Igor Fernandes Gomes

Geological faults are key discontinuities in sedimentary basins and strongly influence the hydraulic and mechanical behavior of hydrocarbon reservoirs. Fault zones typically contain a low-permeability core and a more permeable damage zone, generating sharp contrasts in petrophysical and mechanical properties. Stress variations from production, injection, or geological storage may induce fault reactivation, dilatancy, and permeability enhancement, yet many numerical studies still treat faults as homogeneous features. This study develops a two-dimensional coupled hydro-mechanical framework that explicitly represents fault-core and damage-zone domains incorporating viscoelastoplastic behavior through a Mohr–Coulomb model with Perzyna viscoplasticity. The novelty of this approach lies in integrating realistic geological architecture with explicit core-damage-zone contrasts and coupled viscoelastoplastic analysis under production and injection scenarios in compartmentalized reservoirs. Based on seismic interpretation of the Laurentian Basin (offshore Canada), CODE_BRIGHT simulations model single-phase flow in a deformable reservoir to evaluate stress redistribution, permeability evolution, and deformation. Sensitivity analyses indicate that an injection pressure of 6.5 MPa triggers fault reactivation, causing dilation-induced permeability increases and establishing hydraulic communication between the deep reservoir and the overlying aquifer previously sealed by Faults 01 and 02. Fault reactivation induces an asymmetric deformational field, with horizontal displacements of approximately + 25 cm along Fault 02 and − 13 cm along Fault 01, and a distortional vertical response characterized by a dip-slip response with differential block-scale subsidence and uplift, with a maximum subsidence of ~ 7 cm. Shear stresses concentrate mainly along Faults 01 and 02, particularly near their tips, indicating stress redistribution toward Fault 03. These results underscore the importance of internal fault-zone heterogeneity in controlling deformation, stress evolution, and transmissivity, with implications for CO ₂ storage, geothermal systems, industrial injection, and geotechnical applications.

In recent decades, faster and more affordable methods for characterizing reservoir rocks in environmental and geological studies have gained importance, particularly for hydrocarbon exploration and resource management. One promising method is X-Ray Computed micro-Tomography (XR-?CT), enabling non-destructive analysis of rock properties. However, this technique presents challenges related to image interpretation, property characterization below the voxel scale, and result comparison across configurations. In this study, laminated limestones from the Crato Formation, analogs to the pre-salt Barra Velha Formation, were analyzed using XR-?CT to estimate density and porosity. These rocks serve as substitutes for actual reservoir conditions, addressing the challenge of limited subsurface samples. This study assessed the feasibility of XR-?CT for characterizing these properties and understanding the impact of millimeter-scale laminations on their distribution. Calibration values for calcite, the primary mineral, were used to ensure accuracy and repeatability. The results demonstrate that XR-?CT is a viable tool for environmental and geological characterization. Laminations due to stratification influenced porosity distribution in the axial direction, with higher concentrations in certain sections of the samples. The porosity values calculated using XR-?CT align relatively well with the gas porosimetry results, with most samples showing a relative difference of less than 10%. However, exceptions were observed in LM4 and T10.2, where the relative difference reached -15.90% and -12.80%, respectively. Despite these challenges, qualitative analysis was achieved. The study highlights the necessity of accounting for mineralogy and calibration in XR-?CT to ensure reliable comparisons across different tomographic systems, enhancing the method’s applicability in environmental and geological studies.

Carbonate rocks are important for the petroleum industry, as they contribute significantly to hydrocarbon reserves, although their analysis is complex due to the high cost of core sampling and their high heterogeneity; for this, synthetic rocks aim to provide relatively homogeneous samples with analogous characteristics to natural rocks. In this research, synthetic carbonate rocks were produced by mixing a fixed ratio between limestone powder, obtained from limestone mining waste, and epoxy resin as a cementing material, using compaction energy for consolidation. The work aimed to produce homogeneous samples with high strength, reproducing the intergranular pore system for future applications in rock–fluid interaction analysis. The characteristics and structure of the samples were investigated through X-ray computed microtomography, petrographic images, petrophysical, chemical and geomechanical tests. Results showed a direct increasing relationship between porosity and permeability and a tendency for mechanical strength (UCS) to decrease with increasing porosity. When compared with the natural carbonate rocks, these presented similarities in their mechanical properties and petrophysical measurements, showing that the methodology can be considered as an alternative for the obtention of a realistic material that can be used for future experiments regarding rock mechanics and rock–fluid interaction for prediction of carbonate rocks’ behavior.

The main objective of this study is to evaluate the hanging wall stability of the mining stopes resulting from the open stope underground mining method, taking into account the exposure time of the wall sans any support, through numerical simulation, using an elasto-viscoplastic model formulated for the finite element method. In order to carry out the simulation, a real application case was chosen: the extraction of a mining block from the underground zinc mine of Nexa Resources, in the municipality of Vazante-MG, which operates through the open stope mining method, where the values of unplanned dilution are known. The stability of the stope’s hanging wall was analyzed through two instability indicators, the horizontal displacements and the minor principal stress, simulated in a two-dimensional perpendicular section and in the center of the stope. The results obtained in the simulations were coherent with the real results that occurred in the stope, and with the rheological behavior of the rocks, since the unstable regions increase with the exposure time without any type of support used, which shows that the model used is a good alternative for prediction of the dilution and the evolution of instability areas of the stope wall according to its exposure time.

Characterization and development of hydrocarbon reservoirs depends on the classification of lithological patterns from well log data. In thin reservoir units, limited vertical data impedes the efficient classification of lithologies. We present a test case of petrofacies classification using machine learning models in a thin interval of finely laminated limestones using pseudo-well data created over outcrops (radiometric and unconfined compressive strength logs). We tested Gaussian naïve Bayes (GNB) and support vector machine (SVM) techniques to classify eight petrofacies types, divided into two groups. The objective was to observe the capacity of some well-known models to classify petrofacies with a high-frequency vertical variation of diagenetic heterogeneities in an extreme scenario within a thin sedimentary interval. The GNB was less effective (F ₁ score of 0.29), and the SVM achieved the best results in classifying the main facies patterns (F ₁ = 0.47). However, the GNB performed better when the analysis was focused on distinguishing the two main groups of petrofacies. The results demonstrate that high-frequency facies variations present a challenge to the automatic identification of lithofacies, mainly due to local variations in horizontal heterogeneities (on the mm- to cm-scale) created by depositional and diagenetic processes, which impact the flow in porous media.

Com a crescente demanda energética mundial, torna-se necessário o estudo do comportamento de rochas-reservatório de petróleo (arenitos e carbonatos), para exploração de novas áreas e aumento na produção de óleo e gás. Embora haja o interesse, análises em rochas naturais são complexas, devido ao alto custo de sua extração, como também por apresentar alta heterogeneidade em suas características. Com isso, o desenvolvimento de rochas sintéticas que apresentem similaridades no comportamento geomecânico e petrofísico desses materiais torna-se uma alternativa, a fim de analisar seu comportamento. Esta pesquisa tem como objetivo apresentar um protocolo de preparação e caracterização geomecânica de rochas sintéticas de matriz carbonática, produzidas a partir da consolidação por compactação da combinação entre pó de rocha calcária e resina epóxi, seguido de tratamento térmico em estufa. Diferentes proporções de materiais foram dosadas até se chegar a um quantitativo suficiente para que ela atingisse dimensões de 8 cm de altura e 4 cm de diâmetro, aspecto uniforme e alta resistência mecânica, cujas características foram avaliadas através dos ensaios de microtomografia computadorizada de Raios-X e resistência à compressão simples (UCS). As rochas carbonáticas sintéticas produzidas apresentaram aspecto uniforme, com valores de UCS entre 71,00 e 86,92 MPa, sendo classificada como uma rocha dura, indicando comportamento tensão x deformação semelhante para as amostras avaliadas. Diante dos aspectos observados, o protocolo de produção das rochas mostra repetibilidade na preparação das amostras, indicando aspecto consolidado, uniforme, homogêneo e comportamento geomecânico semelhante dentre os exemplares produzidos, desejável quando se produzem rochas sintéticas, podendo ser aplicado em estudos da engenharia de petróleo que visem avaliar o comportamento de rochas-reservatório com características semelhantes destas obtidas nesta pesquisa.

Oil production in offshore regions involves the transportation of oil and gas in submarine pipelines, which are vulnerable to geological processes triggered by subsurface oil production like fault reactivation. The fault reactivation process can lead to phenomena that impact the seabed, like subsidence and fluid exudation, and can trigger instability of submarine slopes, which can result in environmental and economic damage. The present work addresses a coupled hydromechanical numerical modeling of a hypothetical case involving fault reactivation caused by oil reservoir production and its impact on an overlying submarine slope. The hypothetical case was simulated using a finite element model. The case involves a reservoir which is cut by a fault zone that reaches the seabed. The slope instability studied was induced by the injection and production of fluids in the reservoir. The fault zone is assumed to be a sealing region and a geomechanical and pressure field discontinuity within the reservoir. Int this work was used the Mohr-Coulomb elastoplastic model with Perzyna viscoplastic regularization to represent the behavior of the fault zone and the overlying submarine slope. Results showed that the fault reactivation, caused by the reservoir production, developed shear stress and shear plastic strain along the fault and through the submarine slope, causing horizontal and vertical displacements in the slope mass and acting as a trigger factor for slope stability. Pore pressure increase at the bottom of the slope structure correlated with the injection pressure artificially increased into the reservoir.