Produção Científica
Artigo em Revista
| Analysis of Eshelby-Cheng’s model in anisotropic porous cracked medium: An ultrasonic physical modeling approach Many effective medium theories are designed to describe the macroscopic properties of a medium (the rock, or reservoir in this case) in terms of the properties of its constituents (the background matrix of the rock and the inclusions, for our scenario). A very well known effective medium theory is the Eshelby-Cheng model, which was studied by us in previous work, being tested for the case where the background medium was weakly-anisotropic and porous. The analysis was done testing elastic velocities and Thomsen parameters - as a function of crack density for fixed values of aspect ratio - predicted by the model with data acquired from synthetic rock samples. In this work, we aim to complete the analysis of the Eshelby-Cheng model capabilities when applied to rocks with porous and vertical transversely isotropic (VTI) backgrounds, testing the model for the elastic velocities as functions of aspect ratio - for fixed values of crack density - against experimental data. The data used to test the model were obtained from 17 synthetic rock samples, one uncracked and 16 cracked, the latter divided into four groups of four samples each, each group with cracks having the same aspect ratio, but with the samples having different crack densities. In these samples, ultrasonic pulse transmission measurements were performed to obtain the experimental velocities used to test the model. As was not possible to acquire data for velocity as a function of aspect ratio for fixed values of crack density, we performed interpolations of the experimental data to estimate these velocities. Eshelby-Cheng model effective velocities and Thomsen parameters were calculated using three formulations proposed for the crack porosity: one proposed by Thomsen, the second one proposed in our previous work (which depends only on the crack density) and the third one proposed in this work (which depends on the crack porosity and the aspect ratio, just like Thomsen’s proposal). The comparisons between elastic velocities and Thomsen parameters - as function of crack aspect ratio, for fixed values of crack density - predicted by the model and estimated from the data via interpolation showed that the third formulation produced better fittings (lower root-mean-square errors) between model and experimental data for all ranges of aspect ratio and crack density. |
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Artigo em Revista
| On the seismic wavelet estimative and reflectivity recovering based on linear inversion: Well-to-seismic tie on a real data set from Viking Graben, North Sea Tying seismic data to well data is critical in reservoir characterization. In general, the main factors controlling a successful seismic well tie are an accurate time-depth relationship and a coherent wavelet estimate. Wavelet estimation methods are divided into two major groups: statistical and deterministic. Deterministic methods are based on using the seismic trace and the well data to estimate the wavelet. Statistical methods use only the seismic trace and generally require assumptions about the wavelet’s phase or a random process reflectivity series. We have compared the estimation of the wavelet for seismic well tie purposes through leastsquares minimization and zero-order quadratic regularization with the results obtained from homomorphic deconvolution. Both methods make no assumption regarding the wavelet’s phase or the reflectivity. The best-estimated wavelet is used as the input to sparse-spike deconvolution to recover the reflectivity near the well location. The results show that the wavelets estimated from both deconvolutions are similar, which builds our confidence in their accuracy. The reflectivity of the seismic section is recovered according to known stratigraphic markers (from gamma-ray logs) resent in the real data set from the Viking Graben field, Norway. |
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Artigo em Revista
| Interval mineral and fluid densities estimation from well-logs: Application to the Norne Field dataset Formation evaluation techniques are the key to understand subsurface rocks properties from well-logs, especially those drilled in hydrocarbon exploration wells. Knowledge of the parameters related to different types of rocks is traditionally used in forward determination of lithology, porosity and water saturation, which can be refined by calibrating the input models. In this work, we perform well-log interval linear inversion with respect to formation density to investigate mineral and fluid properties in a real dataset. The method is based on an overdetermined problem, which supposes a homogeneous distribution of petrophysical parameters through stratigraphic layers and is applied in conventional reservoir rocks from the Norne Field (offshore Norway). Bulk density, gamma-ray and neutron porosity logs are employed in a workflow that relies on layer-by-layer least-squares regressions to estimate matrix, shale and fluid apparent densities. In this process, shale volume and the total density porosity are calculated depth by depth from empirical equations feed by the input logs. Therewith, the introduced inversion scheme stands as an alternative approach for well data interpretation that focuses on computing the densities of the rock constituents instead of fixing these parameters to invert fractional volumes. Furthermore, the application in two wellbores resulted in geological consistent individual densities in most intervals, except for a gas-bearing zone observed in one of the boreholes, where porosity uncertainty caused anomalous variationin grain and fluid densities. |
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Artigo em Revista
| Seismic Stratigraphy of Camamu Basin, Northeastern Brazil —The Camamu Basin is located at the northeastern Brazilian coastline and has significant hydrocarbon potential in both shallow and deep water settings. However, despite an already operating productive gas field, the basin is not well known. Herein, a regional stratigraphic interpretation of the rift, the transitional and the drift megasequences is reported, based on a data set of 152 post-stacked 2D seismic lines, 1 3D seismic cube and 34 wells with eletro-logs. The study revealed that the rift megasequence is much more complex than previously thought. In the southern region of the Camamu Basin, five rift sequences were mapped, while in the northern region, in the area of the regional tectonic lineament known as the Salvador Transcurrent Zone (STZ), seven rift sequences were recognized. This difference suggests a tectonic control during the rifting process, because the northern region is intensely affected by shear stress induced by transcurrent tectonics of the STZ during the crustal breakup. For the post-rift or ‘‘transitional’’ phase associated with thermal subsidence installed after the rift, as well as for the drift succession, the tectonic control exerted by Salvador’s Transcurrent Zone is not detectable and the tectono-sedimentary evolution of the basin follows the general pattern of the Brazilian marginal basins. |
Artigo em Revista
| Non-Hyperbolic Velocity Analysis of Seismic Data from Jequitinhonha Basin, Northeastern Brazil Normal moveout (NMO) velocity is used in seismic data processing to correct the data from the moveout effect. This velocity depends on the medium above the reflector and it is estimated from the adjustment of a hyperbolic function that approximates the reflection time. This approximation is reasonable for media formed by isotropic layers. For deeper exploration targets, which effectively behave as anisotropic media,the NMO velocity estimate from the hyperbolic approximation becomes imprecise. One possibility is the use of non-hyperbolic approximations for the reflection time and deeming the medium to be anisotropic. However, these approximations make the NMO velocity estimation a more complex problem, since the anisotropic parameters are unknown. In this study the NMO velocities for a vertical transverse isotropy medium are estimated using two non-hyperbolic reflection time approaches. For comparing the two methodologies that estimate NMO velocity, a 2-D dataset from Jequitinhonha Basin is used and it presents anisotropic behavior. The results show that this approach produces more consistent results than the conventional approach, which ignores the anisotropy of the medium. |
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Artigo em Revista
| Inversion of satellite gravimetric data from Recôncavo-Tucano-Jatobá Basin System Density differences among subsurface rocks cause variations in the gravitational field of Earth, which is known as gravity anomaly. Interpretation of these gravity anomalies allows assessment of the probable depth and shape of the causative body. For several decades, gravity data were acquired on the surface, but after the scientific and technological advances of the last decades, geopotential models were developed, including gravitational observations on a global scale through space satellite missions. This paper investigated the Moho structure in the region of Recôncavo-Tucano-Jatobá rift-basin system based on the information of the terrestrial gravity field from the EIGEN-6C4 geopotential model. The frequency domain inversion technique was applied, which is known as the Parker-Oldenburg iterative method. Bouguer anomaly data were used in the inversion procedure to determine the thickness and geometry of the crust in the region. Data inversion considered a two-layer model with constant density contrast, in which the entire signal was related to Moho topography. In addition, data inversion was carried out to determine the basement depths. The program proved to be efficient and able to manage large data sets. The results, both of the crust thickness and the sedimentary package, validated the geodynamic evolution understanding of the basin system. |
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Artigo em Revista
| EVOLUTIONARY PROBLEMS OF NONLINEAR MAGNETOELASTICITY We consider mixed problems for nonlinear equations of magnetoelasticity. Our main result in the three-dimensional case is the proof of an existence and uniqueness theorem; uniqueness is established under some extra restrictions on the smoothness of solutions. We also manage to prove the existence and uniqueness of a weak solution to the problem in the two-dimensional case; uniqueness is established without any additional a priori assumptions on the smoothness of solutions. |
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Artigo em Revista
| Petrofacies classification using machine learning algorithms Carbonate reservoirs represent a large portion of the world’s oil and gas reserves, exhibiting specific characteristics that pose complex challenges to the reservoirs’ characterization, production, and management. Therefore, the evaluation of the relationships between the key parameters, such as porosity,permeability, water saturation, and pore size distribution, is a complex task considering only well-log data, due to the geologic heterogeneity. Hence, the petrophysical parameters are the key to assess the original composition and postsedimentological aspects of the carbonate reservoirs. The concept of reservoir petrofacies was proposed as a tool for the characterization and prediction of the reservoir quality as it combines primary textural analysis with laboratory measurements of porosity, permeability, capillary pressure, photomicrograph descriptions, and other techniques, which contributes to understanding the postdiagenetic events. We have adopted a workflow to petrofacies classification of a carbonate reservoir from the Campos Basin in southeastern Brazil, using the following machine learning methods: decision tree, random forest, gradient boosting, K-nearest neighbors, and naïve Bayes. The data set comprised1477 wireline data from two wells (A3 and A10) that had petrofacies classes already assigned based on core descriptions. It was divided into two subsets, one for training and one for testing the capability of the trained models to assign petrofacies. The supervised-learning models have used labeled training data to learn the relationships between the input measurements and the petrofacies to be assigned. Additionally, we have developed a comparison of the models’ performance using the testing set according to accuracy, precision, recall, and F1-score evaluation metrics. Our approach has proved to be a valuable ally in petrofacies classification, especially for analyzing a well-logging database with no prior petrophysical information. |
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Artigo em Revista
| Mathematical Model of Water Alternated Polymer Injection Chemical enhanced oil recovery (EOR) methods include the injection of aqueous polymer solutions slugs driven by water. Polymer solutions increase water viscosity, decreasing the water phase mobility and improving oil recovery through better sweep efciency. In this paper, we present the water alternated polymer EOR technique, which is based on the injection of successive polymer slugs alternated by water slugs. The mathematical problem is composed by two conservation equations: one of them is related to the water volume and the other one to the polymer mass. We assume that the polymer may be adsorbed by the rock, and the relation between the concentration in the aqueous solution and the solid is governed by a Langmuir type adsorption isotherm. The water viscosity is a function of the polymer concentration in water. The 2×2 system of hyperbolic equations was decoupled by introducing a potential function instead of time as an independent variable. The water alternated polymer injection is represented by a varying boundary condition. The analytical solution presents interactions between waves of diferent families. It is shown that the polymer slugs always catch up each other along the porous media generating a single slug. As a consequence, the water slugs will disappear. This solution is new and was compared to numerical results with close agreement. It also can be used for the selection of the most suitable enhanced oil recovery technique for a particular oil field. |
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Artigo em Revista
| The effectiveness of spectral decomposition-based layer thickness estimation: A seismic physical modeling example We have constructed a channel complex model at a scale of 1:10,000 by stacking 3D-printed polylactide layers with negative relief meandering channels. This model was subjected to an ultrasonic common-offset acquisition in a water tank (with the water filling the channels), and the result was treated as a zero-offset 3D acoustic reflection seismogram, receiving a deterministic deconvolution and a poststack migration as data treatment. We then developed an algorithm to yield volumes of estimated two-way time layer thickness from multiple-frequency volumes obtained through the short-time Fourier transform. The estimated thicknesses were compared with the measurements of the physical model obtained through X-ray computed tomography. Despite the strong signal attenuation and imaging issues, the results were rather satisfactory, increasing the confidence in using spectral decomposition for quantitative seismic analysis. |
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