Evaluation of petrophysical rock typing and determination of pore size distribution in a carbonate reservoir using nuclear magnetic resonance

Tight carbonate reservoirs exhibit more complex petrophysical parameters than conventional carbonate reservoirs, presenting unique challenges for characterization and hydrocarbon exploration. One crucial aspect of describing a tight carbonate reservoir is the accurate calculation of petrophysical properties (e.g. porosity and permeability) and rock characteristics. The proposed workflow has been implemented in the Ilam Formation, which is a tight carbonate reservoir. Applying an integrated methodology, including petrography, thin-section analysis, mercury injection capillary pressure (MICP), scanning electron microscopy (SEM) and nuclear magnetic resonance (NMR), on reservoir rocks is a prerequisite to understanding the complexity of carbonate reservoirs, petrophysical properties and pore throat size distribution. As a result, combining the aforementioned parameters will reduce the amount of uncertainty associated with exploratory projects. Core measurements and the petrophysical rock typing (PRT) method were used to determine permeability, porosity and capillary pressure curves. Based on the PRT method, four rock types were determined when considering the geological attributes. The pore size distribution curves obtained from the NMR model show that NMR could be applied as a useful technique for estimating pore size distribution and correspond with the results from the MICP method, which reinforces the importance of integrating NMR–MICP to improve carbonate pore facies estimates. Moreover, the results of this study showed that the NMR log data, when calibrated with MICP, core data analysis, thin-section petrography and SEM images, can help to characterize the tight carbonate reservoir more accurately and reduce uncertainty in the reservoir rock typing.