Quantitative Discrimination of Effective Porosity Using Digital Image Analysis - Implications for Porosity-Permeability Transforms
Five relevant digital image analysis parameters for fluid flow are obtained from 2-D image analysis of carbonate rocks: 2-D image porosity, amount of pores, pore shape, total perimeter per area and dominant pore size range. Micro-porosity leads to low permeable, highly porous rocks. 2-D image porosity represents the macro-porosity because the resolution subtracts the small pores from the porosity. Compared to the total porosity, it improves the prediction of permeability by an order of magnitude in the high porosity range. Pore shape factor γ reduces the uncertainty in permeability prediction to 2 orders of magnitude. Pore shape factor analysis is restricted to samples with more than 4000 pores/cm. CT scans of plugs reveals that the pore shape factor γ is a relatively constant measure of the pore shape (+/0.2) throughout the sample plug. The larger the average pore size, the higher the velocity at a given porosity. The average pore size can be quantified by the upper limit of the dominant pore size range.
ESTIMATIVA DE PARÂMETROS HIDRÁULICOS DO AQUÍFERO BARREIRAS-RN A PARTIR DE ANÁLISE COMPUTACIONAL DE IMAGENS DE LÂMINAS DELGADAS
The attainment of hydraulic parameters derive primarily from the interpretation of aquifer tests, practice that usually involves a fairly complex logistics in terms of equipment and staff required. Thus, the digital processing and analysis of two-dimensional micrographs of aquifer rocks samples is presented as an alternative tool for the characterization of hydraulic parameters, and constitutes a promising procedure accordingly. The methodology is based on a flowchart involving (1) sampling and preparation of thin sections and their respective images, (2) segmentation and geometric characterization, (3) three-dimensional reconstruction and flow simulation. Taking as a target for the present study The Barreiras Aquifer System, in the eastern coast of Rio Grande of Norte state (northeastern Brazil).The computational image analysis of thin sections of its rocks showed reservoir storage coefficients, associated in this context with effective porosities (free hydraulic character), ranging from 0.035 to 0.12, with averages of 0.076; its hydrogeological carbonate substrate showed effective porosities on the order of 2 %. Relative to the transport of fluids, it was found that the method presented results smaller than those found in bibliographic data (related to hydraulic conductivity), probably due to the size of the scale under study and the heterogeneity of the investigated medium.
Predicting the gas resource potential in reservoir C-sand interval of Lower Goru Formation, Middle Indus Basin, Pakistan
Abstract The integrated study of seismic attributes and inversion analysis can provide a better understanding for predicting the hydrocarbon-bearing zones even in extreme heterogeneous reservoirs. This study aims to delineate and characterize the gas saturated zone within the reservoir (Cretaceous C-sand) interval of Sawan gas field, Middle Indus Basin, Pakistan. The hydrocarbon bearing zone is well identified through the seismic attribute analysis along a sand channel. The sparse-spike inversion analysis has efficiently captured the variations in reservoir parameter (P-impedance) for gas prospect. Inversion results indicated that the relatively lower P-impedance values are encountered along the predicted sand channel. To further characterize the reservoir, geostatistical techniques comprising multiattribute regression and probabilistic neural network (PNN) analysis are applied to predict the effective porosity of reservoir. Comparatively, the PNN analysis predicted the targeted property more efficiently and applied its estimations on entire seismic volume. Furthermore, the geostatistical estimations of PNN analysis significantly predicted the gas-bearing zones and confirmed the sand channel as a major contributor of gas accumulation in the area. These estimates are in appropriate agreement with each other, and the workflow adopted here can be applied to various South Asian regions and in other parts of the world for improved characterization of gas reservoirs.