is less than one and not equal to the Biot-Willis coefficient. Moreover, there is a good agreement between the static and dynamic Biot-Willis coefficient, which is a suggestion that the presalt rocks behave as a poroelastic media. These observations suggest that more accurate time-lapse studies require the estimation of the effective stress coefficient for the particular reservoir of interest.

Improving representativeness in a scenario reduction process to aid decision making in petroleum fields

This paper presents an extension of the RMFinder technique, previously proposed for scenario reduction within the decision-making process in oil fields. As there are several uncertainties associated with this process, a large number of scenarios should be analyzed so that high-quality production strategies can be defined. Such broad analysis is very time-consuming so techniques to automatically identify representative models (RMs) are particularly relevant. In this context, traditional approaches are often based on the selection of three representative models: pessimistic, optimistic and most likely, according only to the most relevant variable of the problem. Here, the RMs are selected to (i) guarantee representativeness in tens of variables of the problem simultaneously; (ii) maintain the original distribution of the uncertain variables; (iii) preserve a good distribution in the scatterplots (cross-plots) of the main output variables of the problem; and (iv) allow a specialist to adjust the relative importance among the considered variables. Therefore, we modeled such a scenario reduction problem as a multi-criteria optimization problem assisted by an expert. We applied the proposed methodology to the OLYMPUS benchmark model and to two reservoir models based on real-world Brazilian fields: (i) UNISIM-I-D, a benchmark case based on the sandstone Namorado field; and (ii) UNISIM-II-D, a benchmark case based on a highly fractured pre-salt carbonate reservoir. In each experiment, the number of RMs varied from 1 to 25. We verified that, the larger the number of RMs, the smaller the bias will be with respect to the risk curves. The obtained sets of RMs were analyzed by petroleum engineers and considered appropriate for the problems studied, and they were adopted as the standard models in the following steps of the decision-making process to define the production strategies under uncertainties.

Porosity and Permeability Alteration of Carbonates by CO<sub>2</sub>-Enriched Brine Injection

Some carbonate reservoirs are known for their high CO2 content in oil. One possibility to handle this gas without environmental problems is to reinject it into the reservoir. Injection of carbonated water has been drawing attention because it is an advantageous technique when compared to gaseous CO2 injection, due to its improvement in mobility in the reservoir. The objective of this study is to evaluate the phenomenon of dissolution and precipitation during carbonated water injection in carbonate rocks. These effects are identified by analyzing the porosity variations through X-ray computer tomography images and permeability profile, determined indirectly by pressure transducers that measured the differential pressure by the fluid at the inlet and outlet of the core holders. The Coreflooding test were carried out with two core holders in series to represent a near region at the reservoir by the injection of brine saturated with 25% of CO2 in reservoir samples, composed of dolomite, calcite and clay. The test were performed using the following reservoir conditions of 8,500 psi at 70°C. Based on the experimental data provided by CT images, it can be seen that the core porosity increases or decrease during carbonated water injection due to coexistence of dissolution (increase of porosity) and precipitation (decrease of porosity) along the samples. These phenomena are observed in regions with high heterogeneity in porosity. In addition, the mineralogy of the cores is composed by three minerals, which influence in the capacity of reaction with carbonated water. For the experiment, the core placed in the core holder one presented a porosity increase and the second one decreased. On the other hand, the permeability showed a significant increase for both cores, it is believed that, the injection promoted a preferential way flow (wormhole) that affected considerably the permeability of the rock. The novelty of the investigation is that the experiments were carried out using Brazilian pre-salt carbonate reservoir rocks with mineralogy composed basically by dolomite, calcite and clay. Also, experimental work was performed at reservoir operational conditions.

Petroacoustics and composition of presalt rocks from Santos Basin

The deposition of the presalt section from Santos Basin began when Gondwana started to break up and South America and Africa were separating. Initial synrift carbonate deposits affected by relatively severe tectonic activity evolved to a lacustrine carbonate environment during the later stages of basin formation. Although the reservoirs are composed of carbonate rocks, the occurrence of faults and the intense colocation of igneous rocks served as a source of chemical elements uncommon in typical carbonate environments. Consequently, beyond the presence of different facies with complex textures and pore geometries, the presalt reservoir rocks present marked compositional and microstructural variability. Therefore, rock-physics modeling is used to understand and interpret the extensive laboratory measurements of P-wave velocities, S-wave velocities, and density that we have undertaken on the presalt carbonate cores from Santos Basin. We show that quartz and exotic clay minerals (such as stevensite and other magnesium-rich clay minerals), which have different values of elastic moduli and Poisson's ratio as compared to calcite and dolomite, may introduce noticeable “Poisson's reflectivity anomalies” on prestack seismic data. Moreover, although the authors concentrate their attention on composition, it will become clear that pore-space geometry also may influence seismic rock properties of presalt carbonate reservoirs.

Evaporitic carbonates in the pre-salt of Santos Basin – Genesis and tectonic implications

Abstract Since the first discoveries of oil accumulations in the carbonate reservoirs of the Lower Cretaceous Barra Velha Formation of the Santos Basin, their genesis has been the subject of intense discussion. Different depositional models have been proposed, with some authors advocating a microbial origin, while others an abiotic origin as travertines or travertine-like rocks. This search for a modern carbonate analogue for these unusual rocks may have disregarded an intriguing alternative: an evaporative model supported by our petrographical and geochemical data. Evaporitic sediment patterns in endorheic basins, in a depositional framework of brine drawdown, are dominated by ephemeral salt pan hydrology. Bedded salt crusts form a stack of subaqueous aligned crystal beds at the sediment-water interface; salt grows diagenetically within saline and mud layers beneath the dry pan surface; finally laminated sediments are deposited. We observe a similar cyclic pattern in the pre-salt core we described: beds of shrub-like crystals and diagenetic spherulites growing in magnesium clay matrix are followed by laminites. The model we propose attempts to contribute solving the puzzle of Pre-Salt carbonate deposition by integrating sedimentology and geochemistry with basin tectonics. Our observations and basin tectonics point to the exciting possibility that the sag phase carbonates of the Santos-Campos basin were deposited as the initial/transitional stage of a closed sub-sea-level evaporite basin whose rising salinities culminated in the deposition of halite and bittern salts (carnallite, sylvite, tachyhydrite). Basinwide evaporites are singular events in the geological record. They form when a giant sub-sea-level basin becomes a sump of continental, marine and hydrothermal fluids, producing unexpected brine compositions in unusual depositional settings present in ancient evaporitic basins but absent from most modern ones. The novelty in this paper is that we apply to pre-salt carbonate deposition the sedimentology, hydrology and geochemistry of ancient evaporitic basins. With this concept in mind, we propose a geochemical model for the unusual pre-salt carbonate precipitation of the Santos Basin. Regarding the Walvis-Rio Grande volcanic high as a topographic barrier during the Aptian, we suggest that the main sources of calcium to the Barra Velha paleolake were hydrothermal brines, mostly from infiltrating seawater that reacted at depth with the basalts of the volcanic barrier. Hyperextension of the lithosphere, with a shallow Moho, increased geothermal gradients to levels favorable for the generation of hydrothermal CaCl2 brines, a process facilitated by the already elevated Ca++ ion and low sulfate concentration of the Cretaceous ocean. These CaCl2-rich fluids would pass through the volcanic barrier into a sub-sea-level paleolake in the rift basin. The high salinity paleolake would become saturated in calcium bicarbonate/carbonate as internally drained NaHCO3-bearing alkaline waters, formed by physical/chemical weathering of penecontemporaneous basaltic rocks, mix with the CaCl2-bearing hot brines percolating through the barrier, producing a hybrid brine (2NaHCO3 + CaCl2 = Ca(HCO3)2 + 2NaCl). Such a depositional system, integrating the geochemical-depositional controls of sag phase carbonates with those of the South Atlantic evaporites, has important implications for unravelling the genesis of these exotic deposits.

Mineralogy and organic geochemistry of the terrestrial lacustrine pre-salt sediments in the Qaidam Basin: Implications for good source rock development

Abstract Terrestrial pre-salt sediments are not only good lithologic reservoirs similar to marine pre-salt carbonates, but also are supposed to have high hydrocarbon generation potential because the overlying terrestrial thick-bedded salts are generally preserved in basin centers. However, their status as source rock has attracted much less attention than as reservoir. In this paper, we choose the Qaidam Basin as an example and study the minerology, organic geochemistry, and organic petrology of the pre-salt sediments in a hydrocarbon-rich unit, where abundant petroleum resources have been discovered under halite beds. LithoScanner logging of six wells and X-ray diffraction results of 378 samples show that terrestrial pre-salt sediments are characterized by mixed siliciclastic-carbonate-sulphate rocks and their relative proportions are laterally varied. Quartz, feldspar and clay minerals are of allochthonous origin and classified as argillaceous endmember while dolomite and ankerite are of autochthonous origin as carbonate endmember. Organic geochemistry analysis of 118 samples show great variability in TOC, S2, and Tmax values, and this variability is not related to mineral composition heterogeneity as hydrogen index is not well correlated with detritus, carbonate, and sulphate minerals contents, indicating the interacting controls of source rocks by both exogenetic and endogenetic processes in brackish-mesosaline lakes. Strong bacterial reworking of organic matter results in the dominant macerals of pre-salt sediments as bituminite and oil generation at low maturity levels. Sealed by impermeable halite beds and in close proximity to reservoirs, the generating hydrocarbon by pre-salt good source rocks is effectively accumulated, which entails hydrocarbon exploration under halite beds in other terrestrial salt-bearing basins.

Experimental study of the effect of carbonated brine on wettability and oil displacement for EOR application in the Brazilian Pre-Salt reservoirs

ABSTRACT Brazilian Pre-Salt carbonate reservoirs are natural candidates for Enhanced Oil Recovery combined with Carbon Capture and Storage due to their high CO2 production. However, the effect of CO2 on rock wettability still needs to be investigated to build representative reservoir models to predict the ultimate oil recovery. This work applied contact angle measurements to study the consequences of carbonated brine on the initial wettability. Moreover, coreflooding experiments were carried out to evaluate the incremental oil recovery obtained by carbonated brine injection. Finally, nonreactive tracer tests and micro computed tomography were used to observe the effects of mineral dissolution on the sweeping efficiency. Carbonated brine induced a decreased oil-wet behavior caused by rock dissolution and desorption of organic compounds resulting in a contact angle reduction of 55° for the Pre-Salt rock. This contributed to obtain a 27% increase in oil recovery. Moreover, tracer tests and micro computed tomography verified the formation of preferential flow paths by mineral dissolution. The increased oil production and decreased contact angle encourage further studies on the injection of carbonated brine for the Pre-Salt scenario.

Unsupervised seismic facies classification applied to a presalt carbonate reservoir, Santos Basin, offshore Brazil

Mapping of seismic and lithological facies is a very complex process, especially in regions with low seismic resolution caused by 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 presalt 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 poststack 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 buildup 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.

Deposition, diagenetic and hydrothermal processes in the Aptian Pre-Salt lacustrine carbonate reservoirs of the northern Campos Basin, offshore Brazil

The discovery of large oil accumulations in the rift and sag Pre-Salt sections of the Campos and Santos Basins has revived interest in the exploration of the lacustrine carbonate reservoirs in the Brazilian and African marginal basins. More than half of Brazilian oil production originates from the Pre-Salt reservoirs of these offshore basins. A study integrating systematic petrography, cathodoluminescence, scanning electron microscopy, microprobe and X-ray diffraction was performed on seven wells in the northern Campos Basin. This study highlights the major primary, diagenetic and hydrothermal features of the Pre-Salt succession, with the aim to improve our understanding of the factors that influence the porosity and permeability distribution in these important lacustrine carbonate reservoirs. The Pre-Salt deposits correspond to bioclastic grainstones and rudstones, syngenetic crusts of fascicular calcite, and intraclastic grainstones and rudstones of reworked crust fragments and calcite spherulites. Magnesian silicates are frequently associated with carbonate deposits. In the sag phase, stevensitic laminations constitute the substrate for the precipitation of calcite crusts and spherulites, which displace and replace the syngenetic magnesian clay deposits. In the rift section, stevensitic ooids are mixed with bioclasts or form ooidal arenites. Pre-Salt carbonate reservoirs have undergone a complex and heterogeneous diagenetic evolution. Eodiagenetic processes include the dissolution, neomorphism and cementation of bivalve bioclasts in the rift, as well as the dissolution of magnesian silicates and their replacement by calcite spherulites, silica and dolomite in the sag section. Burial alterations are commonly associated with hydrothermal fluids carried through faults and fracture systems. These fluids promote dolomitization, silicification, and dissolution at varying degrees and intensities. Eodiagenetic precipitation and dissolution owing to variations in the lake water chemistry and the episodic flow of hydrothermal fluids under burial conditions control the creation, redistribution, and obliteration of porosity in the Pre-Salt reservoirs.