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Coquinas are a sedimentary rock composed mainly of shells and their fragments with a carbonate or siliciclastic matrix. These rocks exhibit a high range of porosity and permeability values that are related to depositional and diagenetic processes. A series of coquina reservoirs were discovered in the Campos and Santos Basins in the eastern margin of Brazil and the understanding of the petrophysical properties of these rocks is essential for reservoir production. In this work, samples from the Morro do Chaves Formation (Sergipe–Alagoas Basin) and the Itapema Formation (Santos Basin) were selected to identify the porosity vs permeability relationship according to the biofabric characteristics and porosity control. The biofabric textures where classified into four groups according to taphonomic patterns and diagenetic modification: (i) well-sorted and preserved biofabric, (ii) well-sorted and altered biofabric, (iii) unsorted and preserved biofabric, and (iv) unsorted and altered biofabric. The porosity control varies in all groups from depositional to diagenetic with distinct pore types, pore sizes, and pore connectivity that are located in different global hydraulic elements. The analysis of the pore space was carried out through laboratorial measurements (gas injection) and by images from high-resolution computed tomography from plug samples, resulting in a pore network model where values of pore radius, pore throat radius, and coordination number were obtained. The best values of porosity and permeability are related to well-sorted altered biofabrics, whereas the lowest values, either with unsorted biofabrics, with low pore connectivity, or biofabrics that had the porosity reduced by compaction and cementation. [ABSTRACT FROM AUTHOR]

Three-dimensional distribution of karstic zones and estimated porosity were obtained in fractured carbonate units of the Salitre Formation (Brazil) from GPR data. Low-amplitude (shadow) GPR zones could be associated with mineral dissolution halos that developed around fractures and bedding planes. GPR volumes show a 3D mazelike geometry of the vertical karstified carbonate zones, similar to the set of passages controlled by ~ N–S and E–W oriented fracture systems, observed on the surface in unmanned aerial vehicle images. Measurements in plug samples indicate that the mineral dissolution caused bulk density and dielectric permittivity decline and incipient increase in porosity from 0.95 to 1.01%. These changes in the rock properties affect the EM impedance contrasts between carbonate bedding, causing loss of the reflected GPR signal. The correlation between dielectric permittivity and porosity could be analyzed using the complex refractive index model (CRIM), which is used to convert the relative dielectric permittivity into porosity. The CRIM porosities are somewhat lower than plug sample porosities due to different estimation methodologies and measurement scales. However, the fact that porosity is slightly higher in the dissolved carbonates was maintained. In addition, GPR amplitude and frequency instantaneous attributes were used to estimate spatial variability in porosity throughout the whole GPR data volume. The crossplot of these two GPR attributes show that altered zones generally cluster in narrow ranges of instantaneous GPR amplitude and in broad range of instantaneous GPR frequency. Assuming empirical correlation between physical properties and GPR attributes two predicted porosity volumes were established for the karstified carbonates in the studied area. [ABSTRACT FROM AUTHOR]

In the daily practice of Formation Evaluation for porosity calculation considering the shale volume is common the adoption of simple hypotheses about the physical properties of the reservoir rock constituents. In this paper, it is argued that an accurate estimate of clay mineral physical properties in the reservoir rock are essential for a realistic porosity calculation, once it may be different from the physical properties of clay minerals present in nearby shale layers. Geologically, the assumption of similarity between the clay mineral physical properties in the reservoir rock and adjacent shales properties means to presume a depositional continuity in sedimentary process and disregarded the innumerous postpositional processes involved in the sedimentary basin. By applying the angular competitive neural network to the Density-Neutron method to identify the clay mineral in the reservoir rock based on all identifiable clay minerals in the oil field, it is shown that a particular clay mineral signals a characteristic angular pattern in the Density-Neutron cross-plot. The methodology is presented with synthetic data and evaluated with actual well logs and core analysis from a borehole drilled in the Namorado oil field, Campos basin, Brazil. • A geologically coherent method to study petrophysical properties of reservoir rock. • The angular competitive neural network is applied to determine the predominant clay mineral in the reservoir rock. • The identified clay mineral in the reservoir is proposed to a realistic porosity estimate. [ABSTRACT FROM AUTHOR]