Pre-salt Reservoirs Research Articles

Fault and fracture study by incorporating borehole image logs and supervised neural network applied to the 3D seismic attributes: a case study of pre-salt carbonate reservoir, Santos Basin, Brazil

Fractures play a significant role in the development and production phases of carbonate reservoirs. Quantitative interpretation of fractures not only enhances reservoir models but also reduces the drilling risk and optimizes well design. In this study, we attempt to predict the fracture density map by integrating well and seismic data along with maximum horizontal stress identification. To this end, we propose a workflow with a set of machine learning approaches. First, 3D seismic data is conditioned after the migration processing sequence and the main faults and horizons are interpreted. Next, a number of curvature and coherence attributes are created for a supervised neural network technique to generate new seismic-based discontinuity attribute. Using a geostatistical method to incorporate the interpreted dip and azimuth attributes from well image logs and 3D seismic discontinuity attribute, the fracture density map is predicted and the results validated with a blind well. Finally, we evaluate the strike azimuth of possible open fractures based on the stress regime analysis, from which two distinctive zones are identified. There are, however, some limitations in this study. The predicted fracture density map can be employed to build a discrete fracture network, update dual porosity and permeability estimation, and identify sweet spots.

An internally consistent procedure to characterize single carbon number fractions for phase equilibrium of petroleum mixtures: Application to Brazilian pre-salt reservoir fluids

Each natural accumulation of hydrocarbons has unique chemical and molecular characteristics. A complete experimental assessment of every substance involved is impossible and, in most cases, gaps left by laboratory tests must be filled by empirical correlations to provide the minimum set of parameters necessary for the proper functioning of a thermodynamic model. In the present work, a new procedure is developed for calculating the critical properties and acentric factor of single carbon number (SCN) fractions, valid for the C7-C22 interval (Mw≤300g/mol) and successfully tested for mixtures containing heavy fractions with average molecular weights up to 520g/mol. The proposed method is based on a refit of existing correlations that fully respects the internal consistency of the equations. These, in turn, were selected by observing the trends described by the critical compressibility factor in the Soave–Redlich–Kwong (SRK) and Peng–Robinson (PR) cubic equations of state, resulting from the introduction of a volume translation parameter. After applying the new procedure to characterize ten oil samples collected from High-Pressure High-Temperature (HPHT) reservoirs in the Brazilian pre-salt cluster, thermodynamic parameters derived from flash and differential liberation tests were successfully predicted. With average absolute deviations of 8.38% and 8.32% for the SRK and PR equations of state, respectively, the proposed method is superior (or at least equivalent) to other characterization schemes considered in the study, with the advantage of being thermodynamically consistent.

Integration of Seismic Data to Build Geomechanical Models for the Brazilian Pre-Salt Reservoirs – an Example in the Santos Basin

ABSTRACT. Pre-Salt Province hydrocarbon accumulations increased the relevance of E&P activities in the Santos Basin, Brazil. Deep carbonatic reservoirs, below 5 km, located in ultra-deep water of over than 2 km, under a salt section varying from few meters to 3 km of thickness compose this hydrocarbon province. Geomechanical models representing these complexities require a teamwork within an integrated environment of geosciences and engineering. In this context, despite being indirect measurements, high-definition seismic data allows us to add valuable content to build reliable geomechanical models. In the short-term, during drilling and completion phases, it is mandatory to model potential geohazards related with high porosity sands; intercalations of different hardness rock types in shales, sandstone, and marls; and highly creep soluble salts behaviors. These effects are responsible for pipe sticking, project profit losses and seabed facilities risks. Long-term risks are modelled accessing the uncertainty in the static elastic properties from seismic attributes. Here, we choose three different dynamics vs. static equivalences giving more reality to the model, delivering information about seabed subsidence, seal rock failures, post-salt fault/fracture reactivations and well casing damages. In this work, we demonstrate the discipline integration starting from the seismic data to model these geomechanical scenarios.Keywords: geomechanical modeling, seismic data, geohazards, dynamic vs. static equivalences, Santos Basin pre-salt reservoir. Integração de Dados Sísmicos para Construção de Modelos Geomecânicos para os Reservatórios do Pré-Sal Brasileiro – um Exemplo na Bacia de SantosRESUMO. Acumulações de hidrocarboneto na Província do Pré-Sal aumentaram a relevância da atividade de E&P na Bacia de Santos, Brasil. Reservatórios carbonáticos profundos abaixo de 5 km, coluna d’água ultraprofunda (>2 km), e abaixo da seção salífera com espessura de dezenas de metros até aproximadamente 3 km compõem essa província de hidrocarbonetos. Modelos geomecânicos representando essas complexidades requerem uma equipe multidisciplinar em um ambiente integrando-se geociências e engenharias. Neste contexto, uma medida indireta, dados sísmicos de alta definição agregam conteúdo valioso na modelagem geomecânica. No curto prazo, nas fases de perfuração e completação, é mandatório modelar os potenciais perigos geológicos relacionados com: arenitos de alta porosidade; intercalações de rochas folhelhos, margas e arenitos de diferentes rigidez; e sais solúveis de alta fluência. Essas ocorrências causam prisão da coluna, diminuição dos lucros e danos às instalações no fundo marinho. Riscos de longo prazo são modelados estimando-se a incerteza nas propriedades elásticas estáticas a partir de atributos sísmicos. Escolhemos três diferentes equivalências dinâmica vs. estática, entregando informações mais confiáveis sobre subsidência do leito marinho, integridade da capeadora, reativação de falhas e fraturas e danos a revestimentos de poços. Neste trabalho demonstramos a integração das disciplinas desde o dado sísmico até o modelo geomecânico.Palavras-chave: modelagem geomecânica, dado sísmico, geohazards, equivalências dinâmica vs. estática, pré-sal da Bacia de Santos.

Tupi Nodes pilot: A successful 4D seismic case for Brazilian presalt reservoirs

The oil and gas industry has established 4D seismic as a key tool to maximize oil recovery and operational safety in siliciclastic and low- to medium-stiffness carbonate reservoirs. However, for the stiffer carbonate reservoirs of the Brazilian presalt, the value of 4D seismic is still under debate. Tupi Field has been the stage of a pioneering 4D seismic project to field test the time-lapse technique's ability in monitoring production and water-alternating-gas (WAG) injection in the Brazilian presalt. Ocean-bottom node (OBN) technology was applied for the first time in the ultra-deep waters of Santos Basin, leading to the Tupi Nodes pilot project. We started with feasibility studies to forecast the presalt carbonate time-lapse responses. The minerals that constitute these carbonate rocks have an incompressibility modulus that is generally twice as large as those of siliciclastic rocks. This translates into discrete 4D signals that require enhanced seismic acquisition and processing techniques to be correctly detected and mapped. Consequently, two OBN seismic acquisitions were carried out. Time-lapse processing included the application of top-of-the-line processing tools, such as interbed multiple attenuation. The resulting 4D amplitude images demonstrate good signal-to-noise ratio, supporting both static and dynamic interpretations that are compatible with injection and production histories. To unlock the potential of 4D quantitative interpretation and the future employment of 4D-assisted history-matching workflows, we conducted a 4D seismic inversion test. Acoustic impedance variations of about 1.5% are reliably distinguishable beyond the immediate vicinity of the wells. These 4D OBN seismic surveys and interpretations will assist in identifying oil-bypassed targets for infill wells and calibrating WAG cycles, increasing oil recovery. We anticipate that studies of the entire Brazilian presalt section will greatly benefit from the results and conclusions already reached for Tupi Field.

Influence of oil aging time, pressure and temperature on contact angle measurements of reservoir mineral surfaces

Reservoir wettability plays a critical role in determining the fluid interactions, distributions, and flow paths in porous mediums, which is directly reflected in oil production and recovery strategies during a field’s production life. Many factors can influence reservoir wettability characterisation on the laboratory scale such as: sample origin, mineralogical composition, cleaning procedures for further analysis, pressure, temperature, and the oil aging process. The best practice to restore the sample's original wettability by aging processes is unclear, impacting the assessment of contact angle (CA) measurements. This work addresses the oil aging time and experimental conditions associated with the pressure and temperature in CA measurements on rock surfaces from a Brazilian pre-salt reservoir with a predominance of calcite, dolomite, and quartz, respectively. For this purpose, all surfaces used were cleaned with solvents and saturated with synthetic formation water under vacuum conditions. To evaluate the influence of oil aging time on the samples' wettability, the CA measurements, by captive bubble method, were performed on unaged surfaces. The CA measurements were then taken again on the same surfaces after 14 and 42 days of oil aging. To evaluate the pressure and temperature effects on the CA values, the experiments were run at 14.7 psi and 22 °C (room conditions), 14.7 psi and 60 °C and 4000 psi and 60 °C. The results showed a mischaracterization of all surfaces' original wettability due to the cleaning process, showing the higher hydrophilic degree and wettability character of neutral and water-wet surfaces. The oil aging procedure was confirmed to be a fundamental process in restoring the wettability of rock surfaces, requiring more than 14 days to be achieved. Pressure and temperature conditions also matter on CA evaluations. The surface's hydrophobic degree increased as the pressure increased from 14.7 psi to 4000 psi, and the temperature from 22 °C to 60 °C. Furthermore, a higher influence of temperature than pressure was observed to impact CA values. Oil aging and experimental conditions presented a larger effect on increasing the hydrophobic degree of samples with calcite and dolomite predominance than those with quartz predominance.

Bacillus velezensis H2O-1 surfactin efficiently maintains its interfacial properties in extreme conditions found in post-salt and pre-salt oil reservoirs

Biosurfactants are molecules with surfactant properties produced by microorganisms, and can be used in various industrial sectors, e.g., the oil industry. These molecules can be used in enhanced oil recovery (EOR) in the pre-salt and post-salt reservoirs, where conditions of temperature, pressure, and salinity are quite varied, requiring a study of the stability of these molecules under these conditions. Bacillus velezensis H2O-1 produces five different surfactin homologs with a fatty-acid chain ranging from C11 to C16 and with a high capacity to reduce surface (24.8 mN.m−1) and interfacial tensions (1.5 and 0.8 8 mN.m−1 using light, medium oil and n-hexadecane, respectively). The critical micellar concentration (CMC) was 38.7 mg.L−1. Inversion wettability tests were carried out under the salinity conditions found in the post-salt (35 g.L−1) and pre-salt (70 g.L−1) reservoirs, in which it was observed that the surfactin reversed 100 % of the wettability of the calcite impregnated with light and medium oil. Using a central composite rotatable design, we demonstrated that surfactin maintained its interfacial properties when subjected simultaneously to extreme conditions of pressure, temperature and salinity commonly found in the post-salt (70 °C, 70 g.L−1 and 27.58 MPa) and pre-salt (100 °C, 150 g.L−1 and 48.2 MPa) layers. The results presented here highlight the efficiency and stability of H2O-1 surfactin in environmental conditions found in pre-salt and post-salt oil reservoirs.

Study on the Applicability of a New Type of Bit in Ordovician - Cambrian Dolomite Formation of Tarim Basin

The Ordovician-Cambrian reservoirs in Tarim basin are characterized by complex geological structure, deep reservoir, and thick dolomite strata in the middle and deep formation. The dolomite formation is characterized by large content of chert, high dense lithology, high uniaxial compressive strength, prominent impact and heterogeneity of the formation, it was difficult for conventional drill bits to form stable effective cutting depth and prone to vortex damage, which leads to short drill footage, low ROP and long drilling cycle, it seriously restricted the efficient exploration and development of Cambrian subsalt reservoirs in this block. Therefore, experimental analysis of rock mechanics in the Cambrian dolomite formation was carried out to quantitatively evaluate the rock mechanics properties in this area. A new type of PDC bit was designed to improve the impact resistance and eddy resistance of single teeth, and the impact fatigue test was carried out and successfully applied in the field. The research results show that compared with the adjacent wells in the same interval and lithology, the footage is increased by 39%, and the ROP is increased by 84%, which has achieved obvious acceleration effect, providing technical reference and support for the efficient exploration and development of Cambrian pre-salt reservoirs in the Tarim Basin.

Open fractures in pre-salt silicified carbonate reservoirs in block BM-C-33, the Outer Campos Basin, offshore Brazil

Natural open fractures are present in sidewall cores and in whole-core samples from pre-salt reservoirs in the licence block BM-C-33 in the Campos Basin, Brazil. Open fractures are also observed in borehole image logs, and fracture densities are in general high. The highest density of open fractures is seen in the damage zones above and below larger cavities (amalgamated cavern damage zones (ACDZs)). Outside the ACDZs the fracture density is high in silicified carbonates, where it tends to increase with decreasing porosity. Clean dolomites are less fractured than the silicified interval, while the less brittle argillaceous dolomites have the lowest fracture density. Some fractures appear vuggy on borehole image logs, and fracture densities are high close to vugs and larger cavities. The positive correlation between fractures and vugs is caused by flow of dissolving fluids through open fractures, and fracturing at stress concentrations around vugs. Two major fault zones have been interpreted from borehole image logs that have damage zones with very high fracture density. The well-test permeability is much greater than the matrix permeability estimated from sidewall core and log measurements. This excess permeability is attributed to fractures, in combination with caverns and intervals with frequent vugs.

Computation of Acoustic Velocity of Natural Gases With an Alternative Heat Capacity Ratio Equation and Application to Seismic Modeling

Abstract We investigate three formulations for computing acoustic velocity of natural gas and derive an equation for the heat capacity ratio, which plays a central role in these formulations. The first formulation is a compilation of fundamental equations available in the engineering literature, referred to as the DASH formulation. The second formulation is a development from the first, in which we use the derived equation for the heat capacity ratio (modified DASH). The third formulation is a mainstream method implemented in Geoscience (BW formulation). All three formulations stem from virial Equations of State that take preponderance in the exploration stage, when the detailed fluid composition is unknown and compositional methods are frequently inapplicable. We test the formulations on an extensive experimental data set of acoustic velocity of natural gases and compare the resulting accuracies. Both DASH and modified DASH formulations provide significantly higher accuracy when compared to the BW formulation. Additionally, the modified DASH, as we derive in this work, has the highest accuracy at pressures above 7000 psi, a condition typically encountered in the Brazilian pre-salt reservoirs. In a final step, we investigate how these different formulations and corresponding accuracies in velocity computation may affect seismic modeling, using a single interface model between a dense gas reservoir and a sealing rock. A direct comparison of amplitude versus offset modeling using our modified DASH formulation and the BW formulation shows up to 50% difference in amplitude calculation in a sensitivity exercise, especially at the longer offsets and higher pressures.

Assessment of correlations and simulation software to calculate phase diagrams of pre-salt fluids

The presence of heavy n-alkanes , together with CO2 and water, affects the accuracy of existing correlations used in equations of state. Moreover, they impact the performance of simulation software, resulting in flawed calculations. In this work, the most used correlations for predicting the properties of heavy n-alkanes are analyzed. Calculations were made using commercial software packages for two compositions of pre-salt reservoirs, and considering the Peng-Robinson and the Soave-Redlich-Kowng equations of state. The properties of the estimated C20+fraction affected the numerical stability, and the calculated PT diagrams are unexpected. The reasons for the observed pitfalls are discussed.

A new method to improve the NMR log interpretation in drilling mud-invaded zones: A case study from the Brazilian Pre-salt

The Santos Basin hosts several giant carbonate oilfields in the Pre-salt province and is one of the most important hydrocarbon discoveries in the past years. These carbonate reservoirs present exceptional reservoir quality with a challenging depositional and diagenetic history that produced complex and heterogeneous pore systems. As one of the most effective tools for in-situ porosity and permeability evaluation, the nuclear magnetic resonance (NMR) well log plays an essential role in the Pre-salt petrophysical evaluation and its signal interpretation must be performed carefully. This work proposes a new approach to detect and improve the interpretation of zones with unreal NMR logging tool readings in areas heavily affected by drilling mud invasion in caverns/vugs, which causes a T2 distribution shift towards lower relaxation times. This work analyses well log data from 28 wells in the Sapinhoá Field, supported by special core analyses (SCAL) and routine core analyses (RCAL), as well as plugs, sidewall cores and thin sections data. The proposed approach generates synthetic NMR Free Fluid and T2 distributions with minimum error and replaces the faulty data, consisting in five main steps, (1) computing new curves to be used as inputs; (2) detecting the zones affected by the invasion; (3) water saturation calculation by the saturation height modeling method; (4) calculating a synthetic NMR free fluid curve based on a relationship between a NMR-derived water saturation and the saturation height model; and (5) using the Random Forests algorithm to estimate a synthetic T2 distribution. The proposed method has a minimized error and resulted an increase of up to 10% thickness in the pay zone and a reduction of up to 9% in water saturation average, which may represent enormous amounts of oil depending on the reservoir area. This study provides a new method, which can be used in the improvement of petrophysical interpretations in highly heterogeneous carbonate reservoirs and thus reducing the exploratory and development risks. • Drilling mud invades vug pores and results in misleading NMR readings; • A new methodology is proposed to create a synthetic NMR free fluid and T2 distribution with minimum error; • An increase of 10% in pay thickness and a reduction of 9% in average water saturation was achieved in the Pre-salt reservoirs; • The methodology is proper for the petrophysical evaluation of highly heterogeneous carbonate reservoirs

Study Investigates Using Borehole Gravity To Improve Reservoir Monitoring

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30626, “Brazil Presalt, Santos Basin: Feasibility Study for the Application of Borehole Gravity To Improve Reservoir Monitoring,” by Zhijun Du, Adrian Topham, SPE, and Jeremy C. Lofts, SPE, Silicon Microgravity, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4-7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. The complete paper uses a feasibility study to present the potential application of a three-axis gravimeter borehole measurement in the Libra presalt reservoir in the Santos Basin offshore Brazil. The authors’ findings suggest that an annual survey with a limited well stock could be effective in monitoring this type of reservoir and that a wireline-deployed three-axis gravity tool is likely to provide significant additional surveillance to constrain a reservoir production strategy through better appreciation of the direction of water movement. Introduction The giant Brazilian presalt reservoirs are in ultradeep water (greater than 2000 m) and buried at a depth surpassing 5000 m. In order to conduct reservoir monitoring and achieve successful reservoir management, borehole-based geophysical technologies are preferred because the measurements can be made closer to the reservoir mass. The development of a borehole gravimeter suit-able for use in deep reservoirs, however, poses significant technical challenges, and breakthroughs have been limited by the sensor form factor (size) and measurement stabilization. By use of microelectromechanical-system (MEMS) vibrating-beam technology, the authors introduce a borehole gravimeter that enables the recording of gravitational acceleration at very high sensitivity. The new resonant MEMS gravitational sensor is designed to sense mass in the subsurface such that time-lapse wireline-based surveys can be conducted to build a picture of fluid movements at relatively large distances from a wellbore, thereby enabling time-lapse or 4D gravity monitoring. The innovation of the three-axis gravimeter also allows the acquisition of directional information about the spatial movement of fluid, even when acquired from only a single borehole. The principles of measuring gravity in the borehole environment are provided in the complete paper. Libra Field. The field is one of the largest presalt oil discoveries in the Santos Basin. It was discovered in May 2010 with recoverable resources of approximately 9 billion bbl of oil. The first appraisal well was completed and tested in February 2015. At the time of writing, nine appraisal wells have been drilled. A high-density 3D seismic program was acquired over the Santos and Campos basins, and advanced seismic processing technology has also been applied. Reservoir Simulation. The geophysics for reservoir characterization and simulation of these carbonate reservoirs is still in its early stages, and little published knowledge about their properties exists. Nonetheless, since their discovery, 2D and 3D seismic technologies have been applied intensively for imaging the region structures and delineating the reservoirs.

Model for calcite spherulite formation in organic, clay-rich, lacustrine carbonate shales (Barbalha Formation, Aptian, Araripe Basin, NE Brazil)

The formation of carbonate spherulites, recognized as part of the South-Atlantic Pre-Salt reservoir rocks, remains enigmatic. Well-chosen analogues provide insights into depositional and diagenetic conditions and the biotic versus abiotic processes that might influence or even control spherulite growth. Radial fibrous calcite spherulites of the Batateira beds in the Barbalha Formation (Aptian, Araripe, NE Brazil) formed mainly in organic and clay-rich laminite layers as nodules that grew around different nuclei, now represented by, amongst others, micrite and apatite ostracods. They vertically alternate with clays, but also carbonate laminites, which locally also contain spherulites. Characterization of the organic matter content of spherulitites (petrography, total organic carbon, vitrinite reflectance, stable isotopes) reveals TOC's of up to 30% related to the presence of mainly oil-prone alginite next to huminite, inertinite, sporinites and zooclasts. The complex mixture of clays, dominantly autogenic mixed layered illite-montmorrilonite, which alternate with lacustrine carbonates and evaporites, is diagnostic for lakes in a semi-arid environment. The occurrence of gypsum, calcitic alveolar honeycomb spherulite textures, preferential concentration of pyrite at the spherulite-matrix contact and inward spherulite perforations suggest bacterial activity under shallow and evaporitic syn-depositional conditions. Although the Barbalha spherulites formed chemically-driven in a viscous matrix, the microbial influence, mainly as lamalginite in the clayey matrix, is undeniable. The mixed organic-silicate gel catalyzed calcite spherulite formation. The Barbalha spherulites consequently illustrate the complementary influence of clays, organic matter and evaporitic syn-sedimentary conditions.

The challenging carbonates from the Pre-Salt reservoirs offshore Brazil: facies, palaeoenvironment and diagenesis

The Santos Basin in offshore Brazil belongs to the major carbonate reservoir province known informally as the Pre-Salt. A detailed analysis of cores, plugs, sidewall samples and thin-sections from two wells in a sector of this basin was undertaken, on an interval corresponding to the upper part of the Lower Cretaceous Barra Velha Formation. Several facies and subfacies types have been classified independently from existing terminologies for these carbonate rocks. The specific features of the studied material are discussed and comparison to other nomenclatures is made. The facies include, namely: laminated argillaceous limestones; in-situ grown carbonates with a range of singular morphologies (of debatable origin), from laminar crust, stromatolitic-like fabric to robust or delicate shrubby structures; intraclastic grainstones/packstones, whose clasts may be mostly remnants of shrubs or differ; spherulitic grainstones/packstones; locally, oncoidal grainstones/rudstones and packstones/floatstones.These rocks are interpreted as depositional and diagenetic or essentially diagenetic facies. The latter are regarded as originally similar to some of the former ones but now "disguised", because they were differently impacted by diagenesis processes over different time periods. Recognizing these effects is relevant, because they produce different reservoir facies characteristics and quality. The best potential reservoirs are some of the depositional and the mostly diagenetic facies.The palaeoenvironmental setting of the studied facies fits into a shallow, low-gradient lake. Charophyte and other possible, unidentified algae, albeit extremely rare, are documented for the first time. The facies pattern shows some cyclicity, suggestive of both water depth and chemistry changes.If the interpretations in this study are correct, they (i) reinforce existing datasets to improve understanding of these facies; (ii) raise caution concerning some facies previously considered as separate depositional products, which in fact may instead result from diagenetic modifications; (iii) stress the relevance of microfacies analysis and diagenetic petrography to help deciphering how diagenetic modifications impact on reservoir facies properties and quality; and (iv) add new issues to the naming and textural classification problems of the Brazil Pre-Salt carbonates.

Mixed carbonate rocks lithofacies features and reservoirs controlling mechanisms in a saline lacustrine basin in Yingxi area, Qaidam Basin, NW China

Abstract Taking the mixed pre-salt carbonate rocks in the upper member of Eocene Xiaganchaigou Formation (E32) of Yingxi area in the Qaidam Basin as an example, the lithofacies and controlling mechanisms of reservoir formation are analyzed based on a large dataset of cores, thin sections and geochemical analysis. The reservoirs in E32 pre-salt layers have five types of lithofacies, of them, mixed granular calcareous dolostone, massive calcareous dolostone, plaque calcareous dolostone, and laminated dolomtic limestone are of sedimentary origin, and breccia calcareous dolostone is of tectonic origin. The four types of sedimentary lithofacies are divided into two types of saline sedimentary sequence lithofacies combinations, low-energy type in the sag area and low to high-energy type in the slope and paleo-uplift zone in the depression. Affected by high-frequency supply of continental clastic material, the two types of salty sedimentary sequences are mostly incomplete subtypes of lithofacies. Lithofacies have strong impacts on pre-salt reservoirs in E32: (1) Lithofacies type and sedimentary sequence controlled the formation and distribution of dolomite intercrystalline pores and dissolved pores during the pene-sedimentary period. (2) The structure of laminated dolomitic limestone controlled the formation of large-scale laminated fractures and high permeability channels during the diagenetic period. (3) Granular, massive, plaque calcareous dolostones have low mud content and strong brittleness, in the late tectonic reactivation period, the distribution of the three types of lithofacies, together with their distance from the top large slip faults and secondary faults, controlled the formation and distribution of high-efficiency fracture-cave brecciaed calcareous dolostone reservoirs. The above research led to the composite lithofacies-tectonic formation model of pre-salt reservoir in E32 of Yingxi area. The tempo-spatial distribution of tectonic breccia calcareous dolostone reservoirs, laminated dolomitic limestone shale oil reservoirs and granular, massive calcareous dolostone dissolved-intercrystalline pore tight reservoirs in various structural belts of the studied area have been figured out. These findings gave new insights into tight-shale oil accumulation theory in mixed carbonate successions from saline lacustrine basins, aiding in high efficient exploration and development of petroleum in the studied area.

Stepped machine learning for the development of mineral models: Concepts and applications in the pre-salt reservoir carbonate rocks

Understanding rock mineralogy is essential for formation evaluation, improving the calculation of porosity and hydrocarbon saturation. The primary method to obtain the mineralogy from a well is by applying a model to the geochemical tool's chemical elements. However, creating a mineralogical model presents challenges such as the minerals' chemical composition and the decision to include a mineral in the model. The traditional application of machine learning can make mineral models less realistic since conventional training is developed based on a set of minerals with different occurrences, lowering some minerals' representativeness. The present research proposes the stepped machine learning (SML), a stepped way to use machine learning to create a mineralogical model from chemical and mineralogical data. A database was assembled with the elemental concentration obtained with XRF analyses and the mineral concentrations obtained with XRD analyses. The chemical elements were Al, Ca, Fe, K, Mg, Mn, Na, Si, and Ti. The minerals were calcite, dolomite, quartz, clays, K-feldspar, plagioclase, and pyroxene. Four algorithms were tested: MLP, GAN, Random Forest, and XGBoost, with XGBoost showing the best results. SML was applied, where a mineral model results are used to train a subsequent model. SML allowed for a significant improvement in some models, notably to clays with an increase in R2 from 0.597 to 0.853, quartz an increase from 0.673 to 0.869, and calcite, from 0.758 to 0.862. A decrease in the mean squared error of these minerals' models was also observed. The model was applied to the geochemical logs from three wells drilled in the Brazilian pre-salt, and the results were compared with XRD analyzes. The SML model was able to honor the mineral concentrations for different rocks. It is demonstrated that the integration between machine learning tools and geological knowledge in SML was crucial for creating a representative mineralogical model.

Experimental and modeling studies of density and viscosity behavior of a live fluid due to CO2injection at reservoir condition

In this study, highly accurate measurements of density and dynamic viscosities of a recombined live oil and its mixture with additional CO2were performed. The experiments were carried out under pressure and temperature gradients found in Brazilian Pre-salt reservoirs, that is, in the pressure range from (27.6 to 68.9) MPa and at (333.15 and 353.15) K. The assumption of volume change on mixing is evaluated from the experimental results, and the influence of pressure and temperature on the volume change upon mixing is assessed. The densities of mixtures are calculated considering (i) the excess volume approach, and (ii) no volume change. The densities are better correlated using the excess volume approach with Average Absolute Deviations (AAD) of 0.03%. Thirteen mixing rules of viscosity are examined by comparing the predicted values with the experimental viscosity of the recombined live oil + CO2mixture. The performance of some rules using compositional fractions (molar, volume and weight) is also evaluated. Thus, a total of 28 different ways to calculate the mixture viscosities were tested in this study. The worst result was obtained with Bingham’s method, leading to 148.6% AAD. The best result was obtained from Lederer’s method with 2% AAD and a maximum deviation of 5.8% using volume fractions and the fitting parameterα. In addition, deviations presented by the predictive methods of Chevron, Double log, and Kendall did not exceed 9% AAD, using weight fractions (Chevron and Double log) and molar fractions (Kendall and Monroe).

About this title - Seismic Characterization of Carbonate Platforms and Reservoirs

Modern seismic data have become an essential toolkit for studying carbonate platforms and reservoirs in impressive detail. Whilst driven primarily by oil and gas exploration and development, data sharing and collaboration are delivering fundamental geological knowledge on carbonate systems, revealing platform geomorphologies and how their evolution on millennial time scales, as well as kilometric length scales, was forced by long-term eustatic, oceanographic or tectonic factors. Quantitative interrogation of modern seismic attributes in carbonate reservoirs permits flow units and barriers arising from depositional and diagenetic processes to be imaged and extrapolated between wells. This volume reviews the variety of carbonate platform and reservoir characteristics that can be interpreted from modern seismic data, illustrating the benefits of creative interaction between geophysical and carbonate geological experts at all stages of a seismic campaign. Papers cover carbonate exploration, including the uniquely challenging South Atlantic pre-salt reservoirs, seismic modelling of carbonates, and seismic indicators of fluid flow and diagenesis.

Influence of carbonate reservoir mineral heterogeneities on contact angle measurements

The wettability of reservoir rocks is one of the critical, advanced petrophysical parameters affecting oil production, during the field production life, from primary to enhanced recovery projects. This paper addresses the effect of mineral heterogeneities on wettability behaviour by measuring the contact angle (CA) on carbonate rock core samples from a Brazilian pre-salt reservoir. Mineralogical composition and mineral maps of samples extracted from reservoir plugs were characterised by X-ray based image analysis (scanning electron microscope coupled with automated mineral liberation analysis - SEM-MLA). The results indicated that around 99% of the samples were composed of calcite, dolomite, and quartz with completely different mineral distribution and texture. Also, the attained mineral maps directed the obtention of samples containing different mineral contents in which CA measurements were carried out by using the sessile drop method. CA experiments were run at a temperature of 60 °C and a pressure of 4000 psi with no-aged and aged samples in dead oil. Self-organised maps, generated by machine learning, were used to analyse the relationships between the variables. The results indicate that the predominant mineral constituents and their distribution influence the contact angle values and emphasise the importance of using reservoir core samples and their closest analogues when approaching rock/fluid interaction studies. Despite the samples with higher quartz content showing a greater water-phase affinity than carbonate ones, when both phases are inter-grown, wettability was changed to neutral and oil-wet. In this way, the mineral proportions and texture play a key role in the measured CA. Dolomite contributes to increasing the oil-wet tendency of the rock samples. Mineral maps are not currently applied in wettability studies but demonstrate that it can be a valuable tool for more reproducible measurements and a better understanding of the reservoir.

Petrography, geochemistry and origin of South Atlantic evaporites: The Brazilian side

The discovery and production, by Petrobras, of over 50 billion barrels in place of pre-salt oil in Brazil's offshore South Atlantic Santos and Campos basins has drawn worldwide attention to its km-thick Cretaceous salt seal since 2007. However, the depth of the pre-salt reservoir in these basins make prohibitive the costs of continuous coring or even extensive logging of the salt. The salt seal of the Santos and Campos basins forms part of the Cretaceous South Atlantic salt giant, the largest in the world, now divided between Brazil and southwestern Africa. Although our petrographic study is concentrated north of the Santos and Campos basins, we nevertheless discuss the age, facies, tectonic-paleogeographic controls and evolution of the entire Brazilian salt giant. Offshore Brazil, salt extends for 2.200 km from the Sergipe Basin in the northeast to the Santos Basin in the southwest. The Sergipe Basin at its NE end displays the full spectrum of evaporite cycles, spanning from carbonates, anhydrites and halites to the highly soluble hydrated Mg-chlorides carnallite, bischoffite and tachyhydrite, as does the Santos Basin in the SW part of the salt giant. The deposition of Mg-chlorides was terminated in Sergipe by an intra-salt unconformity at the carnallite/sylvinite contact, dated as 110.64 ± 0.34 Ma. In the intervening Espírito Santo and Campos basins, these highly soluble salts have not yet been found. Onshore Sergipe and Espírito Santo basins the entire salt sequence has been cored in several wells, including the highly soluble Mg–K–Ca chlorides.Here, we analyze the petrography and chemistry of cores in Sergipe and Espírito Santo. We prove the presence of tachyhydrite beds at both ends of the salt giant, in the Sergipe and Santos basins, but, at least for the time being, not in between the two basins. By comparing the presence of tachyhydrite beds in Brazil with similar evaporite sequences of similar age in Thailand, we defend that the high Ca/Mg and Ca/SO4 ratios in Cretaceous seawater was the de facto cause for tachyhydrite deposition in both regions. Ca/Mg and Ca/SO4 ratios of global seawater were raised by hydrothermal activity over basalts produced at exceptionally high rates in the Aptian along new mid-oceanic ridges and in oceanic plateaus such as Ontong-Java. The heat loss caused by this exceptionally high igneous activity may have been instrumental to the change of the thermochemical conditions across the core-mantle boundary that stabilized the Cretaceous Normal Superchron for nearly 40 Ma, from 123.4 to 121.2 Ma (2σ) to 83.07 ± 0.15 Ma (2σ) Ma. Aptian volcanic activity in the South Atlantic formed the Rio Grande Rise - Walvis Ridge that was the southern barrier of the salt basin, lava flows on the São Paulo Plateau, and basalts along the developing South Atlantic Ridge. Evaporite facies reflect cyclic changes on all scales when concentrating the depositing brines. We therefore analyze the effect of increases in brine concentration on the formation of salt crystals throughout multiple depositional cycles. In the later stages of the Brazilian salt basins, increased inflow of seawater from the Central Atlantic Ocean along the Equatorial pull-apart rift basins enlarged and deepened the existent brine lake while its salinity, and especially its Ca and Mg contents, dropped. Flooding by this less concentrated brine created an unconformity, leaching Mg and Ca from the carnallite and tachyhydrite previously deposited, and replacing them with secondary sylvinite. Our results can be applied to the essentially uncored salt sequence of the Campos and Santos basins, where igneous and hydrothermal activity provided additional sources of calcium. The Ca excess may have been increased still further by serpentinization of lithospheric mantle beneath hyperextended crust and by percolation of seawater through mafic rocks of the proto-Rio Grande Rise – Walvis Ridge that formed the southern barrier of the salt basin.